ITEM 1. BUSINESS
(a) General Development of Business
The Partnership is a publicly traded Delaware limited partnership formed by Sunoco, Inc. on October 15, 2001 to own, operate and acquire a geographically diverse portfolio of complementary pipeline, terminalling, and crude oil acquisition and marketing assets. The Partnership completed its initial public offering (“IPO”) on February 8, 2002. The principal executive offices of Sunoco Partners LLC, the Partnership’s general partner (the “General Partner”), are located at Mellon Bank Center, 1735 Market Street, Suite LL, Philadelphia, Pennsylvania 19103 (telephone (866) 248-4344). The Partnership’s website address is www.sunocologistics.com.
Sunoco, Inc., and its wholly-owned subsidiaries including Sunoco, Inc. (R&M), owns approximately 43.4 percent of the partnership interests at December 31, 2006, including a 2 percent general partner interest. Sunoco, Inc. and Sunoco, Inc. (R&M) are collectively referred to as “Sunoco”.
(b) Financial Information about Segments
See Part II, Item 8. Financial Statements and Supplementary Data.
(c) Narrative Description of Business
The Partnership is principally engaged in the transport, terminalling and storage of refined products and crude oil and the purchase and sale of crude oil in 12 states located in the Northeast, Midwest and Southwest United States. Sunoco accounted for approximately 31 percent of the Partnership’s total revenues for the year ended December 31, 2006. The business comprises three segments:
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The Eastern Pipeline System primarily serves the Northeast and Midwest United States operations of Sunoco and includes: approximately 1,650 miles of refined product pipelines, including a two-thirds undivided interest in the 80-mile refined product Harbor pipeline, and 58 miles of interrefinery pipelines between two of Sunoco’s refineries; approximately 140 miles of crude oil pipelines; a 9.4 percent interest in Explorer Pipeline Company, a joint venture that owns a 1,413-mile refined product pipeline; a 31.5 percent interest in Wolverine Pipe Line Company, a joint venture that owns a 721-mile refined product pipeline; a 12.3 percent interest in West Shore Pipe Line Company, a joint venture that owns a 652-mile refined product pipeline; and a 14.0 percent interest in Yellowstone Pipe Line Company, a joint venture that owns a 750-mile refined product pipeline.
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The Terminal Facilities consist of 35 refined product terminals with an aggregate storage capacity of 5.9 million barrels, primarily serving the Partnership’s Eastern Pipeline System; the Nederland Terminal, a 12.9 million barrel marine crude oil terminal on the Texas Gulf Coast; a 2.0 million barrel refined product terminal serving Sunoco’s Marcus Hook refinery near Philadelphia, Pennsylvania; one inland and two marine crude oil terminals with a combined capacity of 3.4 million barrels, and related pipelines, which serve Sunoco’s Philadelphia refinery; a ship and barge dock which serves Sunoco’s Eagle Point refinery; and a 1.0 million barrel liquefied petroleum gas (“LPG”) terminal near Detroit, Michigan.
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The Western Pipeline System gathers, purchases, sells, and transports crude oil principally in Oklahoma and Texas and consists of approximately 3,200 miles of crude oil trunk pipelines, including a 37.0 percent undivided interest in the 80-mile Mesa Pipe Line system, and approximately 500 miles of crude oil gathering lines that supply the trunk pipelines; approximately 115 crude oil transport trucks; approximately 150 crude oil truck unloading facilities; a 55.3 percent interest in the Mid-Valley Pipeline Company, a joint venture that owns a 994-mile pipeline and a 43.8 percent interest in West Texas Gulf Pipe Line Company, a joint venture that owns a 579-mile crude oil pipeline.
Revenues are generated by charging tariffs for transporting refined products, crude oil and other hydrocarbons through the pipelines and by charging fees for storing refined products, crude oil, and other hydrocarbons, and for providing other services at the Partnership’s terminals. The Partnership also generates revenue by purchasing domestic crude oil and selling it to Sunoco and other customers. Generally, as crude oil is purchased, corresponding sale transactions are simultaneously entered into involving physical deliveries of crude oil, which enables the Partnership to secure a profit on the transaction at the time of purchase and establish a substantially balanced position, thereby minimizing exposure to price volatility after the initial purchase. The Partnership’s practice is to not enter into commodity derivative contracts.
The Partnership’s primary business strategies are to generate stable cash flows, increase pipeline and terminal throughput, pursue strategic and accretive acquisitions that complement the Partnership’s existing asset base, improve operating efficiencies, and increase distributions to its unitholders.
For the year ended December 31, 2006, Sunoco accounted for approximately 66 percent of the Eastern Pipeline segment’s total revenues, approximately 67 percent of the Terminal Facilities segment’s total revenues, and approximately 30 percent of the Western Pipeline System segment’s total revenues.
Eastern Pipeline System
Refined Product Pipelines
The Partnership owns and operates approximately 1,650 miles of refined product pipelines in the Northeast and Midwest United States. The refined product pipelines transport refined products from Sunoco’s Philadelphia and Marcus Hook, Pennsylvania, Toledo, Ohio and Eagle Point, New Jersey refineries, as well as from third party locations, to markets in New York, New Jersey, Pennsylvania, Ohio, and Michigan. The refined products transported in these pipelines include multiple grades of gasoline, middle distillates (such as heating oil, diesel and jet fuel), liquefied petroleum gases (“LPGs”) (such as propane and butane), refining feedstocks, and other hydrocarbons. The Federal Energy Regulatory Commission (“FERC”) regulates the rates for interstate shipments on the Eastern Pipeline System and the Pennsylvania Public Utility Commission (“PA PUC”) regulates the rates for intrastate shipments in Pennsylvania. The Partnership also leases to Sunoco three bi-directional, 18-mile interrefinery pipelines and a four-mile pipeline spur extending to the Philadelphia International Airport.
The following table details the total shipments on the refined product pipelines in each of the years presented. Total shipments represent the total average daily pipeline throughput multiplied by the number of miles of pipeline through which each barrel has been shipped. Management of the Partnership believes that total shipments is a better performance indicator for the Eastern Pipeline System than barrels transported as certain refined product pipelines such as transfer pipelines transport large volumes over short distances and generate minimal revenues. The following excludes amounts attributable to the interrefinery pipelines and equity ownership interests in the corporate joint ventures:
The mix of refined petroleum products delivered varies seasonally, with gasoline demand peaking during the summer months, and demand for heating oil and other distillate fuels peaking in the winter. In addition, weather conditions in the areas served by the Eastern Pipeline System affect both the demand for, and the mix of, the refined petroleum products delivered through the Eastern Pipeline System, although historically any overall impact on the total volume shipped has been short term.
Crude Oil Pipelines
The Eastern Pipeline system includes a 123-mile, 16-inch crude oil pipeline that runs from Marysville, Michigan to Toledo, Ohio. This pipeline receives crude oil from the Enbridge pipeline system for delivery to
Sunoco and BP refineries located in Toledo, Ohio and to Marathon’s Samaria, Michigan tank farm, which supplies its refinery in Detroit, Michigan. Marysville is also a truck injection point for local production. During 2006, the Partnership completed an expansion project on the Marysville pipeline that increased capacity by approximately 20% to approximately 190,000 barrels per day (“bpd”).
The table below sets forth the average daily number of barrels of crude oil transported through this crude oil pipeline in each of the years presented:
(1)
Production issues at two third-party Canadian synthetic crude oil plants resulted in lower shipments on the Marysville to Toledo crude oil pipeline in 2005.
Explorer Pipeline
The Partnership owns a 9.4 percent interest in Explorer Pipeline Company (“Explorer”), a joint venture that owns a 1,413-mile common carrier refined product pipeline. The system, which is operated by Explorer employees, originates from the refining centers of Lake Charles, Louisiana and Beaumont, Port Arthur and Houston, Texas, and extends to Chicago, Illinois, with delivery points in the Houston, Dallas/Fort Worth, Tulsa, St. Louis, and Chicago areas. Explorer charges market-based rates for all its tariffs.
Wolverine Pipe Line
The Partnership owns a 31.5 percent interest in Wolverine Pipe Line Company (“Wolverine”), a joint venture that owns a 721-mile common carrier pipeline that transports primarily refined products. The system, which is operated by Wolverine employees, originates from Chicago, Illinois and extends to Detroit, Grand Haven, and Bay City, Michigan with delivery points along the way. Wolverine charges market-based rates for tariffs at the Detroit, Jackson, Niles, Hammond, and Lockport destinations.
West Shore Pipe Line
The Partnership owns a 12.3 percent interest in West Shore Pipe Line Company (“West Shore”), a joint venture that owns a 652-mile common carrier refined product pipeline. The system, which is operated by CITGO employees, originates from the Chicago, Illinois refining center and extends to Madison and Green Bay, Wisconsin with delivery points along the way. West Shore charges market-based tariff rates in the Chicago area.
Yellowstone Pipe Line
The Partnership owns a 14.0 percent interest in Yellowstone Pipe Line Company (“Yellowstone”), a joint venture that owns a 750-mile common carrier refined product pipeline. The system, which is operated by ConocoPhillips employees, originates from the Billings, Montana refining center and extends to Moses Lake, Washington with delivery points along the way. Tariff rates are regulated by the FERC for interstate shipments and the Montana Public Service Commission for intrastate shipments in Montana.
Terminal Facilities
Refined Product Terminals
The Partnership’s 35 refined product terminals receive refined products from pipelines and barges and distribute them to Sunoco and to third parties, who in turn deliver them to end-users and retail outlets. Terminals
are facilities where refined products are transferred to or from storage or a transportation system, such as a pipeline, to another transportation system, such as trucks or another pipeline. The operation of these facilities is called “terminalling.” Terminals play a key role in moving product to the end-user market by providing the following services: storage; distribution; blending to achieve specified grades of gasoline; and other ancillary services that include the injection of additives and the filtering of jet fuel. Typically, the Partnership’s terminal facilities consist of multiple storage tanks and are equipped with automated truck loading equipment that is available 24 hours a day. This automated system provides for control of allocations, credit and carrier certification. In 2006, the Partnership completed the installation of ethanol blending facilities at the balance of its 30 refined product terminals that handle gasoline.
The Partnership’s refined product terminals derive most of their revenues from terminalling fees paid by customers. A fee is charged for receiving refined products into the terminal and delivering them to trucks, barges, or pipelines. In addition to terminalling fees, the Partnership generates revenues by charging customers fees for blending, including ethanol blending, injecting additives, and filtering jet fuel. Refined product terminals generate the balance of their revenues from the handling of other hydrocarbons for Sunoco at Toledo, Ohio and from lubricants handled for Sunoco at Cleveland, Ohio. Sunoco accounts for substantially all of the Partnership’s refined product terminal revenues. The Eastern Pipeline System supplies the majority of the Partnership’s refined product terminals, with third-party pipelines and barges supplying the remainder.
The table below sets forth the total average daily throughput for the refined product terminals in each of the years presented:
The following table outlines the number of terminals and storage capacity in barrels (“bbls”) by state:
(1)
The Partnership has a 45 percent ownership interest in a terminal at Inwood, New York. The storage capacity included in the table represents the proportionate share of capacity attributable to the Partnership’s ownership interest.
Nederland Terminal
The Nederland Terminal, which is located on the Sabine-Neches waterway between Beaumont and Port Arthur, Texas, is a large marine terminal that provides storage and distribution services for refiners and other large transporters of crude oil. The terminal receives, stores, and distributes crude oil, feedstocks, lubricants, petrochemicals, and bunker oils (used for fueling ships and other marine vessels). In addition, it also blends lubricants and is equipped with petroleum laboratory facilities. The terminal currently has a total shell storage capacity of approximately 12.9 million barrels in 129 aboveground storage tanks with individual capacities of up
to 660,000 barrels. During 2006, construction of one new tank was completed which added approximately 0.4 million shell barrels of storage capacity to the terminal. Construction also continued on six new tanks, which will add approximately 3.8 million shell barrels of storage capacity to the terminal during 2007 and 2008.
The Nederland Terminal can receive crude oil at each of its five ship docks and three barge berths, which can accommodate any vessel capable of navigating the 40-foot freshwater draft of the Sabine-Neches Ship Channel. The five ship docks are capable of receiving over 1.0 million bpd of crude oil. The terminal can also receive crude oil through a number of pipelines, including the Shell pipeline from Louisiana, the Cameron Highway pipeline, the ExxonMobil pipeline, the Department of Energy (“DOE”) Big Hill pipeline, the DOE West Hackberry pipeline, and the Partnership’s Western Pipeline System. The DOE pipelines connect the terminal to the United States Strategic Petroleum Reserve’s West Hackberry caverns at Hackberry, Louisiana and Big Hill caverns near Winnie, Texas, which have an aggregate storage capacity of 370 million barrels. The Nederland Terminal is one of the facilities connected to the Cameron Highway pipeline, a 390-mile, 24-inch to 30-inch pipeline that has the capacity to deliver up to 500,000 bpd of crude oil from off-shore production developments in the Gulf of Mexico. Crude oil deliveries through the Cameron Highway pipeline began in February 2005. In the first quarter of 2006 ExxonMobil reversed the flow of crude oil on its pipeline from Patoka, Illinois to the Nederland Terminal, which resulted in the flow of Canadian crude oil to the Nederland Terminal beginning in April 2006.
The Nederland Terminal can deliver crude oil and other petroleum products via pipeline, barge, ship, rail, or truck. In the aggregate, the terminal is capable of delivering over 1.8 million bpd of crude oil to 12 connecting pipelines. The connecting pipelines include the ExxonMobil pipeline to its Beaumont, Texas refinery; the DOE pipelines to the Big Hill and West Hackberry Strategic Petroleum Reserve caverns; the Valero pipeline to its Port Arthur, Texas refinery; the TotalFinaElf pipeline to its Port Arthur, Texas refinery; the Shell pipeline to Houston, Texas refineries; the West Texas Gulf and the Partnership’s pipelines to the Mid-Valley pipeline at Longview, Texas and to the CITGO pipeline at Sour Lake, Texas; the Partnership’s pipeline to Seabreeze, Texas; and the Partnership’s pipeline to the Alon Big Spring, Texas refinery and Midland, Texas. In December 2006, the Partnership executed an agreement with Motiva Enterprises LLC to construct three additional crude oil storage tanks, with a combined capacity of approximately 2.0 million shell barrels of storage capacity, and provide a new a 12-mile 30”crude oil pipeline connection from the Nederland Terminal to Motiva’s Port Arthur, Texas refinery. Construction of these assets is expected to be completed on or before January 2010.
The table below sets forth the total average daily throughput for the Nederland Terminal in each of the years presented:
Revenues are generated at the Nederland Terminal primarily by providing term or spot storage services and throughput capability to a number of customers. Most of the terminal’s revenues in 2006 were from unaffiliated third parties.
Fort Mifflin Terminal Complex
The Fort Mifflin Terminal Complex is located on the Delaware River in Philadelphia and supplies Sunoco’s Philadelphia refinery with all of its crude oil. These assets include the Fort Mifflin Terminal, the Hog Island Wharf, the Darby Creek Tank Farm and connecting pipelines. Revenues are generated from the Fort Mifflin Terminal Complex by charging fees based on tank capacity and throughput. Substantially all of the revenues from the Fort Mifflin Terminal Complex are derived from Sunoco.
The Fort Mifflin Terminal consists of two ship docks with 40-foot freshwater drafts and nine tanks with a total storage capacity of 570,000 barrels. Crude oil and some refined products enter the Fort Mifflin Terminal
primarily from marine vessels on the Delaware River. One Fort Mifflin dock is designed to handle crude oil from very large crude carrier-class tankers and smaller crude oil vessels. The other dock can accommodate only smaller crude oil vessels.
The Hog Island Wharf is located next to the Fort Mifflin Terminal on the Delaware River and receives crude oil via two ship docks, one of which can accommodate crude oil tankers and smaller crude oil vessels and the other of which can accommodate some smaller crude oil vessels.
The Darby Creek Tank Farm is a primary crude oil storage terminal for Sunoco’s Philadelphia refinery. This facility has 26 tanks with a total storage capacity of 2.9 million barrels. Darby Creek receives crude oil from the Fort Mifflin Terminal and Hog Island Wharf via the Partnership’s pipelines. The tank farm then stores the crude oil and pumps it to the Philadelphia refinery via the Partnership’s pipelines.
The table below sets forth the average daily number of barrels of crude oil and refined products delivered to Sunoco’s Philadelphia refinery in each of the years presented:
Marcus Hook Tank Farm
The Marcus Hook Tank Farm stores substantially all of the gasoline and middle distillates that Sunoco ships from its Marcus Hook refinery. This facility has 16 tanks with a total storage capacity of approximately 2.0 million barrels. After receipt of refined products from the Marcus Hook refinery, the tank farm either stores or delivers them to the Partnership’s Twin Oaks terminal or to the Twin Oaks pump station, which supplies the Eastern Pipeline System.
The table below sets forth the total average daily throughput for the Marcus Hook Tank Farm in each of the years presented:
Eagle Point Dock
On March 30, 2004, the Partnership acquired the Eagle Point logistics assets from Sunoco, including a ship and barge dock connected to the Sunoco Eagle Point refinery. This dock, located on the Delaware River, can accommodate three ships or barges and supplies the Eagle Point refinery with all of its crude oil. The dock can also receive and deliver intermediate products and refined products to outbound ships and barges.
The table below sets forth the total average daily throughput for the Eagle Point Dock in each of the years presented:
(1)
For the period from March 30, 2004, the date of acquisition, to December 31, 2004.
Inkster Terminal
The Inkster Terminal, located near Detroit, Michigan, consists of eight salt caverns with a total storage capacity of 975,000 barrels. The Partnership uses the Inkster Terminal’s storage in connection with its Toledo, Ohio to Sarnia, Canada pipeline system and for the storage of LPGs from Sunoco’s Toledo refinery and from Canada. The terminal can receive and ship LPGs in both directions at the same time and has a propane truck loading rack.
Western Pipeline System
Crude Oil Pipelines
The Partnership owns and operates approximately 3,200 miles of crude oil trunk pipelines and approximately 500 miles of crude oil gathering pipelines in Texas and Oklahoma. The Partnership also delivers crude oil and other feedstocks for Sunoco and other third parties from points in Texas and Oklahoma.
The Partnership’s pipelines also access several trading hubs, including the largest and most significant trading hub for crude oil in the United States located in Cushing, Oklahoma (“Cushing”), as well as other trading hubs located in Midland, Colorado City and Longview, Texas. The Partnership’s crude oil pipelines also deliver to and connect with other pipelines that deliver crude oil to a number of third-party refineries. The table below sets forth the average daily number of barrels of crude oil and other feedstocks transported on the Partnership’s crude oil pipelines in each of the years presented:
(1)
Includes results from the Corsicana to Wichita Falls crude oil pipeline and the undivided joint interest in the Mesa pipeline from the acquisition date.
(2)
Includes results from the Millennium and Kilgore crude oil pipelines and the Amdel and White Oil crude oil pipelines from the acquisition dates.
Texas
The Partnership owns and operates approximately 2,400 miles of crude oil trunk pipelines and approximately 300 miles of crude oil gathering pipelines in Texas. The Texas system is connected to the Mid-Valley and West Texas Gulf pipelines which are 55.3 percent and 43.8 percent, respectively, owned by the Partnership, other third-party pipelines, and the Partnership’s Nederland Terminal.
Revenues are generated from tariffs paid by shippers utilizing the Partnership’s transportation services. These tariffs are filed with the Texas Railroad Commission and the FERC.
The Partnership’s Texas crude oil pipeline system also includes the following assets acquired since December 31, 2004:
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Corsicana to Wichita Falls Pipeline Acquisition. On August 1, 2005, the Partnership purchased, from an affiliate of Exxon Mobil Corporation, a crude oil pipeline system and storage facilities located in Texas for approximately $100.0 million. The pipeline system consists primarily of a 187-mile, 16-inch pipeline with an operating capacity of 125,000 bpd. It originates at a crude oil terminal in Corsicana, Texas and terminates at Wichita Falls, Texas. The storage facilities include the Corsicana terminal, which has 2.9 million barrels of shell capacity for crude oil, and the Ringgold, Texas terminal, which consists of 0.5 million barrels of shell capacity for crude oil. In addition, the Partnership invested approximately $16.0 million to construct a new 20-mile, 24-inch pipeline to connect the Corsicana terminal to the West Texas Gulf pipeline at Wortham, Texas, in which the Partnership has a 43.8% ownership interest. Construction of the new 20-mile pipeline was completed in December 2005.
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Mesa Pipe Line Undivided Interest Acquisition. On December 5, 2005, the Partnership purchased a subsidiary of Sunoco, which owned a 7.2 percent undivided interest in the Mesa Pipe Line system for approximately $1.3 million. The Mesa Pipe Line system consists of an 80-mile, 24-inch crude oil pipeline from Midland, Texas to Colorado City, Texas, with an operating capacity of 316,000 bpd, and approximately 0.8 million barrels of shell capacity at Midland. The Mesa pipeline connects to the West Texas Gulf pipeline, which supplies crude oil to the Mid-Valley pipeline. On December 29, 2005, the Partnership purchased an additional 29.8 percent interest in Mesa from Chevron for approximately $5.3 million, increasing the Partnership’s ownership to 37.0 percent. On April 21, 2006, the Partnership and the other owner agreed to extend the Mesa operating agreement, previously scheduled to expire on June 30, 2006, until December 31, 2009.
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Millennium and Kilgore Pipeline Acquisition. On March 1, 2006, the Partnership purchased a Texas crude oil pipeline system from affiliates of Black Hills Energy, Inc. for approximately $40.9 million. The system consists of (a) the Millennium Pipeline, a 200-mile, 12-inch crude oil pipeline with approximately 65,000 bpd operating capacity, originating near the Partnership’s Nederland Terminal, and terminating at Longview Texas; (b) the Kilgore Pipeline, a 190-mile, 10-inch crude oil pipeline with approximately 35,000 barrel per day capacity originating in Kilgore, Texas and terminating at the Oil Tanking terminal in the Houston, Texas region; (c) approximately 0.9 million barrels of shell storage capacity at Kilgore, and Longview, Texas, approximately 0.6 million of which were inactive; (d) a crude oil sales and marketing business; and (e) crude oil line fill and working inventory.
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Amdel and White Oil Pipeline Acquisition. On March 1, 2006, the Partnership acquired a Texas crude oil pipeline system from Alon USA Energy, Inc. for approximately $68.0 million. The system consists of (a) the Amdel Pipeline, a 503-mile, 10-inch common carrier crude oil pipeline with approximately 27,000 bpd operating capacity, originating at the Nederland Terminal, and terminating at Midland, Texas, and (b) the White Oil Pipeline, a 25-mile, 10-inch crude oil pipeline with approximately 40,000 bpd operating capacity, originating at the Amdel Pipeline and terminating at Alon’s Big Spring, Texas refinery. Alon has agreed to ship a minimum of 15,000 bpd on the pipelines under a 10-year, throughput and deficiency agreement. The pipelines were idle at the time of purchase and were re-commissioned by the Partnership during the second quarter 2006. The pipelines began making deliveries during the fourth quarter 2006. The Partnership also began construction to expand capacity on the Amdel Pipeline from approximately 27,000 to 40,000 bpd, which it expects to be completed by the first quarter of 2007, and to construct new tankage at the Nederland Terminal to service these new volumes more efficiently.
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Mid-Valley Pipeline Acquisition. On August 18, 2006, the Partnership purchased from Sunoco a 100 percent interest in Sun Pipe Line Company of Delaware LLC, the owner of a 55.3 percent equity interest (50 percent voting rights) in Mid-Valley Pipeline Company (“Mid-Valley”) for $65 million, subject to certain adjustments five years following the date of closing, based on the throughput of Sunoco. Mid-Valley owns a 994-mile pipeline, which originates in Longview, Texas and terminates in Samaria, Michigan, and has operating capacity of approximately 238,000 bpd and 4.2 million barrels of shell storage capacity. Mid-Valley provides crude oil to a number of refineries, primarily in the Midwest United States. The Partnership will continue to be the operator of the Mid-Valley pipeline.
Oklahoma
The Partnership owns and operates a crude oil pipeline and gathering system in Oklahoma. This system contains approximately 800 miles of crude oil trunk pipelines and approximately 200 miles of crude oil gathering pipelines. The Partnership has the ability to deliver substantially all of the crude oil gathered on its Oklahoma system to Cushing. Additionally, deliveries are made on the Oklahoma system to Sunoco and other third-party refiners.
Revenues are generated on the Partnership’s Oklahoma system from tariffs paid by shippers utilizing the Partnership’s transportation services. The Partnership files these tariffs with the Oklahoma Corporation Commission and the FERC. The Partnership is one of the largest purchasers of crude oil from producers in the state, and is the primary shipper on its Oklahoma system.
West Texas Gulf Pipe Line
The Partnership owns a 43.8 percent interest in the West Texas Gulf Pipe Line Company (“West Texas Gulf”), a joint venture that owns a 579-mile common carrier crude oil pipeline. The system originates from the West Texas oil fields at Colorado City and the Nederland crude oil import terminals and extends to Longview, Texas where deliveries are made to several pipelines, including the Mid-Valley pipeline. On January 1, 2005, the Partnership became the operator of this system.
Crude Oil Acquisition and Marketing
In addition to receiving tariff revenues for transporting crude oil on the Western Pipeline System, the Partnership generates most of its revenues through its crude oil acquisition and marketing activities. These activities are primarily in Oklahoma and Texas and include: purchasing crude oil at the wellhead from producers and in bulk from aggregators at major pipeline interconnections and trading locations; transporting crude oil on the Partnership’s pipelines and trucks or, when necessary or cost effective, pipelines or trucks owned and operated by third parties; and marketing crude oil to major integrated oil companies, independent refiners, including Sunoco for its Tulsa and Toledo refineries, and resellers in various types of sale and exchange transactions.
The crude oil acquisition and marketing operations generate substantial revenue and cost of products sold because they reflect the sales price and cost of the significant volume of crude oil bought and sold. However, the absolute price levels for crude oil normally do not bear a relationship to gross margin, although these price levels significantly impact revenue and cost of products sold. As a result, period-to-period variations in revenue and cost of products sold are not generally meaningful in analyzing the variation in gross margin for the crude oil acquisition and marketing operations. The operating results of the crude oil acquisition and marketing operations are dependent on its ability to sell crude oil at a price in excess of the aggregate cost. Management of the Partnership believes gross margin, which is equal to sales and other operating revenue less cost of products sold and operating expenses and depreciation and amortization, is a key measure of financial performance for the Western Pipeline System.
The Partnership mitigates most of its pricing risk on purchase contracts by selling crude oil for an equal term on a similar pricing basis. The Partnership also mitigates most of its volume risk by entering into sales agreements, generally at the same time that purchase agreements are executed, at similar volumes. As a result, volumes sold are generally equal to volumes purchased. The Partnership does not acquire and hold crude oil futures contracts or enter into other commodity derivative contracts.
Crude Oil Purchases and Exchanges
In a typical producer’s operation, crude oil flows from the wellhead to a separator where the petroleum gases are removed. After separation, the producer treats the crude oil to remove water, sand, and other contaminants and then moves it to an on-site storage tank. When the tank is full, the producer contacts the Partnership’s field personnel to purchase and transport the crude oil to market. The crude oil in producers’ tanks is then either delivered directly or transported via truck to the Partnership’s pipeline or to a third party’s pipeline. The trucking services are performed either by the Partnership’s truck fleet or a third-party trucking operation.
Crude oil purchasers who buy from producers compete on the basis of competitive prices and highly responsive services. Management of the Partnership believes that its ability to offer competitive pricing and high-quality field and administrative services to producers is a key factor in its ability to maintain its volume of lease purchased crude oil and to obtain new volume.
The Partnership also enters into exchange agreements to enhance margins throughout the acquisition and marketing process. When opportunities arise to increase its margin or to acquire a grade of crude oil that more nearly matches its delivery requirement or the preferences of its refinery customers, the Partnership’s physical
crude oil is exchanged with third parties. Generally, the Partnership enters into exchanges to acquire crude oil of a desired quality in exchange for a common grade crude oil or to acquire crude oil at locations that are closer to the Partnership’s end-markets, thereby reducing transportation costs.
The Partnership enters into contracts with producers at market prices generally for a term of one year or less, with a majority of the transactions on a 30-day renewable basis. For the year ended December 31, 2006, the Partnership purchased 176,619 bpd from approximately 3,400 producers and from approximately 34,000 leases, and undertook 294,970 bpd of exchanges and bulk purchases during the same period.
The following table shows the Partnership’s average daily volume for crude oil lease purchases and sales and other exchanges and bulk purchases for the years presented:
Market Conditions
Market conditions impact the Partnership’s sales and marketing strategies. The Partnership operates the crude oil acquisition and marketing activities differently as market conditions change. During periods when demand for crude oil is weak, the market for crude oil is often in “contango”, meaning that the price of crude oil in a given month is less than the price of crude oil for delivery in a subsequent month. In a contango market, the Partnership will use its tankage to improve margins by storing crude oil it has purchased at lower current prices for delivery in future months at higher prices. When there is a higher demand than supply of crude oil in the near term, the market is referred to as “backwardated”, meaning that the price of crude oil in a given month exceeds the price of crude oil for delivery in a subsequent month. A backwardated market generally has a positive impact on marketing margins because crude oil marketers can continue to purchase crude oil at fixed premiums to posted prices while selling crude oil at higher premiums to such prices. The Partnership’s storage capacity is less utilized in a backwardated market, however, the increased marketing margins normally reduce the impact of lower storage revenues.
The periods between a backwardated market and a contango market are referred to as transition periods. These transition periods may have either an adverse or beneficial impact on gross margins. A prolonged transition from a backwardated market to a contango market represents the most difficult environment for the Partnership’s sales and marketing activities. Management normally seeks to reduce the adverse impact during such transition periods by renegotiating its crude oil contracts.
Crude Oil Trucking
The Partnership owns approximately 150 crude oil truck unloading facilities in Oklahoma, Texas, and New Mexico, the majority of which are located on the Partnership’s pipeline system. Approximately 180 crude oil truck drivers are employed by a subsidiary of the general partner of the Partnership and approximately 115 crude oil transport trucks are owned. The crude oil truck drivers pick up crude oil at production lease sites and transport it to various truck unloading facilities on the Partnership’s pipelines and third-party pipelines. Third-party trucking firms are also retained to transport crude oil to certain facilities.
Pipeline and Terminal Control Operations
Almost all of the Partnership’s refined products and crude oil pipelines are operated via satellite, microwave, and frame relay communication systems from central control rooms located in Montello, Pennsylvania and Sugar Land, Texas. The Montello control center primarily monitors and controls the Partnership’s Eastern Pipeline System, and the Sugar Land control center primarily monitors and controls the Western Pipeline System. The Nederland Terminal has its own control center.
The control centers operate with Supervisory Control and Data Acquisition, or SCADA, systems that continuously monitor real time operational data, including refined product and crude oil throughput, flow rates, and pressures. In addition, the control centers monitor alarms and throughput balances. The control centers operate remote pumps, motors and valves associated with the delivery of refined products and crude oil. The computer systems are designed to enhance leak-detection capabilities, sound automatic alarms if operational conditions outside of pre-established parameters occur, and provide for remote-controlled shutdown of pump stations on the Partnership’s pipelines. Pump stations and meter-measurement points along the Partnership’s pipelines are linked by satellite or telephone communication systems for remote monitoring and control, which reduces the requirement for full-time on-site personnel at most of these locations.
Acquisitions
The Partnership completed the following acquisitions in the three years ended December 31, 2006:
Mid-Valley Pipeline Acquisition. On August 18, 2006, the Partnership purchased from Sunoco a 100 percent interest in Sun Pipe Line Company of Delaware LLC, the owner of a 55.3 percent equity interest (50 percent voting interest) in Mid-Valley for approximately $65 million, subject to certain adjustments five years following the date of closing, based on throughput by Sunoco. For further information, see “Western Pipeline System” discussion above.
Amdel and White Oil Pipeline Acquisition. On March 1, 2006, the Partnership acquired a Texas crude oil pipeline system from Alon USA Energy, Inc. for approximately $68.0 million. For further information, see “Western Pipeline System” discussion above.
Millennium and Kilgore Pipeline Acquisition. On March 1, 2006, the Partnership purchased a Texas crude oil pipeline system from affiliates of Black Hills Energy, Inc. for approximately $40.9 million. For further information, see “Western Pipeline System” discussion above.
Mesa Pipe Line Undivided Interest Acquisition. On December 5, 2005, the Partnership purchased a subsidiary of Sunoco which owned a 7.2 percent undivided interest in the Mesa Pipe Line system for approximately $1.3 million. On December 29, 2005, the Partnership purchased an additional 29.8 percent interest in Mesa from Chevron for approximately $5.3 million, increasing its combined interest to 37.0 percent. For further information, see “Western Pipeline System” discussion above.
Corsicana to Wichita Falls Pipeline Acquisition. On August 1, 2005, the Partnership purchased, from an affiliate of Exxon Mobil Corporation, a crude oil pipeline system and storage facilities located in Texas for approximately $100.0 million. For further information, see “Western Pipeline System” discussion above.
Columbus Terminal Acquisition. On November 30, 2004, the Partnership acquired a refined products terminal located in Columbus, Ohio for approximately $8.0 million. The terminal is connected to a third-party, refined product, common carrier pipeline and includes 6 refined product tanks with approximately 160,000 barrels of working storage capacity, located on 13 acres; two truck racks for shipping gasoline, distillate fuels, and ethanol via tanker truck; and rail siding access for 4 rail cars for ethanol handling.
Harbor Pipeline Interest Acquisition. On June 28, 2004, the Partnership purchased an additional 33.3 percent undivided interest in the Harbor pipeline for approximately $7.3 million. The Harbor pipeline is an 80-mile, 180,000 bpd refined product, common carrier pipeline originating near Woodbury, New Jersey and terminating in Linden, New Jersey. As a result of this transaction, the Partnership increased its undivided ownership interest to 66.7 percent and continues to operate the pipeline.
Baltimore and Manassas Terminals Acquisition. On April 28, 2004, the Partnership purchased two refined product terminals located in Baltimore, Maryland and Manassas, Virginia for approximately $12.0 million. The Baltimore terminal is connected to a third-party, refined product, common carrier pipeline and includes 13 refined product tanks with approximately 646,000 barrels of working storage capacity, located on 35 acres; one truck rack for shipping gasoline and distillate fuels via tanker truck; and one marine dock with two berths for receiving refined products. The Manassas terminal is connected to a third-party, refined product, common carrier pipeline and includes 7 refined product tanks with approximately 277,000 barrels of working storage capacity, located on 11 acres, and one truck rack for shipping gasoline and distillate fuels via tanker truck.
Eagle Point Logistics Assets Acquisition. On March 30, 2004, the Partnership acquired the Eagle Point refinery logistics assets from Sunoco for approximately $20 million. The Eagle Point logistics assets consist of a crude oil and refined product ship and barge dock, a refined product truck rack, and a 4.5 mile, refined product pipeline from the Eagle Point refinery to the origin of the Harbor pipeline. In connection with the acquisition, the Partnership entered into a throughput agreement with Sunoco whereby they have agreed to minimum volumes on the truck rack upon completion of certain capital improvements, which were completed during the fourth quarter of 2004.
Although the Partnership does not currently engage in business unrelated to the transportation or storage of crude oil and refined products and the other businesses discussed above, management of the Partnership may, in the future, consider and make acquisitions in other business areas.
Competition
As a result of the physical integration with Sunoco, the Partnership believes that it will not face significant competition for crude oil transported to the Philadelphia, Toledo, Tulsa, and Eagle Point refineries, or refined products transported from the Philadelphia, Marcus Hook, Toledo, and Eagle Point refineries. For further information on this agreement, see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Agreements with Sunoco” For the year ended December 31, 2006, Sunoco accounted for approximately 31 percent of the Partnership’s total revenues.
Eastern Pipeline System
Nearly all of the Eastern Pipeline System is directly linked to Sunoco’s refineries. Sunoco constructed or acquired these assets as the most cost-effective means to access raw materials and distribute refined products. Generally, pipelines are the lowest cost method for long-haul, overland movement of refined products. Therefore, the most significant competitors for large volume shipments in the area served by the Eastern Pipeline System are other pipelines. Management of the Partnership believes that high capital requirements, environmental considerations, and the difficulty in acquiring rights-of-way and related permits make it difficult for other companies to build competing pipelines in areas served by the Partnership’s pipelines. As a result, competing pipelines are likely to be built only in those cases in which strong market demand and attractive tariff rates support additional capacity in an area.
Although it is unlikely that a pipeline system comparable in size and scope to the Eastern Pipeline System will be built in the foreseeable future, new pipelines (including pipeline segments that connect with existing pipeline systems) could be built to effectively compete with it in particular locations.
In addition, the Partnership, including its interests in corporate joint ventures, faces competition from trucks that deliver refined products in a number of areas that it serves. While their costs may not be competitive for longer hauls or large volume shipments, trucks compete effectively for incremental and marginal volume in many areas that are served. The availability of truck transportation places a significant competitive constraint on the Partnership’s ability to increase tariff rates.
Terminal Facilities
Historically, except for the Nederland Terminal, essentially all of the throughput at the Terminal Facilities segment has come from Sunoco. Under the terms of the pipelines and terminals storage and throughput agreement and other agreements, the Partnership will continue to receive a significant portion of the throughput at these facilities from Sunoco.
The 35 refined product terminals compete with other independent terminals regarding price, versatility, and services provided. The competition primarily comes from integrated petroleum companies, refining and marketing companies, independent terminal companies, and distribution companies with marketing and trading activities.
The primary competitors for the Nederland Terminal are its refinery customers’ docks and other terminal facilities, located in the Beaumont, Texas area.
The Inkster Terminal’s primary competition comes from other nearby facilities located in Michigan and Windsor, Canada.
Western Pipeline System
The Western Pipeline System faces competition from a number of major oil companies and smaller entities. Competition among common carrier pipelines is based primarily on transportation charges and access to crude oil supply and demand. Management of the Partnership believes that high capital costs make it unlikely that other companies will build new competing crude oil pipeline systems in the pipeline corridors served by the Western Pipeline System, however changes in refiners’ supply sources may negatively impact existing throughput on the Western Pipeline System. Crude oil purchasing and marketing competitive factors include price and contract flexibility, quantity and quality of services, and accessibility to end markets.
Partnership’s Option to Purchase Pipelines from Sunoco
The Partnership owns most of the pipeline, terminalling, storage, and related assets that support Sunoco’s refinery operations. Sunoco owns a 10.0 percent interest in Inland Corporation, which owns and operates a 611-mile refined products pipeline from Lima and Toledo, Ohio to Canton, Cleveland, Columbus, and Dayton, Ohio. This pipeline transports refined products for Sunoco from its Toledo, Ohio refinery and for the other owners.
Sunoco has granted the Partnership a ten-year option, which expires in 2012, to purchase its interest in Inland Corporation for fair market value at the date of purchase. Sunoco’s interest in Inland Corporation is subject to agreements with the other interest owners that include, among other things, consent requirements and rights of first refusal that may be triggered upon certain transfers. The exercise of the options with respect to this asset is subject to the terms and conditions of those agreements.
Sunoco has also granted the Partnership a ten-year option, which expires in 2012, to purchase an idled 370-mile 6-inch refined product pipeline from Icedale, Pennsylvania to Cleveland, Ohio for fair market value at the date of purchase.
Both of the ten-year option agreements discussed above are contained in the Omnibus Agreement that was entered into with Sunoco and the general partner. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Agreements with Sunoco”.
Safety Regulation
A majority of the Partnership’s pipelines are subject to United States Department of Transportation (“DOT”) regulations under the Hazardous Liquid Pipeline Safety Act of 1979 (“HLPSA”), and to regulation under comparable state statutes relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. In addition, the Partnership must permit access to and copying of records and must prepare certain reports and provide information required by the Secretary of Transportation.
DOT regulations, adopted in December 2000, require operators of hazardous liquid interstate pipelines to develop and follow a program to assess the integrity of all pipeline segments that could affect designated “high consequence areas”, including high population areas, drinking water and ecological resource areas that are unusually sensitive to environmental damage from a pipeline release, and commercially navigable waterways. The Partnership has prepared its own written Risk Based Integrity Management Program, identified the line segments that could impact high consequence areas and developed Baseline Assessment Plans. Management expects that it will complete the full assessment of the remaining segments by March 31, 2008, the timeframe prescribed by the regulations.
Management of the Partnership believes that its pipeline operations are in substantial compliance with applicable DOT regulations and comparable state requirements. However, an increase in expenditures may be needed in the future to comply with higher industry and regulatory safety standards. Such expenditures cannot be estimated accurately at this time, but management of the Partnership does not believe they would likely have a material adverse effect relative to its financial position.
Environmental Regulation
General
The Partnership’s operations are subject to complex federal, state, and local laws and regulations relating to the protection of health and the environment, including laws and regulations which govern the handling and release of crude oil and other liquid hydrocarbon materials, some of which are discussed below. Violations of environmental laws or regulations can result in the imposition of significant administrative, civil and criminal fines and penalties and, in some instances, injunctions banning or delaying certain activities. Management of the Partnership believes it is in substantial compliance with applicable environmental laws and regulations. However, these laws and regulations are subject to frequent change at the federal, state and local levels, and the clear trend is to place increasingly stringent limitations on activities that may affect the environment.
There are also risks of accidental releases into the environment associated with the Partnership’s operations, such as releases of crude oil or hazardous substances from its pipelines or storage facilities. To the extent not insured, such accidental releases could subject the Partnership to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for any related violations of environmental laws or regulations.
In connection with the February 2002 IPO, and the contribution of pipeline and terminalling assets to the Partnership by affiliates of Sunoco, Sunoco agreed to indemnify the Partnership for 100 percent of all losses from environmental liabilities related to the transferred assets arising prior to, and asserted within 21 years of, February 8, 2002. There is no monetary cap on this indemnification from Sunoco. Sunoco’s share of liability for claims asserted thereafter will decrease by 10 percent each year through the thirtieth year following the February 8, 2002 date. In addition, this indemnification applies to the interests in the Mesa Pipeline system and the Mid-Valley Pipeline purchased from Sunoco following the IPO. Any remediation liabilities not covered by this indemnity will be the Partnership’s responsibility. The Partnership has agreed to indemnify Sunoco and its affiliates for events and conditions associated with the operation of the transferred assets occurring after February 8, 2002, and for environmental and toxic tort liabilities related to these assets to the extent Sunoco is not required to indemnify the Partnership. Total future costs for environmental remediation activities will depend upon, among other things, the extent of impact at each site, the timing and nature of required remedial actions, the technology available, and the determination of the Partnership’s liability at multi-party sites. As of December 31, 2006, all material environmental liabilities incurred by, and known to, the Partnership are either covered by the environmental indemnification or reserved for by the Partnership within its financial statements.
Air Emissions
The Partnership’s operations are subject to the Clean Air Act, as amended, and comparable state and local statutes. The Partnership will be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing air emission related issues. Although no assurances can be given, management of the Partnership believes implementation of the 1990 Clean Air Act Amendments will not have a material adverse effect on its financial condition or results of operations.
The Partnership’s customers, including Sunoco, are also subject to, and affected by, environmental regulations. As a result of these regulations, Sunoco could be required to make significant capital expenditures, operate refineries at reduced levels, and pay significant penalties. It is uncertain what Sunoco’s responses to these emerging issues will be. Those responses could reduce Sunoco’s obligations under the pipelines and terminals storage and throughput agreement, thereby reducing the Partnership’s throughput in its pipelines and terminals, cash flow, and ability to make distributions or satisfy its debt obligations.
Hazardous Substances and Waste
In the course of ordinary operations, the Partnership may generate waste that falls within the Comprehensive Environmental Response, Compensation, and Liability Act’s, referred to as CERCLA and also known as Superfund, definition of a “hazardous substance” and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. Costs for any such remedial actions, as well as any related claims, could have a material adverse effect on the Partnership’s maintenance capital expenditures and operating expenses to the extent not all are covered by the indemnity from Sunoco or by insurance. For more information, please see “Environmental Remediation”.
The Partnership also generates solid wastes, including hazardous wastes that are subject to the requirements of the Federal Resource Conservation and Recovery Act, referred to as RCRA, and comparable state statutes. The Partnership is not currently required to comply with a substantial portion of the RCRA requirements because its operations generate minimal quantities of hazardous wastes. However, it is possible that additional wastes, which could include wastes currently generated during the Partnership’s operating activities, will in the future be designated as “hazardous wastes.” Hazardous wastes are subject to more rigorous and costly disposal requirements than are non-hazardous wastes. Any changes in the regulations could have a material adverse effect on the Partnership’s maintenance capital expenditures and operating expenses.
The Partnership currently owns or leases, and the Partnership’s predecessor has in the past owned or leased, properties where hydrocarbons are being or have been handled for many years. These properties and wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under these laws, the Partnership 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 contaminated groundwater), or to perform remedial operations to prevent future contamination.
The Partnership has not been identified by any state or federal agency as a potentially responsible party in connection with the transport and/or disposal of any waste products to third party disposal sites.
Water
The Partnership’s operations can result in the discharge of regulated substances, including crude oil. The Federal Water Pollution Control Act of 1972, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of regulated substances into state waters or waters of the United States.
The Oil Pollution Act subjects owners of covered facilities to strict, joint, and potentially unlimited liability for removal costs and other consequences of a release of oil, where the release is into navigable waters, along shorelines or in the exclusive economic zone of the United States. Spill prevention control and countermeasure requirements of the Clean Water Act and some state laws require diking and similar structures to help prevent the impact on navigable waters in the event of a release. The Office of Pipeline Safety of the DOT, the EPA, or various state regulatory agencies have approved the Partnership’s oil spill emergency response plans, and management of the Partnership believes it is in substantial compliance with these laws.
In addition, some states maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Management of the Partnership believes that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on its financial condition or results of operations.
Environmental Remediation
Contamination resulting from releases of refined products and crude oil is not unusual within the petroleum pipeline industry. Historic releases along the Partnership’s pipelines, gathering systems, and terminals as a result of past operations have resulted in impacts to the environment, including soils and groundwater. Site conditions, including soils and groundwater, are being evaluated at a number of properties where operations may have resulted in releases of hydrocarbons and other wastes. Sunoco has agreed to indemnify the Partnership from environmental and toxic tort liabilities related to the assets transferred to the extent such liabilities exist or arise from operation of these assets prior to the acquisition of the assets from Sunoco at the closing of the February 2002 IPO, or otherwise, and are asserted within 30 years after the closing of the IPO. This indemnity will cover the costs associated with performance of the assessment, monitoring, and remediation programs, as well as any related claims and penalties. See “Environmental Regulation-General.”
The Partnership has experienced several petroleum releases for which it is not covered by an indemnity from Sunoco, and for which it is responsible for necessary assessment, remediation, and/or monitoring activities. Management of the Partnership estimates that the total aggregate cost of performing the currently anticipated assessment, monitoring, and remediation activities at these sites is not material in relation to its financial position at December 31, 2006. The Partnership has implemented an extensive inspection program to prevent releases of refined products or crude oil into the environment from its pipelines, gathering systems, and terminals. Any damages and liabilities incurred due to future environmental releases from the Partnership’s assets have the potential to substantially affect its business.
Rate Regulation
General Interstate Regulation. Interstate common carrier pipeline operations are subject to rate regulation by the FERC under the Interstate Commerce Act, the Energy Policy Act of 1992, and rules and orders promulgated pursuant thereto. The Interstate Commerce Act requires that tariff rates for petroleum pipelines be “just and reasonable” and not unduly discriminatory. This statute also permits interested persons to challenge proposed new or changed rates and authorizes the FERC to suspend the effectiveness of such rates for up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund revenues in excess of the prior tariff during the term of the investigation. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.
The FERC generally has not investigated interstate rates on its own initiative when those rates, like the Partnership’s, have not been the subject of a protest or a complaint by a shipper. However, the FERC could investigate the Partnership’s rates at the urging of a third party if the third party is either a current shipper or has a substantial economic interest in the tariff rate level. Although no assurance can be given that the tariffs charged by the Partnership ultimately will be upheld if challenged, management believes that the tariffs now in effect for the Partnership’s pipelines are within the maximum rates allowed under current FERC guidelines.
Sunoco and its subsidiaries are the only current shippers on many of the pipelines. Sunoco has agreed not to challenge, cause others to challenge, or assist others in challenging, the tariff rates for the term of the pipelines and terminals storage and throughput agreement. It is possible that any new shippers, current shippers, or other interested parties, may decide to challenge the tariff rates. If any rate challenge or challenges were successful, revenues, cash flows, and the cash available for distribution could be materially reduced.
The Partnership has applied to FERC for permission to charge market-based rates in most of the refined products markets it serves. On January 19, 2006, the FERC ruled on the Partnership’s application for market-based rates on certain of its pipelines. Market-based rates were approved on the Detroit, MI, Pittsburgh, PA, Rochester, NY and Toledo, OH origin markets and the Detroit, MI, Philadelphia, PA and New York, NY destination markets. FERC ordered hearings on the application for the Philadelphia, PA origin market and the Cleveland, OH, Harrisburg, PA, Scranton, PA and Toledo, OH destination markets. In those markets where market-based rates were approved, the Partnership is able to establish rates without regard to the index or our cost-of-service. As to the markets where hearings have been ordered, there can be no assurances that market-based rates will be approved, in which case, our rates would continue to be subject to current rate structures.
Intrastate Regulation. Some of the Partnership’s pipeline operations are subject to regulation by the Texas Railroad Commission, the Pennsylvania Public Utility Commission, and the Oklahoma Corporation Commission. The operations of the Partnership’s joint venture interests are also subject to regulation in the states in which they operate. The applicable state statutes require that pipeline rates be nondiscriminatory and provide no more than a fair return on the aggregate value of the pipeline property used to render services. State commissions generally have not been aggressive in regulating common carrier pipelines or investigating rates or practices of petroleum pipelines in the absence of shipper complaints. Complaints to state agencies have been infrequent and are usually resolved informally. Although management cannot be certain that the Partnership’s intrastate rates ultimately would be upheld if challenged, it believes that, given this history, the tariffs now in effect are not likely to be challenged or, if challenged, are not likely to be ordered to be reduced.
Title to Properties
Substantially all of the Partnership’s pipelines were constructed on rights-of-way granted by the apparent record owners of the property and in some instances these rights-of-way are revocable at the election of the grantor. Several rights-of-way for the pipelines and other real property assets are shared with other pipelines and other assets owned by affiliates of Sunoco and by third parties. In many instances, lands over which rights-of-way have been obtained are subject to prior liens that have not been subordinated to the right-of-way grants. The Partnership has obtained permits from public authorities to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, and state highways and, in some instances, these permits are revocable at the election of the grantor. The Partnership has also obtained permits from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election. In some cases, property for pipeline purposes was purchased in fee. In some states and under some circumstances, the Partnership has the right of eminent domain to acquire rights-of-way and lands necessary for the common carrier pipelines. The previous owners of the applicable pipelines may not have commenced or concluded eminent domain proceedings for some rights-of-way.
Some of the leases, easements, rights-of-way, permits, and licenses acquired by the Partnership or transferred to it upon the closing of the February 2002 IPO require the consent of the grantor to transfer these rights, which in some instances is a governmental entity. The Partnership has obtained or is in the process of obtaining third-party consents, permits, and authorizations sufficient for the transfer of the assets necessary to operate the business in all material respects. In management’s opinion, with respect to any consents, permits, or authorizations that have not been obtained, the failure to obtain them will not have a material adverse effect on the operation of the business.
The Partnership has satisfactory title to all of the assets contributed to it in connection with the February 2002 IPO, or is entitled to indemnification from Sunoco under the Omnibus Agreement for title defects to these assets and for failures to obtain certain consents and permits necessary to conduct its business that arise within ten years after the closing of the February 2002 IPO. Record title to some of the assets may continue to be held by affiliates of Sunoco until the Partnership has made the appropriate filings in the jurisdictions in which such assets are located and obtained any consents and approvals that were not obtained prior to the closing of the February 2002 IPO. 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 for environmental contamination, taxes and other burdens, easements, or other restrictions, management believes that none of these burdens materially detract from the value of the properties or will materially interfere with their use in the operation of the Partnership’s business.
Employees
To carry out the Partnership’s operations, the general partner and its affiliates employed approximately 1,200 people at December 31, 2006 who provide direct support to the operations. Labor unions or associations represent approximately 620 of these employees at December 31, 2006. The general partner considers its employee relations to be good. The Partnership has no employees.
(d) Financial Information about Geographical Areas
The Partnership has no significant amount of revenue or segment profit or loss attributable to international activities.
(e) Available Information
The Partnership makes available, free of charge on its website, www.sunocologistics.com, all materials that it files electronically with the Securities Exchange Commission, including its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after such materials are electronically filed with, or furnished to, the SEC.
ITEM 1A.
ITEM 1A. RISK FACTORS
The risks below may not be the only risks we face. Additional risks that we do not yet know of or that we currently think are immaterial also may impair our business operations. If any of the following risks actually occur, our business, results of operations, cash flows and financial condition could be affected materially and adversely.
We may not be able to generate sufficient cash from operations to allow us to make the required payments to our debt holders or to pay quarterly distributions.
The amount of cash we can distribute on our common units principally depends upon the cash we generate from our operations. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. Because the cash we generate from operations will fluctuate from quarter to quarter, we may not be able to pay all the applicable interest and principal obligations on our debt, or to pay quarterly distributions.
In the future, we may not be able to generate sufficient cash flow from operations, realize currently anticipated operating improvements or borrow amounts under our revolving credit facility sufficient to fund our liquidity needs. We may need to refinance all or a portion of our indebtedness on or before maturity. We may not be able to refinance any of our indebtedness on or before maturity on commercially reasonable terms, or at all.
Our ability to pay quarterly distributions 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 pay cash distributions during periods when we record net losses and may be unable to pay cash distributions during periods when we record net income.
Our general partner’s discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to our unitholders.
Our partnership agreement provides that our general partner may reduce operating surplus by establishing cash reserves to provide funds for our future operating expenditures. In addition, the partnership agreement provides that our general partner may reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to our unitholders in any one or more of the next four quarters. These cash reserves will affect the amount of cash available for current distribution to our unitholders.
Cost reimbursements, which will be determined by our general partner in good faith, and fees due our general partner and its affiliates will be substantial and could materially and adversely affect our financial condition, results of operations, or cash flows.
We currently pay Sunoco an annual administrative fee for the provision by Sunoco or its affiliates of various general and administrative services for our benefit. This fee is subject to periodic re-negotiation, and there can be no assurance that future administrative fees charged by Sunoco will be at or below the current level. This fee may increase if an expansion of our operations requires an increased level of general and administrative services from Sunoco or its affiliates. If we are unable to obtain such services from Sunoco or third parties at or below the current cost, it could materially and adversely affect our financial condition, results of operations, or cash flows. In addition, our general partner is entitled to reimbursement for all other expenses it incurs on our behalf, including the salaries of, and the cost of employee benefits for, our general partner’s employees, including senior executives, who provide services to us. Our general partner will determine the amount of these expenses in good faith.
Even if unitholders are dissatisfied, they cannot remove our general partner without its consent, which could lower the trading price of the common units.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders did not elect our general partner or its board of directors and have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is chosen by the members of our general partner, all of which are subsidiaries of Sunoco. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a control premium in the trading price.
The partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
The control of our general partner may be transferred to a third party without unitholder consent.
The general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of the owner of the general partner from transferring its ownership interest in the general partner to a third party. The new owner of the general partner would then be in a position to replace the board of directors and officers of the general partner with its own choices.
Sunoco and its affiliates have conflicts of interest and limited fiduciary responsibilities, which may permit them to favor their own interests to the detriment of our unitholders.
Sunoco indirectly owns and controls our general partner, which holds the 2 percent general partner interest and holds a 42.3 percent limited partner interest in us. Conflicts of interest may arise between Sunoco and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, the general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:
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Sunoco, as a shipper on our pipelines, and a customer at our terminals, could seek lower tariff rates or terminalling fees, once the terms of Sunoco’s obligations under the pipelines and terminals storage and throughput agreements expire in 2007 through 2009.
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neither our partnership agreement nor any other agreement requires Sunoco to pursue a business strategy that favors us or utilizes our assets, including whether to increase or decrease refinery production, whether to shut down or reconfigure a refinery, or what markets to pursue or grow. Sunoco’s directors and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of Sunoco;
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our general partner is allowed to take into account the interests of parties other than us, such as Sunoco, in resolving conflicts of interest;
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under our partnership agreement, our general partner has limited liability and restricted fiduciary duties with respect to actions that, without these limitations and restrictions, might constitute breaches of fiduciary duty;
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under our partnership agreement, the remedies available to our unitholders with respect to conduct by our general partner that may constitute a breach of fiduciary duty have been limited;
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our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities, and reserves, each of which can affect the amount of cash that is distributed to our unitholders;
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our general partner determines which costs incurred by Sunoco and its affiliates are reimbursable by us;
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our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf;
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our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including the pipelines and terminals storage and throughput agreements with Sunoco; and
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our general partner decides whether to retain separate counsel, accountants, or others to perform services for us.
We are a holding company. We conduct our operations through our subsidiaries and depend on cash flow from our subsidiaries to service our debt obligations.
We are a holding company. We conduct our operations through our subsidiaries. As a result, our cash flow and ability to service our debt is dependent upon the earnings of our subsidiaries. In addition, we are dependent on the distribution of earnings, loans or other payments from our subsidiaries to us. Any payment of dividends, distributions, loans or other payments from our subsidiaries to us could be subject to statutory or contractual restrictions. Payments to us by our subsidiaries also will be contingent upon the profitability of our subsidiaries. If we are unable to obtain funds from our subsidiaries we may not be able to pay interest or principal on our debt securities when due or to obtain the necessary funds from other sources.
We depend upon Sunoco for a substantial portion of the crude oil and refined products transported on our pipelines and handled at our terminals, and our crude oil sales.
For the year ended December 31, 2006, Sunoco accounted for approximately 66 percent of our Eastern Pipeline System total revenues, 67 percent of our Terminal Facilities total revenues, and 30 percent of our Western Pipeline System total revenues. The balance of our revenues was received from third parties, and we will continue to remain dependent on third parties for these additional revenues. Our pipelines and terminals storage and throughput agreements with Sunoco provide for escalation of the fees charged to Sunoco, but the increased fees may be inadequate to cover increased costs in the future. We expect to continue to derive a substantial portion of our revenues from Sunoco for the foreseeable future. If for any reason, Sunoco were to decrease the throughput transported on our pipelines, the volumes of crude oil or refined products handled at our terminals or the amounts of crude oil purchased from us, it could materially and adversely affect our financial condition, results of operations, or cash flows.
Sunoco’s obligations to us under the pipelines and terminals storage and throughput agreements and other arrangements may be reduced or suspended in some circumstances.
Sunoco’s obligations to us under the pipelines and terminals storage and throughput agreements may be permanently reduced in some circumstances. These events, some of which are within the exclusive control of Sunoco, include:
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The inability of Sunoco and us to agree on the amount of any surcharge required to be paid by Sunoco to cover substantial and unanticipated costs that may be incurred in complying with new laws or governmental regulations applicable to our Terminal Facilities;
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A decision by Sunoco to shut down or reconfigure one or more of its refineries if Sunoco reasonably believes in good faith that such event will jeopardize its ability to satisfy its minimum revenue or throughput obligations; and
Depending on the ultimate cost of complying with existing and future environmental regulations or proceedings, Sunoco may determine that it is more economical to reduce production at a refinery or shut down all or a portion of a refinery rather than make these capital expenditures. Sunoco’s obligations to us under the pipelines and terminals storage and throughput agreements would be reduced in this event.
Furthermore, Sunoco’s obligations to us would be temporarily suspended during the occurrence of an event that is outside the control of the parties, which renders performance impossible with respect to an asset for at least 30 days. The occurrence of any of these events could materially and adversely affect our financial condition, results of operations, or cash flows.
Sunoco actively manages its assets and operations, and therefore, changes of some nature, possibly material to our business relationship, may occur at some point in the future.
If Sunoco satisfies only its minimum obligations to us under, or if we are unable to renew or extend the pipelines and terminals storage and throughput agreements, it could materially and adversely affect our financial condition, results of operations, or cash flows.
Sunoco may reduce the volume it transports on our pipelines or delivers at our terminals to the minimum amounts it is obligated to transport or deliver under the pipelines and terminals storage and throughput agreements. In addition, the terms of Sunoco’s obligations to us under the pipelines and terminals storage and throughput agreements entered into at the time of our initial public offering are of relatively brief duration, generally expiring in 2007 through 2009. If Sunoco reduces its use of our facilities after expiration of this agreement or any other storage and throughput agreements between us and Sunoco, or if the terms under a new agreement are materially changed in a way that reduces revenues, and we are unable to generate additional revenues from third parties, it could materially and adversely affect our financial condition, results of operations, or cash flows.
A sustained decrease in demand for refined products in the markets served by our pipelines and terminals could materially and adversely affect our financial condition, results of operations, or cash flows.
Factors that could lead to a sustained decrease in market demand for refined products include:
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a recession or other adverse economic condition that results in lower purchases of refined petroleum products;
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higher refined product prices due to an increase in the market price of crude oil, changes in economic conditions, or other factors;
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higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline or other refined products;
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a shift by consumers to more fuel-efficient or alternative fuel vehicles or an increase in fuel economy, whether as a result of technological advances by manufacturers, pending legislation proposing to mandate higher fuel economy, or otherwise; and
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a temporary or permanent material increase in the price of refined products as compared to alternative sources of refined products available to our customers.
A material decrease in crude oil available for transport through our Western Pipeline System could materially and adversely affect our financial position, results of operations, or cash flows.
The volume of crude oil transported in our crude oil pipelines depends on the availability of attractively priced crude oil produced in the areas accessible to our crude oil pipelines and received from other common carrier pipelines. If we do not replace volume lost due to a material temporary or permanent decrease in supply, the volume of crude oil transported through our pipelines would decline. In addition, sustained low crude oil prices could lead to a decline in drilling activity and production levels or the shutting-in or abandonment of marginal wells. Similarly, a temporary or permanent material increase in the price of crude oil supplied from any of these sources, as compared to alternative sources of crude oil available to our customers, could cause the volume of crude oil transported in our pipelines to decline.
Any reduction in the capability of, or the allocations to, our shippers in interconnecting, third-party pipelines would cause a reduction of volumes transported in our pipelines and through our terminals.
Sunoco and the other users of our pipelines and terminals are dependent upon connections to third-party pipelines to receive and deliver crude oil and refined products. Any reduction of capabilities of these interconnecting pipelines due to testing, line repair, reduced operating pressures, or other causes would result in reduced volumes transported in our pipelines or through our terminals. Similarly, if additional shippers begin transporting volume over interconnecting pipelines, the allocations to our existing shippers could be reduced, which also would reduce volumes transported in our pipelines or through our terminals.
If we are unable to complete capital projects at their expected costs and/or in a timely manner, or if the market conditions assumed in our project economics deteriorate, our financial condition, results of operations, or cash flows could be affected materially and adversely.
Delays or cost increases related to capital spending programs involving construction of new facilities (or improvements and repairs to our existing facilities) could adversely affect our ability to achieve forecasted internal rates of return and operating results. Delays in making required changes or upgrades to our facilities could subject us to fines or penalties as well as affect our ability to supply certain products we make. Such delays or cost increases may arise as a result of unpredictable factors in the marketplace, many of which are beyond our control, including:
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denial or delay in issuing requisite regulatory approvals and/or permits;
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unplanned increases in the cost of construction materials or labor;
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disruptions in transportation of modular components and/or construction materials;
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severe adverse weather conditions, natural disasters, or other events (such as equipment malfunctions explosions, fires, spills) affecting our facilities, or those of vendors and suppliers;
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shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
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market-related increases in a project’s debt or equity financing costs; and/or
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nonperformance by, or disputes with, vendors, suppliers, contractors, or sub-contractors involved with a project.
Our forecasted internal rates of return also are based upon our projections of future market fundamentals which are not within our control, including changes in general economic conditions, available alternative supply and customer demand.
Potential future acquisitions and expansions, if any, may increase substantially the level of our indebtedness and contingent liabilities, and we may be unable to integrate them effectively into our existing operations.
From time to time, we evaluate and acquire assets and businesses that we believe complement or diversify 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.
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. 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. In some cases, we have indemnified the previous owners and operators of acquired assets. Following an acquisition, we may discover previously unknown liabilities associated with the acquired business for which we have no recourse under applicable indemnification provisions. An acquisition may require us to assume certain prior known or unknown liabilities.
Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.
Our operations and those of our customers and suppliers may be subject to operational hazards and unforeseen interruptions such as natural disasters (including hurricanes), adverse weather, accidents, fires, explosions, hazardous materials releases, and other events beyond our control. These events might result in a loss of equipment or life, injury, or extensive property damage, as well as an interruption in our operations. We may not be able to maintain or obtain insurance of the type and amount desired at reasonable rates. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. If we were to incur a significant liability for which we were not fully insured, it could materially and adversely affect our financial condition, results of operations, or cash flows.
We are exposed to the credit and other counterparty risk of our customers in the ordinary course of our business.
There can be no assurance that we have adequately assessed the credit worthiness of our existing or future counterparties or that there will not be an unanticipated deterioration in their credit worthiness, which could have an adverse impact on us. In those cases in which we provide division order services for crude oil purchased at the wellhead, we may be responsible for distribution of proceeds to all parties. In other cases, we pay all of or a portion of the production proceeds to an operator who distributes these proceeds to the various interest owners. There can be no assurance that we will not experience material losses in dealings with other parties.
Competition with respect to our operating segments could ultimately lead to lower levels of profits and could materially and adversely affect our financial condition, results of operations, or cash flows.
We face competition from other pipelines, terminals and crude oil marketers, as well as from other means of transporting, storing and distributing petroleum products. 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 utilize the services of our competitors. If a competing crude oil or refined product pipeline or other crude oil marketer charged lower rates than we do, we could be forced to reduce our rates to remain competitive.
Mergers among our customers and competitors could result in lower volumes being shipped on our pipelines or products stored in or distributed through our terminals, or reduced crude oil marketing margins or volumes.
Mergers between existing customers could provide strong economic incentives for the combined entities to utilize their existing systems instead of ours in those markets where the systems compete. As a result, we could lose some or all of the volumes and associated revenues from these customers and we could experience difficulty in replacing those lost volumes and revenues, which could materially and adversely affect our financial condition, results of operations, or cash flows.
Rate regulation may not allow us to recover the full amount of increases in our costs. A successful challenge to our rates could materially and adversely affect our financial condition, results of operations, or cash flows.
The primary rate-making methodology of the Federal Energy Regulatory Commission, or FERC, is price indexing. We use this methodology in all of our interstate markets. In an order issued February 24, 2003, the FERC announced that, effective July 1, 2003, the index would equal the change in the producer price index for finished goods (previously, the index was equal to the change in the producer price index for finished goods minus 1%). If the index falls, we would be required to reduce rates that are based on the FERC’s price indexing methodology if they exceed the new maximum allowable rate. In addition, changes in the index might not be large enough to fully reflect actual increases in our costs. The FERC’s rate-making methodologies may limit our ability to set rates based on our true costs or may delay the use of rates that reflect increased costs.
Under the Energy Policy Act adopted in 1992, certain interstate pipeline rates were deemed just and reasonable or “grandfathered.” Most of our revenues are derived from grandfathered rates on our FERC-regulated refined products pipelines. A person challenging a grandfathered rate must, as a threshold matter, establish a substantial change since the date of enactment of the Act, in either the economic circumstances or the nature of the service that formed the basis for the rate. A complainant might assert that the creation of the partnership itself constitutes such a change, an argument that has not previously been specifically addressed by the FERC. If the FERC were to find a substantial change in circumstances, then the existing rates could be subject to detailed review. There is a risk that some rates could be found to be in excess of levels justified by our cost of service. In such event, the FERC would order us to reduce rates prospectively and could order us to pay reparations to complaining shippers. Reparations could be required for a period of up two years prior to the date of filing the complaint in the case of rates that are not grandfathered and for the period starting with the filing of the complaint in the case of grandfathered rates.
On July 20, 2004, the United States Court of Appeals for the District of Columbia Circuit, or the D.C. Circuit, issued its opinion in BP West Coast Products, LLC v. FERC, which upheld FERC’s determination that the rates of an interstate petroleum products pipeline, SFPP, L.P., or SFPP, were grandfathered rates under the Energy Policy Act of 1992 and that SFPP’s shippers had not demonstrated substantially changed circumstances that would justify modification of those rates. The court also vacated the portion of the FERC’s decision applying the Lakehead policy. In the Lakehead decision, the FERC allowed an oil pipeline master limited partnership to include in its cost-of-service an income tax allowance to the extent that its unitholders were corporations subject to income tax. In May and June 2005, the FERC issued a statement of general policy, as well as an order on remand of BP West Coast, respectively, in which the FERC has stated it will permit pipelines to include in cost-of-service a tax allowance to reflect actual or potential tax liability on their public utility income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. Although the new policy is generally favorable for pipelines that are organized as pass-through entities, it still entails rate risk due to the case-by-case review requirement. However, on December 16, 2005, the FERC issued its first case-specific review of the income tax allowance issue in the SFPP, L.P. proceeding. The FERC ruled favorably to SFPP L.P. on all income tax issues and set forth guidelines regarding the evidence necessary for the pipeline to determine its income tax allowance. Shippers in the SFPP, L.P. proceeding have challenged the application of the new income tax allowance policy to the SFPP rates in the U.S. Court of Appeals. In addition, a Canadian producers association has challenged the new income tax allowance policy in a separate proceeding before the U.S. Court of Appeals. Both cases were argued before the Court on December 12, 2006. The ultimate outcome of these proceedings and the applicability of the new tax allowance policy is uncertain, and could result in changes to the FERC’s treatment of income tax allowance in cost of service rates.
In addition, a state commission could also investigate our intrastate rates or terms and conditions of service on its own initiative or at the urging of a shipper or other interested party. If a state commission found that our rates exceeded levels justified by our cost of service, the state commission could order us to reduce our rates.
Sunoco has agreed not to challenge, or to cause others to challenge or assist others in challenging, our tariff rates in effect during the term of the pipelines and terminals storage and throughput agreement. This agreement does not prevent other current or future shippers from challenging our tariff rates. At the end of the term of the agreement, Sunoco will be free to challenge, or to cause other parties to challenge or assist others in challenging, our tariff rates in effect at that time.
Potential changes to current rate-making methods and procedures may impact the federal and state regulations under which we will operate in the future. In addition, if the FERC’s petroleum pipeline ratemaking methodology changes, the new methodology could materially and adversely affect our financial condition, results of operations, or cash flows.
Our operations are subject to federal, state, and local laws and regulations relating to environmental protection and operational safety that could require substantial expenditures.
Our pipelines, gathering systems, and terminal operations are subject to increasingly strict environmental and safety laws and regulations. The transportation and storage of refined products and crude oil result in a risk that refined products, crude oil, and other hydrocarbons may be suddenly or gradually released into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies for natural resources damages, personal injury, or property damages to private parties and significant business interruption. We own or lease a number of properties that have been used to store or distribute refined products and crude oil for many years. Many of these properties also have been previously owned or operated by third parties whose handling, disposal, or release of hydrocarbons and other wastes were not under our control, and for which, in some cases, we have indemnified the previous owners and operators.
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. We may be unable to recover these costs through increased revenues.
Our business is subject to federal, state and local laws and regulations that govern the product quality specifications of the petroleum products that we store and transport.
Petroleum products that we store and transport are sold by our customers for consumption into the public market. Various federal, state and local agencies have the authority to prescribe specific product quality specifications to commodities sold into the public market. Changes in product quality specifications could reduce our throughput volume, require us to incur additional handling costs or require the expenditure of capital. In addition, different product specifications for different markets impact the fungibility of the system and could require the construction of additional storage. We may be unable to recover these costs through increased revenues.
Restrictions in our debt agreements and in Sunoco’s debt agreements may prevent us from engaging in some beneficial transactions or paying distributions to unitholders.
As of December 31, 2006, our total outstanding long-term indebtedness was approximately $491.9 million, consisting of $423.9 million of senior notes, net of unamortized discount of $1.1 million and $68.0 million of borrowings under our credit facility. Our payment of principal and interest on the debt will reduce the cash available for distribution on our units, as will our obligation to repurchase the senior notes upon the occurrence of specified events involving a change in control of our general partner. In addition, we are prohibited by our credit facility and the senior notes from making cash distributions during an event of default, or if the payment of a distribution would cause an event of default, under any of our debt agreements. The termination of our pipelines and terminals storage and throughput agreements with Sunoco would constitute an event of default under our credit facility. Our leverage and various limitations in our credit facility and our senior notes may reduce our ability to incur additional debt, engage in some transactions, and capitalize on acquisition or other business opportunities. Since Sunoco owns and controls our general partner, we are not permitted to incur additional debt if the effect would be to cause an event of default under Sunoco’s revolving credit agreements. Any subsequent refinancing of Sunoco’s or our current debt or any new debt could have similar or greater restrictions.
We could incur a substantial amount of debt in the future, which could prevent us from fulfilling our debt obligations.
We are permitted to incur additional debt, subject to certain limitations under our revolving credit facility and, in the case of secured debt, under the indenture governing the notes. If we incur additional debt in the future, our increased leverage could, for example:
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make it more difficult for us to satisfy our obligations under our debt securities or other indebtedness and, if we fail to comply with the requirements of the other indebtedness, could result in an event of default under our debt securities or such other indebtedness;
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require us to dedicate a substantial portion of our cash flow from operations to required payments on indebtedness, thereby reducing the availability of cash flow from working capital, capital expenditures and other general corporate activities;
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limit our ability to obtain additional financing in the future for working capital, capital expenditures and other general corporate activities;
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limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
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detract from our ability to successfully withstand a downturn in our business or the economy generally; and
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place us at a competitive disadvantage against less leveraged competitors.
Our general partner may cause us to borrow funds in order to make cash distributions, even where the purpose or effect of the borrowing benefits the general partner or its affiliates.
In some instances, our general partner may cause us to borrow funds from affiliates of Sunoco or from third parties in order to permit the payment of cash distributions.
Our general partner has a limited call right that may require our unitholders to sell their common units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their common units at an undesirable time or price, may not receive a return on the investment, and may incur a tax liability upon the sale.
Rising short-term interest rates could increase our financing costs and reduce the amount of cash we generate.
As of December 31, 2006, we had $68.0 million of floating-rate debt. As a result, we have exposure to changes in short-term interest rates. Rising short-term rates could materially and adversely affect our financial condition, results of operations, or cash flows.
A down-grading in Sunoco’s credit rating could result in a down-grading in our credit rating, which could adversely affect our ability to obtain financing.
Due to our relationship with Sunoco, our credit rating is partly dependent on Sunoco’s credit rating. Any down-grading in Sunoco’s credit rating could result in a down-grading in our credit rating, which could, among other things, limit our ability to obtain financing on the terms currently available to us, if at all.
Terrorist attacks aimed at our facilities could adversely affect our business.
Since the September 11, 2001 terrorist attacks, the U.S. government has issued warnings that energy assets, specifically the nation’s pipeline and terminal infrastructure, may be the future targets of terrorist organizations. Any future terrorist attack at our facilities, those of our customers and, in some cases, those of other pipelines, refineries, or terminals could materially and adversely affect our financial condition, results of operations, or cash flows.
Due to our lack of asset diversification, adverse developments in our businesses could materially and adversely affect our financial condition, results of operations, or cash flows.
We rely exclusively on the revenues generated from our businesses, and dividends from our equity investments. Due to our lack of asset diversification, an adverse development in one of these businesses could have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets.
We may issue additional common units without unitholder approval, which would dilute our unitholders’ ownership interests.
The Partnership may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Our partnership agreement does not give our unitholders the right to approve our issuance of equity securities ranking junior to the common units at any time. The issuance of additional common units, or other equity securities of equal or senior rank, will decrease the proportionate ownership interest of existing unitholders and may reduce the amount of cash available for distribution and/or the market price of our common units.
Sunoco and its affiliates may engage in limited competition with us.
Sunoco and its affiliates may engage in limited competition with us. Pursuant to the omnibus agreement, Sunoco and its affiliates have agreed not to engage in the business of purchasing crude oil at the wellhead or operating refined product or crude oil pipelines or terminals or LPG terminals in the continental United States. The Omnibus Agreement, however, does not apply to:
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any business operated by Sunoco or any of its subsidiaries at the closing of our initial public offering;
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any logistics asset constructed by Sunoco or any of its subsidiaries within a manufacturing or refining facility in connection with the operation of that facility;
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any business that Sunoco or any of its subsidiaries acquires or constructs that has a fair market value of less than $5.0 million; and
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any business that Sunoco or any of its subsidiaries acquires or constructs that has a fair market value of $5.0 million or more if we have been offered the opportunity to purchase the business for fair market value, and we decline to do so with the concurrence of our conflicts committee.
Upon a change of control of Sunoco or a sale of the general partner by Sunoco, the non-competition provisions of the omnibus agreement may terminate.
A unitholder may not have limited liability if a state or federal court finds that we are not in compliance with the applicable statutes or that unitholder action constitutes control of our business.
The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some states. A unitholder could be held liable in some circumstances for our obligations to the same extent as a general partner if a state or federal court determined that:
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we had been conducting business in any state without complying with the applicable limited partnership statute; or
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the right or the exercise of the right by the unitholders as a group to remove or replace our general partner, to approve some amendments to the partnership agreement, or to take other action under the partnership agreement constituted participation in the “control” of our business.
Under applicable state law, our general partner has unlimited liability for our obligations, including our debts and environmental liabilities, if any, except for our contractual obligations that are expressly made without recourse to the general partner.
In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that under some circumstances a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity level taxation by individual states. If the Internal Revenue Service, or IRS, treats us as a corporation or we become subject to entity level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to unitholders.
The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this matter. The IRS may adopt positions that differ from the ones we take. A successful IRS contest of the federal income tax positions we take may impact adversely the market for our common units, and the costs of any IRS contest will reduce our cash available for distribution to unitholders.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax at the corporate tax rate, and likely would pay state income tax at varying rates. Distributions to unitholders generally would be taxed again as corporate distributions. Treatment of us as a corporation would result in a material reduction in anticipated cash flow and after-tax return to unitholders. Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or to otherwise subject us to entity-level taxation. States are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise and other forms of taxation. If any of these states were to impose a tax on us, the cash available for distribution to unitholders would be reduced. The partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state, or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
See Item 1.(c) for a description of the locations and general character of the Partnership’s material properties.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
There are certain legal and administrative proceedings arising prior to the February 2002 IPO pending against the Partnership’s Sunoco-affiliated predecessors and the Partnership (as successor to certain liabilities of those predecessors). Although the ultimate outcome of these proceedings cannot be ascertained at this time, it is reasonably possible that some of them may be resolved unfavorably. Sunoco has agreed to indemnify the Partnership for 100 percent of all losses from environmental liabilities related to the transferred assets arising prior to, and asserted within 21 years of February 8, 2002. Sunoco’s share of liability for claims asserted thereafter will decrease by 10 percent each year through the thirtieth year following the February 8, 2002 date. There is no monetary cap on this indemnification from Sunoco. Any remediation liabilities not covered by this indemnity will be the Partnership’s responsibility.
There are certain other pending legal proceedings related to matters arising after the February 2002 IPO that are not indemnified by Sunoco. Management believes that any liabilities that may arise from these legal proceedings will not be material to the Partnership’s financial position at December 31, 2006.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS
No matters were submitted to a vote of the security holders during fiscal 2006.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SECURITYHOLDER MATTERS AND PURCHASES OF EQUITY SECURITIES
The Partnership’s common units were listed on the New York Stock Exchange under the symbol “SXL” beginning on February 5, 2002. Prior to February 5, 2002, the Partnership’s equity securities were not traded on any public trading market. At the close of business on February 22, 2007, there were 85 holders of record of the Partnership’s common units. These holders of record included the general partner with 12,063,734 common units registered in its name, and Cede & Co. with 16,436,510 common units registered to it.
The high and low closing sales price ranges (composite transactions) and distributions declared by quarter for 2005 and 2006 were as follows:
(1)
Distributions were declared and paid within 45 days following the close of each quarter.
Within 45 days after the end of each quarter, the Partnership distributes all cash on hand at the end of the quarter less reserves established by the general partner in its discretion. This is defined as “available cash” in the partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct the Partnership’s business. The Partnership will make minimum quarterly distributions of $0.45 per common unit, to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner.
The Partnership issued 11,383,639 subordinated units to its general partner in connection with the 2002 IPO. The Partnership had 5,691,819 subordinated units outstanding as of December 31, 2006, all of which were held by the general partner, and for which there is no established public trading market. Any subordinated units that remain outstanding at the end of the subordination period convert to common units on a one-for-one basis if the Partnership meets certain required financial tests set forth in the Partnership Agreement. Upon conversion to common units, the subordinated units will no longer be subordinated to the rights of the holders of common units.
The Partnership has met the minimum quarterly distribution requirements on all outstanding units for each of the four-quarter periods ended December 31, 2004, 2005 and 2006. As a result, the total of 11,383,639 subordinated units have been converted into common units on a one-for-one basis, 2,845,910 each on February 15, 2005 and February 15, 2006 and 5,691,819 on February 15, 2007.
The Partnership will, in general, pay cash distributions each quarter in the following manner:
If cash distributions exceed $0.50 per unit in a quarter, the general partner will receive increasing percentages, up to 50 percent, of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions”. The amounts shown in the table under “Percentage of Distributions” are the percentage interests of the general partner and the unitholders in any available cash from operating surplus that is distributed up to and including the corresponding amount in the column “Quarterly Cash Distribution Amount per Unit,” until the available cash that is distributed reaches the next target distribution level, if any. The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.
There is no guarantee that the Partnership will pay the minimum quarterly distribution on the common units in any quarter, and the Partnership is prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default is existing, under the credit facility or the senior notes (Please see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources”).
For equity compensation plan information, see Item 2. “Security Ownership of Certain Beneficial Owners and Management and Related Securityholder Information”.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
On February 8, 2002, the Partnership completed an IPO and related transactions whereby it became the successor to Sunoco Logistics (“Predecessor”), which consisted of a substantial portion of the wholly-owned logistics operations of Sunoco and its subsidiaries. The selected financial and operating data presented is derived from the audited financial statements of Sunoco Logistics Partners L.P., which reflect the Partnership and Predecessor for 2002, and the Partnership for 2003, 2004, 2005 and 2006.
For the periods presented, Sunoco was the primary or exclusive user of the refined product terminals, the Fort Mifflin Terminal Complex, and the Marcus Hook Tank Farm. Prior to January 1, 2002, most of the terminalling and throughput services provided by the Predecessor for Sunoco’s refining and marketing operations were at fees that enabled the recovery of costs, but not to generate any operating income. Accordingly, historical earnings before interest expense, income tax expense, and depreciation and amortization expense (“EBITDA”) for those assets was equal to their depreciation and amortization expense. Sunoco Logistics Partners L.P. began charging Sunoco fees for these services that are comparable to those charged in arm’s length, third-party transactions, generally effective January 1, 2002, using the terms included in a pipelines and terminals storage and throughput agreement entered into at the closing of the IPO.
Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of the assets and to extend their useful lives. Expansion capital expenditures are capital expenditures made to expand the existing operating capacity of the assets, whether through construction or acquisition. The Partnership treats repair and maintenance expenditures that do not extend the useful life of existing assets as operating expenses as incurred.
Throughput is the total number of barrels per day (“bpd”) transported on a pipeline system or through a terminal. Total shipments represent the total average daily pipeline throughput multiplied by the number of miles of pipeline through which each barrel has been shipped. Management of the Partnership believes that total shipments is a better performance indicator for the Eastern Pipeline System than throughput as certain refined product pipelines such as transfer pipelines, transport large volumes over short distances and generate minimal revenues.
The following table should be read together with, and is qualified in its entirety by reference to, the financial statements and the accompanying notes of Sunoco Logistics Partners L.P. included in Item 8. “Financial Statements and Supplementary Data”. The table also should be read together with Item 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion should be read in conjunction with the financial statements of Sunoco Logistics Partners L.P. Among other things, those financial statements include more detailed information regarding the basis of presentation for the following information.
Overview
The Partnership is a Delaware limited partnership formed on October 15, 2001 to acquire, own, and operate, a geographically diverse portfolio of complementary pipeline, terminalling, and crude oil acquisition and marketing assets.
The Partnership is engaged in the transport, terminalling, and storage of refined products and crude oil and in the purchase and sale of crude oil in 12 states located in the Northeast, Midwest and Southwest United States. Revenues are generated by charging tariffs for transporting refined products, crude oil and other hydrocarbons through the Partnership’s pipelines as well as by charging fees for storing refined products, crude oil and other hydrocarbons in, and for providing other services at, its terminals. Revenues are also generated by purchasing domestic crude oil and selling it to Sunoco and other customers. Generally, as the Partnership purchases crude oil it simultaneously enters into corresponding sale transactions involving physical deliveries of crude oil, which enables it to secure a profit on the transaction at the time of purchase.
Strategic Actions
The Partnership’s primary business strategies are to generate stable cash flows, increase pipeline and terminal throughput, pursue strategic and accretive acquisitions that complement the Partnership’s existing asset base, improve operating efficiencies, and increase its cash distributions to unitholders. As part of its strategy, the Partnership has undertaken several strategic initiatives, including:
2006 Acquisitions
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Mid-Valley Pipeline Acquisition. On August 18, 2006, the Partnership purchased from Sunoco a 100 percent interest in Sun Pipe Line Company of Delaware LLC, the owner of a 55.3 percent equity interest (50 percent voting interest) in Mid-Valley Pipeline Company (“Mid-Valley”) for $65 million, subject to certain adjustments five years following the date of closing, based on throughput of Sunoco. Mid-Valley owns a 994-mile pipeline, which originates in Longview, Texas and terminates in Samaria, Michigan, and has operating capacity of approximately 238,000 bpd and 4.2 million barrels of shell storage capacity. Mid-Valley provides crude oil to a number of refineries, primarily in the Midwest United States. The Partnership will continue to be the operator of the Mid-Valley pipeline.
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Millenium and Kilgore Pipeline Acquisition. On March 1, 2006, the Partnership purchased a Texas crude oil pipeline system from affiliates of Black Hills Energy, Inc. for approximately $40.9 million. The system consists of (a) the Millennium Pipeline, a 200-mile, 12-inch crude oil pipeline with approximately 65,000 bpd operating capacity, originating near the Partnership’s Nederland Terminal, and terminating at Longview Texas; (b) the Kilgore Pipeline, a 190-mile, 10-inch crude oil pipeline with approximately 35,000 barrel per day capacity originating in Kilgore, Texas and terminating at refineries in the Houston, Texas region; (c) approximately 900,000 shell barrels of active storage capacity at Kilgore, and Longview, Texas, approximately 550,000 of which are inactive; (d) a crude oil sales and marketing business; and (e) crude oil line fill and working inventory.
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Amdel and White Oil Pipeline Acquisition. On March 1, 2006, the Partnership acquired a Texas crude oil pipeline system from Alon USA Energy, Inc. for approximately $68.0 million. The system consists of (a) the Amdel Pipeline, a 503-mile, 10-inch common carrier crude oil pipeline with approximately 27,000 bpd operating capacity, originating at the Nederland Terminal, and terminating at Midland, Texas, and (b) the White Oil Pipeline, a 25-mile, 10-inch crude oil pipeline with approximately 40,000 bpd operating capacity, originating at the Amdel Pipeline and terminating at Alon’s Big Spring, Texas refinery. Alon has also agreed to ship a minimum of 15,000 bpd on the pipelines under a 10-year, throughput and deficiency agreement. The pipelines were idle at the time of purchase, were re-commissioned by the Partnership during the second quarter 2006 and began making deliveries during the fourth quarter 2006. The Partnership also began construction to expand capacity on the Amdel Pipeline from approximately 27,000 to 40,000 bpd and to construct new tankage at the Nederland Terminal to service these new volumes more efficiently. Construction to expand the Amdel pipeline is expected to be completed during the first quarter of 2007.
2005 Acquisitions
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Mesa Pipe Line System Interest Acquisition. On December 5, 2005, the Partnership purchased a subsidiary of Sunoco which owned a 7.2 percent undivided interest in the Mesa Pipe Line system for approximately $1.3 million. The Mesa Pipe Line system consists of an 80-mile, 24-inch crude oil pipeline from Midland, Texas to Colorado City, Texas, with an operating capacity of 316,000 bpd, and approximately 800,000 shell barrels of tankage at Midland. The Mesa pipeline connects to the West Texas Gulf pipeline, which supplies crude oil to the Mid-Valley pipeline. On December 29, 2005, the Partnership purchased an additional 29.8 percent interest in Mesa from Chevron for approximately $5.3 million, increasing its combined interest to 37.0 percent.
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Corsicana to Wichita Falls Pipeline Acquisition. On August 1, 2005, the Partnership purchased, from an affiliate of Exxon Mobil Corporation, a crude oil pipeline system and storage facilities located in Texas for approximately $100.0 million. The pipeline system consists primarily of a 187-mile, 16-inch pipeline with an operating capacity of 125,000 bpd. It originates at a crude oil terminal in Corsicana, Texas and terminates at Wichita Falls, Texas. The storage facilities include the Corsicana terminal, which has 2.9 million shell barrels of capacity for crude oil, and the Ringgold, Texas terminal, which consists of 0.5 million barrels of shell capacity for crude oil. In addition, the Partnership invested approximately $16.0 million to construct a new 20-mile pipeline to connect the Corsicana to Wichita Falls pipeline to the West Texas Gulf pipeline, in which the Partnership has a 43.8% ownership interest.
2004 Acquisitions
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Columbus Terminal Acquisition. On November 30, 2004, the Partnership acquired a refined products terminal located in Columbus, Ohio for approximately $8.0 million. The terminal is connected to a third-party, refined product, common carrier pipeline and includes 6 refined product tanks with approximately 160,000 barrels of working storage capacity, located on 13 acres; two truck racks for shipping gasoline, distillate fuels, and ethanol via tanker truck; and rail siding access for 4 rail cars for ethanol handling.
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Harbor Pipeline Interest Acquisition. On June 28, 2004, the Partnership purchased an additional 33.3 percent undivided interest in the Harbor pipeline for approximately $7.3 million. The Harbor pipeline is an 80-mile, 180,000 bpd refined product, common carrier pipeline originating near Woodbury, New Jersey and terminating in Linden, New Jersey. As a result of this transaction, the Partnership increased its undivided ownership interest to 66.7 percent and continues to operate the pipeline.
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Baltimore and Manassas Terminals Acquisition. On April 28, 2004, the Partnership purchased two refined product terminals located in Baltimore, Maryland and Manassas, Virginia for approximately $12.0 million. The Baltimore terminal is connected to a third-party, refined product, common carrier pipeline and includes 13 refined product tanks with approximately 646,000 barrels of working storage capacity, located on 35 acres; one truck rack for shipping gasoline and distillate fuels via tanker truck; and one marine dock with two berths for receiving refined products. The Manassas terminal is connected to a third-party, refined product, common carrier pipeline and includes 7 refined product tanks with approximately 277,000 barrels of working storage capacity, located on 11 acres, and one truck rack for shipping gasoline and distillate fuels via tanker truck.
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Eagle Point Logistics Assets Acquisition. On March 30, 2004, the Partnership acquired the Eagle Point refinery logistics assets from Sunoco for approximately $20 million. The Eagle Point logistics assets consist of a crude oil and refined product ship and barge dock, a refined product truck rack, and a 4.5 mile, refined product pipeline from the Eagle Point refinery to the origin of the Harbor pipeline. In connection with the acquisition, the Partnership entered into a throughput agreement with Sunoco whereby they have agreed to minimum volumes on the truck rack upon completion of certain capital improvements, which were completed during the fourth quarter of 2004.
Growth Capital Program
In December 2006, the Partnership announced that it had executed an agreement with Motiva Enterprices LLC to construct three additional crude oil storage tanks, with a combined capacity of 2.0 millions shell barrels of capacity, and a 12-mile 30” crude oil pipeline from the Nederland Terminal to Motiva’s Port Arthur, Texas refinery. Construction of these assets is expected to be completed on or before January 2010 and cost in excess of $70 million. During 2007, the Partnership expects to spend approximately $35 million related to the Motiva project, along with approximately $63 million for organic growth projects consisting primarily of the continued construction of new tankage at the Nederland Terminal, pipeline connections in the Western Pipeline system and new pipeline tankage in both the Eastern and Western Pipeline systems.
Conservative Capital Structure
The Partnership’s goal is to maintain a conservative capital structure and substantial liquidity. In December 2005, the Partnership amended its Credit Facility, which expanded its size to $300 million and extended the maturity to 2010. (See “Liquidity and Capital Resources” for further information.). The Partnership also completed a series of equity issuances during 2004, 2005 and 2006, through which it issued an aggregate of 10.5 million limited partner units, generating $398.6 million of net proceeds. Proceeds from these equity issues were used to redeem 5.0 million limited partner units owned by Sunoco, repay a portion of the debt incurred to fund its acquisitions and fund the Partnership’s organic growth program.
Cash Distribution Increases
As a result of the above initiatives, the general partner was able to increase the cash distributions to limited partners in all but one quarter during each of the three years ended December 31, 2006. During the three year period ended December 31, 2006, the distribution increased to $0.8125 per common and subordinated partnership unit, ($3.25 annualized), which will be paid in February 2007. This increase represents a 30% increase over the fourth quarter 2004 distribution.
Results of Operations
Operating Highlights
(1)
Excludes amounts attributable to equity ownership interests in the corporate joint ventures.
(2)
Represents total average daily pipeline throughput multiplied by the number of miles of pipeline through which each barrel has been shipped.
(3)
Acquired on March 30, 2004. Amount for 2004 represents throughput for the period from the date of acquisition through December 31, 2004, divided by the number of days in that period.
(4)
Includes results from the Corsicana to Wichita Falls, Texas pipeline system, the Millennium and Kilgore pipeline system and the Amdel pipeline system from acquisition dates.
(5)
Represents total segment sales and other operating revenue minus cost of products sold and operating expenses and depreciation and amortization divided by crude oil pipeline throughput.
Analysis of Consolidated Net Income
Net income was $57.0 million, $61.7 million and $90.3 million for the years ended December 31, 2004, 2005 and 2006 respectively.
The $28.6 million increase in net income from 2005 to 2006 was primarily the result of the operating results from the acquisitions completed in 2005 and 2006 in the Western Pipeline System, an increase in total shipments in the Eastern Pipeline System, increased revenues at the Partnership’s refined product terminals associated with ethanol blending, higher lease acquisition results and the absence of non-recurring costs related to Hurricane Rita, described below. These increases in net income were partially offset by higher interest expense related to financing the acquisitions completed in 2006 and the Partnership’s internal expansion capital program.
The $4.7 million increase in net income from 2004 to 2005 was primarily the result of higher pipeline volumes in the Western Pipeline System and higher refined product terminal volumes. Partially offsetting these increases were $5.3 million in lost operating income and additional costs as a result of Hurricane Rita (see discussion below), higher insurance costs related to $2.5 million in special assessments by one of the Partnership’s insurers as a result of Hurricanes Rita and Katrina, and $2.0 million of costs related to the relocation of the Western area office from Tulsa, Oklahoma to Sugar Land, Texas.
On September 24, 2005, Hurricane Rita damaged the Partnership’s Nederland Terminal facility and a portion of the Western Pipeline System, impacting several storage tanks, dock facilities, buildings and equipment. Although the Nederland Terminal resumed operations on October 3, 2005, the business was impacted for a few weeks as a result of interruptions in customer and supplier business activities related to the hurricane. The additional costs in 2005 and 2006 attributed to the hurricane totaled approximately $6.2 million. The
Partnership expects to incur additional costs of approximately $2.1 million in 2007 to repair its damaged facilities and expects to negotiate a settlement with its insurance carrier for reimbursement of a portion of its costs during 2007.
Net interest expense was $27.9 million for the year ended December 31, 2006, a $6.3 million increase from the prior year. Interest expense increased due to increased borrowings and higher interest rates, partially offset by an increase of $2.5 million in capitalized interest. The increased borrowings were used to partially fund the 2006 acquisitions of the Millennium and Kilgore crude oil pipelines, and Amdel and White Oil crude oil pipelines and the 55.3 percent equity interest in the Mid-Valley pipeline, as well as to fund organic growth projects. Net interest expense was $21.6 million for the year ended December 31, 2005, a $1.3 million increase from the previous year due principally to higher interest rates and increased borrowings under the Partnership’s Credit Facility, partially offset by $0.5 million in capitalized interest.
Analysis of Segment Operating Income
Year Ended December 31, 2006 versus Year Ended December 31, 2005
Eastern Pipeline System
Operating income for the Eastern Pipeline System was $44.2 million for the year ended December 31, 2006 compared with $32.3 million for the prior year. The $11.9 million increase was the result of a $8.4 million increase in total revenues and a $1.5 million decrease in operating expenses. Sales and other operating revenue increased from $96.7 million from the prior year to $105.6 million for the year ended December 31, 2006 mainly due to an increase in total shipments resulting from higher throughput on the Marysville, Michigan to Toledo, Ohio crude oil pipeline. During 2005, two third-party Canadian synthetic crude oil plants experienced reduced production as a result of fire damage. Resumption of production at these crude oil plants, along with higher demand due to the expansion of a Detroit refinery served by the Marysville pipeline, resulted in an increase in shipments. Other income decreased to $11.2 million for the year ended December 31, 2006 from $11.8 million for the prior year period due primarily to a decrease in joint venture equity income. Operating expenses decreased from $47.0 million in the prior year to $45.5 million for the year ended December 31, 2006 due mainly to product operating gains, partially offset by increased utility, employee and operating costs associated with increased volumes. Selling, general and administrative expenses decreased $1.0 million for the year ended December 31, 2006 when compared to the prior year due primarily to increased capitalization of certain engineering-employee costs associated with the Partnership’s organic growth capital projects. Depreciation and amortization expense decreased $1.0 million for the full year 2006 as certain assets reached the end of their depreciation life during the third quarter 2006.
Terminal Facilities
The Terminal Facilities business segment experienced an increase in operating income to $39.1 million for the year ended December 31, 2006 compared with $35.8 million for the prior year. Total revenues increased $9.4 million from the prior year to $123.3 million for the year ended December 31, 2006 due primarily to increased revenues associated with the addition of ethanol blending at the balance of the Partnership’s refined product terminals starting in May 2006, an increase in revenues at the Partnership’s Nederland Terminal and the addition of product additive revenues at the Partnership’s refined product terminals. Operating expenses increased $4.9 million from the prior year to $53.4 million for the year ended December 31, 2006 due to higher maintenance activity, increased employee costs and additional refined product additive costs.
Western Pipeline System
Operating income for the Western Pipeline System was $34.8 million for the year ended December 31, 2006 compared with $15.2 million for the prior year. The increase was primarily the result of higher crude oil pipeline volumes resulting from the 2005 and 2006 crude oil pipeline acquisitions, an increase in other income of $3.6 million primarily attributable to equity income from the acquisition of a 55.3 percent interest in the Mid-Valley
Pipeline Company in August 2006 and higher lease acquisition results. Total revenues, and cost of products sold and operating expenses increased for the full year 2006 compared with the prior year due principally to an increase in the price of crude oil. The average price of West Texas Intermediate crude oil at Cushing, Oklahoma, increased to $66.25 per barrel for the full year 2006 from $56.61 per barrel for the full year 2005. Selling, general and administrative expenses increased $2.7 million due principally to costs related to the Western area office relocation from Tulsa, Oklahoma to Sugar Land, Texas, as well as increased costs associated with the acquired assets. The relocation to Sugar Land was completed in the first quarter 2006. Depreciation and amortization increased by $3.5 million due principally to the 2005 and 2006 acquisitions discussed earlier.
Year Ended December 31, 2005 versus Year Ended December 31, 2004
Eastern Pipeline System
Operating income for the Eastern Pipeline System was $32.3 million for the year ended December 31, 2005 compared with $34.3 million for the prior year. The $2.0 million decrease was the result of a $0.7 million decrease in total revenues and a $1.3 million increase in operating expenses. Total revenues decreased to $108.4 million for the year ended December 31, 2005 from $109.1 million for the prior year due mainly to lower shipments on the Marysville to Toledo crude oil pipeline caused by production issues at two third-party Canadian synthetic crude oil plants during the first three quarters of 2005, partially offset by a full year’s results in 2005 from the acquisition of an additional one-third interest in the Harbor pipeline in June 2004. Operating expenses increased from $45.8 million in 2004, to $47.0 million for 2005 due mainly to higher pipeline maintenance activity. Selling, general and administrative expenses increased due mainly to the allocation of a portion of the special insurance assessments discussed above.
Terminal Facilities
The Terminal Facilities business segment experienced an increase in operating income to $35.8 million for the year ended December 31, 2005 compared with $32.8 million for the prior year. This increase was due mainly to a $7.8 million increase in sales and other operating revenue, partially offset by a $4.9 million increase in total costs and expenses. The increase in sales and other operating revenue to $113.8 million for 2005 compared with $106.0 million for the prior year was principally due to a full year’s results in 2005 from the acquisitions of the Eagle Point terminal assets located in Westville, New Jersey, and the three refined product terminals located in Baltimore, Maryland; Manassas, Virginia; and Columbus, Ohio during 2004, as well as an increase in the Nederland Terminal’s volumes despite the adverse impact of Hurricane Rita.
The increase in total costs and expenses was due mainly to a $3.6 million increase in operating expenses and a $1.4 million increase in selling, general and administrative expenses. Operating expenses increased in 2005 due principally to the assets acquired in 2004. Selling, general and administrative expenses increased due mainly to the allocation of a portion of the special insurance assessments discussed above.
Western Pipeline System
Operating income for the Western Pipeline System was $15.2 million for the year ended December 31, 2005 compared with $10.3 million for the prior year. The $4.9 million increase was primarily the result of an increase in crude oil pipeline volumes, partially offset by lower crude oil sales and marketing results, a $2.5 million increase in depreciation and amortization and a $2.7 million increase in selling, general and administrative costs. The increase in pipeline volumes was due to volumes from the Corsicana to Wichita Falls, Texas crude oil pipeline acquisition and higher volumes on the Nederland to Longview, Texas pipeline. Sales and other operating revenue and cost of products sold and operating expenses increased for the year ended December 31, 2005 compared with the prior year due principally to an increase in crude oil prices. Depreciation and amortization increased by $2.5 million in 2005 due principally to the Corsicana to Wichita Falls crude oil pipeline acquisition. Selling, general and administrative expenses increased due to the allocation of a portion of the special insurance assessments discussed above and $2.0 million of costs related to the Western area office relocation from Tulsa to Sugar Land.
Liquidity and Capital Resources
Liquidity
Cash generated from operations and borrowings under the Credit Facility are the Partnership’s primary sources of liquidity. At December 31, 2006, the Partnership had a working capital deficit of $17.6 million and available borrowing capacity under the Credit Facility of $232.0 million. The Partnership’s working capital position reflects crude oil inventories based on historical costs under the LIFO method of accounting. If the inventories had been valued at their current replacement cost, the Partnership would have had working capital of $77.4 million at December 31, 2006.
Capital Resources
The Partnership periodically supplements its cash flows from operations with proceeds from debt and equity financing activities.
Credit Facility
On December 1, 2005, Sunoco Logistics Partners Operations L.P., a wholly-owned subsidiary of the Partnership (the “Operating Partnership”), amended the November 22, 2004, Credit Facility to increase the commitment amount from $250 million to $300 million, and extend the term by one year to November 22, 2010. At December 31, 2005, there was $106.6 million outstanding under the Credit Facility. In March, 2006, the Partnership drew an additional $109.5 million against the Credit Facility to fund the acquisitions of two Texas crude oil pipeline systems. As discussed below, the $216.1 million in borrowings outstanding under the Credit Facility were repaid in May 2006 with proceeds from the Senior Notes offering, together with a portion of the net proceeds from the concurrent equity offering of approximately 2.7 million limited partner common units described below. In August, 2006, the Partnership drew $46.0 million against the Credit Facility which was used along with $19.0 million of cash to fund the acquisition of a 55.3 percent equity interest (50 percent voting rights) in Mid-Valley Pipeline Company. In November 2006, the Partnership drew $22.0 million against the Credit Facility, to fund its organic growth projects. The amount outstanding under the Credit Facility at December 31, 2006 totaled $68.0 million.
The Credit Facility is available to fund working capital requirements, to finance future acquisitions, and for general partnership purposes. It also includes a $20.0 million distribution sublimit that is available for distributions, and may be used to fund the quarterly distributions, provided the total outstanding borrowings for distributions do not at any time exceed $20.0 million. The Partnership will be required to reduce to zero all borrowings under the distribution sublimit under the Credit Facility each year for 15 days.
Obligations under the Credit Facility are unsecured. Indebtedness under the Credit Facility will rank equally with all the outstanding unsecured and unsubordinated debt of the Operating Partnership. All loans may be prepaid at any time without penalty subject to reimbursement of breakage and redeployment costs in the case of prepayment of LIBOR borrowings. Indebtedness under the Credit Facility bears interest, at the Partnership’s option, at either (i) LIBOR plus an applicable margin or (ii) the higher of the federal funds rate plus 0.50 percent or the Citibank prime rate (each plus the applicable margin). The interest rate on the borrowings outstanding under the Credit Facility as of December 31, 2006 was 5.70 percent. Additionally, certain fees are incurred in connection with the Credit Facility.
The credit agreement prohibits the Partnership from declaring distributions to unitholders if any event of default, as defined in the credit agreement, occurs or would result from the declaration of distributions. In addition, the Credit Facility contains various covenants requiring the maintenance, on a rolling-four-quarter basis, of:
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a maximum ratio of 4.75 to 1 of consolidated total debt to consolidated EBITDA (each as defined in the credit agreement), which can be increased to 5.25 to 1 during an acquisition period (as defined in the credit agreement); and
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an interest coverage ratio (as defined in the credit agreement) of at least 3.0 to 1.
For the year ended December 31, 2006, the Partnership’s ratio of total debt to EBITDA was 2.9 to 1 and the interest coverage ratio was 4.9 to 1.
Senior Notes
In May 2006, the Operating Partnership issued $175 million of 6.125 percent Senior Notes, due May 15, 2016 at 99.858 percent of the principal amount, for net proceeds of $173.3 million after the underwriter’s commission and legal, accounting and other transaction expenses. The Senior Notes are redeemable, at a make-whole premium, and are not subject to sinking fund provisions. The Senior Notes contain various covenants limiting the Operating Partnership’s ability to incur certain liens, engage in sale/leaseback transactions, or merge, consolidate or sell substantially all of its assets. The Operating Partnership is in compliance with these covenants as of December 31, 2006. The net proceeds from the Senior Notes, together with the $110.3 million in net proceeds from the concurrent offering of approximately 2.7 million limited partner common units, described below, were used to repay all of the $216.1 million in outstanding borrowings under the Partnership’s Credit Facility. The balance of the proceeds from the offerings are being used to fund the Partnership’s organic growth program and for general Partnership purposes, including to finance pending and future acquisitions.
Equity Offerings
In May 2006, the Partnership sold 2.4 million common units in a public offering. In June 2006, the Partnership sold an additional 280,000 common units to cover over-allotments in connection with the May 2006 sale. The purchase price for the over allotment was equal to the offering price in the May 2006 sale. The total sale of units resulted in gross proceeds of $115.2 million, and net proceeds of $110.3 million, after the underwriters’ commission and legal, accounting and other transaction expenses. Net proceeds of the offering, together with the $173.3 million in net proceeds from the concurrent offering of Senior Notes, described above, were used to repay $216.1 million of the debt incurred under the revolving credit facility, to fund the Partnership’s 2006 organic growth program, and for general partnership purposes. Also as a result of the issuance of these units, the general partner contributed $2.4 million to the Partnership to maintain its 2.0 percent general partner interest.
In August 2005, the Partnership sold 1.5 million common units in a public offering. In September 2005, the Partnership sold an additional 125,000 common units to cover over-allotments in connection with the August 2005 sale. The total sale of units resulted in total gross proceeds of $63.4 million, and net proceeds of $60.4 million, after the underwriters’ commission and legal, accounting and other transaction expenses. Net proceeds of the sale were used to repay $56.5 million of the debt incurred to finance the August 1, 2005 purchase of a Texas crude oil pipeline system and storage facilities, with the balance for general partnership purposes. As a result of this issuance of 1.625 million common units, the general partner contributed $1.3 million to the Partnership to maintain its 2.0 percent general partner interest.
In May 2005, the Partnership sold 2.5 million common units in a public offering. In June 2005, the Partnership sold an additional 275,000 common units to cover over-allotments in connection with the May 2005 sale. The purchase price for the over-allotment was equal to the offering price in the May 2005 sale. The sale of units resulted in total gross proceeds of $104.1 million, and net proceeds of $99.2 million, after underwriters’ commissions and legal, accounting and other transaction expenses. Net proceeds from the sale were used to redeem 2.775 million common units owned by Sunoco at a redemption price per unit equal to the public offering price per unit after the underwriters’ commissions.
On April 7, 2004, the Partnership sold 3.4 million common units in a public offering for total gross proceeds of $135.1 million. The sale of the units resulted in net proceeds of $128.7 million, after underwriters’ commissions and legal, accounting, and other transaction expenses. Net proceeds from the sale were used to (a) redeem approximately 2.2 million common units from Sunoco for $82.7 million, (b) replenish cash utilized to acquire the Eagle Point logistics assets for $20.0 million, (c) finance the acquisition of two refined product terminals for $12.0 million, (d) finance the acquisition of an additional 33.3 percent undivided interest in the
Harbor pipeline for $7.3 million, and (e) for general partnership purposes, including to replenish cash used for past acquisitions and capital improvements, and for other expansion, capital improvements and acquisition projects. As a result of this net issuance of 1.2 million common units, the general partner contributed $1.0 million to the Partnership to maintain its 2.0 percent general partner interest.
Shelf Registration Statement
On December 21, 2005, the Partnership, the Operating Partnership, and the Operating Partnership’s wholly-owned subsidiaries, as co-registrants, filed a shelf registration statement with the Securities and Exchange Commission. This shelf registration, if and when declared effective by the SEC, will permit the periodic offering and sale of up to $500 million of equity securities by the Partnership or debt securities of the Operating Partnership (guaranteed by the Partnership). The shelf registration statement also covers the resale of up to 5.0 million common units by the Partnership’s general partner. This shelf registration statement replaced the March 2003 shelf registration statement previously filed. As of December 31, 2006, $209.8 remains available for issuance under the shelf registration statement. The amount, type and timing of any offerings will depend upon, among other things, the funding requirements of the Partnership, prevailing market conditions, and compliance with covenants in applicable debt obligations of the Operating Partnership (including the Credit Facility).
Cash Flows and Capital Expenditures
Net cash provided by operating activities for the years ended December 31, 2004, 2005 and 2006 was $106.6 million, a $90.8 million and $141.5 million, respectively. Net cash provided by operating activities for 2006 consists primarily of net income of $90.3 million, depreciation and amortization of $36.6 million, and an increase in the working capital deficit of $11.5 million. Net cash provided by operating activities for 2005 consists primarily of net income of $61.7 million, depreciation and amortization of $33.8 million, and an increase in working capital of $6.2 million. Net cash provided by operating activities for 2004 consists primarily of net income of $57.0 million, depreciation and amortization of $31.9 million, and a decrease in working capital of $13.5 million. The increase in net cash provided by operating activities from 2005 to 2006 was primarily attributable to an increase in net income of approximately $28.6 million during 2006. The decrease in net cash provided by operating activities from 2004 to 2005 was primarily attributable to changes in working capital due to fluctuations in the price of crude oil and timing of operating cash receipts and disbursements.
Net cash used in investing activities for the years ended December 31, 2004, 2005 and 2006 was $95.6 million, $180.7 million, and $241.2 million respectively. The increases in cash used in investing activities from 2004 to 2005 and from 2005 to 2006 are due to acquisitions and organic growth projects. Capital expenditures (excluding acquisitions) were $46.4 million in 2004, $73.3 million in 2005 and $119.8 million in 2006 (see “Capital Requirements” below).
Cash used for acquisitions was $49.2 million in 2004, $107.3 million in 2005 and $121.4 million in 2006. Acquisitions completed in 2006 include the Amdel and White Oil pipeline for approximately $68.0 million, the Millennium and Kilgore pipeline system, storage facilities, sales and marketing business and crude oil inventoy for approximately $40.9 million and a 55.3 percent equity interest (50 percent voting rights) in Mid-Valley Pipeline Company for approximately $65.0 million. Since the acquisition was from a related party, the interest in the entity was recorded by the Partnership at Sunoco’s historical cost of $12.5 million and the $52.5 million difference between the purchase price and the cost basis of the assets was recorded by the Partnership as a capital distribution. Acquisitions completed in 2005 include the Corsicana to Wichita Falls, Texas crude oil pipeline system and storage facilities for approximately $100.0 million and a 37.0 percent undivided joint interest in the Mesa Pipe Line system for approximately $6.6 million. During 2004, the Partnership completed the following acquisitions: the Eagle Point logistics assets, which were purchased for approximately $20.0 million; two refined product terminals located in Baltimore, Maryland and Manassas, Virginia, which were purchased for approximately $12.0 million; an additional 33.3 percent undivided interest in the Harbor pipeline, which was acquired for approximately $7.3 million; and a refined product terminal located in Columbus, Ohio, which was purchased for approximately $8.0 million.
Net cash provided by / (used in) financing activities for the years ended December 31, 2004, 2005 and 2006 was, ($8.5) million $58.8 million, and $87.5 million respectively.
For the year ended December 31, 2006, the Partnership received $173.3 million of net proceeds from the issuance of Senior Notes and net proceeds of $110.3 million from the concurrent public offerings completed in May 2006 and borrowings of $177.5 million drawn against the Credit Facility to fund the acquisitions of two Texas crude oil pipelines and the 55.3 percent interest in the Mid-Valley pipeline. The $173.3 million net proceeds from the Senior Notes, together with the $110.3 million in net proceeds from the concurrent public offering were used to repay all of the $216.1 million in outstanding borrowings under the Partnership’s Credit Facility. Additionally, the Partnership received $5.7 million of capital contributions for reimbursement of certain maintenance capital expenditures and operating expenses under agreements with Sunoco. The net proceeds from these sources were partially offset by $98.0 million in distributions paid to limited partners and the general partner, $47.4 million in capital distributions to Sunoco due primarily to the acquisition of a 55.3 percent interest (50 percent voting rights) in the Mid-Valley Pipeline Company and net advances to affiliates of $13.2 million.
For the year ended December 31, 2005, the Partnership received $60.4 million of net proceeds from the public offering completed in September 2005, net borrowings of $42.1 million drawn against the Credit Facility to fund the acquisitions of an undivided joint interest in the Mesa Pipe Line system and a portion of the Corsicana to Wichita Falls, Texas crude oil pipeline system and storage facilities, and the related pipeline construction. Additionally, the Partnership received $8.0 million of capital contributions for reimbursement of certain maintenance capital expenditures and operating expenses under agreements with Sunoco, and $18.1 million as a result of a reduction in advances to affiliates. The net proceeds from these sources were partially offset by $67.3 million in distributions paid to limited partners and the general partner in 2005.
For the year ended December 31, 2004, the $8.5 million of net cash used in financing activities was due to the $82.7 million redemption of approximately 2.2 million common units from Sunoco, $57.5 million of cash distributions paid to the limited partners and general partner, and net advances to affiliates of $5.1 million, partially offset by $128.7 million of net proceeds from the sale of 3.4 million common units in April 2004, $7.0 million of capital contributions for reimbursement of certain maintenance capital expenditures and operating expenses under agreements with Sunoco, and a $1.0 million net contribution from the general partner to maintain its 2.0 percent ownership interest after the sale of common units.
Under a treasury services agreement with Sunoco, the Partnership participates in Sunoco’s centralized cash management program. Advances from affiliates in the Partnership’s balance sheets at December 31, 2005 represent amounts due to Sunoco under this agreement, and advances to affiliates in the balance sheet at December 31, 2006 represent amounts due from Sunoco under the agreement.
Capital Requirements
The pipeline, terminalling, and crude oil storage operations are capital intensive, requiring significant investment to maintain, upgrade and enhance existing operations and to meet environmental and operational regulations. The capital requirements have consisted, and are expected to continue to consist, primarily of:
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Maintenance capital expenditures, such as those required to maintain equipment reliability, tankage, and pipeline integrity and safety, and to address environmental regulations; and
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Expansion capital expenditures to acquire complementary assets to grow the business and to expand existing and construct new facilities, such as projects that increase storage or throughput volume.
The following table summarizes maintenance and expansion capital expenditures, including amounts paid for acquisitions, for the years presented:
(1)
Includes the following acquisitions: $20.0 million for the Eagle Point logistics assets; $12.0 million for two refined product terminals located in Baltimore, Maryland and Manassas, Virginia; $7.3 million for an additional 33.3 percent undivided interest in the Harbor pipeline; and $8.0 million for a refined product terminal located in Columbus, Ohio.
(2)
Includes $100.0 million related to the acquisition of the Corsicana to Wichita Falls, Texas crude oil pipeline system and storage facilities and $5.5 million for the undivided joint interest in the Mesa Pipe Line system. The total purchase price of the Mesa interest was $6.6 million, however since a portion of the interest was acquired from a related party, it was recorded by the Partnership at Sunoco’s historical cost and the $1.1 million difference between the purchase price and the cost basis of the assets was recorded by the Partnership as a capital distribution.
(3)
Includes $40.9 million related to the acquisition of the Millennium and Kilgore crude oil pipeline system, $68.0 million related to the acquisition of the Amdel and White Oil crude oil pipeline system and $12.5 million related to the acquisition of a 55.3 percent equity interest in Mid-Valley Pipeline Company. The total purchase price of Mid-Valley was $65.0 million, however since a portion of the interest was acquired from a related party, it was recorded by the Partnership at Sunoco’s historical cost and the $52.5 million difference between the purchase price and the cost basis of the assets was recorded by the Partnership as a capital distribution.
Maintenance capital expenditures primarily consist of recurring expenditures at each of the business segments such as pipeline integrity costs, pipeline relocations, repair and upgrade of field instrumentation, including measurement devices, repair and replacement of tank floors and roofs, upgrades of cathodic protection systems, crude trucks and related equipment, and the upgrade of pump stations. In addition to these recurring projects, maintenance capital includes certain expenditures for which the Partnership received reimbursement from Sunoco under the terms of agreements between the parties (see “Agreements with Sunoco”). Maintenance capital for the years ended December 31, 2005 and 2006 include $2.7 million and $2.8 million, respectively, related to the Western Area office move that was completed in the first quarter of 2006. As of December 31, 2006, the Partnership has received the maximum aggregate reimbursements defined within the Omnibus Agreement with Sunoco. As a result, the Partnership does not expect to be reimbursed by Sunoco for certain maintenance capital expenditures going forward. Management expects maintenance capital expenditures to be approximately $25.0 million in 2007, excluding reimbursements from Sunoco in accordance with the terms of certain agreements.
Expansion capital expenditures include $49.2 million, $107.3 million and $121.4 million in the years ended December 31, 2004, 2005 and 2006 respectively related to the acquisitions discussed above.
Expansion capital expenditures for the year ended December 31, 2006 also include the ongoing construction at Nederland of seven new crude oil storage tanks with approximately 4.2 million shell barrels capacity, installation of ethanol blending facilities at certain refined product terminals and expansions of the Marysville crude oil pipeline and the Montello to Pittsburgh segment of the Eastern Products System.
Management expects to invest approximately $98.0 million in expansion capital projects in 2007. This internal expansion program includes primarily the construction of new tankage and pipeline connections
associated with the previously discussed agreement with Motiva Enterprises LLC, the continued construction of tankage at the Nederland Terminal, pipeline connections in the Western Pipeline system and new tankage in both the Eastern and Western Pipeline systems.
The Partnership expects to fund its capital expenditures, including any additional acquisitions, from cash provided by operations and, to the extent necessary, from the proceeds of borrowing under the Credit Facility, other borrowings and issuance of additional common units.
Contractual Obligations
The following table sets forth the aggregate amount of long-term debt maturities (including interest commitments based upon the interest rate in effect at December 31, 2006), annual rentals applicable to noncancelable operating leases, and purchase commitments related to future periods at December 31, 2006 (in thousands of dollars):
The Partnership’s operating leases reported above include leases of office space, third-party pipeline capacity, and other property and equipment, with initial or remaining noncancelable terms in excess of one year. On September 1, 2005, the Partnership executed an agreement to lease office space in Sugar Land, Texas for a term of approximately ten years. The lease terminates in December 2016.
A purchase obligation is an enforceable and legally binding agreement to purchase goods and services that specifies significant terms, including: fixed or expected quantities to be purchased; market-related pricing provisions; and a specified term. The Partnership’s purchase obligations consist of noncancelable contracts to purchase crude oil for terms of one year or less by its Crude Oil Acquisition and Marketing group. The majority of the above purchase obligations include actual crude oil purchases for the month of January 2007. The remaining crude oil purchase obligation amounts are based on the quantities committed to be purchased assuming adequate well production for the remainder of the year, at December 31, 2006 crude oil prices. Actual amounts to be paid in regards to these obligations will be based upon market prices or formula-based market prices during the period of purchase. For further discussion of the Partnership’s Crude Oil and Marketing activities, see Item 1. “Business-Western Pipeline System-Crude Oil Acquisition and Marketing”.
Environmental Matters
Operation of the pipelines, terminals, and associated facilities are subject to stringent and complex federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment. As a result of compliance with these laws and regulations, liabilities have been accrued for estimated site restoration costs to be incurred in the future at the facilities and properties, including liabilities for environmental remediation obligations. Under the Partnership’s 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. For a discussion of the accrued liabilities and charges against income related to these activities, see Note 10 to the financial statements included in Item 8. “Financial Statements and Supplementary Data.”
Under the terms of the Omnibus Agreement and in connection with the contribution of assets to the Partnership by affiliates of Sunoco, Sunoco has agreed to indemnify the Partnership for 30 years from environmental and toxic tort liabilities related to the assets contributed that arise from the operation of such assets prior to closing of the February 2002 IPO. See “Agreements with Sunoco.”
For more information concerning environmental matters, please see Item 1. “Business-Environmental Regulation.”
Impact of Inflation
The impact of inflation is 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 existing agreements, the Partnership has and will continue to pass along increased costs to customers in the form of higher fees.
Critical Accounting Policies
A summary of the Partnership’s significant accounting policies is included in Note 1 to the financial statements included in Item 8 “Financial Statements and Supplementary Data.” Management believes that the application of these policies on a consistent basis enables it to provide the users of the financial statements with useful and reliable information about the Partnership’s operating results and financial condition. The preparation of the Partnership’s financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Significant items that are subject to such estimates and assumptions include long-lived assets and environmental remediation activities. Although management bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, actual results may differ from the estimates on which the Partnership’s financial statements are prepared at any given point in time. Despite these inherent limitations, management believes the Partnership’s Management’s Discussion and Analysis and financial statements provide a meaningful and fair perspective of the Partnership. Management has reviewed the estimates affecting its critical accounting policies with the Audit/Conflicts Committee of Sunoco Partners LLC’s Board of Directors.
The critical accounting policies identified by management of the Partnership are as follows:
Long-Lived Assets. The cost of properties, plants and equipment, less estimated salvage value, is generally depreciated on a straight-line basis over the estimated useful lives of the assets. Useful lives are based on historical experience and are adjusted when changes in planned use, technological advances or other factors indicate that a different life would be more appropriate. Changes in useful lives that do not result in the impairment of an asset are recognized prospectively. During 2004 and 2005, the Partnership accelerated the depreciation of assets related to equipment upgrade programs and the Western area office move from Tulsa, Oklahoma to Sugar Land, Texas, based upon the estimated remaining useful lives of these assets until their replacement. The acceleration resulted in $1.8 million and $0.5 million of additional depreciation expense recognized in 2005 and 2006, respectively
Long-lived assets are reviewed for impairment whenever events or circumstances indicate that the carrying amount of the assets may not be recoverable. Such events and circumstances include, among other factors: operating losses; unused capacity; market value declines; technological developments resulting in obsolescence; changes in demand for products manufactured by others utilizing the Partnership’s services or for the Partnership’s products; changes in competition and competitive practices; uncertainties associated with the United States and world economies; changes in the expected level of environmental capital, operating or remediation expenditures; and changes in governmental regulations or actions. Additional factors impacting the economic viability of long-lived assets are discussed under “Forward Looking Statements” in this document.
A long-lived asset is considered to be impaired when the undiscounted net cash flows expected to be generated by the asset are less than its carrying amount. Such estimated future cash flows are highly subjective and are based on numerous assumptions about future operations and market conditions. The impairment recognized is the amount by which the carrying amount exceeds the fair market value of the impaired asset. It is also difficult to precisely estimate fair market value because quoted market prices for the Partnership’s long-lived assets may not be readily available. Therefore, fair market value is generally based on the present values of estimated future cash flows using discount rates commensurate with the risks associated with the assets being reviewed for impairment.
There were no asset impairments for the years ended December 31, 2004 and 2005 and 2006.
Environmental Remediation. The operation of the Partnership’s pipelines, terminals and associated facilities are subject to numerous federal, state and local laws and regulations which regulate the discharge of materials into the environment or that otherwise relate to the protection of the environment. As a result of compliance with these laws and regulations, site restoration costs have been and will be incurred in the future at the Partnership’s facilities and properties, including liabilities for environmental remediation obligations.
At December 31, 2006, the Partnership’s accrual for environmental remediation activities was $0.5 million. This accrual is for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. The accrual is undiscounted and is based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. It is often extremely difficult to develop reasonable estimates of future site remediation costs due to changing regulations, changing technologies and their associated costs, and changes in the economic environment. In the above instances, if a range of probable environmental cleanup costs exists for an identified site, FASB Interpretation No. 14, “Reasonable Estimation of the Amount of a Loss” requires that the minimum of the range be accrued unless some other point or points in the range are more likely, in which case the most likely amount in the range is accrued. Engineering studies, historical experience and other factors are used to identify and evaluate remediation alternatives and their related costs in determining the estimated accruals for environmental remediation activities. Losses attributable to unasserted claims are also reflected in the accruals to the extent their occurrence is probable and reasonably estimable.
Management believes that none of the current remediation locations are material, individually or in the aggregate, to the Partnership’s financial position at December 31, 2006. As a result, the Partnership’s exposure to adverse developments with respect to any individual site is not expected to be material. However, if changes in environmental regulations occur, such changes could impact several of the Partnership’s facilities. As a result, from time to time, significant charges against income for environmental remediation may occur.
Under the terms of the Omnibus Agreement and in connection with the contribution of assets to the Partnership by affiliates of Sunoco, Sunoco has agreed to indemnify the Partnership, in whole or in part, for 30 years from environmental and toxic tort liabilities related to the assets contributed that arise from the operation of such assets prior to closing of the February 2002 IPO. The Partnership has agreed to indemnify Sunoco and its affiliates for events and conditions associated with the operation of the assets that occur on or after the closing of the February 2002 IPO and for environmental and toxic tort liabilities to the extent Sunoco is not required to indemnify the Partnership. See “Agreements with Sunoco” for more information.
In summary, total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the technology available and needed to meet the various existing legal requirements, the nature and terms of cost sharing arrangements with other potentially responsible parties and the nature and extent of future environmental laws, inflation rates and the determination of the Partnership’s liability at the sites, if any, in the light of the number, participation level and financial viability of other parties.
New Accounting Pronouncements
For a discussion of recently issued accounting pronouncements requiring adoption subsequent to December 31, 2006, see Note 1 to the consolidated financial statements.
Agreements with Sunoco
The Partnership has entered into several agreements with Sunoco, and their affiliates as discussed below.
Pipelines and Terminals Storage and Throughput Agreement
Under this 2002 agreement, Sunoco is paying the Partnership fees generally comparable to those charged by third parties to:
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transport on the refined product pipelines or throughput in the refined product terminals existing at the time of the agreement an amount of refined products that will produce at least $80.1 million of revenue for the contract year from March 1, 2006 to February 28, 2007. In addition, Sunoco will pay the Partnership to transport on those refined product pipelines or throughput in those refined product terminals an amount of refined products that will produce at least $54.3 million of revenue in the contract year commencing March 1, 2007, and at least $55.2 million of revenue in the contract year commencing March 1, 2008. Sunoco will pay the published tariffs on the pipelines and contractually agreed upon fees at the terminals. Based upon the prorated minimum amount noted, Sunoco has exceeded the minimum revenue amount through December 31, 2006 and management of the Partnership expects Sunoco to exceed the minimum amount under the agreement for the contract year from March 1, 2006 through February 28, 2007. An agreement with respect to Sunoco’s continued throughput of refined products in the refined product terminals is expected to be renegotiated with Sunoco during the first quarter of 2007;
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receive and deliver at least 130,000 bpd of refined products per year at the Marcus Hook Tank Farm for five years ending February 28, 2007. For the calendar year ended December 31, 2006, the Partnership received a fee of $0.1738 per barrel for the first 130,000 bpd and $0.0869 per barrel for volume in excess of 130,000 bpd. Based upon the prorated minimum throughput amount noted, Sunoco has exceeded the minimum throughput amount through December 31, 2006 and management of the Partnership expects Sunoco to exceed the minimum throughput amount under the agreement for the contract year from March 1, 2006 through February 28, 2007. An agreement with respect to Sunoco’s continued throughput of refined products through the Marcus Hook Tank Farm is expected to be renegotiated with Sunoco during the first quarter 2007;
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store 975,734 barrels of LPG per contract year at the Inkster Terminal, which represents all of the LPG storage capacity at this facility. This storage is an annual amount for the contract period from April 1 to March 31 for the seven-year term of the agreement ending March 31, 2009. For the calendar year ended December 31, 2006, the Partnership received a fee of $2.197 per barrel of committed storage, a fee of $0.220 per barrel for receipts greater than 975,734 barrels per contract year and a fee of $0.220 per barrel for deliveries greater than 975,734 barrels per contract year. These fees will escalate at the rate of 1.875 percent each January 1 for the term of the agreement. Based upon the prorated minimum storage amount noted, Sunoco has exceeded the minimum storage amount through December 31, 2006 and management of the Partnership expects Sunoco to exceed the minimum storage amount under the agreement for the contract year from April 1, 2006 through March 31, 2007;
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receive and deliver at least 290,000 bpd of crude oil or refined products per contract year at the Fort Mifflin Terminal Complex for seven years ending February 28, 2009. This throughput is an annual amount for the contract period from March 1 to February 28 for the term of the agreement. For the year ended December 31, 2006, the Partnership received a fee of $0.1738 per barrel for the first 180,000 bpd and $0.0869 per barrel for volume in excess of 180,000 bpd. These fees will escalate at the rate of 1.67 percent each January 1 for the term of the agreement. Based upon the prorated minimum throughput amount noted, Sunoco has exceeded the minimum throughput amount through December 31, 2006 and
management of the Partnership expects Sunoco to exceed the minimum throughput amount under the agreement for the contract year from March 1, 2006 through February 28, 2007; and
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transport or cause to be transported an aggregate of at least 140,000 bpd of crude oil per contract year on the Marysville to Toledo, Nederland to Longview, Cushing to Tulsa, Barnsdall to Tulsa, and Bad Creek to Tulsa crude oil pipelines at the published tariffs for a term of seven years ending February 28, 2009. This throughput is an annual amount for the contract period from March 1 to February 28 for the term of the agreement. Based upon the prorated minimum throughput amount noted, Sunoco has exceeded the minimum throughput amount through December 31, 2006 and management of the Partnership expects Sunoco to exceed the minimum throughput amount under the agreement for the contract year from March 1, 2006 through February 28, 2007.
If Sunoco fails to meet its minimum obligations pursuant to the contract terms set forth above, it will be required to pay in cash the amount of any shortfall, which may be applied as a credit in the following year after Sunoco’s minimum obligations for that year are met.
Sunoco’s obligations under this agreement may be permanently reduced or suspended if Sunoco (1) shuts down or reconfigures one of its refineries (other than planned maintenance turnarounds), or is prohibited from using MTBE in the gasoline it produces, and (2) reasonably believes in good faith that such event will jeopardize its ability to satisfy these obligations.
Sunoco actively manages its assets and operations, and, therefore, changes of some nature, possibly material to our business relationship, may occur at some point in the future.
There can be no assurance that upon expiration of any of the above described commitments, Sunoco will renew such commitments or agree to new commitments, or that, if renewed, the rates will be at or above the current rates. If Sunoco does not extend or renew one or more of the above commitments, the Partnership’s financial condition and results of operations may be adversely affected. The Partnership’s assets were constructed or purchased to service Sunoco’s refining and marketing supply chain and are well-situated to suit Sunoco’s needs. As a result, management of the Partnership would expect that even if this agreement is not renewed, Sunoco would continue to use the pipelines and terminals. However, there can be no assurance that Sunoco will continue to use the Partnership’s facilities or that additional revenues can be generated from third parties.
Sunoco’s obligations under this agreement do not terminate if Sunoco and its affiliates no longer own the general partner.
Omnibus Agreement
In 2002, the Partnership entered into an Omnibus Agreement with Sunoco and the general partner that addresses the following matters:
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Sunoco’s obligation to reimburse the Partnership for specified operating expenses and capital expenditures or otherwise to complete certain tank maintenance and inspection projects;
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the Partnership’s obligation to pay the general partner or Sunoco an annual administrative fee for the provision by Sunoco of certain general and administrative services;
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Sunoco’s and its affiliates’ agreement not to compete with the Partnership under certain circumstances;
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the Partnership’s agreement to undertake to develop and construct or acquire an asset if requested by Sunoco;
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an indemnity by Sunoco for certain environmental, toxic tort and other liabilities;
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the Partnership’s obligation to indemnify Sunoco and its affiliates for events and conditions associated with the operation of the assets that occur on or after the closing of the initial public offering and for environmental and toxic tort liabilities related to the assets to the extent Sunoco is not required to indemnify the Partnership; and
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the Partnership’s option to purchase certain pipeline, terminalling, and storage assets retained by Sunoco or its affiliates.
Reimbursement of Expenses and Completion of Certain Projects by Sunoco. The Omnibus Agreement requires Sunoco to:
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reimburse the Partnership for any operating expenses and capital expenditures in excess of $8.0 million per year in each calendar year from 2002 to 2006 that are made to comply with the DOT’s pipeline integrity management rule, subject to a maximum aggregate reimbursement of $15.0 million over the five-year period ending December 31, 2006;
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complete, at its expense, certain tank maintenance and inspection projects at the Darby Creek Tank Farm; and
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reimburse the Partnership for up to $10.0 million of required expenditures at the Marcus Hook Tank Farm and the Darby Creek Tank Farm to maintain compliance with existing industry standards and regulatory requirements, including: cathodic protection upgrades at these facilities; raising tank farm pipelines above ground level at these facilities; and repairing or demolishing two riveted tanks at the Marcus Hook Tank Farm.
The Partnership reports outlays for these programs as operating expenses or capital expenditures, as appropriate, in the financial statements. Capital expenditures are depreciated over their useful lives. Reimbursements by Sunoco are reflected as capital contributions to Partners’ Capital within the Partnership’s balance sheets.
For the years ended December 31, 2004, 2005 and 2006 the Partnership was reimbursed $2.1 million, $7.0 million, and $3.3 million respectively, by Sunoco for maintenance capital expenditures and operating expenses incurred in excess of $8.0 million to comply with the DOT’s pipeline integrity management rule. At December 31, 2006, the Partnership has received a cumulative reimbursement equal to the $15.0 million maximum aggregate reimbursement over the five-year period for compliance expenditures related to the DOT’s pipeline integrity management rule. As a result, the Partnership does not expect to be reimbursed by Sunoco going forward for expenditures related to integrity management.
For the years ended December 31, 2004, 2005 and 2006 the Partnership was reimbursed by Sunoco for expenditures at the Marcus Hook Tank Farm and the Darby Creek Tank Farm to maintain compliance with existing industry standards and regulatory requirements. These expenditures, which were recorded as maintenance capital and operating expenses, were as follows:
At December 31, 2006, the Partnership has received a cumulative reimbursement equal to the $10.0 million maximum aggregate reimbursement for compliance expenditures at the Marcus Hook Tank Farm and the Darby Creek Tank Farm. As a result, the Partnership does not expect to be reimbursed by Sunoco going forward for expenditures related to the Marcus Hook Tank Farm and the Darby Creek Tank Farm.
General and Administrative Services Fee. Under the Omnibus Agreement, the Partnership pays Sunoco or the general partner an annual administrative fee that includes expenses incurred by Sunoco and its affiliates to perform centralized corporate functions, such as legal, accounting, treasury, engineering, information technology, insurance, and other corporate services, including the administration of employee benefit plans. This fee was $8.4 million, $8.4 million and $7.7 million for the years ended December 31, 2004, 2005 and 2006, respectively. This fee does not include the costs of shared insurance programs (which are allocated to the Partnership based upon its share of the cash premiums incurred), the salaries of pipeline and terminal personnel or other employees of the general partner (including senior executives), or the cost of their employee benefits. The Partnership has no employees, and reimburses Sunoco and its affiliates for these costs and other direct expenses incurred on the Partnership’s behalf. In addition, the Partnership has incurred additional general and administrative costs which it pays directly.
The initial term of Section 4.1 of the Omnibus Agreement (which concerns the Partnership’s obligation to pay the annual fee for provision of certain general and administrative services) was through the end of 2004. The parties extended the term of Section 4.1 by one year each in January 2005, January 2006 and January 2007. The 2007 annual fee decreased to $6.5 million, which reflects the Partnership directly incurring some of these general and administrative costs. These costs may be increased if the acquisition or construction of new assets or businesses require an increase in the level of general and administrative services received by the Partnership. There can be no assurance that Section 4.1 of the Omnibus Agreement will be extended beyond 2007, or that, if extended, the administrative fee charged by Sunoco will be at or below the current administrative fee. In the event that the Partnership is unable to obtain such services from Sunoco or other third parties at or below the current cost, the Partnership’s financial condition and results of operations may be adversely impacted.
In addition to the fees for the centralized corporate functions, selling, general and administrative expenses in the statements of income include the allocation of shared insurance costs of $2.5 million, $5.1 million and $3.2 million for the years ended December 31, 2004, 2005 and 2006, respectively. The insurance costs for the year ended December 31, 2005 include $2.5 million resulting from two special assessments by one of the Partnership’s insurers as a result of Hurricanes Rita and Katrina. The Partnership’s share of allocated Sunoco employee benefit plan expenses, including non-contributory defined benefit retirement plans, defined contribution 401(k) plans, employee and retiree medical, dental and life insurance plans, incentive compensation plans and other such benefits, was $21.0 million, $21.5 million and $22.5 million for the years ended December 31, 2004, 2005 and 2006, respectively.
Development or Acquisition of an Asset by the Partnership. The Omnibus Agreement contains a provision pursuant to which Sunoco may at any time propose to the Partnership that it undertake a project to develop and construct or acquire an asset. If the general partner determines in its good faith judgment, with the concurrence of its Audit/Conflicts Committee, that the project, including the terms on which Sunoco would agree to use such asset, will be beneficial on the whole and that proceeding with the project will not effectively preclude the Partnership from undertaking another project that will be more beneficial to the Partnership, the Partnership will be required to use commercially reasonable efforts to finance, develop, and construct or acquire the asset.
Noncompetition. Sunoco agreed, and will cause its affiliates to agree, for so long as Sunoco controls the general partner, not to engage in, whether by acquisition or otherwise, the business of purchasing crude oil at the wellhead or operating crude oil pipelines or terminals, refined products pipelines or terminals, or LPG terminals in the continental United States. This restriction does not apply to:
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any business currently operated by Sunoco or any of its subsidiaries;
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any logistics asset constructed by Sunoco or any of its subsidiaries within a manufacturing or refining facility in connection with the operation of that facility;
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any business that Sunoco or any of its subsidiaries acquires or constructs that has a fair market value of less than $5.0 million; and
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any business that Sunoco or any of its subsidiaries acquires or constructs that has a fair market value of $5.0 million or more if the Partnership has been offered the opportunity to purchase the business for fair market value not later than six months after completion of such acquisition or construction, and the Partnership declines to do so with the concurrence of the Audit/Conflicts Committee.
In addition, the limitations on the ability of Sunoco and its affiliates to compete with the Partnership may terminate upon a change of control of Sunoco.
Options to Purchase Assets Retained by Sunoco. The Omnibus Agreement also contains the terms under which the Partnership has the option to purchase Sunoco’s direct or indirect interests in Inland Corporation, as well as the Icedale pipeline, as discussed under “Business-Pipeline, Terminalling, and Storage Assets Retained by Sunoco”.
Indemnification. Under the terms of the Omnibus Agreement and in connection with the contribution of assets by affiliates of Sunoco, Sunoco has agreed to indemnify the Partnership for 30 years from environmental and toxic tort liabilities related to the assets contributed that arise from the operation of such assets prior to closing of the February 2002 IPO. Sunoco is obligated to indemnify the Partnership for 100 percent of all losses asserted within the first 21 years of closing of the February 2002 IPO. Sunoco’s share of liability for claims asserted thereafter will decrease by 10 percent a year. For example, for a claim asserted during the twenty-third year after closing of the February 2002 IPO, Sunoco would be required to indemnify the Partnership for 80 percent of the loss. There is no monetary cap on the amount of indemnity coverage provided by Sunoco. In addition, this indemnification applies to the interests in the Mesa Pipeline system and the Mid-Valley pipeline purchased from Sunoco following the IPO. Any environmental and toxic tort liabilities not covered by this indemnity will be the Partnership’s responsibility. Total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the technology available and needed to meet the various existing legal requirements, the nature and extent of future environmental laws, inflation rates, and the determination of the liability at multiparty sites, if any, in light of the number, participation levels, and financial viability of other parties. The Partnership has agreed to indemnify Sunoco and its affiliates for events and conditions associated with the operation of the assets that occur on or after the closing of the February 2002 IPO and for environmental and toxic tort liabilities to the extent Sunoco is not required to indemnify the Partnership.
Sunoco has also agreed to indemnify the Partnership for liabilities relating to:
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the assets contributed, other than environmental and toxic tort liabilities, that arise out of the operation of the assets prior to the closing of the February 2002 IPO and that are asserted within ten years after the closing of the IPO;
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certain defects in title to the assets contributed and failure to obtain certain consents and permits necessary to conduct the business that arise within ten years after the closing of the February 2002 IPO;
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legal actions related to the period prior to the February 2002 IPO currently pending against Sunoco or its affiliates; and
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events and conditions associated with any assets retained by Sunoco or its affiliates.
Inter-refinery Pipeline Lease Agreement
Under a 20-year lease agreement entered into by the Partnership and Sunoco upon the closing of the February 2002 IPO, Sunoco leases the Partnership’s 58 miles of interrefinery pipelines between Sunoco’s Philadelphia and Marcus Hook refineries for an annual fee which escalates at 1.67 percent each January 1st for the term of the agreement. The annual fee for the year ended December 31, 2006 was $5.7 million. These fees are recorded as revenue within the Partnership’s statements of income.
The lease agreement also requires Sunoco to reimburse the Partnership for any non-routine maintenance expenditures, as defined, incurred during the term of the agreement. For the year ended December 31, 2006, the Partnership was reimbursed by Sunoco for maintenance capital expenditures associated with this provision. The reimbursement was recorded as a capital contribution to Partners’ Capital within the Partnership’s balance sheet.
Crude Oil Purchase Agreement
The Partnership has agreements with Sunoco whereby Sunoco purchases from the Partnership, at market-based rates, particular grades of crude oil that are purchased by the crude oil acquisition and marketing business. These agreements automatically renew on a monthly basis unless terminated by either party on 30 days’ written notice. Sunoco cancelled two of these agreements during 2006 in accordance with the terms, but the cancellation did not have a material impact on the Partnership’s results of operations or cash flows. During each of the three years ended December 31, 2006, Sunoco purchased all the barrels offered pursuant to these agreements and has not indicated that it intends to terminate any additional agreements.
License Agreement
The Partnership has granted to Sunoco and certain of its affiliates, including the general partner, a license to its intellectual property so that the general partner can manage its operations and create new intellectual property using the Partnership’s intellectual property. The general partner will assign to the Partnership the new intellectual property it creates in operating the Partnership’s business. The general partner has also licensed to the Partnership certain of its own intellectual property for use in the conduct of the Partnership’s business and the Partnership has licensed to the general partner certain intellectual property for use in the conduct of its business. The license agreement has also granted to the Partnership a license to use the trademarks, trade names, and service marks of Sunoco in the conduct of its business.
Treasury Services Agreement
The Partnership has a treasury services agreement with Sunoco pursuant to which, among other things, it is participating in Sunoco’s centralized cash management program. Under this program, all of the cash receipts and cash disbursements are processed, together with those of Sunoco and its other subsidiaries, through Sunoco’s cash accounts with a corresponding credit or charge to an intercompany account. The intercompany balance will be settled periodically, but no less frequently than monthly. Amounts due from Sunoco and its subsidiaries earn interest at a rate equal to the average rate of the Partnership’s third-party money market investments, while amounts due to Sunoco and its subsidiaries bear interest at a rate equal to the interest rate provided in the revolving credit facility (the “Credit Facility”).
Eagle Point Logistics Assets Purchase and Throughput Agreements
On March 30, 2004, the Partnership entered into a purchase agreement with Sunoco to acquire the Eagle Point refinery logistics assets for approximately $20 million. The purchase agreement requires Sunoco to reimburse the Partnership for certain maintenance capital and expense expenditures incurred regarding the assets acquired, as defined, up to $5.0 million within the first 10 years of the closing of the transaction. At December 31, 2006, the Partnership has received a cumulative reimbursement of $2.3 million relative to the $5.0 million maximum reimbursement.
In connection with the acquisition, the Partnership also entered into a throughput agreement with Sunoco under which the Partnership is charging Sunoco fees for services provided under this agreement that are comparable to those charged in arm’s length, third-party transactions to:
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receive or deliver all crude oil to and from the Eagle Point refinery, other than those received or shipped via rail car, tanker truck or pipeline for twelve years ending March 31, 2016. This throughput is an annual amount for the contract period from April 1 to March 31 for the term of the agreement. For the calendar year ended December 31, 2006, the Partnership received a fee of $0.0827 per barrel for the first
130,000 bpd of crude oil and $0.0413 per barrel for volumes in excess of 130,000 bpd. These fees escalate at the rate of 1.67 percent each January 1 for the term of the agreement;
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receive and deliver at least 41,800 bpd of refined and intermediate products per year at the Eagle Point dock for twelve years ending March 31, 2016. This throughput is an annual amount for the contract period from April 1 to March 31 for the term of the agreement. For the calendar year ended December 31, 2006, the Partnership received a fee of $0.0827 per barrel for the first 14,200 bpd of refined and intermediate products and $0.0413 per barrel for volume in excess of 14,200 bpd and also received a fee of $0.0724 per barrel for each shipment that required vapor combustion services. These fees escalate at the rate of 1.67 percent each January 1 for the term of the agreement; and
•
receive and deliver at least 32,000 bpd of refined and intermediate products per year at the Eagle Point Refined Products Terminal for twelve years ending March 31, 2016. This throughput is an annual amount for the contract period from April 1 to March 31 for the term of the agreement. For the year ended December 31, 2006, the Partnership received per barrel fees as set forth in the contract by refined and intermediate product shipped. These fees will escalate at the rate of 1.67 percent each January 1 for the term of the agreement. For the year ended December 31, 2006, the Partnership received $0.2 million from Sunoco for not meeting the minimum throughput amount in the contract year ended March 31, 2006. Sunoco has met the minimum throughput amount through December 31, 2006. Under the agreement, Sunoco will pay the Partnership any shortfall if it does not exceed the minimum throughput amount under the agreement for the contract year from April 1, 2006 through March 31, 2007.
Unit Redemptions and Equity Offering Cost-Sharing Agreements
In May and June 2005, the Partnership sold 2.775 million common units in a public offering for net proceeds of $99.2 million. The net proceeds were used to redeem 2.775 million common units owned by Sunoco. Also in connection with the equity offering, Sunoco reimbursed the Partnership for $0.4 million in transaction costs incurred by the Partnership. The reimbursement was accounted for in the third quarter of 2005 as an increase to Partners’ Capital within the Partnership’s consolidated balance sheet.
In April 2004, the Partnership sold 3.4 million common units in a public offering for net proceeds of $128.7 million. In connection with this common unit offering, the Partnership utilized a portion of the offering proceeds to redeem 2.2 million common units held by Sunoco at a price per unit equal to the public offering price per unit after the underwriters’ commissions, or an aggregate of $82.7 million. Sunoco reimbursed the Partnership for $0.4 million in transaction costs it incurred based upon the percentage that Sunoco’s net redemption proceeds received represented of the total gross proceeds of the Partnership’s offering (64.2 percent). The reimbursement was accounted for in the fourth quarter of 2004 as an increase to Partners’ Capital within the Partnership’s consolidated balance sheet.
Other Agreements
The Partnership has also entered into various other agreements with Sunoco and their affiliates, including throughput agreements regarding certain acquired assets or improvements or expansions at existing assets which are not covered within the pipelines and terminals storage and throughput agreement. Although these agreements did not result from arm’s-length negotiations, management of the Partnership believes the terms of these agreements to be comparable to those that could be negotiated with an unrelated third party.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Partnership is exposed to various market risks, including volatility in crude oil commodity prices and interest rates. To manage such exposure, inventory levels and expectations of future commodity prices and interest rates are monitored when making decisions with respect to risk management. The Partnership has not entered into derivative transactions that would expose it to price risk.
The $300 million Credit Facility, with outstanding borrowings at December 31, 2006 of $68.0 million, exposes the Partnership to interest rate risk, since it bears interest at a variable rate (5.7 percent at December 31, 2006). A one percent change in interest rates changes annual interest expense by approximately $0.7 million.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
MANAGEMENT’S REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING
Management of Sunoco Logistics Partners L.P. (the “Partnership”) is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. The Partnership’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles.
The Partnership’s management assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2006. In making this assessment, the Partnership’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control-Integrated Framework.
Based on this assessment, management believes that, as of December 31, 2006, the Partnership’s internal control over financial reporting is effective based on those criteria. Ernst & Young LLP, an independent registered public accounting firm, has issued an attestation report on management’s assessment of the Partnership’s internal control over financial reporting, which appears in this section.
Deborah M. Fretz
President, Chief Executive Officer and Principal Financial Officer
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
ON INTERNAL CONTROL OVER FINANCIAL REPORTING
To the Board of Directors of
Sunoco Partners LLC:
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that Sunoco Logistics Partners L.P. (the “Partnership”) maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Partnership’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that the Partnership maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2006 financial statements of the Partnership and our report dated February 23, 2007 expressed an unqualified opinion thereon.
ERNST & YOUNG LLP
Philadelphia, Pennsylvania
February 23, 2007
REPORT OF INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM ON FINANCIAL STATEMENTS
To the Board of Directors of
Sunoco Partners LLC:
We have audited the accompanying balance sheets of Sunoco Logistics Partners L.P. (the “Partnership”) as of December 31, 2005 and 2006 and the related statements of income, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2006. 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 the standards of the Public Company Accounting Oversight Board (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 financial position of Sunoco Logistics Partners L.P. at December 31, 2005 and 2006 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2007 expressed an unqualified opinion thereon.
ERNST & YOUNG LLP
Philadelphia, Pennsylvania
February 23, 2007
SUNOCO LOGISTICS PARTNERS L.P.
STATEMENTS OF INCOME
(in thousands, except units and per unit amounts)
(See Accompanying Notes)
SUNOCO LOGISTICS PARTNERS L.P.
BALANCE SHEETS
(in thousands)
(See Accompanying Notes)
SUNOCO LOGISTICS PARTNERS L.P.
STATEMENTS OF CASH FLOWS
(in thousands)
(See Accompanying Notes)
SUNOCO LOGISTICS PARTNERS L.P.
STATEMENTS OF PARTNERS’ CAPITAL
(in thousands)
(See Accompanying Notes)
SUNOCO LOGISTICS PARTNERS L.P.
NOTES TO FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Principles of Consolidation
Sunoco Logistics Partners L.P. (the “Partnership”) is a Delaware limited partnership formed by Sunoco, Inc. (“Sunoco”) in October 2001 to acquire, own and operate a substantial portion of Sunoco’s logistics business, consisting of refined product pipelines, terminalling and storage assets, crude oil pipelines, and crude oil acquisition and marketing assets located in the Northeast, Midwest and South Central United States. Sunoco, Inc and its wholly-owned subsidiaries including Sunoco, Inc. (R&M) are collectively referred to as “Sunoco”. The financial statements of the Partnership contain the accounts of the Partnership and its subsidiaries. Equity ownership interests in corporate joint ventures, which are not consolidated, are accounted for under the equity method.
Use of Estimates
The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual amounts could differ from these estimates.
Revenue Recognition
Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil gathering and marketing revenues are recognized when title to the crude oil is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to the Partnership’s end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of income based upon the concepts set forth in APB Opinion No. 29, “Accounting for Nonmonetary Transactions.” In September 2005, the Emerging Issues Task Force (the “EITF”) completed its deliberations on the accounting for exchange transactions in Issue 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty”. The consensus reached in EITF 04-13 supports the Partnership’s accounting treatment of its exchange transactions.
Affiliated revenues consist of sales of crude oil as well as the provision of crude oil and refined product pipeline transportation, terminalling and storage services to Sunoco. Sales of crude oil to affiliates are priced using market based rates. In 2002, the Partnership entered into a pipelines and terminals storage and throughput agreement with Sunoco under which the Partnership is charging Sunoco fees for services provided under these agreements comparable to those charged in arm’s-length, third-party transactions. Under the pipelines and terminals storage and throughput agreement, Sunoco has agreed to pay the Partnership a minimum level of revenue for transporting and terminalling refined products. Sunoco also has agreed to minimum throughputs of refined products and crude oil in the Partnership’s Inkster Terminal, Fort Mifflin Terminal Complex, Marcus Hook Tank Farm and certain crude oil pipelines. In 2004, in connection with the Partnership’s acquisition of the Eagle Point logistics assets, Sunoco also agreed to minimum throughputs of refined products at the Eagle Point truck rack (see Note 3).
Cash Equivalents
The Partnership considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. These cash equivalents consist principally of money market accounts.
SUNOCO LOGISTICS PARTNERS L.P.
NOTES TO FINANCIAL STATEMENTS-(Continued)
Accounts Receivable, net
Accounts receivable represent valid claims against non-affiliated customers (see Note 3 for affiliated receivables) for products sold or services rendered. The Partnership extends credit terms to certain customers after review of various credit indicators, including the customer’s credit rating. Outstanding customer receivable balances are regularly reviewed for possible non-payment indicators and reserves are recorded for doubtful accounts based upon management’s estimate of collectibility at the time of review. Actual balances are charged against the reserve when all collection efforts have been exhausted. The following table provides the activity in the allowance for doubtful accounts for the three-year period ended December 31, 2006:
Inventories
Inventories are valued at the lower of cost or market. Crude oil inventory cost has been determined using the last-in, first-out method (“LIFO”). Under this methodology, the cost of products sold consists of the actual crude oil acquisition costs of the Partnership. Such costs are adjusted to reflect increases or decreases in crude oil inventory quantities, which are valued based on the changes in the LIFO inventory layers. The cost of materials, supplies and other inventories is principally determined using the average cost method.
Properties, Plants and Equipment
Properties, plants and equipment are stated at cost. Additions to properties, plants and equipment, including replacements and improvements, are recorded at cost. Repair and maintenance expenditures are charged to expense as incurred. Depreciation is provided principally using the straight-line method based on the estimated useful lives of the related assets. For certain interstate pipelines, the depreciation rate is applied to the net asset value based on FERC requirements. When FERC-regulated properties, plants and equipment are retired or otherwise disposed of, the cost less net proceeds is charged to accumulated depreciation and amortization, except that gains and losses for unusual disposals for those groups are reflected in other income in the statements of income. Gains and losses on the disposal of non-FERC properties, plants and equipment are reflected in other income in the statements of income.
During 2004, 2005 and 2006, the Partnership accelerated the depreciation of assets related to equipment upgrade programs and the Western area office move from Tulsa, Oklahoma to Sugar Land, Texas, based upon the estimated remaining useful lives of these assets until their replacement. The acceleration resulted in $1.8 million of additional depreciation expense in both 2004 and 2005 and $0.5 million of additional depreciation expense recognized in 2006.
Capitalized Interest
The Partnership capitalizes interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. During the years ended December 31, 2005 and 2006, the amount of interest capitalized was $0.5 million and $3.0 million, respectively. There were no amounts capitalized in 2004. The weighted average rate used to capitalize interest on borrowed funds was 6.5 percent for 2005 and 6.6 percent for 2006.
SUNOCO LOGISTICS PARTNERS L.P.
NOTES TO FINANCIAL STATEMENTS-(Continued)
Impairment of Long-Lived Assets
Long-lived assets other than those held for sale are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. An asset is considered to be impaired when the undiscounted estimated net cash flows expected to be generated by the asset are less than its carrying amount. The impairment recognized is the amount by which the carrying amount exceeds the estimated fair value of the impaired asset. Long-lived assets held for sale are recorded at the lower of their carrying amount or estimated fair value less cost to sell the assets.
Goodwill and Other Intangible Assets
Goodwill, which represents the excess of the purchase price over fair value of net assets acquired, is presented net of accumulated amortization within deferred charges and other assets on the balance sheets. At December 31, 2005 and 2006, the Partnership had $16.2 million of goodwill and accumulated amortization of $1.3 million related to goodwill. In accordance with Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets,” goodwill and indefinite-lived intangible assets are tested for impairment at least annually. The Partnership determined during 2004, 2005 and 2006 that such assets were not impaired.
Deferred financing fees of $2.4 million, net of accumulated amortization of $1.2 million, as of December 31, 2005, and $2.0 million, net of accumulated amortization of $1.6 million, as of December 31, 2006, have been included within deferred charges and other assets on the balance sheets. The Partnership deferred total fees of $0.2 million paid in 2005 related to the renewal and amendment of the Credit Facility during those periods. Amortization expense of $0.7 million, $0.4 million and $0.4 million for the years ended December 31, 2004, 2005 and 2006, respectively, has been included within other interest cost and debt expense on the statements of income. The Partnership amortizes deferred financing fees over the life of the respective debt agreement.
Investment in Affiliates
Investments in affiliates, which consist of corporate joint ventures, are accounted for under the equity method of accounting as required by Accounting Principles Board Opinion 18, “The Equity Method of Accounting for Investments in Common Stock” (“APB 18”). Under this method, an investment is carried at acquisition cost, increased for the equity in income or decreased for the equity in loss from the date of acquisition, and reduced for dividends received. The Partnership had $2.6 million of undistributed earnings from its investments in corporate joint ventures within Partners’ Capital on its December 31, 2006 balance sheet. During the years ended December 31, 2004, 2005 and 2006 the Partnership received dividends of $13.3 million, $13.2 million and $15.9 million respectively, from its investments in corporate joint ventures.
The Partnership allocates its excess investment cost over its equity in the net assets of affiliates to the underlying tangible and intangible assets of the corporate joint ventures. Other than land and indefinite-lived intangible assets, all amounts allocated, principally to pipeline and related assets, are amortized using the straight-line method over their estimated useful life of 40 years. The amortization of these amounts is included within depreciation and amortization in the statements of income.
Environmental Remediation
The Partnership accrues environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions,
SUNOCO LOGISTICS PARTNERS L.P.
NOTES TO FINANCIAL STATEMENTS-(Continued)
existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point or points in the range are more likely, in which case the most likely amount in this range is accrued.
Income Taxes
No provision for U.S. federal income taxes is included in the accompanying financial statements, because as a partnership we are not subject to federal and generally not subject to state income tax. The tax effect of our activities accrues to the unitholders. There are some states where the Partnership operates where we are subject to certain state and local income taxes.
In July 2006, FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an Interpretation of SFAS 109, Accounting for Income Taxes (“FIN 48”) was issued. This interpretation clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with Statement of Financial Accounting Standards No. 109 “Accounting for Income Taxes,” by prescribing the minimum recognition threshold and measurement attributed a tax position taken or expected to be taken on a tax return is required to meet before being recognized in the financial statements. The Partnership expects the adoption of FIN 48 on its state and local income tax provisions to be immaterial.
Long-Term Incentive Plan
In December 2004, Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (“SFAS No. 123R”) was issued, which revised Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”). Effective January 1, 2006, the Partnership adopted Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (“SFAS No. 123R”), using the modified-prospective method. Among other things, SFAS No. 123R requires a fair-value-based method of accounting for share-based payment transactions. SFAS No. 123R also requires the use of a non-substantive vesting period approach for new share-based payment transactions that vest when an employee becomes retirement eligible as is the case under the Partnership’s Long-Term Incentive Plan (i.e., the vesting period cannot exceed the date an employee becomes retirement eligible). The effect will be to accelerate expense recognition for units awarded to retirement-eligible participants compared to the vesting period approach the Partnership currently uses, which reflects the stated vesting period. As a result of adopting Statement 123(R) on January 1, 2006, the Partnership’s net income is $0.8 million lower for the year ended December 31, 2006, than if it had continued to account for share-based compensation under SFAS No. 123. Basic and diluted earnings per unit are each $0.1 and $0.2, respectively, lower for the year ended December 31, 2006 than if the Partnership had continued to account for share-based compensation under SFAS No. 123. The future impact of the non-substantive vesting period will be dependent upon the value of future stock-based awards granted to employees who are eligible to retire prior to the normal vesting periods of the awards.
Asset Retirement Obligations
In March 2005, the Financial Accounting Standards Board issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FASB Interpretation No. 47”). FASB Interpretation No. 47 clarifies that the term “conditional asset retirement obligation” as used in Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. FASB Interpretation No. 47 provides that a liability for the
SUNOCO LOGISTICS PARTNERS L.P.
NOTES TO FINANCIAL STATEMENTS-(Continued)
fair value of a conditional asset retirement obligation should be recognized if that fair value can be reasonably estimated. FASB Interpretation No. 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. In conjunction with the implementation of FASB Interpretation No. 47 in 2005, the Partnership recorded an increase in the liability for asset retirement obligations of $20.6 million (included as a component of other deferred credits and liabilities on the balance sheet) and additional properties, plants and equipment of $20.6 million, primarily attributed to pipelines and crude oil and refined product storage tanks at the Partnership’s facilities. This amount approximates the amount that would have been included in the balance sheets at the beginning of 2004 and as of December 31, 2004 if FASB Interpretation No. 47 had been applied to that period. During 2006, the Partnership increased the liability for asset retirement obligations and properties, plant and equipment by $1.1 million related to the obligations associated with two crude oil pipelines acquired in March 2006. This change did not have a significant impact on the Partnership’s statement of income for the years ended December 31, 2005 and 2006. The Partnership believes it may have additional asset retirement obligations related to its pipeline assets and storage tanks, for which it is not possible to estimate when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time.
Lease Accounting
The Partnership applies the provisions of Emerging Issues Task Force Issue 01-8, “Determining Whether an Arrangement Contains a Lease” (“EITF 01-8”). EITF 01-8 provides guidance in determining whether an arrangement meets the definition of a lease under the provisions of Statement of Financial Accounting Standards No. 13, “Accounting for Leases” (“SFAS No. 13”). SFAS No. 13 defines a lease as an agreement conveying the right to use property, plant or equipment for a stated period of time. EITF 01-8 provides criteria to determine whether an arrangement conveys the right to use property, plant and equipment under SFAS No. 13. The accounting requirements under EITF 01-8 could affect an arrangement’s timing of revenue and expense recognition, and revenues previously reported as transportation and storage services might have to be reported as rental or leasing income. However, the timing of the cash receipts associated with these agreements would not be impacted by the accounting requirements under EITF 01-8. The provisions of EITF 01-8 are to be applied prospectively to arrangements agreed to, modified, or acquired in business combinations after July 1, 2003. During 2004, 2005 and 2006 previous arrangements that would be leases or would contain a lease according to this pronouncement were recorded in accordance with their prior accounting treatment. The Partnership is continually analyzing its agreements that were in existence prior to July 1, 2003 to determine if the accounting for these agreements would be impacted upon renewal or amendment. The provisions of EITF 01-8 had no impact on the Partnership’s financial statements for the years ended December 31, 2004, 2005 and 2006.
Hurricane Rita Losses
On September 24, 2005, Hurricane Rita damaged the Partnership’s Nederland Terminal facility and a portion of the Western Pipeline System, impacting several storage tanks, dock facilities, buildings and equipment. Although the Nederland Terminal resumed operations on October 3, 2005, the business was impacted for a few weeks as a result of interruptions in customer and supplier business activities related to the Hurricane. The additional costs in 2005 and 2006 attributed to the Hurricane totaled approximately $6.2 million. The Partnership expects to incur additional costs of approximately $2.1 million in 2007 to repair its damaged facilities and expects to negotiate a settlement with its insurance carrier for reimbursement of a portion of its costs during 2007.
2. Equity Offerings
In April 2004, the Partnership sold 3.4 million common units in a public offering for total gross proceeds of $135.1 million. The units were issued under the Partnership’s previously filed Form S-3 shelf registration
SUNOCO LOGISTICS PARTNERS L.P.
NOTES TO FINANCIAL STATEMENTS-(Continued)
statement. The sale of the units resulted in net proceeds of $128.7 million, after underwriters’ commissions and legal, accounting, and other transaction expenses. Net proceeds from the sale were used to (a) redeem approximately 2.2 million common units from Sunoco for $82.7 million, (b) replenish cash utilized to acquire the Eagle Point logistics assets for $20.0 million, (c) finance the acquisition of two refined product terminals for $12.0 million, (d) finance the acquisition of an additional 33.3 percent undivided interest in the Harbor pipeline for $7.3 million, and (e) for general partnership purposes, including to replenish cash used for past acquisitions and capital improvements, and for other expansion, capital improvements or acquisition projects. As a result of this net issuance of 1.2 million common units, the general partner contributed $1.0 million to the Partnership to maintain its 2.0 percent general partner interest.
In May 2005, the Partnership sold 2.5 million common units in a public offering. In June 2005, the Partnership sold an additional 275,000 common units to cover over-allotments in connection with the May 2005 sale. The purchase price for the over-allotment was equal to the offering price in the May 2005 sale. The units were issued under the Partnership’s previously filed Form S-3 shelf registration statement. The sale of units resulted in total gross proceeds of $104.1 million, and net proceeds of $99.2 million, after underwriters’ commissions and legal, accounting and other transaction expenses. Net proceeds from the sale were used to redeem 2.775 million common units owned by Sunoco. The redemption price per unit was equal to the public offering price per unit after the underwriters’ commissions.
In August 2005, the Partnership sold 1.5 million common units in a public offering. In September 2005, the Partnership sold an additional 125,000 common units to cover over-allotments in connection with the August 2005 sale. The purchase price for the over allotment was equal to the offering price in the August 2005 sale. The units were issued under the Partnership’s previously filed Form S-3 shelf registration statement. The total sale of units resulted in total gross proceeds of $63.4 million, and net proceeds of $60.4 million, after the underwriters’ commission and legal, accounting and other transaction expenses. Net proceeds of the sale were used to repay $56.5 million of the debt incurred to finance the August 1, 2005 purchase of a Texas crude oil pipeline system and storage facilities with the balance for general partnership purposes. As a result of this issuance of 1.625 million common units, the general partner contributed $1.3 million to the Partnership to maintain its 2.0 percent general partner interest.
In May 2006, the Partnership sold 2.4 million common units in a public offering. In June 2006, the Partnership sold an additional 280,000 common units to cover over-allotments in connection with the May 2006 sale. The purchase price for the over allotment was equal to the offering price in the May 2006 sale. The total sale of units resulted in gross proceeds of $115.2 million, and net proceeds of $110.3 million, after the underwriters’ commission and legal, accounting and other transaction expenses. Net proceeds of the offering, together with the $173.3 million in net proceeds from the concurrent offering of Senior Notes (see Note 9), were used to repay $216.1 million of the debt incurred under the revolving credit facility, to fund the Partnership’s 2006 organic growth program, and for general partnership purposes. Also as a result of the issuance of these units, the general partner contributed $2.4 million to the Partnership to maintain its 2.0 percent general partner interest. At December 31, 2006, Sunoco’s ownership in the Partnership, including its 2.0 percent general partner interest, was 43.4 percent.
3. Related Party Transactions
Advances to/from Affiliate
The Partnership has a treasury services agreement with Sunoco pursuant to which it, among other things, participates in Sunoco’s centralized cash management program. Under this program, all of the Partnership’s cash receipts and cash disbursements are processed, together with those of Sunoco and its other subsidiaries, through
SUNOCO LOGISTICS PARTNERS L.P.
NOTES TO FINANCIAL STATEMENTS-(Continued)
Sunoco’s cash accounts with a corresponding credit or charge to an intercompany account. The intercompany balances are settled periodically, but no less frequently than monthly. Amounts due from Sunoco earn interest at a rate equal to the average rate of the Partnership’s third-party money market investments, while amounts due to Sunoco bear interest at a rate equal to the interest rate provided in the Partnership’s revolving credit facility (see Note 9).
Administrative Services
Under the Omnibus Agreement, the Partnership pays Sunoco or the general partner an annual administrative fee that includes expenses incurred by Sunoco and its affiliates to perform centralized corporate functions, such as legal, accounting, treasury, engineering, information technology, insurance, and other corporate services, including the administration of employee benefit plans. This fee was $8.4 million, $8.4 million and $7.7 million for the years ended December 31, 2004, 2005, and 2006 respectively. This fee does not include the costs of shared insurance programs (which are allocated to the Partnership based upon its share of the cash premiums incurred), the salaries of pipeline and terminal personnel or other employees of the general partner (including senior executives), or the cost of their employee benefits. The Partnership has no employees, and reimburses Sunoco and its affiliates for these costs and other direct expenses incurred on the Partnership’s behalf. In addition, the Partnership has incurred additional general and administrative costs which it pays directly.
The initial term of Section 4.1 of the Omnibus Agreement (which concerns the Partnership’s obligation to pay the annual fee for provision of certain general and administrative services) was through the end of 2004. The parties extended the term of Section 4.1 by one year each in January 2005, January 2006 and January 2007. The 2007 annual fee will decrease to $6.5 million, which reflects the Partnership directly incurring some of these general and administrative costs. These costs may be increased if the acquisition or construction of new assets or businesses require an increase in the level of general and administrative services received by the Partnership. There can be no assurance that Section 4.1 of the Omnibus Agreement will be extended beyond 2007, or that, if extended, the administrative fee charged by Sunoco will be at or below the current administrative fee. In the event that the Partnership is unable to obtain such services from Sunoco or other third parties at or below the current cost, the Partnership’s financial condition and results of operations may be adversely impacted.
In addition to the fees for the centralized corporate functions, selling, general and administrative expenses in the statements of income include the allocation of shared insurance costs of $2.5 million, $5.1 million and $3.2 million for the years ended December 31, 2004 2005 and 2006 respectively. The insurance costs for the year ended December 31, 2005 include $2.5 million resulting from two special assessments by one of the Partnership’s insurers as a result of Hurricanes Rita and Katrina. The Partnership’s share of allocated Sunoco employee benefit plan expenses, including non-contributory defined benefit retirement plans, defined contribution 401(k) plans, employee and retiree medical, dental and life insurance plans, incentive compensation plans and other such benefits was $21.0 million, $21.5 million and $22.5 million for the years ended December 31, 2004, 2005 and 2006 respectively. These expenses are reflected in cost of products sold and operating expenses and selling, general and administrative expenses in the statements of income.
Affiliated Revenues and Accounts Receivable, Affiliated Companies
Affiliated revenues in the statements of income consist of sales of crude oil as well as the provision of crude oil and refined product pipeline transportation, terminalling and storage services to Sunoco. Sales of crude oil are priced using market based rates. Pipeline revenues are generally determined using posted tariffs. In 2002, the Partnership entered into a pipelines and terminals storage and throughput agreement and various other agreements with Sunoco under which the Partnership is charging Sunoco fees for services provided under these agreements that, in management’s opinion, are comparable to those charged in arm’s-length, third-party
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transactions. Under the pipelines and terminals storage and throughput agreement, Sunoco has agreed to pay the Partnership a minimum level of revenues for transporting and terminalling refined products. Sunoco also has agreed to minimum throughputs of refined products and crude oil in the Partnership’s Inkster Terminal, Fort Mifflin Terminal Complex, Marcus Hook Tank Farm and certain crude oil pipelines. Under various other agreements entered into in 2002, Sunoco is, among other things, purchasing from the Partnership, at market-based rates, particular grades of crude oil that the Partnership’s crude oil acquisition and marketing business purchases for delivery to certain pipelines. These agreements automatically renew on a monthly basis unless terminated by either party on 30 days’ written notice. During the years ended December 31, 2005 and 2006 two of these agreements were terminated by Sunoco, however the cancellations have not had a material impact on the Partnership’s results of operations. Sunoco also leases the Partnership’s 58 miles of interrefinery pipelines between Sunoco’s Philadelphia and Marcus Hook refineries for a term of 20 years.
Capital Contributions
The Omnibus Agreement requires Sunoco to: reimburse the Partnership for any operating expenses and capital expenditures in excess of $8.0 million per year in each calendar year through 2006 that are made to comply with the U.S. Department of Transportation’s (“DOT”) pipeline integrity management rule, subject to a maximum aggregate reimbursement of $15.0 million over the five-year period ending December 31, 2006; complete, at its expense, certain tank maintenance and inspection projects at the Darby Creek Tank Farm; and reimburse the Partnership for up to $10.0 million of expenditures required at the Marcus Hook Tank Farm and the Darby Creek Tank Farm to maintain compliance with existing industry standards and regulatory requirements.
For the years ended December 31, 2004, 2005 and 2006, the Partnership was reimbursed $2.1 million, $7.0 million and $3.3 million, respectively, by Sunoco for maintenance capital expenditures and operating expenses incurred in excess of $8.0 million to comply with DOT’s pipeline integrity management rule. At December 31, 2006, the Partnership has received a cumulative reimbursement equal to the $15.0 million maximum aggregate reimbursement over the five-year period for compliance expenditures relative to the DOT’s pipeline integrity management rule. As a result, the Partnership does not expect to be reimbursed by Sunoco going forward for expenditures related to integrity management.
For the years ended December 31, 2004, 2005 and 2006 the Partnership was reimbursed by Sunoco for expenditures at the Marcus Hook Tank Farm and the Darby Creek Tank Farm to maintain compliance with existing industry standards and regulatory requirements. These expenditures, which were recorded as maintenance capital and operating expenses, were as follows:
At December 31, 2006, the Partnership has received a cumulative reimbursement equal to the $10.0 million maximum reimbursement for compliance expenditures at the Marcus Hook Tank Farm and the Darby Creek Tank Farm. As a result, the Partnership does not expect to be reimbursed by Sunoco going forward for expenditures related to the Marcus Hook Tank Farm and the Darby Creek Tank Farm.
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The aggregate amounts reimbursed related to these provisions of the Omnibus Agreement of $6.8 million, $7.9 million and $3.4 million for the years ended December 31, 2004, 2005 and 2006, respectively, by Sunoco related to these projects were recorded as capital contributions to Partners’ Capital within the Partnership’s balance sheets.
Under the terms of the Interrefinery Lease Agreement, Sunoco is required to reimburse the Partnership for any non-routine maintenance expenditures, as defined, incurred during the term of the agreement. The Eagle Point purchase agreement requires Sunoco to reimburse the Partnership for certain maintenance capital and expense expenditures incurred regarding the assets acquired, as defined, up to $5.0 million within the first 10 years of closing of the transaction. For the years ended December 31, 2004 and 2005 the Partnership incurred maintenance capital expenditures of $0.2 million, $0.1 million, respectively, under the provisions within these agreements and was reimbursed by Sunoco. The reimbursements were recorded as capital contributions to Partners’ Capital within the Partnership’s balance sheet.
In August 2005, the Partnership sold 1.5 million common units in a public offering. In September 2005, the Partnership sold an additional 125,000 common units to cover over-allotments in connection with the August 2005 sale. As a result of this issuance of 1.625 million common units, the general partner contributed $1.3 million to the Partnership to maintain its 2.0 percent general partner interest. The Partnership recorded this amount as a capital contribution to Partners’ Capital within its consolidated balance sheet.
In February 2006 and 2005, the Partnership issued 0.1 million and 0.2 million common units, respectively, to participants in the Sunoco Partners LLC Long-Term Incentive Plan (“LTIP”) upon completion of award vesting requirements. As a result of these issuances of common units, the general partner contributed $0.1 million in each period to the Partnership to maintain its 2.0 percent general partner interest. The Partnership recorded these amounts as capital contributions to Partners’ Capital within its consolidated balance sheets.
In May 2006, the Partnership sold 2.4 million common units in a public offering. In June 2006, the Partnership sold an additional 280,000 common units to cover over-allotments in connection with the May 2006 sale (see Note 2). As a result of this issuance of 2.68 million common units, the general partner contributed $2.4 million to the Partnership to maintain its 2.0 percent general partner interest. The Partnership recorded this amount as a capital contribution to Partners’ Capital within its consolidated balance sheet.
Asset Acquisitions
On August 18, 2006, the Partnership purchased from Sunoco a 100 percent interest in Sun Pipe Line Company of Delaware LLC, the owner of a 55.3 percent equity interest (50 percent voting rights) in Mid-Valley Pipeline Company (“Mid-Valley”) for approximately $65 million, subject to certain adjustments five years following the date of closing, based on throughput of Sunoco (see Note 4). Since the acquisition was from a related party, the interest in the entity was recorded by the Partnership at Sunoco’s historical cost of approximately $12.5 million, and the $52.5 million difference between the purchase price and the cost basis of the assets was recorded by the Partnership as a capital distribution.
On December 5, 2005, the Partnership acquired a subsidiary of Sunoco which owned a 7.2 percent undivided interest in the Mesa Pipe Line system for approximately $1.3 million (see Note 4). Since the acquisition was from a related party, the interest in the entity was recorded by the Partnership at Sunoco’s historical cost of approximately $0.2 million, and the $1.1 million difference between the purchase price and the cost basis of the assets was recorded by the Partnership as a capital distribution.
On March 30, 2004, the Partnership acquired the Eagle Point refinery logistics assets from Sunoco for approximately $20 million (see Note 4).
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Redemption of Common Units
In May and June 2005, the Partnership sold a total of 2.775 million common units in a public offering (see Note 2). Net proceeds from the sale were used to redeem 2.775 million common units owned by Sunoco for $99.6 million. Also in connection with the equity offering, Sunoco agreed to reimburse the Partnership for transaction costs incurred by the Partnership. Reimbursement of these costs of $0.4 million occurred during the third quarter of 2005 when the transaction costs were finalized and was accounted for as an increase to Partners’ Capital within the Partnership’s balance sheet.
4. Acquisitions
On August 18, 2006, the Partnership purchased from Sunoco a 100 percent interest in Sun Pipe Line Company of Delaware LLC, the owner of a 55.3 percent equity interest (50 percent voting interest) in Mid-Valley Pipeline Company (“Mid-Valley”) for approximately $65 million, subject to certain adjustments five years following the date of closing, based on the throughput of Sunoco. Mid-Valley owns a 994-mile pipeline, which originates in Longview, Texas and terminates in Samaria, Michigan, and has operating capacity of approximately 238,000 bpd and 4.2 million shell barrels of storage capacity. Mid-Valley provides crude oil to a number of refineries, primarily in the Midwest United States. The Partnership will continue to be the operator of the Mid-Valley pipeline. The Partnership receives a quarterly cash dividend from Mid-Valley that is proportionate with its ownership interest. The purchase price of the acquisition was initially funded with $46.0 million in borrowings under the Partnership’s Credit Facility and with cash on hand, and has been included in the Western Pipeline System business segment. Since the acquisition was from a related party, the interest in the entity was recorded by the Partnership at Sunoco’s historical cost of approximately $12.5 million and the $52.5 million difference between the purchase price and the cost basis of the assets was recorded by the Partnership as a capital distribution. The results of the acquisition are included in the financial statements from the date of acquisition.
On March 1, 2006, the Partnership purchased a Texas crude oil pipeline system from affiliates of Black Hills Energy, Inc. for approximately $40.9 million. The system consists of (a) the Millennium Pipeline, a 200-mile, 12-inch crude oil pipeline with approximately 65,000 bpd operating capacity, originating near the Partnership’s Nederland Terminal, and terminating at Longview Texas; (b) the Kilgore Pipeline, a 190-mile, 10-inch crude oil pipeline with approximately 35,000 barrel per day capacity originating in Kilgore, Texas and terminating at refineries in the Houston, Texas region; (c) approximately 900,000 shell barrels of active storage capacity at Kilgore, and Longview, Texas, approximately 550,000 of which are inactive; (d) a crude oil sales and marketing business; and (e) crude oil line fill and working inventory. The purchase price of the acquisition was initially funded with borrowings under the Partnership’s Credit Facility, and has been included in the Western Pipeline System business segment. The purchase price has been preliminarily allocated to the assets acquired based on their relative fair values at the acquisition date. The following is a summary of the effects of the transaction on the Partnership’s consolidated financial position (in thousands of dollars):
The results of the acquisition are included in the financial statements from the date of acquisition.
On March 1, 2006, the Partnership acquired a Texas crude oil pipeline system from Alon USA Energy, Inc. for approximately $68.0 million. The system consists of (a) the Amdel Pipeline, a 503-mile, 10-inch common
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carrier crude oil pipeline with approximately 27,000 bpd operating capacity, originating at the Nederland Terminal, and terminating at Midland, Texas, and (b) the White Oil Pipeline, a 25-mile, 10-inch crude oil pipeline with approximately 40,000 bpd operating capacity, originating at the Amdel Pipeline and terminating at Alon’s Big Spring, Texas refinery. Alon has also agreed to ship a minimum of 15,000 bpd on the pipelines under a 10-year, throughput and deficiency agreement. The pipelines were idle at the time of purchase, were re-commissioned by the Partnership during the second quarter 2006 and began making deliveries during the fourth quarter 2006. The Partnership also began construction to expand capacity on the Amdel Pipeline from approximately 27,000 to 40,000 bpd, which it expects to be completed by the first quarter of 2007, and to construct new tankage at the Nederland Terminal to service these new volumes more efficiently. The purchase price of the acquisition was initially funded with borrowings under the Partnership’s Credit Facility, and has been preliminarily allocated to property, plants and equipment based on the relative fair value of the assets acquired on the acquisition date within the Western Pipeline System business segment. The results of the acquisition are included in the financial statements from the date of acquisition.
On December 5, 2005, the Partnership purchased a subsidiary of Sunoco that owned a 7.2 percent undivided interest in the Mesa Pipe Line system for approximately $1.3 million. The Mesa Pipe Line system consists of an 80-mile, 24-inch crude oil pipeline from Midland, Texas to Colorado City, Texas, with an operating capacity of 316,000 bpd, and approximately 800,000 shell barrels of tankage at Midland. Mesa Pipeline connects to West Texas Gulf’s pipeline, which supplies crude oil to Mid-Valley. On December 29, 2005, the Partnership purchased an additional 29.8 interest in the Mesa Pipe Line system from Chevron for approximately $5.3 million. The purchase prices of the acquisitions were funded with $6.6 million of net borrowings under the Partnership’s Credit Facility, and were allocated on a preliminary basis to property, plant and equipment within the Western Pipeline System business segment.
On August 1, 2005, the Partnership purchased, from an affiliate of Exxon Mobil Corporation, a crude oil pipeline system and storage facilities located in Texas for approximately $100.0 million. The pipeline system consists primarily of a 187-mile, 16-inch pipeline with an operating capacity of 125,000 bpd. It originates at a crude oil terminal in Corsicana, Texas and terminates at Wichita Falls, Texas. The storage facilities include the Corsicana terminal, which has 2.9 million shell barrels of storage capacity for crude oil, and the Ringgold, Texas terminal, which consists of 0.5 million shell barrels of storage capacity for crude oil. In addition, the Partnership invested approximately $16.0 million to construct a new 20-mile pipeline to connect the Corsicana to Wichita Falls pipeline to the West Texas Gulf pipeline, in which the Partnership has a 43.8% ownership interest. The Partnership funded the purchase price of the Corsicana to Wichita Falls pipeline and storage facilities with a $75.0 million borrowing under the Credit Facility and $25.0 million of cash. The Partnership repaid $56.5 million of the additional indebtedness with proceeds from the August 2005 units offering (see Note 2), reducing the net borrowings used to fund the acquisition to $18.5 million. The pipeline construction and the acquisition of the related right-of-way were also funded with borrowings under the Partnership’s Credit Facility. The purchase price was allocated to property, plant and equipment within the Western Pipeline System business segment.
On November 30, 2004, the Partnership acquired a refined products terminal located in Columbus, Ohio for approximately $8.0 million. The terminal is connected to a third-party, refined product, common carrier pipeline and includes 6 refined product tanks with approximately 160,000 shell barrels of working storage capacity. The purchase price was funded through cash on hand, and was allocated to property, plant and equipment within the Terminal Facilities business segment.
On June 28, 2004, the Partnership purchased an additional 33.3 percent undivided interest in the Harbor pipeline for approximately $7.3 million. The Harbor pipeline is an 80-mile, 180,000 bpd refined product, common carrier pipeline originating near Woodbury, New Jersey and terminating in Linden, New Jersey. As a result of this transaction, the Partnership increased its ownership to 66.7 percent and will continue to be the
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operator of the pipeline. The purchase price was funded through the proceeds of the April 7, 2004 sale of common units (see Note 2). The purchase price was allocated to property, plant and equipment within the Eastern Pipeline System business segment.
On April 28, 2004, the Partnership purchased two refined product terminals located in Baltimore, Maryland and Manassas, Virginia for approximately $12.0 million. The Baltimore terminal is connected to a third-party, refined product, common carrier pipeline and includes 13 refined product tanks with approximately 646,000 shell barrels of working storage capacity. The Manassas terminal is connected to a third-party, refined product, common carrier pipeline and includes 7 refined product tanks with approximately 277,000 shell barrels of working storage capacity. The purchase price was funded through the proceeds of the April 7, 2004 sale of common units (see Note 2). The purchase price was allocated to property, plant and equipment within the Terminal Facilities business segment.
On March 30, 2004, the Partnership acquired the Eagle Point refinery logistics assets from Sunoco for approximately $20.0 million. The Eagle Point logistics assets consist of crude and refined product ship and barge docks, a refined product truck rack, and a 4.5-mile, refined product pipeline from the Eagle Point refinery to the origin of the Harbor pipeline. In connection with the acquisition, the Partnership entered into a throughput agreement with Sunoco whereby they have agreed to maintain minimum volumes on the truck rack upon completion of certain capital improvements which were completed during the fourth quarter of 2004. The purchase price was funded initially through cash on hand. A portion of the proceeds of the April 7, 2004 sale of common units was subsequently utilized to replenish cash used to fund this acquisition (see Note 2). The purchase price was allocated to property, plant and equipment. The ship and barge docks and the truck rack have been included within the Terminal Facilities business segment, while the pipeline has been included within the Eastern Pipeline System.
5. Net Income Per Unit Data
Basic and diluted net income per limited partner unit is calculated by dividing net income, after deducting the amount allocated to the general partner’s interest, by the weighted-average number of limited partner common and subordinated units outstanding during the period.
The general partner’s interest in net income consists of its 2.0 percent general partner interest and “incentive distributions”, which are increasing percentages, up to 50 percent of quarterly distributions in excess of $0.50 per limited partner unit (see Note 12). The general partner was allocated net income of $2.8 million (representing 5.0 percent of total net income for the period) for the year ended December 31, 2004, $3.1 million (representing 4.9 percent of total net income for the period) for the year ended December 31, 2005, and $11.2 million (representing 12.4 percent of total net income for the period) for the year ended December 31, 2006. Diluted net income per limited partner unit is calculated by dividing net income applicable to limited partners’ by the sum of the weighted-average number of common and subordinated units outstanding and the dilutive effect of incentive unit awards (see Note 11), as calculated by the treasury stock method.
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The following table sets forth the reconciliation of the weighted average number of limited partner units used to compute basic net income per limited partner unit to those used to compute diluted net income per limited partner unit for the years ended December 31, 2004, 2005 and 2006:
6. Inventories
The components of inventories are as follows (in thousands of dollars):
The current replacement cost of crude oil inventory exceeded its carrying value by $94.5 million and $95.0 million at December 31, 2005 and 2006, respectively.
7. Properties, Plants and Equipment
The components of net properties, plants and equipment are as follows (in thousands of dollars):
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8. Investment in Affiliates
The Partnership’s ownership percentages in corporate joint ventures as of December 31, 2005 and 2006 are as follows:
(1)
Mid-Valley Pipeline Company was acquired in August 2006 and includes 50 percent voting interest.
The following table provides summarized financial information on a 100 percent basis for the Partnership’s equity ownership interests. (in thousands of dollars):
The Partnership’s investments in Wolverine, West Shore, Yellowstone, and West Texas Gulf at December 31, 2006 include an excess investment amount of approximately $55.0 million, net of accumulated amortization of $2.6 million. The excess investment is the difference between the investment balance and the Partnership’s proportionate share of the net assets of the entities. The excess investment was allocated to the underlying tangible and intangible assets. Other than land and indefinite-lived intangible assets, all amounts allocated, principally to pipeline and related assets, are amortized using the straight-line method over their estimated useful life of 40 years and included within depreciation and amortization in the statements of income.
9. Long-Term Debt
The components of long-term debt are as follows (in thousands of dollars):
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Credit Facility
On December 1, 2005, Sunoco Logistics Partners Operations L.P., a wholly-owned entity of the Partnership (the “Operating Partnership”), amended the November 22, 2004, Credit Facility to increase the commitment amount from $250 million to $300 million, and extend the term by one year to November 22, 2010.
The Credit Facility is available to fund the Operating Partnership’s working capital requirements, to finance future acquisitions and for general partnership purposes. It may also be used to fund the quarterly distribution to a maximum of $20.0 million. Borrowing under this distribution sublimit must be reduced to zero each year for a 15-day period. The Credit Facility bears interest at the Operating Partnership’s option, at either (i) LIBOR plus an applicable margin or (ii) the higher of the federal funds rate plus 0.50 percent or the Citibank prime rate (each plus the applicable margin). The interest rate on the outstanding borrowings at December 31, 2005 and 2006 was 4.74 and 5.70 percent, respectively. The Credit Facility may be prepaid at any time. The Credit Facility contains various covenants limiting the Operating Partnership’s ability to incur indebtedness; grant certain liens; make certain loans, acquisitions and investments; make any material change to the nature of its business; acquire another company; or enter into a merger or sale of assets, including the sale or transfer of interests in the Operating Partnership’s subsidiaries. The Credit Facility also contains covenants (each as defined in the credit agreement) requiring the Operating Partnership to maintain, on a rolling four-quarter basis, a maximum total debt to EBITDA ratio of 4.75 to 1, which can generally be increased to 5.25 to 1 during an acquisition period; and an interest coverage ratio of at least 3.0 to 1. The Operating Partnership is in compliance with these covenants as of December 31, 2006. The Partnership’s ratio of total debt to EBITDA was 2.9 to 1 and the interest coverage ratio was 4.9 to 1 for the year ended December 31, 2006.
Senior Notes
In February 2002, the Operating Partnership issued $250 million of 7.25% Senior Notes, due February 15, 2012 at a discount of 99.325 percent of the principal amount, for net proceeds of $244.8 million after the underwriter’s commission and legal, accounting and other transaction expenses. The Senior Notes are redeemable, at a make-whole premium, and are not subject to sinking fund provisions. The Senior Notes contain various covenants limiting the Operating Partnership’s ability to incur certain liens, engage in sale/leaseback transactions, or merge, consolidate or sell substantially all of its assets. The Operating Partnership is in compliance with these covenants as of December 31, 2006. In addition, the Senior Notes are also subject to repurchase by the Operating Partnership at a price equal to 100 percent of their principal amount, plus accrued and unpaid interest upon a change of control to a non-investment grade entity.
On May 2, 2006, the Operating Partnership issued $175 million of 6.125 percent Senior Notes, due May 15, 2016 at 99.858 percent of the principal amount, for net proceeds of $173.3 million after the underwriter’s commission and legal, accounting and other transaction expenses. The Senior Notes are redeemable, at a make-whole premium, and are not subject to sinking fund provisions. The Senior Notes contain various covenants limiting the Operating Partnership’s ability to incur certain liens, engage in sale/leaseback transactions, or merge, consolidate or sell substantially all of its assets. The Operating Partnership is in compliance with these covenants as of December 31, 2006.
The Partnership and the operating subsidiaries of the Operating Partnership serve as joint and several guarantors of the Senior Notes and of any obligations under the Credit Facility. The guarantees are full and unconditional.
The Partnership has no operations and its only assets are its investments in its wholly-owned partnerships and subsidiaries. The Operating Partnership also has no operations and its assets are limited primarily to its
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investments in its wholly-owned operating partnerships, deferred charges, and cash and cash equivalents of $9.4 million. Except for amounts associated with the Senior Notes, the Credit Facility, cash and cash equivalents and advances to affiliate, the assets and liabilities in the balance sheets and the revenues and costs and expenses in the statements of income are primarily attributable to the operating partnerships. See Note 18 for supplemental condensed consolidating financial information.
The aggregate amount of long-term debt maturities is as follows (in thousands of dollars):
Cash payments for interest related to long-term debt, net of capitalized interest (see Note 1), were, $19.4 million, $20.6 million and $24.7 million in 2004, 2005 and 2006, respectively.
10. Commitments and Contingent Liabilities
Total rental expense for 2004, 2005 and 2006 amounted to $4.5 million, $4.7 million and $5.8 million, respectively. The Partnership, as lessee, has noncancelable operating leases for land, office space and equipment for which the aggregate amount of future minimum annual rentals as of December 31, 2006 is as follows (in thousands of dollars):
The Partnership is subject to numerous federal, state and local laws which regulate the discharge of materials into the environment or that otherwise relate to the protection of the environment. These laws and regulations result in liabilities and loss contingencies for remediation at the Partnership’s facilities and at third-party or formerly owned sites. At December 31, 2005 and 2006, there were accrued liabilities for environmental remediation in the balance sheets of $0.6 million and $0.5 million, respectively. The accrued liabilities for environmental remediation do not include any amounts attributable to unasserted claims, nor have any recoveries from insurance been assumed. Charges against income for environmental remediation totaled $1.4 million, $1.6 million and $1.3 million for the years ended December 31, 2004, 2005 and 2006, respectively.
Total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the technology available and needed to meet the various existing legal requirements, the nature and extent of future environmental laws, inflation rates and the determination of the Partnership’s liability at multi-party sites, if any, in light of uncertainties with respect to joint and several
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liability, and the number, participation levels and financial viability of other parties. As discussed below, the Partnership’s current and future costs have been and will be impacted by an indemnification from Sunoco.
The Partnership is a party to certain pending and threatened claims. Although the ultimate outcome of these claims cannot be ascertained at this time, it is reasonably possible that some portion of them could be resolved unfavorably to the Partnership. Management does not believe that any liabilities which may arise from such claims and the environmental matters discussed above would be material in relation to the financial position of the Partnership at December 31, 2006. Furthermore, management does not believe that the overall costs for such matters will have a material impact, over an extended period of time, on the Partnership’s operations, cash flows or liquidity.
Sunoco has indemnified the Partnership for 30 years from environmental and toxic tort liabilities related to the assets contributed to the Partnership that arise from the operation of such assets prior to the closing of the February 2002 IPO. Sunoco has indemnified the Partnership for 100 percent of all losses asserted within the first 21 years of closing of the February 2002 IPO. Sunoco’s share of liability for claims asserted thereafter will decrease by 10 percent a year. For example, for a claim asserted during the twenty-third year after closing of the February 2002 IPO, Sunoco would be required to indemnify the Partnership for 80 percent of its loss. There is no monetary cap on the amount of indemnity coverage provided by Sunoco. The Partnership has agreed to indemnify Sunoco for events and conditions associated with the operation of the Partnership’s assets that occur on or after the closing of the February 2002 IPO and for environmental and toxic tort liabilities to the extent Sunoco is not required to indemnify the Partnership.
Sunoco also has indemnified the Partnership for liabilities, other than environmental and toxic tort liabilities related to the assets contributed to the Partnership, that arise out of Sunoco’s ownership and operation of the assets prior to the closing of the February 2002 IPO and that are asserted within 10 years after closing of the February 2002 IPO. In addition, Sunoco has indemnified the Partnership from liabilities relating to certain defects in title to the assets contributed to the Partnership and associated with failure to obtain certain consents and permits necessary to conduct its business that arise within 10 years after closing of the February 2002 IPO as well as from liabilities relating to legal actions currently pending against Sunoco or its affiliates and events and conditions associated with any assets retained by Sunoco or its affiliates.
Management of the Partnership does not believe that any liabilities which may arise from claims indemnified by Sunoco would be material in relation to the financial position of the Partnership at December 31, 2006. There are certain other pending legal proceedings related to matters arising after the February 2002 IPO that are not indemnified by Sunoco. Management believes that any liabilities that may arise from these legal proceedings will not be material in relation to the financial position of the Partnership at December 31, 2006.
11. Management Incentive Plan
Sunoco Partners LLC, the general partner of the Partnership, has adopted the Sunoco Partners LLC Long-Term Incentive Plan (“LTIP”) for employees and directors of the general partner who perform services for the Partnership. The LTIP is administered by the independent board directors of the Compensation Committee of the general partner’s board of directors with respect to employee awards, and by the non-independent members of the general partners’ board of directors with respect to awards granted to the independent members. The LTIP currently permits the grant of restricted units and unit options covering an aggregate of 1,250,000 common units.
Effective January 1, 2006, the Partnership adopted Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (“SFAS No. 123R”), using the modified-prospective method. SFAS No. 123R revised the accounting for stock-based compensation required by Statement of Financial Accounting
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Standards No. 123 “Accounting for Stock-Based Compensation” (“SFAS No. 123”). Among other things, SFAS No. 123R requires a fair-value-based method of accounting for share-based payment transactions, which is similar to the method followed by the Partnership under the provisions of SFAS No. 123.
Restricted Units
A restricted unit entitles the grantee to receive a common unit or, at the discretion of the Compensation Committee, an amount of cash equivalent to the value of a common unit upon the vesting of the unit, which may include the attainment of predetermined performance targets. The Compensation Committee may make additional grants under the LTIP to employees and directors containing such terms as the Compensation Committee shall determine. Common units to be delivered to the grantee upon vesting may be common units acquired by the general partner in the open market, common units already owned by the general partner, common units acquired by the general partner directly from the Partnership or any other person, or any combination of the foregoing. The general partner will be entitled to reimbursement by the Partnership for the cost incurred in acquiring common units. If the Partnership issues new common units upon vesting of the restricted units, the total number of common units outstanding will increase. The Compensation Committee, in its discretion, may grant tandem distribution equivalent rights (“DERs”) with respect to the restricted units. Subject to applicable vesting criteria, DERs entitle the grantee to receive an amount of cash equal to the per unit cash distributions made by the Partnership during the period the restricted unit is outstanding.
The following table provides the LTIP restricted unit activity for the three-year period ended December 31, 2006:
(1)
The weighted average price for restricted unit awards on the date of grant was $37.15, $41.93 and $39.55 for awards granted in 2004, 2005 and 2006 respectively.
(2)
Consists of adjustments to performance-based awards to reflect actual performance. The adjustments are required since the original grants of these awards were at 100 percent of the targeted amounts.
As of December 31, 2006, there were approximately 0.2 million unvested restricted stock units outstanding with a contractual life of three years. As of December 31, 2006, total compensation cost related to non-vested awards not yet recognized was $1.3 million, and the weighted-average period over which this cost is expected to be recognized in expense is 1.5 years. The number of restricted stock units outstanding and the total compensation cost related to non-vested awards not yet recognized reflect the Partnership’s estimates of performance factors pertaining to performance-based restricted unit awards.
The Partnership recognized share-based compensation expense related to the LTIP of approximately $3.2 million for both the years ended December 31, 2004 and 2005, respectively under SFAS No.123, and $3.7 million in the year ended December 31, 2006 under SFAS No. 123R related to the unit grants and performance factor adjustments noted in the table above. Each of the restricted unit grants also have tandem DERs which are recognized as a reduction of Partners’ Capital when earned.
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Unit Options
A unit option entitles the grantee to purchase a common unit at a price determined at the date of grant by the Compensation Committee. There have been no grants of unit options for the years ended December 31, 2004, 2005 and 2006, and there are no unit options outstanding as of December 31, 2006. However, the Compensation Committee may, in the future, make grants under the LTIP to employees and directors containing such terms as the Compensation Committee shall determine, provided that unit options have an exercise price no less than the fair market value of the units on the date of grant.
12. Cash Distributions
Within 45 days after the end of each quarter, the Partnership distributes all cash on hand at the end of the quarter, less reserves established by the general partner in its discretion. This is defined as “available cash” in the partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct the Partnership’s business. The Partnership will make quarterly distributions to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner.
The Partnership issued 11,383,639 subordinated units to its general partner in connection with the February 2002 IPO. The Partnership had 5,691,819 subordinated units outstanding as of December 31, 2006, all of which were held by the general partner, and for which there is no established public trading market. Any subordinated units that remain outstanding at the end of the subordination period convert to common units on a one-for-one basis if the Partnership meets certain required financial tests set forth in the Partnership Agreement. Upon conversion to common units, the subordinated units will no longer be subordinated to the rights of the holders of common units.
The Partnership has met the minimum quarterly distribution requirements on all outstanding units for each of the four-quarter periods ended December 31, 2004, 2005 and 2006. As a result, the total of 11,383,639 subordinated units have been converted into common units on a one-for-one basis, 2,845,910 each on February 15, 2005 and February 15, 2006 and 5,691,819 on February 15, 2007.
After the subordination period, the Partnership will, in general, pay cash distributions each quarter in the following manner:
If cash distributions exceed $0.50 per unit in a quarter, the general partner will receive increasing percentages, up to 50 percent, of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions”. The amounts shown in the table under “Percentage of Distributions” are the percentage interests of the general partner and the unitholders in any available cash from operating surplus that is distributed up to and including the corresponding amount in the column “Quarterly Cash Distribution Amount per Unit,” until the available cash that is distributed reaches the next target distribution level, if any. The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.
SUNOCO LOGISTICS PARTNERS L.P.
NOTES TO FINANCIAL STATEMENTS-(Continued)
Distributions paid by the Partnership during the years ended December 31, 2004, 2005 and 2006 were as follows:
On January 26, 2007, the Partnership declared a cash distribution of $0.8125 per unit ($3.25 per unit annualized) on its outstanding common and subordinated units, representing the distribution for the quarter ended December 31, 2006. The $28.3 million distribution, including $5.1 million to the general partner, was paid on February 14, 2007 to unitholders of record at the close of business on February 7, 2007.
13. Exit Costs Associated with Western Pipeline Headquarters Relocation
On June 10, 2005, the Partnership announced its intention to relocate its Western area office operations from Tulsa, Oklahoma to the Houston, Texas area. On September 1, 2005, the Partnership executed an agreement to lease office space in Sugar Land, Texas. The Partnership’s general partner has offered to relocate all affected employees. The Partnership substantially completed the relocation during the first quarter 2006.
The total non-recurring expenses incurred in connection with the relocation plan amounted to $5.0 million, including $2.9 million recognized during the first quarter 2006. These costs consist primarily of employee relocation costs, one-time termination benefits and new hire expenses. These costs are included in selling, general and administrative expenses in the condensed statement of income, and are included in the operating results for the Western Pipeline System segment. In addition, the total capital expenditures associated with the move amounted to $5.5 million, including $2.8 million in the first quarter 2006. These capital expenditures include furniture and equipment, communication infrastructure and a pipeline control center. The Partnership did not incur any material costs related to the move in the second, third and fourth quarter of 2006, and does not expect the remaining costs related to the relocation to be material.
14. Financial Instruments and Concentration of Credit Risk
The estimated fair value of financial instruments has been determined based on the Partnership’s assessment of available market information and appropriate valuation methodologies. However, these estimates may not necessarily be indicative of the amounts that the Partnership could realize in a current market exchange.
The Partnership’s current assets (other than inventories) and current liabilities are financial instruments. The estimated fair value of these financial instruments approximates their carrying amounts. The estimated fair value
SUNOCO LOGISTICS PARTNERS L.P.
NOTES TO FINANCIAL STATEMENTS-(Continued)
of the $106.6 million and $68.0 million of borrowings under the Credit Facility at December 31, 2005 and 2006 approximate their carrying amounts as these borrowings bear interest based upon short-term interest rates. The estimated fair value of the Senior Notes at December 31, 2005 and 2006 was $272.9 million and $444.5 million, respectively, compared to the carrying amounts of $249.0 million and $424.0 million, respectively. The Senior Notes, which are publicly traded, were valued based upon quoted market prices.
Approximately 31 percent of total revenues recognized by the Partnership during 2006 was derived from Sunoco. The Partnership sells crude oil to Sunoco, transports crude oil and refined products to/from Sunoco’s refineries and provides terminalling and storage services for Sunoco. Sunoco has been issued an investment grade credit rating by three recognized agencies and, accordingly, management of the Partnership does not believe that the transactions with Sunoco expose it to significant credit risk.
The Partnership’s other trade relationships are primarily with major integrated oil companies, independent oil companies and other pipelines and wholesalers. These concentrations of customers may affect the Partnership’s overall credit risk in that the customers (including Sunoco) may be similarly affected by changes in economic, regulatory or other factors. The Partnership’s customers’ credit positions are analyzed prior to extending credit and periodically after the credit has been extended. The Partnership manages its exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions may utilize letters of credit, prepayments and guarantees.
15. Business Segment Information
The Partnership operates in three principal business segments: Eastern Pipeline System, Terminal Facilities and Western Pipeline System.
•
The Eastern Pipeline System primarily serves the Northeast and Midwest United States operations of Sunoco and includes: approximately 1,650 miles of refined product pipelines, including a two-thirds undivided interest in the 80-mile refined product Harbor pipeline, and 58 miles of interrefinery pipelines between two of Sunoco’s refineries; approximately 140 miles of crude oil pipelines; a 9.4 percent interest in Explorer Pipeline Company, a joint venture that owns a 1,413-mile refined product pipeline; a 31.5 percent interest in Wolverine Pipe Line Company, a joint venture that owns a 721-mile refined product pipeline; a 12.3 percent interest in West Shore Pipe Line Company, a joint venture that owns a 652-mile refined product pipeline; and a 14.0 percent interest in Yellowstone Pipe Line Company, a joint venture that owns a 750-mile refined product pipeline.
•
The Terminal Facilities consist of 35 refined product terminals with an aggregate storage capacity of 5.9 million barrels, primarily serving the Partnership’s Eastern Pipeline System; the Nederland Terminal, a 12.9 million barrel marine crude oil terminal on the Texas Gulf Coast; a 2.0 million barrel refined product terminal serving Sunoco’s Marcus Hook refinery near Philadelphia, Pennsylvania; one inland and two marine crude oil terminals with a combined capacity of 3.4 million barrels, and related pipelines, which serve Sunoco’s Philadelphia refinery; a ship and barge dock which serves Sunoco’s Eagle Point refinery; and a 1.0 million barrel liquefied petroleum gas (“LPG”) terminal near Detroit, Michigan.
•
The Western Pipeline System gathers, purchases, sells, and transports crude oil principally in Oklahoma and Texas and consists of approximately 3,200 miles of crude oil trunk pipelines, including a 37.0 percent undivided interest in the 80-mile Mesa Pipe Line system, and approximately 500 miles of crude oil gathering lines that supply the trunk pipelines; approximately 115 crude oil transport trucks; approximately 150 crude oil truck unloading facilities; a 55.3 percent interest in the Mid-Valley Pipeline Company, a joint venture that owns a 994-mile pipeline and a 43.8 percent interest in West Texas Gulf Pipe Line Company, a joint venture that owns a 579-mile crude oil pipeline.
SUNOCO LOGISTICS PARTNERS L.P.
NOTES TO FINANCIAL STATEMENTS-(Continued)
Segment Information (in thousands of dollars)
(1)
Includes equity income of $11,446 thousand attributable to the Partnership’s equity ownership interests in Explorer, Wolverine, West Shore and Yellowstone.
(2)
Includes equity income of $1,787 thousand attributable to the Partnership’s equity ownership interest in West Texas Gulf.
(3)
Excludes $7,409 thousand for the acquisition of the additional 33.3 percent ownership interest in the Harbor pipeline, including transaction costs, and $334 thousand of the allocated purchase price for a 4.5 mile refined product pipeline acquired as part of the Eagle Point logistics assets acquisition (see Note 4).
(4)
Excludes the following acquisition amounts, including transaction costs: $8,081 thousand for the acquisition of a refined products terminal located in Columbus, Ohio; $12,276 thousand for the acquisition of two refined products terminals located in Baltimore, Maryland and Manassas, Virginia; and $21,065 thousand of the allocated purchase price for the dock and truck rack acquired as part of the Eagle Point logistics assets acquisition (see Note 4).
(5)
Identifiable assets include the Partnership’s unallocated $52,660 thousand cash and cash equivalents, $12,349 thousand advances to affiliates, $2,561 thousand deferred financing costs, and $3,130 thousand attributable to corporate activities.
SUNOCO LOGISTICS PARTNERS L.P.
NOTES TO FINANCIAL STATEMENTS-(Continued)
(1)
Includes equity income of $11,152 thousand attributable to the Partnership’s equity ownership interests in Explorer, Wolverine, West Shore and Yellowstone.
(2)
Includes equity income of $2,063 thousand attributable to the Partnership’s equity ownership interest in West Texas Gulf.
(3)
Excludes $100,057 thousand for the acquisition of the Corsicana to Wichita Falls, Texas crude oil pipeline system and related storage facilities, and $5,505 thousand related to the acquisition of a 37.0 undivided joint interest in the Mesa Pipe Line system (see Note 4).
(4)
Identifiable assets include the Partnership’s unallocated $21,645 thousand cash and cash equivalents, $4,834 thousand deferred financing costs, and $581 thousand attributable to corporate activities.
(1)
Includes equity income of $11,012 thousand attributable to the Partnership’s equity ownership interests in Explorer, Wolverine, West Shore and Yellowstone.
SUNOCO LOGISTICS PARTNERS L.P.
NOTES TO FINANCIAL STATEMENTS-(Continued)
(2)
Includes equity income of $5,870 thousand attributable to the Partnership’s equity ownership interest in West Texas Gulf and Mid-Valley.
(3)
Excludes $108,900 thousand for the acquisition of the Amdel and White Oil crude oil pipeline system, and Millennium and Kilgore crude oil pipeline system and, $12,482 thousand related to the acquisition of a 55.3 percent equity interest in Mid-Valley Pipeline Company (see Note 4).
(4)
Identifiable assets include the Partnership’s unallocated $9,412 thousand cash and cash equivalents, $7,431 thousand advances to affiliates, $7,204 thousand deferred financing costs, and $2,202 thousand attributable to corporate activities.
The following table sets forth total sales and other operating revenue by product or service (in thousands of dollars):
16. Quarterly Financial Data (Unaudited)
Summarized quarterly financial data is as follows (in thousands of dollars, except per unit amounts):
SUNOCO LOGISTICS PARTNERS L.P.
NOTES TO FINANCIAL STATEMENTS-(Continued)
(1)
Gross margin equals sales and other operating revenue less cost of products sold and operating expenses and depreciation and amortization.
(2)
Net income included within this calculation excludes amounts attributable to the general partner’s interest in net income.
17. Supplemental Condensed Consolidating Financial Information
The Partnership and the operating subsidiaries of the Operating Partnership serve as joint and several guarantors of the 6.125% and 7.25% Senior Notes and of any obligations under the Credit Facility. The guarantees are full and unconditional. Given that certain, but not all subsidiaries of the Partnership are guarantors, the Partnership is required to present the following supplemental condensed consolidating financial information. For purposes of the following footnote, Sunoco Logistics Partners, L.P. is referred to as “Parent” and Sunoco Logistics Partners Operations L.P. is referred to as “Subsidiary Issuer.” Sunoco Partners Marketing and Terminals L.P., Sunoco Pipeline L.P., Sun Pipeline Company of Delaware LLC and Sunoco Pipeline Acquisition LLC are collectively referred to as the “Subsidiary Guarantors”. Sunoco Logistics Partners GP LLC, Sunoco Logistics Partners Operations GP LLC and Sunoco Partners Lease Acquisition & Marketing LLC, are referred to as “Non-Guarantor Subsidiaries.”
The following supplemental condensed consolidating financial information (in thousands) reflects the Parent’s separate accounts, the Subsidiary Issuer’s separate accounts, the combined accounts of the Subsidiary Guarantors, the combined accounts of the Non-Guarantor Subsidiaries, the combined consolidating adjustments and eliminations and the Parent’s consolidated accounts for the dates and periods indicated. For purposes of the following condensed consolidating information, the Parent’s investments in its subsidiaries and the Subsidiary Issuer’s investments in its subsidiaries are accounted for under the equity method of accounting.
SUNOCO LOGISTICS PARTNERS L.P.
NOTES TO FINANCIAL STATEMENTS-(Continued)
Balance Sheet
December 31, 2005
SUNOCO LOGISTICS PARTNERS L.P.
NOTES TO FINANCIAL STATEMENTS-(Continued)
Balance Sheet
December 31, 2006
SUNOCO LOGISTICS PARTNERS L.P.
NOTES TO FINANCIAL STATEMENTS-(Continued)
Statement of Income
Year Ended December 31, 2004
SUNOCO LOGISTICS PARTNERS L.P.
NOTES TO FINANCIAL STATEMENTS-(Continued)
Statement of Income
Year Ended December 31, 2005
SUNOCO LOGISTICS PARTNERS L.P.
NOTES TO FINANCIAL STATEMENTS-(Continued)
Statement of Income
Year Ended December 31, 2006
SUNOCO LOGISTICS PARTNERS L.P.
NOTES TO FINANCIAL STATEMENTS-(Continued)
Statement of Cash Flows
Year Ended December 31, 2004
SUNOCO LOGISTICS PARTNERS L.P.
NOTES TO FINANCIAL STATEMENTS-(Continued)
Statement of Cash Flows
Year Ended December 31, 2005
SUNOCO LOGISTICS PARTNERS L.P.
NOTES TO FINANCIAL STATEMENTS-(Continued)
Statement of Cash Flows
Year Ended December 31, 2006
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure controls and procedures are designed to ensure that information required to be disclosed in the Partnership reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the rules and forms of the Securities and Exchange Commission. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed in the Partnership reports under the Exchange Act is accumulated and communicated to management, including the President, Chief Executive Officer and principal financial officer of Sunoco Partners LLC (the Partnership’s general partner), as appropriate, to allow timely decisions regarding required disclosure.
As of December 31, 2006, the Partnership carried out an evaluation, under the supervision and with the participation of the management of the general partner (including the President, Chief Executive Officer and Principal Financial Officer), of the effectiveness of the design and operation of the Partnership’s disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, the general partner’s President, Chief Executive Officer and Principal Financial Officer, concluded that the Partnership’s disclosure controls and procedures are effective.
The management of the general partner is responsible for establishing, maintaining, and annually assessing internal control over the Partnership’s financial reporting. A report by the general partner’s management, assessing the effectiveness of the Partnership’s internal control over financial reporting, appears under Item 8 “Financial Statements and Supplementary Data” of this report. Ernst & Young LLP, the Partnership’s independent registered public accounting firm, have issued an attestation report on management’s assessment of the Partnership’s internal control over financial reporting, that also appears under Item 8 of this report.
No change in the Partnership’s internal control over financial reporting has occurred during the fiscal quarter ended December 31, 2006 that has materially affected, or that is reasonably likely to materially affect, the Partnership’s internal control over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Sunoco Partners LLC, the general partner, is a wholly-owned, indirect subsidiary of Sunoco, Inc. The general partner manages the Partnership’s operations and activities. The general partner’s board of directors held 6 meetings during 2006. The board has established standing committees to consider designated matters. The standing committees of the board are the Audit/Conflicts Committee and the Compensation Committee. The board has adopted governance guidelines for the board and charters for the standing committees.
The Audit/Conflicts Committee, in its role as an audit committee, oversees external financial reporting, engages independent auditors, and reviews procedures for internal auditing and the adequacy of internal accounting controls. In addition, the Audit/Conflicts Committee, in its role as a “conflicts” committee, reviews specific matters that the board believes may involve conflicts of interest between the Partnership and Sunoco and determines if the resolution of the conflict of interest is fair and reasonable to the Partnership. The Audit/Conflicts Committee met as an audit committee 9 times during 2006, and met as a conflicts committee 9 times during 2006. The current members of the Audit/Conflicts Committee are: Stephen L. Cropper (chairman), L. Wilson Berry, Jr. and Gary W. Edwards. The general partner’s board of directors has determined that, based upon relevant experience, Audit/Conflicts Committee member Stephen L. Cropper is an “audit committee financial expert,” as defined in Item 401 of Regulation S-K of the Securities Exchange Act of 1934, as amended. The members of the Audit/Conflicts Committee consist of those directors of the general partner who are not also executive officers of the general partner or its parent, all of whom meet certain independence and experience standards to serve on an audit committee of a board of directors established by the New York Stock Exchange. In conjunction with regular meetings, the Audit/Conflicts Committee meets in executive session without members of management present. Mr. Cropper leads these executive session meetings, the purpose of which is to promote open and candid discussion among the non-management and independent members of the general partner’s board of directors.
The Compensation Committee of the general partner’s board of directors oversees compensation decisions for the officers of the general partner and the administration of the compensation plans described below. The Compensation Committee held 4 meetings during 2006. The current members of the Compensation Committee are: Gary W. Edwards (chairman), Stephen L. Cropper, L. Wilson Berry, Jr. and John G. Drosdick. Since he also is an officer and director of Sunoco, Mr. Drosdick recuses himself from Compensation Committee decisions relating to equity compensation awards.
The general partner’s board of directors has determined affirmatively that Messrs. Berry, Cropper and Edwards are independent, as described in the governance guidelines and the New York Stock Exchange rules.
In order that interested parties may be able to make their concerns known to the non-management directors, the Partnership’s unitholders and other interested parties may communicate directly with the general partner’s board of directors, with the non-management directors as a group, or with any director or committee chairperson by writing to such parties in care of Bruce D. Davis, Jr., Vice President, General Counsel and Secretary, Sunoco Partners LLC, Mellon Bank Center, 1735 Market Street, Suite LL, Philadelphia, PA 19103-7583. Communications addressed to the board generally will be forwarded either to the appropriate committee chairperson or to all directors. Communications may be submitted confidentially and anonymously. Under certain circumstances, the Partnership or the general partner may be required by law to disclose the information or identity of the person submitting the communication. There were no material actions taken by the Board of Directors as a result of communications received during 2006 from unitholders or others. Certain concerns communicated to the general partner’s board of directors also may be referred to the general partner’s internal auditor or its General Counsel, in accordance with the general partner’s regular procedures for addressing such concerns. The chairman of the general partner’s board of directors, or the chairman of the general partner’s Audit/Conflicts Committee may direct that certain concerns be presented to the Audit/Conflicts Committee, or to the full board, or that they otherwise receive special treatment, including retention of external counsel or other advisors.
The officers of the general partner, other than Paul A. Mulholland, Treasurer, spend substantially all of their time managing the Partnership’s business and affairs. The non-executive directors devote as much time as is necessary to prepare for and attend board of directors and committee meetings.
The Partnership’s general partner has adopted a Code of Ethics for Senior Officers, which applies to all executive officers, including the principal executive officer, the principal financial officer, the principal accounting officer, the treasurer and persons performing similar functions for the general partner and its subsidiaries. In addition, the general partner has adopted a Code of Business Conduct and Ethics, which applies to all directors, officers and employees. The Code of Business Conduct and Ethics addresses ethical handling of actual or apparent conflicts of interest, compliance with applicable laws, rules and regulations, full, fair, accurate, timely and understandable disclosure in public communications, and prompt internal reporting of violations. In accordance with the disclosure requirements of applicable law or regulation, the Partnership intends to disclose any amendment to, or waiver from, any provision of these Codes, on its website, or under Item 5.05 of a current report on Form 8-K.
The Partnership makes available, free of charge within the “Corporate Governance” section of its website at www.sunocologistics.com, and in print to any unitholder who so requests, the Code of Ethics for Senior Officers, the Code of Business Conduct and Ethics, the Audit/Conflicts Committee Charter, the Compensation Committee Charter, the Corporate Governance Guidelines and the Partnership’s limited partnership agreement. Requests for print copies may be directed to: Investor Relations, Sunoco Logistics Partners L.P., 1735 Market Street, Suite LL, Philadelphia, PA 19103-7583, or telephone (866) 248-4344. The information contained on, or connected to, the Partnership’s internet website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that the Partnership files with, or furnishes to, the SEC.
On March 31, 2006, Deborah M. Fretz, President and Chief Executive Officer of Sunoco Partners LLC (general partner of the Partnership), submitted to the New York Stock Exchange (“NYSE”) the Written Affirmation required by the rules of the NYSE certifying that she was not aware of any violations by the Partnership of NYSE corporate governance listing standards.
The certifications of Ms. Fretz, principal executive officer and principal financial officer of the general partner, made pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, regarding the quality of the Partnership’s public disclosure, have been filed as exhibits to the Partnership’s 2006 Annual Report to the SEC on Form 10-K.
Directors and Executive Officers of Sunoco Partners LLC (the General Partner)
The Partnership’s common unit holders do not nominate candidates for, or vote for the election of, the directors of the general partner. The general partner is a limited liability company, and its directors are elected by its members, all of which are corporate affiliates of Sunoco. The executive officers of the general partner are appointed by its directors. The following table shows information for the directors and executive officers of Sunoco Partners LLC, the general partner. Executive officers and directors are elected for one-year terms.
Mr. Drosdick was elected Chairman of the Board of Directors in October 2001. He has been Chairman of the Board of Directors, President and Chief Executive Officer of Sunoco, Inc. since May 2000. Prior to that, he was a director, President and Chief Operating Officer of Sunoco, Inc. from December 1996 to May 2000. Mr. Drosdick is also a director of the H.J. Heinz Company and United States Steel Corporation.
Ms. Fretz was elected President, Chief Executive Officer and director in October 2001. Prior to assuming her positions with the Partnership, she was Senior Vice President, MidContinent Refining, Marketing and Logistics of Sunoco, Inc. from November 2000. Prior to that, she was Senior Vice President, Logistics of Sunoco, Inc. from August 1994 to November 2000 and also held the position of Senior Vice President, Lubricants of Sunoco, Inc. from January 1997 to November 2000. In addition, she has been President of Sun Pipe Line Company, a subsidiary of Sunoco, Inc., since October 1991. Ms. Fretz is a director of GATX Corporation.
Ms. Archer was elected to the Board of Directors in April 2002. Ms. Archer has been Vice President, Marketing and Development, Sunoco, Inc. since January 2001. Prior to joining Sunoco, she was Senior Vice President, Operations for Williams-Sonoma Inc., in charge of their direct-to-customer business from June 1999 to January 2001. Ms. Archer is a director of Mercantile Bankshares Corporation, where she serves as Chair of the Audit Committee.
Mr. Berry was elected to the Board of Directors in March 2003. He is currently a consultant in the energy field. From 1998 until his retirement in 2000, Mr. Berry was Chief Executive Officer and President of Motiva Enterprises LLC, a refining and marketing joint venture in the Eastern United States, established by Shell Norco Refining Company, Texaco Refining and Marketing (East) Inc., and Saudi Refining Inc. From 1996 to 1998, he was President of Texaco Refining & Marketing, Inc., a domestic refining and marketing division of Texaco, Inc.
Mr. Cropper was elected to the Board of Directors in May 2002. Mr. Cropper is currently a private investor. From January 1996 until the time of his retirement in December 1998, he served as President and Chief Executive Officer of Williams Energy Services, a diversified energy company. Mr. Cropper served as President of Williams Pipe Line Company from 1986 to 1998. He is a director of Berry Petroleum, NRG Energy, Inc. and Rental Car Finance Corporation, a subsidiary of Dollar Thrifty Automotive Group, Inc.
Mr. Dingus was elected to the Board of Directors in April 2002. He has been Senior Vice President, Sunoco, Inc. since January 2002. Prior to that, he was Vice President of Sunoco, Inc. from May 1999, and he has been President, Sun Coke Company since June 1996.
Mr. Edwards was elected to the Board of Directors in May 2002. Mr. Edwards is currently a consultant in the energy field. From November 1999 until the time of his retirement in December 2001, he was Senior Executive Vice President, Corporate Strategy & Development, Conoco, Inc., and had been Executive Vice President, Refining, Marketing, Supply & Transportation of Conoco from September 1991 until November 1999. Mr. Edwards is a director of Entergy, Inc.
Mr. Fischer was elected to the Board of Directors in April 2002. He has been Senior Vice President, Sunoco Chemicals of Sunoco, Inc. since January 2002. Prior to that, he was Vice President, Sunoco Chemicals from November 2000 to January 2002 and Vice President and General Manager, Sunoco MidAmerica Marketing and Refining from January 1999 to November 2000.
Mr. Hofmann was elected to the Board of Directors in October 2001. He has been Senior Vice President and Chief Financial Officer of Sunoco, Inc. since January 2002. Prior to that, he was Vice President and Chief Financial Officer of Sunoco, Inc. from July 1998 to January 2002. Mr. Hofmann is a director of Viasys Healthcare, Inc.
Mr. Broker was elected Vice President, Western Operations in November 2001. Prior to that, he had been Manager, Western Area Operations for Sun Pipe Line Company since September 2000. Mr. Broker served as Area Superintendent of Eastern Area Operations for Sun Pipe Line Company from March 1997 through September 2000.
Mr. Davis was elected Vice President, General Counsel and Secretary in January 2004. From November 2003 to January 2004, he was General Counsel and Secretary. From September 2000 to November 2003, Mr. Davis was Associate General Counsel for Mirant Corporation. Prior to that, from July 1992 to September 2000, he was Associate General Counsel for Constellation Energy Group.
Mr. Justin was elected Vice President, Eastern Operations in November 2001. From September 2000 to November 2001, Mr. Justin served as Manager, Eastern Area Operations for Sun Pipe Line Company. Prior to that, he had been Manager, Western Area Operations for Sun Pipe Line Company from 1998 through September 2000.
Mr. Keene was elected Vice President, Business Development in January 2005. From February 2002 to December 2004, Mr. Keene was the Director, Midstream Development for Unocal Midstream & Trade (UMT), a division of Unocal Corporation. Prior to that, he had been the Director, Business Development, Unocal Global Trade, a division of Unocal Corporation, and Vice President, Unocal Pipeline Company from April 1999 to January 2002.
Mr. Mulholland was elected Treasurer in January 2002. He has been Treasurer of Sunoco, Inc. since April 2000. Prior to that, from May 1996 to April 2000, he was Assistant Treasurer of Sunoco, Inc.
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 the units to file certain ownership reports with the Securities and Exchange Commission and the New York Stock Exchange. The Securities and Exchange Commission regulations also require that copies of these Section 16(a) reports be furnished to the Partnership by such reporting persons. Based upon a review of copies of these reports, the Partnership believes that the reporting persons are in compliance with the applicable requirements of Section 16(a).
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The Partnership has no employees. It is managed by the officers of its general partner. The Partnership reimburses its general partner for certain indirect and direct expenses, including executive compensation expenses, incurred on the Partnership’s behalf. Officers and employees of the general partner participate in employee benefit plans and arrangements sponsored by the general partner or its affiliates.
COMPENSATION DISCUSSION AND ANALYSIS
Overview: The general partner seeks to improve the Partnership’s financial and operating performance and provide a desirable return on investment to holders of the Partnership’s common units, while maintaining financial strength and flexibility. The general partner provides a competitive compensation package in order to attract highly competent and skilled executives to meet these objectives. In addition, where doing so has been determined to be a cost-effective and administratively efficient means of providing benefits to its employees, the general partner is a participating employer in certain benefit plans sponsored by Sunoco, including its defined benefit pension plan. The Partnership reimburses the general partner for such benefits purchased through its participation in these plans.
Compensation Philosophy: The compensation program for the Named Executive Officers (“NEOs”) of the general partner utilizes objectives and measurement criteria based upon performance relative to peer companies, and is designed to provide the competitive level of total compensation needed to attract, retain and motivate talented and experienced executives who can contribute to the Partnership’s success. The compensation program emphasizes performance-based compensation (pay at risk), to promote achievement of short-term and long-term business objectives consistent with the Partnership’s strategic plan, and is structured so that the actual compensation received is aligned equally with the Partnership’s overall performance in the areas of total unitholder return relative to peer companies, and growth in cash distributions to unitholders. Executive compensation is aligned with the interests of the Partnership’s unitholders by providing incentives in the form of restricted units and requiring significant holdings of common units, representing limited partnership interests in the Partnership. The general partner has adopted unit ownership guidelines requiring executives and certain other key employees to own common units, as further described herein. The Compensation Committee reviews the compensation program and makes changes deemed appropriate and in the best interests of the Partnership and its unitholders. The general partner’s eligible executives participate in the defined benefit programs and the qualified and non-qualified defined contribution plans of Sunoco.
Compensation Methodology: The Compensation Committee utilizes Towers Perrin as a consultant to assist in evaluating the effectiveness and competitiveness of the compensation program. As part of its review, the Compensation Committee examines the compensation practices of the Partnership’s peer companies, which consist of other publicly traded master limited partnerships having a business mix comparable to that of the Partnership. Changes occur, from time to time, in the composition of this peer group, in order to reflect mergers, acquisitions, business bankruptcies and other similar events. Because the general partner and the Compensation Committee believe that the direct competition for executive talent is broader than this group of peer companies, the Compensation Committee also reviews compensation data from the pipeline industry and general industry.
The three basic components of compensation for executives of the general partner consist of base salary; annual incentives; and long-term incentives. For most of the general partner’s executives, the grant-date value of each of these components is targeted to the 50th percentile of the corporate-level competitive market data for general industry. However, based upon the Partnership’s performance, actual realized compensation may be significantly higher or lower than the target. As a tool to assist in its review of executive compensation, the Compensation Committee uses tally sheets that reflect all components of the executive’s total compensation, including salary, annual incentives, long-term incentives, and the value or incremental cost to the Partnership of all other compensation. Additionally, in consultation with the compensation consultant, management and other outside advisors, the Compensation Committee has reviewed the estimated compensation to be received by the CEO and the other NEOs under various scenarios, including normal retirement, voluntary or involuntary termination, and involuntary termination due to a change in control of the Partnership or Sunoco, Inc.
Elements of Compensation:
•
Base Salary: Base salary is designed to compensate executives for their level of responsibility and sustained individual performance (including experience, scope of responsibility, results achieved and future potential). The salaries of the NEOs are reviewed on an annual basis, as well as at the time of promotion and other change in responsibilities. The compensation consultant provides benchmarking data on the compensation of the NEOs compared to the compensation of executives in similar positions with similar responsibility levels in the pipeline industry and in general industry. The general partner and the Compensation Committee attempt to establish and maintain base salaries for the NEOs within the median range of base salaries in the applicable competitive market data. Base salaries also are influenced by internal equity (fair and consistent application of compensation practices). The Compensation Committee, with input from the compensation consultant and the CEO (who provides input for the NEOs other than herself), approves all base salaries for the NEOs. The Summary Compensation Table on page 109 includes the base salaries of the NEOs that were approved for 2006. At the NEO level, the balance of compensation is weighted toward pay-at-risk compensation (annual and long-term incentives).
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Annual Incentive Awards:
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Why the Partnership Has Adopted the Annual Incentive Plan. The general partner’s Annual Incentive Plan is designed to enhance the performance of key employees, including the NEOs, by providing annual cash incentive (“bonus”) opportunities for achievement of annual financial and operational performance goals. In particular, bonus awards are provided to the NEOs in order to provide competitive incentives to these executives who can significantly impact performance and promote achievement of the Partnership’s short-term business objectives. The Compensation Committee, in its sole discretion, determines the individual participants and payments, if any, for each fiscal year. The Compensation Committee also may amend or change the annual incentive plan at any time.
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Determination of the Amounts Awarded Under the Annual Incentive Plan. Under the plan, an individual’s annual incentive payout amount is determined by multiplying the product of his or her base salary and individual incentive guideline by a factor ranging from zero to 200 percent, based upon the level of attainment of pre-established goals for the Partnership’s cash flow from operations. Following the end of each year, the Compensation Committee reviews performance data with management and the compensation consultant, and determines the extent to which these goals have been achieved. That amount then may be adjusted up or down (by no more than 20 percent) to reflect financial performance of the Partnership’s lease crude acquisition business. This adjusted amount may be further adjusted up or down (by no more than 10 percent) to reflect actual Partnership performance with regard to certain health, environment and safety criteria. This health, environment and safety component does not apply if the minimum Partnership performance goals are not attained. If the Partnership does not achieve at least the minimum threshold performance goals, no award payment will be made. Payout for performance between specified performance goals will be interpolated on a straight-line basis. In no event can the annual incentive payout amount exceed 200 percent of the individual’s guideline amount, even after taking the applicable adjustments into account.
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How the Partnership Determined the Formula Criteria. Use of cash flow from operations as the primary criterion for payout of the 2006 annual incentive award ensures that management will continue to be focused on operations excellence. Use of health, environment and safety performance to further adjust the payout reinforces that, along with financial success, management is focused on continuing to protect the Partnership’s employees and the communities in which the Partnership operates. The respective payout percentages for these criteria were established at levels that the Compensation Committee believes provide meaningful incentives to achieve the established performance goals.
•
2006 Annual Incentive Payout Amount. Based upon the Partnership’s level of attainment of pre-established goals for cash flow from operations during the 2006 plan year, the payout factor was 127 percent, adjusted by the applicable health, environmental and safety factor for each business unit. The annual incentive reinforces the links between strategy, goal-setting and results. The individual incentive guidelines (as a percentage of base salary) for each of the NEOs for 2006 are as follows:
Under the general partner’s annual incentive plan, the Compensation Committee has the discretion to reduce the amounts payable to participants, or to determine that no amount will be paid, even if all performance criteria for payout are met. The annual incentive awards are paid in cash. The annual incentives earned by NEOs for 2006 are included in the Summary Compensation Table on page 109 under “Non-Equity Incentive Plan Compensation.”
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Long-Term Incentive Awards:
•
Why the Long-Term Incentive Plan was Adopted. Long-term incentive awards for the NEOs are granted under the Sunoco Partners LLC Long-Term Incentive Plan (LTIP), in order to promote achievement of the Company’s long-term strategic business objectives. This plan was designed to align the economic interests of key employees and directors with those of the Partnership’s common unitholders; to provide competitive compensation opportunities that can be realized through attainment of performance goals; and to provide an incentive to management for continuous employment with the general partner and its affiliates. Long-term incentive compensation is based upon the common units representing limited partnership interests in the Partnership, although it may be payable in common units, or in cash. The Compensation Committee administers the plan and, in its discretion, may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. However, no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the participant. The Compensation Committee also has the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted, subject to unitholder approval as required by the exchange upon which the common units are listed at that time.
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What are the elements of compensation under the LTIP? The LTIP provides for two types of awards: restricted units and unit options.
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Restricted Units. Each restricted unit entitles the grantee to receive a common unit upon vesting or, in the discretion of the Compensation Committee, an amount of cash equivalent to the value of a common unit. From time to time, the Compensation Committee may make grants under the plan to employees and/or directors containing such terms as the Compensation Committee shall determine under the plan. Special one-time grants of restricted units may be made at any time during the year, subject to the approval of the Compensation Committee. These grants are infrequent, and generally are used for new hires, promotions and recognition of extraordinary accomplishments. The Compensation Committee will determine the period over which restricted units granted to employees and/or directors will vest, and whether or not any such restricted units will have distribution equivalent rights entitling the grantee to receive an amount in cash equal to cash distributions made by the Partnership with respect to a like number of its common units during the period such restricted units are outstanding. Performance-based restricted units are designed to pay out only if certain objective Partnership-specific
performance measures have been met over the applicable performance period, generally three years. As a result, the payout under an LTIP award of performance-based restricted units is influenced not only by performance in the year in which the award is paid, but also by performance for the two prior years. Thus, extreme positive or negative performance during the two years prior to the payout of an award may influence the actual award more than performance in the year in which the award vests. In addition, the value received from restricted unit awards will be affected by any changes in the trading price of the Partnership’s common units during the period of time between the grant date and the payment date.
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2006 Awards. For the 2006 awards, payout will depend upon achievement by the Partnership of certain performance levels based on two equally weighted performance measures relative to the Partnership’s peer group: total unitholder return (including cash distributions plus appreciation in unit price) and growth in cash distributions to unitholders, both measured for the three-year period ending December 31, 2008. Actual payout may range from zero percent to 200 percent of the target amount, with payments increasing as the Partnership’s percentile ranking against its peer companies improves with respect to each of these two performance measures. The respective payout factor is zero for a ranking below the fortieth percentile on each performance measure. Maximum potential payout is achieved at a ranking above the ninetieth percentile on each performance measure. Payout factors applicable to performance between points will be interpolated along a straight line.
In selecting total unitholder return and growth in distributable cash as the performance measures applicable to the payout of performance-based restricted units, consideration was given to a balanced incentive approach, utilizing those measures deemed most important to the Partnership’s common unitholders, while recognizing the difficulty of accurately predicting market conditions over time. The Compensation Committee believes that performance relative to the peer companies is an important criterion for payout since market conditions are outside the control of management, and management will realize greater than median levels of compensation only when the Partnership outperforms its peer group. Conversely, regardless of market conditions, management will realize less than median compensation levels when the Partnership underperforms its peer group.
As an additional incentive to promote the growth of cash distributions to unitholders, during the performance period, distribution equivalent rights were granted in tandem with the 2006 awards of performance-based restricted units. At the end of the performance period, to the extent that the performance-based restricted units are paid out, these distribution equivalent rights entitle the grantee of performance-based restricted units to receive an amount equal to the cumulative cash distributions that otherwise would have been paid over the performance period had the grantee been the holder of record of Partnership common units equal to the number of performance-based restricted units paid out. This amount may be taken in the form of cash or additional common units (fractional units are cashed out).
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2006 Payout for Prior Awards. The performance period for the performance-based restricted units awarded in January 2004 ended December 31, 2006, and the level of payout of these awards reflects the Partnership’s level of achievement of the applicable performance measures during the period from January 1, 2004 to December 31, 2006. The performance measures for these awards were total unitholder return, and growth in operating cash flow over the three-year performance period.
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Unit Options. The long-term incentive plan currently permits the grant of options covering common units. No unit options have been granted since the inception of the LTIP in 2002. However, in the future, the Compensation Committee may determine to grant unit options under the plan to employees and directors, containing such terms as the committee shall determine.
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Determination of the Amounts Awarded under the Long-Term Incentive Plan. In conjunction with the review and approval of other elements of the NEOs’ compensation, the annual LTIP awards generally are reviewed and approved each year at the Compensation Committee’s regularly scheduled January meeting, and the grant date is the date of the meeting. Approval of the 2006 LTIP grants of performance-based restricted units, although considered at the January 2006 meeting, was deferred until the Compensation Committee’s April 2006 meeting, to enable the Compensation Committee to further evaluate appropriate performance criteria. However, the number of restricted units awarded in 2006 was determined in January 2006 in accordance with established Partnership practice. In determining the appropriate long-term value for each executive, the Compensation Committee reviews the level of responsibility and total compensation of each senior executive, and the competitive market data presented by the compensation consultant. The Compensation Committee approves the specific amounts granted to each employee. In general, the target number of restricted units granted to each NEO under the LTIP is calculated by taking the product of the NEO’s base salary and the applicable guideline percentage for that NEO, and then dividing by the average daily closing market price of the Partnership’s common units during the last thirty (30) trading days prior to the December 31 preceding the meeting at which the LTIP grant will be approved. Under no circumstances may the aggregate number of units granted to a single employee exceed the maximum applicable limit(s) under the LTIP. When approving grants to the executives, the Compensation Committee considers information or recommendations provided by the CEO, except with respect to the CEO’s own grants. The Compensation Committee utilizes outside compensation consultants to assist in the evaluation of grant recommendations. For the LTIP grants made during the 2006 fiscal year, the applicable NEO guideline percentages were as follows:
The long-term incentive compensation is based upon the common units representing limited partnership interests in the Partnership, although it may be payable in common units, or in cash. The accounting treatment for the long-term incentive compensation is specified by Statement of Financial Accounting Standards No.123 (Revised December 2004) “Share-Based Payment” (“SFAS123R”). The restricted units payable in the form of common units are valued using the price on the grant date, whereas those restricted units payable in cash are marked to market quarterly. The expenses for LTIP equity awards are recognized ratably over the vesting period, and are accelerated for vesting at retirement eligibility dates.
Unit Ownership Guidelines: Sunoco Partners LLC has established guidelines for the ownership of Partnership common units, applicable to its directors, executives and certain key employees. Under these guidelines, the independent directors must own Partnership common units having a market value at all times equal to at least three times their average annual compensation (including retainers and fees). The other directors must own at least 1,000 Partnership common units. For executives and certain other key employees, the applicable unit ownership guidelines are denominated as a multiple of base salary, and the amount of common units required to be owned increases with the level of responsibility, with the Chief Executive Officer expected to own common units with a value equal to at least five times base salary, and the senior executives (including the other NEOs) expected to own common units with a minimum value of between one and two times their base salary. The general partner and the Compensation Committee believe that the ownership of Partnership common units, as reflected in these guidelines, is an important means of tying the financial risks and rewards for such executives to the Partnership’s total unitholder return and better aligning the interests of such executives with those of the Partnership’s unitholders. Those key employees and executives, including the NEOs, who are subject to these unit ownership guidelines, but who have not yet met their respective guideline, must accumulate common units of the Partnership until such guideline is met. Except for sales of common units in settlement of
tax obligations relating to the receipt and payment of LTIP awards, such persons are prohibited from disposing of any common units of the Partnership until the applicable ownership guideline has been attained. However, those individuals who have exceeded their applicable ownership guideline may dispose of Partnership common units in a manner consistent with applicable law and Partnership policy, but only to the extent that such individual’s remaining ownership of Partnership common units would continue to meet the applicable ownership guideline.
Other Plans: Employees of the general partner and its affiliates, including the NEOs, also may participate in the following Sunoco benefit plans:
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Capital Accumulation Plan (“SunCAP”) is a defined contribution 401(k) plan, designed for long-term investment, to assist in accumulating funds for retirement. For employees having at least one year of service, the Partnership matches the first five percent of base pay contributed, on a dollar-for-dollar basis. The employee chooses from among various funds provided for investment of contributions, and matching contributions. An employee who terminates employment may elect to take a lump-sum distribution from the plan.
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Savings Restoration Plan is a non-qualified deferred compensation plan available to those SunCAP participants subject to compensation and/or contribution limitations under the Internal Revenue Code. Participants may contribute amounts in excess of the applicable limits, up to five percent of base salary. The amounts of the company match for the NEOs in 2006 under the Capital Accumulation Plan and the Savings Restoration Plan are included in the Summary Compensation Table on page 109 under “All Other Compensation” and are further described in the notes accompanying the table.
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Retirement Plan is a qualified defined benefit plan, under which benefits are subject to IRS limits for pay and amount. Under the Retirement Plan, executives hired before January 1, 1987 participate in a “final average pay” formula. Those executives hired on or after January 1, 1987 participate in a “cash balance” formula, which provides a benefit based on career pay rather than final average pay.
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Pension Restoration Plan is a non-qualified, unfunded plan that provides retirement benefits that otherwise would be provided under the Retirement Plan, except for the Internal Revenue Code limits.
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Executive Retirement Plan is a non-qualified, unfunded plan available to the NEOs which may provide to certain eligible executives supplemental pension benefits over and above an NEO’s benefits under the Retirement Plan and the Pension Restoration Plan. This plan was designed to attract mid-career senior executives by providing competitive retirement benefits and by accelerating benefit accruals for the first 12 years of service. Such benefits otherwise would not be available, due to the break in service when leaving a prior employer. Benefits under this plan are offset by those provided under the Retirement Plan and the Pension Restoration Plan.
The present values of each NEO’s accumulated pension benefit, as of year-end 2006 are included in the Pension Benefits Table on page 115. More detailed descriptions of the Retirement Plan, the Pension Restoration Plan and the Executive Retirement Plan are included in the narrative accompanying the table.
Other Benefits: Employees of the Partnership’s general partner and its affiliates, including the NEOs, participate in a variety of other benefits, including medical, dental, life insurance, disability, holidays and vacation. These benefits generally are provided on an enterprise-wide basis to employees of the general partner and its affiliates. The executives receive the same benefits at the same rates as other employees.
Perquisites. In 2006, the NEOs also received certain other personal benefits, or “perquisites,” including: financial counseling allowance (up to a maximum of $2,500 per year) that will be discontinued beginning January 1, 2007. Any unused portion of this allowance may not be carried over into 2007. The dollar amount of the perquisites received by the NEOs is included in the Summary Compensation Table on page 109, under “All Other Compensation.
Severance and Change-in-Control Benefits: An employee, including an NEO, is an employee at will. This means that the Partnership’s general partner may terminate employment at any time, with or without notice, and with or without cause or reason. Upon certain types of termination of employment and in the event of a change in control, certain benefits may be paid or provided to the NEOs.
The Partnership’s general partner is a participating employer in certain Sunoco plans that provide certain severance benefits to the general partner’s NEOs and other key management personnel. The Sunoco, Inc. Executive Involuntary Severance Plan provides severance benefits to executives involuntarily terminated other than for just cause, death or disability. In recognition of their past service, the plan is intended to alleviate the financial hardship that may be experienced by certain employees whose employment is terminated. The amount or kind of benefit to be provided is based on the executive’s position and compensation at the time of termination. Depending upon salary level, NEOs would receive severance payments ranging from one to one and one-half times base salary plus their guideline annual incentive in effect on the termination date.
The Sunoco Partners LLC Special Executive Severance Plan provides severance benefits in case of termination (whether actual or constructive and other than for just cause, death or disability) occurring within two years of a Change of Control of the Partnership, as defined in the plan. The plan was adopted to retain executives in the event of a major transaction or change in control, and to eliminate the uncertainty and questions which such a transaction may raise among management, and which may result in the departure or distraction of key management personnel to the detriment of the Partnership and/or the general partner. The general partner’s board of directors has determined that appropriate steps should be taken to reinforce and encourage the continued attention and dedication of key management personnel to their assigned duties without distraction. Severance under this plan would be payable in a lump sum, equal to three times annual compensation for the CEO, and two times annual compensation for the other NEOs. For these purposes, annual compensation consists of: (i) annual base salary in effect immediately prior to a change in control or immediately prior to the employment termination date, whichever is greater, plus (ii) the greater of annual guideline incentive in effect immediately before the change of control or employment termination date whichever is greater, or the highest bonus awarded in any of the three years ending prior to the change of control, or any subsequent year ending before the employment termination date.
Eligible executives under both the Involuntary Severance Plan and the Special Executive Severance Plan are entitled to medical coverage during the applicable severance period, at the same rate that such benefits are provided to active employees.
The Annual Incentive Plan provides that, upon a change in control, as defined in the plan, the participants will receive a pro rata portion of the annual incentive award based on the level of attainment of applicable performance targets.
The Sunoco Partners LLC Long-Term Incentive Plan provides that, upon a change in control, as defined in the plan, all awards of restricted units or unit options automatically vest and become payable or exercisable, as the case may be. Restricted units that have been outstanding for more than one year will be paid out at the greater of the target amount, or an amount in line with the Partnership’s actual performance immediately prior to the change in control. Those restricted units that have been outstanding for one year or less will be paid out at the target amount.
Additional information regarding these plans can be found under “Other Potential Post-Employment Payments” on page 118.
SUMMARY COMPENSATION TABLE
The Summary Compensation Table reflects the total compensation earned by the CEO, CFO and each of the three other most highly compensated executive officers of the general partner, during 2006:
NOTES TO TABLE:
(1)
The amounts shown in this column reflect the amounts recognized as compensation expense on the general partner’s financial statements at year-end 2006, relating to performance-based restricted unit awards under the Sunoco Partners LLC Long-Term Incentive Plan (“LTIP”), approved by the Compensation Committee at its regularly scheduled meeting in April, 2006, as well as similar expense for outstanding prior year awards, approved by the Compensation Committee at its regularly scheduled meetings in January 2005 and 2004, calculated in accordance with the requirements of Statement of Financial Accounting Standards No.123 (Revised December 2004) “Share-Based Payment” (“SFAS 123R”). Such compensation expense includes tandem distribution equivalent rights related to the restricted unit awards. These awards have a three-year restriction period. Compensation expense for the 2005 and 2006 awards was calculated assuming an eventual target payout of 100 percent. Compensation expense for the 2004 awards (which were paid out on February 8, 2007, in the form of common units) was calculated using the actual performance-adjusted payout percentage of 176.8 percent. At the time of filing of this report, Ms. Fretz and Mr. Justin are retirement eligible and the compensation expense for their 2006 awards has been accelerated, in accordance with SFAS 123R. See the “Compensation, Discussion and Analysis on page 102 for the specific performance measures applicable to the payout and vesting of these awards. These awards were granted with tandem distribution equivalent rights.
(2)
Although permitted by the terms of the LTIP, no Unit Options have been awarded at this time.
(3)
The amounts shown in this column reflect annual incentive amounts earned under the Sunoco Partners LLC Annual Incentive Plan, for performance during 2006, and payable on or before March 15, 2007.
(4)
The amounts shown in this column reflect the change in each NEO’s pension value between December 31, 2005 and December 31, 2006. The NEOs did not have any above-market or preferential payments on deferred compensation during 2006. Certain of the NEOs have deferred amounts under the Sunoco, Inc. Savings Restoration Plan, an excess 401(k) benefit plan available to employees of Sunoco and its subsidiaries such as the Partnership’s general partner. However, the earnings received
from participation in this plan are the same as dividends earned on Sunoco, Inc. common stock (in the case of the Sunoco stock-related funds), and/or are based on the gains/losses of certain mutual funds, which are calculated in the same manner and at the same rate of earnings as for all other employees invested in those funds in the SunCAP, the broad-based 401(k) qualified defined contribution plan for Sunoco and its subsidiaries.
(5)
The table below shows the components of this column for 2006:
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For Ms. Fretz, the amount shown for perquisites in 2006 includes: (1) an allowance for parking at the headquarters office; and (2) reimbursements for certain fees and dues relating to country and social club memberships (in addition to any such club memberships maintained for business purposes by the Partnership or its general partner.
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Sunoco Partners LLC, the Partnership’s general partner, is a participating employer in two Sunoco, Inc. defined contribution plans: (1) SunCAP, and (2) the Sunoco, Inc. Savings Restoration Plan, for executive-level SunCAP participants otherwise subject to certain Internal Revenue Code limitations on 401(k) plan contributions. The Savings Restoration Plan permits such participants to continue to receive matching contributions after exceeding the applicable limits.
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Basic life insurance coverage is provided to employees of the Partnership’s general partner, including the NEOs. The coverage/premium amount is one times base salary, at a monthly rate of $0.228 for each $1,000 of base salary.
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In 2006, the NEOs received perquisites including an allowance for financial counseling up to a maximum of $2,500 per year. The Partnership values the financial counseling benefit on the amount actually used. This annual financial counseling allowance was discontinued beginning on January 1, 2007, and any unused portion of the 2006 allowance could not be carried over into 2007. However, the NEOs were permitted to continue to use amounts accrued prior to 2005, until such balances are depleted. Mr. Oerton received a payment of $3,000, representing the balance of his financial counseling benefit, on October 13, 2006.
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For Mr. Oerton, the figure shown in the column captioned “Amounts Paid in Connection with Termination of Employment” represents cash severance benefits payable under the Sunoco, Inc. Executive Involuntary Severance Plan to Mr. Oerton, following his termination effective September 30, 2006, consisting of:
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78 weeks’ worth of annual base salary, increased by a portion of the applicable guideline, or target, annual bonus amount;
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vacation benefits accrued through his employment termination date ($8,870); and
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certain medical plan benefits (excluding dental coverage, but including COBRA continuation coverage) beginning as of October 1, 2006, and running for a period of 78 weeks.
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In compliance with Internal Revenue Code 409A, cash severance benefits for the period from September 30, 2006 to April 1, 2007, will be paid on April 1, 2007 in a lump sum of $165,576, plus simple interest at 5 percent (i.e., $4,140). Monthly payments of $27,596 will begin in May 2007 and continue through May 2008. A final severance payment of $13,798 will be made June 2008.
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The general partner provides certain NEOs with tax gross-ups for business club memberships and, through April 2006, for country club memberships, if any.
(6)
Ms. Fretz is a director of Sunoco Partners LLC, the Partnership’s general partner. However, she does not receive separate compensation for her service as a director.
(7)
Effective September 30, 2006, Mr. Oerton’s employment with the Partnership’s general partner was terminated. Mr. Oerton is included in the table since he was principal financial officer for part of the fiscal year ending December 31, 2006.
(8)
This figure represents the portion of the 2006 salary paid to Mr. Oerton, prior to the date of his termination.
(9)
All Mr. Oerton’s then-outstanding restricted units were forfeited upon his termination of employment with the Partnership’s general partner.
GRANTS OF PLAN-BASED AWARDS
The following table sets forth the grants of awards to the CEO, CFO and each of the three other most highly compensated executive officers of the Partnership’s general partner in 2006:
NOTES TO TABLE:
(1)
The annual incentive was awarded under the Sunoco Partners LLC Annual Incentive Plan. The annual incentive is paid out in cash, and any amounts earned for performance during the 2006 year will be paid out no later than March 15, 2007.
(2)
The performance-based restricted units were awarded under the Sunoco Partners LLC Long-Term Incentive Plan (“LTIP”) on April 17, 2006. These performance-based restricted units were granted with tandem distribution equivalent rights. Actual payout of these awards will depend upon the Partnership achieving certain specified performance levels, ranked against its peer group of companies, based upon equally weighted annual objectives for total unitholder return and growth cash distributions to unitholders. The portion of each award that may be earned during the performance period (which runs from January 1, 2006 to December 31, 2008) ranges from a threshold value of zero, to a target value
equal to 100 percent of the award, and a maximum value of 200 percent of the award. Payment of any amounts earned will occur following such period, assuming continued employment with the general partner at such time.
(3)
Amounts shown in this column reflect the grants of certain time-vested restricted units to NEOs granted during the 2006 fiscal year under the LTIP. The eventual payout of these grants may be made either in the form of cash or in common units, as determined at the time of grant by the general partner’s Compensation Committee. No such time-vested awards were granted during 2006.
(4)
Although permitted by the terms of the LTIP, no Unit Options have been awarded at this time.
(5)
Grant date fair value was calculated in accordance with SFAS 123R.
(6)
Effective September 30, 2006, Mr. Oerton’s employment with the Partnership’s general partner was terminated, and all his then-outstanding restricted units were forfeited at that time. Mr. Oerton is included in the table since he was principal financial officer for part of the fiscal year ending December 31, 2006.
OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END
The following table provides information concerning the unvested and outstanding equity awards to the CEO, CFO and each of the three other most highly compensated executive officers of the Partnership’s general partner in 2006:
NOTES TO TABLE:
(1)
Although permitted by the terms of the Sunoco Partners LLC Long-Term Incentive Plan (“LTIP”), no Unit Options have been awarded at this time.
(2)
Amounts shown in these columns reflect awards of time-vested restricted units (i.e., not performance-based), granted under the terms of the LTIP. On January 18, 2005, in connection with his hiring,
Mr. Keene was granted a one-time award of 2,436 restricted units, together with applicable distribution equivalent rights, pursuant to the LTIP; and the payout of this special award is contingent only upon Mr. Keene’s continued employment with the general partner through the end of the restriction period on December 31, 2007.
(3)
The market value or payout value of the unearned restricted units is based on the trading price of the common units, representing limited partnership interests in the Partnership, on December 29, 2006 of $50.56, and assumes a payout at the target of 100 percent.
(4)
These performance-based restricted units were awarded January 20, 2004, and the performance period ended on December 31, 2006. The number of units shown in the table reflects a payout percentage of 176.8 percent, applicable to the actual level of achievement of certain specified performance goals (based upon annual objectives for growth in cash flow per common unit, and total unitholder return ranked against peers) during the performance period. The Compensation Committee of the general partner’s Board of Directors approved the payout of these awards, in the form of common units, representing limited partnership interests in the Partnership, at its regularly scheduled January 26, 2007 meeting. These awards were paid out on February 8, 2007. Holders of these restricted units also received an amount equal to the cumulative cash distributions that would have been paid over the applicable performance period had he or she been the holder of record of a like number of common units. For Mr. Davis, the amounts shown also include the value of a special restricted unit award, granted in December 2003, in connection with his hiring, the payout of which was conditioned only upon his continued employment through the end of a restriction period running from January 1, 2004 through December 31, 2006, and the related cumulative distribution equivalents. The number of restricted units earned by Mr. Davis upon vesting of this special award was 4,514 units.
(5)
These performance-based restricted units were awarded January 18, 2005, and the performance period ends on December 31, 2007. Actual payout of these awards will depend upon the Partnership achieving certain specified performance levels, based upon annual objectives for growth in cash flow per common unit, and total unitholder return ranked against its peer group of companies. The portion of each award that may be earned during the performance period ranges from a threshold value of zero, to a target value equal to 100 percent of the award, and a maximum value of 200 percent of the award. Payment of any amounts earned will occur following such period, assuming continued employment with the general partner at such time. At the end of the performance period, to the extent that the performance-based restricted units are paid out, each holder of performance-based restricted units also will receive an amount equal to the cumulative cash distributions that would have been paid over the performance period had he or she been the holder of record of common units, representing limited partnership interests in the Partnership, equal to the number of the performance-based restricted units, if any, paid out.
(6)
These performance-based restricted units were awarded April 17, 2006, and the performance period ends on December 31, 2008. Actual payout of these awards will depend upon the Partnership achieving certain specified performance levels, ranked against its peer group of companies, based upon total unitholder return and growth in cash distributions to unitholders. The portion of each award that may be earned during the performance period ranges from a threshold value of zero, to a target value equal to 100 percent of the award, and a maximum value of 200 percent of the award. Payment of any amounts earned will occur following such period, assuming continued employment with the general partner at such time. At the end of the performance period, to the extent that the performance-based restricted units are paid out, each holder of performance-based restricted units also will receive an amount equal to the cumulative cash distributions that would have been paid over the performance period had he or she been the holder of record of common units, representing limited partnership interests in the Partnership, equal to the number of the performance-based restricted units, if any, paid out.
(7)
Effective September 30, 2006, Mr. Oerton’s employment with the Partnership’s general partner was terminated, and all his then-outstanding restricted units were forfeited at that time. Mr. Oerton is included in the table since he was principal financial officer for part of the fiscal year ending December 31, 2006.
OPTION EXERCISES AND STOCK VESTED
The following table provides information concerning the amounts related to the vesting, during 2006, of certain awards for the CEO, CFO and each of the three other most highly compensated executive officers of the Partnership’s general partner in 2006, upon the exercise of unit options, or vesting of restricted units, previously awarded under the Sunoco Partners LLC Long-Term Incentive Plan (“LTIP”):
NOTES TO TABLE:
(1)
Although permitted by the terms of the LTIP, no Unit Options have been awarded at this time.
(2)
Amounts shown in this column reflect the vesting and payout of performance-based restricted unit awards granted in January 2004 under the LTIP, and the Partnership’s level of attainment of certain performance goals over the three-year performance period running from January 1, 2004 through December 31, 2006. The value upon vesting was determined by multiplying (i) the product of the target number of such restricted units and the applicable performance factor (176.8 percent) at the end of the performance period; by (ii) the closing market price of the Partnership’s common units on the last trading day before the units were paid out ($55.99), and then adding the cumulative cash value of earned distribution equivalents. The performance measures for these awards were growth in operating cash flow, and total unitholder return during the performance period. The price of the Company’s stock at the time of the award was $37.00.
(3)
Amounts shown in this column do not include the following amounts paid out in respect of the earned cumulative distribution equivalents on the restricted units:
(4)
Effective September 30, 2006, Mr. Oerton’s employment with the Partnership’s general partner was terminated, and all his then-outstanding restricted units were forfeited at that time. Mr. Oerton is included in the table since he was principal financial officer for part of the fiscal year ending December 31, 2006.
(5)
Mr. Keene’s employment with the Partnership’s general partner began in January 2005 following the 2004 grant of the restricted units shown in the table.
(6)
For Mr. Davis, the amounts shown include:
a. the value of a special restricted unit award, granted in December 2003, in connection with his hiring, the payout of which was conditioned only upon his continued employment through the end of a restriction period running from January 1, 2004 through December 31, 2006, and the related cumulative distribution equivalents. The number of restricted units earned by Mr. Davis upon vesting of this special award was 4,514 units, with an aggregate cash value of $252,739 (calculated using a value of $55.99 per unit, which is the closing market price of the Partnership’s common units on the last trading day before the units were paid out); and
b. the value of the earned distribution equivalents related to this special award (i.e., $36,879).
PENSION BENEFITS
Sunoco Partners LLC, the Partnership’s general partner, is a participating employer in certain Sunoco pension and retirement plans, and the NEOs are eligible to participate in such plans. Benefits under these plans are calculated based on cash compensation including both base pay and annual incentives. This table shows the estimated annual retirement benefits payable to a covered executive based upon the final average pay and/or career pay formulas of the Sunoco, Inc. Retirement Plan (“SCIRP”), the Sunoco, Inc. Pension Restoration Plan, and the Sunoco, Inc. Executive Retirement Plan (“SERP”). Executives who participate in these plans may elect to receive their accrued benefits in the form of either a lump sum or an annuity. The estimates shown in the table below assume that benefits are received in the form of a single lump sum at retirement. These estimates do not take into account potential future increases in base salary, or future bonuses that may be paid.
NOTES TO TABLE:
(1)
Credited years of service reflect actual service with the general partner, including years of service credited with Sunoco prior to the Partnership’s initial public offering in February 2002.
(2)
Actuarial present value of benefits is calculated by estimating expected future payments starting at an assumed retirement age, weighting such payments by the probability of surviving to each post-retirement age, and discounting the weighted payments at an assumed discount rate to reflect the time value of money. The actuarial present value represents the amount which, if invested as of
December 31, 2006 at a 5.85% discount rate, would be sufficient to provide estimated future payments based on the current accumulated benefit. Estimated future payments are assumed to be in the form of a single lump sum payment at retirement. The interest rate assumed for lump sum payments is 4.85% and the lump sum mortality table is derived from current IRS regulations for qualified pension plans. For NEOs, the assumed retirement age is 60 (i.e., the earliest age at which the executive could retire without any benefit reduction due to age), or actual age, if older than 60. Actual benefit present values may vary from these estimates, depending upon actual retirement age, final service, future compensation levels, interest rate movements and regulatory changes.
The Sunoco, Inc. Retirement Plan
The Sunoco, Inc. Retirement Plan (“SCIRP”) is a qualified defined benefit retirement plan that covers salaried and hourly employees, including the NEOs. SCIRP provides for normal retirement at age 65. The plan includes two benefit formulas:
(1) Final Average Pay formula.
•
Benefit equals 1 2/3 percent of Final Average Pay (the average earnings during the 36 consecutive months of highest earnings in the last ten years prior to retirement) multiplied by the credited service up to 30 years, plus 3/4 percent of final average pay multiplied by the credited service over 30 years.
•
The amount is then reduced by 1 2/3 percent of the estimated Social Security Primary Insurance amount multiplied by the credited years of service up to a maximum of 30 years.
•
The Final Average Pay benefit is reduced by 5/12 percent for each month that retirement precedes age 60 (down to age 55), with the early retirement benefit at age 55 being 75 percent of the unreduced Final Average Pay benefit.
(2) Career Pay (cash balance) formula.
•
The benefit is expressed as an account balance, which is comprised of pay credits and indexing adjustments.
•
Pay credits equal 7 percent of pay for the year up to the Social Security (FICA) Wage Base ($94,200 in 2006) plus 12 percent of pay for the year that exceeds the Wage Base.
•
The indexing adjustment equals the account balance at the end of each month multiplied by the monthly change in the All-Urban Consumer Price Index, plus 0.17 percent. However, if in any month the adjustment would be negative, the adjustment would be zero for such month.
For employees, including NEOs, hired before January 1, 1987 (Ms. Fretz), the benefits under SCIRP are the greater of the Final Average Pay or Career Pay formula benefits. An employee may retire at the Normal Retirement Age of 65 regardless of years of service with Sunoco, or may retire as early as age 55 with 10 years of service. All employees hired before January 1, 1987 are 100 percent vested in their benefits. For employees, including NEOs, hired on or after January 1, 1987 (Messrs. Keene, Davis and Justin), retirement benefits are calculated under the Career Pay formula only. An employee may retire at the Normal Retirement Age of 65, or may retire as early as age 55 with 10 years of service. An employee is 40 percent vested in his or her benefit after completing two years of eligible service, with the vested portion increasing in 20 percent increments each year until it reaches 100 percent at five years.
The normal form of benefit under SCIRP is an annuity for the life of the employee, with 50 percent of that annuity paid for the life of the employee’s surviving spouse (50 percent Joint and Survivor Benefit). This 50 percent Joint and Survivor benefit is free for participants who benefit under the Final Average Pay formula, but is reduced actuarially for participants who benefit under the Career Pay formula. Other forms of payment are also offered such as a lump sum and other annuity options. Under the Career Pay formula, the lump sum is equal to
the value of the employee’s account, and under the Final Average Pay formula, the lump sum is the actuarial equivalent of the annuity benefit, based on Internal Revenue Service prescribed interest rates and mortality tables.
SCIRP is subject to qualified plan Internal Revenue Code (“Code”) limits on the amount of annual benefit that may be paid, and on the amount of compensation that may be taken into account in calculating retirement benefits, under the plan. For 2006, the limit on the compensation that may be used was $220,000, and will be $225,000 for 2007. The limit on annual benefits payable for an employee retiring in 2006 was $175,000, and for 2007 is $180,000. Benefits in excess of those permitted under the statutory limits are paid from the Pension Restoration Plan, described below.
The amounts presented in the table above are actuarial present values based on accrued annual benefits, using pay and service through December 31, 2006. If the benefit is paid in a lump sum, the actual amount distributed would vary depending on the actual interest rate and the mortality assumptions used to calculate the distribution at the time of retirement. The lump sum conversion mortality table and the method for selecting lump sum conversion interest rate is due to change in 2008 under the Pension Protection Act of 2006. It is not known at this time, what impact this change will have on lump sum distributions. The estimated amounts above do not take into account potential future changes in base salary, the annual guideline incentive opportunity, or future annual incentives that may be paid as a result of Partnership performance.
Pension Restoration Plan
The Pension Restoration Plan is a non-qualified plan that provides retirement benefits that would be provided under SCIRP, but are prohibited from being paid from SCIRP by the Code limits. (See the discussion regarding SCIRP above for the limits.) The benefit paid by the Pension Restoration Plan is the excess of the total benefit accrued under SCIRP over the amount of benefit that SCIRP is permitted to provide under the Code. All benefits under the Pension Restoration Plan are paid in a lump sum calculated using the same actuarial factors applicable under SCIRP. Payment of benefits is made upon termination of employment, except that payment of amounts subject to Code Section 409A is delayed until six months after separation from service for any specified employee as defined under Code Section 409A.
Sunoco, Inc. Executive Retirement Plan
The Sunoco, Inc. Executive Retirement Plan (“SERP”) is a non-qualified defined benefit plan that may cover certain executive employees, including the NEOs. The SERP may provide pension benefits over and above an NEO’s benefits under SCIRP and the Pension Restoration Plan. All SERP benefits are offset by SCIRP and Pension Restoration Plan benefits. NEOs hired before 1987 (Ms. Fretz) generally will not receive a SERP benefit at retirement, since their SCIRP and Pension Restoration Plan benefits at retirement will equal or exceed their SERP benefits. An NEO must be at least 55 years old with five years of qualifying executive service, to be eligible for a SERP retirement benefit.
For Mr. Justin, the SERP benefit (before offset by SCIRP and Pension Restoration Plan benefits) equals the highest benefit resulting from three calculations:
(1) SCIRP Final Average Pay formula (described above).
(2) Minimum Benefit formula.
•
The benefit equals 3 1/3% of final average pay multiplied by credited service up to 12 years, with the maximum benefit under this formula equal to 40 percent of final average pay.
•
The minimum benefit is reduced by 5/12 percent for each month that retirement precedes age 60 (down to age 55), with the early retirement benefit at age 55 being 75 percent of the unreduced minimum benefit.
•
The minimum benefit is offset by the value of benefits paid by a prior employer’s qualified and non-qualified retirement plans.
(3) Executive Service formula.
•
The benefit equals 2 1/4 percent of final average pay multiplied by length of executive service, with the maximum benefit under this formula equal to 50 percent of final average pay.
•
The executive service benefit is reduced by 5/12 percent for each month that retirement precedes age 62 (down to age 55), with the early retirement benefit at age 55 being 65 percent of the unreduced executive service benefit. There is no reduction when payments start at age 62 or later.
•
Executive service means service with the Partnership’s general partner while the participant was an executive level employee. In the case of principal officers who become participants after December 31, 2002, executive service includes only service while a principal officer.
SERP benefits are paid in a lump sum calculated using the same actuarial factors applicable under SCIRP, with payment delayed until six months after separation from service, pursuant to Code Section 409A for any specified employee as defined in Code Section 409A. The two non-qualified plans are unfunded. The benefits from the non-qualified plans are paid from general assets that are subject to the claims of Sunoco’s general creditors under federal and state law in the event of insolvency.
OTHER POTENTIAL POST-EMPLOYMENT PAYMENTS
Certain plans, described below, provide for payments of benefits to the NEOs in connection with termination, or separation from employment, or a change in control of the Partnership’s general partner. The following describes the benefits that the NEOs would receive it such event occurred. The actual amounts paid can be determined only at the time of such NEO’s separation from employment with the Partnership’s general partner.
Retirement: The benefits paid to the NEOs upon retirement are described above, on pages 115 through 118.
Voluntary Termination: An NEO who resigns and leaves voluntarily, would receive the following benefits:
•
Sunoco, Inc. Retirement Plan (“SCIRP”): Retirement eligible NEOs hired prior to January 1, 1987 (Ms. Fretz) will receive benefits based upon the Final Average Pay formula of the SCIRP, which is a qualified defined benefit retirement plan. Effective January 1, 1987, for employees hired subsequent to that date, the SCIRP was converted from a final average pay plan to a cash balance pension plan. SCIRP benefits for NEOs hired after this conversion (Messrs. Keene, Davis and Justin) are calculated using the Career Pay formula, based on a percentage of pay each year and an indexing adjustment. Normal retirement age under the SCIRP is 65 years. To the extent that the amount payable exceeds the amount available under SCIRP, the remaining amount would be paid under the Pension Restoration Plan.
•
Sunoco, Inc. Executive Retirement Plan (“SERP”): The SERP provides pension benefits over and above benefits available under the SCIRP to participants who are at least 55 years of age, with a minimum of five (5) years service as an executive. SERP benefits are offset by benefits payable under other qualified or non-qualified plans of Sunoco, Inc. The maximum benefit payable under any SERP formula cannot exceed 50% of final average earnings. Under the terms of the SERP, only Mr. Justin would be eligible to receive benefits under this plan.
•
Sunoco Partners LLC Long-Term Incentive Plan: Under the LTIP, if an NEO is not retirement eligible, outstanding performance-based restricted units will be cancelled as of the termination date. If the NEO is eligible for retirement, unvested restricted units would continue to vest, and will pay out if the performance measures are met. If the NEO voluntarily terminates employment prior to December 31 of the plan year, other than by retirement, the NEO will not receive any incentive award for that year.
•
Vacation Benefits: Each NEO will be entitled to receive an amount for his or her accrued vacation, which benefit is generally provided to active employees of the Company.
Involuntary Termination:
•
Sunoco, Inc. Executive Involuntary Severance Plan (“Involuntary Severance Plan”): Executives whose employment is terminated by the Partnership’s general partner, other than for just cause, or as a result of death or disability, receive a severance allowance under the Involuntary Severance Plan. The Partnership’s general partner is a participating employer in this plan, and the plan is available to the general partner’s NEOs and certain other executive level employees. However, any NEO receiving benefits under SERP would not also be eligible to receive benefits under this plan. The following is a summary of the benefits available under this plan:
•
In the case of the CEO, severance payments would be for a period of one and one half (1 1/2) years of and equal to base salary for that period, plus guideline annual incentive in effect on the termination date, as defined in the plan.
•
The other NEOs would receive severance payments for periods ranging from one (1) to one and one-half (1 1/2) years of base salary plus guideline annual incentive, depending upon employment grade level.
•
Each NEO will be entitled to medical coverage for up to the period of severance received, at the same rate that such benefits are generally provided to active employees.
•
If an NEO is not retirement eligible, outstanding performance-based restricted units will be cancelled as of the termination date. If the NEO is eligible for retirement, unvested restricted units would continue to vest, and will pay out if the performance measures are met.
•
The NEOs would receive a cash amount in lump sum equal to the NEO’s earned vacation through the end of his or her employment termination date as defined in the plan.
At a regularly scheduled meeting on January 26, 2007, the Compensation Committee of the general partner’s board of directors voted to adopt the Sunoco Partners LLC Executive Involuntary Severance Plan, the terms and provisions of which are essentially identical to those described above.
•
Sunoco, Inc. Retirement Plan (“SCIRP”): NEOs hired prior to January 1, 1987 (Ms. Fretz) will receive benefits based upon the Final Average Pay formula of the SCIRP. SCIRP benefits for NEOs hired after the January 1, 1987 conversion of SCIRP from a final average pay plan to a cash balance pension plan (Messrs. Keene, Davis and Justin), are calculated using the Career Pay formula. To the extent that the amount payable exceeds the amount available under SCIRP, the remaining amount would be paid under the Pension Restoration Plan.
•
Sunoco, Inc. Executive Retirement Plan (“SERP”): SERP benefits are offset by benefits payable under the SCIRP and Pension Restoration Plan. Under the terms of the SERP, only Mr. Justin would be eligible to receive benefits under this plan.
Change of Control:
•
Sunoco Partners LLC Special Executive Severance Plan: This plan was adopted to retain executives in the event of a change of control, and to eliminate the distraction and uncertainty such a transaction may create among management personnel, to the detriment of the organization. Payment of severance benefits under this plan provides severance allowances to executives whose employment is terminated in connection with, or following, a change of control. A “change of control” is defined as any one or more of the following events:
•
a transaction pursuant to which more than 50 percent of the combined voting power of the outstanding equity interests in the general partner cease to be owned by Sunoco, Inc. and its affiliates;
•
a “Change in Control” of Sunoco, Inc., as defined from time to time in the Sunoco, Inc. stock plans; or
•
the general partner of the Partnership ceases to be an affiliate of Sunoco.
There is a “double trigger” mechanism for the payment of severance benefits under this plan, requiring both a change of control, and a qualifying termination of employment (as defined in the plan)
following such change of control, prior to the payout of any severance benefits under this plan. Severance benefits under this plan are paid in a lump sum equal to three times annual compensation for the CEO, and two times annual compensation for the other NEOs. For these purposes, annual compensation consists of:
•
the executive’s annual base salary in effect immediately prior to a change of control or immediately prior to the employment termination date, whichever is greater, plus
•
the greater of 100 percent of the executive’s annual incentive guideline in effect immediately before the change of control or employment termination date, whichever is greater, or the highest annual incentive awarded to the NEO in any of the three years ending before the change of control or in any subsequent year ending before the employment termination date.
Each NEO will be entitled to medical, dental and life insurance coverage for the period of severance received, at the same rate that such benefits are generally provided to active employees of the general partner. In the case of a change of control, the plan also provides for the protection of certain pension benefits and reimbursement for any additional tax liability incurred as a result of excise taxes imposed on payments deemed to be attributable to the change in control.
•
Sunoco, Inc. Retirement Plan (“SCIRP”): In the event of a change of control, the benefits of a participant whose employment began before September 5, 2001, and who is terminated (as defined in the plan) following a change in control, become 100 percent vested and are increased as follows:
•
Final Average Pay formula. A participant’s service is increased by three years, subject to reduction for service after the change in control. Final Average Pay will be the greater of (A) the regularly determined Final Average Pay, (B) Final Average Pay based on earnings of the month preceding the change in control, or (C) Final Average Pay based on earnings for the month preceding the termination of employment. For purposes of (B) and (C) monthly earnings will include base pay and 1/12 of the unadjusted annual guideline bonus under the Sunoco Partners LLC Annual Incentive Plan.
•
Career Pay (cash balance) formula. A participant’s service is increased by three years, subject to reduction for service after the change in control. In the month of termination, a participant’s Career Pay Earnings are increased by an amount equal to 36 months less the number of months worked after the Change in Control, times the greater of Career Pay Earnings for (A) the month preceding termination or (B) the month preceding the change in control. For purposes of (A) and (B) monthly earnings will include base pay and 1/12 of the annual guideline bonus under the Sunoco Partners LLC Annual Incentive Plan.
•
Sunoco, Inc. Executive Retirement Plan (“SERP”): Under SERP, after a change of control and qualifying termination (as defined in the plan) (a “double trigger”), a participant becomes 100 percent vested in his SERP benefit. The following provisions also apply:
•
A participant’s service is increased by three years, subject to reduction for service following the change in control.
•
Final average pay at termination is no less than final average pay at the time of the change in control. In the case of a participant under age 55 at the time of termination, the change in control benefit will equal the benefit that would have been paid at age 55.
•
The benefit will be paid in a lump sum six months after separation from service with Sunoco pursuant to Internal Revenue Code Section 409A.
•
Sunoco Partners LLC Annual Incentive Plan: If a change of control occurs, an NEO will receive a pro rata portion of the annual incentive based on level of attainment of applicable performance targets.
•
Sunoco Partners LLC Long-Term Incentive Plan: If a change of control occurs, all outstanding restricted units become fully vested. The units that have been outstanding for more than one year will be paid out at the greater of target or an amount in line with actual performance results. The units that have been outstanding for less than one year will be paid out at target. Retention-based units will be paid out at as awarded.
DIRECTOR COMPENSATION
Directors, who are employees of Sunoco Partners LLC, Sunoco, and their respective affiliates, including the CEO, receive no additional compensation for service on the general partner’s board of directors or any committees of the board.
Compensation Philosophy: The general partner’s board of directors believes that the compensation program for directors who are not employees of Sunoco Partners LLC, Sunoco, or their respective affiliates (“non-employee directors”) should be designed to attract experienced and highly qualified individuals; provide appropriate compensation for their commitment and contributions to the Partnership and its unitholders; and align the interests of the non-employee directors and unitholders. The general partner’s board of directors engages a third-party compensation consultant each year to benchmark director compensation against the Partnership’s performance peer group, other pipeline companies, and general industry. The director compensation consultant provides advice regarding “best practices” and trends in director compensation. Non-employee directors are compensated partly in cash and partly in the common units, representing limited partnership interests, of the Partnership. Currently, equity-based compensation represents a substantial portion of the total compensation package.
Retainers and Fees: During 2006, non-employee directors received an annual retainer of $17,500 in cash, paid quarterly, and a number of restricted units paid quarterly under the Sunoco Partners LLC Long-Term Incentive Plan. These restricted units had an aggregate fair market value equal to $17,500 on an annual basis (the fair market value of each quarterly payment of restricted units is calculated as of the payment date). These restricted units are required to be deferred, and are credited to each non-employee director’s mandatory deferred compensation account in the Directors’ Deferred Compensation Plan. Amounts thus deferred in the form of restricted units are treated as if invested in common units of the Partnership, and include a credit for distribution equivalent rights (in the form of additional restricted units), credited on the applicable date(s) for Partnership cash distributions. Also in 2006, the members of the Audit/Conflicts Committee were paid a $20,000 cash retainer in connection with their review of the acquisition, from affiliates of Sunoco, of a 55.3 percent interest in the Mid-Valley Pipeline Company joint venture. During 2006, the chairman of the Audit/Conflicts Committee received an annual committee chair retainer of $6,500 in cash, and the chairman of the Compensation Committee received an annual chair retainer of $2,500 in cash. In addition, the non-employee directors received fees of $1,500 in cash for each board meeting attended, and $1,000 in cash for each committee meeting attended.
Directors’ Deferred Compensation Plan: Directors are voluntarily permitted to defer all or a portion of their cash retainers and fees under the Sunoco Partners LLC Directors’ Deferred Compensation Plan. Voluntarily deferred cash compensation amounts are credited in the form of restricted units, the value of which varies as though invested in common units of the Partnership. Amounts voluntarily deferred in the form of restricted units also are credited with distribution equivalent rights (in the form of additional restricted units), on the applicable date(s) for Partnership cash distributions. Payments of compensation deferred under the Directors’ Deferred Compensation Plan are restricted in terms of the earliest and latest dates that payments may begin. All deferrals, whether mandatory or voluntary, will be paid out in cash.
Business Expenses: Each non-employee director is reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or committees, including room, meals and transportation to and from the meetings. When traveling on Partnership business, a director occasionally may be accompanied by a spouse. At times, a director may travel to and from board and/or committee meetings on the corporate aircraft of Sunoco, Inc. Directors may be reimbursed for attendance at qualified third-party director education programs.
Directors’ Unit Ownership Guidelines: Each non-employee director is expected to own common units, representing limited partnership interests in the Partnership, with a market value equal to at least three times the total (cash and restricted unit) annual retainer and board/committee meeting fees. Directors who do not meet the criteria for independence established by the New York Stock Exchange must own at least one
thousand (1,000) Partnership common units. Included in the determination of unit ownership for purposes of these guidelines are all common units beneficially owned, as well as any restricted units in the Directors’ Deferred Compensation Plan. New directors are allowed a five-year phase-in period to comply with the guidelines.
Indemnification: Each director will be indemnified fully by the Partnership for actions associated with being a director to the extent permitted under Delaware law.
The following table reflects the compensation actually earned by each of the non-employee directors of the Partnership’s general partner during fiscal year 2006:
NOTES TO TABLE:
(1)
The amounts shown in this column reflect aggregate cash payments to directors in 2006, including: the annual cash retainer ($17,500) for outside directors; a special “conflicts” committee retainer ($20,000) for Audit/Conflicts Committee members; regular and special board meeting fees (totaling $7,500 for each director); committee meeting fees (totaling $13,000 for each director); and, as applicable, committee chair retainers ($6,500 for the Audit/Conflicts Committee and $2,500 for the Compensation Committee). Pursuant to the Sunoco Partners LLC Directors’ Deferred Compensation Plan, the directors are permitted voluntarily to defer, all or a portion of their fees and/or retainers. These amounts are deferred in the form of restricted units. As of December 31, 2006, the following directors had the following aggregate numbers of restricted units accumulated in their respective voluntary deferred compensation accounts for their years of service (these figures include distribution equivalents credited to such accounts in the form of additional restricted units):
• L. W. Berry, Jr.:
2,277
• G. W. Edwards:
1,850
(2)
The amounts shown in this column reflect the dollar value of the portion of the annual retainer (approximately half) that is paid quarterly, in the form of restricted units issued pursuant to the LTIP during 2006 calculated in accordance with the requirements of Statement of Financial Accounting Standards No.123 (Revised December 2004) “Share-Based Payment” (“SFAS 123R”). For each director, this restricted unit retainer is automatically and mandatorily deferred, in accordance with terms of the Sunoco Partners LLC Directors’ Deferred Compensation Plan. As of December 31, 2006, these directors had the following aggregate numbers of restricted units accumulated in their respective mandatory deferred compensation accounts as a result of the mandatory deferrals of the restricted unit retainer for their years of service (these figures include distribution equivalents credited to such accounts in the form of additional restricted units):
• L. W. Berry, Jr.:
1,688
• S. L. Cropper:
2,011
• G. W. Edwards:
2,010
(3)
Although permitted by the terms of the LTIP, no Unit Options have been awarded to directors at this time.
(4)
Amounts shown in this column include distribution equivalents earned on deferred compensation during 2006, and imputed income realized due to life insurance ($137) and travel/accident insurance benefits ($24). The life insurance and travel accident insurance benefit for directors was eliminated in 2007.
(5)
In 2006, Mr. Cropper was Chair of the Audit/Conflicts Committee, and Mr. Edwards was Chair of the Compensation Committee.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
There are no compensation committee interlocks.
COMPENSATION COMMITTEE REPORT
The Compensation Committee (the “Committee”) of the Board of Directors of Sunoco Partners LLC (the “Company”) reviews and approves the Company’s executive compensation philosophy; reviews and recommends to the Board for approval the Company’s short-term and long-term compensation plans; reviews and approves the executive compensation programs and awards; and annually reviews, determines and approves the compensation for the Chief Executive Officer (“CEO”) and the other executive officers (collectively, the “Named Executive Officers” or “NEOs”) of the Company named in the Summary Compensation Table contained in the Annual Report on SEC Form 10-K of Sunoco Logistics Partners L.P. (the “Partnership”). The Company is the general partner of the Partnership. The Committee Chair reports committee actions, decisions and recommendations at the meetings of the full Board. The Committee has authority to directly engage and consult outside advisors, experts and others to assist the Committee at the expense of the Partnership.
As required by applicable regulations of the Securities and Exchange Commission, the Committee has reviewed the executive compensation disclosures contained in the report captioned “Compensation Discussion and Analysis,” which report is required pursuant to Item 402(b) of SEC Regulation S-K, as amended. As part of this review, the Committee met with management and with such outside consultants and experts as it has deemed necessary or advisable (with and without management present), to discuss the scope and overall quality of the disclosure.
In reliance on the reviews and discussions referred to above, the Committee recommended to the Board of Directors, and the Board has approved, the inclusion of the “Compensation Discussion and Analysis” in the Partnership’s Annual Report on SEC Form 10-K for the fiscal year ended December 31, 2006, for filing with the Securities and Exchange Commission.
Respectfully submitted on February 23, 2007 by the members of the Compensation Committee of the Board of Directors of Sunoco Partners LLC:
Gary W. Edwards (Chair)
L. Wilson Berry, Jr.
Stephen L. Cropper
John G. Drosdick
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SECURITYHOLDER MATTERS
Securities Authorized for Issuance Under Equity Compensation Plans
The following table provides information, as of December 31, 2006, regarding Partnership common units that may be issued upon conversion (assuming a one-for-one conversion) of outstanding restricted units granted under the general partner’s LTIP to executive officers and other key employees. For more information about this plan (which did not require approval by the Partnership’s limited partners at the time of its adoption in 2002), refer to “Item 11 - Executive Compensation.”
EQUITY COMPENSATION PLAN INFORMATION(1)
NOTES TO TABLE:
(1)
The amounts in column (a) of this table reflect only restricted units that have been granted under the LTIP, since the inception of the plan. No unit options have been granted. Each restricted unit shown in the table represents a right to receive (upon vesting and payout) a specified number of Partnership common units. Vesting and payout may be conditioned upon achievement of pre-determined financial or other performance objectives for, or attainment of certain length of service goals with, the Partnership and its affiliates. No value is shown in column (b) of the table, since the restricted units do not have an exercise, or “strike,” price. For illustrative purposes, a maximum payment (i.e., a 200 percent ratio) has been assumed for vesting and payout of performance-related grants, and a target payout (i.e., a 100 percent ratio) has been assumed for vesting and payout of grants conditioned only upon length of service.
Beneficial Ownership Table
The following table sets forth the beneficial ownership of common units of Sunoco Logistics Partners L.P., by directors of Sunoco Partners LLC (the general partner), by each named executive officer and by all directors and officers of Sunoco Partners LLC as a group as of December 31, 2006. Unless otherwise noted, each individual exercises sole voting or investment power over the Partnership common units shown in the table. For purposes of this table, beneficial ownership includes Partnership common units as to which the person has sole or shared voting or investment power, as well as: (a) those Partnership common units actually acquired by LTIP participants as a result of the payout on February 8, 2007, of performance-based restricted units awarded January 20, 2004 which vested on December 31, 2006; and (b) any additional Partnership common units that a person has the right to acquire within 60 days of December 31, 2006, through the conversion of restricted units. During 2006, Sunoco Partners LLC was owned by the following members: Sun Pipe Line Company (67%); Sunoco, Inc. (R&M) (13%); and Atlantic Refining & Marketing Corp. (20%), each of which is a direct or indirect wholly-owned subsidiary of Sunoco, Inc.
* Less than 0.5 percent.
NOTES TO TABLE:
(1)
The address of each beneficial owner named above is: 1735 Market Street, Suite LL, Philadelphia, PA 19103.
(2)
The figures shown in the table reflect the conversion on February 15, 2007, of 5,691,819 subordinated units to common units in accordance with the partnership agreement. The number of subordinated units converted represented 50 percent of the amount originally issued in February 2002, in connection with the Partnership’s initial public offering. Following this conversion, there are no subordinated units outstanding.
(3)
The amounts shown in this column represent the balance, as of December 31, 2006, of restricted units credited to the respective deferred compensation accounts established for each non-employee director pursuant to the terms of the Sunoco Partners LLC Directors Deferred Compensation Plan. These restricted units cannot be converted to common units of the Partnership, and will be paid out in cash (as a lump sum or series of installments), commencing on: (1) the later of: (a) the first day of the calendar year following the date of separation from Board service, or (b) the first day following the six (6) month anniversary of separation from Board service; or (2) in the event of death, the later of: (a) the first day of the calendar year following the year of death, (b) the first day following the six (6) month anniversary of separation from Board service, or (c) the date that is thirty (30) days after the Participant’s death. In no event will payment be made within six (6) months of the compensation being earned or awarded. A portion of these restricted units, credited quarterly to each such director’s mandatory deferred compensation account, reflects payment of the applicable board restricted unit retainer.
(4)
Sunoco, Inc. is the ultimate parent company of Sunoco Partners LLC and may, therefore, be deemed to beneficially own the units that are held by Sunoco Partners LLC.
In addition to the foregoing, Tortoise Capital Advisors LLC, a Delaware limited liability company (“TCA”), filed a Schedule 13G on February 13, 2007, to report that, as of December 31, 2006, it had shared voting power over 1,906,785 common units of the Partnership, and beneficial ownership of, and shared dispositive power over, 1,973,153 common units of the Partnership, representing 8.6 percent of the total outstanding common units of the Partnership, as of that date. Of these units, 934,625 were held by an affiliate, Tortoise Energy Infrastructure Corporation, a Maryland corporation, and the remainder were held by certain closed-end investment companies, and in managed accounts, for each of which TCA acts as investment advisor.
The following table sets forth certain information regarding beneficial ownership of Sunoco, Inc.’s common stock, as of December 31, 2006, by directors of Sunoco Partners LLC, by each named executive officer and by all directors and officers of Sunoco Partners LLC as a group. Unless otherwise noted, each individual exercises sole voting or investment power over the shares of Sunoco, Inc. common stock shown in the table. For purposes of this table, beneficial ownership includes shares of Sunoco, Inc. common stock as to which the person has sole or shared voting or investment power and also any shares of Sunoco, Inc. common stock that such person has the right to acquire within 60 days of December 31, 2006, through the exercise of any option, warrant, or right.
* Less than 0.5 percent.
NOTES TO TABLE:
(1)
The amounts shown include 12,237 shares of Sunoco, Inc. common stock held by certain officers (not including the named executive officers), and 18,400 shares of Sunoco, Inc. common stock that such officers have the right to acquire through the exercise of stock options within 60 days after December 31, 2006 under certain Sunoco, Inc. plans.
(2)
The number of shares of Sunoco, Inc. common stock beneficially owned by the following directors and officers of the general partner include the shares of such stock (set forth below) that these persons have the right to acquire through the exercise of stock options within sixty (60) days after December 31, 2006 under certain Sunoco, Inc. plans:
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
As of December 31, 2006, the general partner owned 6,371,915 common units and 5,691,819 subordinated units, representing a 42.3 limited partner interest. Following the conversion of certain subordinated units to common units on February 16, 2007, the general partner now owns 12,063,734 common units. The general partner’s limited partnership percentage interest was not changed as a result of the conversion. In addition, the general partner also owns a 2 percent general partner interest. The general partner’s ability to manage and operate the Partnership and its ownership of a 43.4 percent partnership interest effectively gives the general partner the ability to control the Partnership.
Distribution and Payments to the General Partner and Its Affiliates
The following table summarizes the distribution and payments made and to be made by the Partnership to the general partner and its affiliates in connection with the ongoing operation and liquidation. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.
Operational Stage
Payments to the general partner and its affiliates
The Partnership paid the general partner an administrative fee, $7.7 million for the year ended December 31, 2006, for the provision of various general and administrative services for the Partnership’s benefit. In addition, the general partner is entitled to reimbursement for all expenses it incurs on the Partnership’s behalf, including other general and administrative expenses. These reimbursable expenses include the salaries and the cost of employee benefits of employees of the general partner who provide services to the Partnership. The general partner has sole discretion in determining the amount of these expenses.
Removal or withdrawal of the general partner
If the general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests as provided in the Partnership Agreement.
Liquidation Stage
Liquidation
Upon liquidation, the partners, including the general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.
Concurrently with the closing of the February 2002 IPO, the Partnership entered into several agreements with Sunoco. These agreements include the Omnibus Agreement, the Pipelines and Terminals Storage and Throughput Agreement, the Inter-refinery Pipeline Lease Agreement, an intellectual property license agreement, certain crude oil purchase and sale agreements, a treasury services agreement and other agreements, all of which are discussed in detail under “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Agreements with Sunoco.”
Subsequent to the February 2002 IPO, the Partnership entered into other agreements with Sunoco, including various throughput agreements regarding certain recently acquired assets or improvements or expansions at existing assets not covered by the Pipelines and Terminals Storage and Throughput Agreement; the purchase agreements with Sunoco to acquire the Eagle Point refinery logistics assets, an undivided interest in the Mesa
Pipe Line system, and an interest in the Mid-Valley Pipeline Company; and certain redemption and expense-sharing agreements with Sunoco that were ancillary to the Partnership’s April 2004 and May 2005 offerings of common units for sale to the public. For further information on these agreements, please refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Agreements with Sunoco.”
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The following table presents the aggregate fees billed for audit and other professional services and products by the Partnership’s independent registered public accounting firm, Ernst & Young LLP, for each of the last two fiscal years:
NOTES:
(1)
Audit Fees, including those for statutory audits, include the aggregate fees paid by the Partnership during the fiscal year indicated for professional services rendered by Ernst & Young for the audit of the Partnership’s annual financial statements and the Partnership’s assessment and Ernst & Young’s opinion on the Partnership’s internal control over financial reporting for compliance under Section 404 of the Sarbanes-Oxley Act of 2002 and review of financial statements included in the Partnership’s quarterly reports on Form 10-Q. Audit Fees also includes reviews of registration statements, issuance of consents and accounting advice.
Each of the services listed above were approved by the Audit/Conflicts Committee of the general partner’s board of directors prior to their performance. All services rendered by Ernst & Young LLP, the Partnership’s principal accountant, are performed pursuant to a written engagement letter with the general partner. During the last two fiscal years, no audit or audit-related services were performed for the Partnership, or its general partner, by anyone other than Ernst & Young LLP.
The Audit/Conflicts Committee of the general partner’s board of directors is responsible for pre-approving all audit services, and permitted non-audit services, to be performed by the independent registered public accounting firm for the Partnership, or its general partner. The Committee reviews the services to be performed to determine whether provision of such services potentially could impair the independence of the Partnership’s independent registered public accounting firm. The Committee’s approval procedures include reviewing a detailed budget for each particular service or category of audit, audit-related, or tax services to be rendered, as well as a description of, and budgeted amounts for, specific categories of anticipated non-audit services. Pre-approval is generally granted for up to one year. Committee approval is required to exceed the budgeted amount for any particular category of services or to engage the independent registered public accounting firm for services not included in the budget. Additional services or specific engagements may be approved, on a case-by-case basis, prior to the independent registered public accounting firm undertaking such services.
Subject to the requirements of applicable law, the Audit/Conflicts Committee may delegate such pre-approval authority to the Audit/Conflicts Committee chairman. However, any pre-approvals granted by the chairman, acting pursuant to such delegated authority, are reviewed by the full membership of the Audit/Conflicts Committee at its next regular meeting. Management of the general partner provides periodic updates to the Audit/Conflicts Committee regarding the extent of any services provided in accordance with this pre-approval process, as well as the cumulative fees incurred to date for all non-audit services, to ensure that such services are within the parameters approved by the Audit/Conflicts Committee.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) The following documents are filed as part of this report:
(1) The financial statements are included in Item 8. Financial Statements and Supplementary Data.
(2) All financial statement schedules required are included in the financial statements or notes thereto.
(3) Exhibits:
* 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.
** This exhibit amends Exhibit 10.4 to Form 10-Q, File No. 1-31219, filed May 9, 2005 (incorporated herein by reference), by adding conformed signatures to the signature pages. Confidential status has been granted for certain portions of this exhibit pursuant to a Confidential Treatment Request filed May 9, 2005.
*** Confidential status has been requested for certain portions thereof pursuant to a Confidential Treatment Request filed February 23, 2007. Such provisions have been separately filed with the Commission.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SUNOCO LOGISTICS PARTNERS L.P.
(Registrant)
By:
Sunoco Partners LLC (its General Partner)
By:
/s/ DEBORAH M. FRETZ
Deborah M. Fretz
President, Chief Executive Officer and Principal
Financial Officer
February 23, 2007
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by or on behalf of the following persons on behalf of the registrant and in the capacities indicated on February 23, 2007.
CYNTHIA A. ARCHER*
Cynthia A. Archer
Director of Sunoco Partners LLC,
General Partner of
Sunoco Logistics Partners L.P.
BRUCE G. FISCHER*
Bruce G. Fischer
Director of Sunoco Partners LLC,
General Partner of
Sunoco Logistics Partners L.P.
STEPHEN L. CROPPER*
Stephen L. Cropper
Director of Sunoco Partners LLC,
General Partner of
Sunoco Logistics Partners L.P.
DEBORAH M. FRETZ*
Deborah M. Fretz
Chief Executive Officer and Director of
Sunoco Partners LLC,
General Partner of
Sunoco Logistics Partners L.P.
(Principal Executive Officer)
MICHAEL H.R. DINGUS*
Michael H.R. Dingus
Director of Sunoco Partners LLC,
General Partner of
Sunoco Logistics Partners L.P.
THOMAS W. HOFMANN*
Thomas W. Hofmann
Director of Sunoco Partners LLC,
General Partner of
Sunoco Logistics Partners L.P.
JOHN G. DROSDICK*
John G. Drosdick
Director and Chairman of
Sunoco Partners LLC,
General Partner of
Sunoco Logistics Partners L.P.
GARY W. EDWARDS*
Gary W. Edwards
Director of Sunoco Partners LLC,
General Partner of
Sunoco Logistics Partners L.P
L. WILSON BERRY, JR.*
L. Wilson Berry, Jr.
Director of Sunoco Partners LLC,
General Partner of
Sunoco Logistics Partners L.P