ITEM 1. BUSINESS
(a) GENERAL DEVELOPMENT OF BUSINESS
We were formed as a limited partnership under the laws of the State of Delaware in August 2000. The principal executive offices of Williams GP LLC, our general partner, are located at One Williams Center, Tulsa, Oklahoma 74172 (telephone (918) 573-2000).
On October 30, 2000, we filed with the Securities and Exchange Commission a registration statement on Form S-1 related to an initial public offering of common units. In February 2001, 4,600,000 common units, representing approximately 40 percent of our total outstanding units, were sold to the public. The Williams Companies, Inc., through its wholly owned subsidiaries, currently owns approximately 60 percent of our Partnership interests including its general partner interest.
Effective June 30, 2001, we purchased two petroleum distribution facilities in Little Rock, Arkansas, from TransMontaigne, Inc. for $29.1 million. These facilities primarily handle gasoline and diesel fuel and have 452,000 barrels of storage capacity.
Effective November 8, 2001, we purchased the crude oil storage and distribution assets of Geonet Gathering, Inc., for $21.1 million. The assets included three pipelines in Gibson, Louisiana that have a combined capacity to distribute up to 60,000 barrels per day of crude oil from a storage facility into pipeline interconnects. The acquisition also included long-term lease agreements for 56,000 barrels of crude oil storage, two barge docks and a truck loading rack.
(b) FINANCIAL INFORMATION ABOUT SEGMENTS
See Part II, Item 8 -- Financial Statements and Supplementary Data.
(c) NARRATIVE DESCRIPTION OF BUSINESS
We were formed by The Williams Companies, Inc., which we sometimes refer to as Williams or WMB, to own, operate and acquire a diversified portfolio of complementary energy assets. We are principally engaged in the storage, transportation and distribution of refined petroleum products and ammonia. Our asset portfolio currently consists of:
- Five petroleum product terminal facilities located along the Gulf Coast and near the New York harbor. We refer to these facilities as our marine terminals.
- 25 petroleum product terminals (some of which are partially owned) located principally in the southeastern United States. We refer to these terminals as our inland terminals.
- An ammonia pipeline and terminals 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 and terminals system were transferred to us, including the related liabilities. We acquired an additional marine terminal and two additional inland terminals and sold one inland terminal during 2001.
PETROLEUM PRODUCT TERMINALS
The United States refined petroleum product distribution system links oil refineries to end-users of gasoline and other refined petroleum products. It is comprised of a network of terminals, storage facilities,
pipelines, tankers, barges, rail cars and trucks and is used to move refined petroleum products from refineries to the ultimate end-consumer. Throughout the distribution system, terminals play a key role in moving product to the end-user market by providing storage, distribution, blending and other ancillary services. Products stored in and distributed through our terminal network include:
- Refined Petroleum Products, which are the output from refineries and are often used as fuels for consumers. Refined petroleum products include gasoline, diesel, jet fuel, kerosene and heating oil.
- Blendstocks, which are blended with other products to change or enhance their characteristics such as increasing a gasoline's octane or oxygen content. Blendstocks include products such as 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 products such as number six fuel oil, vacuum gas oil and asphalt.
Within our terminal network, we operate two types of 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 and heavy oils and feedstocks. 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, who 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. Williams Energy Marketing & Trading Company and Williams Refining & Marketing, L.L.C., subsidiaries of The Williams Companies, Inc., utilize our facilities to support their business activities and are among our largest terminal customers. Williams Energy Marketing & Trading Company and Williams Refining & Marketing, L.L.C. represented approximately 13 percent and 9 percent, respectively, of our terminal's revenues and 11 percent and 7 percent, respectively, of our total revenues for the year ended December 31, 2001.
MARINE TERMINALS
The Gulf Coast region is a major hub for petroleum refining, representing approximately 42 percent of total U.S. daily refining capacity and 67 percent of U.S. refining capacity expansion from 1990 to 2000. The growth in Gulf Coast refining capacity has resulted in part from consolidation in the petroleum industry to take advantage of economies of scale from operating larger, concentrated refineries. We expect this trend to continue in order to meet growing domestic and international demand. From 1990 to 2000, the amount of petroleum products exported from the Gulf Coast region increased by approximately 18 percent, or 195 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, 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. In addition, in order to meet government specifications, products often must be combined with other products through the blending and mixing process. Blending is the combination of products from different storage tanks. Once the products are blended together, the mixing process circulates the blended product through mixing lines and nozzles to further combine the products. Finally, injection is the process of injecting refined petroleum products with additives and dyes to comply with governmental regulations and to meet our customer's marketing initiatives. We also provide marine vessel fueling services, referred to as bunkering.
Our terminals generate fees primarily through providing long term or spot on demand storage services and inventory management for a variety of customers. Refiners and chemical companies will typically use our facilities because their 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:
Galena Park Facility. Our Galena Park, Texas facility is located along the Houston Ship Channel and is one of the largest marine distribution facilities in the United States. It has 103 tanks with an aggregate storage capacity of 8.9 million barrels, two ship docks and three barge docks and includes a storage tank at Channelview, Texas. The facility stores a mix of refined petroleum products, blendstocks and heavy oils and feedstocks. We primarily receive products in this facility via barge, pipe and ship and distribute products from the facility via truck, barge, ship and pipeline.
Our Galena Park facility provides our customers with access to multiple common carrier pipelines, deep-water port facilities that accommodate both ship and barge traffic and loading and unloading facilities for trucks and rail cars. The facility has a 14-inch, 2.5-mile pipeline that runs under the Houston Ship Channel to the Witter Street Station. The Witter Street Station is a major pipeline junction that connects our facility to most major Gulf Coast refineries and common carrier pipelines such as the TEPPCO Partners, L.P. and El Paso Corporation pipelines. These refineries and pipelines provide marketers such as Valero Marketing and Supply Company, Koch Supply and Trading Company, CITGO Petroleum Corporation, El Paso Corporation and Shell Oil Company with opportunities to supply their retail and wholesale needs along our terminal network. We also own two 36-inch pipelines and one 14-inch pipeline that connect our facility to the Colonial and Explorer pipelines, providing distribution capacity to markets in the southeastern, east coast and
midwestern United States. We also own one active pipeline and several inactive pipelines that run to the Holland Avenue Station and connect our facility to Equistar Chemicals' petrochemical plant.
Corpus Christi Facility. Our Corpus Christi, Texas facility is located near four major refineries and one petrochemical plant. This facility includes 47 tanks with an aggregate storage capacity of 2.7 million barrels. We primarily receive products at our Corpus Christi facility by ship and barge through three docks owned by the Port of Corpus Christi, and we deliver product by barge, ship, truck and pipeline, including El Paso's common carrier pipeline with appropriate connections that transport products from Corpus Christi to Houston.
We provide inventory management and storage services for the refineries and petrochemical plants. We store blendstocks, heavy oils and feedstocks. Our Corpus Christi facility has pipeline connections to many of the local refineries including Koch, CITGO, El Paso and Equistar Chemicals' petrochemical plant.
Marrero Facility. Our Marrero, Louisiana facility is located adjacent to the Mississippi River and is 22 miles from the Port of New Orleans. This facility has 71 tanks with an aggregate storage capacity of 2.0 million barrels and three barge docks. We primarily receive products at our Marrero facility by ship and barge, and we deliver products from Marrero by rail, barge and truck. In addition, our facility is connected to a Texaco, Inc. terminal by four separate pipelines.
Our Marrero facility primarily stores heavy oils and feedstocks. Also, a major local refiner uses our facility to store its excess production.
Gibson Facility. Our Gibson, Louisiana facility is located adjacent to Bayou Black, a body of water which connects to the Intracoastal Waterway. The facility has five tanks with an aggregate storage capacity of 0.1 million barrels and two barge docks. The facility receives products by barge, pipeline and truck, and we primarily deliver products by pipeline.
Our Gibson terminal primarily stores and transports crude oil and condensate. The facility is connected to the Ship Shoal Pipeline system by one 8-inch pipeline and one 6-inch pipeline, both of which we own.
New Haven Facility. Our New Haven, Connecticut facility has four refined product terminals, the Waterfront, Forbes, 85 East and Hamden terminals, with an aggregate refined product storage capacity of 3.6 million barrels and asphalt tankage with 0.4 million barrels of storage capacity. Our New Haven facility receives product by ship and barge and distributes products by pipeline and truck. We also have the capability to deliver products via ship and barge.
Our Waterfront terminal has 0.8 million barrels of storage capacity and handles refined petroleum products. We receive products in this terminal via barge and ship, and we deliver products from the terminal via truck, barge and the Buckeye Pipeline. The Forbes terminal has 0.6 million barrels of storage capacity and handles refined petroleum products. The Forbes terminal is connected to the Waterfront terminal by four two-way 10-inch and 12-inch pipelines that we own. The 85 East terminal has 1.4 million barrels of storage capacity and handles refined petroleum products and asphalt. The Hamden terminal has 1.2 million barrels of storage capacity and handles refined petroleum products. The Hamden terminal is connected to the 85 East Terminal by a three mile 8-inch pipeline that we own.
Customers and Contracts. We have long-standing relationships with oil refiners, suppliers and traders at our facilities, and most of our customers have consistently renewed their short-term contracts. During 2001, approximately 89 percent of our marine terminal working storage capacity was under contract. As of December 31, 2001, approximately 44 percent of the revenues that we generated were from contracts with remaining terms in excess of one year or that renew on an annual basis. Williams Energy Marketing & Trading Company represented approximately 17 percent of revenues at our marine terminals for the year ended December 31, 2001. For a further discussion of revenues from major customers and concentration of credit risk, refer to Note 6 of the Consolidated Financial Statements.
Markets and Competition. We believe that the strong demand for our marine terminal facilities from our refining and chemical customers results from our cost-effective distribution services and key transportation links such as deep-water ports. We experience the greatest demand at our marine 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. The additional heating and blending services that we provide at our marine terminals, however, attract additional demand for our storage services and result in increased revenue opportunities.
Several major and integrated oil companies have their own proprietary storage terminals along the Gulf Coast that are currently being used in their refining operations. If these companies choose to shut down their refining operations and elect to store and distribute refined petroleum products through their proprietary terminals, we would experience increased competition for the services that we provide. In addition, several companies have facilities in the Gulf Coast region and offer competing storage and distribution services.
INLAND TERMINALS
We own and operate a network of 25 refined petroleum product terminals located primarily in the southeastern United States. These terminals have a combined storage capacity of 5.0 million barrels. Our customers utilize these facilities to take delivery of refined petroleum products transported on major common-carrier interstate pipelines. The majority of our inland terminals connect to the Colonial, Plantation, TEPPCO or Explorer pipelines, and some facilities have multiple pipeline connections. In addition, our Dallas terminal connects to Dallas Love Field airport via a 6-inch pipeline we purchased in April 2001. During 2001, gasoline represented approximately 53 percent of the volume of product distributed through our inland terminals, with the remaining 47 percent consisting of distillates such as low sulfur diesel and jet fuel.
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 through our virtual supply network and the ATLAS 2000 software system;
- distribution; and
- other services such as injection of gasoline additives.
We generate revenues by charging our customers a fee based on the amount of product that we deliver through our terminals. We charge these fees when we deliver the product to our customers and load it into a truck or rail car. In addition to throughput fees, we generate revenues by charging our customers a fee for injecting additives into gasoline, diesel and jet fuel, and for filtering jet fuel.
We wholly own 14 of these inland terminals and our percentage ownership of the remaining 11 inland terminals ranges from 50 percent to 79 percent. The following table sets forth our inland terminal locations, percentage ownership, capacities and methods of supply:
Our inland terminals are equipped with automated loading facilities that are available 24 hours a day. The Williams Companies, Inc.'s proprietary ATLAS 2000 software system allows us to manage inventory across our inland terminal network and bill our customers electronically. The ATLAS system provides our customers with the ability to manage, among other things, inventory allocations, throughput and carrier certification from remote locations. Our customers can access the ATLAS system via the internet. Under our omnibus agreement, The Williams Companies, Inc. and its affiliates have licensed the use of the ATLAS 2000 software system to us. See Item 13 -- Certain Relationships and Related Transactions.
Customers and Contracts. All but four of our inland terminals were acquired by The Williams Companies, Inc. over a period of five years, beginning with the acquisition of interests in eight terminals in 1996. When The Williams Companies, Inc. acquired the new terminals, it generally entered into long-term
throughput contracts with the sellers under which they agreed to continue to use the facilities. These agreements typically last for two to ten years from the beginning of the agreement, and must be renegotiated at the end of the term. In addition to these agreements, we 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 provision that obligates the customer to move a minimum amount of product through our terminals or pay for terminal capacity reserved but not used. Our customers include:
- retailers that sell gasoline and other petroleum products through proprietary retail networks;
- wholesalers that sell petroleum products to retailers as well as to large commercial and industrial end-users;
- exchange transaction customers, where we act as an intermediary so that the parties to the transaction are able to exchange petroleum products; and
- traders that arbitrage, trade and market products stored in our terminals.
For the year ended December 31, 2001, Williams Refining & Marketing, L.L.C. accounted for approximately 38 percent of our inland terminal revenues. For a further discussion of revenues from major customers and concentration of credit risk, refer to Note 6 to the Consolidated Financial Statements.
Markets and Competition. We compete with other independent terminal operators as well as integrated oil companies on the basis of terminal location and versatility, services provided and price. Our competition from independent operators primarily comes from distribution companies with marketing and trading arms, independent terminal operators and refining and marketing companies.
AMMONIA PIPELINE AND TERMINALS SYSTEM
We own and operate a 1,100-mile pipeline and terminals 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.
Although ammonia consumption peaks in the fall and early spring, ammonia production is reasonably consistent throughout the year. Generally, storage facilities reach their peak storage capacities during early spring, prior to agricultural application. As a result, we experience only limited seasonal fluctuations for transportation services on our pipeline. Our customers inject the ammonia they produce into our pipeline, and we transport it as a liquid to terminal facilities and storage and upgrade facilities located in the Midwest.
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 were significantly higher than historical levels between 1999 and the first six months of 2001. As a result, our customers substantially curtailed their production of ammonia and shipped lower volumes of ammonia on our pipeline. However, our shippers have committed to minimum shipping agreements of an aggregate of 700,000 tons per year through June 2005.
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 94 percent 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.
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.
Customers and Contracts. We ship ammonia for three customers:
- Farmland Industries, Inc., one of the largest farmer-owned cooperatives in the United States;
- Agrium U.S. Inc., a subsidiary of Agrium Inc., the largest producer of nitrogen fertilizers in North America; and
- Terra Nitrogen, L.P., a wholesaler of nitrogen fertilizer products.
Each of these companies has an ammonia production facility connected to our pipeline as well as related storage and distribution facilities along the pipeline. The transportation contracts with our customers extend through June 2005. Our customers are obligated to ship an aggregate minimum of 700,000 tons per year and have historically shipped an amount in excess of the required minimum. Our customers have been shipping ammonia through our pipeline for an average of more than 20 years.
Each transportation contract contains a ship or pay mechanism, whereby each customer must ship a specific minimum tonnage per year and an aggregate minimum tonnage 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 78 percent of our pipeline's 900,000 ton per year capacity. If a customer fails to ship its annual commitment, that customer must pay for the pipeline capacity it did not use.
In general, our customers have historically shipped ammonia in excess of their annual commitments. We allow our customers to bank any ammonia shipped in excess of their annual commitments. If a customer has previously shipped an amount in excess of its annual commitment, the shipper may offset subsequent annual shipment shortfalls against the excess tonnage in its bank. There are approximately 115,000 tons in this combined bank that may be used to offset future ship or pay obligations.
The transportation contracts establish a fixed tariff schedule per ton of ammonia shipped for each customer for the first five years of the contract period. Because of the long-term nature of these contracts, the shippers receive a volume incentive tariff per ton that decreases with increased commitments. Since July 1, 2000, we have had the right to adjust our tariff schedule on an annual basis pursuant to a formula contained in the contracts. The adjustment formula takes into consideration the cost of labor, power, property taxes and changes in the producer price index. We use the combined increase or decrease in these factors to calculate any increases or decreases in tariffs. Any annual adjustment is limited to a maximum increase or decrease of five percent measured against the rate previously in effect. These tariff adjustments cannot decrease the tariffs to rates less than those charged in 1997.
Two of our three customers have credit ratings below investment grade. For a further discussion of revenues from major customers and concentrations of credit risk, refer to Note 6 of the Consolidated Financial Statements.
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 and terminals system with the other United States ammonia pipeline, which originates on the Gulf Coast and transports domestically produced and imported ammonia.
TARIFF REGULATION
Interstate Regulation
The Surface Transportation Board, 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.
Intrastate Regulation
Because in some instances we transport ammonia between two terminals in the same state, our 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.
SAFETY AND MAINTENANCE
We monitor our marine terminals, inland terminals and ammonia pipeline and terminals system on a regular basis to ensure reliability, safety and efficiency of our assets. We believe that our assets have been constructed and are maintained in all material respects in accordance with applicable federal, state and local laws, including, where applicable, the regulations of the Department of Transportation, and accepted industry standards.
ENVIRONMENTAL
General
Our operation of terminals and associated facilities in connection with the storage and transportation of crude oil and other liquid hydrocarbons, together with our operation of an ammonia pipeline, are subject to stringent and complex laws and regulations governing the discharge of materials into the environment or otherwise relating 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. As with the industry generally, our compliance with existing and anticipated laws and regulations increases the cost of planning, constructing and operating our terminals, pipeline and other facilities. Included in our construction and operation costs are 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 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 provide assurance that the cost to comply with these laws and regulations in the future will not have a material adverse effect on our financial position or results of operations.
Indemnification
Williams Energy Services, LLC has agreed to indemnify us for up to $15.0 million for environmental liabilities that exceed the amounts covered by the seller indemnities and insurance coverage described below. The indemnity applies to environmental liabilities arising from conduct prior to 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.
In accordance with our acquisition agreement with Amerada Hess Corporation, Hess will indemnify us for environmental and other liabilities related to the three Gulf Coast marine terminals we acquired from them in August 1999, including:
- Indemnification for specified 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 terminals. This indemnity has no limit and will remain in effect until July 30, 2014.
- Indemnification for a variety of pre-acquisition fines and claims that may be imposed or asserted under the Superfund Law and federal Resource Conservation and Recovery Act ("RCRA") or analogous state laws. 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 a cooling tower at the Corpus Christi, Texas terminal and a vapor recovery unit and process safety management compliance matter at the Galena Park, Texas terminal.
We have insurance against the first $2.5 million of environmental liabilities related to the Hess terminals 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 $50.0 million.
In connection with the acquisition of the New Haven, Connecticut marine terminal facility acquired from Wyatt Energy, Incorporated and the acquisitions of our inland terminals, the sellers of those terminals agreed to indemnify us against specified environmental liabilities. We also have insurance until August 31, 2005 for up to $25.0 million of environmental liabilities for the New Haven marine terminal facility, with a deductible of $0.3 million.
Hazardous Substances and Wastes
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 our petroleum products terminals in Mobile, Alabama; New Haven, Connecticut; Doraville and South Albany, Georgia; Gibson, Louisiana; St. Charles, Missouri; Greensboro and Selma, North Carolina; North Augusta, South Carolina; Nashville, Tennessee; Dallas and Galena Park, Texas; and Montvale and Richmond, Virginia. Similar operations are also being conducted at an ammonia terminal facility in Early, Iowa and along our ammonia pipeline in Valley, Nebraska and Noble County, Oklahoma. We expect to conduct a number of these investigatory and cleanup activities at an estimated cost of $5.4 million, and we have recognized a liability for that amount. Of that liability, $5.1 million is expected to be recoverable from affiliates or third parties pursuant to contractual requirements. In other instances, prior owners or operators of these properties are performing or are expected to perform these activities pursuant to contractual requirements that make these prior owners or operators responsible for performing the activities.
Aboveground Storage Tanks
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. Although there is not currently a federal statute dedicated to regulating these above ground tanks, there is a possibility that a law could one day be passed in the United States. 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 in Charlotte and Selma, North Carolina and Nashville, Tennessee 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.
Water Discharges
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. We have determined that the secondary containment surrounding above ground tanks at our Galena Park, Texas, terminal requires upgrading to comply with the law, at an estimated cost of $0.1 million. 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 our terminals in Selma, North Carolina and North Augusta, South Carolina, we are resolving these exceedances by electing to make capital improvements to the wastewater handling system at Selma at an estimated cost of $0.1 million and by discontinuing wastewater discharges at the North Augusta terminal. In addition, similar capital expenditures to improve wastewater handling systems are expected to be made to comply with applicable laws at our terminal in Galena Park, Texas, at an estimated cost of $0.4 million. We do not expect our compliance with existing permits and foreseeable new permit requirements, nor any of the estimated capital expenditures to upgrade or replace existing wastewater handling systems to have a material adverse effect on our financial position or results of operations.
Air Emissions
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 also expect that changes to the state implementation plans pertaining to air quality in regional, non-attainment areas will have an impact on our terminals in Doraville, Georgia and Galena Park and Dallas, Texas, possibly resulting in the need to upgrade air pollution control equipment. 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. Nevertheless, we anticipate making capital improvements involving modification or repair of roofs and seals on certain of our tanks at Galena Park, Texas and Corpus Christi, Texas to comply with applicable law, at a total estimated cost of $0.5 million. In addition, we previously received a notice of violation for air permitting issues relating to operation of a vapor recovery unit at our terminal in Galena Park, Texas. The alleged violation commenced while the property was operated by Hess and continued after The Williams Companies, Inc.'s acquisition of the property. In order to optimize our vapor recovery compliance, we have acquired a vapor combustion unit which is in the final stages of testing. If any penalties are imposed on us as a result of the assessed notice of violation that relates to ownership or operation of the vapor recovery unit, then Hess has agreed to reimburse us for costs arising prior to December 19, 2000. 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.
EMPLOYEE SAFETY
We are subject to the requirements of the federal Occupational Safety and Health Act, or 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.
TITLE TO PROPERTIES
Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of this property. The rights-of-way for our ammonia pipelines are shared with other pipelines owned by affiliates of The Williams Companies, Inc. In some instances these rights-of-way are revocable at the election of the grantor. In many instances, lands over which rights-of-way have been obtained are subject to prior liens which have not been subordinated to the right-of-way grants. In some cases, not all of the apparent record owners have joined in the right-of-way grants. We have obtained permits from public authorities to cross over or under, or to lay facilities in or along water courses, county roads, municipal streets and state highways, and in some instances, these permits are revocable at the election of the grantor. We have also obtained permits from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor's election. In some cases, property for pipeline purposes was purchased in fee. We have the right of eminent domain to acquire rights-of-way and lands necessary for our ammonia pipeline. However, the original owner of the pipeline may not have concluded eminent domain proceedings for some rights-of-way.
Some of the leases, easements, rights-of-way, permits and licenses transferred to us, upon the completion of our initial public offering in February 2001, required the consent of the grantor to transfer these rights, which in some instances is a governmental entity. We have obtained substantially all required third-party consents, permits and authorizations sufficient for the transfer to us of the assets necessary for us to operate our business in all material respects. Failure to obtain such consents, permits or authorizations should not have a material adverse effect on the operation of our business.
We have sufficient title to all of our assets subject to the limitations described in this section, or we are entitled to indemnification from affiliates of The Williams Companies, Inc. for right-of-way defects or failures under the omnibus agreement. 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 related to environmental liabilities associated with historical operations, liens for current taxes and other burdens and minor easements, restrictions and other encumbrances to which the underlying properties were subject at the time of acquisition by our predecessor or us, none of these burdens should materially detract from the value of our properties or from our interest in them or materially interfere with their use in the operation of our business.
EMPLOYEES
To carry out our operations, our general partner or its affiliates employ approximately 195 people who provide direct support to our operations. Other than at our Galena Park marine terminal facility, none of these employees are represented by labor unions. The employees at our Galena Park marine terminal facility are currently represented by a union, but have indicated their unanimous desire to terminate their union affiliation. Nevertheless, the National Labor Relations Board has ordered us to bargain with the union as the exclusive collective bargaining representative of the employees at the facility. We are appealing this decision. If our appeal is unsuccessful, we will bargain with the union as ordered by the National Labor Relations Board. Our general partner considers its employee relations to be good.
FORWARD-LOOKING STATEMENTS
Certain matters discussed in this report, excluding historical information, 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:
- Changes in demand for refined petroleum products that we store and distribute;
- Changes in demand for storage in our petroleum product terminals;
- Changes in the throughput on petroleum product pipelines owned and operated by third parties and connected to our petroleum product terminals;
- Loss of Williams Energy Marketing & Trading and/or Williams Refining & Marketing, L.L.C. as customers;
- Loss of one or all of our three customers on our ammonia pipeline and terminals system;
- An increase in the price of natural gas, which increases ammonia production costs and reduces the amount of ammonia transported through our ammonia pipeline and terminals system;
- Changes in the federal government's policy regarding farm subsidies, which negatively impact the demand for ammonia and reduce the amount of ammonia transported through our ammonia pipeline and terminals system;
- An increase in the competition our petroleum products terminals and ammonia pipeline and terminals system encounter;
- The occurrence of an operational hazard or unforeseen interruption for which we are not adequately insured;
- 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 ability to raise capital in a cost-effective way;
- The effect of changes in accounting policies;
- The ability to manage rapid growth;
- The ability to control costs;
- Supply disruption; and
- Global and domestic economic repercussions from terrorist activities and the government's response thereto.
(d) FINANCIAL INFORMATION ABOUT GEOGRAPHICAL AREAS
We have no revenue or segment profit or loss attributable to international activities.
ITEM 2.
ITEM 2. PROPERTIES
See Item 1(c) for a description of the locations and general character of our material properties.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
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.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of the unitholders, through solicitation of proxies or otherwise, during the fiscal year covered by this report.
PART II
ITEM 5.
ITEM 5.MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Our common units are listed on the New York Stock Exchange under the symbol "WEG". At the close of business on February 28, 2002, we had 51 holders of record of our common units. The high and low closing sales price ranges (composite transactions) and distributions declared by quarter for 2001 since the close of our initial public offering on February 9, 2001 are as follows:
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* Distributions declared 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.
We have also issued subordinated units, all of which are held by two affiliates of our general partner, for which there is no established public trading market.
During the subordination period, the holders of our common 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 percent 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 units and the subordinated units may be converted into common units.
During the subordination period, our cash is distributed first 98 percent to the holders of common units and 2 percent to our general partner until there has been distributed to the holders of common units an amount equal to the minimum quarterly distribution and arrearages in the payment of the minimum quarterly distribution on the common units for any prior quarter. Any additional cash is distributed 98 percent to the holders of subordinated units and 2 percent 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 as 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 $0.59 per unit. In general, we intend to continue to pay comparable cash distributions in the future assuming no adverse change in our operations, economic conditions and other factors. We cannot guarantee that future distributions, if any, will continue at such levels.
USE OF PROCEEDS
On February 5, 2001, our Registration Statement on Form S-1 (Registration No. 333-48866) with the Securities and Exchange Commission became effective. The managing underwriter for this transaction was Lehman Brothers Inc. Under the registration statement, we issued 5,679,694 common units and 5,679,694 subordinated units, of which 1,679,694 common units and all of the subordinated units were issued to affiliates of our general partner.
The closing date of our initial public offering was February 9, 2001, and on that date we sold 4,000,000 common units to the public at a price of $21.50 per unit, or $86.0 million. Underwriter commissions on this sale were $5.6 million. In addition, concurrent with the closing of the initial public offering, we borrowed $90.1 million under a credit facility with Bank of America and incurred $0.9 million of debt issuance costs. Subsequent to the initial public offering, the underwriters exercised in full their over-allotment option and purchased an additional 600,000 common units for $12.9 million. Underwriter commissions on this sale were $0.8 million. The aggregate offering price of the common units (including the over-allotment) was $98.9 million.
Net proceeds from the sale of common units, after underwriter commissions, were $92.5 million, and net proceeds from the borrowings under the credit facility with Bank of America were $89.2 million, for total net proceeds of $181.7 million. We used $3.1 million of the net proceeds to pay legal, accounting and other professional services costs associated with the initial public offering. Another $12.1 million of the proceeds was used to redeem 600,000 common units from Williams Energy Services, LLC, an affiliate of our general partner, to reimburse it for capital expenditures related to our assets. The remaining proceeds of $166.5 million were used to reduce affiliate note balances with Williams.
ITEM 6.
ITEM 6.
SELECTED FINANCIAL AND OPERATING DATA (IN THOUSANDS, EXCEPT OPERATING STATISTICS AND PER UNIT AMOUNTS)
The historical financial information presented below for Williams Energy Partners L.P. was derived from our audited consolidated financial statements as of December 31, 2001 and 2000 and for the three years ended December 31, 2001. 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 on pages 20 through 33 of this report.
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(a) From 1999 to February 9, 2001, interest income and expense was allocated to the terminal and ammonia operations based upon their actual affiliate note receivable or payable balance. After February 9, 2001, interest expense is based on our outstanding debt balance.
(b) Management believes that excluding the affiliate note receivable, but not the affiliate accounts receivable, from working capital provides a more appropriate comparative representation of working capital. The affiliate note receivable and payable result from our long-term involvement in Williams' cash management program. The notes were due on demand; however, in February 2001, we borrowed $90.1 million under a credit facility, which expires in February 2004 and issued 4,000,000 common units in our Partnership in an initial public offering for net proceeds, after underwriter commissions, of $80.4 million. An additional 600,000 common units were sold subsequent to the initial public offering when the underwriters exercised their over-allotment option. Net proceeds of $12.1 million from this sale were used to redeem 600,000 common units held by Williams Energy Services, LLC to reimburse it for capital expenditures related to our assets. The remaining affiliate note payable was contributed to us as a capital contribution by an affiliate of Williams. As a result, the affiliate note payable at December 31, 2000 and 1999, have been classified as long-term.
(c) Cash distributions declared for 2001 include a pro-rated distribution for the first quarter which included the period from February 10, 2001 through March 31, 2001. The cash distribution associated with the fourth quarter of 2001 was declared on January 22, 2002 and paid on February 14, 2002.
(d) EBITDA is defined as earnings before interest expense, income taxes and depreciation and amortization expense.
(e) For the year ended December 31, 1999, represents the average storage capacity utilized per month for the Gulf Coast marine terminals for the five months that we owned these assets in 1999. For the year ended December 31, 2000, represents the twelve month average storage capacity utilized for the Gulf Coast facilities (11.8 million barrels) and the four months that we owned the New Haven, Connecticut facility in 2000 (2.9 million barrels). For the year ended December 31, 2001, represents the average storage capacity utilized for the Gulf Coast facilities (12.7 million barrels) and the New Haven, Connecticut facility (3.0 million barrels).
(f) For the year ended December 31, 2000, represents activity at the New Haven, Connecticut facility, which was acquired in September 2000. For the year ended December 31, 2001, represents a full year of activity for the New Haven facility (9.3 million barrels) and two months of activity at the Gibson, Louisiana facility (2.2 million barrels), which was acquired on October 31, 2001.
ITEM 7.
ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
Williams Energy Partners L.P. is a Delaware limited partnership formed by The Williams Companies, Inc. in August 2000 to own, operate and acquire a diversified portfolio of complementary energy assets. We are principally engaged in the storage, transportation and distribution of refined petroleum products and ammonia. Our current asset portfolio consists of:
- five marine terminal facilities;
- 25 inland terminals (some of which are partially owned); and
- an ammonia pipeline and terminals system.
Most of these assets were acquired and owned by several wholly-owned subsidiaries of The Williams Companies, Inc. prior to our initial public offering ("IPO"). Upon the closing of our initial public offering on February 9, 2001, these assets were transferred to Williams Energy Partners L.P., including the related liabilities. The following discussion has been prepared as if the assets were operated as a stand-alone business throughout the periods presented.
OVERVIEW
Our marine terminal facilities, which are large product storage facilities, generate revenues primarily from fees that we charge customers for storage and throughput services. Our inland terminals earn revenues primarily from fees that we charge based on the volumes of refined petroleum products distributed from our terminals. Our inland terminals also earn ancillary revenues from injecting additives into gasoline and jet fuel, from filtering jet fuel and from rental income. Also included in ancillary revenues is the gain or loss resulting from differences in metered-versus-physical volumes of refined petroleum products received at our terminals. Our ammonia pipeline and terminals system earns the majority of its revenue from transportation tariffs that we charge for transporting ammonia through our pipeline.
Operating costs and expenses we incur in our marine and inland terminals are principally fixed costs related to routine maintenance as well as field and support personnel. Other costs, including fuel and power, fluctuate with storage capacity or throughput levels. Generally, most of the operating costs for our ammonia pipeline and terminals system fluctuate with the volume of ammonia transported through our pipeline.
The Williams Companies, Inc. allocates both indirect and direct general and administrative expenses to its subsidiaries. Indirect expenses, including legal, accounting, treasury, engineering, information technology and other corporate services, are based on a calculation that compares a combination of operating margins, payroll costs and property, plant and equipment to The Williams Companies, Inc. and its subsidiaries. Historically, the amount of indirect general and administrative expenses allocated to us increased as the relative size of our operations compared to The Williams Companies, Inc.'s operations increased. Direct expenses allocated by The Williams Companies, Inc. are primarily salaries and benefits of employees, officers and directors associated with the business activities of the subsidiary. We will reimburse our general partner and its affiliates for indirect and direct expenses they incur on our behalf. We agreed with our general partner, subject to future acquisitions or other changes in the business, that the general and administrative expenses to be reimbursed will not exceed $6.0 million for 2001, excluding expenses associated with the Partnership's Long-Term Incentive Plan, even though the direct and allocated general and administrative costs incurred by the general partner were significantly higher. As a result of the acquisitions made during 2001, the amount of general and administrative expenses charged to us increased to $6.3 million. Including the 7 percent escalation amount, the annual general and administrative expense charge increased to $6.7 million beginning in January 2002.
We have little direct exposure to commodity price fluctuations since we do not trade commodities. However, our operations can be indirectly affected by overall price trends for the products we handle. During periods when the price of a product is lower today than the price available through the forward pricing market, the market for that product is said to be in "contango." A contango market is favorable to our marine terminal facilities because this market condition incentivizes customers to store product in the near term to take advantage of expected higher future prices. Conversely, when the price of a product today is higher than the price available through the forward pricing market, the market is said to be "backwardated." In a backwardated market, customers are less likely to store product because market conditions incentivize them to sell as much product as possible to take advantage of higher current prices. The forward pricing market for petroleum products became backwardated in the second quarter of 1999 and remained so through second quarter 2001, contributing to reduced storage revenues during that time. The market reversed to contango during the latter half of 2001 and remained so through 2001, contributing to increased storage revenues. We cannot predict whether the current contango market will continue.
ACQUISITION HISTORY
We are principally engaged in the storage, transportation and distribution of refined petroleum products and ammonia. We materially increased our operations through a series of transactions, including:
- 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 one marine crude oil terminal facility located in Gibson, Louisiana from Geonet Gathering, Inc.;
- in June 2001, the acquisition of two inland refined petroleum product terminals in Little Rock, Arkansas from TransMontaigne, Inc.;
- in April 2001, the acquisition of a refined petroleum product pipeline located in Dallas, Texas from Equilon Pipeline Company LLC;
- in September 2000, the acquisition of one marine refined petroleum product terminal facility located in New Haven, Connecticut from Wyatt Energy, Incorporated;
- in March 2000, the acquisition of a 50.0 percent ownership interest in one inland refined petroleum product terminal in Southlake, Texas from CITGO Petroleum Corporation;
- in August 1999, the acquisition of three marine refined petroleum product terminal facilities, located in Galena Park and Corpus Christi, Texas and Marrero, Louisiana from Amerada Hess Corporation;
- in February 1999, the acquisition of an additional 10.0 percent interest in eight inland refined petroleum product terminals located in Georgia, North Carolina, South Carolina, Tennessee and Virginia from Murphy Oil USA, Inc., which increased our ownership percentage in these terminals to 78.9 percent; and
- in January 1999, the acquisition of 12 inland refined petroleum product terminals, located in Alabama, Florida, Mississippi, North Carolina, Ohio, South Carolina and Tennessee from Amoco Oil Company.
RESULTS OF OPERATIONS
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
FINANCIAL HIGHLIGHTS
OPERATING STATISTICS
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(a) For the year ended December 31, 2000, represents the twelve-month average storage capacity utilized for the Gulf Coast marine terminal facilities (11.8) and the four months that we owned the New Haven, Connecticut facility in 2000 (2.9). For the year ended December 31, 2001, represents the average storage capacity utilized for the Gulf Coast facilities (12.7) and the New Haven facility (3.0).
(b) For the year ended December 31, 2000, represents four months of activity at the New Haven, Connecticut facility, which was acquired in September 2000. For the year ended December 31, 2001, represents a full year of activity at the New Haven facility (9.3) and two months of activity at the Gibson, Louisiana facility (2.2), which was acquired on October 31, 2001.
Our combined revenues for the year ended December 31, 2001 were $86.1 million compared to $72.5 million for the year ended December 31, 2000, an increase of $13.6 million, or 19 percent. This increase was a result of:
- an increase in petroleum product terminals revenues of $10.7 million, or 18 percent, due to the following:
- an increase in the marine terminal facilities revenues of $11.2 million, from $44.1 million to $55.3 million. This increase reflects increased volumes as a result of our acquisitions of the New Haven, Connecticut facility in September 2000 and the Gibson, Louisiana facility in October 2001. In addition, the increase was due to a 0.9 million barrel per month higher utilization at our Gulf Coast marine facilities due to an improved marketing environment. Included in 2001 revenue is a $0.5 million decrease from $9.9 million in 2000 to $9.4 million in 2001 from Williams Energy Marketing & Trading, an affiliate of our general partner, which utilizes our facilities in connection with their trading business; and
- a decrease in inland terminal revenues of $0.5 million, from $16.7 million to $16.2 million primarily due to the December 2000 expiration of a customer's contractual commitment to utilize a specific amount of throughput capacity. The customer contract that expired was executed in January 1999 in conjunction with the acquisition of 12 inland terminals. These revenue decreases were partially offset by additional revenues from the acquisition of two inland terminals in Little Rock, Arkansas on June 30, 2001. Included in this revenue is a $1.0 million decrease from $7.5 million in 2000 to $6.5 million in 2001 from Williams Refining & Marketing and Williams Energy Marketing & Trading; affiliates of our general partner, which utilize our facilities in connection with their trading business;
- an increase in ammonia pipeline and terminals system revenues of $2.9 million, or 25 percent. Part of the increase is due to a $1.3 million throughput deficiency billing resulting from a shipper not meeting its minimum annual throughput commitment for the contract year ended June 2001. However, favorable conditions were experienced primarily during the fourth quarter of 2001 for the application of ammonia, resulting in a 50,000 ton, or 7 percent, increase in pipeline volume shipped compared to 2000. Unusually warm weather during the fall season resulted in higher demand for ammonia application on agricultural fields. In addition, the price of natural gas, the primary component for the production of ammonia, declined to more historical levels, resulting in our customers electing to produce and ship more ammonia through our pipeline to meet increased demand and replenish inventories. Tariffs also increased by $0.71 per ton, from a weighted-average tariff of $15.50 per ton for 2000 compared to a tariff of $16.21 per ton for 2001. The increase in the weighted-average tariff resulted from the annual mid-year indexing adjustments allowed under the transportation agreements.
Operating expenses for the year ended December 31, 2001 were $37.3 million compared to $33.5 million for the year ended December 31, 2000, an increase of $3.8 million, or 11 percent. This increase was a result of:
- an increase in petroleum product terminals expenses of $3.8 million, or 13 percent, due to:
- an increase in marine terminal facilities expenses of $3.0 million, from $21.2 million to $24.2 million, primarily due to the acquisition and assimilation of the New Haven, Connecticut facility which was acquired in September 2000 and the Gibson, Louisiana facility which was acquired in late October 2001. Expenses at the Gulf Coast facilities increased slightly due to higher utility costs, partially offset by lower environmental and maintenance expenses; and
- an increase in inland terminal expenses of $0.8 million, from $8.3 million to $9.1 million. Expenses primarily increased due to the acquisition of the Little Rock, Arkansas terminals in June 2001 as well as increased property taxes at some of our other inland terminal locations;
- ammonia pipeline and terminals system operating costs were unchanged, as reduced property taxes offset slightly higher environmental accruals.
Depreciation expense for the year ended December 31, 2001 was $11.7 million compared to $9.3 million for the year ended December 31, 2000, an increase of $2.4 million, or 26 percent. This increase primarily resulted from a full year of depreciation related to the New Haven, Connecticut marine facility acquired in September 2000, the acquisitions of the two Little Rock, Arkansas inland terminals in June 2001 and the Gibson, Louisiana marine facility in October 2001.
General and administrative expenses for the year ended December 31, 2001 were $9.0 million compared to $12.0 million for the year ended December 31, 2000, a decrease of $3.0 million, or 25 percent. This decrease is a result of the general and administrative expense limit of $6.0 million per year established in the Omnibus Agreement at the time of the initial public offering. General and administrative expense for the current year includes the established limit plus additional general and administrative costs associated with businesses acquired during 2001 and incentive compensation expenses related to the Partnership's performance. Costs associated with the Long-Term Incentive Plan were $2.0 million in 2001 and are specifically excluded from the $6.0 million annual general and administrative expense. The limit on general and administrative expense that can be charged by our general partner to the Partnership will continue to be adjusted in the future to
reflect inflation and additional direct general and administrative expenses associated with completed acquisitions.
Interest expense for the year ended December 31, 2001 was $6.9 million compared to $12.8 million for the year ended December 31, 2000. The decline in interest was primarily related to the partial payment and cancellation of an affiliate note in connection with the closing of the initial public offering of Williams Energy Partners on February 9, 2001, and lower interest rates. Concurrent with the closing of our offering, we borrowed $90.1 million under our term loan facility and revolving credit facility. At the end of 2001, $90.0 million was still outstanding under the term loan as well as $49.5 million under the revolving credit facility due to the acquisition of the Little Rock, Arkansas terminals and the Gibson, Louisiana facility.
We do not pay income taxes because we are a partnership. We based our income tax provision for the pre-initial public offering earnings upon the effective income tax rate for The Williams Companies, Inc. for those periods of 38.0 percent. 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, 2001 was $21.7 million compared to $3.0 million for the year ended December 31, 2000, an increase of $18.7 million, or 623 percent. Our operating margin increased by $9.8 million during the period, primarily as a result of the acquisitions of the New Haven, Little Rock and Gibson terminal facilities. Operating margin further increased due to enhanced utilization of our Gulf Coast marine facilities and increased revenues from our ammonia pipeline and terminals system. While depreciation increased by $2.4 million, general and administrative expenses and interest declined by $8.9 million. In addition, other income of $1.0 million was reported to recognize the gain on the sale of the Meridian, Mississippi inland terminal in October 2001. Minority interest expense increased by $0.2 million but income taxes declined by $1.6 million as a result of the Partnership not paying taxes after the initial public offering closing on February 9, 2001.
Year Ended December 31, 2000 Compared to Year Ended December 31, 1999
FINANCIAL HIGHLIGHTS
OPERATING STATISTICS
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(a) 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 twelve-month average storage capacity utilized for the Gulf Coast facilities (11.8) and the four months that we owned the New Haven, Connecticut facility in 2000 (2.9).
(b) Represents four months of activity at the New Haven, Connecticut facility, which was acquired in September 2000.
Our combined revenues for the year ended December 31, 2000 were $72.5 million compared to $44.4 million for the year ended December 31, 1999, an increase of $28.1 million, or 63 percent. This increase was a result of:
- an increase in petroleum product terminals revenues of $28.5 million, or 88 percent, due to the following:
- an increase in the marine terminal facilities revenues of $28.3 million, from $15.8 million to $44.1 million. This increase reflects increased volumes as a result of our acquisition of the Gulf Coast facilities in August 1999, a 1.7 million barrel per month increase in utilization of the Gulf Coast facilities and the acquisition of the New Haven, Connecticut facility in September 2000. Slightly offsetting these increases was a storage revenue rate decline at the Gulf Coast facilities of approximately $.015 per barrel as a result of a revenue deficiency billing associated with the purchase of the Gulf Coast terminal facilities from Amerada Hess ending in July 2000. Included in the 2000 revenue is a $7.5 million increase from $2.4 million in 1999 to $9.9 million in 2000 from Williams Energy Marketing & Trading, an affiliate of our general partner, which utilizes our facilities in connection with its trading business; and
- an increase in inland terminal revenues of $0.2 million, from $16.5 million to $16.7 million, as increased ancillary revenues more than offset reduced throughput revenues resulting from a decline in throughput volumes of 2.0 million barrels. Our throughput volume decreased primarily because of the gradual reduction, beginning in January 2000, of a customer's contractual commitment to utilize a specific amount of throughput capacity. This contract was entered into in January 1999 in connection with our acquisition of 12 inland terminals. This volume reduction was partially offset by a volume increase resulting from the Southlake, Texas terminal acquisition in March 2000 and increased marketing activity by Williams Energy Marketing & Trading. Included in this revenue is a $3.0 million increase from $4.5 million in 1999 to $7.5 million in 2000 from Williams Energy Marketing & Trading.
- ammonia pipeline and terminals system revenues declined by $0.4 million, or 3 percent, primarily due to a 82,000 ton, or 10 percent, reduction of ammonia shipped through our pipeline. This decline was due to lower product demand as well as the continuing impact of higher prices for natural gas, the primary component for the production of ammonia. Wet weather during the 2000 spring planting season resulted in reduced farm demand for ammonia. Further, due to higher natural gas prices, our customers elected to produce and transport lower quantities of ammonia and to draw more ammonia from their existing inventories to meet demand. This volume decline was partially offset by a higher weighted average tariff of $15.50 per ton for 2000 compared to a tariff of $14.74 per ton for 1999. The increase in the weighted average tariff resulted from the 2000 mid-year indexing adjustment allowed under the transportation agreements as well as the expiration of a discount received by one of our customers.
Operating expenses for the year ended December 31, 2000 were $33.5 million compared to $18.6 million for the year ended December 31, 1999, an increase of $14.9 million, or 80 percent. This increase was a result of:
- an increase in petroleum product terminals expenses of $14.4 million, or 95 percent, due to:
- an increase in marine terminal facilities expenses of $15.2 million, from $6.0 million to $21.2 million, due to the acquisition and assimilation of the Gulf Coast facilities, which were acquired in August 1999 and the New Haven, Connecticut facility which was acquired in September 2000; and
- a decrease in inland terminal expenses of $0.8 million, from $9.1 million to $8.3 million, primarily resulting from a decrease in environmental expenses associated with a system-wide environmental evaluation in 1999, decreases in employee relocation expenses associated with 12 terminals acquired in 1999 and a decrease in utility expenses as a result of lower throughput volumes. These reductions were slightly offset by increased costs related to our Southlake, Texas terminal acquired in March, 2000;
- ammonia pipeline and terminals system operating costs increased $0.5 million, or 14 percent, primarily due to increased utility costs as a result of higher natural gas prices.
Depreciation expense for the year ended December 31, 2000 was $9.3 million compared to $4.6 million for the year ended December 31, 1999, an increase of $4.7 million, or 102 percent. This increase primarily resulted from a full year of depreciation related to the Gulf Coast marine facilities acquired in August 1999 and the acquisition of the New Haven, Connecticut marine facility in September 2000.
General and administrative expenses for the year ended December 31, 2000 were $12.0 million compared to $5.5 million for the year ended December 31, 1999, an increase of $6.5 million, or 118 percent. This increase resulted principally from the acquisition of the Gulf Coast marine facilities and the New Haven, Connecticut marine facility. As a result of these acquisitions, the percentage increase of our asset growth was greater than the percentage increase of the growth in assets of The Williams Companies, Inc. and its subsidiaries. Therefore, The Williams Companies, Inc. allocated more general and administrative expenses to us.
Affiliate interest expense for the year ended December 31, 2000 was $12.8 million compared to $4.8 million for the year ended December 31, 1999. A significant portion of this increase can be attributed to carrying twelve months of debt in 2000 related to the acquisition of the Gulf Coast marine facilities in August 1999 and the acquisition of the New Haven, Connecticut facility in September 2000.
We based our income tax provision for 2000 and 1999 upon the effective income tax rate for The Williams Companies, Inc. for those periods of 38.0 percent. 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, 2000 was $3.0 million compared to $6.8 million for the year ended December 31, 1999, a decrease of $3.8 million, or 56 percent. While the operating margin increased by $13.2 million during the period, this was more than offset by an $11.2 million increase in depreciation and general and administrative expenses and an $8.0 million increase in interest expense, all of which are principally a result of the acquisitions of the Gulf Coast and New Haven, Connecticut marine terminal facilities in August 1999 and September 2000, respectively. In addition, income tax expense decreased $2.2 million due to the decline in earnings in 2000 as compared to 1999.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows and Capital Expenditures
Net cash provided by operating activities for the year ended December 31, 2001 was $42.5 million compared to $15.6 million for the year ended December 31, 2000 and $5.7 million for the year ended December 31, 1999. The increase from 2000 to 2001 was primarily attributable to increased net income before depreciation and deferred compensation costs. Acquisitions and enhanced operations of our initial assets increased operating margins significantly. In addition, our initial public offering in 2001 resulted in reduced general and administrative costs and interest expense as well as the elimination of income taxes. The increase from 1999 to 2000 was primarily attributable to a reduction in the account receivable due from our affiliate, Williams Energy Marketing & Trading. During this period, acquisitions also added significantly to operating margins, but these increases were offset by an increase in general and administrative expense allocations, higher depreciation and increased interest expense.
Net cash used by investing activities for the years ended December 31, 2001, 2000 and 1999 was $63.3 million, $41.7 million and $237.7 million, respectively. We increased capital expenditures during these
years primarily to make acquisitions of petroleum product terminals. In 2001, we acquired two inland terminals in Little Rock, Arkansas and a marine terminal facility in Gibson, Louisiana. In 2000, we acquired one inland terminal and the New Haven, Connecticut marine terminal facility. In 1999, we acquired 12 inland terminals, the Gulf Coast marine facilities and an additional ownership interest in eight existing inland terminals.
Net cash provided by financing activities for the years ended December 31, 2001, 2000 and 1999 was $34.6 million, $26.1 million and $232.1 million, respectively. The cash flow for 2001 is primarily comprised of proceeds from our equity and debt proceeds at the time of our initial public offering and $49.5 million associated with additional borrowings for the acquisitions of the Little Rock, Arkansas terminals and Gibson, Louisiana marine terminal facility. The 1999 and 2000 amounts represent loans received from The Williams Companies, Inc. to fund our terminal acquisitions.
Capital Requirements
The storage, transportation 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 business have consisted, and we expect them to continue to consist, primarily of:
- maintenance capital expenditures, such as those required to maintain equipment reliability and safety and to address environmental regulations; and
- expansion capital expenditures to acquire additional complementary assets to grow our business and to expand or upgrade our existing facilities, such as projects that increase storage or throughput volumes.
According to the Omnibus Agreement between Williams Energy Partners L.P. and The Williams Companies, Inc., Williams will reimburse us for maintenance capital in excess of $4.9 million per year during 2001 and 2002 on the assets initially included in the initial public offering up to a combined maximum reimbursement of $15.0 million. We incurred $3.9 million of maintenance capital costs in 2001 in excess of the $4.9 million limit agreed to with Williams. We received reimbursement of $2.0 million of these during 2001, with the remaining $1.9 million reimbursement made in January 2002. The total amount we expect to spend on maintenance capital for these assets in 2002 will exceed $4.9 million. As a result, Williams will continue to make capital contributions to Williams Energy Partners L.P. during 2002. In addition to maintenance capital, we are also planning to incur expansion and upgrade capital expenditures at our existing facilities, including pipeline connections. The total amount we plan to spend for expansion is approximately $11.0 million in 2002, not including capital needs associated with acquisition opportunities. We expect to fund our capital expenditures, including any acquisitions, from cash provided by operations and, to the extent necessary, from the proceeds of:
- borrowings under the revolving credit facility discussed below and other borrowings; and
- 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.
Liquidity
Subsequent to the closing of our initial public offering on February 9, 2001, we have relied on cash generated from internal operations as our primary source of funding. To review the risks associated with our cash flows generated from operations, refer to Risks Related to our Business discussed beginning on page 30. Additional funding requirements are being served by a $175.0 million credit facility 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.
Immediately after the closing of the offering, our Partnership borrowed the entire $90.0 million term loan and $0.1 million under the revolving credit facility. As of December 31, 2001, $23.5 million was available
under the acquisition sub-facility after borrowing $49.5 million to fund the Little Rock, Arkansas and Gibson, Louisiana acquisitions. Borrowings for the Aux Sable transaction occurred during January 2002. In addition, $12.0 million was available under the working capital sub-facility at December 31, 2001.
The credit facility contains various operational and financial covenants. Management believes that we are in compliance with all of these covenants.
ENVIRONMENTAL
Our operations are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. We have accrued liabilities for estimated site restoration costs to be incurred in the future at our facilities and properties, including liabilities for environmental remediation obligations at various sites where we have been identified as a potentially 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, Williams Energy Services, LLC, a subsidiary of The Williams Companies, Inc., agreed to indemnify us against any covered environmental losses, up to $15.0 million, relating to assets it contributed to Williams Energy Partners L.P. that arose prior to February 9, 2001, that become known within three years after February 9, 2001 and that exceed all amounts recovered or recoverable by us under contractual indemnities from third parties or under any applicable insurance policies.
As of December 31, 2001 we had accrued environmental liabilities of $5.4 million. Management estimates that these expenditures for environmental remediation liabilities will be paid over the next five to ten years. Receivables associated with environmental liabilities of $5.1 million have been recognized as recoverable from affiliates and third parties.
IMPACT OF INFLATION
Although the impact of inflation has slowed in recent years, it is still a factor in the United States economy and may increase the cost to acquire or replace property, plant and equipment and may increase the costs of labor and supplies. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher fees.
CRITICAL ACCOUNTING POLICIES
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. We deem the following accounting policies to be critical:
- Revenues are recognized in the month that services are rendered. Changes in the available tankage for storage and demand for petroleum and anhydrous ammonia products could have a material impact on our revenues.
- Depreciation expense is calculated based on management's best estimate of the remaining useful lives of our assets. Because of the expected long useful lives of our assets, we depreciate terminals and pipelines over a 30-year to 67-year period for financial statement purposes. Changes in the estimated lives of our assets could have a material effect on results of operations.
- Incentive compensation expense is recorded for the restricted unit compensation program for Williams' employees who directly support the Partnership. The expense associated with the one-time initial public offering award is based on the price of the units on the date of grant. The expense associated with the annual incentive compensation plan is computed based on the estimated number of units that will ultimately vest adjusted by the current market value of the units at each period end. The Partnership is accruing costs for these units based on management's estimate that the maximum
number of units will vest. Any changes in those assumptions would result in lower compensation expense to the Partnership.
- Environmental liabilities are recorded when site restoration, environmental remediation and cleanup obligations are either known or considered probable and can be reasonably estimated. Environmental liabilities are recorded independently of any potential claim for recovery. Receivables are recognized in cases where reimbursements for remediation costs are considered probable. During 2001, we recorded a $2.6 million environmental liability associated with our New Haven facility. The amount of the liability was based on third-party engineering estimates developed as part of our Phase II environmental assessment, required by the State of Connecticut. This environmental liability could change materially upon finalization of the more comprehensive Phase III assessment, scheduled to be completed in the summer of 2002. This environmental liability is covered by the Partnership's indemnifications from Williams Energy Services, LLC up to a maximum amount of $15.0 million; hence, any adjustments to the liability should not impact the Partnership's results of operations.
- With the adoption of Statement of Financial Accounting Standards No. 142, goodwill will no longer be amortized beginning January 1, 2002 but will be tested periodically for impairment. Management's judgments and assumptions relative to estimating the future cash flows of our various assets will be critical in determining whether an impairment exists and, if so, the financial impact of such impairment. Changes in market conditions, customers and/or industry financial conditions, technology and other factors could materially impact the future assessment of goodwill values, which could have a material impact on our results of operations, financial condition and cash flows.
NEW ACCOUNTING PRONOUNCEMENTS
In August 2001, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." This Statement supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of" and amends Accounting Principles Board Opinion No. 30, "Reporting the Results of Operations -- Reporting the Effects of Disposal of a Segment of a Business and Extraordinary, Unusual and Infrequently Occurring Events and Transactions." The Statement retains the basic framework of SFAS No. 121, resolves certain implementation issues of SFAS No. 121, extends applicability to discontinued operations and broadens the presentation of discontinued operations to include a component of an entity. The Statement is to be applied prospectively and is effective for financial statements issued for fiscal years beginning after December 15, 2001. The Statement is not expected to have any initial impact on our results of operations or financial position.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This Statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs and amends FASB Statement No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." The Statement requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made and that the associated asset retirement costs be capitalized as part of the carrying amount of the long-lived asset. The Statement is effective for financial statements issued for fiscal years beginning after June 15, 2002. We plan to adopt this standard in January 2003, and we are evaluating its effect on our results of operations and financial position.
In June 2001, the FASB issued SFAS No. 141, "Business Combinations" and SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 141 establishes accounting and reporting standards for business combinations and requires all business combinations to be accounted for by the purchase method. The Statement is effective for all business combinations for which the date of acquisition is July 1, 2001 or later. SFAS No. 142 addresses accounting and reporting standards for goodwill and other intangible assets. Under this Statement, goodwill and intangible assets with indefinite useful lives will no longer be amortized but will be tested annually for impairment. The Statement becomes effective for all fiscal years beginning after December 15, 2001. We will apply the new rules on accounting for goodwill and other intangible assets
beginning January 1, 2002. Based on the amount of goodwill recorded as of December 31, 2001, application of the non-amortization provision of the Statement will result in a decrease to amortization expense in future years of approximately $1.1 million.
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." This was followed in June 2000 by the issuance of SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities," which amends SFAS No. 133. SFAS No. 133 and No. 138 establish accounting and reporting standards for derivative financial instruments. The standards require that all derivative financial instruments be recorded on the balance sheet at their fair value. Changes in fair value of derivatives will be recorded each period in earnings if the derivative is not a hedge. If a derivative qualifies for special hedge accounting, changes in the fair value of the derivative will either be recognized in earnings as an offset against the change in fair value of the hedged assets, liabilities or firm commitments also recognized in earnings, or the changes in fair value will be deferred on the balance sheet until the hedged item is recognized in earnings. The ineffective portion of a derivative's change in fair value will be recognized immediately in earnings. These standards were adopted on January 1, 2001. There was no impact to our financial position, results of operations or cash flows from adopting these standards.
The FASB issued SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities." The Statement provides guidance for determining whether a transfer of financial assets should be accounted for as a sale or a secured borrowing and whether a liability has been extinguished. The Statement is effective for recognition and reclassification of collateral and for disclosures ending after December 15, 2000. The Statement became effective for transfers and servicing of financial assets and extinguishments of liabilities occurring after March 31, 2001. The initial application of SFAS No. 140 had no impact on our results of operations and financial position.
RELATED PARTY TRANSACTIONS
Williams Energy Marketing & Trading Company and Williams Refining & Marketing, L.L.C., subsidiaries of The Williams Companies, Inc. and affiliates of the Partnership, are significant customers at our petroleum product terminals, representing 11.0 percent and 7.2 percent, respectively, of our total revenues for the year ended December 31, 2001. The services we provide them are conducted pursuant to various contracts between them and the Partnership. As of December 31, 2001, 3 percent of the revenues from these affiliates were generated under contracts renewing on a monthly basis, while 97 percent were generated under contracts with remaining terms in excess of one year or that are renewed on an annual basis.
RISKS RELATED TO OUR BUSINESS
WE MAY NOT BE ABLE TO GENERATE SUFFICIENT CASH FROM OPERATIONS TO ALLOW US TO PAY THE MINIMUM QUARTERLY DISTRIBUTION FOLLOWING ESTABLISHMENT OF CASH RESERVES AND PAYMENT OF FEES AND EXPENSES, INCLUDING PAYMENTS TO OUR GENERAL PARTNER.
The amount of cash we can distribute on our common units principally depends upon the cash we generate from our operations. Because the cash we generate from operations will fluctuate from quarter to quarter, we may not be able to pay the minimum quarterly distribution for each quarter. Our ability to pay the minimum quarterly distribution each quarter depends primarily on cash flow, including cash flow from financial reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and may not make cash distributions during periods when we record net income.
POTENTIAL FUTURE ACQUISITIONS AND EXPANSIONS, IF ANY, MAY AFFECT OUR BUSINESS BY SUBSTANTIALLY INCREASING THE LEVEL OF OUR INDEBTEDNESS AND CONTINGENT LIABILITIES AND INCREASING OUR RISKS OF BEING UNABLE TO EFFECTIVELY INTEGRATE THESE NEW OPERATIONS.
From time to time, we evaluate and acquire assets and businesses that we believe complement our existing assets and businesses. Acquisitions may require substantial capital or the incurrence of substantial indebtedness. If we consummate any future acquisitions, our capitalization and results of operations may
change significantly, and you will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.
Acquisitions and business expansions involve numerous risks, including difficulties in the assimilation of the assets and operations of the acquired businesses, inefficiencies and difficulties that arise because of unfamiliarity with new assets and the businesses associated with them and new geographic areas and the diversion of management's attention from other business concerns. Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. Following an acquisition, we may discover previously unknown liabilities associated with the acquired business for which we have no recourse under applicable indemnification provisions.
OUR FINANCIAL RESULTS DEPEND ON THE DEMAND FOR THE REFINED PETROLEUM PRODUCTS THAT WE STORE AND DISTRIBUTE.
Any sustained decrease in demand for refined petroleum products in the markets served by our terminals could result in a significant reduction in the volume of products that we store at our marine terminal facilities and in the throughput in our inland terminals, and therefore reduce our cash flow and our ability to pay cash distributions to you. Factors that could lead to a decrease in market demand include:
- an increase in the market price of crude oil that leads to higher refined product prices, which may reduce demand for gasoline and other petroleum products. Market prices for refined petroleum products are subject to wide fluctuation in response to changes in global and regional supply over which we have no control;
- a recession or other adverse economic condition that results in lower spending by consumers and businesses on transportation fuels such as gasoline, jet fuel and diesel;
- higher fuel taxes or other governmental or regulatory actions that increase the cost of gasoline;
- an increase in fuel economy, whether as a result of a shift by consumers to more fuel-efficient vehicles or technological advances by manufacturers; and
- the increased use of alternative fuel sources, such as fuel cells and solar, electric and battery-powered engines. Several state and federal initiatives mandate this increased use.
WHEN PRICES FOR THE FUTURE DELIVERY OF PETROLEUM PRODUCTS THAT WE STORE IN OUR MARINE TERMINALS FALL BELOW CURRENT PRICES, CUSTOMERS ARE LESS LIKELY TO STORE THESE PRODUCTS, THEREBY REDUCING OUR STORAGE REVENUES.
This market condition is commonly referred to as "backwardation." When the petroleum product market is in backwardation, the demand for storage capacity at our marine terminal facilities may decrease. The forward pricing market for petroleum products moved to backwardation in the second quarter of 1999 and continued for a majority of 2000. This market condition contributed to reduced storage revenues in 1999 and 2000. In 2001, the forward pricing market remained backwardated during the first half of the year, reversing during the latter half of 2001. If this market becomes strongly backwardated for an extended period of time, it may affect our ability to pay cash distributions to you.
WE DEPEND ON PETROLEUM PRODUCT PIPELINES OWNED AND OPERATED BY OTHERS TO SUPPLY OUR TERMINALS.
Most of our inland and marine terminal facilities depend on connections with petroleum product pipelines owned and operated by third parties. Reduced throughput on these pipelines because of testing, line repair, damage to pipelines, reduced operating pressures or other causes could result in our being unable to deliver products to our customers from our terminals or receive products for storage and could adversely affect our ability to pay cash distributions to you.
COLLECTIVELY, OUR AFFILIATES WILLIAMS ENERGY MARKETING & TRADING AND WILLIAMS REFINING & MARKETING ARE OUR LARGEST CUSTOMER, AND ANY REDUCTION IN THEIR USE OF OUR TERMINAL FACILITIES COULD REDUCE OUR ABILITY TO PAY CASH DISTRIBUTIONS TO YOU.
For the year ended December 31, 2001, our affiliates Williams Energy Marketing & Trading and Williams Refining & Marketing collectively accounted for approximately 18 percent of our revenues. If Williams Energy Marketing & Trading and Williams Refining & Marketing were to decrease the throughput volume they allocate to our terminals for any reason, we could experience difficulty in replacing those lost volumes. Because our operating costs are primarily fixed, a reduction in throughput would result in not only a reduction of revenues, but also a decline in net income and cash flow of a similar magnitude, which would reduce our ability to pay cash distributions to you. Either Williams Energy Marketing & Trading or Williams Refining & Marketing could reduce the volume of throughput it allocates to us because of market conditions or because of factors that specifically affect Williams Energy Marketing & Trading or Williams Refining & Marketing, including a decrease in demand for products in the markets served by our terminals or a loss of customers in those markets.
OUR AMMONIA PIPELINE AND TERMINALS SYSTEM IS DEPENDENT ON THREE CUSTOMERS.
Three customers ship all of the ammonia on our pipeline and utilize the six terminals that we own and operate on the pipeline. We have contracts with Farmland Industries, Inc., Agrium U.S. Inc. and Terra Nitrogen, L.P. through June 2005 that obligate them to ship-or-pay for specified minimum quantities of ammonia. Two of these customers have credit ratings below investment grade. The loss of any one of these three customers or their failure or inability to pay us would adversely affect our ability to pay cash distributions to you.
HIGH NATURAL GAS PRICES CAN INCREASE AMMONIA PRODUCTION COSTS AND REDUCE THE AMOUNT OF AMMONIA TRANSPORTED THROUGH OUR AMMONIA PIPELINE AND TERMINALS SYSTEM.
The profitability of our customers that produce ammonia partially depends on the price of natural gas, which is the principal raw material used in the production of ammonia. From 1999 through the first half of 2001, natural gas prices were substantially higher than historical averages. As a result, our customers substantially curtailed their production of ammonia and shipped lower volumes of ammonia on our pipeline. Because of this, our ammonia business realized reduced revenues and cash flows in 1999, 2000 and the first six months of 2001. Our ammonia pipeline and terminals system revenues increased during the second half of 2001 with the return of high natural gas prices to lower historical levels. An extended period of high natural gas prices may cause our customers to produce and ship lower volumes of ammonia, which could adversely affect our ability to pay cash distributions to you.
CHANGES IN THE FEDERAL GOVERNMENT'S POLICY REGARDING FARM SUBSIDIES COULD NEGATIVELY IMPACT THE DEMAND FOR AMMONIA AND RESULT IN DECREASED SHIPMENTS THROUGH OUR AMMONIA PIPELINE AND TERMINALS SYSTEM.
Our customers who ship ammonia through our pipeline primarily market the ammonia to corn farmers in the Midwest. The government's Freedom to Farm program enacted by the 1996 Farm Bill has provided these farmers with increased incentives to grow corn, resulting in large corn crops over the last few years. This program, however, ends in 2002 and is under legislative consideration at this time. If the program is revised or terminated, it could reduce farmers' incentive to grow corn and reduce the demand for the ammonia used to fertilize the crops. In addition, the federal government and state governments have been providing tax credits related to the production of ethanol, for which corn is the essential element. If these tax incentives are reduced or repealed, the demand for ammonia would be reduced and our customers might reduce the volumes transported through our pipeline.
OUR MARINE AND INLAND TERMINALS ENCOUNTER COMPETITION FROM OTHER TERMINAL COMPANIES AND OUR AMMONIA PIPELINE AND TERMINALS SYSTEM ENCOUNTERS COMPETITION FROM RAIL CARRIERS AND ANOTHER AMMONIA PIPELINE.
Our marine and inland terminals face competition from large, generally well-financed companies that own many terminals, as well as from small companies. Our marine and inland terminals also encounter competition from integrated refining and marketing companies that own their own terminal facilities. Our customers demand delivery of products on tight time schedules and in a number of geographic markets. If our quality of service declines or we cannot meet the demands of our customers, they may use our competitors.
We compete primarily with rail carriers for the transportation of ammonia. If our customers elect to transport ammonia by rail rather than pipeline, we may realize lower revenues and cash flows and our ability to pay cash distributions may be adversely affected. Our ammonia pipeline also competes with the Koch Pipeline Company LP ammonia pipeline in Iowa and Nebraska.
OUR BUSINESS IS SUBJECT TO FEDERAL, STATE AND LOCAL LAWS AND REGULATIONS THAT GOVERN THE ENVIRONMENTAL AND OPERATIONAL SAFETY ASPECTS OF OUR OPERATIONS.
Our marine and inland terminal facilities and ammonia pipeline and terminals system are subject to the risk of incurring substantial costs and liabilities under environmental and safety laws. These costs and liabilities arise under increasingly strict environmental and safety laws, including regulations and governmental enforcement policies, and as a result of claims for damages to property or persons arising from our operations. Failure to comply with these laws and regulations may result in assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens and, to a lesser extent, issuance of injunctions to limit or cease operations. If we were unable to recover these costs through increased revenues, our ability to pay cash distributions to you could be adversely affected.
We own a number of properties that have been used for many years to distribute or store petroleum products by third parties not under our control. In some cases, owners, tenants or users of these properties have disposed of or released hydrocarbons or solid wastes on or under these properties. In addition, some of our terminals are located on or near current or former refining and terminal operations, and there is a risk that contamination is present on these sites. The transportation of ammonia by our pipeline is hazardous and may result in environmental damage, including accidental releases that may cause death or injuries to humans and farm animals and damage to crops.
TERRORIST ATTACKS AIMED AT OUR FACILITIES COULD ADVERSELY AFFECT OUR BUSINESS.
On September 11, 2001, the United States was the target of terrorist attacks of unprecedented scale. Since the September 11 attacks, the U.S. government has issued warnings that energy assets, specifically our nation's pipeline infrastructure, may be the future target of terrorist organizations. These developments have subjected our operations to increased risks. Any future terrorist attack on our facilities, those of our customers and, in some cases, those of other pipelines, could have a material adverse effect on our business.
OUR BUSINESS INVOLVES MANY HAZARDS AND OPERATIONAL RISKS, SOME OF WHICH MAY NOT BE COVERED BY INSURANCE.
Our operations are subject to the many hazards inherent in the transportation of refined petroleum products and ammonia, including ruptures, leaks and fires. These risks could result in substantial losses due to personal injury or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations. We are not fully insured against all risks incident to our business. In addition, as a result of market conditions, premiums 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.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Williams Energy Partners currently does 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 bears variable interest based on LIBOR. If the LIBOR changed by 0.125 percent, our annual debt coverage obligations associated with the $139.5 million of outstanding borrowings under the term loan and revolving credit facility at December 31, 2001 would change by approximately $0.2 million. Unless interest rates change significantly in the future, our exposure to interest rate market risk is minimal.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
REPORT OF INDEPENDENT AUDITORS
The Board of Directors of Williams GP LLC, General Partner of Williams Energy Partners L.P.
We have audited the accompanying consolidated balance sheets of Williams Energy Partners L.P. as of December 31, 2001 and 2000, and the related consolidated statements of income, partners' capital and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of 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 financial statements referred to above present fairly, in all material respects, the consolidated financial position of Williams Energy Partners L.P. at December 31, 2001 and 2000, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States.
ERNST & YOUNG LLP
Tulsa, Oklahoma March 4, 2002
WILLIAMS ENERGY PARTNERS L.P.
CONSOLIDATED STATEMENTS OF INCOME (IN THOUSANDS)
See accompanying notes.
WILLIAMS ENERGY PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS (IN THOUSANDS)
See accompanying notes.
WILLIAMS ENERGY PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)
See accompanying notes.
WILLIAMS ENERGY PARTNERS L.P.
CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL (IN THOUSANDS, EXCEPT UNIT AMOUNTS)
See accompanying notes.
WILLIAMS ENERGY PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND PRESENTATION
Williams Energy Partners L.P. (the "Partnership") is a Delaware limited partnership that was formed in August 2000, to acquire, own and operate: (a) selected petroleum product terminals owned by Williams Energy Ventures, Inc. ("WEV"), and (b) an ammonia pipeline and terminals system, Williams Ammonia Pipeline, Inc., ("WAPI"), owned by Williams Natural Gas Liquids, Inc. ("WNGL"). Prior to the closing of the Partnership's initial public offering in February 2001, WEV was owned by Williams Energy Services, LLC ("WES"). Both WES and WNGL are wholly-owned subsidiaries of The Williams Companies, Inc. ("Williams"). Williams GP LLC (the "Managing GP" or "General Partner"), a Delaware limited liability company, was also formed in August 2000, to serve as managing general partner for the Partnership.
On February 9, 2001, the Partnership completed its initial public offering of 4,000,000 common units representing limited partner interests in the Partnership at a price of $21.50 per unit. The proceeds of $86.0 million were used to pay underwriter 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.
On October 28, 2000, the Partnership and the Managing GP formed a limited operating partnership named Williams OLP, L.P. ("OLP") to serve as limited partner of the operating limited partnerships. Concurrent with the closing of the initial public offering and pursuant to the Contribution and Conveyance Agreement dated February 9, 2001, WEV converted itself into Williams Terminals Holdings, L.P. ("WTH LP"). Williams Pipeline Holdings, LLC, a subsidiary of WTH LP, converted itself into Williams Pipeline Holdings, LP ("WPH LP") and Williams Ammonia Pipeline, Inc. converted itself into Williams Ammonia Pipeline, L.P. ("WAP LP"). All three converted entities are Delaware limited partnerships. WNGL contributed 3.05 percent of its ownership in WAP LP and WES contributed 2.05 percent of its ownership in WTH LP to the Managing GP in exchange for 19.2 percent and 80.8 percent ownership interest in the Managing GP, respectively. WNGL contributed the remainder of its interest in WAP LP to the OLP and WES contributed the remainder of its interest in WTH LP and all of its interest in WPH LP to the OLP in exchange for ownership interests in the OLP. The Managing GP contributed all of its interest in WAP LP, WTH LP and WPH LP in exchange for: (a) a 1.0 percent managing general partner interest in the Partnership and (b) a 1.0101 percent managing general partner interest in the OLP. WNGL contributed to the Partnership all of its limited partner interest in OLP in exchange for 322,501 common units and 1,090,501 subordinated units, and WES contributed all of its limited partner interest in OLP to the Partnership in exchange for 1,357,193 common units and 4,589,193 subordinated units.
Subsequent to 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 underwriter commissions of $0.8 million, from this over-allotment option were used to redeem 600,000 of the common units held by WES to reimburse it for capital expenditures related to the Partnership's assets. Upon completion of this transaction, Williams owned 60 percent of the equity units of the Partnership. The Partnership maintained the historical costs of the net assets received under the Contribution Agreement. Following the exercise of the underwriters over-allotment, 40.09 percent of the Partnership is owned by the public and 59.91 percent, including the general partners ownership, is owned by affiliates of Williams Energy Partners L.P.
On February 26, 2002, the Partnership formed a wholly-owned Delaware corporation named Williams GP Inc. ("GP Inc.") The Partnership then contributed a 0.001 percent limited partner interest in OLP to GP Inc. as a capital contribution. The OLP agreement was then amended to convert GP Inc.'s OLP limited partner interest to a general partner interest and to convert the General Partner's existing interest to a limited partner interest. The General Partner then contributed its 1.0101 percent OLP limited partner interest to the Partnership in exchange for an additional 1.0 percent general partner interest in the Partnership.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The resulting structure is as follows: Williams GP LLC serves as the managing general partner for the Partnership. OLP is the limited partner of the operating limited partnerships and GP Inc. serves as its general partner. The operating limited partnerships are comprised of WTH LP, WPH LP and WAP LP. Williams NGL LLC was established to serve as general partner of the operating limited partnerships and is owned by OLP. Under the resulting structure, the limited partners' liability in each of the limited partnerships is limited to their investment.
Pro Forma Results of Operations (Unaudited):
The pro forma results of operations for the year ended December 31, 2000, are derived from the historical financial statements of the Partnership. The pro forma results of operations reflect certain pro forma adjustments to the historical results of operations as if the MLP had been formed on January 1, 2000. Significant pro forma adjustments include: (a) pro forma interest on debt outstanding on February 9, 2001, (b) reductions in general and administrative expenses to $6.0 million per year, (c) additional revenues and expenses from acquisitions as though the acquisitions had occurred as of January 1, 2000, (d) reductions of $0.7 million in 2000 for additional revenues recognized as a result of a revenue guarantee provided by Amerada Hess Corporation for a specified period after the acquisition of the Gulf Coast marine terminals and (e) the elimination of income tax expense as income taxes are the responsibility of the unitholders and not the MLP.
2. DESCRIPTION OF BUSINESSES
Williams Energy Partners L.P. owns and operates certain petroleum product terminal operations and an interstate common carrier ammonia pipeline.
Petroleum Product Terminals
Most of the Partnership's 30 petroleum product terminals are strategically located along or near third party pipelines or petroleum refineries. The terminal network consists of marine terminals and inland terminals. The petroleum product 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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
industries. Products stored in and distributed through the petroleum product terminal network include refined petroleum products, blendstocks and heavy oils and feedstocks. The inland terminals are located primarily in the southeastern United States. Four marine terminal facilities are located along the Gulf Coast and one marine terminal facility is located in Connecticut near the New York harbor. Other than at our Galena Park marine terminal facility, none of the employees assigned to the petroleum product terminal operations are covered by collective bargaining agreements. The employees at the Galena Park marine terminal facility are currently represented by a union, but have indicated their unanimous desire to terminate their union affiliation. Nevertheless, the National Labor Relations Board has ordered the Partnership to bargain with the union as the exclusive collective bargaining representative of the employees at the facility. The Partnership is appealing this decision.
Ammonia Pipeline and Terminals System
The ammonia pipeline and terminals system consists of an ammonia pipeline and six company-owned terminals. Shipments on the pipeline primarily originate from ammonia production plants located in Borger, Texas and Enid and Verdigris, Oklahoma for transport to terminals throughout the Midwest for ultimate distribution to end-users in Iowa, Kansas, Minnesota, Missouri, Nebraska, Oklahoma and South Dakota. The ammonia transported through the system is used primarily as nitrogen fertilizer. Approximately 94 percent of ammonia system revenues are generated from transportation tariffs received from three customers, who are obligated under "ship or pay" contracts to ship an aggregate minimum of 700,000 tons per year but have historically shipped an amount in excess of the required minimum. The current ammonia transportation contracts extend through June 2005. The tariffs charged by the interstate ammonia pipeline are regulated by the Surface Transportation Board of the U.S. Department of Transportation.
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The petroleum product terminal operations consist of 30 independent petroleum product terminal facilities and associated storage, located across 12 states primarily in the South, Southeast and Gulf Coast areas of the United States. For 11 of these petroleum product terminals, Williams Energy Partners L.P. 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, Williams Energy Partners L.P. applies proportionate consolidation for their interests in these assets. All of the remaining terminal facilities and the ammonia pipeline are wholly-owned subsidiaries and are fully consolidated.
Reclassifications
Certain previously reported balances have been classified differently to conform with current year presentation.
Use of Estimates
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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Cash Equivalents
Cash and cash equivalents include demand and time deposits and other marketable securities with maturities of three months or less when acquired.
Property, Plant and Equipment
Property, plant and equipment are stated at cost. Expenditures for maintenance and repairs are charged to operations in the period incurred. 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. Depreciation of property, plant and equipment is provided on the straight-line basis.
Goodwill and Other Intangible Assets
Goodwill, which represents the excess of cost over fair value of assets of businesses acquired, was amortized on a straight-line basis over a period of 20 years for those assets acquired prior to July 1, 2001. Other intangible assets are amortized on a straight-line basis over a period of up to 25 years.
Impairment of Long-Lived Assets
Williams Energy Partners L.P. 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.
Revenue Recognition
Revenues are recognized in the month that services are rendered.
Income Taxes
Prior to February 9, 2001, Williams Energy Partners L.P.'s operations wee included in Williams' consolidated federal income tax return. Williams Energy Partners L.P. 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 Williams Energy Partners L.P.'s assets and liabilities.
Effective with the closing of the Partnership's initial public offering on February 9, 2001 (See Note 1), the Partnership is not a taxable entity for federal and state income tax purposes. Accordingly, no recognition has been given to income taxes for financial reporting purposes. The tax on Partnership net income is borne by the individual partners through the allocation of taxable income. Net income for financial statement purposes may differ significantly from taxable income of unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under the Partnership Agreement. The aggregate difference in the basis of the Partnership's net assets for financial and
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
tax reporting purposes cannot be readily determined because information regarding each partner's tax attributes in the Partnership is not available to the Partnership.
Employee Stock-Based Awards
Williams' employee stock-based awards are accounted for under provisions of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations. Williams' fixed plan common stock options do not result in compensation expense because the exercise price of the stock options equals the market price of the underlying stock on the date of grant.
The Partnership's General Partner has issued incentive awards to Williams' employees assigned to the Partnership. These awards are also accounted for under provisions of Accounting Principles Board Opinion No. 25. Since the exercise price of the unit awards is less than the market price of the underlying units on the date of grant, compensation expense is recognized by the General Partner and directly allocated to the Partnership.
Environmental
Environmental expenditures that relate to current or future revenues are expensed or capitalized based upon the nature of the expenditures. Expenditures that relate to an existing condition caused by past operations that do not contribute to current or future revenue generation are expensed. Environmental liabilities are recorded independently of any potential claim for recovery. Receivables are recognized in cases where the realization of reimbursements of remediation costs are considered probable. Accruals related to environmental matters are generally determined based on site-specific plans for remediation, taking into account prior remediation experience of Williams Energy Partners L.P. and Williams.
Earnings Per Unit
Basic earnings per unit are based on the average number of common and subordinated units outstanding. Diluted earnings per unit include any dilutive effect of restricted unit grants.
Recent Accounting Standards
In August 2001, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." This Statement supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of" and amends Accounting Principles Board Opinion No. 30, "Reporting the Results of Operations -- Reporting the Effects of Disposal of a Segment of a Business and Extraordinary, Unusual and Infrequently Occurring Events and Transactions." The Statement retains the basic framework of SFAS No. 121, resolves certain implementation issues of SFAS No. 121, extends applicability to discontinued operations and broadens the presentation of discontinued operations to include a component of an entity. The Statement is to be applied prospectively and is effective for financial statements issued for fiscal years beginning after December 15, 2001. The Statement is not expected to have any initial impact on the Partnership's results of operations or financial position.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This Statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs and amends FASB Statement No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." The Statement requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made and that the associated asset retirement costs be capitalized as part of the carrying amount of the long-lived asset. The Statement is effective for financial statements
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
issued for fiscal years beginning after June 15, 2002. The Partnership plans to adopt this standard in January 2003, and we are evaluating its effect on the Partnership's results of operations and financial position.
In June 2001, the FASB issued SFAS No. 141, "Business Combinations" and SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 141 establishes accounting and reporting standards for business combinations and requires all business combinations to be accounted for by the purchase method. The Statement is effective for all business combinations for which the date of acquisition is July 1, 2001 or later. SFAS No. 142 addresses accounting and reporting standards for goodwill and other intangible assets. Under this Statement, goodwill and intangible assets with indefinite useful lives will no longer be amortized, but will be tested annually for impairment. The Statement becomes effective for all fiscal years beginning after December 15, 2001. The Partnership will apply the new rules on accounting for goodwill and other intangible assets beginning January 1, 2002. Based on the amount of goodwill recorded as of December 31, 2001 application of the non-amortization provision of the Statement will result in a decrease to amortization expense in future years of approximately $1.1 million.
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." This was followed in June 2000 by the issuance of SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities," which amends SFAS No. 133. SFAS No. 133 and No. 138 establish accounting and reporting standards for derivative financial instruments. The standards require that all derivative financial instruments be recorded on the balance sheet at their fair value. Changes in fair value of derivatives will be recorded each period in earnings if the derivative is not a hedge. If a derivative qualifies for special hedge accounting, changes in the fair value of the derivative will either be recognized in earnings as an offset against the change in fair value of the hedged assets, liabilities or firm commitments also recognized in earnings, or the changes in fair value will be deferred on the balance sheet until the hedged item is recognized in earnings. The ineffective portion of a derivative's change in fair value will be recognized immediately in earnings. These standards were adopted on January 1, 2001. There was no impact to Williams Energy Partners L.P.'s financial position, results of operations or cash flows from adopting these standards.
The FASB issued SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities." The Statement provides guidance for determining whether a transfer of financial assets should be accounted for as a sale or a secured borrowing and whether a liability has been extinguished. The Statement is effective for recognition and reclassification of collateral and for disclosures ending after December 15, 2000. The Statement became effective for transfers and servicing of financial assets and extinguishments of liabilities occurring after March 31, 2001. The initial application of SFAS No. 140 had no impact on our results of operations and financial position.
4. ACQUISITIONS AND DIVESTITURES
Petroleum product terminal facilities and partial ownership interests in several petroleum product terminals were acquired for cash during the periods presented and are described below. All acquisitions, except the Aux Sable transaction, were accounted for as purchases of businesses and the results of operations of the acquired petroleum product terminals are included with the combined results of operations from their acquisition dates.
On December 31, 2001, the Partnership purchased an 8.5-mile, 8-inch natural gas liquids pipeline in northeastern Illinois from Aux Sable Liquid Products L.P. ("Aux Sable") for $8.9 million. The Partnership then entered into a long-term lease arrangement under which Aux Sable is the sole lessee of these assets. The Partnership has accounted for this transaction as a capital lease. The lease expires in December 2016 and has a purchase option after the first year. The minimum lease payments to be made by Aux Sable are $19.2 million in total and $1.3 million per year over each of the next five years. Aux Sable has the right to re-acquire the pipeline at the end of the lease for a de minimis amount. The fair value of the lease at December 31, 2001, approximates its carrying value.
WILLIAMS ENERGY PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In October 2001, the Partnership acquired the crude oil storage and distribution assets of Geonet Gathering, Inc. ("Geonet") located in Gibson, Louisiana. The Partnership acquired these assets with the intent to use the facility as a crude storage and distribution facility with an affiliate company as its primary customer. The purchase price was approximately $21.1 million, consisting of $20.3 million in cash and $0.9 million in assumed liabilities. The purchase price and allocation to assets acquired and liabilities assumed was as follows (in thousands):
Factors contributing to the recognition of goodwill are the market in which the facility is located and the opportunity to enter into a throughput agreement with an affiliate company, combined with the affiliate company's ability to trade around those assets. 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. Total weighted average amortization period of intangible assets is approximately 16 years. Of the consideration paid for the facility, $1.0 million is held in escrow, pending final evaluation of necessary repairs by the Partnership.
In June 2001, the Partnership purchased two petroleum product terminals located in Little Rock, Arkansas from TransMontaigne, Inc. ("TransMontaigne") at a cost of $29.1 million, of which $20.2 million was allocated to property, plant and equipment and $8.9 million to goodwill and other intangibles. Goodwill resulting from this acquisition is being amortized over a 20-year period. The final purchase price allocation has not been determined pending assessment of the environmental liabilities assumed.
In April 2001, the Partnership purchased a 6-mile pipeline for $0.3 million from Equilon Pipeline Company LLC, enabling connection of its existing Dallas, Texas area petroleum storage and distribution facility to Dallas Love Field. The acquisition was made in conjunction with an agreement for the Partnership to provide jet fuel delivery services into Dallas Love Field for Southwest Airlines. In December 2001, the Partnership completed construction of additional jet fuel storage tanks at its distribution facility in Dallas to support delivery of jet fuel to the airport. Total cost of the pipeline and construction of the additional jet fuel storage tanks totaled $5.5 million.
In September 2000, a northeast petroleum product terminal facility in New Haven, Connecticut was acquired from Wyatt Energy, Incorporated ("Wyatt") and its affiliates for approximately $30.8 million.
In March 2000, a 50 percent ownership interest in CITGO Petroleum Corporation's petroleum product terminal located in Southlake, Texas was acquired for approximately $0.3 million.
In August 1999, three storage and distribution petroleum product terminals and Terminal Pipeline Company ("TPC"), a wholly owned subsidiary of Amerada Hess Corporation ("Hess"), were acquired from Hess for approximately $212 million. The petroleum product terminals are located in Galena Park and Corpus Christi, Texas and Marrero, Louisiana. TPC owned a common carrier pipeline that began at a connection east
WILLIAMS ENERGY PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
of the Houston Ship Channel and terminated at the Galena Park terminal. The pipeline acquired from Hess was converted to private pipeline status during 2001.
In February 1999, an additional 10 percent ownership interest in eight petroleum product terminals was acquired from Murphy Oil USA, Inc. for approximately $3.4 million, which increased the Partnership's ownership interest to 78.9 percent from 68.9 percent. The petroleum product terminals, which are now operated by the Partnership, are located in Georgia, North Carolina, South Carolina, Tennessee and Virginia.
In January 1999, 11 petroleum product terminals owned by Amoco Oil Company ("Amoco") were acquired. The petroleum product terminals, located in Alabama, Florida, Mississippi, North Carolina, Ohio, South Carolina and Tennessee, were acquired for approximately $6.9 million. In addition, Amoco's 60 percent interest in a twelfth petroleum product terminal, located in Greensboro, North Carolina, was acquired for approximately $1.0 million.
The following summarized unaudited pro forma financial information for the years ended December 31, 2001 and 2000 assumes each acquisition had occurred on January 1 of the year immediately preceding the year of the acquisition (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.
Except where stated above, the purchase prices of the above acquisitions were allocated to various categories of property, plant and equipment and liabilities based upon the fair value of the assets acquired and liabilities assumed.
In October 2001, the Meridian, Mississippi terminal, previously reported with the Terminals business segment, was sold for $1.7 million. The Partnership recognized a gain of $1.1 million associated with the sale of the terminal, which is included in other income.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
5. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consists of the following (in thousands):
Depreciation expense for the years ended December 31, 2001, 2000 and 1999 was $11.2 million, $9.3 million and $4.6 million, respectively.
6. MAJOR CUSTOMERS AND CONCENTRATION OF CREDIT RISK
Williams Energy Marketing & Trading, an affiliate customer, Farmland Industries, Inc. and BP are major customers of the Partnership. No other customer accounted for more than 10 percent of total revenues during 2001, 2000 and 1999. Williams Energy Marketing & Trading and BP are customers of the petroleum product terminals segment. Farmland Industries, Inc. is a customer of the ammonia pipeline segment. The percentage of revenues derived by customer is provided below:
The accounts receivable balance of Williams Energy Marketing & Trading accounted for 8.2 percent and 15.0 percent of total accounts and affiliate receivables at December 31, 2001 and 2000, respectively.
Any issues impacting these industries could impact the Partnership's overall exposure to credit risk. While sales to petroleum product terminal and ammonia pipeline customers are generally unsecured, the financial condition and creditworthiness of customers are routinely evaluated. The Partnership has the ability with many of its contracts to sell stored customer products to recover unpaid receivable balances, if necessary.
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 they are unable to pass on higher costs to their customers, they may reduce shipments through the pipeline.
During 2001, the Partnership reserved $0.3 million for potential bad debt losses. However, no accounts were written off during 2001.
7. EMPLOYEE BENEFIT PLANS
All employees dedicated to, or otherwise supporting, Williams Energy Partners L.P. are employees of The Williams Companies, Inc. and substantially all of these employees are covered by Williams' noncontribu-
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
tory defined benefit pension plans and health care plan that provides postretirement medical benefits to certain retired employees. Contributions for pension and postretirement medical benefits related to Williams Energy Partners L.P.'s participation in the Williams' plans were $0.3 million, $0.2 million and $0.2 million in 2001, 2000 and 1999, respectively.
Williams maintains various defined contribution plans in which employees supporting Williams Energy Partners L.P. are included. Williams Energy Partners L.P.'s costs related to these plans were $0.5 million, $0.4 million and $0.2 million in 2001, 2000 and 1999, respectively.
8. RELATED PARTY TRANSACTIONS
Williams Energy Marketing & Trading Company and Williams Refining & Marketing, L.L.C., subsidiaries of The Williams Companies, Inc. and affiliates of the Partnership, are significant customers at our petroleum product terminals, representing 11.0 percent and 7.2 percent, respectively, of our total revenues for the year ended December 31, 2001. The accounts receivable balance of Williams Energy Marketing & Trading Company accounted for 8.2 percent and 15.0 percent of total accounts and affiliate receivables at December 31, 2001 and 2000, respectively. The accounts receivable balance of Williams Refining & Marketing, L.L.C. was 2.4 percent and 0 percent of total accounts and affiliate receivables at December 31, 2001 and 2000, respectively. The services we provide them are conducted pursuant to various contracts between them and the Partnership. As of December 31, 2001, 3 percent of the revenues from these affiliates were generated under contracts renewing on a monthly basis, while 97 percent were generated under contracts with remaining terms in excess of one year or that are renewed on an annual basis.
Williams allocates its affiliates, including the Partnership, for certain corporate administrative expenses, which are directly identifiable or allocable to the affiliates. Prior to the initial public offering, allocated general corporate expenses were based on a three-factor formula that considered operating margins, property, plant and equipment and payroll. Beginning with the closing date of the initial public offering, the general partner, through provisions included in the Omnibus Agreement, has limited the amount of general and administrative costs allocated to the Partnership. The additional general and administrative costs incurred by the general partner, but not charged to the Partnership, totaled $10.4 million for the period February 10, 2001 through December 31, 2001. A summary of the general and administrative expenses charged to the Partnership is as follows (in thousands):
The above costs are reflected in affiliate general and administrative expenses in the accompanying consolidated statements of income. In management's estimation, the allocation methodologies used are reasonable and the direct and allocated expenses represent amounts that would have been incurred on a stand- alone basis.
The affiliate payable primarily represents amounts owed to affiliates for general and administrative expenses and operational costs incurred on the Partnership's behalf. Affiliate payroll and benefit costs are amounts due to affiliate companies for salary and wages and associated charges for employees directly assigned to the Partnership. Long-term affiliate payables represent amounts due to an affiliate for certain non-compete agreements and for amounts associated with long-term incentive compensation.
Prior to February 9, 2001, the Partnership was a participant in Williams' cash management program. As of December 31, 2000, the Partnership's affiliate note payable consisted of an unsecured promissory note
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
agreement with Williams for advances from Williams. The advances were due on demand; however, in February 2001, a portion of the advances was refinanced with debt and equity offerings (see Note 1). Williams contributed the remaining advances in exchange for equity of the Partnership. Therefore, the affiliate note payable was classified as noncurrent at December 31, 2000.
Affiliate interest income or expense is calculated at the London Interbank Offered Rate ("LIBOR") plus a spread based on the outstanding balance of the note receivable or note payable with Williams. The spread is equivalent to the spread above LIBOR rates on Williams' revolving credit facility. The interest rate of the note with Williams was 7.6 percent at December 31, 2000. As the interest rate on the affiliate note payable is variable, the carrying value of the affiliate note payable at December 31, 2000 approximates its fair value.
9. 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, 2000, are as follows (in thousands):
Williams Energy Partners L.P. recognized a pre-initial public offering federal net operating loss for income tax purposes of $3.9 million and $57.0 million for the years 2001 and 2000, respectively. The $3.9 million federal net operating loss expires in 2021. The $57.0 million federal net operating loss carryforward expires in 2020. Payments to Williams in lieu of income taxes were $2.3 million in 1999.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
As a result of the initial public offering and the concurrent transactions on February 9, 2001 (see Note 1), the net deferred tax liability on that date was assumed by Williams, in exchange for an additional equity investment in Williams Energy Partners L.P.
10. LONG-TERM DEBT
Long-term debt and available borrowing capacity at December 31, 2001, were $139.5 million and $35.5 million, respectively. At December 31, 2001, the Partnership had a $175.0 million bank credit facility, led by Bank of America. The credit facility was comprised of a $90.0 million term loan facility and an $85.0 million revolving credit facility, which includes a $73.0 million acquisition sub-facility and a $12.0 million working capital sub-facility. On February 9, 2001, the OLP borrowed $90.0 million under the term loan facility and $0.1 million under the acquisition sub-facility. The $0.1 million borrowed under the acquisition sub-facility was repaid in July 2001. In June 2001, the Partnership borrowed $29.5 million under the acquisition facility to fund the purchase of two terminals in Little Rock, Arkansas from TransMontaigne. In October 2001, the Partnership borrowed $20.0 million to fund the acquisition of the Gibson, Louisiana terminal from Geonet. 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 LIBOR plus a spread from 1.0 percent to 1.5 percent, 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 percent to 0.4 percent, 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. Average interest rates at December 31, 2001 were 3.1 percent for the term loan facility and 3.3 percent for the acquisition sub-facility. Cash paid for interest for the twelve months ended December 31, 2001 was $6.7 million. Interest capitalized was $0.1 million in 2001. The fair value of the long-term debt approximates its carrying value, because of the floating interest rate applied to the debt facility.
11. LONG-TERM INCENTIVE PLAN
In February 2001, the general partner adopted the Williams Energy Partners' Long-Term Incentive Plan for Williams' employees who perform services for Williams Energy Partners L.P. and directors of the general partner. The Long-Term Incentive Plan consists of two components, phantom units and unit options. The Long-Term Incentive Plan permits the grant of awards covering an aggregate of 700,000 common units. The Long-Term Incentive Plan is administered by the compensation committee of the general partner's board of directors.
In April 2001, the general partner issued grants of 92,500 phantom units to certain key employees associated with the Partnership's initial public offering in February 2001. These one-time initial public offering phantom units will vest over a 34-month period ending on February 9, 2004, and are subject to forfeiture if employment is terminated prior to vesting. These units are subject to early vesting if the Partnership achieves certain performance measures. The Partnership recognized $0.7 million of compensation expense associated with these grants in 2001. The fair market value of the phantom units associated with this grant was $2.7 million on the grant date.
In April 2001, the general partner issued grants of 64,200 phantom units associated with the annual incentive compensation plan. The actual number of units that will be awarded under this grant will be determined by the Partnership on February 9, 2004. At that time, the Partnership will assess whether certain performance criteria have been met and determine the number of units that will be awarded, which could range from zero units up to a total of 128,400 units. These units are also subject to forfeiture if employment is terminated prior to February 9, 2004. These awards do not have an early vesting feature. The Partnership recognized $1.3 million of deferred compensation expense associated with these awards in 2001. The fair market value of the phantom units associated with this grant was $5.4 million on December 31, 2001.
WILLIAMS ENERGY PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Certain employees of Williams dedicated to or otherwise supporting Williams Energy Partners L.P. receive stock-based compensation awards from Williams. Williams has several plans providing for common-stock-based awards to employees and to nonemployee directors. The plans permit the granting of various types of awards including, but not limited to, stock options, stock-appreciation rights, restricted stock and deferred stock. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets being achieved. The purchase price per share for stock options and the grant price for stock-appreciation rights may not be less than the market price of the underlying stock on the date of grant. Depending upon terms of the respective plans, stock options generally become exercisable in one-third increments each year from the date of the grant or after three or five years, subject to accelerated vesting if certain future Williams' stock prices or specific Williams' financial performance targets are achieved. Stock options expire 10 years after grant.
The following summary reflects Williams' stock option activity for 2001, 2000 and 1999, 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, 2001:
The estimated fair value at the date of grant of options for Williams' common stock granted in 2001, 2000 and 1999, using the Black-Scholes option pricing model, is as follows:
WILLIAMS ENERGY PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 1999 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 1999 include the remaining total compensation expense from Williams' awards made in 1998 and the total compensation expense from Williams' awards made in 1999 as a result of the accelerated vesting provisions. Since compensation expense from stock options is recognized over the future years' vesting period for pro forma disclosure purposes, and additional awards generally are made each year, pro forma amounts may not be representative of future years' amounts.
12. SEGMENT DISCLOSURES
Management evaluates performance based upon segment profit or loss from operations, which includes revenues from affiliate and external customers, operating expenses, depreciation and affiliate general and administrative expenses. The accounting policies of the segments are the same as those described in Note 3 -- Summary of Significant Accounting Policies. Affiliate revenues are accounted for as if the sales were to unaffiliated third parties.
The Partnership's reportable segments are strategic business units that offer different products and services. The segments are managed separately because each segment requires different marketing strategies and business knowledge.
WILLIAMS ENERGY PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Non-cash charges for incentive compensation costs, included in 2001 affiliate general and administrative expenses, were $1.7 million for the petroleum product terminal operations and $0.3 million for the ammonia pipeline operations.
13. COMMITMENTS AND CONTINGENCIES
The Partnership leases land, tanks and related terminal equipment at the Gibson terminal facility. Minimum future lease payments for these leases as of December 31, 2001, are $0.1 million for each of the next five years and $1.7 million thereafter. The lease payments can be canceled after 2006 and include provisions for renewal of the lease at five-year increments which can extend the lease for a total of 25 years.
In conjunction with the 1999 acquisition of the Gulf Coast marine terminals from Hess, Hess has disclosed to the Partnership all suits, actions, claims, arbitrations, administrative, governmental investigation or other legal proceedings pending or threatened, against or related to the assets acquired by the Partnership, which arise under environmental law. Hess agreed to indemnify the Partnership against all environmental claims and losses arising from any matters related to the pre-acquisition period through July 30, 2014. In the event that any pre-acquisition releases of hazardous substances are identified by the Partnership prior to July 20, 2004, the Partnership will be liable for the first $2.5 million of environmental liabilities, Hess will be liable for the next $12.5 million of losses, and the Partnership will assume responsibility for any losses in excess of $15.0 million. Hess has indemnified the Partnership against any pre-acquisition fines and claims that may be imposed or asserted against the Partnership under environmental laws. At both December 31, 2001 and December 31, 2000, the Partnership had accrued $0.6 million for costs that may not be recoverable under Hess' indemnification.
WES has agreed to indemnify the Partnership against any covered environmental losses, up to $15.0 million, relating to assets it contributed to the Partnership that arose prior to February 9, 2001, that become known within three years after February 9, 2001, and that exceed all amounts recovered or recoverable by the Partnership under contractual indemnities from third parties or under any applicable insurance policies. Covered environmental losses are those non-contingent 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.
Estimated liabilities for environmental costs were $5.4 million and $1.9 million at December 31, 2001 and 2000, respectively. Management estimates that expenditures associated with these environmental remediation liabilities will be paid over the next five to ten years. Receivables associated with these environmental liabilities of $5.1 million and $0.3 million at December 31, 2001 and 2000, respectively, have been recognized as recoverable from WES and third parties. These estimates, provided on an undiscounted basis, were determined based primarily on data provided by a third-party environmental evaluation service. These liabilities have been classified as current or non-current based on management's estimates regarding the timing of actual payments.
During 2001, the Partnership recorded an environmental liability of $2.6 million at its New Haven, Connecticut facility, which was acquired in September 2000. This liability was based on third-party environmental engineering estimates completed as part of a Phase II environmental assessment, routinely required by the State of Connecticut to be conducted by the purchaser following the acquisition of a petroleum storage facility. The Partnership will complete a Phase III environmental assessment at this facility during the second or third quarter of 2002, and the environmental liability could change materially based on this more thorough analysis. The environmental liabilities at this location are covered by the WES environmental indemnifications to the Partnership.
WILLIAMS ENERGY PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
WNGL will indemnify the Partnership for right-of-way defects or failures in our 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, Corpus Christi and Marrero for 15 years after the initial public offering closing date.
The Partnership is party to various other claims, legal actions and complaints arising in the ordinary course of business. In the opinion of management, the ultimate resolution of all claims, legal actions and complaints after consideration of amounts accrued, insurance coverage or other indemnification arrangements will not have a material adverse effect upon the Partnership's future financial position, results of operations or cash flows.
14. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data is as follows (in thousands, except per unit amounts).
Basic and diluted net income for the first quarter of 2001 is calculated on the Limited Partners' interest in net income applicable for the period after February 9, 2001, through the end of the quarter. Revenues and expenses in 2001 were impacted by the acquisition of two terminals from TransMontaigne in June 2001 and the Gibson terminal from Geonet in October 2001. See Note 4 -- Acquisitions. 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.
Revenues and expenses in 2000 were impacted by the Southlake terminal acquisition in March 2000 and the marine terminal acquisition from Wyatt Energy in September 2000. Second quarter 2000 expenses included a $0.5 million charge from the write-off of an unsuccessful business transaction. Third quarter 2000 expenses included a $0.6 million environmental accrual. A throughput revenue deficiency billing related to the August 1999 acquisition of certain assets from Amerada Hess resulted in adjustments to revenues of $0.7 million impacting the first and second quarters of 2000.
WILLIAMS ENERGY PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
15. DISTRIBUTIONS
On May 15, 2001, the Partnership paid cash distributions of $0.292 per unit on its outstanding common and subordinated units to unitholders of record at the close of business on May 1, 2001. This distribution represented the minimum quarterly distribution for the 50-day period following the initial public offering closing date, which included February 10, 2001 through March 31, 2001. The total distributions paid were $3.4 million.
On August 14, 2001, the Partnership paid cash distributions of $0.5625 per unit on its outstanding common and subordinated units to unitholders of record at the close of business on August 2, 2001. The total distributions paid were $6.5 million.
On November 14, 2001, the Partnership paid cash distributions of $0.5775 per unit on its outstanding common and subordinated units to unitholders of record at the close of business on November 1, 2001. The total distributions paid were $6.7 million.
Total distributions paid during 2001 were as follows (in thousands except per unit amounts):
16. EARNINGS PER UNIT
The following table provides details of the basic and diluted earnings 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 11).
17. PARTNERS' CAPITAL
Of the 5,679,694 common units outstanding at December 31, 2001, 4,600,000 are held by the public, with the remaining 1,079,694 held by affiliates of the Partnership. All of the 5,679,694 subordinated units are held by affiliates of the Partnership.
During the subordination period, 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;
WILLIAMS ENERGY PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
- 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 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. However, if any person or group other than the general partner and its affiliates acquires beneficial ownership of 20 percent or more of any class of units, that group or person loses voting rights on all of its units; and
- Right to inspect our books and records at the unitholders' own expense.
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.
18. REGISTRATION STATEMENT (UNAUDITED)
The Partnership plans to file a shelf registration statement 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.
WILLIAMS ENERGY PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
19. OTHER EVENTS
On February 14, 2002, the Partnership paid cash distributions of $0.59 per unit on its outstanding common and subordinated units to unitholders of record at the close of business on February 1, 2002. The total distribution, including distributions paid to the general partner on its equivalent units, was $6.9 million.
With the payment of the $0.59 per unit distribution on February 14, 2002, the first early vesting performance measure of the one-time initial public offering grant was achieved, and 46,250 units associated with this grant vested on that date. The Partnership recognized additional compensation expense of $1.0 million with the vesting of these units in February 2002.
In January 2002, the Partnership borrowed $8.5 million to finance the acquisition of a pipeline from Aux Sable and remitted those funds to complete the transaction. The Partnership entered into a long-term lease arrangement with Aux Sable under which Aux Sable is the sole lessee of these assets. The transaction will be accounted for as a capital lease.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENT WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
PART III
ITEM 10.
ITEM 10. PARTNERSHIP MANAGEMENT
Our general partner manages our operations and activities. Unitholders do not directly or indirectly participate in our management or operations. Our general partner owes a fiduciary duty to the unitholders. 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 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 matters, which the board of directors believes may involve conflicts of interest. When a conflict arises, the conflicts committee will determine if the resolution of the conflict of interest 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 an audit committee, which reviews our external financial reporting, recommends engagement of our independent auditors and reviews procedures for internal auditing and the adequacy of our internal accounting controls and on the compensation committee that oversees compensation decisions for the officers of Williams GP LLC as well as the compensation plans described below.
As is commonly the case with publicly-traded limited partnerships, we are managed and operated by the officers and are subject to the oversight of the directors of our general partner. All of our personnel are employees of our affiliates.
Some officers of our general partner may spend a substantial amount of time managing the business and affairs of The Williams Companies, Inc. and its affiliates. These officers may face a conflict regarding the allocation of their time between our business and the other business interests of The Williams Companies, Inc. Our general partner causes its officers to devote as much time as is necessary for the proper conduct of our business and affairs. Steven J. Malcolm and Phillip D. Wright devote approximately three percent of their time to Williams Energy Partners. Craig R. Rich devotes approximately fifty percent of his time to our operations and Don R. Wellendorf, our Senior Vice President, Chief Financial Officer and Treasurer, devotes approximately seventy-five percent of his time to our operations. Jay A. Wiese devotes ninety-five percent of his time to our operations. The board of directors of the general partner is presently composed of seven directors.
DIRECTORS AND EXECUTIVE OFFICERS OF WILLIAMS GP LLC
The following table sets forth certain information with respect to the executive officers and members of the board of directors of our general partner. Executive officers and directors are elected for one-year terms.
Steven J. Malcolm serves as the Chief Executive Officer and Chairman of the Board of Directors of our general partner and was elected as Chief Executive Officer on January 7, 2001, and Director on February 9, 2001. He is currently President and Chief Executive Officer of The Williams Companies, Inc. and has served in the capacity as President since September 2001, and as Chief Executive Officer since January 2002. From 1998 to September 2001, he served as President and Chief Executive Officer of Williams Energy Services, LLC. From 1994 to 1998, he served as Senior Vice President for The Williams Companies, Inc.'s 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.
Phillip D. Wright serves as President, Chief Operating Officer and Director of our general partner and was elected as President and Chief Operating Officer on January 7, 2001, and Director on February 9, 2001. He is currently President and Chief Executive Officer for Williams Energy Services, LLC and has served in that capacity since September 2001. From 1996 to September 2001, he served as Senior Vice President of Enterprise Development and Planning for Williams Energy Services, LLC. From 1989 to 1996 he held various senior management positions with The Williams Companies, Inc.'s primary refined product pipeline, Williams Pipe Line Company, Williams Energy Ventures, Inc. and Williams Energy Services Company. Prior to 1989, he spent 13 years working for Conoco, Inc.
Don R. Wellendorf serves as Senior Vice President, Chief Financial Officer, Treasurer and Director of our general partner and was elected as Senior Vice President, Chief Financial Officer and Treasurer on January 7, 2001, and as Director on February 9, 2001. Since 1998, he has served as Vice President of Strategic Development and Planning for Williams Energy Services, LLC. Prior to The Williams Companies, Inc.'s merger with MAPCO Inc. in 1998, he was Vice President and Treasurer for MAPCO from 1995 to 1998. From 1994 to 1995, he served as Vice President and Corporate Controller for MAPCO. He began his career in 1979 as an accountant with MAPCO and held various accounting positions with MAPCO from 1979 to 1994.
Jay A. Wiese serves as Vice President, Terminal Services and Development of our general partner and was elected on January 7, 2001. He is currently Managing Director, Terminal Services and Commercial Development for Williams Energy Services, LLC and has served in that capacity since 2000. From 1995 to 2000, he served as Director, Terminal Services and Commercial Development of The Williams Companies, Inc.'s 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 Company. He joined Williams Pipe Line Company in 1982.
Craig R. Rich serves as General Counsel of our general partner and was elected on January 7, 2001. He is currently Associate General Counsel of Williams Energy Services, LLC and has served in that capacity since 1996. From 1993 to 1996, he served as General Counsel of The Williams Companies, Inc.'s midstream gas
and liquids division. Prior to that time, Mr. Rich was a Senior Attorney representing Williams Gas Pipeline-West. He joined Williams in 1985.
Keith E. Bailey serves as a Director of the general partner and was elected on February 9, 2001. He is currently Chairman of the Board of The Williams Companies, Inc. and served in that capacity since 1994. He served as President of The Williams Companies, Inc. from 1992 to 1994 and served as its Chief Executive Officer from 1994 to January 2002. He served as Executive Vice President of The Williams Companies, Inc. from 1986 to 1992.
William A. Bruckmann, III serves as a director of our general partner and was elected on May 9, 2001. He is a former managing director at Chase Securities, Inc. He has more than 25 years of banking experience, starting with Manufacturers Hanover Trust Company, where he became a senior officer in 1985. Mr. Bruckmann later served as managing director, sector head of the Manufacturers Hanover's gas pipeline and midstream practices through the acquisition of Manufacturers Hanover by Chemical Bank and the acquisition of Chemical Bank by Chase Bank.
Don J. Gunther serves as a director of our general partner and was elected May 9, 2001. He is a retired vice chairman of Bechtel Group Inc. He began his career with Bechtel in 1961 and was promoted to a variety of positions, including Bechtel's executive committee in 1989; president of Bechtel Petroleum in 1984; president of Europe, Africa, Middle East and southwest Asia operations in 1992; and president of Bechtel Americas in 1995. He was named vice chairman in July 1997, retiring from the position in 1998.
William W. Hanna serves as a director of our general partner and was elected on January 18, 2002. He is a retired vice chairman of Koch Industries where he held management and leadership positions since he commenced employment in 1968. In his first year, he established a gas and gas liquids group. In 1981, he became executive vice president of energy products for Koch. In 1984, he was elected to the board of directors, and in 1987, was named president and chief operating officer. In 1999, he was named vice chairman.
COMPLIANCE WITH SECTION 16(a) OF THE SECURITIES EXCHANGE ACT OF 1934
Section 16(a) of the Securities Exchange Act of 1934 requires directors, executive officers and persons who beneficially own more than 10 percent 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 percent unitholders. Based on a review of the copies of such forms and amendments thereto received by us with respect to 2001, we are not aware of any late filings.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
We have no employees. We are managed by the officers of our general partner. We reimburse The Williams Companies, Inc. for indirect and direct expenses incurred on our behalf, as discussed in Part II, Item 7. A percentage of the compensation expense of each executive officer is allocated by The Williams Companies, Inc. to us as follows: Mr. Malcolm, three percent; Mr. Rich, fifty percent; Mr. Wellendorf, seventy-five percent; Mr. Wiese, ninety-five percent; and Mr. Wright, three percent. The following table represents compensation expense allocated to us by The Williams Companies, Inc. for the fiscal year ended
December 31, 2001, for the CEO and each of the four other most highly compensated executive officers of our general partner.
ALLOCATED SUMMARY COMPENSATION TABLE
- ---------------
(1) Represents expense allocated by our general partner to us on behalf of each executive officer for contributions made by the general partner to the Investment Plus Plan, a defined contribution plan.
ALLOCATED STOCK OPTION GRANTS IN THE LAST FISCAL YEAR
The following table provides certain information concerning the grant 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 represent The Williams Companies, Inc. allocation to us as follows: Mr. Malcolm, three percent; Mr. Rich, fifty percent; Mr. Wellendorf, seventy-five percent; Mr. Wiese, ninety-five percent; and Mr. Wright, three percent.
ALLOCATED WILLIAMS OPTION GRANTS IN LAST FISCAL YEAR
- ---------------
(1) Options granted in 2001 were granted subject to accelerated vesting if certain future Williams' stock prices or specific Williams' financial performance targets are achieved. The Williams Companies, Inc. granted these options under its 1996 Stock Plan and its Stock Plan for Nonofficer Employees. Williams' stock option shares granted prior to the April 23, 2001 spinoff of Williams Communications Group, Inc. were adjusted as a result of the spinoff using a factor of 1.089263 per share.
(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 and dividend yield. The model does not take into account that the stock options are subject to vesting restrictions and that executives cannot sell their 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 29.6 percent. The weighted-average risk-free rate of return is 5.3 percent. The model assumes a dividend yield of 1.9 percent and an exercise date at the end of the contractual term in 2011. 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' stock price.
ALLOCATED OPTION EXERCISES AND FISCAL YEAR-END VALUES
The following table provides certain information on stock option 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, 2001. This table represents the allocated value of option exercises of Williams' stock.
ALLOCATED OPTION EXERCISES OF WILLIAMS' STOCK IN LAST FISCAL YEAR AND FISCAL YEAR-END OPTION VALUES
- ---------------
(1) Williams' stock option shares granted and unexercised prior to the April 23, 2001 spinoff of Williams Communications Group, Inc. were adjusted as a result of the spinoff using a factor of 1.089263.
The following table provides certain information concerning the grant of our units under the Williams Energy Partners' Long-Term Incentive Plan during the last fiscal year to the named executive officers:
LONG-TERM INCENTIVE PLAN-AWARDS IN LAST FISCAL YEAR
- ---------------
(1) Represents an initial public offering grant of our phantom units on April 19, 2001 (market values at date of grant are noted as follows): Mr. Malcolm, 13,000 units valued at $399,100; Mr. Rich, 5,000 units valued at $153,500; Mr. Wellendorf, 13,000 units valued at $399,100; Mr. Wiese, 15,500 units valued at $475,850 and Mr. Wright, 13,000 units valued at $399,100. The units are subject to early vesting if we achieve certain performance measures.
(2) Represents phantom units of deferred limited interest granted on April 19, 2001 (market values at date of grant are noted as follows): Mr. Rich, 4,500 units valued at $138,150; Mr. Wellendorf, 13,300 units valued at $408,310; Mr. Wiese, 4,500 units valued at $138,150; and Mr. Wright, 15,800 units valued at
$485,060. At the end of the vesting period, the number of units awarded under this grant will be determined based on our 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.
COMMITTEES, MEETINGS AND DIRECTOR COMPENSATION
Our general partner's Board of Directors has the responsibility for establishing broad policies and for our overall performance. However, the Board is not involved in our day-to-day operations. The Board is kept informed of our business through discussions with the Chief Executive Officer, and other officers, by reviewing analyses and reports provided to it on a regular basis and by participating in Board and Committee meetings.
Our general partner's Board of Directors held 4 meetings during 2001. Each director during 2001 attended all of the Board meetings. The Board has established standing committees to consider designated matters. The Committees of the Board are Audit, Compensation and Conflicts.
Audit Committee.
The members of the Audit Committee are: William A. Bruckmann, III, Chairman, Don J. Gunther and William W. Hanna. The Audit Committee is composed of nonemployee directors who review our external financial reporting, recommend engagement of our independent auditors and review procedures for internal auditing and the adequacy of our internal accounting controls. The Committee held 4 meetings during 2001 and all members of the Committee in 2001 attended each of the meetings.
Compensation Committee.
The members of the Compensation Committee are: Don J. Gunther, Chairman, William A. Bruckmann, III and William W. Hanna. The members of the Compensation Committee oversee related compensation decisions for the officers of our general partner. The Committee held 1 meeting during 2001 and all members of the Committee in 2001 were in attendance.
Conflicts Committee.
The members of the Conflicts Committee are: William A. Bruckmann, III, Chairman, Don J. Gunther and William W. Hanna. The Conflicts Committee reviews specific matters which the board of directors believe may involve conflicts of interest. The Conflicts Committee will determine if the resolution of the conflict of interest 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. The Committee held 2 meetings during 2001 and all members of the Committee in 2001 were in attendance.
Compensation of Directors.
Employee directors receive no additional compensation for service on our general partner's Board of Directors or Committees of the Board. Nonemployee directors receive an annual retainer of $10,000 in cash and 400 of our common units. Chairmen of the Audit, Compensation and Conflicts Committees receive an annual retainer of $1,000. Nonemployee directors receive $1,000 for each Board meeting attended and $500 for each Audit, Compensation or Conflicts Committee meeting attended.
Nonemployee 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. Nonemployee 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 2001.
In addition, each independent director will be reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director will be fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth the beneficial ownership of units held by beneficial owners of five percent or more of the units, by directors of the general partner, by each named executive officer of the general partner and by all directors and executive officers of the general partner as a group as of February 28, 2002.
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(1) Williams GP LLC is owned through Williams Energy Services, LLC and Williams Natural Gas Liquids, Inc., which are subsidiaries of The Williams Companies, Inc. The address of The Williams Companies, Inc., Williams Energy Services, LLC and Williams Natural Gas Liquids, Inc. is One Williams Center, Tulsa, Oklahoma 74172.
(2) Does not include any common units or subordinated units owned by Williams Energy Services, LLC or by Williams Natural Gas Liquids, Inc. Mr. Wright in his capacity as Chairman and Chief Executive Officer of Williams Energy Services, LLC and as Chairman, President and Director of Williams Natural Gas Liquids, Inc. may be deemed to beneficially own these units.
(3) Does not include any common units or subordinated units owned by Williams Energy Services, LLC or by Williams Natural Gas Liquids, Inc. Mr. Bailey in his capacity as Chairman and Mr. Malcolm in his capacity as Chief Executive Officer of The Williams Companies, Inc., which is the owner of Williams Energy Services, LLC and Williams Natural Gas Liquids, Inc., may be deemed to beneficially own these units.
(4) In each instance, a dash ( -- ) indicates that the individual or group does not own any units, or the percentage calculation is less than 0.1 percent.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Williams Energy Marketing & Trading Company and Williams Refining & Marketing, L.L.C., subsidiaries of The Williams Companies, Inc. and affiliates of the Partnership, are significant customers at our petroleum product terminals, representing 11.0 percent and 7.2 percent, respectively, of our total revenues for the year ended December 31, 2001. The services we provide them are conducted pursuant to various contracts between them and the Partnership. As of December 31, 2001, 3 percent of the revenues from these affiliates were generated under contracts renewing on a monthly basis, while 97 percent were generated under contracts with remaining terms in excess of one year or that are renewed on an annual basis.
Affiliates of The Williams Companies, Inc. own 1,079,694 common units and 5,679,694 subordinated units representing an approximate aggregate 60 percent limited partner interest in us and Williams OLP, L.P. In addition, Williams GP LLC owns an aggregate 2 percent general partner interest in us and Williams OLP, L.P. The general partner's ability, as general partner, to manage and operate Williams Energy Partners and The Williams Companies, Inc.'s affiliates' ownership of an approximate aggregate 60 percent limited partner
interest in us effectively gives the general partner the right to veto some actions of Williams Energy Partners and to control the management of Williams Energy Partners L.P.
DISTRIBUTIONS AND PAYMENTS TO THE GENERAL PARTNER AND ITS AFFILIATES
The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the 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.
FORMATION STAGE
The consideration received by our general partner and its affiliates, Williams Energy Services, LLC and Williams Natural Gas Liquids, Inc., for the transfer of the affiliates' interests in the subsidiaries and a capital contribution...................... 1,679,694 common units and 5,679,694 subordinated units;
a combined 2 percent general partner interest in Williams Energy Partners L.P. and Williams OLP, L.P.;
the incentive distribution rights; and
$166.5 million of the net proceeds of our initial public offering of the common units and the borrowings under the credit facility. In addition, the net proceeds of $12.1 million from the exercise of the underwriters' over-allotment option in our initial public offering were used to redeem 600,000 common units from Williams Energy Services, LLC, an affiliate of the general partner, as partial reimbursement for capital expenditures incurred by Williams Energy Services, LLC for assets we own after the initial public offering.
Williams Energy Services, LLC and Williams Natural Gas Liquids, Inc., affiliates of The Williams Companies, Inc., transferred to us their interests in the entities that became our subsidiaries in exchange for 1,679,694 common units, 5,679,694 subordinated units, the incentive distribution rights and the combined 2 percent general partner interest described above. The common units and subordinated units received by Williams Energy Services, LLC and Williams Natural Gas Liquids, Inc. were valued at the $21.50 initial public offering price. In addition, the over-allotment was exercised for 600,000 common units. Those units were redeemed from the 1,357,193 common units initially owned by Williams Energy Services, LLC. After the redemption of these units, affiliates of the Partnership owned 1,079,694 common units.
OPERATIONAL STAGE
Distributions of available cash to our general partner and its affiliates........................ Cash distributions will generally be made 98 percent to the unitholders, including to affiliates of the general partner as holders of common units and subordinated units, and 2 percent to the general partner. However, distributions that exceed the specified target levels will result in our general partner receiving increasing percentages of the distributions, up to 50 percent of the distributions above the highest target level.
Assuming we have sufficient available cash to continue to pay distributions on all of our outstanding units for four quarters at our current distribution level of $0.59 per unit per quarter, our general partner and its affiliates would receive annual distributions of approximately $0.6 million on the combined 2 percent general partner interest and a distribution of approximately $16.0 million on their common and subordinated units.
Payments to our general partner and its affiliates...................... Our general partner and its affiliates will not receive any management fee or other compensation for the management of Williams Energy Partners L.P. Our general partner and its affiliates will be reimbursed, however, for direct and indirect expenses incurred on our behalf. Per the Omnibus Agreement, in 2001 we were charged $6.0 million, prorated for the Partnership's partial 2001 year, for general and administrative expenses, excluding expenses associated with incentive compensation plans and completed acquisitions. The annual general and administrative expense charge was increased to $6.3 million by the end of 2001. The increase is due to the incremental general and administrative expenses associated with acquisitions made during 2001. In 2002, the annual general and administrative expense charge was increased to $6.7 million, including the annual escalator as provided in the Partnership's Omnibus Agreement.
Withdrawal or removal of our general partner............................. If our general partner withdraws in violation of the Partnership agreement or is removed for cause, a successor general partner has the option to buy the general partner interests and incentive distribution rights for a cash price equal to fair market value. If our general partner withdraws or is removed under any other circumstances, the departing general partner has the option to require the successor general partner to buy the departing general partner's interests and its incentive distribution rights for a cash price equal to fair market value.
If either of these options is not exercised, the departing general partner's interests and incentive distribution
rights will automatically convert into common units equal to the fair market value of those interests. In addition, we will be required to pay the departing general partner for expense reimbursements.
LIQUIDATION STAGE
Liquidation......................... Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.
RIGHTS OF OUR GENERAL PARTNER
Our general partner and its affiliates own 1,079,694 common units and 5,679,694 subordinated units, representing an aggregate 58.3 percent limited partner interest in Williams Energy Partners L.P. In addition, our general partner owns an aggregate 2 percent general partner interest in Williams Energy Partners L.P. and the operating limited Partnership on a combined basis. Through the general partner's ability, as general partner, to manage and operate our business and The Williams Companies, Inc.'s affiliates' ownership of 1,079,694 common units and all of the outstanding subordinated units, the general partner will control the management of our business.
OMNIBUS AGREEMENT
We entered into an agreement in February 2001 with The Williams Companies, Inc. 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.
Competition
The Williams Companies, Inc. 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. We refer to these assets below as restricted assets. The Williams Companies, Inc. will not be prohibited from owning or operating the following restricted assets:
- any restricted assets owned, leased or operated by The Williams Companies, Inc. 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 The Williams Companies, Inc. after February 9, 2001 with construction costs not greater than $20.0 million; and
- any restricted assets constructed or acquired by The Williams Companies, Inc. after February 9, 2001 that are connected to assets owned by The Williams Companies, Inc. or are primarily related to and located within 50 miles of The Williams Companies, Inc.'s refinery in Memphis, Tennessee.
If The Williams Companies, Inc. acquires or constructs restricted assets other than those identified above, it shall offer to sell such assets to us within six months of acquiring or completing construction. If we and The Williams Companies, Inc. are unable to agree on the terms of the sale, we and The Williams
Companies, Inc. 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 The Williams Companies, Inc. and us, we 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 The Williams Companies, Inc. and us, we 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 us, we will have the right to purchase the business for the amount submitted by us.
- If the valuation of the investment bank is greater than the proposed sale value submitted by The Williams Companies, Inc., we will have the right to purchase the business for the amount submitted by The Williams Companies, Inc.
If we elect not to purchase any restricted assets, The Williams Companies, Inc. will be permitted to own or operate such assets without limitation.
General and Administrative Expenses
In 2002, we will reimburse the general partner or The Williams Companies, Inc. for general and administrative expenses of not more than $6.7 million, excluding expenses associated with our Long-Term Incentive Plan. This amount may increase during the next nine years as follows:
- In each year after 2002, the amount of general and administrative expenses, excluding expenses associated with the Long-Term Incentive Plan, allocated to us by The Williams Companies, Inc. and the general partner may increase by no more than the greater of 7 percent 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.
Indemnification
Williams Energy Services, LLC 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, LLC will indemnify us for right-of-way defects or failures associated with our marine terminal facilities at Galena Park, Corpus Christi and Marrero for 15 years after February 9, 2001.
ATLAS 2000 License
The Williams Companies, Inc. 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 The Williams Companies, Inc. controls our general partner, at no charge.
Maintenance Capital Expenditures
In 2001 and 2002, The Williams Companies, Inc. will reimburse us for maintenance capital expenditures for our current operations in excess of $4.9 million per year, subject to a maximum aggregate reimbursement of $15.0 million over this two year period.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) 1 and 2.
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.
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* 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.
(c) Reports on Form 8-K.
The Partnership's unaudited earnings for the three and six months ending September 30, 2001 and 2000, were issued on Form 8-K on October 25, 2001.
The Partnership announced its acquisition of a petroleum storage and distribution facility in Gibson, Louisiana from Geonet Gathering, Inc. on Form 8-K on November 8, 2001.
(d) We do not own any partially-owned companies.
SIGNATURES
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.
WILLIAMS ENERGY PARTNERS L.P. (Registrant)
By: Williams GP LLC, its General Partner
By: /s/ SUZANNE H. COSTIN ------------------------------------ Suzanne H. Costin Attorney-in-fact
Date: March 7, 2002
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.
INDEX TO EXHIBITS
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* 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.