Item 1. Business
Introduction
Buckeye Partners, L.P. (the “Partnership”) is a publicly traded (NYSE symbol: BPL) master limited partnership organized in 1986 under the laws of the State of Delaware. The Partnership is principally engaged in the transportation, terminalling and storage of refined petroleum products for major integrated oil companies, large refined products marketing companies and major end users of petroleum products on a fee basis through facilities owned and operated by the Partnership. The Partnership also operates pipelines owned by third parties under contracts with major integrated oil and chemical companies and performs pipeline construction activities, generally for these same customers. Buckeye GP LLC (the “General Partner”), a Delaware limited liability company, is the general partner of the Partnership.
The Partnership owns and operates one of the largest independent refined petroleum products pipeline systems in the United States in terms of volumes delivered, with approximately 5,400 miles of pipeline, serving 17 states, and operates approximately 2,500 miles of other pipelines under agreements with major oil and chemical companies. The Partnership also owns and operates 45 active refined petroleum products terminals with aggregate storage capacity of approximately 17.6 million barrels in Illinois, Indiana, Massachusetts, Michigan, Missouri, New York, Ohio and Pennsylvania.
The Partnership’s pipelines service approximately 100 delivery locations, transporting refined petroleum products, including gasoline, jet fuel, diesel fuel, heating oil, kerosene and natural gas liquids from major supply sources to terminals and airports located within end-use markets. These pipelines also transport other refined products, such as propane and butane, refinery feedstocks and blending components. The Partnership’s transportation services are typically provided on a common carrier basis under published tariffs for customers. The Partnership’s geographical diversity, connections to multiple sources of supply and extensive delivery system help create a stable base business. The Partnership is an independent transportation provider that is not affiliated with any oil company or marketer of refined petroleum products and generally does not own the petroleum products that it transports.
The Partnership currently conducts all of its operations through seven operating subsidiaries, which are referred to as the “Operating Subsidiaries”:
· Buckeye Pipe Line Company, L.P. (“Buckeye”), which owns an approximately 2,643-mile interstate common carrier refined petroleum products pipeline system serving major population centers in eight states. It is the primary jet fuel transporter to John F. Kennedy International Airport (“JFK”), LaGuardia Airport, Newark Liberty International Airport and certain other airports within its service territory.
· Laurel Pipe Line Company, L.P. (“Laurel”), which owns an approximately 345-mile refined petroleum products pipeline connecting five Philadelphia area refineries to 10 delivery points across Pennsylvania.
· Wood River Pipe Lines LLC (“Wood River”), which owns six refined petroleum products pipelines with aggregate mileage of approximately 925 miles located in Illinois, Indiana, Missouri and Ohio.
· Buckeye Pipe Line Transportation LLC (“BPL Transportation”), which owns a refined petroleum products pipeline system with aggregate mileage of approximately 478 miles located in New Jersey, New York, and Pennsylvania.
· Everglades Pipe Line Company, L.P. (“Everglades”), which owns an approximately 37-mile intrastate common carrier refined petroleum products pipeline connecting Port Everglades, Florida to
Ft. Lauderdale-Hollywood International Airport and Miami International Airport. It is the primary jet fuel provider to Miami International Airport.
· Buckeye NGL Pipe Lines LLC (“Buckeye NGL”), which owns an approximate 350-mile natural gas liquids pipeline, acquired in January 2006, extending generally from the Wattenberg, Colorado area to Bushton, Kansas.
· Buckeye Pipe Line Holdings, L.P. (“BPH”), which, through its subsidiary Buckeye Terminals, LLC (“Buckeye Terminals”), owns (or in certain instances leases from other Operating Subsidiaries) and operates 45 refined petroleum products terminals with aggregate storage capacity of approximately 17.6 million barrels. BPH also owns interests in 574 miles of pipelines in the Midwest, Southwest and West Coast. BPH operates, through its subsidiary Buckeye Gulf Coast Pipe Lines, L.P. (“BGC”), pipelines in the Gulf Coast region for third parties. BPH also holds minority stock interests in two midwest refined petroleum products pipelines and a natural gas liquids pipeline system.
Beginning in the fourth quarter of 2004 and continuing into 2006, the Partnership substantially expanded its business operations through equity investments and asset acquisitions of approximately $850.0 million. As a result , in 2005 the Partnership redesigned the financial information it regularly provides to management and, based on the nature of the new information, determined in the fourth quarter of 2005 that its operations are appropriately presented in three reportable operating segments: (i) Pipeline Operations, (ii) Terminalling and Storage and (iii) Other Operations.
Significant Events in 2006
Asset Acquisitions
On January 1, 2006, the Partnership acquired a refined petroleum products terminal located in Niles, Michigan from affiliates of Shell Oil Products, U.S. (“Shell”) for $13.0 million.
On January 31, 2006, the Partnership acquired a natural gas liquids pipeline, which extends generally from Wattenberg, Colorado to Bushton, Kansas, from BP Pipelines (North America) Inc. for approximately $87.0 million.
Initial Public Offering of the Parent of the General Partner
On August 9, 2006, Buckeye GP Holdings L.P. (“BGH”), the owner of the General Partner, sold 10.5 million common units in an underwritten initial public offering (“IPO”), the net proceeds of which were approximately $167.4 million. BGH used the net proceeds from the IPO, along with cash on hand, to repay certain outstanding indebtedness under its term loan and to make distributions to its pre-IPO equity owners. Following the IPO, approximately 54% of the limited partner units of BGH are owned by affiliates of Carlyle/Riverstone Global Energy and Power Fund II L.P. (“Carlyle Riverstone”), approximately 9% are owned by certain members of senior management of the Partnership and the remaining approximately 37% is owned by the public.
The following chart depicts the Partnership’s and BGH’s ownership structure as of December 31, 2006.
Ownership of Buckeye Partners, L.P. and Buckeye GP Holdings L.P.
Ownership percentages in the chart are approximate.
Business Activities
The following discussion describes the business activities of the Partnership’s operating segments. Detailed information regarding revenues, operating income and total assets of each segment can be found in Note 20, Segment Information, to the Partnership’s consolidated financial statements.
Pipeline Operations
The Partnership owns and operates petroleum products pipelines which receive petroleum products from refineries, connecting pipelines and bulk and marine terminals, and transports those products to other locations. In 2006, the Pipeline Operations segment accounted for approximately 76% of the Partnership’s consolidated revenues.
The Partnership transported an average of approximately 1,450,300 barrels of petroleum products per day in 2006. The following table shows the volume and percentage of refined petroleum products transported over the last three years.
Volume and Percentage of Petroleum Products Transported(1)
(Volume in thousands of barrels per day)
(1) Excludes local product transfers.
(2) Includes diesel fuel, heating oil, kerosene and other middle distillates.
The Partnership provides pipeline transportation service in the following states: California, Colorado, Connecticut, Florida, Illinois, Indiana, Kansas, Massachusetts, Michigan, Missouri, New Jersey, Nevada, New York, Ohio, Pennsylvania and Tennessee.
Pennsylvania-New York-New Jersey
Buckeye serves major population centers in Pennsylvania, New York and New Jersey through approximately 928 miles of pipeline. Refined petroleum products are received at Linden, New Jersey from 17 major source points, including two refineries, six connecting pipelines and nine storage and terminalling facilities. Products are then transported through two lines from Linden, New Jersey to Macungie, Pennsylvania. From Macungie, the pipeline continues west through a connection with the Laurel pipeline to Pittsburgh, Pennsylvania (serving Reading, Harrisburg, Altoona/Johnstown and Pittsburgh, Pennsylvania) and north through eastern Pennsylvania into New York (serving Scranton/Wilkes-Barre, Binghamton, Syracuse, Utica, Rochester and, via a connecting carrier, Buffalo, New York). Buckeye leases capacity in one of the pipelines extending from Pennsylvania to upstate New York to a major oil pipeline company. Products received at Linden, New Jersey are also transported through one line to Newark International Airport and through two additional lines to JFK and LaGuardia airports and to commercial refined petroleum products terminals at Long Island City and Inwood, New York. These pipelines supply JFK, LaGuardia and Newark airports with substantially all of each airport’s jet fuel requirements.
In addition, BPL Transportation’s pipeline system delivers refined petroleum products from the Valero refinery located in Paulsboro, New Jersey to destinations in New Jersey, Pennsylvania, and New York. A portion of the pipeline system extends from Paulsboro, New Jersey to deliver products to Malvern, Pennsylvania. From Malvern, a pipeline segment delivers refined products to locations in upstate New York, while another segment delivers products to central Pennsylvania. Two shorter pipeline
segments connect the Valero refinery to the Colonial pipeline system and the Philadelphia International Airport, respectively.
The Laurel pipeline system transports refined petroleum products through a 345-mile pipeline extending westward from five refineries and a connection to the Colonial pipeline system in the Philadelphia area to Reading, Harrisburg, Altoona/Johnstown and Pittsburgh, Pennsylvania.
Illinois-Indiana-Michigan-Missouri-Ohio
Buckeye and Norco Pipe Line Company, LLC (“Norco”), a subsidiary of BPH, transport refined petroleum products through 2,025 miles of pipeline in northern Illinois, central Indiana, eastern Michigan, western and northern Ohio and western Pennsylvania. A number of receiving lines and delivery lines connect to a central corridor which runs from Lima, Ohio through Toledo, Ohio to Detroit, Michigan. Refined petroleum products are received at a refinery and other pipeline connection points near Toledo, Lima, Detroit and East Chicago, Indiana. Major market areas served include Peoria, Illinois; Huntington/Fort Wayne, Indianapolis and South Bend, Indiana; Bay City, Detroit and Flint, Michigan; Cleveland, Columbus, Lima and Toledo, Ohio and Pittsburgh, Pennsylvania.
Wood River owns six refined petroleum products pipelines with aggregate mileage of approximately 925 miles located in the midwestern United States. Refined petroleum products are received at the ConocoPhillips Wood River refinery in Illinois and transported to the Chicago area, to a terminal in the St. Louis, Missouri area to the Lambert-St. Louis Airport, to receiving points across Illinois and Indiana and to Buckeye’s pipeline in Lima, Ohio. At the Partnership’s tank farm located in Hartford, Illinois, one of Wood River’s pipelines also receives refined petroleum products from the Explorer pipeline, which are transported to the Partnership’s 1.3 million barrel terminal located on the Ohio River in Mt. Vernon, Indiana. Wood River also owns an approximately 26-mile pipeline that extends from Marathon’s Wood River Station in southern Illinois to a third party terminal in the East St. Louis, Missouri area.
Colorado-Kansas
Buckeye NGL transports natural gas liquids via an approximately 350-mile pipeline, acquired in January 2006, that extends generally from the Wattenberg, Colorado area to Bushton, Kansas.
Other Refined Products Pipelines
Buckeye serves Connecticut and Massachusetts through an approximately 112-mile pipeline (the “Jet Lines System”) that carries refined petroleum products from New Haven, Connecticut to Hartford, Connecticut and Springfield, Massachusetts.
Everglades transports primarily jet fuel on an approximately 37-mile pipeline from Port Everglades, Florida to Ft. Lauderdale-Hollywood International Airport and Miami International Airport. Everglades supplies Miami International Airport with substantially all of its jet fuel requirements.
WesPac Pipelines-Reno LLC (“WesPac Reno”) owns an approximately 3.0 mile pipeline serving the Reno/Tahoe International Airport. WesPac Pipelines-San Diego LLC (“WesPac San Diego”) owns an approximately 4.3 mile pipeline serving the San Diego International Airport. WesPac Pipelines-Memphis LLC (“WesPac Memphis”) owns and operates an approximately 11-mile pipeline and related terminal facilities that primarily serve Federal Express Corporation at the Memphis International Airport. Each of the WesPac entities originally was a joint venture between BPH and Kealine Partners LLC. In May 2005, BPH purchased the membership interest in WesPac Reno owned by Kealine Partners for approximately $2.5 million. Since this purchase, BPH has owned 100% of WesPac Reno. BPH has a 75% ownership interest in WesPac Memphis and a 50% ownership interest in WesPac San Diego. Kealine
Partners owns the remaining interest in these two joint ventures. As of December 31, 2006, the Partnership had provided $52.8 million in intercompany financing to these WesPac entities.
Equity Investments
BPH owns a 24.99% equity interest in West Shore Pipe Line Company (“West Shore”). West Shore owns a pipeline system that originates in the Chicago, Illinois area and extends north to Green Bay, Wisconsin and west and then north to Madison, Wisconsin. The pipeline system transports refined petroleum products to markets in northern Illinois and Wisconsin. The other equity holders of West Shore are major oil companies. The pipeline is operated under contract by Citgo Pipeline Company.
BPH also owns a 20% equity interest in West Texas LPG Pipeline Limited Partnership (“WTP”). WTP owns a pipeline system that delivers natural gas liquids to Mont Belvieu, Texas for fractionation. The natural gas liquids are delivered to the WTP pipeline system from the Rocky Mountain region via connecting pipelines and from gathering fields located in west and central Texas. The majority owners and the operators of WTP are affiliates of ChevronTexaco, Inc.
BPH also owns a 40% equity interest in Muskegon Pipeline LLC (“Muskegon”). The majority owner of Muskegon is Marathon Pipe Line LLC (“Marathon”). Muskegon owns an approximately 170-mile pipeline that delivers petroleum products from Griffith, Indiana to Muskegon, Michigan. The pipeline is operated by Marathon Pipe Line LLC.
Terminalling and Storage
Through BPH and its subsidiary, Buckeye Terminals, the Partnership’s Terminalling and Storage segment owns and operates 45 terminals located in Illinois, Indiana, Massachusetts, Michigan, Missouri, New York, Ohio and Pennsylvania that provide bulk storage and throughput services and have the capacity to store an aggregate of approximately 17.6 million barrels of refined petroleum products. In addition, Buckeye Terminals owns four currently idle terminals with an aggregate storage capacity of approximately 863,000 barrels. In 2006, the Terminalling and Storage segment accounted for approximately 18% of the Partnership’s consolidated revenue.
The Partnership’s refined petroleum products terminals receive products from pipelines (and, in certain cases, barges) and distribute them to third parties, who in turn deliver them to end-users and retail outlets. The Partnership’s refined petroleum products terminals play a key role in moving refined products to the end-user market by providing storage and inventory management, distribution, blending to achieve specified grades of gasoline, and other ancillary services that include the injection of ethanol and other additives. 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.
The Partnership’s refined petroleum products terminals derive most of their revenues from terminalling fees paid by customers. A fee is charged for receiving refined petroleum products into the terminal and delivering them to trucks, barges, or pipelines. In addition to terminalling fees, the Partnership’s revenues are generated by charging customers fees for blending and injecting additives, and, in certain instances, leasing terminal capacity to customers on either a short-term or long-term basis. Of the Partnership’s 45 refined petroleum products terminals, 32 are connected to the Partnership’s pipelines and 13 are not.
The table below sets forth the total average daily throughput for the refined petroleum products terminals in each of the years presented:
The following table outlines the number of terminals and storage capacity in barrels (“bbls”) by state as of December 31, 2006:
Other Operations
The business of the Partnership’s Other Operations segment consists primarily of pipeline operation and maintenance services and pipeline construction services for third parties pursuant to contractual arrangements. BGC is a contract operator of pipelines owned in Texas by major petrochemical companies. BGC currently has 14 operations and maintenance contracts in place to operate and maintain approximately 2,500 miles of pipeline. In addition, BGC owns an approximately 23-mile pipeline located in Texas and leases a portion of the pipeline to a third-party chemical company. Subsidiaries of BGC also own an approximate 63% interest in a crude butadiene pipeline between Deer Park, Texas and Port Arthur, Texas. Volumes of crude butadiene are transported on this line, known as the Sabina pipeline. BGC also owns and operates an ammonia pipeline located in Texas that was acquired in November 2005. In addition, BGC also provides engineering and construction management services to major chemical companies in the Gulf Coast area. In 2006, the Other Operations segment accounted for approximately 6% of the Partnership’s consolidated revenue.
Competition and Other Business Considerations
The Operating Subsidiaries conduct business without the benefit of exclusive franchises from government entities. In addition, the Operating Subsidiaries’ pipeline operations generally operate as common carriers, providing transportation services at posted tariffs and without long-term contracts. The Operating Subsidiaries generally do not own the products they transport. Demand for the services provided by the Operating Subsidiaries derives from demand from end users for petroleum products in the regions served and the ability and willingness of refiners and marketers to supply such demand by deliveries through the Operating Subsidiaries’ pipelines. Demand for refined petroleum products is primarily a function of price, prevailing general economic conditions and weather. The Operating Subsidiaries’ businesses are, therefore, subject to a variety of factors partially or entirely beyond their control. Multiple sources of pipeline entry and multiple points of delivery, however, have historically helped maintain stable total volumes even when volumes at particular source or destination points have changed.
The consolidated Partnership customer base was approximately 214 customers in 2006 and 160 customers in 2005. Affiliates of Shell contributed 11% in 2006 and 13% in 2005 of consolidated Partnership revenue. For the year ended December 31, 2004, no customer contributed more than 10% of consolidated revenue. Approximately 5% of the 2006 consolidated revenue was generated by Shell in the Pipeline Operations segment; the remaining 6% of consolidated revenue was in the Terminalling and Storage segment. The 20 largest customers accounted for 53% and 63% of consolidated Partnership revenue in 2006 and 2005, respectively.
Generally, pipelines are the lowest cost method for long-haul overland movement of refined petroleum products. Therefore, the Operating Subsidiaries’ most significant competitors for large volume shipments are other pipelines, some of which are owned or controlled by major integrated oil companies. Although it is unlikely that a pipeline system comparable in size and scope to the Operating Subsidiaries’ 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 the Operating Subsidiaries in particular locations.
The Operating Subsidiaries compete with marine transportation in some areas. Tankers and barges on the Great Lakes account for some of the volume to certain Michigan, Ohio and upstate New York locations during the approximately eight non-winter months of the year. Barges are presently a competitive factor for deliveries to the New York City area, the Pittsburgh area, Connecticut and locations on the Ohio River such as Mt. Vernon, Indiana and Cincinnati, Ohio, and locations on the Mississippi River such as St. Louis, Missouri.
Trucks competitively deliver refined products in a number of areas served by the Operating Subsidiaries. While their costs may not be competitive for longer hauls or large volume shipments, trucks compete effectively for smaller volumes in many local areas served by the Operating Subsidiaries. The availability of truck transportation places a significant competitive constraint on the ability of the Operating Subsidiaries to increase their tariff rates.
Privately arranged exchanges of refined petroleum products between marketers in different locations are another form of competition. Generally, such exchanges reduce both parties’ costs by eliminating or reducing transportation charges. In addition, consolidation among refiners and marketers that has accelerated in recent years has altered distribution patterns, reducing demand for transportation services in some markets and increasing them in other markets.
Distribution of refined petroleum products depends to a large extent upon the location and capacity of refineries. However, because the Partnership’s business is largely driven by the consumption of fuel in its delivery areas and the Operating Subsidiaries’ pipelines have numerous source points, the General Partner does not believe that the expansion or shutdown of any particular refinery is likely, in most instances, to have a material effect on the business of the Partnership. Certain of the pipelines which were acquired from Shell on October 1, 2004 emanate from a refinery owned by ConocoPhillips and located in the vicinity of Wood River, Illinois. While these pipelines are, in part, supplied by connecting pipelines, a temporary or permanent closure of the ConocoPhillips Wood River refinery could have a negative impact on volumes delivered through these pipelines. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Forward-Looking Information-Competition and Other Business Conditions.”
The Operating Subsidiaries’ mix of products transported tends to vary seasonally. Declines in demand for heating oil during the summer months are, to a certain extent, offset by increased demand for gasoline and jet fuel. Overall, operations have been only moderately seasonal, with somewhat lower than average volumes being transported during March, April and May and somewhat higher than average volumes being transported in November, December and January.
Many of the general competitive factors discussed above, such as demand for refined petroleum products and competitive threats from methods of transportation other than pipelines, also impact the Partnership’s terminal operations. In addition, the Partnership’s terminals generally compete with other terminals in the same geographic market. Many competitive terminals are owned by major integrated oil companies. These major oil companies may have the opportunity for product exchanges that are not available to the Partnership’s terminals. While the Partnership’s terminal throughput fees are not regulated, they are subject to price competition from competitive terminals and alternate modes of transporting refined petroleum products to end users such as retail gas stations.
Other independent pipeline companies, engineering firms, major integrated oil companies and petrochemical companies compete with BGC to operate and maintain pipelines for third-party owners. In addition, in many instances it is more cost-effective for petrochemical companies to operate and maintain their own pipelines than to enter into agreements for BGC to operate and maintain such pipelines. Numerous engineering and construction firms compete with BGC for pipeline construction business.
Employees
Neither the Partnership nor any of the Operating Subsidiaries has any employees. The Operating Subsidiaries are managed and operated by employees of Buckeye Pipe Line Services Company, a Pennsylvania corporation (“Services Company”). Services Company is reimbursed by the Operating Subsidiaries pursuant to a services agreement for the cost of providing employee services. In December 2006, Services Company had a total of 867 full-time employees, 171 of whom were represented by two labor unions. The Operating Subsidiaries (and their predecessors) have never experienced any work stoppages or other significant labor problems.
Capital Expenditures
The Partnership makes capital expenditures in order to maintain and enhance the safety and integrity of its pipelines, terminals and related assets, to expand the reach or capacity of its pipelines and terminals, to improve the efficiency of its operations and to pursue new business opportunities. See “Pipeline and Terminal Maintenance and Safety Regulation” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources.”
During 2006, the Partnership made approximately $92.7 million of capital expenditures, of which $30.2 million related to maintenance and integrity projects and $62.5 million related to expansion and cost reduction projects.
In 2007, the Partnership anticipates capital expenditures of approximately $80.0 million, of which approximately $30.0 million is projected to be sustaining capital expenditures for maintenance and integrity projects and approximately $50.0 million is projected to be for expansion and cost reduction projects. See “Pipeline and Terminal Maintenance and Safety Regulation” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources.”
Regulation
General
Buckeye, Wood River, BPL Transportation, Buckeye NGL and Norco operate pipelines subject to the regulatory jurisdiction of the Federal Energy Regulatory Commission (“FERC”) under the Interstate Commerce Act and the Department of Energy Organization Act. FERC regulations require that interstate oil pipeline rates be posted publicly and that these rates be “just and reasonable” and non-discriminatory. FERC regulations also enforce common carrier obligations and specify a uniform system of accounts. In addition, the Operating Subsidiaries are subject to the jurisdiction of certain other federal agencies with respect to environmental and pipeline safety matters.
The Operating Subsidiaries are also subject to the jurisdiction of various state and local agencies, including, in some states, public utility commissions which have jurisdiction over, among other things, intrastate tariffs, the issuance of debt and equity securities, transfers of assets and pipeline safety. The Partnership’s Laurel subsidiary operates a pipeline in intrastate service across Pennsylvania, and its tariff rates are regulated by the Pennsylvania Public Utility Commission. The Partnership’s Wood River subsidiary operates a pipeline in intrastate service in Illinois and tariff rates related to this pipeline are regulated by the Illinois Commerce Commission.
FERC Rate Regulation
The generic oil pipeline regulations issued under the Energy Policy Act of 1992 rely primarily on an index methodology, that allows a pipeline to change its rates in accordance with an index (currently the change in the Producer Price Index plus 1.3%) that FERC believes reflects cost changes appropriate for application to pipeline rates. The tariff rates of each of Wood River, BPL Transportation, Buckeye NGL and Norco are governed by this generic FERC index methodology, and therefore are subject to change annually according to the index. If PPI +1.3% is negative, then Wood River, BPL Transportation, Buckeye NGL and Norco could be required to reduce their rates if they exceed the new maximum allowable rate.
In addition, FERC had a longstanding rule that pass-through entities, like the Partnership and the Operating Subsidiaries, may not claim an income tax allowance for income attributable to non-corporate limited partners in justifying the reasonableness of their rates that are based on their cost of service. (The General Partner believes only a small percentage of the Partnership’s limited partnership units are held by corporations). Further, in a July 2004 decision involving an unrelated pipeline limited partner, the United States Court of Appeals for the District of Columbia Circuit overruled a prior FERC decision allowing a limited partnership to claim a partial income tax allowance. On May 4, 2005, the FERC adopted a new policy providing that all entities owning public utility assets-oil and gas pipelines and electric utilities-would be permitted to include an income tax allowance in their cost-of-service rates to reflect the actual or potential income tax liability attributable to their public utility income, regardless of the form of ownership. FERC determined that any pass-through entity seeking an income tax allowance in a rate proceeding must establish that its partners have an actual or potential income tax obligation on the entity’s public utility income. The amount of any income tax allowance will be reduced accordingly to the extent that any of the partners do not have an actual or potential income tax obligation. This reduction will be reflected in the weighted income tax liability of the entity’s partners. Whether a pipeline’s owners have an actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. This policy was applied by FERC in June 2005 with an order involving an unrelated pipeline limited partnership. FERC concluded that the pipeline should be afforded an income tax allowance on all of its partnership interests to the extent that the ultimate owners of those interests had an actual or potential income tax obligation during the periods at issue. In December 2005, FERC reaffirmed its new income tax allowance policy as it applied to that pipeline. FERC’s tax allowance policy has been appealed to the United States Court of Appeals for the District of Columbia Circuit. The ultimate outcome of these proceedings is not certain and could result in changes to the FERC’s treatment of income tax allowances.
A shipper or FERC could cite these decisions in a protest or complaint challenging indexed rates maintained by certain of the Partnership’s Operating Subsidiaries. If a challenge were brought and FERC were to find that some of the indexed rates exceed either the maximum allowable rate or levels justified by the cost of service, FERC could order a reduction in the indexed rates and could require reparations. As a result, the Partnership’s results of operations could be adversely affected.
Under FERC’s rules, as an alternative to indexed rates, a pipeline is also allowed to charge market-based rates if the pipeline establishes that it does not possess significant market power in a particular market. The final rules became effective on January 1, 1995.
Buckeye’s rates are governed by an exception to the rules discussed above, pursuant to specific FERC authorization. Buckeye’s market-based rate regulation program was initially approved by FERC in March 1991 and was subsequently extended in 1994. Under this program, in markets where Buckeye does not have significant market power, individual rate increases: (a) will not exceed a real (i.e., exclusive of inflation) increase of 15% over any two-year period (the “rate cap”), and (b) will be allowed to become effective without suspension or investigation if they do not exceed a “trigger” equal to the change in the Gross Domestic Product implicit price deflator since the date on which the individual rate was last increased, plus 2%. Individual rate decreases will be presumptively valid upon a showing that the proposed rate exceeds marginal costs. In markets where Buckeye was found to have significant market power and in
certain markets where no market power finding was made: (i) individual rate increases cannot exceed the volume-weighted average rate increase in markets where Buckeye does not have significant market power since the date on which the individual rate was last increased, and (ii) any volume-weighted average rate decrease in markets where Buckeye does not have significant market power must be accompanied by a corresponding decrease in all of Buckeye’s rates in markets where it does have significant market power. Shippers retain the right to file complaints or protests following notice of a rate increase, but are required to show that the proposed rates violate or have not been adequately justified under the market-based rate regulation program, that the proposed rates are unduly discriminatory, or that Buckeye has acquired significant market power in markets previously found to be competitive.
The Buckeye program was subject to review by FERC in 2000 when FERC reviewed the index selected in the generic oil pipeline regulations. FERC decided to continue the generic oil pipeline regulations with no material changes and did not modify or discontinue Buckeye’s program. The General Partner cannot predict the impact that any change to Buckeye’s rate program would have on Buckeye’s operations. Independent of regulatory considerations, it is expected that tariff rates will continue to be constrained by competition and other market factors.
Environmental Regulation
The Operating Subsidiaries are subject to federal, state and local laws and regulations relating to the protection of the environment. Although the General Partner believes that the operations of the Operating Subsidiaries comply in all material respects with applicable environmental laws and regulations, risks of substantial liabilities are inherent in pipeline operations, and there can be no assurance that material environmental liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly rigorous environmental laws, regulations and enforcement policies, and claims for damages to property or injuries to persons resulting from the operations of the Operating Subsidiaries, could result in substantial costs and liabilities to the Partnership. See “Legal Proceedings” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources-Environmental Matters.”
The Oil Pollution Act of 1990 (“OPA”) amended certain provisions of the federal Water Pollution Control Act of 1972, commonly referred to as the Clean Water Act (“CWA”), and other statutes as they pertain to the prevention of and response to petroleum product spills into navigable waters. The OPA subjects owners of facilities to strict joint and several liability for all containment and clean-up costs and certain other damages arising from a spill. The CWA provides penalties for the discharge of petroleum products in reportable quantities and imposes substantial liability for the costs of removing a spill. State laws for the control of water pollution also provide varying civil and criminal penalties and liabilities in the case of releases of petroleum or its derivatives into surface waters or into the ground.
Contamination resulting from spills or releases of refined petroleum products sometimes occurs in the petroleum pipeline industry. The Operating Subsidiaries’ pipelines cross numerous navigable rivers and streams. Although the General Partner believes that the Operating Subsidiaries comply in all material respects with the spill prevention, control and countermeasure requirements of federal laws, any spill or other release of petroleum products into navigable waters may result in material costs and liabilities to the Partnership.
The Resource Conservation and Recovery Act (“RCRA”), as amended, establishes a comprehensive program of regulation of “hazardous wastes.” Hazardous waste generators, transporters, and owners or operators of treatment, storage and disposal facilities must comply with regulations designed to ensure detailed tracking, handling and monitoring of these wastes. RCRA also regulates the disposal of certain non-hazardous wastes. As a result of these regulations, certain wastes typically generated by pipeline operations are considered “hazardous wastes.”
The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”), also known as “Superfund,” governs the release or threat of release of a “hazardous substance.” Releases of a hazardous substance, whether on or off-site, may subject the generator of that substance to liability under CERCLA for the costs of clean-up and other remedial action. Pipeline maintenance and other activities in the ordinary course of business generate “hazardous substances.” As a result, to the extent a hazardous substance generated by the Operating Subsidiaries or their predecessors may have been released or disposed of in the past, the Operating Subsidiaries may in the future be required to remediate contaminated property. Governmental authorities such as the Environmental Protection Agency (“EPA”), and in some instances third parties, are authorized under CERCLA to seek to recover remediation and other costs from responsible persons, without regard to fault or the legality of the original disposal. In addition to its potential liability as a generator of a “hazardous substance,” the property or right-of-way of the Operating Subsidiaries may be adjacent to or in the immediate vicinity of Superfund and other hazardous waste sites. Accordingly, the Operating Subsidiaries may be responsible under CERCLA for all or part of the costs required to cleanup such sites, which costs could be material.
The Clean Air Act, amended by the Clean Air Act Amendments of 1990 (the “Amendments”), imposes controls on the emission of pollutants into the air. The Amendments required states to develop facility-wide permitting programs over the past several years to comply with new federal programs. Existing operating and air-emission requirements like those currently imposed on the Operating Subsidiaries are being reviewed by appropriate state agencies in connection with the new facility-wide permitting program. It is possible that new or more stringent controls will be imposed on the Operating Subsidiaries through this program.
The Operating Subsidiaries are also subject to environmental laws and regulations adopted by the various states in which they operate. In certain instances, the regulatory standards adopted by the states are more stringent than applicable federal laws.
Pipeline and Terminal Maintenance and Safety Regulation
The pipelines operated by the Operating Subsidiaries are subject to regulation by the United States Department of Transportation (“DOT”) under the Hazardous Liquid Pipeline Safety Act of 1979 (“HLPSA”), which governs the design, installation, testing, construction, operation, replacement and management of pipeline facilities. HLPSA covers petroleum and petroleum products and requires any entity that owns or operates pipeline facilities to comply with applicable safety standards, to establish and maintain a plan of inspection and maintenance and to comply with such plans.
The Pipeline Safety Reauthorization Act of 1988 requires coordination of safety regulation between federal and state agencies, testing and certification of pipeline personnel, and authorization of safety-related feasibility studies. The Partnership has a drug and alcohol testing program that complies in all material respects with the regulations promulgated by the Office of Pipeline Safety and DOT.
HLPSA also requires, among other things, that the Secretary of Transportation consider the need for the protection of the environment in issuing federal safety standards for the transportation of hazardous liquids by pipeline. The legislation also requires the Secretary of Transportation to issue regulations concerning, among other things, the identification by pipeline operators of environmentally sensitive areas; the circumstances under which emergency flow restricting devices should be required on pipelines; training and qualification standards for personnel involved in maintenance and operation of pipelines; and the periodic integrity testing of pipelines in unusually sensitive and high-density population areas by internal inspection devices or by hydrostatic testing. Effective in August 1999, the DOT issued its Operator Qualification Rule, which required a written program by April 27, 2001, for ensuring operators are qualified to perform tasks covered by the pipeline safety rules. All persons performing covered tasks were required to be qualified under the program by October 28, 2002. The Partnership filed its written plan and has qualified its employees and contractors as required and requalified the employees under its plan in
2005. On March 31, 2001, DOT’s rule for Pipeline Integrity Management in High Consequence Areas (Hazardous Liquid Operators with 500 or more Miles of Pipeline) became effective. This rule sets forth regulations that require pipeline operators to assess, evaluate, repair and validate the integrity of hazardous liquid pipeline segments that, in the event of a leak or failure, could affect populated areas, areas unusually sensitive to environmental damage or commercially navigable waterways. Under the rule, pipeline operators were required to identify line segments which could impact high consequence areas by December 31, 2001. Pipeline operators were required to develop “Baseline Assessment Plans” for evaluating the integrity of each pipeline segment by March 31, 2002 and to complete an assessment of the highest risk 50% of line segments by September 30, 2004, with full assessment of the remaining 50% by March 31, 2008. Pipeline operators will thereafter be required to re-assess each affected segment in intervals not to exceed five years. The Partnership has implemented an Integrity Management Program in compliance with the requirements of this rule.
In December 2002, the Pipeline Safety Improvement Act of 2002 (“PSIA”) became effective. The PSIA imposes additional obligations on pipeline operators, increases penalties for statutory and regulatory violations, and includes provisions prohibiting employers from taking adverse employment action against pipeline employees and contractors who raise concerns about pipeline safety within the company or with government agencies or the press. Many of the provisions of the PSIA are subject to regulations to be issued by the Department of Transportation. The PSIA also requires public education programs for residents, public officials and emergency responders and a measurement system to ensure the effectiveness of the public education program. The Partnership implemented a public education program that complies with these requirements and the requirements of the American Petroleum Institute Recommended Practice 1162. While the PSIA imposes additional operating requirements on pipeline operators, the Partnership does not believe that costs of compliance with the PSIA are likely to be material.
The Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 (“PIPES Act”), which became effective on December 24, 2006, among other things, reauthorized HLPSA, strengthened damage prevention measures designed to protect pipelines from excavation damage, removed the exemption from regulation of pipelines operating at less than 20 percent of maximum yield strength in rural areas, and required pipeline operators to manage human factors in pipeline control centers, including controller fatigue. While the PIPES Act imposes additional operating requirements on pipeline operators, the Partnership does not believe that costs of compliance with the PIPES Act are likely to be material.
The Partnership also has certain contractual obligations to Shell for testing and maintenance of certain of the pipelines that the Partnership acquired from Shell in October 2004. In 2003, Shell entered into a consent decree with the EPA arising out of a June 1999 incident unrelated to the assets acquired by the Partnership. The consent decree included requirements for testing and maintenance of two of the pipelines (the “North Line” and the “East Line”) acquired from Shell, the creation of a damage prevention program, submission to independent monitoring and various reporting requirements. In the purchase agreement with Shell, the Partnership agreed to perform, at its own expense, the work required of Shell on the North Line and the East Line under the consent decree. The Partnership’s obligations to Shell with respect to the consent decree extend to approximately 2008, a date five years from the date of the consent decree.
The Partnership believes that the Operating Subsidiaries currently comply in all material respects with HLPSA, the PSIA, the PIPES Act and other pipeline safety laws and regulations. However, the industry, including the Partnership, will incur additional pipeline and tank integrity expenditures in the future, and the Partnership is likely to incur increased operating costs based on these and other government regulations. During 2006, the Partnership’s integrity expenditures for these programs were approximately $20.1 million (of which $9.6 million was capitalized and $10.5 million was expensed). The Partnership expects 2007 integrity expenditures for these programs to be approximately $23 million of which approximately $13 million will be capitalized and $10 million will be expense.
The Operating Subsidiaries are also subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The Partnership believes that the Operating Subsidiaries’ operations comply in all material respects with OSHA requirements, including general industry standards, record-keeping, hazard communication requirements, training and monitoring of occupational exposure to benzene, asbestos and other regulated substances.
The Partnership cannot predict whether or in what form any new legislation or regulatory requirements might be enacted or adopted or the costs of compliance. In general, any such new regulations could increase operating costs and impose additional capital expenditure requirements, but the Partnership does not presently expect that such costs or capital expenditure requirements would have a material adverse effect on its results of operations or financial condition.
Tax Considerations for Unitholders
This section is a summary of material tax considerations that may be relevant to the holders (“Unitholders”) of the Partnership’s limited partner units (“LP Units”). It is based upon the Internal Revenue Code of 1986, as amended (the “Code”), regulations promulgated thereunder and current administrative rulings and court decisions, all of which are subject to change. Subsequent changes in such authorities may cause the tax consequences to vary substantially from the consequences described below.
No attempt has been made in the following discussion to comment on all federal income tax matters affecting the Partnership or the Unitholders. Moreover, the discussion focuses on Unitholders who are individuals and who are citizens or residents of the United States and has only limited application to corporations, estates, trusts, non-resident aliens or other Unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts, REITs or mutual funds.
UNITHOLDERS ARE URGED TO CONSULT, AND SHOULD DEPEND ON, THEIR OWN TAX ADVISORS IN ANALYZING THE FEDERAL, STATE, LOCAL AND FOREIGN TAX CONSEQUENCES TO THEM OF THE OWNERSHIP OR DISPOSITION OF LP UNITS.
Characterization of the Partnership for Tax Purposes
A partnership is not a taxable entity and incurs no federal income tax liability. Instead, partners are required to take into account their respective allocable shares of the items of income, gain, loss and deduction of the partnership in computing their federal income tax liability, regardless of whether distributions are made. Distributions of cash by a partnership to a partner are generally not taxable unless the amount of cash distributed to a partner is in excess of the partner’s tax basis in his partnership interest. Allocable shares of partnership tax items are generally determined by a partnership agreement. However, the IRS may disregard such an agreement in certain instances and re-determine the tax consequences of partnership operations to the partners.
Section 7704 of the Code provides that publicly traded partnerships (such as the Partnership) will, as a general rule, be taxed as corporations. However, an exception to this rule exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year of the partnership’s existence consists of “qualifying income.” Qualifying income includes interest, dividends, real property rents, gains from the sale or disposition of real property, and most importantly for Unitholders “income and gains derived from the exploration, development, mining or production, processing, refining, transportation (including pipelines transporting gas, oil or products thereof), or the marketing of any mineral or natural resource (including fertilizer, geothermal energy and timber),” and gain from the sale or disposition of capital assets that produce such income.
The Partnership is engaged primarily in the refined petroleum products transportation business. The General Partner believes that at least 90% or more of the Partnership’s gross income constitutes, and has
constituted, qualifying income and, accordingly, that the Partnership will continue to be classified as a partnership and not as a corporation for federal income tax purposes.
If we fail to meet the Qualifying Income Exception, other than a failure that is determine by the IRS to be inadvertent and that is cured within a reasonable time after discovery, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to our Unitholders in liquidation of their interests in us. This contribution and liquidation should be tax-free to Unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.
If we were taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to the Unitholders, and our net income would be taxed to us at corporate rates. If we were taxable as a corporation, losses recognized by us would not flow through to our Unitholders. In addition, any distribution made by us to a Unitholder would be treated as either taxable dividend income, to the extent of current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the Unitholder’s tax basis in his units, or taxable capital gain, after the Unitholder’s tax basis in his units is reduced to zero.
Allocation of Partnership Income, Gain, Loss and Deduction
The Partnership’s items of income, gain, loss and deduction will generally be allocated among the General Partner and the Unitholders in accordance with their respective percentage interests in the Partnership.
Certain items of the Partnership’s income, gain, loss or deduction will be allocated as required or permitted by Section 704(c) of the Internal Revenue Code to account for the difference between the tax basis and fair market value of property contributed to the Partnership. Allocations will also be made to account for the difference between the fair market value of the Partnership’s assets and their tax basis at the time of any offering.
In addition, certain items of recapture income which the Partnership recognizes on the sale of any of its assets will be allocated to the extent provided in regulations and the partnership agreement which generally require such depreciation recapture to be allocated to the partner who (or whose predecessor in interest) was allocated the deduction giving rise to the treatment of such gain as recapture income.
Treatment of Partnership Distributions
The Partnership’s distributions to a Unitholder generally will not be taxable for federal income tax purposes to the extent of the Unitholder’s tax basis in its LP Units immediately before the distribution. Distributions in excess of a Unitholder’s tax basis generally will be gain from the sale or exchange of the LP Units, taxable in accordance with the rules described under “Disposition of LP Units,” below. Any reduction in a Unitholder’s share of the Partnership’s liabilities for which no partner, including the General Partner, bears the economic risk of loss (“nonrecourse liabilities”) will be treated as a distribution of cash to that Unitholder.
A non-pro rata distribution of money or property may result in ordinary income to a Unitholder if such distribution reduces the Unitholder’s share of the Partnership’s “unrealized receivables,” including depreciation recapture or substantially appreciated “inventory items,” both as defined in Section 751 of the Internal Revenue Code (collectively, “Section 751 Assets”).
Basis of LP Units
A Unitholder will have an initial tax basis for its LP Units equal to the amount paid for the LP Units plus its share of the Partnership’s liabilities. A Unitholder’s tax basis will be increased by his share of the Partnership’s income and by any increase in his share of the Partnership’s liabilities. A Unitholder’s tax basis will be decreased, but not below zero, by its share of the Partnership’s distributions, by its share of the Partnership’s losses, by any decrease in its share of the Partnership’s liabilities and by its share of the Partnership’s expenditures that are not deductible in computing the Partnership’s taxable income and are not required to be capitalized.
Tax Treatment of Operations
The Partnership uses the adjusted tax basis of its various assets for purposes of computing depreciation and cost recovery deductions and gain or loss on any disposition of such assets. If the Partnership disposes of depreciable property, all or a portion of any gain may be subject to the recapture rules and taxed as ordinary income rather than capital gain.
The costs incurred in promoting the issuance of LP Units (i.e., syndication expenses) must be capitalized and cannot be deducted by the Partnership currently, ratably or upon the Partnership’s termination. Uncertainties exist regarding the classification of costs as organization expenses, which may be amortized, and as syndication expenses, which may not be amortized, but underwriters’ discounts and commissions are treated as syndication costs.
Section 754 Election
The Partnership has made the election permitted by Section 754 of the Code, which effectively permits the Partnership to adjust the tax basis of its assets to each purchaser of the Partnership’s LP Units from another Unitholder pursuant to Section 743(b) of the Internal Revenue Code to reflect the purchaser’s purchase price. The Section 743(b) adjustment is intended to provide a purchaser with the equivalent of an adjusted tax basis in the purchaser’s share of the Partnership’s assets equal to the value of such share that is indicated by the amount that the purchaser paid for the LP Units.
A Section 754 election is advantageous if the transferee’s tax basis in the transferee’s LP Units is higher than such LP Units’ share of the aggregate tax basis of the Partnership’s assets immediately prior to the transfer because the transferee would have, as a result of the election, a higher tax basis in the transferee’s share of the Partnership’s assets. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in the transferee’s LP Units is lower than such LP Units’ share of the aggregate tax basis of the Partnership’s assets immediately prior to the transfer. The Section 754 election is irrevocable without the consent of the IRS.
The Partnership intends to compute the effect of the Section 743(b) adjustment so as to preserve the ability to determine the tax attributes of an LP Unit from its date of purchase and the amount paid therefor. In that regard, the Partnership has adopted depreciation and amortization conventions that may not conform with all aspects of applicable Treasury regulations, though the Partnership believes that they do conform to Section 743(b) of the Code.
The calculations involved in the Section 754 election are complex and are made by the Partnership on the basis of certain assumptions as to the value of assets and other matters. There is no assurance that the determinations made by the Partnership will prevail if challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether.
Notification Requirements
A Unitholder who sells or exchanges LP Units is required to notify the Partnership in writing of that sale or exchange within 30 days after the sale or exchange and in any event by no later than January 15 of the year following the calendar year in which the sale or exchange occurred. The Partnership is required to notify the IRS of that transaction and to furnish certain information to the transferor and transferee. However, these reporting requirements do not apply with respect to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker. Failure to satisfy these reporting obligations may lead to the imposition of substantial penalties.
Constructive Termination
The Partnership will be considered terminated if there is a sale or exchange of 50% or more of the total interests in its capital and profits within a 12-month period. Any such termination would result in the closing of the Partnership’s taxable year for all Unitholders. In the case of a Unitholder reporting on a taxable year that does not end with the Partnership’s taxable year, the closing of the taxable year may result in more than 12 months of taxable income or loss being includable in that Unitholder’s taxable income for the year of termination. New tax elections required to be made by the Partnership, including a new election under Section 754 of the Internal Revenue Code, must be made subsequent to a termination and a termination could result in a deferral of deductions for depreciation. A termination could also result in penalties if the Partnership was unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject the Partnership to, any tax legislation enacted prior to the termination.
Alternative Minimum Tax
Each Unitholder will be required to take into account his share of items of income, gain, loss or deduction for purposes of the alternative minimum tax. A portion of depreciation deductions may be treated as an item of tax preference for this purpose. A Unitholder’s alternative minimum taxable income derived from the Partnership may be higher than his share of the Partnership’s net income because the Partnership may use accelerated methods of depreciation for federal income tax purposes. Prospective Unitholders should consult their tax advisors as to the impact of an investment in LP Units on their liability for the alternative minimum tax.
Loss Limitations
The deduction by a Unitholder of that Unitholder’s allocable share of the Partnership’s losses will be limited to the amount of that Unitholder’s tax basis in his or her LP Units and, in the case of an individual Unitholder or a corporate Unitholder who is subject to the “at risk” rules (generally, certain closely-held corporations), to the amount for which the Unitholder is considered to be “at risk” with respect to the Partnership’s activities, if that is less than the Unitholder’s tax basis. A Unitholder must recapture losses deducted in previous years to the extent that distributions cause the Unitholder’s at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a Unitholder or recaptured as a result of these limitations will carry forward and will be allowable to the extent that the Unitholder’s tax basis or at risk amount, whichever is the limiting factor, subsequently increases. Upon the taxable disposition of an LP Unit, any gain recognized by a Unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation.
In general, a Unitholder will be at risk to the extent of the Unitholder’s tax basis in the Unitholder’s LP Units, excluding any portion of that basis attributable to the Unitholder’s share of the Partnership’s nonrecourse liabilities, reduced by any amount of money the Unitholder borrows to acquire or hold the Unitholder’s LP Units if the lender of such borrowed funds owns an interest in the Partnership, is related
to such a person or can look only to LP Units for repayment. A Unitholder’s at risk amount will increase or decrease as the tax basis of the Unitholder’s LP Units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in the Unitholder’s share of the Partnership’s nonrecourse liabilities.
The passive loss limitations generally provide that individuals, estates, trusts, certain closely-held corporations and personal service corporations can deduct losses from passive activities, which include any trade or business activity in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. Moreover, the passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses generated by the Partnership will only be available to Unitholders who are subject to the passive loss rules to offset future passive income generated by the Partnership and, in particular, will not be available to offset income from other passive activities, investments or salary. Passive losses that are not deductible because they exceed a Unitholder’s share of income may be deducted in full when the Unitholder disposes of the Unitholder’s entire investment in the Partnership in a fully taxable transaction to an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions such as the at-risk rules and the basis limitation.
Deductibility of Interest Expense
The Code generally provides that investment interest expense is deductible only to the extent of a non-corporate taxpayer’s net investment income. In general, net investment income for purposes of this limitation includes gross income from property held for investment, gain attributable to the disposition of property held for investment (except for net capital gains for which the taxpayer has elected to be taxed at special capital gains rates) and portfolio income (determined pursuant to the passive loss rules as income not derived from a trade or business) reduced by certain expenses (other than interest) which are directly connected with the production of such income. Property that generates passive losses under the passive loss rules is not generally treated as property held for investment. However, the IRS has issued a Notice which provides that net income from a publicly traded partnership (not otherwise treated as a corporation) may be included in net investment income for purposes of the limitation on the deductibility of investment interest. Furthermore, a Unitholder’s investment income attributable to its LP Units will also include its allocable share of the Partnership’s portfolio income. A Unitholder’s investment interest expense will include its allocable share of the Partnership’s interest expense attributable to portfolio investments.
Valuation of Partnership Properties
The federal income tax consequences of the ownership and disposition of LP Units will depend in part on the Partnership’s estimates of the fair market values and its determination of the adjusted tax basis of assets. Although the Partnership may from time to time consult with professional appraisers with respect to valuation matters, the Partnership will make many of the fair market value estimates itself. These estimates and determinations are subject to challenge and will not be binding on the IRS or the courts. If such estimates or determinations of basis are subsequently found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by Unitholders might change, and Unitholders might be required to adjust their tax liability for prior years.
Withholding
If the Partnership was required or elected under applicable law to pay any federal, state or local income tax on behalf of any Unitholder, the Partnership is authorized to pay those taxes from its funds. Such payment, if made, will be treated as a distribution of cash to the Unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, the Partnership is authorized to treat the payment as a distribution to a current Unitholder.
Disposition of LP Units
A Unitholder will recognize gain or loss on a sale of LP Units equal to the difference between the amount realized and the Unitholder’s tax basis in the LP Units sold. A Unitholder’s amount realized is measured by the sum of the cash and the fair market value of other property received plus his share of liabilities. Because the amount realized includes a Unitholder’s share of the Partnership’s liabilities, the gain recognized on the sale of LP Units could result in a tax liability in excess of any cash received from such sale.
Gain or loss recognized by a Unitholder, other than a “dealer” in LP Units, on the sale or exchange of an LP Unit will generally be a capital gain or loss. Capital gain recognized on the sale of LP Units by an individual Unitholder held for more than one year will generally be taxed at a maximum rate of 15% (such rate to be increased to 20% for taxable years beginning after December 31, 2010). A portion of this gain or loss (which could be substantial), however, will be separately computed and will be classified as ordinary income or loss to the extent attributable to Section 751 Assets giving rise to depreciation recapture or other unrealized receivables or to inventory items owned by the Partnership. Ordinary income attributable to Section 751 may exceed net taxable gain realized upon the sale of the LP Units and will be recognized even if there is a net taxable loss realized on the sale of the LP Units. Thus, a Unitholder may recognize both ordinary income and a capital loss upon a disposition of LP Units. Net capital loss may offset no more than $3,000 ($1,500 in the case of a married individual filing a separate return) of ordinary income in the case of individuals and may only be used to offset capital gain in the case of corporations.
The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis. Upon a sale or other disposition of less than all of such interests, a portion of that tax basis must be allocated to the interests sold based upon relative fair market values. On the other hand, a selling partner who can identify partnership interests transferred with an ascertainable holding period may elect to use the actual holding period of the partnership interests transferred. A partner electing to use the actual holding period of partnership interests transferred must consistently use that identification method for all later sales or exchanges of partnership interests.
Unrelated Business Taxable Income
Certain entities otherwise exempt from federal income taxes (such as individual retirement accounts, pension plans and charitable organizations) are nevertheless subject to federal income tax on net unrelated business taxable income and each such entity must file a tax return for each year in which it has more than $1,000 of gross income from unrelated business activities. The General Partner believes that substantially all of the Partnership’s gross income will be treated as derived from an unrelated trade or business and taxable to such entities. The tax-exempt entity’s share of the Partnership’s deductions directly connected with carrying on such unrelated trade or business are allowed in computing the entity’s taxable unrelated business income. ACCORDINGLY, TAX-EXEMPT ENTITIES SUCH AS INDIVIDUAL RETIREMENT ACCOUNTS, PENSION PLANS AND CHARITABLE TRUSTS ARE ENCOURAGED TO CONSULT THEIR PROFESSIONAL TAX ADVISORS REGARDING THE TAX IMPLICATIONS OF THEIR OWNERSHIP OF L.P. UNITS.
Foreign Unitholders
Non-resident aliens and foreign corporations, trusts or estates which hold LP Units will be considered to be engaged in business in the United States on account of ownership of LP Units. As a consequence they will be required to file federal tax returns in respect of their share of the Partnership’s income, gain, loss or deduction and pay federal income tax at regular rates on any net income or gain. Generally, a partnership is required to pay a withholding tax on the portion of the partnership’s income which is effectively connected with the conduct of a United States trade or business and which is allocable to the
foreign partners, regardless of whether any actual distributions have been made to such partners. However, under rules applicable to publicly traded partnerships, taxes may be withheld at the highest marginal rate applicable to individuals on actual cash distributions made to foreign Unitholders who obtain a taxpayer identification number from the IRS and submit that number to the transfer agent of the publicly traded partnership.
Because a foreign corporation that owns LP Units will be treated as engaged in a United States trade or business, such a corporation will also be subject to United States branch profits tax at a rate of 30% (or any applicable lower treaty rate) of the portion of any reduction in the foreign corporation’s “U.S. net equity,” which is the result of the Partnership’s activities. In addition, such Unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.
In a published ruling, the IRS has taken the position that gain realized by a foreign partner who sells or otherwise disposes of a limited partner unit will be treated as effectively connected with a United States trade or business of the foreign partner, and thus subject to federal income tax, to the extent that such gain is attributable to appreciated personal property used by the limited partnership in a United States trade or business. Moreover, a foreign partner is subject to federal income tax on gain realized on the sale or disposition of a unit to the extent that such gain is attributable to appreciated United States real property interests; however, a foreign Unitholder will not be subject to federal income tax under this rule unless such foreign Unitholder has owned more than 5% in value of the Partnership’s LP Units during the five-year period ending on the date of the sale or disposition, provided the LP Units are regularly traded on an established securities market at the time of the sale or disposition.
Regulated Investment Companies
A regulated investment company, or “mutual fund,” is required to derive 90% or more of its gross income from specific sources including interest, dividends and gains from the sale of stocks or securities, foreign currency or specified related sources, and net income derived from the ownership of an interest in a “qualified publicly traded partnership.” The Partnership expects that it will meet the definition of a “qualified publicly traded partnership.”
State Tax Treatment
During 2006, the Partnership owned property or conducted business in the states of California, Colorado Connecticut, Florida, Illinois, Indiana, Kansas, Massachusetts, Michigan, Missouri, Nevada, New Jersey, New York, Ohio, Pennsylvania, Tennessee and Texas. A Unitholder will likely be required to file state income tax returns and to pay applicable state income taxes in many of these states and may be subject to penalties for failure to comply with such requirements. Some of the states have proposed that the Partnership withhold a percentage of income attributable to Partnership operations within the state for Unitholders who are non-residents of the state. In the event that amounts are required to be withheld (which may be greater or less than a particular Unitholder’s income tax liability to the state), such withholding would generally not relieve the non-resident Unitholder from the obligation to file a state income tax return.
A new entity level tax on the portion of our income that is generated in Texas will begin in our tax year ending in 2007. Specifically, the Texas margin tax will be imposed at a maximum effective rate of 0.7% of our gross income apportioned to Texas. Imposition of such a tax on us by Texas will reduce the cash available for distribution to our Unitholders.
Certain Tax Consequences to Unitholders
Upon formation of the Partnership in 1986, the General Partner elected twelve-year straight-line depreciation for tax purposes. For this reason, starting in 1999, the amount of depreciation available to the Partnership has been reduced significantly and taxable income has increased accordingly. Unitholders,
however, will continue to offset Partnership income with the amortization of their respective Section 743(b) adjustments (which, effectively, allow Unitholders who purchase LP Units other than directly from the Partnership to increase their share of the common basis of the Partnership’s assets to their purchase price). Each Unitholder’s tax situation will differ depending upon the price paid and when LP Units were purchased. Notwithstanding the additional taxable income beginning in 1999, the current cash distributions exceed expected tax payments. In addition, gain recognized on the sale of LP Units will, generally, result in taxable ordinary income as a consequence of depreciation recapture. UNITHOLDERS ARE ENCOURAGED TO CONSULT THEIR PROFESSIONAL TAX ADVISORS REGARDING THE TAX IMPLICATIONS TO THEIR OWNERSHIP OF LP UNITS.
Available Information
The Partnership files annual, quarterly, and current reports and other documents with the Securities and Exchange Commission (the “SEC”) under the Securities Exchange Act of 1934. The public can obtain any documents that the Partnership files with the SEC at http://www.sec.gov. The Partnership also makes available free of charge its Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after filing such materials with, or furnishing such materials to, the SEC, on or through the Partnership’s Internet website, www.buckeye.com. The Partnership is not including the information contained on its website as a part of, or incorporating it by reference into, this Annual Report on Form 10-K.
You can also find information about the Partnership at the offices of the New York Stock Exchange (“NYSE”), 20 Broad Street, New York, New York 10005 or at the NYSE’s Internet site www.nyse.com. The NYSE requires the chief executive officer of each listed company to certify annually that he is not aware of any violation by the company of the NYSE corporate governance listing standards as of the date of the certification, qualifying the certification to the extent necessary. The Chief Executive Officer of the General Partner provided such certification to the NYSE in 2006 without qualification. In addition, the certifications of the General Partner’s Chief Executive Officer and Chief Financial Officer required by Sections 302 and 906 of the Sarbanes-Oxley Act have been included as exhibits to the Partnership’s Annual Report on Form 10-K.
Item 1A.
Item 1A. Risk Factors
In this Item 1A, references to “we”, “us” and “our” mean Buckeye Partners, L.P. and its consolidated subsidiaries.
Risks Inherent to our Business
Changes in petroleum demand and distribution may adversely affect our business.
Demand for the services provided by our Operating Subsidiaries depends upon the demand for refined petroleum products in the regions served. Prevailing economic conditions, price and weather affect the demand for refined petroleum products. Changes in transportation and travel patterns in the areas served by our pipelines also affect the demand for refined petroleum products because a substantial portion of the refined petroleum products transported by our pipelines and throughput at our terminals is ultimately used as fuel for motor vehicles and aircraft. If these factors result in a decline in demand for refined petroleum products, the business of our Operating Subsidiaries would be particularly susceptible to adverse effects because they operate without the benefit of either exclusive franchises from government entities or long term contracts.
Energy conservation, changing sources of supply, structural changes in the oil industry and new energy technologies also could adversely affect our business. We cannot predict or control the effect of these factors on us or our Operating Subsidiaries.
Competition could adversely affect our operating results.
Generally, pipelines are the lowest cost method for long-haul overland movement of refined petroleum products. Therefore, our most significant competitors for large volume shipments are other existing pipelines, some of which are owned or controlled by major integrated oil companies. In addition, new pipelines (including pipeline segments that connect with existing pipeline systems) could be built to effectively compete with us in particular locations.
We compete with marine transportation in some areas. Tankers and barges on the Great Lakes account for some of the volume to certain Michigan, Ohio and upstate New York locations during the approximately eight non-winter months of the year. Barges are presently a competitive factor for deliveries to the New York City area, the Pittsburgh area, Connecticut and locations on the Ohio River such as Mt. Vernon, Indiana and Cincinnati, Ohio, and locations on the Mississippi River such as St. Louis, Missouri.
Trucks competitively deliver refined petroleum products in a number of areas that we serve. While their costs may not be competitive for longer hauls or large volume shipments, trucks compete effectively for incremental and marginal volumes in many areas that we serve. The availability of truck transportation places a significant competitive constraint on our ability to increase our Operating Subsidiaries’ tariff rates.
Privately arranged exchanges of refined products between marketers in different locations are an increasing form of competition. Generally, these exchanges reduce both parties’ costs by eliminating or reducing transportation charges. In addition, consolidation among refiners and marketers that has accelerated in recent years has altered distribution patterns, reducing demand for transportation services in some markets and increasing them in other markets.
Mergers among our customers and competitors could result in lower volumes being shipped on our pipelines and stored in our terminals, thereby reducing the amount of cash we generate.
Mergers between existing customers could provide strong economic incentives for the combined entities to utilize their existing pipeline and terminal systems instead of ours. As a result, we could lose some or all of the volumes and associated revenues from these customers and we could experience difficulty in replacing those lost volumes and revenues. Because most of our operating costs are fixed, a reduction in volumes would result in not only a reduction of revenues, but also a decline in net income and cash flow of a similar magnitude, which would reduce our ability to meet our financial obligations and pay cash distributions.
We are a holding company and depend entirely on our Operating Subsidiaries’ distributions to service our debt obligations and pay cash distributions to our Unitholders.
We are a holding company with no material operations. If we do not receive cash distributions from our Operating Subsidiaries, we will not be able to meet our debt service obligations or to make cash distributions to our Unitholders. Among other things, this would adversely affect the market price of our limited partner units. We are currently bound by the terms of a revolving credit facility which prohibits us from making distributions to our Unitholders if a default under the credit facility exists at the time of the distribution or would result from the distribution. Our Operating Subsidiaries may from time to time incur additional indebtedness under agreements that contain restrictions which could further limit each Operating Subsidiary’s ability to make distributions to us.
We may incur liabilities from assets we have acquired.
Some of the assets we have acquired have been used for many years to distribute, store or transport petroleum products. Releases from terminals or along pipeline rights-of-way may have occurred prior to our acquisition. In addition, releases may have occurred in the past that have not yet been discovered, which could require costly future remediation. If a significant release or event occurred in the past and we
are unable to recover from the seller, it could adversely affect our financial position and results of operations.
A decline in production at the ConocoPhillips Wood River refinery could materially reduce the volume of refined petroleum products we transport.
A decline in production at the ConocoPhillips Wood River refinery could materially reduce the volume of refined petroleum products we transport on certain of the pipelines owned by Wood River. As a result, our revenues and, therefore, our ability to pay cash distributions on our units could be adversely affected. The ConocoPhillips Wood River refinery could partially or completely shut down its operations, temporarily or permanently, due to factors such as unscheduled maintenance, catastrophes, labor difficulties, environmental proceedings or other litigation, loss of significant downstream customers; or legislation or regulation that adversely impacts the economics of refinery operations.
Potential future acquisitions and expansions, if any, may affect our business by substantially increasing the level of our indebtedness and contingent liabilities and increasing the risks of our being unable to effectively integrate these new operations.
From time to time, we evaluate and acquire assets and businesses that we believe complement our existing assets and businesses. Acquisitions may require substantial capital or the incurrence of substantial indebtedness. If we consummate any future acquisitions, our capitalization and results of operations may change significantly.
Acquisitions and business expansions involve numerous risks, including difficulties in the assimilation of the assets and operations of the acquired businesses, inefficiencies and difficulties that arise because of unfamiliarity with new assets and the businesses associated with them and new geographic areas and the diversion of management’s attention from other business concerns. Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. Following an acquisition, we may discover previously unknown liabilities associated with the acquired business for which we have no recourse under applicable indemnification provisions.
Debt securities we issue are, and will continue to be, junior to claims of our Operating Subsidiaries’ creditors.
Our outstanding debt securities are structurally subordinated to the claims of our Operating Subsidiaries’ creditors. In addition, any debt securities we issue in the future will likewise be subordinated in the same manner. Holders of the debt securities will not be creditors of our Operating Subsidiaries. Our claim to the assets of our Operating Subsidiaries derives from our own ownership interests in those Operating Subsidiaries. Claims of our Operating Subsidiaries’ creditors will generally have priority as to the assets of our Operating Subsidiaries over our own ownership interests and will therefore have priority over the holders of our debt, including our debt securities.
Our Operating Subsidiaries’ rate structures are subject to regulation and change by the Federal Energy Regulatory Commission.
Buckeye, Wood River, BPL Transportation, Buckeye NGL and Norco are interstate common carriers regulated by the FERC, under the Interstate Commerce Act and the Department of Energy Organization Act. The FERC’s primary ratemaking methodology is price indexing. This methodology is used to establish rates on the pipelines owned by Wood River, BPL Transportation, Buckeye NGL and Norco. The indexing method presently allows a pipeline to increase its rates by a percentage equal to the change in the annual producer price index for finished goods plus 1.3%. If the change in PPI +1.3% is negative, we could be required to reduce the rates charged by Wood River, BPL Transportation, Buckeye NGL and Norco if
they exceed the new maximum allowable rate. In addition, changes in the PPI might not fully reflect actual increases in the costs associated with these pipelines, thus hampering our ability to recover our costs.
Buckeye presently is authorized to charge rates set by market forces, subject to limitations, rather than by reference to costs historically incurred by the pipeline, in 15 regions and metropolitan areas. The Buckeye program is an exception to the generic oil pipeline regulations the FERC issued under the Energy Policy Act of 1992. The generic rules rely primarily on the index methodology described above. In the alternative, a pipeline is allowed to charge market-based rates if the pipeline establishes that it does not possess significant market power in a particular market.
The Buckeye rate program was reevaluated by the FERC in July 2000, and was allowed to continue with no material changes. We cannot predict the impact, if any, that a change in the FERC’s method of regulating Buckeye would have on our operations, financial condition or results of operations.
Environmental regulation may impose significant costs and liabilities on us.
Our Operating Subsidiaries are subject to federal, state and local laws and regulations relating to the protection of the environment. Risks of substantial environmental liabilities are inherent in the Operating Subsidiaries’ operations, and we cannot assure you that the Operating Subsidiaries will not incur material environmental liabilities. Additionally, our costs could increase significantly and we could face substantial liabilities, if, among other developments:
· environmental laws, regulations and enforcement policies become more rigorous; or
· claims for property damage or personal injury resulting from the operations of the Operating Subsidiaries are filed.
Existing or future state or federal government regulations relating to certain chemicals or additives in gasoline or diesel fuel could require capital expenditures or result in lower pipeline volumes and thereby adversely affect our results of operations.
Changes made to governmental regulations governing the components of refined petroleum products may necessitate changes to our pipelines and terminals which may require significant capital expenditures or result in lower pipeline volumes. For instance, the increasing use of ethanol as a fuel additive, which is blended with gasoline at product terminals, may lead to reduced pipeline volumes and revenue which may not be totally offset by increased terminal blending fees we may receive at our terminals.
Department of Transportation regulations may impose significant costs and liabilities on us.
The Operating Subsidiaries’ pipeline operations are subject to regulation by the United States Department of Transportation. These regulations require, among other things, that pipeline operators engage in a regular program of pipeline integrity testing to assess, evaluate, repair and validate the integrity of their pipelines, which, in the event of a leak or failure, could affect populated areas, unusually sensitive environmental areas, or commercially navigable waterways. In response to these regulations, the Operating Subsidiaries conduct pipeline integrity tests on an ongoing and regular basis. Depending on the results of these integrity tests, the Operating Subsidiaries could incur significant and unexpected capital and operating expenditures, not accounted for in anticipated capital or operating budgets, in order to repair such pipelines to ensure their continued safe and reliable operation.
Terrorist attacks could adversely affect our business.
Since the attacks of September 11, 2001, the United States government has issued warnings that energy assets, specifically our nation’s pipeline infrastructure, may be the future target of terrorist organizations. These developments have subjected our operations to increased risks. Any future terrorist attack on our facilities, those of our customers and, in some cases, those of other pipelines, refineries or terminals, could have a material adverse effect on our business.
Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.
Our Operating Subsidiaries’ operations are subject to operational hazards and unforeseen interruptions such as natural disasters, 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. Our Operating Subsidiaries’ operations are currently covered by property, casualty, workers’ compensation and environmental insurance policies. In the future, however, we may not be able to maintain or obtain insurance of the type and amount desired at reasonable rates. As a result of market conditions, premiums and deductibles for certain insurance policies have increased substantially, and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. For example, insurance carriers are now requiring broad exclusions for losses due to war risk and terrorist acts. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position, thereby reducing our ability to make distributions to Unitholders, or payments to debt holders.
Risks Relating to Partnership Structure
Our partnership status may be a disadvantage to us in calculating cost of service for rate-making purposes.
In the past, the FERC ruled that pass-through entities, like us, may not claim an income tax allowance for income attributable to non-corporate limited partners in justifying the reasonableness of their rates that are based on their cost of service. Further, in a July 2004 decision involving an unrelated pipeline limited partnership, the United States Court of Appeals for the District of Columbia Circuit overruled a prior FERC decision allowing a limited partnership to claim a partial income tax allowance. On May 4, 2005, the FERC adopted a new policy providing that all entities owning public utility assets-oil and gas pipelines and electric utilities-would be permitted to include an income tax allowance in their cost-of-service rates to reflect the actual or potential income tax liability attributable to their public utility income, regardless of the form of ownership. FERC determined that any pass-through entity seeking an income tax allowance in a rate proceeding must establish that its partners have an actual or potential income tax obligation on the entity’s public utility income. The amount of any income tax allowance will be reduced accordingly to the extent that any of the partners do not have an actual or potential income tax obligation. This reduction will be reflected in the weighted income tax liability of the entity’s partners. Whether a pipeline’s ultimate owners have actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. Although this new policy is generally favorable for pipelines that are organized as pass-through entities, it still entails risk due to the case-by-case review requirement. This policy was applied by FERC in June 2005 with an order involving an unrelated pipeline limited partnership. FERC concluded that the pipeline should be afforded an income tax allowance on all of its partnership interests to the extent that the owners of those interests had an actual or potential income tax obligation during the periods at issue. In December 2005, FERC reaffirmed its new income tax allowance policy as it applied to that pipeline. FERC’s tax allowance policy has been appealed to the United States Court of Appeals for the District of Columbia Circuit. The ultimate outcome of these proceedings is not certain and could result in changes to the FERC’s treatment of income tax allowances.
A shipper or FERC could cite these decisions in a protest or complaint challenging indexed rates maintained by certain of our Operating Subsidiaries. If a challenge was brought and FERC were to find that some of the indexed rates exceed levels justified by the cost of service, FERC could order a reduction in the indexed rates and could require reparations. As a result, our results of operations could be adversely affected.
We may sell additional limited partner units, diluting existing interests of Unitholders.
Our partnership agreement allows us to issue additional limited partner units and certain other equity securities without Unitholder approval. There is no limit on the total number of limited partner units and other equity securities we may issue. When we issue additional limited partner units or other equity securities, the proportionate partnership interest of our existing Unitholders will decrease. The issuance could negatively affect the amount of cash distributed to Unitholders and the market price of the limited partner units. Issuance of additional units will also diminish the relative voting strength of the previously outstanding units.
Our general partner and its affiliates may have conflicts with the Partnership.
The directors and officers of our general partner and its affiliates have fiduciary duties to manage the general partner in a manner that is beneficial to its sole member, BGH. At the same time, the general partner has fiduciary duties to manage the Partnership in a manner that is beneficial to our partners. Therefore, the general partner’s duties to us may conflict with the duties of its officers and directors to its sole member.
Such conflicts may arise from, among others, the following factors:
· decisions by our general partner regarding the amount and timing of our cash expenditures, borrowings and issuances of additional limited partner units or other securities can affect the amount of incentive distribution payments we make to our general partner;
· under our partnership agreement we reimburse the general partner for the costs of managing and operating the Partnership; and
· under our partnership agreement, it is not a breach of our general partner’s fiduciary duties for affiliates of our general partner to engage in activities that compete with us.
Specifically, the parent company of our general partner, BGH, is owned by its public unitholders, certain members of senior management, and by an affiliate of the Carlyle/Riverstone Global Energy and Power Fund II, L.P., which also owns, through affiliates, an interest in the general partner of Magellan Midstream Partners, L.P., and an interest in the general partner of SemGroup, L.P. SemGroup transports and stores crude oil, natural gas, natural gas liquids, refined products and asphalt through its ownership and operation of proprietary and common carrier pipelines, terminals, storage tanks, processing plants, underground storage facilities and a transportation fleet. Additionally, an affiliate of Carlyle/Riverstone is a member of a group of investors that has agreed to purchase Kinder Morgan, Inc., which owns the general partner interest in Kinder Morgan Energy Partners, L.P. (“Kinder Morgan”), a publicly traded partnership engaged in the transportation and distribution of petroleum products primarily in the midwestern United States. In January 2007, the Federal Trade Commission approved the closing of the transaction on the condition that Carlyle/Riverstone relinquish its control of Magellan Midstream Partners. Although neither the Partnership, on the one hand, nor Magellan Midstream Partners or SemGroup on the other hand, has extensive operations in the geographic areas primarily served by the other entity, the Partnership will compete directly with Magellan Midstream Partners, SemGroup L.P., Kinder Morgan, and perhaps other entities in which Carlyle/Riverstone or its affiliates have an interest for acquisition opportunities and potentially will compete with one or more of these entities for new business or extensions of the existing services provided by our Operating Subsidiaries, creating actual and potential conflicts of interest between the Partnership and affiliates of our general partner.
A default under BGH’s Credit Facility could result in a change of control of our general partner which would be an event of default under our revolving credit facility.
BGH is a party to a $10.0 million credit agreement with SunTrust Bank, pursuant to which it has pledged its ownership interest in our general partner as collateral security for its obligations under this
agreement. If BGH were to default on its obligations under its credit agreement, its lender could exercise its rights under this pledge which could result in a change of control of our general partner and a change of control of us. A change of control would constitute an event of default under our revolving credit facility and require the administrative agent, upon request of the lenders providing a majority of the loan commitments or outstanding loan amounts, to declare all amounts payable by us under our revolving credit facility immediately due and payable.
Unitholders have limited voting rights and control of management.
Our general partner manages and controls our activities and the activities of our Operating Subsidiaries. Unitholders have no right to elect the general partner or the directors of the general partner on an annual or other ongoing basis. However, if the general partner resigns or is removed, its successor must be elected by holders of a majority of the limited partner units. Unitholders may remove the general partner only by a vote of the holders of at least 80% of the limited partner units and only after receiving certain state regulatory approvals required for the transfer of control of a public utility. As a result, Unitholders will have limited influence on matters affecting our operations, and third parties may find it difficult to gain control of us or influence our actions.
Our partnership agreement limits the liability of our general partner.
Our general partner owes fiduciary duties to our Unitholders. Provisions of our partnership agreement and the partnership agreements for each of our operating partnerships, however, contain language limiting the liability of the general partner to the Unitholders for actions or omissions taken in good faith which do not involve gross negligence or willful misconduct. In addition, the partnership agreements grant broad rights of indemnification to the general partner and its directors, officers, employees and affiliates.
Unitholders may not have limited liability in some circumstances.
The limitations on the liability of holders of limited partnership interests for the obligations of a limited partnership have not been clearly established in some states. If it were determined that we had been conducting business in any state without compliance with the applicable limited partnership statute, or that the Unitholders as a group took any action pursuant to our partnership agreement that constituted participation in the “control” of our business, then the Unitholders could be held liable under some circumstances for our obligations to the same extent as a general partner.
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 distributions paid to the Unitholder for a period of three years from the date of the distribution.
Tax Risks to Unitholders
Unitholders are urged to read the section above entitled “Tax Considerations for Unitholders” beginning on page 16 for a more complete discussion of the expected material federal income tax consequences of owning and disposing of limited partner units.
The IRS could treat us as a corporation for tax purposes or changes in law could subject us to entity-level taxation, which would substantially reduce the cash available for distribution to Unitholders.
The availability to a Unitholder of the anticipated after tax economic benefits of an investment in limited partner units depends, in large part, on our classification as a partnership for federal income tax purposes. No ruling from the Internal Revenue Service, or the IRS, as to this status has been or is expected to be requested.
If we were classified as a corporation for federal income tax purposes, we would be required to pay tax on our taxable income at corporate tax rates (currently a 35% federal rate), and distributions received by the Unitholders would generally be taxed a second time as corporate distributions. Because a tax would be imposed upon us as an entity, the cash available for distribution to the Unitholders would be substantially reduced. Treatment of us as a corporation would cause a material reduction in the anticipated cash flow and after-tax return to the Unitholders, likely causing a substantial reduction in the value of the limited partner units.
The law could be changed so as to cause us to be treated as a corporation for federal income tax purposes or otherwise to be subject to entity-level taxation. For example, a new entity level tax on the portion of our income that is generated in Texas will begin in our tax year ending in 2007. Specifically, the Texas margin tax will be imposed at a maximum effective rate of 0.7% of our gross income apportioned to Texas. Imposition of such a tax on us by Texas will reduce the cash available for distribution to our Unitholders.
A successful IRS contest of the federal income tax positions that we take may adversely affect the market for limited partner units.
We have not requested a ruling from the IRS with respect to our classification as a partnership for federal income tax purposes. Accordingly, the IRS may adopt positions that differ from the conclusions expressed in this report or the positions taken by us. It may be necessary to resort to administrative or court proceedings in an effort to sustain some or all of such conclusions or the positions taken by us. A court may not concur with some or all of our positions. Any contest with the IRS may materially and adversely impact the market for the limited partner units and the prices at which they trade. In addition, the costs of any contest with the IRS will be borne directly or indirectly by the Unitholders and our general partner.
Unitholders may be required to pay taxes even if they do not receive any cash distributions.
A Unitholder will be required to pay federal income taxes and, in some cases, state and local income taxes on the Unitholder’s allocable share of our income, even if the Unitholder receives no cash distributions from us. We cannot guarantee that a Unitholder will receive cash distributions equal to the Unitholder’s allocable share of our taxable income or even the tax liability to the Unitholder resulting from that income. Further, if we incur a large amount of nonrecourse indebtedness, a Unitholder may incur a tax liability upon the sale of the Unitholder’s limited partner units in excess of the amount of cash received in the sale.
Ownership of limited partner units may have adverse tax consequences for tax-exempt organizations and certain other investors.
Investment in limited partner units by certain tax-exempt entities, regulated investment companies and foreign persons raises issues unique to them. For example, virtually all of our taxable income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and thus will be taxable to the Unitholder. Distributions to foreign persons will be reduced by withholding taxes. Further, Unitholders who are nonresident aliens, foreign corporations or other foreign persons will be required to file a federal income tax return and pay tax on their respective allocable shares of our taxable income because they will be regarded as being engaged in a trade or business in the United States as a result of their ownership of limited partner units.
There are limits on the deductibility of our losses that may adversely affect Unitholders.
There are a number of limitations that may prevent Unitholders from using their allocable share of our losses as a deduction against unrelated income. In the case of taxpayers subject to the passive loss rules (generally, individuals and closely-held corporations), any losses generated by us will only be available to offset our future income and cannot be used to offset income from other activities, including other passive activities or investments. Unused losses may be deducted when the unitholder disposes of the Unitholder’s entire investment in us in a fully taxable transaction with an unrelated party. A Unitholder’s share of our net passive income may be offset by unused losses from us carried over from prior years, but not by losses from other passive activities, including losses from other publicly traded partnerships. Other limitations that may further restrict the deductibility of our losses include the at-risk rules and the prohibition against loss allocations in excess of limited partner unit tax basis.
Tax gain or loss on disposition of limited partner units could be different than expected.
A Unitholder who sells limited partner units will recognize gain or loss equal to the difference between the amount realized from the sale (which will include the Unitholder’s share of our liabilities to the extent deemed relieved in the sale) and the Unitholder’s adjusted tax basis in the sold limited partner units (which will include the Unitholder’s share of our liabilities only if not previously used to support loss allocations or to defer tax on our distributions). Prior distributions in excess of cumulative net taxable income allocated to a Unitholder with respect to a limited partner unit which decreased such Unitholder’s tax basis in that limited partner unit will, in effect, become taxable income if the limited partner unit is sold at a price greater than the Unitholder’s tax basis in that limited partner unit, even if the price is less than the unit’s original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income.
The reporting of partnership tax information is complicated and subject to audits.
We will furnish each Unitholder with a Schedule K-1 that sets forth the Unitholder’s share of our income, gains, losses and deductions. We cannot guarantee that these schedules will be prepared in a manner that conforms in all respects to statutory or regulatory requirements or to administrative pronouncements of the IRS. Further, our tax return may be audited, which could result in an audit of a Unitholder’s individual tax return and increased liabilities for taxes because of adjustments resulting from the audit.
There is a possibility of loss of tax benefits relating to nonconformity of limited partner units and nonconforming depreciation conventions.
Because we cannot match transferors and transferees of limited partner units, uniformity of the tax characteristics of the limited partner units to a purchaser of limited partner units of the same class must be maintained. To maintain uniformity and for other reasons, we have adopted certain depreciation and amortization conventions that may not conform with all aspects of applicable Treasury regulations. A successful challenge to those conventions by the IRS could adversely affect the amount and timing of tax benefits available to a purchaser of limited partner units, as well as the amount of gain recognized from a sale of the limited partner units, and could have a negative impact on the value of the limited partner units.
Unitholders will likely be subject to state, local and other taxes in states where they do not reside or as a result of an investment in the limited partner unit.
In addition to United States federal income taxes, Unitholders will likely be subject to other taxes, such as state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which the Unitholder resides or in which we do business or own property. A Unitholder will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of the various jurisdictions in which we do business or own property and
may be subject to penalties for failure to comply with those requirements. It is the responsibility of each Unitholder to file all applicable United States federal, state, local and foreign tax returns.
Unitholders may have negative tax consequences if we default on our debt or sell assets.
If we default on any of our debt, the lenders will have the right to sue us for non-payment. This could cause an investment loss and negative tax consequences for Unitholders through the realization of taxable income by Unitholders without a corresponding cash distribution. Likewise, if we were to dispose of assets and realize a taxable gain while there is substantial debt outstanding and proceeds of the sale were applied to the debt, our Unitholders could have increased taxable income without a corresponding cash distribution.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Item 2. Properties
As of December 31, 2006, the principal facilities of the Partnership included approximately 5,400 miles of 6-inch to 24-inch diameter pipeline, approximately 100 delivery points and 45 active bulk storage and terminal facilities with aggregate capacity of approximately 17.6 million barrels. In addition, the Partnership owns four currently idle terminals with an aggregate storage capacity of 863,000 barrels. The Partnership’s pipelines are used by its Pipeline Operations segment and its terminals and storage facilities are used in its Terminalling and Storage segment. Properties used in the Partnership’s Other Operations segment include a 63% interest in a crude butadiene pipeline between Deer Park, Texas and Port Arthur, Texas, known as the Sabina pipeline, a 23-mile pipeline located in Texas that is leased to a third-party chemical company and a 29-mile ammonia pipeline located in Texas. The Operating Subsidiaries and their subsidiaries own substantially all of these facilities. The Partnership’s corporate headquarters in Breinigsville, Pennsylvania is approximately 75,000 square feet in size and is leased.
In general, the Partnership’s pipelines are located on land owned by others pursuant to rights granted under easements, leases, licenses and permits from railroads, utilities, governmental entities and private parties. Like other pipelines, certain of the Operating Subsidiaries’ rights are revocable at the election of the grantor or are subject to renewal at various intervals, and some require periodic payments. The Operating Subsidiaries have not experienced any revocations or lapses of such rights which were material to their business or operations, and the General Partner has no reason to expect any such revocation or lapse in the foreseeable future. Most delivery points, pumping stations and terminal facilities are located on land owned by the Operating Subsidiaries.
The General Partner believes that the Operating Subsidiaries have sufficient title to their material assets and properties, possess all material authorizations and revocable consents from state and local governmental and regulatory authorities and have all other material rights necessary to conduct their business substantially in accordance with past practice. Although in certain cases the Operating Subsidiaries’ title to assets and properties or their other rights, including their rights to occupy the land of others under easements, leases, licenses and permits, may be subject to encumbrances, restrictions and other imperfections, none of such imperfections are expected by the General Partner to interfere materially with the conduct of the Operating Subsidiaries’ businesses.
Item 3.
Item 3. Legal Proceedings
The Partnership, in the ordinary course of business, is involved in various claims and legal proceedings, some of which are covered in whole or in part by insurance. The General Partner is unable to predict the timing or outcome of these claims and proceedings.
With respect to environmental litigation, certain Operating Subsidiaries (or their predecessors) have been named in the past as defendants in lawsuits, or have been notified by federal or state authorities that they are potentially responsible parties (“PRPs”) under federal laws or a respondent under state laws relating to the generation, disposal or release of hazardous substances into the environment. In connection with actions brought under CERCLA and similar state statutes, the Operating Subsidiary is usually one of many PRPs for a particular site and its contribution of total waste at the site is usually de minimis.
Although there is no material environmental litigation pending against the Partnership or the Operating Subsidiaries at this time, claims may be asserted in the future under various federal and state laws, and the amount of any potential liability associated with such claims cannot be estimated. See “Business-Environmental Matters.”
In the third quarter of 2006 the Partnership received penalty assessments from the IRS in the aggregate amount of $4.3 million based on a failure to timely file excise tax information returns relating to its terminal operations from January 2005 through February 2006. The Partnership filed the information returns with the IRS on May 10, 2006. In January 2007, the Partnership agreed to pay the IRS approximately $0.6 million to settle and resolve the penalty assessment. The settlement is subject to the negotiation and execution of a closing agreement between the Partnership and the IRS. The negotiated penalty assessment has been recorded as an expense in the Partnership’s financial statements in the fourth quarter of 2006.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of the holders of LP Units during the fourth quarter of the fiscal year ended December 31, 2006.
PART II
Item 5.
Item 5. Market for the Registrant’s LP Units, Related Unitholder Matters, and Issuer Purchases of LP Units
The LP Units of the Partnership are listed and traded principally on the New York Stock Exchange. The high and low sales prices of the LP Units in 2006 and 2005, as reported in the New York Stock Exchange Composite Transactions, were as follows:
On February 7, 2005, the Partnership issued 1.1 million LP Units in an underwritten public offering at $45.00 per LP Unit. Proceeds from the offering, after the underwriter’s discount of $1.46 per unit and offering expenses, were approximately $47.7 million. Proceeds from the offering were used to repay, in part, amounts outstanding under the Partnership’s revolving line of credit and to fund the Partnership’s expansion and cost reduction capital expenditures.
On May 17, 2005, the Partnership issued 2.5 million LP Units in an underwritten public offering at $45.20 per LP Unit. Proceeds from the offering, after the underwriters’ discount of $1.80 per LP Unit and offering expenses, were approximately $108.4 million. Proceeds from the offering were used to repay $108 million that was outstanding under the Partnership’s revolving line of credit.
On March 7, 2006, the Partnership issued 1.5 million LP Units in an underwritten public offering at $44.22 per LP Unit. Proceeds from the offering, after the underwriter’s discount of $1.45 per LP Unit and offering expenses, were approximately $64.1 million. Proceeds from the offering were used to repay amounts outstanding under the Partnership’s revolving line of credit.
The Partnership has gathered tax information from its known LP Unitholders and from brokers/nominees and, based on the information collected, the Partnership estimates its number of beneficial LP Unitholders to be approximately 50,000 at December 31, 2006.
Cash distributions paid during 2005 and 2006 were as follows:
Item 6.
Item 6. Selected Financial Data
The following tables set forth, for the period and at the dates indicated, the Partnership’s income statement and balance sheet data for each of the last five years. The tables should be read in conjunction with the consolidated financial statements and notes thereto included elsewhere in this Report.
(1) Net income in 2006 is $6.6 million higher due to the re-characterization, effective in the fourth quarter of 2006, of incentive compensation payments to the Partnership’s General Partner as equity distributions rather than compensation payments. See Note 21 to the Partnership’s financial statements for further discussion.
(2) Net income in 2003 includes an expense of $45.5 million related to a yield maintenance premium paid on the retirement of the $240 million Senior Notes of Buckeye.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion provides an analysis of the results for each of the Partnership’s operating segments, an overview of its liquidity and capital resources and other items related to the Partnership. The following discussion and analysis should be read in conjunction with the consolidated financial statements and related notes included in this Annual Report on Form 10-K for the year ended December 31, 2006.
Overview
Buckeye Partners, L.P. (the “Partnership”) is a publicly traded master limited partnership (NYSE symbol: BPL) organized in 1986 under the laws of the state of Delaware. The Partnership’s principal line of business is the transportation, terminalling and storage of petroleum products in the United States for major integrated oil companies, large refined petroleum product marketing companies and major end users of petroleum products on a fee basis through facilities owned and operated by the Partnership. The Partnership also operates pipelines owned by third parties under contracts with major integrated oil and chemical companies, and performs certain construction activities, generally for the owners of those third-party pipelines.
The Partnership’s direct subsidiaries are Buckeye Pipe Line Company, L.P. (“Buckeye”), Laurel Pipe Line Company, L.P. (“Laurel”), Everglades Pipe Line Company, L.P. (“Everglades”), Buckeye Pipe Line Holdings, L.P. (“BPH”), Wood River Pipe Lines LLC (“Wood River”), Buckeye Pipe Line Transportation LLC (“BPL Transportation”) and Buckeye NGL Pipe Lines LLC (“Buckeye NGL”). Each of these entities is referred to as an “Operating Subsidiary” and they are collectively referred to as the “Operating Subsidiaries.” The Partnership owns an approximately 99% interest in each Operating Subsidiary except that it owns a 100% interest in each of Wood River, BPL Transportation and Buckeye NGL.
The Partnership’s pipeline system and terminals generate a substantial portion of the Partnership’s cash flows. The revenues generated by the Partnership’s businesses are significantly influenced by demand for refined petroleum products. Operating expenses are principally fixed costs related to routine maintenance and system integrity as well as field and support personnel. Other costs, including power, fluctuate with volumes transported in the Partnership’s pipelines or stored in its terminals. Expenses resulting from environmental remediation projects have historically included costs from projects relating both to current and past events. For further discussion of environmental matters, see “Business-Environmental Regulation” under Item 1 of this Annual Report on Form 10-K.
Strategic Actions
The Partnership’s primary business strategies are to generate stable cash flows, increase pipeline and terminal throughput and pursue strategic cash-flow accretive acquisitions that complement the Partnership’s existing asset base, improve operating efficiencies, and allow increased cash distributions to Unitholders. In the years 2004, 2005 and 2006, the Partnership significantly expanded its operations through the following asset acquisitions:
· On October 1, 2004, the Partnership acquired five refined petroleum products pipelines with an aggregate mileage of approximately 900 miles and 24 refined products terminals with an aggregate storage capacity of 9.3 million barrels (the “Midwest Pipelines and Terminals”) from Shell Oil Products U.S. (“Shell”) for a purchase price of $517.0 million.
· In May 2005, the Partnership acquired a refined petroleum products pipeline system comprising approximately 478 miles of pipeline and four refined products terminals with aggregate storage capacity of approximately 1.3 million barrels located principally in the northeastern United States (the “Northeast Pipelines and Terminals”) from affiliates of ExxonMobil Corporation (“ExxonMobil”) for a purchase price of $175.0 million.
· In December 2005, the Partnership acquired a 26-mile pipeline and a 40% interest in a joint venture company that owns another refined petroleum products pipeline and terminal in the midwestern United States. It also acquired a refined petroleum products terminal and related assets (including certain railroad offloading facilities) located in Taylor, Michigan for a purchase price of $20.0 million.
· On January 1, 2006, the Partnership acquired a refined petroleum products terminal located in Niles, Michigan, with aggregate storage capacity of 630,000 barrels from affiliates of Shell for a purchase price of $13.0 million.
· On January 31, 2006, the Partnership acquired a natural gas liquids pipeline (the “NGL Pipeline”) with aggregate mileage of approximately 350 miles from BP Pipelines (North America) Inc. for approximately $87.0 million, including a deposit of $7.7 million paid in December 2005. The NGL Pipeline extends generally from Wattenberg, Colorado to Bushton, Kansas.
The acquired assets have been included in the Partnership’s operations from their dates of acquisition.
Operating Segments
The Partnership has determined that its operations are appropriately presented in three operating segments:
· Pipeline Operations,
· Terminalling and Storage, and
· Other Operations.
Pipeline Operations:
The Pipeline Operations segment receives petroleum products including gasoline, jet fuel, diesel fuel and other distillates and natural gas liquids from refineries, connecting pipelines and bulk and marine terminals and transports those products to other locations by pipeline for a fee. As of December 31, 2006, this segment owned and operated approximately 5,400 miles of pipelines in the following states: California, Colorado, Connecticut, Florida, Illinois, Indiana, Kansas, Massachusetts, Michigan, Missouri, New Jersey, Nevada, New York, Ohio, Pennsylvania and Tennessee.
Terminalling and Storage:
The Terminalling and Storage segment provides bulk storage and terminal throughput services. This segment consists of 45 active terminals that have the capacity to store an aggregate of approximately 17.6 million barrels of refined petroleum products. The terminals are located in Illinois, Indiana, Massachusetts, Michigan, Missouri, New York, Ohio and Pennsylvania.
Other Operations:
The Other Operations segment consists primarily of the Partnership’s operation of third-party pipelines owned principally by major petrochemical companies pursuant to operations and maintenance contracts. The third party pipelines are located primarily in Texas. This segment also includes the provision by the Partnership, through its Buckeye Gulf Coast subsidiary, of pipeline construction management services, typically on a cost plus a fixed fee basis. The Other Operations segment also includes the Partnership’s ownership and operation of an ammonia pipeline acquired in November 2005, and its majority ownership of a crude butadiene pipeline located in Texas.
Results of Operations
Summary
Summary operating results for the Partnership were as follows:
The improvement in revenues, operating income and net income in 2006 compared to 2005, and 2005 compared to 2004, is generally due to the expansion of the Partnership’s operations through acquisitions, internal growth projects, and increases in interstate pipeline tariff rates and terminalling throughput fees.
The Partnership’s net income in 2006 reflects an amendment of the Partnership’s Incentive Compensation Agreement and Partnership Agreement between the General Partner and the Partnership which changed the incentive compensation paid to the General Partner from a compensation payment to a partnership distribution as described in Note 21 to the Partnership’s financial statements. These amendments affected the Partnership’s results of operations commencing in the fourth quarter of 2006. Accordingly, net income for 2006 was $6.6 million higher than it would have been if the Partnership Agreement had not been amended.
Earnings per limited partner unit as shown above were impacted by the issuance of 1.5 million LP Units in March 2006, 2.5 million LP Units in May 2005, 1.1 million LP Units in February 2005 and 5.5 million LP units in October 2004.
EBITDA and Adjusted EBITDA
The following table summarizes EBITDA and adjusted EBITDA for the Partnership for the years ended December 31, 2006, 2005 and 2004. EBITDA, a measure not defined under generally accepted accounting principles (“GAAP”) is defined by the Partnership as income before interest expense (including amortization and write-off of deferred debt financing costs), income taxes, depreciation and amortization. Adjusted EBITDA, also a non-GAAP measure, is defined as EBITDA plus the General Partner incentive compensation expense. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, operating profit, cash flow from operations or any other measure of financial performance presented in accordance with GAAP.
Because EBITDA and Adjusted EBITDA exclude some items that affect net income and these items may vary among other companies, the EBITDA and Adjusted EBITDA data presented may not be comparable to similarly titled measures at other companies. The Partnership has provided Adjusted EBITDA in addition to EBITDA because, commencing in the fourth quarter of 2006, the Partnership reports incentive payments to the General Partner as equity distributions, rather than incentive compensation expense as reported in periods prior to the fourth quarter of 2006. See Note 21 to the Partnership’s consolidated financial statements for a further discussion of this change. Accordingly, the General Partner incentive compensation presented below includes only three quarters of incentive payments and does not include the $6.6 million incentive payment paid in the fourth quarter of 2006. Future periods will not reflect General Partner incentive payments as a component of net income. Management of the Partnership uses EBITDA and Adjusted EBITDA as performance measures to assist in the analysis and assessment of the Partnership’s operations, to evaluate the viability of proposed projects and to determine overall rates of return on alternative investment opportunities. The Partnership believes that investors benefit from having access to the same financial measures used by the Partnership’s management.
Revenues and operating income by operating segment for each of the three years ended December 31, 2006, 2005 and 2004, were as follows:
Results of operations are affected by factors that include general economic conditions, weather, competitive conditions, demand for refined petroleum products, seasonal factors and regulation. See Item 1 - “Business-Competition and Other Business Considerations.”
2006 Compared to 2005
Revenues
Total revenues for the year ended December 31, 2006 were $461.7 million and increased by $53.3 million or 13% from revenue of $408.4 million in 2005.
Operating income in 2006 increased to $177.1 million from $161.3 million in 2005. The Partnership’s net income for 2006 was $110.2 million compared to net income in 2005 of $100.0 million. Net income per LP Unit was $2.64 in 2006 compared to net income per LP Unit of $2.69 in 2005. Net income per LP Unit in 2006 includes an increase in the average number of LP Units outstanding to 39.2 million from an average of 36.9 million LP Units outstanding during 2005.
Pipeline Operations:
Revenue from pipeline transportation of petroleum products was $350.9 million in 2006 compared to $306.8 million in 2005. The increase of $44.1 million was due primarily to higher volumes associated with pipeline assets acquired in 2006, or acquired in 2005 and operated for a full year in 2006, as well as tariff rate increases in connection with certain of the Partnership’s pipelines. More specifically, the increase in revenue in 2006 as compared to 2005 was due in part to:
· BPL Transportation revenue of $6.9 million (BPL Transportation’s assets were acquired on May 5, 2005);
· Buckeye NGL revenue of $10.8 million (Buckeye NGL’s assets were acquired on January 31, 2006);
· a 1.2% or $1.7 million increase net of BPL Transportation, in gasoline transportation revenue, on a 2.3% decline in gasoline volumes;
· a 13.0% or $6.4 million increase net of BPL Transportation, in jet fuel transportation revenue on an 8.2% increase in jet fuel volumes delivered;
· an 8.7% or $5.9 million increase net of BPL Transportation, in distillate transportation revenue on comparable distillate volumes delivered;
· a $4.0 million increase in incidental revenue primarily from increased revenues under a product supply arrangement in connection with WesPac-Reno;
· a $6.5 million increase in other revenues principally resulting from commencement of the pipeline and terminal operations of WesPac-Memphis in April 2006;
· a $5.5 million decrease in transportation settlement revenue, representing the settlement of overages and shortages on product deliveries.
Product deliveries for each of the three years ended December 31 were as follows:
During the approximate eight months in 2005 that the Partnership owned the BPL Transportation pipeline system, volumes on the BPL Transportation pipeline system averaged 74,400 barrels per day. Volumes on all of the Partnership’s other pipelines (excluding the BPL Transportation pipeline system) averaged 1,335,800 barrels per day for 2005.
Terminalling and Storage:
Terminalling and Storage revenues were $81.3 million in 2006 and increased by $12.4 million from Terminalling and Storage revenues generated in 2005.
Terminal acquisitions increased Terminalling and Storage revenues by $5.9 million for the year ended December 31, 2006 compared to 2005. The increase in terminal revenue associated with acquisitions reflects terminals acquired in 2006 and terminals acquired in 2005 and operated for a full year in 2006.
Terminalling and Storage revenues at existing terminals owned by the Partnership were $75.4 million for the year ended December 31, 2006, an increase of $6.5 million from Terminalling and Storage revenues generated by those terminals in 2005.
Average daily throughput for all refined petroleum products terminals for the years ended December 31 was as follows:
Other Operations:
Revenue from Other Operations of $29.6 million for the year ended December 31, 2006 decreased by $3.1 million from 2005 primarily as a result of the absence of a large construction project which provided approximately $7.7 million of revenue in 2005.
Operating Expenses
Costs and expenses for the years ended December 31, 2006, 2005 and 2004 were as follows:
Payroll and payroll benefits costs were $78.5 million in 2006, an increase of $5.6 million from 2005. Of this increase, approximately $3.5 million was related to the hiring of additional employees as a result of recent acquisitions. Increases in salaries and wages of $6.0 million resulted from an increase in the number of employees and overtime pay due to the Partnership’s expanded operations and higher wage rates. The Partnership also experienced an increase in benefit costs of $0.4 million. These increases were partially offset by an increase of capitalized payroll of $0.8 million resulting from increased charges to capital projects by internal personnel and a decrease in severance pay. The Partnership incurred expense of $0.4 million for severance pay in 2005 which did not occur during 2006. Payroll and benefits expense was also reduced by $2.0 million as a result of a reduction in the fair value of the Partnership’s liability under the Services Agreement to make future cash payments to Services Company in amounts sufficient for Services Company’s ESOP to make payments due under its note agreement. The reduction in the fair value of this liability resulted from changes in estimates of future cash distributions likely to be paid on the Partnership’s LP Units owned by Services Company. Payroll and benefits expense was also reduced by $1.1 million in 2006 compared to 2005 as a result of lower incentive compensation accruals. In 2006, the Partnership accrued approximately $0.9 million in annual incentive compensation for employees, compared to approximately $2.0 million in 2005.
Depreciation and amortization expense of $44.0 million increased by $7.3 million in 2006 over 2005. Depreciation related to acquisitions completed in 2006 was $3.5 million. The Partnership incurred depreciation expense of $0.7 million related to the Memphis Terminal which commenced operations in April 2006. The remaining increase resulted from assets placed into service during 2006.
Operating power costs, consisting primarily of electricity required to operate pumping facilities, were $28.9 million in 2006, an increase of $2.7 million over 2005. Recent acquisitions added $2.1 million to operating power expense. The remainder of the increase was principally due to higher rates associated with purchases of electricity.
Outside services costs, consisting principally of third-party contract services for maintenance activities, were $35.7 million in 2006, an increase of $11.3 million over 2005. Outside services costs related to recent acquisitions were $1.1 million. The Partnership incurred an additional $6.8 million for pipeline inspection and maintenance costs related to an operating service contract. The remainder of the increase was due to additional pipeline and tank inspections and maintenance work that occurred during 2006 as compared to 2005.
Property and other taxes were $20.9 million in 2006, an increase of $4.3 million over 2005. Of this increase, $1.1 million related to acquisitions completed in 2006. As more fully discussed in Note 4 to the financial statements, the Partnership incurred a $0.6 million charge related to a penalty assessment received from the IRS for failure to file excise tax information in a timely fashion. These increases were offset by a reimbursement of $0.9 million in 2006 for certain property taxes under an operating service agreement. The remainder of the increase was due to increased real estate property assessments over the same period in 2005.
Construction management costs were $8.4 million in 2006, a decrease from the prior year of $0.5 million. The decrease was a result of the absence of a significant construction contract that was completed in 2005.
All other costs were $68.1 million in 2006 compared to $61.3 million in 2005, an increase of $6.8 million. The increase reflects $3.1 million of costs associated with fuel purchases by WesPac Reno related to a product supply arrangement, with corresponding revenue included in the Partnership’s incidental revenue. Other costs related to recent acquisitions were $2.4 million. The Partnership had an increase in other expenses of $3.5 million related to the Memphis Terminal which commenced operations in April 2006. These increases were partially offset by a decrease in casualty losses of $2.5 million. The
remainder of the increases related to various pipeline operating costs resulting from the Partnership’s expanded operations.
Costs and expenses by segment for the years ended December 31, 2006, 2005, and 2004 were as follows:
Total other income (expense) for the years ended December 31, 2006, 2005 and 2004 were as follows:
Investment and equity income for the year ended December 31, 2006 was $1.4 million higher than 2005. The increase was principally a result of equity income earned from the Partnership’s approximate 40% interest in Muskegon Pipeline LLC which was acquired in December 2005.
Interest and debt expense for the year ended December 31, 2006 was $8.8 million higher than 2005. The Partnership incurred approximately $3.3 million of additional interest expense in 2006 because its 5.125% Notes that were issued in June of 2005 were outstanding for all of 2006. The balance of the increase in interest expense in 2006 resulted from higher average balances outstanding and higher interest rates on the Partnership’s revolving credit facility.
General Partner incentive compensation was $18.3 million for the year ended December 2006, as compared to $20.2 million in 2005, a decrease of $1.9 million. Since the latter part of 2004, this expense has steadily increased due to issuances of additional LP Units as well as increases in the quarterly distributions paid on the LP Units. As noted above and in Note 21 to the Partnership’s financial statements, in connection with the initial public offering of BGH, the Partnership’s Incentive Compensation Agreement and Partnership Agreement were amended to change the incentive payments to equity distributions rather than compensation payments. This change reduced the amount reported as a compensation expense in 2006 by $6.6 million and the Partnership will report no General Partner incentive compensation expense in 2007 and future years.
2005 Compared to 2004
Revenues
Total revenues for the year ended December 31, 2005 were $408.4 million and increased by $84.9 million or 26.2% from revenue of $323.5 million in 2004.
Pipeline Operations:
Revenue from pipeline transportation of petroleum products was $306.8 million in 2005 compared to $264.0 million in 2004. The increase of $42.8 million in transportation revenue was primarily the result of:
· a Wood River transportation revenue increase of $23.5 million (Wood River’s assets were acquired on October 1, 2004);
· BPL Transportation revenue of $12.1 million (BPL Transportation’s assets were acquired on May 5, 2005);
· a 3.7% average tariff rate increase effective May 1, 2005, and a 2.8% average tariff rate increase effective May 1, 2004;
· a 2.8% or $3.5 million increase, net of Wood River and BPL Transportation, in gasoline transportation revenue on a 1.0% decrease in gasoline volumes delivered;
· a 3.2% or $1.3 million increase, net of Wood River and BPL Transportation, in jet fuel transportation revenue on a 0.5% increase in jet fuel volumes delivered;
· a 4.2% or $2.7 million increase, net of Wood River and BPL Transportation, in distillate transportation revenue on a 2.4% increase in distillate volumes delivered;
· a decrease in liquefied petroleum gas (“LPG”) transportation revenue of $1.0 million as a result of lower LPG volumes delivered;
· a decrease in transportation settlement revenue, representing the settlement of overages and shortages on product deliveries, of $3.4 million; and
· a $3.7 million increase in incidental revenue primarily from increased revenues under a product supply arrangement in connection with WesPac Reno.
During the three months in 2004 that the Partnership owned the Wood River pipeline system, volumes on the Wood River pipeline system averaged 196,000 barrels per day. Volumes on all of the Partnership’s other pipelines (excluding the Wood River pipeline system) averaged 1,151,400 barrels per day for 2004.
During the approximate eight months in 2005 that the Partnership owned the BPL Transportation pipeline system, volumes on the BPL Transportation pipeline system averaged 74,400 barrels per day. Volumes on all of the Partnership’s other pipelines (excluding the BPL Transportation pipeline system) averaged 1,335,800 barrels per day for 2005.
Terminalling and Storage:
Terminalling and storage revenues were $68.8 million in 2005 and increased by $42.5 million from 2004.
The terminals acquired from Shell on October 1, 2004 (the “Shell Terminals”) generated terminalling and storage revenues of $48.9 million in 2005. This was $39.7 million greater than the terminalling and storage revenues generated by the Shell terminals during the three months they were owned by the Partnership in 2004. The terminals acquired from ExxonMobil on May 5, 2005 (the “ExxonMobil Terminals”) generated terminalling and storage revenues of $3.9 million in 2005.
Terminalling and storage revenues at other facilities owned by the Partnership were $16.0 million in 2005, a decline of $1.1 million from 2004. The decline in revenue resulted from a decrease in throughput charges of $1.8 million that was partially offset by a $0.7 million increase in rent and incidental charges.
Other Operations:
Revenue from other operations of $32.8 million for the year ended December 31, 2005 decreased by $0.4 million from 2004. Revenues from other operating activities include revenue from pipeline construction activities of $12.0 million, contract operating services of $14.2 million and rental revenues of $6.6 million.
Operating Expenses
Payroll and payroll benefits costs were $72.9 million in 2005, an increase of $11.8 million over 2004. Of this increase, approximately $7.4 million, which represented payroll and payroll benefit costs for the first nine months of 2005, was related to employees added as a result of the acquisition of the Midwest Pipelines and Terminals on October 1, 2004. Employees hired in connection with the acquisition of the Northeast Pipelines and Terminals added $2.0 million of payroll and payroll benefits costs. Of the remaining increase of $2.4 million of payroll costs, approximately $1.8 million resulted from increases in wage rates in 2005 compared to 2004.
Depreciation and amortization expense of $36.8 million increased by $10.8 million in 2005 over 2004. Depreciation related to the Midwest Pipelines and Terminals for the first nine months of 2005 was $7.6 million. The Northeast Pipelines and Terminals added $2.3 million of depreciation expense in 2005. The remaining increase of $0.9 million resulted from the Partnership’s ongoing maintenance and expansion capital program.
Operating power costs, consisting primarily of electricity required to operate pumping facilities, were $26.2 million in 2005, an increase of $3.3 million over 2004. The Midwest Pipelines and Terminals added $2.3 million in operating power costs from January 1 through September 30, 2005, and the Northeast Pipelines and Terminals added $1.7 million in operating power costs from the date of acquisition in May 2005. Increases in operating power costs that resulted from the acquisitions of the Midwest Pipelines and Terminals and Northeast Pipelines and Terminals were partially offset by a decrease of $0.8 million at the Partnership’s Buckeye Gulf Coast subsidiary related to the loss of an operations and maintenance contract with a third party in 2004.
Outside services costs, consisting principally of third-party contract services for maintenance activities, were $24.4 million in 2005, an increase of $4.5 million over 2004. Outside services costs related to the Midwest Pipelines and Terminals and Northeast Pipelines and Terminals for 2005 were $4.5 million and $0.8 million, respectively.
Property and other taxes were $16.6 million in 2005, an increase of $3.3 million over 2004. Property and other taxes related to the Midwest Pipelines and Terminals were $1.9 million. The Northeast Pipelines and Terminals added $1.3 million of property and other taxes. Of the remaining increase, the Partnership experienced higher real property tax assessments in several states.
Construction management costs were $8.9 million in 2005, a decrease from the prior year of $3.4 million. The decrease in construction management costs was a result of the completion of a major construction contract with a chemical company which began in 2004 and was completed in the first quarter of 2005.
All other costs were $61.3 million in 2005 compared to $45.8 million in 2004, an increase of $15.5 million. Other costs related to the Midwest Pipelines and Terminals and Northeast Pipelines and Terminals were $7.1 million and $3.8 million, respectively. The Partnership experienced an increase of $3.5 million in costs related to a product supply arrangement over such costs in 2004. Casualty losses, net of the Midwest Pipelines and Terminals and Northeast Pipelines and Terminals, increased by $1.1 million primarily as a result of pipeline and terminal product releases in 2005.
Other income (expense) was a net expense of $61.4 million in 2005, compared to a net expense of $39.2 million in 2004. Investment income in 2005 was consistent with investment income generated in 2004.
The Partnership incurred interest expense of $43.4 million in 2005 compared to $27.6 million in 2004, which is an increase of $15.8 million. Approximately $11.3 million of the interest expense incurred in 2005 related to the Partnership’s 5.300% Notes due 2014, which were issued in October 2004 in connection with the acquisition of the Midwest Pipelines and Terminals. The Partnership incurred approximately $3.2 million in interest expense related to the 5.125% Notes due 2017, which were issued in June 2005 primarily in connection with the acquisition of the Northeast Pipelines and Terminals. Interest expense was reduced by $2.6 million in 2004 as a result of the interest rate swap in effect until December 2004. Increases in interest expense in 2005 were partially offset by an increase in capitalized interest which was due to an increase in capital projects in 2005.
General Partner incentive compensation was $20.2 million in 2005 compared to $14.0 million in 2004, an increase of $6.2 million. The increase in incentive compensation paid to the General Partner resulted from the issuance of 1.1 million LP Units in February 2005, the issuance of 2.5 million LP Units in May 2005, the full year impact of the issuance of the 5.5 million LP units in October 2004 and an increase in the quarterly distribution rate on the LP Units to Unitholders in 2005 compared to 2004.
Liquidity and Capital Resources
The Partnership’s financial condition at December 31, 2006, 2005, and 2004 is highlighted in the following comparative summary:
Liquidity and Capital Indicators
(1) current assets divided by current liabilities
(2) current assets minus current liabilities
(3) long-term debt divided by long-term debt plus total partners’ capital
(4) total partners’ capital divided by total units outstanding at year-end.
During 2006, 2005 and 2004 the Partnership’s principal sources of cash were cash from operations, borrowings under its revolving credit facility and proceeds from the financing transactions described under “Cash Flows from Financing Activities” below. The Partnership’s principal uses of cash are capital expenditures, investments and acquisitions, distributions to Unitholders and repayments of borrowings.
At December 31, 2006, the Partnership had $995.0 million aggregate principal amount of long-term debt, which consisted of $300.0 million of the Partnership’s 4.625% Notes due 2013 (the “4.625% Notes”), $275.0 million of the Partnership’s 5.30% Notes due 2014 (the “5.30% Notes”), $150.0 million of the Partnership’s 6.75% Notes due 2033 (the “6.75% Notes”), $125.0 million of the Partnership’s 5.125% Notes due 2017 (the “5.125% Notes”) and $145.0 million outstanding under the Partnership’s revolving credit facility.
On November 13, 2006 the Partnership entered into a new $400.0 million 5-year revolving credit facility (the “Credit Facility”) with a syndicate of banks. The Credit Facility, which replaced the Partnership’s previous $400.0 million credit facility, contains a one-time expansion feature up to $600.0 million subject to certain conditions. Borrowings under the Credit Facility are guaranteed by certain of the Partnership’s subsidiaries. The Credit Facility matures on November 13, 2011 but may be extended for up to two additional 12-month periods under certain circumstances. The weighted average interest rate on amounts outstanding under the Credit Facility at December 31, 2006 was 5.59%.
Borrowings under the Credit Facility bear interest under one of two rate options, selected by the Partnership, equal to either (i) the greater of (a) the federal funds rate plus 0.5% and (b) SunTrust Bank’s prime rate plus an applicable margin, or (ii) the London Interbank Offered Rate (“LIBOR”) plus an applicable margin. The applicable margin is determined based on the current utilization level of the Credit Facilitly and ratings assigned by Standard & Poor’s and Moody’s Investor Services for the Partnership’s senior unsecured non-credit enhanced long-term debt. At December 31, 2006 and December 31, 2005, the Partnership had $145.0 million and $50.0 million outstanding under the Credit Facility and its predecessor credit facility, respectively, and had committed $2.1 million and $1.7 million in support of letters of credit, respectively.
The Credit Facility contains covenants and provisions that:
· Restrict the Partnership and certain of its subsidiaries’ ability to incur additional indebtedness based on a Funded Debt ratio described below;
· Prohibit the Partnership and certain of its subsidiaries from creating or incurring certain liens on their property;
· Prohibit the Partnership and certain of its subsidiaries from disposing of property material to their operations; and
· Limit consolidations, mergers and asset transfers by the Partnership and certain of its subsidiaries.
The Credit Facility requires that the Partnership and certain of its subsidiaries maintain a maximum “Funded Debt Ratio” which is calculated using “EBITDA” as defined in the Credit Facility. The Credit Facility’s definition of EBITDA is substantially the same as the Partnership’s definition above for EBITDA (for quarterly periods commencing with the fourth quarter of 2006) and Adjusted EBITDA (for quarterly periods commencing prior to the fourth quarter of 2006), except that the Credit Facility excludes the income of certain majority-owned subsidiaries and equity investments, though distributions from these excluded entities to the Partnership are included in EBITDA.
The Partnership’s Funded Debt Ratio at the end of any quarterly period equals the ratio of the long-term debt of the Partnership and certain of its subsidiaries (including the current portion, if any) to EBITDA for the previous four fiscal quarters. As of the end of any fiscal quarter, the Funded Debt Ratio may not exceed 4.75 to 1.00, subject to a provision for increases to 5.25 to 1.00 in connection with future acquisitions. At December 31, 2006 the Partnership’s Funded Debt Ratio was 4.40 to 1.00.
The Credit Facility provides for a “change of control” event of default that will be triggered if (i) Carlyle/Riverstone ceases to beneficially own 100% of the sole general partner of BGH, (ii) BGH ceases to own 100% of our general partner or (iii) our general partner ceases to be our sole general partner.
At December 31, 2006 the Partnership was in compliance with all of the covenants under the Credit Facility.
The Partnership’s financial strategy is to maintain an investment-grade credit rating, which involves, among other things, the issuance of additional LP Units in connection with the Partnership’s acquisitions
and internal growth activities in order to maintain acceptable financial ratios, including total debt to total capital. From 2003 through 2006 the Partnership raised net proceeds of approximately $439.3 million from the issuance of its LP Units in support of its acquisition and growth strategies. The Partnership may issue additional LP Units in 2007 and beyond to partially fund acquisitions and internal growth activities, market conditions permitting. The Partnership is subject, however, to changes in the equity markets for its LP Units, and there can be no assurance the Partnership will be able or willing to access the public or private markets for its LP Units in the future. If the Partnership were unable to issue additional LP Units, the Partnership would be required to either restrict potential future acquisitions or pursue other debt financing alternatives, some of which could involve higher costs.
Cash Flows from Operations
The components of cash flows from operations for the years ended December 31, 2006, 2005 and 2004 were as follows:
Cash flows from operations were $149.0 million in 2006, compared to $142.5 million in 2005, an increase of $6.5 million. The principal reason for the increase was the increase in the Partnership’s net income of $10.3 million and an increase of $7.3 million in depreciation and amortization, a non-cash expense, which were partially offset by increased working capital requirements in 2006 as compared to 2005 of $9.8 million. Depreciation and amortization increased principally from the acquisition of new assets in 2005 and 2006, as well as the Partnership’s ongoing capital programs.
During 2006, the increase in cash used in working capital resulted primarily from increases in trade receivables of $12.2 million and prepaid insurance and other current assets of $22.8 million. The increase in trade receivables was principally due to the expansion of the Partnership’s business (the acquisition of the NGL Pipeline and certain terminals along with the commencement of operations at WesPac-Memphis), as well as the timing of pipeline billings at year-end. The increase in prepaid and other current assets resulted from receivables of $6.3 million related to activities on the ammonia pipeline purchased by the Partnership in November 2005, increases of $8.5 million resulting from amounts determined to be recoverable from insurance companies related to environmental remediation expenditures, an increase in prepaid insurance of $2.6 million as well as other increases totaling $4.4 million. A portion of the insurance receivables related to amounts billed to the insurance companies, with the balance relating to anticipated future expenditures at identified remediation sites. These decreases in cash were partially offset by an increase in accrued and other current liabilities of $18.0 million. Of this increase, $6.1 million related to payables arising from activity on the ammonia pipeline purchased in November 2005, $5.5 million related to the current portion of environmental liabilities (a portion of which is recoverable from insurance as described above) and $4.8 million related to other current liabilities. The change in other assets and liabilities resulted principally from the absence in 2006 of the accrual of certain long-term environmental liabilities which occurred in 2005.
Cash flows from operations were $142.5 million in 2005, compared to $99.7 million in 2004, an increase of $42.8 million. The principal reason for the increase was the Partnership’s increase in net income of $17.0 million, coupled with an increase in depreciation and amortization of $10.8 million, a non-cash expense. Depreciation and amortization increased by $10.8 million as a result of the inclusion of the Midwest Pipelines and Terminals for twelve months in 2005 compared to three months in 2004, as well as the addition of the Northeast Pipelines and Terminals in May 2005, along with ongoing capital additions. Also, in 2004 the Partnership experienced a $13.4 million increase in working capital resulting from the operations it acquired with the Midwest Pipelines and Terminals which was not repeated in 2005 (working capital increased by $1.1 million). In 2005, an increase in trade and other receivables of $6.4 million and construction and pipeline relocation receivables of $1.2 million (related to timing of pipeline billings) were principally offset by a reduction in prepaid and other current assets of $5.9 million and an increase in accounts payable and accrued liabilities of $1.2 million. In 2004, trade receivables increased by $15.4 million and construction receivables increased by $4.4 million. The increase in trade receivables was related to increased outstanding billings related primarily to the terminal assets acquired as part of the Midwest Pipelines and Terminals. In connection with terminal revenue, the Partnership bills on a monthly basis, compared to the weekly basis used in pipeline billings. Construction and pipeline relocation receivables increased in 2004 due to an increase in construction activity in the fourth quarter. Prepaid and other current assets increased by $4.4 million in 2004, principally related to insurance receivables associated with environmental claims. Partially offsetting these reductions in 2004 cash from operations were increases in accounts payable of $0.7 million and accrued and other current liabilities of $10.3 million. The 2004 increase in accrued and other current liabilities resulted from an increase in accrued interest payable related to the timing of the semi-annual interest payments due on the Partnership’s 5.300% Notes issued in October 2004 and an increase in accrued environmental liabilities.
Cash Flows from Investing Activities
Net cash used in investing activities for the years ended December 31, 2006, 2005 and 2004 were as follows:
In 2006, the Partnership paid $94.3 million related to acquisitions, including $79.3 million related to the NGL Pipeline, $12.5 million related to the acquisition of the Niles, Michigan terminal and approximately $2.5 million for miscellaneous asset acquisitions.
In 2005, cash used for investments and acquisitions consisted of $176.3 million for the Northeast Pipelines and Terminals with the balance expended in connection with a terminal acquisition in Taylor, Michigan, a deposit of $7.7 million for the NGL Pipeline, the purchase of an ammonia pipeline located near Houston, TX and the acquisition of the 25% of WesPac - Reno not previously owned by the Partnership. In 2004, investments and acquisitions consisted of the acquisition of the Midwest Pipelines and Terminals. In addition, in December 2005, the Partnership acquired an approximately 26-mile pipeline and a 40% interest in Muskegon Pipeline LLC (“Muskegon”), which owns an approximately 170-mile pipeline which extends from Griffith, IN to Muskegon, MI (together, the “Pipeline Interests”). The Pipeline Interests were acquired in exchange for consideration that included capacity lease agreements (with purchase options) related to one of the Partnership’s pipelines and a terminal. The Partnership has
recorded the Pipeline Interests at their estimated fair values of $20.1 million, with $4.8 million allocated to the 26-mile pipeline and $15.3 million allocated to the 40% interest in Muskegon.
Capital expenditures are summarized below:
In 2006, the Partnership incurred $30.2 million of sustaining capital expenditures and $62.5 million of expansion and cost reduction expenditures. The increase in sustaining capital expenditures related principally to construction of leasehold improvements to the Partnership’s new administrative offices in Breinigsville, PA and transition capital expenditures related to assets purchased in late 2005 and in 2006. Expansion projects in 2006 included $12.4 million to complete an approximate 11-mile pipeline and related terminal facilities to serve the Memphis International Airport, $12.1 million for the addition of pipelines, tankage and equipment to meet new handling requirements for ultra-low sulfur diesel, and $11.9 million for a capacity expansion in Illinois to handle additional LPG volumes. Other expansion projects underway in 2006 included various ethanol-blending and butane-blending projects at pipeline stations and terminals owned by the Partnership, and an expansion of pipeline and terminal infrastructure at the Memphis International Airport to accommodate a new generation of cargo planes for Federal Express Corporation. The Memphis International Airport project is owned by WesPac Pipelines-Memphis, a 75%-owned subsidiary of the Partnership.
The Partnership expects to spend approximately $80.0 million in capital expenditures in 2007, of which approximately $30.0 million is expected to relate to sustaining capital expenditures and $50.0 million is expected to relate to expansion and cost reduction projects. Sustaining capital expenditures include renewals and replacement of tank floors and roofs and upgrades to station and terminalling equipment, field instrumentation and cathodic protection systems.
During 2005, the Partnership’s capital expenditures of $77.8 million increased by $5.2 million from $72.6 million in capital expenditures in 2004. In 2005, sustaining capital expenditures decreased by $9.4 million to $23.4 million principally as a result of a reduction in pipeline and tank integrity capital expenditures of $11.3 million, which was only partially offset by an increase in operating infrastructure expenditures of $1.9 million. The reduction in pipeline and tank integrity expenditures occurred because (1) the Partnership completed much of the integrity work required, including electronic internal inspections, other integrity expenditures and associated repairs and improvements, as part of its comprehensive plan to comply with legal requirements and to improve the reliability of the Partnership’s pipelines and terminals (see “Business-Environmental Matters” and “Business-Pipeline Regulation and Safety Matters”) and (2) an increasing amount of the Partnership’s integrity expenditures were charged to expense in 2005 compared to 2004.
Until December 31, 2005, the Partnership’s initial integrity expenditures had been capitalized as part of pipeline cost when such expenditures improved or extended the life of the pipeline or related assets. Subsequent integrity expenditures have been expensed as incurred. As of January 1, 2006, the Partnership began charging all internal inspection integrity expenditures to expense, whether or not such expenditures were for the initial or subsequent internal inspection. In 2006, approximately $10.5 million of integrity costs
were expensed compared to $3.0 million in 2005 and $0.9 million in 2004. The Partnership expects to charge approximately $10 million of integrity expenditures to expense in 2007.
Expansion and cost reduction capital expenditures were $54.4 million in 2005, an increase of $14.6 million from $39.8 million in 2004. The majority of these expenditures related to two major projects. During 2005, the Partnership expended $33.7 million on an approximately 11-mile pipeline and associated terminal to serve Federal Express at the Memphis International Airport. The project entered commercial service in the first quarter of 2006. In 2004, approximately $10.3 million was expended in connection with this project. Also in 2005, the Partnership expended approximately $9.3 million to complete a major expansion of the Partnership’s Laurel pipeline across Pennsylvania. In 2004, approximately $11.0 million was expended in connection with this project. The remaining $11.4 million of expansion and cost reduction capital expended in 2005 related to various other projects including a butane blending project associated with the Partnership’s Macungie, Pennsylvania station. In 2004, the Partnership expended approximately $12.8 million to complete the replacement of approximately 45 miles of pipeline in the Midwest between Lima, Ohio and Huntington, Indiana. The pipeline replacement project improved the reliability of the pipeline and expanded its capacity.
Total capital expenditures among the Partnership’s three operating segments were as follows:
Cash Flows from Financing Activities
In order to fund its acquisition and internal growth opportunities, the Partnership issued debt and equity securities and borrowed amounts under a Credit Facility (a portion of which were repaid with the proceeds from the issuance of debt and equity securities) in 2006, 2005 and 2004.
The Partnership’s financing transactions are summarized as follows:
Equity Securities:
On March 7, 2006, the Partnership issued 1.5 million LP Units in an underwritten public offering at $44.22 per LP Unit. Proceeds from the offering, after underwriter’s discount of $1.45 per LP Unit and offering expenses, were approximately $64.1 million and were used to reduce amounts outstanding under the Credit Facility.
On May 17, 2005, the Partnership issued 2.5 million LP Units in an underwritten public offering at $45.20 per LP Unit. Proceeds from the offering, after underwriters’ discount of $1.80 per LP Unit and offering expenses, were approximately $108.4 million. Proceeds from the offering were used to reduce amounts outstanding under the Credit Facility.
On February 7, 2005, the Partnership issued 1.1 million LP Units in an underwritten public offering at $45.00 per LP Unit. Proceeds from the offering, after underwriters’ discount of $1.46 per LP Unit and offering expenses, were approximately $47.7 million. Proceeds from the offering were used to reduce amounts outstanding under the Credit Facility and to fund the Partnership’s expansion and cost reduction capital expenditures.
On October 19, 2004, the Partnership issued 5.5 million LP Units in an underwritten public offering at $42.50 per LP Unit. Proceeds from the LP Unit offering were approximately $223.3 million after underwriters’ discount of $1.806 per LP Unit and offering expenses and were used to reduce amounts outstanding under the Credit Facility.
Debt Securities:
On June 30, 2005, the Partnership sold $125 million aggregate principal amount of its 5.125% Notes due July 1, 2017 in an underwritten public offering. Proceeds from the note offering, after underwriters’ fees and expenses, were approximately $123.5 million. Proceeds from the offering were used in part to repay $122.0 million that was outstanding under the Credit Facility.
On October 1, 2004, in connection with the acquisition of the Midwest Pipelines and Terminals, the Partnership borrowed a total of $490.0 million, consisting of $300.0 million under a 364-day interim loan (the “Interim Loan”) and $190.0 million under the Credit Facility. On October 12, 2004, the Partnership sold $275.0 million aggregate principal amount of its 5.300% Notes due 2014 in an underwritten public offering. Proceeds from the note offering, after underwriter’s discount and commissions, were approximately $272.1 million. Proceeds from the note offering, together with additional borrowings under the Credit Facility, were used to repay the Interim Loan.
In addition to the above, the Partnership borrowed $177.0 million, $250.0 million and $320.0 million, and repaid $82.0 million, $273.0 million and $247.0 million under the Credit Facility (and its predecessor facility) in 2006, 2005 and 2004, respectively.
Distributions:
Distributions to Unitholders increased to $125.5 million in 2006 compared to $104.3 million in 2005 and $80.2 million in 2004. Distributions in 2006 increased over 2005 primarily as a result of increases in the unit distribution rate and the issuance of the 1.5 million LP Units in 2006. Additionally, distributions increased in 2006 by $6.6 million as a result of incentive payments to the General Partner being treated as distributions rather than compensation payments beginning in the fourth quarter of 2006. Distributions in 2005 increased over 2004 primarily as a result of increases in the unit distribution rate and the issuance of the 5.5 million LP Units in October 2004.
Debt Obligations, Credit Facilities and Other Financing
At December 31, 2006, the Partnership had $995.0 million in aggregate outstanding long-term debt, consisting of $125.0 million of the 5.125% Notes due 2017, $275.0 million of the 5.300% Notes due 2014, $300.0 million of the 4 5/8% Notes due 2013, $150.0 million of the 6 ¾% Notes due 2033 and $145.0 million outstanding under the Credit Facility. The terms of the Credit Facility are described in “Liquidity and Capital Resources” above. At December 31, 2006, the Partnership had $252.9 million available under the Credit Facility, with $2.1 million allocated in support of certain operational letters of credit.
In December 2004 the Partnership terminated an interest rate swap agreement and received proceeds of $2.0 million. Interest expense in the Partnership’s income statement was reduced by $2.6 million in 2004 as a result of the interest rate swap. The Partnership has deferred the $2.0 million gain as an adjustment to the fair value of the hedged portion of the Partnership’s debt and is amortizing the gain as a reduction of interest expense over the remaining life of the hedged debt. Interest expense was reduced by $0.2 million in both 2006 and 2005.
Operating Leases
The Operating Subsidiaries lease certain land and rights-of-way. Minimum future lease payments for these leases as of December 31, 2006 were approximately $4.9 million for each of the next three years. Substantially all of these lease payments may be canceled at any time should the leased property no longer be required for operations.
The Partnership leases space in an office building and certain office equipment. Buckeye leases certain computing equipment and automobiles. Future minimum lease payments under these noncancelable operating leases at December 31, 2006 were as follows: $1.3 million for 2007, $1.1 million for 2008, $0.9 million for 2009, $1.0 million for 2010, $1.1 million for 2011 and $10.2 million in the aggregate thereafter.
Rent expense under operating leases was $10.3 million, $8.7 million and $8.5 million for 2006, 2005 and 2004, respectively.
Contractual Obligations
Contractual obligations are summarized in the following table:
Interest payable on fixed long-term debt obligations includes semi-annual payments required for the Partnership’s 4 5/8% Notes, its 6 3/4% Notes, its 5.300% Notes and its 5.125% Notes.
Amounts for acquisitions represents amounts for which the Partnership is contractually obligated to close in January 2007, including two refined petroleum products terminals located in Flint, Michigan and Woodhaven, Michigan.
Purchase obligations generally represent commitments for recurring operating expenses or capital projects.
The Partnership’s obligations related to its pension and postretirement benefit plans are discussed in Note 12 in the Partnership’s accompanying consolidated financial statements.
The Partnership’s interest payable under its Credit Facility is not reflected in the above table because such amounts depend on outstanding balances and interest rates which will vary from time to time. Based on balances outstanding and rates in effect at December 31, 2006, annual interest payments would be $8.1 million.
Environmental Matters
The Operating Subsidiaries are subject to federal, state and local laws and regulations relating to the protection of the environment. These laws and regulations, as well as the Partnership’s own standards
relating to protection of the environment, cause the Operating Subsidiaries to incur current and ongoing operating and capital expenditures. Environmental expenses are incurred in connection with emergency response activities associated with the release of petroleum products to the environment from the Partnership’s pipelines and terminals, and in connection with longer term environmental remediation efforts which may involve, for example, groundwater monitoring and treatment. The Partnership regularly incurs expenses in connection with these environmental remediation activities. In 2006, the Operating Subsidiaries incurred operating expenses of $6.2 million and at December 31, 2006, had $29.2 million accrued for environmental matters. At December 31, 2006, the Partnership estimates that approximately $8.0 million of environmental expenditures incurred will be covered by insurance. These recovery amounts have not been included in expense in the Partnership’s financial statements. The Partnership maintains environmental liability insurance covering all of its pipelines and terminals with a per occurrence deductible in the amount of $3.0 million. Expenditures, both capital and operating, relating to environmental matters are expected to continue due to the Partnership’s commitment to maintaining high environmental standards and to comply with increasingly rigorous environmental laws.
Employee Stock Ownership Plan
Services Company provides an employee stock ownership plan (the “ESOP”) to the majority of its regular full-time employees hired before September 16, 2004. Effective September 16, 2004, new employees, including employees hired by Services Company from BGC, Buckeye Terminals and Norco on December 26, 2004, do not participate in the ESOP. The ESOP owns all of the outstanding common stock of Services Company. As of December 31, 2006, Services Company owned 2,313,395 LP Units of the Partnership. As of the same date, the ESOP was directly obligated to a third-party lender for $27.2 million of 3.60% Notes due 2011 (the “ESOP Notes”). The ESOP Notes were issued on May 4, 2004 to refinance Services Company’s 7.24% Notes which were originally issued to purchase Services Company common stock. The ESOP Notes are secured by 2,313,395 shares of Services Company’s common stock. The Partnership has committed that, in the event that the value of the LP Units owned by Services Company falls to less than 125% of the balance payable under the ESOP Notes, the Partnership will fund an escrow account with sufficient assets to bring the value of the total collateral (the value of the LP Units owned by Services Company and the escrow account) up to the 125% minimum. Amounts deposited in the escrow account are returned to the Partnership when the value of the LP Units owned by Services Company returns to an amount which exceeds the 125% minimum. At December 31, 2006, the value of the LP Units was approximately $108 million, which exceeded the 125% minimum requirement.
Services Company common stock is released to employee accounts in the proportion that current payments of principal and interest on the ESOP Notes bear to the total of all principal and interest payments due under the ESOP Notes. Individual employees are allocated shares based on the ratio of their eligible compensation to total eligible compensation. Eligible compensation generally includes base salary, overtime payments and certain bonuses.
The Partnership contributed 2,573,146 LP Units to Services Company in August 1997 in exchange for the elimination of the Partnership’s obligation to reimburse its general partner and the parent of its general partner for certain executive compensation costs, a reduction of the incentive compensation paid by the Partnership to its general partner, and other changes that made the ESOP a less expensive fringe benefit for the Partnership. Funding for the ESOP Notes is provided by distributions that Services Company receives on the LP Units that it owns and from cash payments from the Partnership, which are required to cover any shortfall between the distributions that Services Company receives on the LP Units that it owns and amounts currently due under the ESOP Notes (the “top-up reserve”), except that the Partnership has no obligation to fund the accelerated portion of the ESOP Notes upon a default. The Partnership also incurs routine ESOP-related administrative costs and taxes associated with taxable income incurred on the sale of LP Units, if any. In 2006, ESOP costs were reduced by $2.0 million as
estimates of future shortfalls between the distributions that Services Company receives on the LP Units that it owns and amounts currently due under the ESOP Notes were reduced to reflect higher distributions on the LP Units than was previously anticipated. Total ESOP-related costs charged to earnings were $0.2 million and $0.6 million in 2005 and 2004, respectively.
Off-Balance Sheet Arrangements
The Partnership has no off-balance sheet arrangements except for operating leases.
Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to select appropriate accounting principles from those available, to apply those principles consistently and to make reasonable estimates and assumptions that affect revenues and associated costs as well as reported amounts of assets and liabilities.
Approximately 87% of the Partnership’s consolidated assets consist of property, plant and equipment. Property, plant and equipment consists of pipeline and related transportation facilities and equipment, including land, rights-of-way, buildings and leasehold improvements and machinery and equipment. Pipeline assets are generally self-constructed, using either contractors or the Partnership’s own employees. Additions and improvements to the pipeline are capitalized based on the cost of the improvement while repairs and maintenance are expensed.
As discussed under “Environmental Matters” above, the Operating Subsidiaries are subject to federal, state and local laws and regulations relating to the protection of the environment. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. Generally, the timing of these accruals coincides with the Partnership’s commitment to a formal plan of action. Accrued environmental remediation related expenses include estimates of direct costs of remediation and indirect costs related to the remediation effort, such as compensation and benefits for employees directly involved in the remediation activities and fees paid to outside engineering, consulting and law firms. The Partnership maintains insurance which may cover certain environmental expenditures. During 2006, the Operating Partnerships incurred operating expenses, net of insurance recoveries, of $6.2 million and, at December 31, 2006, had $29.2 million accrued for environmental matters. The environmental accruals are revised as new matters arise, or as new facts in connection with environmental remediation projects require a revision of estimates previously made with respect to the probable cost of such remediation projects.
Related Party Transactions
With respect to related party transactions see Note 16 to the consolidated financial statements and Item 13 “Certain Relationships and Related Transactions and Director Independence.”
Recent Accounting Pronouncements
See Note 2 to the Partnership’s consolidated financial statements for a description of certain new accounting pronouncements issued in the year ended December 31, 2006.
Forward-Looking Information
The information contained above in this Management’s Discussion and Analysis and elsewhere in this Annual Report on Form 10-K includes “forward-looking statements,” within the meaning of the Private
Securities Litigation Reform Act of 1995. Such statements use forward-looking words such as “anticipate,” “continue,” “estimate,” “expect,” “may,” “believe,” “will,” or other similar words, although some forward-looking statements are expressed differently. These statements discuss future expectations and contain projections. Specific factors that could cause actual results to differ from those in the forward-looking statements include, but are not limited to: (1) price trends and overall demand for petroleum products in the United States in general and in our service areas in particular (economic activity, weather, alternative energy sources, conservation and technological advances may affect price trends and demands); (2) competitive pressures from other transportation services; (3) changes, if any, in laws and regulations, including, among others, safety, tax and accounting matters or Federal Energy Regulatory Commission regulation of our tariff rates; (4) liability for environmental claims; (5) security issues affecting our assets, including, among others, potential damage to our assets caused by vandalism, acts of war or terrorism; (6) unanticipated capital expenditures and operating expenses to repair or replace our assets; (7) availability and cost of insurance on our assets and operations; (8) our ability to successfully identify and complete strategic acquisitions and make cost saving changes in operations; (9) expansion in the operations of our competitors; (10) our ability to integrate any acquired operations into our existing operations; and to realize anticipated cost savings and other efficiencies; (11) shut-downs or cutbacks at major refineries that use our services; (12) deterioration in our labor relations; (13) changes in real property tax assessments; (14) regional economic conditions; (15) disruptions to the air travel system; (16) interest rate fluctuations and other capital market conditions; (17) market conditions in our industry; (18) availability and cost of insurance on our assets and operations; (19) conflicts of interest between us, our general partner, the owner of our general partner and its affiliates; (20) the treatment of us as a corporation for federal income tax purposes or if we become subject to entity-level taxation for state tax purposes; and (21) the impact of government legislation and regulation on us.
These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on future results. Although the expectations in the forward-looking statements are based on our current beliefs and expectations, we do not assume responsibility for the accuracy and completeness of such statements. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Report on Form 10-K, including those described in the “Risk Factors” section of this Report. Further, we undertake no obligation to update publicly any forward-looking statement whether as a result of new information or future events.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Market Risk-Trading Instruments
Currently the Partnership has no derivative instruments and does not engage in hedging activity with respect to trading instruments.
Market Risk-Other than Trading Instruments
The Partnership is exposed to risk resulting from changes in interest rates. The Partnership does not have significant commodity or foreign exchange risk. The Partnership is exposed to fair value risk with respect to the fixed portion of its financing arrangements (the 5.125% Notes, the 5.300% Notes, the 4 5/8% Notes and the 6 ¾% Notes) and to cash flow risk with respect to its variable rate obligations (the Credit Facility). Fair value risk represents the risk that the value of the fixed portion of its financing arrangements will rise or fall depending on changes in interest rates. Cash flow risk represents the risk that interest costs related to the Credit Facility will rise or fall depending on changes in interest rates.
The Partnership’s practice with respect to derivative transactions has been to have each transaction authorized by the board of directors of the General Partner.
At December 31, 2006, the Partnership had total fixed debt obligations at face value of $850.0 million, consisting of $125.0 million of the 5.125% Notes, $275.0 million of the 5.300% Notes, $300.0 million of the 4 5/8% Notes and $150.0 million of the 6 ¾% Notes. The fair value of these obligations at December 31, 2006 was approximately $882.0 million. The Partnership estimates that a 1% decrease or increase in rates for obligations of similar maturities would increase or decrease the fair value of these obligations by $63.0 million. The Partnership’s variable debt obligation under the Credit Facility was $145.0 million. Based on the balance outstanding at December 31, 2006, a 1% increase or decrease in interest rates would increase or decrease annual interest expense by $1.5 million.
In December 2004, the Partnership terminated an interest rate swap agreement associated with the 4.625% Notes due June 15, 2013 and received proceeds of $2.0 million. In 2004 interest expense was reduced by $2.6 million as a result of the swap agreement. In accordance with FASB Statement No. 133-“Accounting for Derivative Instruments and Hedging Activities”, the Partnership deferred the $2.0 million gain as an adjustment to the fair value of the hedged portion of the Partnership’s debt and is amortizing the gain as a reduction of interest expense over the remaining term of the hedged debt. Interest expense was reduced by $0.2 million during each of the years ended December 31, 2006 and 2005 related to the amortization of the gain on the interest rate swap.
Item 8.
Item 8. Financial Statements and Supplementary Data
BUCKEYE PARTNERS, L.P.
Schedules are omitted because they are either not applicable or not required or the information required is included in the consolidated financial statements or notes thereto.
MANAGEMENT’S REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING
Management of Buckeye GP LLC (the “General Partner”), as general partner of Buckeye Partners, L.P. (the “Partnership”), is responsible for establishing and maintaining adequate internal control over financial reporting of the Partnership. Internal control over financial reporting is a process designed to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. A company’s internal control over financial reporting includes those policies and procedures that pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and 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.
Management evaluated the General Partner’s internal control over financial reporting of the Partnership as of December 31, 2006. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (COSO). As a result of this assessment and based on the criteria in the COSO framework, management has concluded that, as of December 31, 2006, the General Partner’s internal control over financial reporting of the Partnership was effective.
The Partnership’s independent registered public accounting firm, Deloitte & Touche LLP, has audited management’s assessment of the General Partner’s internal control over financial reporting for the Partnership. Their opinion on management’s assessment and their opinion on the effectiveness of the General Partner’s internal control over financial reporting for the Partnership appears herein.
WILLIAM H. SHEA, JR.
ROBERT B. WALLACE
Chief Executive Officer
Senior Vice President, Finance and
Chief Financial Officer
February 23, 2007
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners of Buckeye Partners, L.P.
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Buckeye Partners, L.P. and subsidiaries (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 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 opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel 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 the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the 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 criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. 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 criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2006, of the Partnership and our report dated February 23, 2007, expressed an unqualified opinion on those financial statements and included an explanatory paragraph regarding the adoption of Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 106, and 132(R),” as of December 31, 2006.
DELOITTE & TOUCHE LLP
Philadelphia, Pennsylvania
February 23, 2007
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners of Buckeye Partners, L.P.
We have audited the accompanying consolidated balance sheets of Buckeye Partners, L.P. and subsidiaries (the “Partnership”) as of December 31, 2006 and 2005, and the related consolidated statements of income, cash flows, and partners’ capital for each of the three years in the period ended December 31, 2006. These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated 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, such consolidated financial statements present fairly, in all material respects, the financial position of Buckeye Partners, L.P. and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Notes 2 and 12 to the consolidated financial statements, the Partnership adopted the provisions of Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 106, and 132(R),” as of December 31, 2006.
We have also 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 the 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 on management’s assessment of the effectiveness of the Partnership’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.
DELOITTE & TOUCHE LLP
Philadelphia, Pennsylvania
February 23, 2007
BUCKEYE PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except per unit amounts)
See Notes to consolidated financial statements.
BUCKEYE PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
See Notes to consolidated financial statements.
BUCKEYE PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
See Notes to consolidated financial statements.
BUCKEYE PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(In thousands)
See Notes to consolidated financial statements.
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION
Buckeye Partners, L.P. (the “Partnership”) is a publicly traded master limited partnership (NYSE symbol: BPL) organized in 1986 under the laws of the state of Delaware. The Partnership’s principal line of business is the transportation, terminalling and storage of refined petroleum products in the United States for major integrated oil companies, large refined petroleum product marketing companies and major end users of petroleum products on a fee basis through facilities owned and operated by the Partnership. The Partnership also operates pipelines owned by third parties under contracts with major integrated oil and chemical companies, and performs certain construction activities, generally for the owners of these third-party pipelines.
The Partnership owns and operates one of the largest independent refined petroleum products pipeline systems in the United States in terms of volumes delivered, with approximately 5,400 miles of pipeline, serving 17 states, and operates another approximately 2,500 miles of pipeline under agreements with major oil and chemical companies. The Partnership also owns and operates 45 active refined petroleum products terminals with aggregate storage capacity of approximately 17.6 million barrels in Illinois, Indiana, Massachusetts, Michigan, Missouri, New York, Ohio and Pennsylvania.
The Partnership conducts all of its operations through subsidiary entities. These operating subsidiaries are Buckeye Pipe Line Company, L.P. (“Buckeye”), Laurel Pipe Line Company, L.P. (“Laurel”), Everglades Pipe Line Company, L.P. (“Everglades”), Buckeye Pipe Line Holdings, L.P. (“BPH”), Wood River Pipe Lines LLC (“Wood River”), Buckeye Pipe Line Transportation LLC (“BPL Transportation”) and Buckeye NGL Pipe Lines LLC (“Buckeye NGL”). Buckeye NGL commenced operations on January 31, 2006 with the acquisition of a natural gas liquids pipeline located in Colorado and Kansas (see Note 3). Each of these entities is referred to hereinafter as an “Operating Subsidiary” or collectively as the “Operating Subsidiaries.” The Partnership owns an approximate 99% limited partner interest in each Operating Subsidiary except Wood River, BPL Transportation and Buckeye NGL, in each of which it owns a 100% limited liability company interest.
BPH owns, directly or indirectly, a 100% interest in each of Buckeye Terminals, LLC (“Buckeye Terminals”), NORCO Pipe Line Company, LLC (“Norco”), Buckeye Gulf Coast Pipe Lines, L.P. (“BGC”), Buckeye Texas Pipe Line Company, L.P. and WesPac Pipelines-Reno LLC (“WesPac Reno”). BPH also owns a 75% interest in WesPac Pipelines-Memphis LLC, and a 50% interest in WesPac Pipelines-San Diego LLC (together with WesPac Reno, collectively known as “WesPac”), an approximate 25% interest in West Shore Pipe Line Company (“West Shore”), a 20% interest in West Texas LPG Pipeline Limited Partnership (“WTP”) and a 40% interest in Muskegon Pipeline LLC (“Muskegon”). Subsidiaries of BPH also own approximately 63% of two partnerships which own a crude butadiene pipeline between Deer Park, Texas and Port Arthur, Texas that was completed in March 2003 (the “Sabina Pipeline”).
Buckeye GP LLC (the “General Partner”) is the general partner of the Partnership. As of December 31, 2006, the General Partner owned an approximate 0.6% general partner interest in the Partnership. The General Partner also owns 100% of and controls MainLine GP, Inc. which, together with the General Partner, owns 100% and controls MainLine LP (the “Operating Subsidiary GP”), which is the general partner of and owns a 1% interest in each of Buckeye, Laurel and Everglades and an approximate 0.6% interest in BPH.
The General Partner is a wholly-owned subsidiary of Buckeye GP Holdings L.P. (“BGH”), a Delaware limited partnership that is owned by an affiliate of Carlyle/Riverstone Global Energy and Power Fund II, L.P. (“Carlyle/Riverstone”), certain members of the Partnership’s senior management and the public and is separately traded on the New York Stock Exchange (NYSE symbol: BGH). See Note 21 for an explanation of the restructuring of the General Partner and the Operating Subsidiary GP that occurred in connection with the initial public offering of BGH common units on August 9, 2006 (the “BGH IPO”).
Buckeye Pipe Line Services Company (“Services Company”) employs all of the employees who work for the Operating Subsidiaries. Under a services agreement entered into in December 2004 (the “Services Agreement”), the Operating Subsidiaries and their subsidiaries directly reimburse Services Company for the cost of the services provided by the employees. Under the Services Agreement and an Executive Employment Agreement, certain executive compensation costs and related benefits for the General Partner’s Named Executive Officers are not reimbursed by the Partnership or the Operating Subsidiaries, but are reimbursed to Services Company by BGH. Prior to August 9, 2006, these executive compensation costs and related benefits were reimbursed to Services Company by MainLine Sub LLC (See Note 21). At December 31, 2006 and 2005, Services Company owned an approximate 5.9% limited partner interest in the Partnership.
The Partnership has three reportable operating segments:
· Pipeline Operations
· Terminalling and Storage
· Other Operations
See Note 20 for further discussion on the Partnership’s segments.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The consolidated financial statements and the accompanying notes are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and the rules of the US Securities and Exchange Commission. They include the accounts of the Partnership and its subsidiaries on a consolidated basis. All significant intercompany transactions have been eliminated in consolidation. The financial statements do not include the accounts of the General Partner or Services Company.
Changes in General Partner Incentive Payments
The General Partner has historically received incentive compensation payments under an Incentive Compensation Agreement, which were payments based on cash distributions to the limited partners of the Partnership. As described in Note 21, as part of the reorganization of the General Partner and the Operating Subsidiary GP on August 9, 2006, the Incentive Compensation Agreement and the Partnership Agreement were amended to re-characterize the incentive payments received by the General Partner under the Incentive Compensation Agreement and the Partnership Agreement as distribution payments with respect to the general partner interest rather than compensation payments. These amendments were effective for payments related to Partnership distributions declared after August 9, 2006. Accordingly, effective with the fourth quarter of 2006, these payments are characterized as distributions rather than compensation payments from the Partnership to the General Partner.
These amendments do not change the timing or amounts of incentive payments or other distributions payable to the General Partner. However, commencing in the fourth quarter of 2006, the amendments do affect reported net income and the amount of income that is allocated to the General Partner and limited partners. The effect of this amendment was to increase reported net income for the fourth quarter and for
2006 by approximately $6.6 million compared to the amount that would have been reported had the Incentive Compensation Agreement and Partnership Agreement not been amended.
Use of Estimates
The preparation of the Partnership’s consolidated financial statements in conformity with GAAP necessarily requires management to make estimates and assumptions. These estimates and assumptions, which may differ from actual results, will affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenue and expense during the reporting period.
Regulatory Reporting
The majority of the Partnership’s petroleum products pipelines are subject to regulation by the Federal Energy Regulatory Commission (“FERC”), which prescribes certain accounting principles and practices for the annual Form 6 Report filed with the FERC that differ from those used in these financial statements. Reports to FERC differ from the accompanying consolidated financial statements, which have been prepared in accordance with GAAP, generally in that such reports calculate depreciation over estimated useful lives of the assets as prescribed by FERC.
Revenue Recognition
Revenue from the transportation of petroleum products is recognized as products are delivered. Revenues from terminalling, storage and rental operations are recognized as the services are performed. Revenues for contract operation and construction services of facilities and pipelines not directly owned by the Partnership are recognized as the services are performed. Contract and construction services revenue typically includes costs to be reimbursed by the customer plus an operator fee.
Cash and Cash Equivalents
All highly liquid debt instruments purchased with an original maturity of three months or less are classified as cash equivalents.
Trade Receivables
Trade receivables represent valid claims against non-affiliated customers and are recognized when products are sold or services are rendered. The Partnership extends credit terms to certain customers based on historical dealings and to other customers after a review of various credit indicators, including the customers’ credit rating.
Construction and pipeline relocation receivables
Construction and pipeline relocation receivables represent valid claims against non-affiliated customers for services rendered in constructing, maintaining and/or operating pipelines and are recognized when services are rendered.
Inventories
Inventories, consisting of materials and supplies such as pipes, valves, pumps, electrical/electronic components, drag reducing agent and other miscellaneous items are carried at the lower of cost or market based on the first-in, first-out method.
Equity Investments
Investments greater than 20% in entities in which the Partnership does not exercise control are accounted for using the equity method. Under this method, an investment is recorded at acquisition cost plus the Partnership’s equity in undistributed earnings or losses since acquisition, reduced by distributions received and amortization of excess net investment. Excess investment is the amount by which the initial investment exceeds the proportionate share of the book value of the net assets of the investment. Management evaluates equity method investments for impairment whenever events or circumstances indicate that there is a loss in value of the investment which is other than temporary. In the event that the loss in value of an investment is other than temporary, the Partnership records a charge to earnings to adjust the carrying value to fair value. There were no equity investment impairments during 2006, 2005 or 2004.
Property, Plant and Equipment
Property, plant and equipment consists primarily of pipeline and related transportation facilities and equipment. For financial reporting purposes, depreciation on pipeline assets is calculated using the straight-line method over the estimated useful life of 50 years. Other plant and equipment is depreciated on a straight line basis over an estimated life of 5 to 50 years. Additions and betterments are capitalized and maintenance and repairs are charged to income as incurred. Generally, upon normal retirement or replacement, the cost of property (less salvage) is charged to the depreciation reserve, which has no effect on income.
The following table represents the depreciation life for the major components of the Partnership’s assets:
Goodwill and Intangible Assets
The Partnership does not amortize goodwill. Goodwill is reviewed for impairment at the reporting unit level, which is consistent with the Partnership’s operating segments, annually on January 1 for potential impairment based on the carrying value of the reporting unit compared to its fair value. Intangible assets that have finite useful lives are amortized over their useful lives.
Long-Lived Assets
The Partnership regularly assesses the recoverability of its long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The Partnership assesses recoverability based on estimated undiscounted future cash flows expected to result from the use of the asset and its eventual disposal. The measurement of an impairment loss is based on the difference between the carrying amount and fair value of the assets.
Asset Retirement Obligations
The Partnership accounts for asset retirement obligations in accordance with Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations” (“SFAS No. 143”) as amended by FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”) which was effective December 31, 2005. SFAS No. 143 requires that the fair value of a liability related to the retirement of long-lived assets be recorded at the time a legal obligation is incurred. FIN 47 clarifies the term conditional asset retirement obligation as used in SFAS No. 143 as a legal obligation to perform an asset retirement activity in which the timing or method of settlement are conditional on a future event that may or may not be within the control of the entity. Once an asset retirement obligation is identified and a liability is recorded, a corresponding asset is recorded at that time which is then depreciated over the remaining useful life of the asset. After the initial measurement, the obligation is periodically adjusted to reflect changes in the asset retirement obligation’s fair value. If and when it is determined that a legal obligation has been incurred, the fair value of any liability is determined based on estimates and assumptions related to retirement costs, future inflation rates and credit-adjusted risk-free interest rates.
The Operating Subsidiaries’ assets generally consist of underground refined petroleum products pipelines installed along rights-of-way acquired from land owners and related above-ground facilities that are owned by the Operating Subsidiaries. The Partnership is unable to predict if and when its pipelines, which generally serve high-population and high-demand markets, will become completely obsolete and require decommissioning. Further, the Operating Subsidiaries’ rights-of-way agreements typically do not require the dismantling and removal of the pipelines and reclamation of the rights-of-way upon permanent removal of the pipelines from service. Accordingly, the Partnership has recorded no liability, or corresponding asset, in conjunction with the adoption of SFAS No. 143 and FIN 47 because the future dismantlement and removal dates of the Partnership’s assets, and the amount of any associated costs, are indeterminable.
Debt Issuance Costs
Costs incurred for debt borrowings are capitalized as paid and amortized over the life of the associated debt instrument. When debt is retired before its scheduled maturity date, any remaining placement costs associated with that debt are expensed.
Fair Value and Hedging Activities
At December 31, 2006 and 2005, cash, trade receivables, construction and pipeline relocation receivables, prepaid and other current assets, and all current liabilities are reported in the consolidated balance sheets at amounts which approximate fair value due to the relatively short period to maturity of these financial instruments. The value of the Partnership’s debt was calculated using interest rates currently available to the Partnership for issuance of debt with similar terms and remaining maturities and approximate market values on the respective dates (see Note 10).
The Partnership accounts for hedging activities in accordance with SFAS No. 133 “Accounting for Financial Instruments and Hedging Activities,” SFAS No. 138 “Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of FASB Statement No. 133” and SFAS No. 149, “Amendment of Statement No. 133 on Derivative Instruments and Hedging Activities.” These statements establish accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet at fair value as either assets or liabilities.
The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and its resulting designation, which is established at the inception of the derivative instrument. SFAS No. 133 provides for a short-cut method which permits gains and losses on certain
derivatives qualifying as fair value hedges to directly offset the changes in value of the hedged item in the Partnership’s income statement, and for the Partnership to assume no hedge ineffectiveness with respect to the hedged financial instrument.
In 2003, the Partnership entered into an interest rate swap contract with a financial institution (see Note 10). The Partnership designated the swap as a fair value hedge at the inception of the contract and utilized the short-cut method provided for in SFAS No. 133. The interest rate swap was terminated on December 8, 2004.
When entering into interest rate swap transactions, the Partnership becomes exposed to both credit risk and market risk. Credit risk occurs when the value of the swap transaction is positive, and the Partnership is subject to the risk that the counterparty will fail to perform under the terms of the contract. The Partnership is subject to market risk with respect to changes in value of the swap. The Partnership manages its credit risk by only entering into swap transactions with major financial institutions with investment-grade credit ratings. The Partnership manages its market risk by associating each swap transaction with an existing debt obligation. The Partnership’s practice is to have the Board of Directors of the General Partner approve each swap transaction.
Capitalization of Interest
Interest on borrowed funds is capitalized on projects during construction based on the approximate average interest rate of the Partnership’s debt.
Income Taxes
For federal and state income tax purposes, the Partnership and the Operating Subsidiaries, except for BGC, are not taxable entities. Accordingly, the taxable income or loss of the Partnership and the Operating Subsidiaries other than BGC, which may vary substantially from income or loss reported for financial reporting purposes, is generally includable in the federal and state income tax returns of the individual partners. As of December 31, 2006 and 2005, the Partnership’s reported amount of net assets for GAAP purposes exceeded its tax basis for financial statement reporting and for allocating taxable income under the partnership agreement.
Effective August 1, 2004, BGC elected to be treated as a taxable corporation for federal income tax purposes. Accordingly, BGC has recognized deferred tax assets and liabilities for temporary differences between the amounts of assets and liabilities measured for financial reporting purposes and the amounts measured for federal income tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance when the amount of any tax benefit is not expected to be realized.
Total income tax expense for the years ended December 31, 2006 and 2005 was $0.6 million and $0.9 million, respectively. For the period August 1, 2004 to December 31, 2004, income tax expense was $0.5 million. Income tax expense is included in operating expenses in the consolidated statements of income.
Environmental Expenditures
Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. Generally, the timing of these accruals coincides with the Partnership’s commitment to a formal plan of action. Accrued environmental remediation related expenses include direct costs of remediation and indirect costs related to the remediation effort, such as compensation and benefits for employees directly involved in the remediation activities and fees estimated to be paid to outside engineering, consulting and law firms. The Partnership maintains insurance which may cover certain environmental expenditures.
Pensions
Services Company sponsors a defined contribution plan (see Note 12), defined benefit plans (see Note 12) and an employee stock ownership plan (the “ESOP”) (see Note 14) that provide retirement benefits to certain regular full-time employees. Certain hourly employees of Services Company are covered by a defined contribution plan under a union agreement (see Note 12).
Postretirement Benefits Other Than Pensions
Services Company provides post-retirement health care and life insurance benefits for certain of its retirees. Certain other retired employees are covered by a health and welfare plan under a union agreement (see Note 12).
Unit Option and Distribution Equivalent Plan
The Partnership has a Unit Option and Distribution Equivalent Plan, which, effective January 1, 2006, is accounted for under the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”). SFAS 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. See Note 13 for a further discussion of the Partnership’s Unit Option and Distribution Equivalent Plan.
Comprehensive Income
The Partnership accounts for comprehensive income in accordance with Statement of Financial Accounting Standards No. 130, “Reporting Comprehensive Income” (“SFAS No. 130”). SFAS No. 130 requires certain items such as foreign currency translation adjustments, minimum pension liability adjustments and unrealized gains and losses on certain investments to be reported in a financial statement. Comprehensive income consisted of the following:
Allocation of Net Income
In the fourth quarter of 2006, the Partnership began attributing income to the General Partner and the limited partners as if the net income of the Partnership were entirely distributed to its Unitholders. The Partnership determined the amount of income allocable to the General Partner, which represents the sum of the incentive distribution that would have been payable to the General Partner if the total distribution equaled net income, plus the General Partner’s proportional share of the remaining income of the Partnership.
Earnings per Unit
Basic earnings per limited partner unit (“LP Unit”) is determined by dividing the limited partners’ allocation of net income by the weighted average number of LP Units outstanding for the period. Diluted net income per unit is calculated the same way except the weighted average LP Units outstanding include any dilutive effect of LP Unit option grants.
Major Customers and Concentration of Credit Risk
The Partnership has a concentration of trade receivables due from major integrated oil companies, major petroleum refiners, major petrochemical companies, large regional marketing companies and large commercial airlines. These concentrations of customers may affect the Partnership’s overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors. The consolidated Partnership customer base was approximately 214 customers in 2006 and 160 customers in 2005. Affiliates of Shell Oil Products U.S. (“Shell”) contributed 11% of consolidated Partnership revenue in 2006 and 13% in 2005. For the year ended December 31, 2004, no customer contributed more than 10% of consolidated revenue. Approximately 5% of the 2006 consolidated revenue was generated by Shell in the Pipeline Operations segment; the remaining 6% of consolidated revenue was generated by Shell in the Terminalling and Storage segment. The 20 largest customers accounted for 53% and 63% of consolidated Partnership revenue in 2006 and 2005, respectively. The Partnership manages its credit risk through a credit approval process. For certain customers, prepayments are required. The Pipeline Operations segment bills its customers on a weekly basis, and the Terminalling and Storage segment on at least a monthly basis. The effect of these billing practices is to reduce credit risk. The Partnership does not maintain an allowance for doubtful accounts due to its favorable collections experience.
Recent Accounting Pronouncements
In July 2006, the Financial Accounting Standards Board (“FASB”) adopted FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes” (“FIN 48”). FIN 48 sets forth a recognition threshold and measurement attribute for financial statement recognition of positions taken or expected to be taken in income tax returns. Only tax positions meeting a “more-likely-than-not” threshold of being sustained should be recognized under FIN 48. FIN 48 also provides guidance on derecognizing, classification of interest and penalties and accounting and disclosures for annual and interim financial statements. FIN 48 is effective for fiscal years beginning after December 15, 2006. The cumulative effect of the changes arising from the initial application of FIN 48 is required to be reported as an adjustment to the opening balance of retained earnings in the period of adoption. The Partnership does not expect the adoption of FIN 48 to have a material impact on its financial statements.
In September 2006, the FASB adopted Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 106, and 132(R)” (“SFAS No. 158”). SFAS No. 158 requires companies to recognize a net liability or asset and an offsetting adjustment to accumulated other comprehensive income in connection with reporting on the funded status of defined benefit pension and other postretirement benefit plans. SFAS No. 158 requires prospective application, and the recognition and disclosure requirements are effective for the Partnership’s fiscal year ending December 31, 2006. Additionally, SFAS No. 158 requires companies to measure plan assets and obligations at their year-end balance sheet date. This requirement is effective for fiscal years ending after December 15, 2008. See Note 12 for the effects of the adoption of SFAS No. 158.
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”). This statement clarifies the definition of fair value, establishes a framework for measuring fair value, and expands the disclosures on fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 and interim periods within that year. The Partnership is still determining the impact, if any, of the adoption of SFAS No. 157 on its financial statements.
In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB No. 108”). SAB No. 108 provides guidance on how prior year misstatements should be taken into consideration when quantifying misstatements in current year
financial statements for purposes of determining whether the current year’s financial statements are materially misstated. SAB No. 108 was effective for fiscal years ending after November 15, 2006. The adoption of SAB 108 did not have any impact on the Partnership’s financial statements.
3. ACQUISITIONS AND EQUITY INVESTMENTS
2006 Acquisitions
On January 31, 2006, the Partnership completed the acquisition of a natural gas liquids pipeline that extends generally from Wattenberg, Colorado to Bushton, Kansas, from BP Pipelines (North America) Inc. for approximately $87.0 million, which included a deposit of $7.7 million paid in December 2005. The allocated fair value, based on allocations by the Partnership, of the assets acquired is summarized as follows (in thousands):
On January 1, 2006, the Partnership acquired a refined petroleum products terminal located in Niles, Michigan from Shell for $13.0 million.
2005 Acquisitions
In December 2005, the Partnership acquired a refined petroleum products terminal and related assets (including railroad offloading facilities and customer contracts) located in Taylor, Michigan for $20.0 million. The allocated fair value, based on allocations by the Partnership, of the assets acquired is summarized as follows (in thousands):
Effective December 1, 2005, the Partnership acquired from affiliates of Marathon Oil Company an approximately 26-mile pipeline and a 40% interest in Muskegon. Muskegon owns an approximately 170-mile pipeline which extends from Griffith, Indiana to Muskegon, Michigan. The pipeline and the interest in Muskegon (collectively, the “Pipeline Interests”) were acquired in exchange for consideration that included capacity lease agreements (with purchase options) related to one of the Partnership’s pipelines and a terminal. The Partnership has recorded the Pipeline Interests (and the corresponding obligations) at their estimated fair values of $20.1 million, with $4.8 million allocated to the 26-mile pipeline and $15.3 million allocated to the 40% interest in Muskegon. In connection with the transaction, the parties also entered into throughput agreements related to certain of the Partnership’s pipelines and terminals.
On May 5, 2005, the Partnership acquired a refined petroleum products pipeline system with approximately 478 miles of pipeline and four petroleum products terminals with aggregate storage capacity of approximately 1.3 million barrels located in the northeastern United States (the “Northeast Pipelines and Terminals”) for a purchase price of $175.0 million from affiliates of ExxonMobil.
In connection with the closing of the Northeast Pipelines and Terminals transaction, the Partnership entered into throughput agreements with ExxonMobil relating to each of the acquired petroleum products terminals. The throughput agreements have an initial term of five years and renew automatically for five successive three-year terms unless terminated by ExxonMobil. The agreements provide that the Partnership will reserve storage capacity at the terminals for ExxonMobil. The parties also agreed on the terminalling fees to be charged for volumes throughput at the terminals by ExxonMobil. The amount of storage capacity reserved for ExxonMobil was based initially on historical usage and adjusts periodically based on ExxonMobil’s actual usage.
The Partnership’s cost of the Northeast Pipelines and Terminals totaled $178.6 million, which consisted of the purchase price of $175.0 million, accrued environmental obligations of $2.3 million, and direct acquisition costs of $1.3 million. The allocated fair value, based on allocations by the Partnership of the assets acquired is summarized as follows (in thousands):
In the fourth quarter of 2005, the Partnership recorded an expense of $2.2 million associated with additional environmental costs identified with the Northeast Pipelines and Terminals acquisition.
In November 2005, the Partnership acquired an approximately 29-mile ammonia pipeline located in Texas and, in a separate transaction, the 25% membership interest in WesPac-Reno that it did not previously own for approximately $3.5 million and $2.5 million, respectively.
2004 Acquisitions
On October 1, 2004, the Partnership acquired from Shell five refined petroleum products pipelines with aggregate mileage of approximately 900 miles and 24 petroleum products terminals with aggregate storage capacity of approximately 9.3 million barrels located in the midwestern United States for a purchase price of approximately $517.0 million (the “Midwest Pipelines and Terminals”). All five of the refined petroleum products pipelines are interstate common carriers regulated by the FERC.
In connection with the acquisition of the Midwest Pipelines and Terminals, the Partnership entered into a terminalling agreement and a transportation agreement with Shell, each with an initial term of three years. The terminalling and transportation agreements provide for a minimum revenue commitment from Shell averaging approximately $35.7 million per year for the initial three-year term following the closing of the acquisition. The terminalling agreement may be extended, at the option of Shell, for four, two-year periods with the committed revenues for subsequent years based upon the revenues produced by Shell’s use of the terminals in the prior year. Both of these agreements provide that if an event occurs beyond the control of either the Partnership or Shell, Shell has the right to reduce its revenue commitments during the period of interruption. Through December 31, 2006, Shell has exceeded its minimum revenue commitment.
As part of the acquisition of these assets, Shell agreed to retain liabilities and expenses related to active environmental remediation projects. In addition, Shell agreed to indemnify the Partnership for certain environmental liabilities arising from pre-closing conditions relating to the operation of the acquired pipelines, tank farms or terminals, so long as the Partnership provides notice of those conditions
within two years of the closing of the acquisition. Shell’s indemnification obligation is subject to a $250,000 per-claim deductible and a $29.3 million aggregate liability. The Partnership agreed to perform certain monitoring activities at its own expense associated with certain sites which are or could become subject to environmental remediation. The Partnership accrued as part of its purchase price approximately $4.9 million related to its obligation to monitor these sites.
The Partnership’s total cost of the Midwest Pipelines and Terminals totaled $523.7 million, which consisted of the purchase price of $517.0 million, the accrued environmental monitoring costs of $4.9 million discussed above, plus direct acquisition costs of $1.8 million. The allocated fair value based on allocations by the Partnership of assets acquired is summarized as follows (in thousands):
In the fourth quarter of 2005, the Partnership recorded a reduction of expense of $3.1 million associated with a reduced estimate of the cost of the Partnership’s obligation to perform certain environmental monitoring activities at these sites. Management continues to evaluate on an ongoing basis the amounts required for these obligations.
Summary
The acquisitions discussed above were accounted for as acquisitions of assets rather than the acquisitions of businesses, as defined in Statement of Financial Accounting Standards No. 141-“Business Combinations.” Accordingly, the Partnership allocated the cost of the assets acquired using appraised values on the date of acquisition. In conjunction with the appraisals, the Partnership determined that a significant portion of the value of the purchases relate to the physical assets acquired, which are generally depreciated over 50 years. The acquired pipelines and related assets were allocated to the Pipeline Operations segment; the acquired terminals and related assets were allocated to the Terminalling and Storage segment. Note 20 summarizes the allocation of acquisitions by segment.
4. CONTINGENCIES
Claims and Proceedings
The Partnership and the Operating Subsidiaries in the ordinary course of business are involved in various claims and legal proceedings, some of which are covered by insurance. The General Partner is generally unable to predict the timing or outcome of these claims and proceedings. Based upon its evaluation of existing claims and proceedings and the probability of losses relating to such contingencies, the Partnership has accrued certain amounts relating to such claims and proceedings, none of which are considered material.
In the third quarter of 2006, the Partnership received penalty assessments from the IRS in the aggregate amount of $4.3 million based on a failure to timely file excise tax information returns relating to its terminal operations from January 2005 through February 2006. The Partnership filed the information returns with the IRS on May 10, 2006. In January 2007, the Partnership agreed to pay the IRS approximately $0.6 million to settle and resolve the penalty assessment. The settlement is subject to the negotiation and execution of a closing agreement between the Partnership and the IRS. The negotiated penalty assessment has been recorded as an expense in the Partnership’s financial statements in the fourth quarter of 2006.
Environmental Contingencies
In accordance with its accounting policy on environmental expenditures, the Partnership recorded operating expenses, net of insurance recoveries, of $6.2 million, $9.3 million and $6.2 million for 2006, 2005 and 2004, respectively, which were related to environmental expenditures unrelated to claims and proceedings. Expenditures, both capital and operating, relating to environmental matters are expected to continue due to the Partnership’s commitment to maintaining high environmental standards and to increasingly strict environmental laws and government enforcement policies. Additional discussions regarding environmental expenditures are contained in Notes 2 (Summary of significant accounting policies), 9 (Accrued and other current liabilities) and 11 (Other non-current liabilities).
5. GOODWILL AND INTANGIBLE ASSETS
Effective January 1, 2002, the Partnership adopted Statement of Financial Accounting Standards No. 142 - “Goodwill and Other Intangible Assets (“SFAS No. 142”),” which establishes financial accounting and reporting guidance for acquired goodwill and other intangible assets. Under SFAS No. 142, goodwill and indefinite-lived intangible assets are no longer amortized but are reviewed at least annually for impairment. Intangible assets that have finite useful lives will continue to be amortized over their useful lives.
SFAS No. 142 requires that goodwill be tested for impairment at least annually utilizing a two-step methodology. The initial step requires the Partnership to determine the fair value of each of its reporting units and compare it to the carrying value, including goodwill, of such reporting unit. If the fair value exceeds the carrying value, no impairment loss is recognized. However, a carrying value that exceeds its fair value may be an indication of impaired goodwill. The amount, if any, of the impairment would then be measured and an impairment loss would be recognized. Goodwill in the amount of $11.4 million was recorded in the Terminalling and Storage segment as part of the acquisition of six terminals in June 2000. The impairment testing performed each January 1st has determined that no impairment had been incurred in 2006, 2005 or 2004.
The Partnership’s amortizable intangible assets consist of a deferred charge and contracts acquired in acquisitions. The contracts were acquired in connection with the acquisition of BGC in March 1999 and the Taylor, Michigan terminal acquired in December 2005 (see Note 8).
For the years 2006, 2005 and 2004, consolidated amortization expense related to amortizable intangible assets was $5.4 million, $4.9 million and $4.9 million, respectively. The Partnership’s consolidated amortization expense related to amortizable intangible assets is estimated to be $5.3 million per year for the years 2007 to 2010 and $1.9 million for the year 2011. The deferred charge is being amortized over 13.5 years. The customer contracts are being amortized over periods ranging from 15 to 25 years (see Note 8).
6. PREPAID AND OTHER CURRENT ASSETS
Prepaid and other current assets consisted of the following:
7. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consist of the following:
Depreciation expense was $38.7 million, $31.8 million and $21.0 million for the years 2006, 2005 and 2004, respectively.
8. OTHER NON-CURRENT ASSETS
Other non-current assets consist of the following:
** The $64.2 million market value of the LP Units issued in connection with the restructuring of the ESOP in August 1997 (the “ESOP Restructuring”) was recorded as a deferred charge and is being amortized on the straight-line basis over 13.5 years (see Note 14).
9. ACCRUED AND OTHER CURRENT LIABILITIES
Accrued and other current liabilities consist of the following:
10. LONG-TERM DEBT AND CREDIT FACILITY
Long-term debt consists of the following:
At December 31, 2006, $145.0 million of debt was scheduled to mature November 13, 2011, $300.0 million was scheduled to mature on July 15, 2013, $275.0 million was scheduled to mature October 15, 2014, $125.0 million was scheduled to mature on July 1, 2017 and $150.0 million was scheduled to mature on August 15, 2033.
The fair value of the Partnership’s long-term debt was estimated to be $964.0 million and $908.0 million at December 31, 2006 and 2005, respectively. The value of the Partnership’s debt was calculated using interest rates currently available to the Partnership for issuance of debt with similar terms and remaining maturities and approximate market values on the respective dates.
On June 30, 2005, the Partnership sold $125.0 million aggregate principal of its 5.125% Notes due July 1, 2017 in an underwritten public offering. Proceeds from the note offering, after underwriters’ fees and expenses, were approximately $123.9 million. Proceeds from the offering were used in part to repay $122.0 million under the Partnership’s 5-year Revolving Credit Agreement.
In connection with the Midwest Pipelines and Terminals acquired from Shell on October 1, 2004, the Partnership borrowed a total of $490.0 million, consisting of $300.0 million under a 364-day interim loan (the “Interim Loan”) and $190.0 million under the Partnership’s $400.0 million five-year revolving credit facility. On October 12, 2004, the Partnership sold $275.0 million aggregate principal of its 5.300% Notes
due 2014 in an underwritten public offering (the “5.300% Note Offering”). Proceeds from the 5.300% Note Offering, net of underwriter’s discount and commissions, were approximately $272.1 million. Proceeds from the 5.300% Note Offering, together with additional borrowings under the Credit Facility, were used to repay the Interim Loan. On October 19, 2004, the Partnership issued 5.5 million LP units in an underwritten public offering (the “LP Unit Offering”). Proceeds from the LP Unit Offering were approximately $223.3 million, after underwriters’ discount and expenses, and were used to reduce amounts outstanding under the Credit Facility.
On November 13, 2006 the Partnership entered into a new a $400 million 5-year revolving credit facility (the “Credit Facility”) with a syndicate of banks. The Credit Facility, which replaced the Partnership’s previous $400 million credit facility, contains a one-time expansion feature to $600 million subject to certain conditions. Borrowings under the Credit Facility are guaranteed by certain of the Partnership’s subsidiaries. The Credit Facility matures on November 13, 2011, but may be extended for up to two additional 12-month periods under certain circumstances. The weighted average interest rate on amounts outstanding under the Credit Facility at December 31, 2006 was 5.59%.
Borrowings under the Credit Facility bear interest under one of two rate options, selected by the Partnership, equal to either (i) the greater of (a) the federal funds rate plus 0.5% and (b) SunTrust Bank’s prime rate plus an applicable margin, or (ii) the London Interbank Offered Rate (“LIBOR”) plus an applicable margin. The applicable margin is determined based on the current utilization level of the Credit Facility and on ratings assigned by Standard & Poor’s and Moody’s Investor Services for the Partnership’s senior unsecured non-credit enhanced long-term debt. At December 31, 2006 and December 31, 2005, the Partnership had $145.0 million and $50.0 million outstanding under the Credit Facility and its predecessor credit facility, respectively, and had committed $2.1 million and $1.7 million in support of letters of credit, respectively.
The Credit Facility contains covenants and provisions that:
· Restrict the Partnership and certain of its subsidiaries’ ability to incur additional indebtedness based on a Funded Debt Ratio ratios described below;
· Prohibit the Partnership and certain of its subsidiaries from creating or incurring certain liens on their property;
· Prohibit the Partnership and certain of its subsidiaries from disposing of property material to their operations;
· Limit consolidations, mergers and asset transfers by the Partnership and certain of its subsidiaries.
The Credit Facility requires that the Partnership and certain of its subsidiaries maintain a maximum “Funded Debt Ratio” which is calculated using “EBITDA” as defined in the Credit Facility. The Credit Facility defines EBITDA for periods prior to the fourth quarter of 2006 as earnings before interest, taxes, depreciation, depletion, amortization and incentive compensation payments to the General Partner, and for periods commencing after October 1, 2006 as earnings before interest, taxes, depreciation, depletion and amortization, in each case excluding the income of certain majority-owned subsidiaries and equity investments (but including distributions from those majority-owned subsidiaries and equity investments).
The Partnership’s Funded Debt Ratio at the end of any quarterly period equals the ratio of the long-term debt of the Partnership and certain of its subsidiaries (including the current portion, if any) to EBITDA for the previous four fiscal quarters. As of the end of any fiscal quarter, the Funded Debt Ratio may not exceed 4.75 to 1.00, subject to a provision for increases to 5.25 to 1.00 in connection with future acquisitions. At December 31, 2006 the Partnership’s Funded Debt Ratio was 4.40 to 1.00.
The Credit Facility provides for a “change of control” event of default that will be triggered if (i) Carlyle/Riverstone ceases to beneficially own 100% of the sole general partner of BGH, (ii) BGH
ceases to own 100% of our general partner or (iii) our general partner ceases to be our sole general partner.
At December 31, 2006 the Partnership was in compliance with all of the covenants under the Credit Facility.
In December 2004, the Partnership terminated an interest rate swap agreement associated with the 4.625% Notes due July 15, 2013 and received proceeds of $2.0 million. In 2004 interest expense was reduced by $2.6 million as a result of the swap agreement. In accordance with FASB Statement No. 133-“Accounting for Derivative Instruments and Hedging Activities,” the Partnership deferred the $2.0 million gain as an adjustment to the fair value of the hedged portion of the Partnership’s debt and is amortizing the gain as a reduction of interest expense over the remaining term of the hedged debt. Interest expense was reduced by $0.2 million during each of the years ended December 31, 2006 and 2005 related to the amortization of the gain on the interest rate swap.
11. OTHER NON-CURRENT LIABILITIES
Other non-current liabilities consist of the following:
12. PENSIONS AND OTHER POSTRETIREMENT BENEFITS
RIGP and Retiree Medical Plan
Services Company sponsors a retirement income guarantee plan (a defined benefit plan) (the “RIGP”) which generally guarantees employees hired before January 1, 1986, a retirement benefit at least equal to the benefit they would have received under a previously terminated defined benefit plan. Services Company’s policy is to fund amounts necessary to at least meet the minimum funding requirements of ERISA.
Services Company also provides post-retirement health care and life insurance benefits to certain of its retirees. To be eligible for these benefits an employee had to be hired prior to January 1, 1991 and meet certain service requirements. Services Company does not pre-fund this postretirement benefit obligation.
As discussed in Note 1, the Partnership adopted the provisions of SFAS No. 158 as of December 31, 2006. In connection with adopting SFAS No. 158, the Partnership recorded an increase in other comprehensive income of approximately $0.8 million, consisting of an increase of $4.6 million related to the postretirement benefits plan and a decrease of $3.8 million related to the RIGP.
In December 2006 Services Company amended the postretirement health care and life insurance plan (the “Retiree Medical Plan”) to freeze amounts payable to Medicare-eligible beneficiaries at $2,500 per year commencing in 2008. This change had the effect of reducing the Partnership’s postretirement benefit obligation by approximately $20.4 million. Because this amendment was adopted near year-end, the effects of the amendment did not impact the Partnership’s net income. However, coincident with the adoption of SFAS No. 158, the amendment did result in an increase in other comprehensive income of $20.4 million, which is included in the total adjustment of $4.6 million described above. The Partnership expects that this plan amendment will result in a decrease in postretirement benefits expense of approximately $4.0 million in 2007.
A reconciliation of the beginning and ending balances of the benefit obligations under the RIGP and the Retiree Medical Plan is as follows:
(1) In 2005, the Retiree Medical Plan was amended to increase the retail drug deductible. In 2006, the Retiree Medical Plan was amended to fix amounts payable to Medicare-qualified plan participants at $2,500 per year commencing in 2008.
A reconciliation of the beginning and ending balances of the fair value of plan assets under the RIGP and the Retiree Medical Plan is as follows:
Amounts recognized in the Partnership’s balance sheet as liabilities consist of the following:
Amounts recognized in accumulated other comprehensive income consist of the following:
Information regarding the accumulated benefit obligation in excess of plan assets for the Partnership’s RIGP is as follows:
The weighted average assumptions used in accounting for the RIGP and the Retiree Medical Plan were as follows:
The assumed rate of cost increase in the Retiree Medical Plan in 2006 was 9.00% for both non-Medicare eligible and Medicare eligible retirees. The assumed annual rates of cost increases declines each year through 2011 to a rate of 4.50%, and remain at 4.50% thereafter for both non-Medicare eligible and Medicare eligible retirees.
Assumed healthcare cost trend rates have a significant effect on the amounts reported for the healthcare plans. The effect of a 1.00% change in the health care cost trend rate for each future year would have had the following effects on 2006 results:
The components of the net periodic benefit cost recognized for the RIGP and the Retiree Medical Plan were as follows:
During 2004, the recognition of the Medicare Prescription Drug Law resulted in decreases in service costs of $27,000, interest costs of $97,900 and amortization of unrecognized loss of $161,900.
During 2007, the Partnership expects that the following amounts currently included in other comprehensive income will be recognized in the Partnership’s consolidated statement of income:
The Partnership estimates the following benefit payments, which reflect expected future service, as appropriate, will be paid in the years indicated:
The Partnership expects to receive Medicare prescription subsidies of $317,000 in 2007 and, due to the change in the Retiree Medical Plan discussed above, will not receive any Medicare prescriptions subsidies in 2008 or thereafter.
A minimum funding contribution is not required to be made to the RIGP during 2007. Funding requirements for subsequent years are uncertain and will significantly depend on whether the plan’s actuary changes any assumptions used to calculate plan funding levels, the actual return on plan assets and any legislative or regulatory changes affecting plan funding requirements. For tax planning, financial planning, cash flow management or cost reduction purposes, the Partnership may increase, accelerate, decrease or delay contributions to the plan to the extent permitted by law.
The Partnership does not fund the Retiree Medical Plan and, accordingly, no assets are invested in the plan. A summary of investments in the RIGP are as follows at December 31, 2006 and 2005:
The RIGP investment policy does not target specific asset classes, but seeks to balance the preservation and growth of capital in the plan’s mutual fund investments with the income derived with proceeds from the coal lease. While no significant changes in the asset allocation of the plan are expected during the upcoming year, Services Company may make changes at any time.
Retirement and Savings Plan
Services Company also sponsors a retirement and savings plan (the “Retirement Plan”) through which it provides retirement benefits for substantially all of its regular full-time employees, except those covered by certain labor contracts. The Retirement Plan consists of two components. Under the first component, Services Company contributes 5% of each eligible employee’s covered salary to an employee’s separate account maintained in the Retirement Plan. Under the second component, for all employees not participating in the ESOP, Services Company makes a matching contribution into the employee’s separate account for 100% of an employee’s contribution to the Retirement Plan up to 6% of an employee’s eligible covered salary. For Services Company employees who participate in the ESOP, Services Company does not make a matching contribution. Total costs of the Retirement Plan were approximately $4.3 million in 2006, $3.6 million in 2005 and $2.9 million in 2004.
Services Company also participates in a multi-employer retirement income plan that provides benefits to employees covered by certain labor contracts. Pension expense for the plan was $164,000, $175,000 and $190,000 for 2006, 2005 and 2004, respectively.
In addition, Services Company contributes to a multi-employer postretirement benefit plan that provides health care and life insurance benefits to employees covered by certain labor contracts. The cost of providing these benefits was approximately $143,000, $135,000 and $131,000 for 2006, 2005 and 2004, respectively.
13. UNIT OPTION AND DISTRIBUTION EQUIVALENT PLAN
The Partnership sponsors a Unit Option and Distribution Equivalent Plan (the “Option Plan”), pursuant to which it grants options to purchase LP Units at 100% of the market price of the LP Units on the date of grant to key employees of Services Company. The options vest three years from the date of grant and expire ten years from the date of grant. As options are exercised, the Partnership issues new LP Units. The Partnership has not historically repurchased, and does not expect to repurchase in 2007, any of its LP Units.
Effective January 1, 2006, the Partnership adopted the fair value measurement and recognition provisions of Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (“SFAS No. 123R”), using the modified prospective basis transition method. Under this method, unit-based compensation expense recognized for the year ended December 31, 2006 includes: (a) compensation expense for all grants made prior to, but not yet vested as of, January 1, 2006, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123, and (b) compensation expense for all grants made on or after January 1, 2006, based on the grant date fair value estimated using the Black-Scholes option pricing model. The Partnership recognizes compensation expense for awards granted on or after January 1, 2006, on a straight-line basis over the requisite service period.
For the retirement eligibility provisions of the Option Plan, the Partnership follows the non-substantive vesting method and recognizes compensation expense immediately for options granted to retirement-eligible employees, or over the period from the grant date to the date retirement eligibility is achieved. Unit-based compensation expense recognized in the consolidated statements of income for the year ended December 31, 2006 is based upon options ultimately expected to vest. In accordance with SFAS No. 123R, forfeitures have been estimated at the time of grant and will be revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates. Forfeitures were estimated based upon historical experience.
As a result of adopting SFAS No. 123R on January 1, 2006, the Partnership’s net income for the year ended December 31, 2006, was $329,000 lower than it would have been if the Partnership had continued to account for unit-based compensation under Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB No. 25”). Basic and diluted earnings per unit would have increased by $0.01 for the year ended December 31, 2006. Both the basic and diluted earnings per LP Unit for the year ended December 31, 2006 were $2.64.
The following table summarizes the total unit-based compensation expense included in the Partnership’s consolidated statements of income:
Prior to January 1, 2006, the Partnership accounted for the Option Plan under the recognition and measurement provisions of APB No. 25, and related Interpretations, as permitted by Financial Accounting Standards Board Statement No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”), as amended by SFAS No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosure” (“SFAS No. 148”). No unit-based employee compensation cost was recognized in the consolidated statements of income for the years ended December 31, 2005 and 2004, as all unit options granted under the Option Plan had an exercise price equal to the market value of the underlying units on the date of grant.
The following table illustrates the effect on net income for the years ended December 31, 2005 and 2004, respectively, as if the Partnership had applied the fair value recognition provisions of SFAS No. 123 to options granted under the Option Plan. For purposes of this pro forma disclosure, the value of the options is estimated using the Black-Scholes option pricing model and amortized to expense over the units’ vesting periods:
The fair value of unit options granted to employees was estimated using the Black-Scholes option pricing model with the following weighted-average assumptions for the years ended December 31, 2006, 2005 and 2004, respectively:
The expected volatility is based on historic volatility of the Partnership’s market-traded LP Units. Effective January 1, 2006, the Partnership has elected to use the simplified method for the expected life which is the option vesting period of three years plus the option term of ten years divided by two. The risk-free interest rate is calculated using the U.S. Treasury yield curves in effect at the time of grant, for the periods within the expected life of the options.
The following is a summary of the changes in the LP Unit options outstanding under the Option Plan as of December 31, 2006, 2005 and 2004:
At December 31, 2006, the aggregate intrinsic value of options outstanding and exercisable was $1,491,000 and $1,033,000, respectively. The aggregate intrinsic value represents the total intrinsic value that would have been received by the option holders had all option holders exercised their options on December 31, 2006. Intrinsic value is determined by calculating the difference between the Partnership’s closing LP Unit price on the last trading day of 2006 and the exercise price, multiplied by the number of LP Units. The total intrinsic value of options exercised during the year ended December 31, 2006 was $363,000. The total number of in-the-money options exercisable as of December 31, 2006 was 92,600. As of December 31, 2006, total unrecognized compensation cost related to unvested options was $300,000. The cost is expected to be recognized over a weighted average period of 1.2 years. At December 31, 2006, 570,900 LP Units were available for grant in connection with the Option Plan.
The following table summarizes information relating to LP Unit options outstanding under the Option Plan (all of which are vested or expected to vest) at December 31, 2006:
Until April 29, 2004, the Partnership offered a unit option loan program whereby optionees could borrow, at market rates, up to 95% of the purchase price of the LP Units and up to 100% of the applicable income tax withholding obligation in connection with such exercise. At December 31, 2006, two employees had outstanding loans under the unit option loan program. The aggregate borrowings outstanding at December 31, 2006 and 2005 were $390,000 and $535,000, respectively, of which $355,000 and $483,000, respectively, were related to the purchase price of the LP Units.
14. EMPLOYEE STOCK OWNERSHIP PLAN
Services Company provides the ESOP to the majority of its employees hired before September 16, 2004. Effective September 16, 2004, new employees do not participate in the ESOP. Employees transferred into Services Company from BGC, Buckeye Terminals and Norco on December 26, 2004, employees added from acquisitions occurring after September 15, 2004, and certain employees covered by a union multiemployer pension plan do not participate in the ESOP. The ESOP owns all of the outstanding common stock of Services Company.
At December 31, 2006, the ESOP was directly obligated to a third-party lender for $27.2 million of 3.60% Notes due 2011 (the “ESOP Notes”). The ESOP Notes were issued on May 4, 2004, to refinance Services Company’s 7.24% Notes which were originally issued to purchase Services Company common stock. The ESOP Notes are collateralized by Services Company common stock and are guaranteed by Services Company. The Partnership has committed that, in the event that the value of the LP Units owned by Services Company falls to less than 125% of the balance payable under the ESOP Notes, the Partnership will fund an escrow account with sufficient assets to bring the value of the total collateral (the value of LP Units owned by the Services Company and the escrow account) up to the 125% minimum. Amounts deposited in the escrow account are returned to the Partnership when the value of the LP Units owned by Services Company returns to an amount which exceeds the 125% minimum. At December 31, 2006, the value of the LP Units owned by Services Company was approximately $108 million, which exceeded the 125% requirement.
Services Company stock is released to employee accounts in the proportion that current payments of principal and interest on the ESOP Notes bear to the total of all principal and interest payments due under the ESOP Notes. Individual employees are allocated shares based upon the ratio of their eligible compensation to total eligible compensation. Eligible compensation generally includes base salary, overtime payments and certain bonuses. Except for the period March 1, 2003 through November 1, 2004, Services Company stock held in employee accounts received stock dividends in lieu of cash. The ESOP was amended to eliminate the payment of stock dividends on allocations made after February 28, 2003. Based upon provisions contained in the American Jobs Creation Act of 2004, the plan was amended further to reinstate this feature on allocations made after November 1, 2004.
The Partnership contributed 2,573,146 LP Units to Services Company in August 1997 in exchange for the elimination of the Partnership’s obligation to reimburse the General Partner and its parent for certain executive compensation costs, a reduction of the incentive compensation paid by the Partnership to the General Partner under the incentive compensation agreement, and other changes that made the ESOP a less expensive fringe benefit for the Partnership. Funding for the ESOP Notes is provided by distributions that Services Company receives on the LP Units that it owns and from cash payments from the Partnership, as required, to cover any shortfall between the distributions that Services Company receives on the LP Units that it owns and amounts currently due under the ESOP Notes (the “accrued top-up reserve”). The Partnership will also incur ESOP-related costs for taxes associated with the sale and taxable income of the LP Units and for routine administrative costs. In 2006, ESOP costs were reduced by $2.0 million as estimates of future shortfalls between the distributions that Services Company receives on the LP Units that it owns and amounts currently due under the ESOP Notes were reduced to reflect higher distributions on the LP Units than was previously anticipated. Total ESOP-related costs charged to earnings were $0.2 million in 2005 and $0.6 million in 2004.
15. LEASES AND COMMITMENTS
The Operating Subsidiaries lease certain land and rights-of-way. Minimum future lease payments for these leases as of December 31, 2006 are approximately $4.9 million for each of the next five years. Substantially all of these lease payments can be canceled at any time should they not be required for operations.
The General Partner leases space in an office building and certain copying equipment and charges these costs to the Operating Subsidiaries. Buckeye leases certain computing equipment and automobiles. Future minimum lease payments under these noncancelable operating leases at December 31, 2006 were as follows: $1.3 million for 2007, $1.1 million for 2008, $0.9 million for 2009, $1.0 million for 2010, $1.1 million for 2011 and $10.2 million in the aggregate thereafter
Rent expense under operating leases was $10.3 million, $8.7 million and $8.5 million for 2006, 2005 and 2004, respectively.
16. RELATED PARTY TRANSACTIONS
The Partnership and the Operating Subsidiaries are managed by the General Partner. Under certain partnership agreements, management agreements and a services agreement, Services Company is entitled to reimbursement of substantially all direct and indirect costs related to the business activities of the Partnership and the Operating Subsidiaries except for certain executive compensation and related benefits costs incurred by BGH.
Costs incurred by the Partnership and the Operating Subsidiaries for the above services totaled $98.3 million, $92.9 million, and $70.3 million in 2006, 2005 and 2004, respectively. The reimbursable costs include insurance, general and administrative costs, compensation and benefits payable to employees of Services Company, tax information and reporting costs, legal and audit fees and an allocable portion of overhead expenses.
Services Company, which is beneficially owned by the ESOP, owned 2,313,395 of the Partnership’s LP Units (approximately 5.9% of the LP Units outstanding) as of December 31, 2006. Distributions received by Services Company from the Partnership on such LP Units are used to fund obligations of the ESOP. Distributions paid to Services Company totaled $7.0 million, $6.7 million and $6.4 million in 2006, 2005 and 2004, respectively. In 2006, ESOP costs were reduced by $2.0 million as estimates of future shortfalls between the distributions that Services Company receives on the LP Units that it owns and amounts currently due under the ESOP Notes were reduced to reflect higher distributions on the LP Units than was
previously anticipated. Total ESOP-related costs charged to earnings were $0.2 million and $0.6 million in 2005 and 2004, respectively.
The Partnership pays a senior administrative charge for certain management functions performed by affiliates of Carlyle/Riverstone. The Partnership incurred $1.9 million for the years 2006 and 2005 and $1.0 million for the year 2004. The disinterested directors of the General Partner approve the amount of the senior administrative charge on an annual basis.
The General Partner receives incentive distributions from the Partnership pursuant to its partnership agreement and incentive compensation agreement. Incentive distributions are based on the level of quarterly cash distributions paid per LP Unit. Incentive compensation payments totaled $24.9 million, $20.2 million and $14.0 million in 2006, 2005 and 2004, respectively. Of the amounts paid in 2006, $18.3 million are included in “General Partner incentive compensation” expense on the Consolidated Statements of Income and $6.6 million are treated as Partnership distributions. Commencing with the fourth quarter of 2006, the Partnership ceased recording incentive compensation payable to the General Partner as an expense and instead began recording such payments as distributions from equity. See Note 21 for further discussion.
Other Related Party Transactions
The General Partner is partially owned by Carlyle/Riverstone. Three members of the eight-member board of directors of the General Partner are nominees of Carlyle/Riverstone. On January 25, 2005, affiliates of Carlyle/Riverstone acquired general and limited partner interests in SemGroup, L.P. (“SemGroup”). SemGroup transports and stores crude oil, natural gas, natural gas liquids, refined products and asphalt through its ownership and operation of proprietary and common carrier pipelines, terminals, storage tanks, processing plants, underground storage facilities and a transportation fleet. Carlyle/Riverstone’s total combined interest in SemGroup is approximately 30%. One of the members of the seven-member board of directors of SemGroup’s general partner is a nominee of Carlyle/Riverstone, with three votes on that board.
The Partnership provides terminal and pipeline transportation services to an affiliate of SemGroup. The Partnership received approximately $518,000 and $0 in revenue from the affiliate of SemGroup in 2006 and 2005, respectively. Carlyle/Riverstone also has an ownership interest in the general partner of Magellan Midstream Partners, L.P. (“Magellan”). The Partnership does not have a significant relationship with Magellan and does not have extensive operations in the geographic areas primarily served by Magellan.
Also, an affiliate of Carlyle/Riverstone is a member of a group that has agreed to acquire Kinder Morgan, Inc. Among other assets, Kinder Morgan, Inc. owns the general partner interest of Kinder Morgan Energy Partners, L.P. (“Kinder Morgan”), a publicly traded partnership engaged in the transportation and distribution of petroleum products and natural gas that is a Partnership customer and competes with the Partnership to a limited extent in the midwestern United States. If this acquisition is completed, all transactions between the Partnership and Kinder Morgan, Inc. and its affiliates will become related party transactions. In January 2007, the Federal Trade Commission approved the closing of the transaction on the condition that Carlyle/Riverstone relinquish its control of Magellan Midstream Partners. Carlyle/Riverstone has done so and representatives of Carlyle/Riverstone have resigned from the Board of Directors of Magellan Midstream Partners.
The Partnership does compete directly with Kinder Morgan, Magellan and SemGroup for acquisition opportunities throughout the United States and potentially will compete with these entities for new business or extensions of the existing services provided by our Operating Subsidiaries.
The board of directors of the General Partner has adopted a policy to address board of director conflicts of interests. In compliance with this policy, Carlyle/Riverstone has adopted procedures internally to ensure that BGH’s and the Partnership’s confidential information is protected from disclosure to competing companies in which Carlyle/Riverstone has an interest. As part of these procedures, none of the nominees of Carlyle/Riverstone who serve on the board of directors of the General Partner will also serve on the board of directors of the general partners of Kinder Morgan, Magellan or SemGroup or on the boards of directors of other competing companies in which Carlyle/Riverstone owns an interest.
17. PARTNERS’ CAPITAL
The following is a reconciliation of LP Units outstanding for the years ended December 31, 2006, 2005 and 2004:
The Partnership Agreement provides that, without prior approval of limited partners of the Partnership holding an aggregate of at least two-thirds of the outstanding LP Units, the Partnership cannot issue any LP Units of a class or series having preferences or other special or senior rights over the LP Units.
18. CASH DISTRIBUTIONS
The Partnership makes quarterly cash distributions to Unitholders of substantially all of its available cash, generally defined as consolidated cash receipts less consolidated cash expenditures and such retentions for working capital, anticipated cash expenditures and contingencies as the General Partner deems appropriate. All such distributions were paid on the then outstanding GP Units and LP Units. Cash distributions aggregated $125.5 million in 2006, $104.3 million in 2005 and $80.2 million in 2004.
On January 26, 2007, the Partnership announced a quarterly distribution of $0.7875 per unit payable on February 28, 2007, to Unitholders of record on February 6, 2007.
19. EARNINGS PER UNIT
Except as discussed in the following paragraph, basic and diluted net income per LP Unit is calculated by dividing net income, after deducting the amount allocated to the General Partner, by the weighted-average number of LP Units outstanding during the year.
Emerging Issues Task Force Issue No. 03-06 (“EITF 03-06”) “Participating Securities and the Two-Class Method under FASB Statement No. 128” addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity. EITF 03-06 provides that the General Partner’s interest in net income is to be calculated based on the amount that would be allocated to the General Partner if all the net income for the period were distributed, and not on the basis of actual cash distributions for the period. The Partnership applied EITF 03-06 prospectively beginning with the fourth quarter of 2006. The application of EITF 03-06 may have an impact on earnings per LP Unit in future periods if there are material differences between net income and actual cash distributions or if other participating securities are issued.
The following table sets forth the reconciliation of the weighted average number of LP Units used to compute basic net income per LP Unit for the years ended December 31, 2006, 2005 and 2004:
Options reported as dilutive securities are related to unexercised options outstanding under the Option Plan (see Note 13).
20. SEGMENT INFORMATION
Prior to 2005, the Partnership determined that it had one reportable operating segment, the transportation segment, based on its management and financial reporting structure. Beginning in the fourth quarter of 2004 and continuing throughout 2005, the Partnership substantially expanded its business, including a significant increase in its terminalling operations. As a result, in 2005 the Partnership redesigned the financial information it regularly provides to management and, based on the nature of the new information, determined in the fourth quarter of 2005 that its operations are appropriately presented in three reportable operating segments: Pipeline Operations, Terminalling and Storage, and Other Operations.
Pipeline Operations
The Pipeline Operations segment receives refined petroleum products including gasoline, jet and diesel fuel and other distillates from refineries, connecting pipelines, and bulk and marine terminals and transports those products to other locations for a fee. This segment owns and operates approximately 5,400 miles of pipeline systems in the following states: California, Connecticut, Florida, Illinois, Indiana, Massachusetts, Michigan, Missouri, New Jersey, Nevada, New York, Ohio, Pennsylvania and Tennessee.
Terminalling and Storage
The Terminalling and Storage segment provides bulk storage and throughput services. This segment owns and operates 45 terminals that have the capacity to store an aggregate of approximately 17.6 million barrels of refined petroleum products. The terminals are located in Indiana, Illinois, Massachusetts, Michigan, Missouri, New York, Ohio and Pennsylvania.
Other Operations
The Other Operations segment consists primarily of the Partnership’s contract operation and maintenance of third-party pipelines owned principally by major petrochemical companies located in Texas. This segment also performs construction management services, typically for cost plus a fixed fee, for these same customers. The Other Operations segment also includes the Partnership’s ownership and operation of the ammonia pipeline acquired in November 2005 and its majority ownership of the Sabina Pipeline.
Financial information about each segment is presented below. Each segment uses the same accounting policies as those described in the summary of significant accounting policies (see note 2). All inter-segment revenues, operating income and assets have been eliminated. All three years are presented on a consistent basis.
* All equity investments shown in Note 8 are included in the assets of Pipeline Operations.
21. OTHER EVENTS
BGH IPO and General Partner Restructuring
On August 9, 2006, BGH consummated an initial public offering (“IPO”) of its common units. Following the IPO, approximately 54% of BGH’s limited partner units are owned by Carlyle/Riverstone, approximately 9% of BGH’s limited partner units are owned by certain members of senior management and approximately 37% of BGH’s limited partner units are owned by the public. In connection with the closing of the offering, BGH and the General Partner restructured the ownership of the General Partner.
This restructuring did not have any impact on the amounts or timing of cash distributions paid to the general or limited partners of the Partnership.
MainLine Sub LLC (“MainLine Sub”), which was then a wholly-owned subsidiary of BGH and the owner of the General Partner, assigned all of its rights under the Fourth Amended and Restated Incentive Compensation Agreement, dated as of December 15, 2004, between MainLine Sub and the Partnership to the General Partner. Thereafter, the Partnership and the General Partner amended and restated that agreement by entering into the Fifth Amended and Restated Incentive Compensation Agreement, dated as of August 9, 2006 (the “Incentive Compensation Agreement”). On August 9, 2006, the Partnership and the General Partner also entered into the Amended and Restated Agreement of Limited Partnership of Buckeye Partners, L.P. (the “Partnership Agreement”). The amendments to the Incentive Compensation Agreement and the Partnership Agreement reflect the assignment of the Incentive Compensation Agreement to the General Partner and the re-characterization of payments to the General Partner under the Incentive Compensation Agreement and the Partnership Agreement as distribution payments rather than compensation payments. On August 18, 2006, MainLine Sub was merged with and into BGH.
BGH’s third quarter 2006 distribution was declared prior to August 9, 2006 and, therefore, the related incentive compensation attributable to the General Partner became payable prior to such date. As a result, incentive compensation paid in the third quarter of 2006 was recorded as an expense by the Partnership in the accompanying consolidated financial statements, consistent with the Partnership’s prior practice. Commencing with the fourth quarter of 2006, the Partnership ceased recording incentive compensation payable to the General Partner as an expense and instead began recording such payments as distributions from equity.
The amendments to the Incentive Compensation Agreement and the Partnership Agreement were effective on August 9, 2006. These amendments resulted in certain prospective changes in the financial statements of the Partnership that began in the fourth quarter of 2006. Commencing in the fourth quarter of 2006, in addition to the re-characterization of incentive distributions, the Partnership changed the way it attributes income between the General Partner and the limited partners. Generally, the Partnership now attributes income to the General Partner and the limited partners as if the net income of the Partnership were entirely distributed to its Unitholders. The Partnership determines the amount of income allocable to the General Partner, which represents the sum of the incentive compensation that would have been payable to the General Partner if the total distribution equaled net income, plus the General Partner’s proportional share of the remaining income of the Partnership. The recording of incentive payments as equity distributions rather than an expense resulted in an increase in reported net income of $6.6 million for the year ended 2006.
As discussed above, none of these changes affected the amounts or timing of cash distributions to the general or limited partners. The Partnership’s criteria for determining the amount of cash distributions and its policies regarding the timing of declaring and paying such cash distributions remain unchanged.
Immediately prior to the closing of the BGH IPO, in connection with the restructuring of the ownership of the General Partner, the General Partner transferred its 1% general partner interest in each of Buckeye, Laurel and Everglades and its approximate 0.6% interest in BPH to the Operating Subsidiary GP, which is owned by the General Partner. In connection with the transfer, the partnership agreements of each operating subsidiary named above, as well as the related management agreements, were amended to reflect the Operating Subsidiary GP as the new general partner.
22. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data for 2006 and 2005 are set forth below. Quarterly results were influenced by seasonal and other factors inherent in the Partnership’s business.
(i) The Partnership’s reported net income in the fourth quarter and for the year ended 2006 reflect an amendment of the incentive compensation agreement between the General Partner, and the Partnership which changed the incentive compensation paid to the General Partner from a compensation payment to a partnership distribution (see Note 21 for a further discussion). Accordingly, net income in the fourth quarter and for the year ended 2006 was $6.6 million higher than it would have been if the incentive compensation agreement had not been amended.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A. Controls and Procedures
(a) Evaluation of Disclosure Controls and Procedures.
The management of the General Partner, with the participation of its Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of its disclosure controls and procedures for the Partnership as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the General Partner’s disclosure controls and procedures as of the end of the period covered by this report are designed and functioning effectively to provide reasonable assurance that the information required to be disclosed by the General Partner in reports filed under the Securities Exchange Act of 1934, as amended, is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (ii) accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding disclosure. A controls system cannot provide absolute assurance, however, that the objectives of the controls system are met, and no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a company have been detected.
(b) Management’s Report on Internal Control Over Financial Reporting
Management’s report on internal control over financial reporting is set forth in Item 8 of this annual report on Form 10-K and is incorporated by reference herein.
(c) Change in Internal Control over Financial Reporting
No change in the General Partner’s internal control over financial reporting for the Partnership occurred during the Partnership’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the General Partner’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
The Partnership does not have directors or officers. The executive officers of the General Partner perform all management functions for the Partnership and the Operating Subsidiaries in their capacities as officers and directors of the General Partner and Services Company. Directors and officers of the General Partner are selected by Buckeye GP Holdings L.P (“BGH”)., as sole member of the General Partner. See “Certain Relationships and Related Transactions.”
Directors of the General Partner
Set forth below is certain information concerning the directors of the General Partner. The General Partner has been restructured several times in recent years. References in the table below to service with the General Partner mean service with the current General Partner and its predecessor companies where applicable.
Name, Age and Present
Position with General Partner
Business Experience During Past Five Years
William H. Shea, Jr., 52
Chairman of the Board, President
and Chief Executive Officer and
Director*
Mr. Shea was named Chairman of the Board on May 12, 2004 and President and Chief Executive Officer and a director of the General Partner on September 27, 2000. He has served as President and Chief Executive Officer and as a director of the general partner of BGH (and its predecessors) since May 4, 2004. He served as President and Chief Operating Officer of the General Partner from July 1998 to September 2000. Mr. Shea serves on the Board of Trustees of The Franklin Institute.
Brian F. Billings, 68
Directorü
Mr. Billings became a director of the General Partner in October 1986. He has been a private investor for the past five years.
Michael B. Hoffman, 56
Director
Mr. Hoffman became a director of the General Partner on May 4, 2004. He also serves as a director of the general partner of BGH. Mr. Hoffman has been a Managing Director at Riverstone Holdings, LLC since January 2003. Mr. Hoffman is on the Board of Trustees of Lenox Hill Hospital and Manhattan Eye, Ear and Throat Hospital. Prior to joining Riverstone Holdings, LLC, Mr. Hoffman was a Senior Managing Director and Co-Head of M&A Advisory at The Blackstone Group, where he was also a member of Blackstone’s Principal Group Investment Committee.
E. Bartow Jones, 30
Director
Mr. Jones became a director of the General Partner on October 31, 2006. He also serves as a director of the general partner of BGH. Mr. Jones became a Vice President of Riverstone Holdings LLC in 2005. From 2001 to 2005, he was an associate at Riverstone Holdings, LLC.
Edward F. Kosnik, 62
Directorü
Mr. Kosnik became a director of the General Partner in October 1986. Mr. Kosnik was President and Chief Executive Officer of Berwind Corporation, a diversified industrial real estate and financial services company, from December 1999 until February 2001. From November 2004 to September 2005, he served on the Board of Directors of Premcor, Inc. and was a member of Premcor, Inc.’s audit committee. Since 2005, he has been a Trustee of Marquette University and a member of its Audit Committee.
Joseph A. LaSala, Jr., 52
Directorü
Mr. LaSala became a director of the General Partner on April 23, 2001. He has served as Vice President, General Counsel and Secretary of Novell, Inc. since July 11, 2001. Mr. LaSala served as Vice President, General Counsel and Secretary of Cambridge Technology Partners from March 2000 to July 2001.
Jonathan O’Herron, 77
Directorü
Mr. O’Herron became a director of the General Partner in September 1997. He has been Managing Director of Lazard Freres & Company, LLC for more than five years.
Andrew W. Ward, 39
Director
Mr. Ward became a director of the General Partner on May 4, 2004. He also serves as a director of the general partner of BGH. He is currently a Managing Director of Riverstone Holdings, LLC where he served as a Principal from March 2002 to December 2004. Prior to joining Riverstone Holdings, LLC, Mr. Ward was a Limited Partner and Managing Director with Hyperion Partners/Ranieri & Co., a private equity fund that specialized in investments in the financial services and real estate sectors.
* Also a director of Services Company.
ü Is a non-employee director of our General Partner and is not otherwise affiliated with our General Partner or its parent companies.
Executive Officers of the General Partner
Set forth below is certain information concerning the executive officers of the General Partner who also serve in similar positions in Services Company.
Name, Age and Present Position
Business Experience During Past Five Years
William H. Shea, 52
Chairman of the Board, President
and Chief Executive Officer
Mr. Shea was named Chairman of the Board on May 12, 2004 and President and Chief Executive Officer and a director of the General Partner on September 27, 2000. He has served as President and Chief Executive Officer and as a director of the general partner of BGH (and its predecessors) since May 4, 2004. He served as President and Chief Operating Officer of the General Partner from July 1998 to September 2000. Mr. Shea serves on the Board of Trustees of The Franklin Institute.
Eric A. Gustafson, 58
Senior Vice President, Operations
and Technology
Mr. Gustafson became Senior Vice President, Operations and Technology of the General Partner on January 1, 2005. Mr. Gustafson had served as Vice President-Transportation and Technology of Services Company since May 1998.
Stephen C. Muther, 57
Executive Vice President,
Administration and Legal Affairs
Mr. Muther became Executive Vice President, Administration and Legal Affairs of the General Partner on February 1, 2007. Mr. Muther had served as Senior Vice President, Administration, General Counsel and Secretary of the General Partner since May, 1990. He has served in these same capacities for the general partner of BGH since May 4, 2004.
Robert B. Wallace, 45
Senior Vice President, Finance and
Chief Financial Officer
Mr. Wallace became the Senior Vice President, Finance and Chief Financial Officer of the General Partner on September 1, 2004. He serves in the same capacity for the general partner of BGH. Mr. Wallace was an executive director in the UBS Energy Group from September 1997 to February 2004.
Section 16(a) Beneficial Ownership Reporting Compliance
Pursuant to Section 16(a) of the Exchange Act, the General Partner’s executive officers and directors, and persons beneficially owning more than 10% of the Partnership’s LP Units, are required to file with the Commission reports of their initial ownership and changes in ownership of LP Units. Based solely on its review of Forms 3, 4 and 5 furnished to it and written representations from its executive officers and directors, the General Partner believes that for 2006, all executive officers and directors who were required to file reports under Section 16(a) complied with such requirements.
Committees of the Board of Directors
Audit Committee
The General Partner has an audit committee (the “Audit Committee”) composed of Brian F. Billings (Chairman), Edward F. Kosnik, Joseph A. LaSala and Jonathan O’Herron. The members of the Audit Committee are independent, non-employee directors of the General Partner and are not officers, directors or otherwise affiliated with the General Partner or its parent companies. The General Partner’s board of directors has determined that no Audit Committee member has a material relationship with the General Partner. The board of directors has also determined that each of Messrs. Billings, Kosnik and O’Herron qualifies as an audit committee financial expert as defined in Item 407(d)(5) of Regulation S-K.
The Audit Committee provides independent oversight with respect to our internal controls, accounting policies, financial reporting, internal audit function and independent auditors. The Audit Committee also reviews the quality, independence and objectivity of the independent and internal auditors. The Audit Committee has sole authority as to the retention, evaluation, compensation and oversight of the work of the independent auditors. The independent auditors report directly to the Audit Committee. The Audit Committee also has sole authority to approve all audit and non-audit services provided by the independent auditors. The Audit Committee also reviews grants of unit options under the Partnership’s unit option and distribution equivalent plan. The charter of the Audit Committee is available at the Partnership’s website at www.buckeye.com.
The Audit Committee may act as a conflicts committee or a special committee at the request of the General Partner to determine matters that may present a conflict of interest between the General Partner and the Partnership.
The Audit Committee has established procedures for the receipt, retention and treatment of complaints we receive regarding accounting, internal accounting controls or auditing matters and the confidential, anonymous submission by our employees of concerns regarding questionable accounting or auditing matters. These procedures are part of the Business Code of Conduct and are available at the Partnership’s website at www.buckeye.com.
Finance Committee
The General Partner has a Finance Committee, which currently consists of four directors: E. Bartow Jones, Edward F. Kosnik, Jonathan O’Herron and Andrew W. Ward (Chairman). The Finance Committee provides oversight and advice with respect to the capital structure of the Partnership.
Corporate Governance Matters
The Partnership has adopted a Code of Ethics for Directors, Executive Officers and Senior Financial Officers that applies to, among others, the Chairman, President, Chief Financial Officer and Controller of the General Partner, as required by Section 406 of the Sarbanes Oxley Act of 2002. Furthermore, the Partnership has adopted Corporate Governance Guidelines and a charter for its Audit Committee. Each of the foregoing is available on the Partnership’s website at www.buckeye.com. The Partnership will provide copies, free of charge, of any of the foregoing upon receipt of a written request. The Partnership intends to disclose amendments to, or director and executive officer waivers from, the Code of Ethics, if any, on its website, or by Form 8-K to the extent required.
You can also find information about the Partnership at the offices of the New York Stock Exchange (“NYSE”), 20 Broad Street, New York, New York 10005 or at the NYSE’s Internet site (www.nyse.com). The NYSE requires the chief executive officer of each listed company to certify annually that he is not aware of any violation by the company of the NYSE corporate governance listing standards as of the date of the certification, qualifying the certification to the extent necessary. The Chief Executive Officer of the General Partner provided such certification to the NYSE in 2006 without qualification. In addition, the certifications of the General Partner’s Chief Executive Officer and Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act have been included as exhibits to the Partnership’s Annual Report on Form 10-K.
Item 11.
Item 11. Executive Compensation
Overview
In Items 11 (Executive Compensation), 12 (Security Ownership of Certain Beneficial Owners and Management) and 13 (Certain Relationships and Related Transactions, and Director Independence), when we are referring to Buckeye Partners, L.P. we will use the terms “we,” “us,” “our” and other similar terms.
We are managed by our general partner, Buckeye GP LLC. Our general partner is 100% owned by Buckeye GP Holdings L.P., a publicly traded limited partnership that is owned approximately 54% by affiliates of Carlyle/Riverstone Global Energy and Power Fund II L.P. (which we call “Carlyle/Riverstone”), approximately 37% by the public and approximately 9% by our management. We refer to Buckeye GP Holdings L.P. as “BGH.” All of our employees are employed by and receive employee benefits from Buckeye Pipe Line Services Company, a Pennsylvania corporation that we refer to as “Services Company.” Pursuant to a services agreement and an executive employment agreement, we and our general partner reimburse Services Company for the costs of employing these employees.
Compensation Discussion and Analysis
Named Executive Officers
We do not have officers or directors. Our business is managed by the board of directors of our general partner, and the executive officers of our general partner perform all of our management functions. Thus, the executive officers of our general partner are our executive officers. This Compensation Discussion and Analysis is focused on the total compensation of the executive officers of our general partner and is set forth below. Our executive officers, which we refer to in this discussion as our “named executive officers” are:
· William H. Shea, Jr., President and Chief Executive Officer;
· Robert B. Wallace, Senior Vice President, Finance and Chief Financial Officer;
· Stephen C. Muther, Executive Vice President, Administration and Legal Affairs; and
· Eric A. Gustafson, Senior Vice President, Operations and Technology.
Our Responsibility for Compensation
We do not currently compensate our named executive officers. Historically, our partnership agreement and the partnership agreements of our operating subsidiaries that are limited partnerships required that we and those subsidiaries reimburse our general partner for substantially all direct and indirect costs related to our business activities and those of our operating subsidiaries. In 1997, in connection with a restructuring of our ESOP, we and our operating subsidiaries entered into an Exchange Agreement with our general partner pursuant to which our general partner permanently released our operating subsidiaries and us from our obligation to reimburse the general partner for certain compensation and fringe benefit costs for executive level duties performed by the general partner with respect to operations, finance, legal, marketing and business development, and treasury, as well as the President of the general partner. In connection with a subsequent restructuring in 2004, the Exchange Agreement was amended to provide that such release included all compensation and fringe benefit costs for the four highest salaried officers of our general partner, which corresponds to our named executive officers. Accordingly, the total compensation of our named executive officers discussed in this analysis (with the exception of some potential contractual severance payments that could become payable to Mr. Muther upon termination of his employment, as further described under the heading “Potential
Payments upon Termination or Change in Control” below) is paid by our general partner or its owner, BGH, and not by us.
Our general partner receives quarterly distributions from us, which are payments that our partnership agreement and an incentive compensation agreement obligate us to pay. Our general partner pays the compensation of our named executive officers out of these distributions. The amount of each quarterly distribution that we must pay to our general partner is based solely on the amount of cash that we distribute to our limited partners each quarter, and bears no relationship to the amount of compensation our general partner must pay the named executive officers. Therefore, even if our general partner were to receive no distributions from us, it would still be obligated for the compensation of our named executive officers. The general partner’s distribution rights are described in detail in Item 13 of this report under the heading “General Partner Reimbursement and Incentive Distributions.”
Additionally, prior to its initial public offering on August 9, 2006, BGH (through its predecessors) was a private company that had been owned by members of our management (including some of our named executive officers), members of their families and trusts for their benefit, and then was purchased by Carlyle/Riverstone in 2004. In connection with its purchase of BGH’s predecessor company in 2004, Carlyle/Riverstone negotiated employment agreements and compensation arrangements with our general partner’s executive officers that included provisions regarding salaries and benefits that are still effective today. As a result, the context in which decisions were made regarding the 2006 compensation of our named executive officers was that of a private company board of directors determining how best to allocate that private company’s resources in order to compensate its officers.
Compensation Committees
As a limited partnership that is listed on the New York Stock Exchange, we are not required to have a Compensation Committee. Our general partner’s board of directors has determined that a compensation committee is unnecessary because the compensation of our named executive officers is paid by our general partner and not by us.
BGH is also a NYSE-listed limited partnership, and, therefore, it is likewise not required to have a Compensation Committee. However, because, as the owner of our general partner, BGH, is responsible for the payment of our named executive officers’ compensation, its board of directors formed a Compensation Committee in January 2007. The committee is composed of two independent directors (as that term is defined in the applicable NYSE rules and Rule 10A-3 of the Exchange Act) and one director who is not independent. The independent directors are Mr. Frank S. Sowinski and Mr. W. Barnes Hauptfuhrer. The non-independent director is Mr. Andrew W. Ward, who is affiliated with Carlyle/Riverstone. The BGH Compensation Committee will determine whether any changes to BGH’s policies and philosophies regarding the compensation of our named executive officers should be made in 2007.
Types of Compensation
In 2006, the compensation paid by our general partner to our named executive officers had four components: salary, non-equity incentive plan compensation, nonqualified deferred compensation and vesting of previously issued equity-based awards.
As discussed above, the salaries of our named executive officers were determined by private negotiations between those officers and BGH prior to BGH becoming a public company. Pursuant to their employment arrangements (which are described in more detail in the narrative discussion that follows the Summary Compensation Table), Mr. Shea’s salary is not less than $400,000 per year, and each of Messrs. Wallace, Muther and Gustafson have salaries of not less than $300,000 per year. In 2006, each of these named executive officers’ salaries equaled their respective minimum amounts. None of BGH, its
Compensation Committee, or our general partner has engaged in any benchmarking of these salaries against those of similarly situated executives in peer companies.
In early 2006, BGH’s predecessor and its owner Carlyle/Riverstone communicated to the named executive officers their desire to complete an initial public offering of BGH’s common units. The board of directors of BGH’s predecessor informed the named executive officers that it had established a pool of up to $2.0 million for the payment of cash awards to the named executive officers and other employees upon the consummation of an initial public offering of BGH common units. Following the completion of the BGH initial public offering on August 9, 2006, BGH paid a total of $1,737,500 to the named executive officers as set forth in the Summary Compensation Table. These amounts were not paid in respect of services rendered by the named executive officers to us, but they are included here for the sake of completeness.
The named executive officers also received nonqualified deferred compensation in 2006 in the form of contributions by our general partner to their Benefit Equalization Plan accounts. The Equalization Plan is a non-qualified deferred compensation plan and provides that any employee whose company contributions to qualified pension and savings plans have been limited due to IRS limits on compensation allowable for calculating benefits under qualified plans will receive an equivalent benefit under the Benefit Equalization Plan for company contributed amounts they would have received under qualified plans if there were no IRS limits on compensation levels. Each named executive officer participated in this plan prior to BGH becoming a public company in August of 2006 and continued to participate in this plan thereafter.
Each of our named executive officers owns BGH management units that were issued in 2004, a portion of which vested in 2006. The board of directors of BGH (and its predecessor companies) determined both the number of management units awarded to the named executive officers and also the vesting schedules of those management units. A description of the management units and their vesting schedules is contained in the narrative discussion following the Summary Compensation Table below.
Tax and Accounting Implications
Deductibility of Executive Compensation
We believe that the compensation paid to the named executive officers is generally fully deductible by BGH and its limited partners for federal income tax purposes. However, BGH can approve compensation that will not meet these requirements in order to ensure competitive levels of total compensation for its executive officers.
Nonqualified Deferred Compensation
On October 22, 2004, the American Jobs Creation Act of 2004 was signed into law, changing the tax rules applicable to nonqualified deferred compensation arrangements. While the final regulations have not become effective yet, BGH believes it is operating in good faith compliance with the statutory provisions which were effective January 1, 2005. A more detailed discussion the BGH’s nonqualified deferred compensation arrangements is provided in the narrative discussion accompanying the “Nonqualified Deferred Compensation Table” below.
Accounting for Stock-Based Compensation
Effective January 1, 2006, we and BGH began accounting for stock-based payments, including management units issued in connection with the BGH initial public offering and the Buckeye Pipe Line Services Company Unit Option and Distribution Equivalent Plan, in accordance with the requirements of SFAS No. 123R.
Compensation Committee Report
As discussed in the Compensation Discussion and Analysis, we do not currently compensate our named executive officers. Rather, the name executive officers are compensated by our general partner and its parent company, BGH. Accordingly, to the extent that decisions are made regarding the compensation policies pursuant to which our named executive officers are compensated, they are made by the board of directors of BGH, and not by our board of directors.
In light of the foregoing, as required by Item 407(e)(5) of Regulation S-K, our general partner’s board of directors has reviewed and discussed the Compensation Discussion and Analysis with our management, and, based on such review and discussions, has approved the inclusion of the Compensation Discussion and Analysis in this annual report on Form 10-K.
THE BOARD OF DIRECTORS OF
BUCKEYE GP LLC
Brian F. Billings
Michael B. Hoffman
E. Bartow Jones
Edward F. Kosnik
Joseph A. LaSala, Jr.
Jonathan O’Herron
William H. Shea, Jr.
Andrew W. Ward
2006 Summary Compensation Table
(1) The amounts in column (e) reflect the amounts recognized in the financial statements for the fiscal year ended December 31, 2006, in accordance with SFAS 123(R). The awards relate to BGH limited partner units that were issued to the named executive in exchange for MainLine L.P (the predecessor company of BGH) limited partner units that were granted to them in 2004.
In August 2006, BGH became a publicly traded company in an initial public offering at a price of $17.00 per unit. Concurrent with the initial public offering, BGH acquired all the limited partner units of MainLine L.P. in exchange for units of BGH. When the BGH units were exchanged for the MainLine L.P. limited partner units, the prior grants of MainLine L.P. limited partner units were exchanged for equivalent value of BGH units. See the narrative discussion immediately following this table for a further discussion of this exchange and the assumptions used for the valuation of the management units.
(2) The amounts in column (f) reflect the amounts recognized in the financial statements for fiscal year ended December 31, 2006, in accordance with SFAS 123(R), for option awards of our limited partner units made pursuant to the Buckeye Pipe Line Services Company Unit Option and Distribution Equivalent Plan. The current named executive officers are not eligible for option awards under this program. Mr. Gustafson has outstanding option awards that were granted to him under this program prior to his becoming a named executive officer. See Note 13 to the financial statements contained in this report on Form 10-K for a further discussion of the assumptions related to unit option expense.
(3) The amounts in column (g) were paid to the named executive officers in connection with the initial public offering of BGH.
(4) The amounts in column (i) reflect for each named executive officer:
· a 5% company contribution to the Buckeye Pipe Line Services Company Retirement and Savings Plan on wages of up to $220,000, amounting to $11,000 for each named executive officer;
· the value of Buckeye Pipe Line Services Company stock allocated to each named executive officer, in accordance with the terms of the Buckeye Pipe Line Services Company Employee Stock Ownership Plan described in the accompanying narrative, amounting to $22,285 for Mr. Shea and $22,744 for each of the other named executive officers;
· for Mr. Gustafson, the payment of distribution equivalents under the Buckeye Pipe Line Services Company Unit Option and Distribution Equivalent Plan which were equal to $60,033. Pursuant to the plan, distribution equivalents were calculated by multiplying (i) the number of our limited partner units subject to such options that have not vested by (ii) two times the Partnership’s per limited partner unit regular quarterly distribution; and
· contributions to the named executive officer’s account under the Buckeye Pipe Line Services Company Benefit Equalization Plan. The amounts set forth in column (i) represent only the BGH contributions to each named executive officer’s account for 2006. A description of the plan and the amounts of contributions credited to each named executive officer’s account in 2006 are set forth in the “2006 Nonqualified Deferred Compensation Table” and the accompanying narrative discussion below.
Employment Agreements
BGH and Mr. Shea are parties to an employment agreement, dated as of May 4, 2004. Mr. Shea’s base salary under his employment agreement is not less than $400,000 per year (less applicable taxes and withholdings). The employment agreement is terminable at any time for any reason by BGH or Mr. Shea. Under the employment agreement, Mr. Shea is employed by Buckeye Pipe Line Services Company, referred to as Services Company, which is the servicing entity that employs our employees. Pursuant to an exchange agreement and an executive employment agreement between BGH and Services Company, BGH reimburses Services Company for all payments to Mr. Shea and the cost of Mr. Shea’s benefits under the employment agreement. Accordingly, we do not pay any of Mr. Shea’s compensation.
Mr. Muther and BGH are parties to an employment and severance agreement, dated as of May 4, 2004. Mr. Muther’s base salary under his employment agreement is not less than $300,000 per year (less
applicable taxes and withholdings). Mr. Muther’s employment agreement is terminable at any time for any reason by BGH or Mr. Muther, subject to the obligations of BGH and us to pay Mr. Muther severance under certain circumstances. Pursuant to the employment agreement, Mr. Muther is employed by Services Company. Pursuant to an exchange agreement and an executive employment agreement between BGH and Services Company, BGH reimburses Services Company for all payments to Mr. Muther and the cost of Mr. Muther’s benefits under the employment agreement. Accordingly, we do not pay any of Mr. Muther’s compensation (but we may be liable for certain severance payments described in “Potential Payments Upon Termination or Change in Control” below).
Mr. Wallace’s base salary is $300,000 per year and is paid by BGH. Mr. Wallace is not party to any employment agreement with BGH or us, but he may be entitled to severance payments to be paid by BGH upon termination as described in “Potential Payments Upon Termination or Change in Control” below.
Mr. Gustafson’s base salary is $300,000 per year and is paid by BGH. He is not party to any employment agreement with BGH or us.
Conversion of MainLine B Units to Buckeye GP Holdings L.P. Management Units
Prior to BGH’s initial public offering of its common units on August 9, 2006, our general partner was owned by a limited partnership named MainLine L.P., which was formed by Carlyle/Riverstone in 2004 solely for the purpose of purchasing our general partner. MainLine’s equity consisted of Class A Units and Class B Units. When Carlyle/Riverstone purchased our general partner in 2004, MainLine instituted a Unit Compensation Plan and issued Class B Units to senior management of MainLine (which included Messrs. Shea, Muther and Gustafson). On May 4, 2004, MainLine issued 16,216,668 Class B Units to certain members of senior management (including Messrs. Shea, Muther and Gustafson). Mr. Wallace also received Class B Units when he was elected by MainLine as the Senior Vice President, Finance and Chief Financial Officer of our general partner. All of the Class B Units were issued for no consideration because they were deemed to have only a nominal value as a result of being subject to subordination to the Class A Units on the liquidation of MainLine which also carried a 9% cumulative annual return to which the holders of the Class A Units were entitled prior to any distribution to the holders of the Class B Units. One half, or 8,108,334, of the Class B Units vested ratably over five years. The remainder, or 8,108,334, of the Class B Units vested over five years only if certain performance targets based on the dollar amounts of incentive compensation payments received by MainLine from us were met.
Coincident with BGH’s initial public offering, the equity interests of MainLine were exchanged for the equity interests of BGH. The total 145,900,000 of Class A Units and the general partner interest of MainLine were exchanged for 16,438,000 common units of BGH. The 16,216,668 Class B Units of MainLine (including those owned by Messrs. Shea, Wallace, Muther and Gustafson) were exchanged for 1,362,000 management units of BGH. The 9% cumulative annual return on MainLine’s Class A Units and general partner interest was eliminated as part of the exchange. BGH’s management units are exchangeable for its common units on a 1 to 1 basis at the option of the holder. The vesting schedule of the BGH management units received by management varies from that of the MainLine Class B Units for which they were exchanged. Pursuant to the terms of the exchange, seventy percent, or 953,400 management units, became vested immediately upon their exchange, and the remaining 30%, or 408,600 of the management units, vest over a three year period with 136,200 of the units vesting on each May 4 of 2007, 2008 and 2009.
MainLine recorded no compensation expense for the time-based Class B Units for the years ended December 31, 2006 and 2005. Although the grant date of May 4, 2004 represented the measurement date for the time-based Class B Units (the date both the number of units available for purchase and the purchase price ($0) were known), there was a nominal fair value for these units at the grant date. Under Statement of Financial Accounting Standards No. 123 (Revised) (SFAS No. 123R), which BGH and the
Partnership adopted January 1, 2006, compensation expense for the time-based Class B Units subsequent to January 1, 2006 is measured based on the nominal fair value established at the grant date.
Prior to January 1, 2006, MainLine recognized deferred compensation for the performance-based Class B Units when it was probable that the performance target specified in MainLine’s partnership agreement would be met. The cost of this deferred compensation was recognized over the respective service periods of the performance-based Class B Units until December 31, 2005. MainLine recorded compensation expense for the performance-based Class B Units of $3.4 million in general and administrative expenses in its consolidated financial statements for the year ended December 31, 2005. Under the SFAS No. 123R however, compensation expense for the performance-based Class B Units subsequent to January 1, 2006 is measured based on the nominal fair value established at the grant date. Accordingly, MainLine recorded no compensation expense related to the performance-based Class B Units from January 1, 2006 to August 9, 2006.
As noted above, in connection with BGH’s initial public offering, on August 9, 2006 the holders of MainLine’s Class B Units exchanged all of the Class B Units for 1,362,000 management units of BGH. Under the provisions of SFAS No. 123R, BGH recognized deferred compensation for the management units for which both (i) vesting was accelerated compared to the MainLine Class B Units, and (ii) were now deemed probable of vesting compared to BGH’s previous estimates. BGH determined that these criteria applied to 272,400 management units, the fair value of which was $4.6 million at August 9, 2006. There are no additional management units available for grant.
Of the total deferred compensation recognized of $4.6 million, BGH recognized approximately $3.3 million as an expense in the third quarter of 2006 (with an offsetting increase in partners’ capital). Approximately $2.6 million of this was attributable to the exchange of management units for Messrs. Shea, Wallace, Muther and Gustafson as set forth in the Summary Compensation Table above. BGH will recognize the balance of $1.3 million as an expense ratably in periods commencing August 9, 2006 and ending May 4, 2009.
Retirement and Other Benefits
The majority of our regular full-time employees hired before September 16, 2004 (including our named executive officers) participate in Services Company’s employee stock ownership plan, or ESOP, which is a qualified plan. Services Company owns 2,313,395 of our limited partner units. The ESOP owns all of the outstanding common stock of Services Company, or 2,313,395 shares. Accordingly, one share of Services Company common stock is generally considered to have a value equal to one of our limited partner units. Under the ESOP, Services Company common stock is allocated to employee accounts quarterly. Individual employees are allocated shares based on the ratio of their eligible compensation to the aggregate eligible compensation of all ESOP participants. Eligible compensation generally includes base salary, overtime payments and certain bonuses. The value of shares accumulated by an employee in the ESOP is payable to the employee, upon termination of employment or, transferable to other qualified plans in accordance with the terms of the ESOP plan.
Services Company also sponsors a Retirement and Savings Plan through which it provides retirement benefits for substantially all of its regular full-time employees (including our named executive officers), except those covered by certain labor contracts. The retirement plan consists of two components. Under the first component, Services Company contributes 5% of each eligible employee’s covered salary to an employee’s separate account maintained in the retirement plan. Under the second component, for all employees not participating in the ESOP, Services Company makes a matching contribution into the employee’s separate account for 100% of an employee’s contribution to the retirement plan up to 6% of an employee’s eligible covered salary. For Services Company employees who participate in the ESOP, Services Company does not make a matching contribution. Each of our named executive officers receives the contribution equal to 5% of his salary (subject to certain IRS limits) annually, and these amounts are
fully vested upon contribution. Because each of our named executive officers participates in the ESOP, we do not make any matching contributions to the retirement plan on their behalf.
Services Company also sponsors a Benefit Equalization Plan, which is described in detail in the narrative discussion following the “Nonqualified Deferred Compensation Table” below.
2006 Grants of Plan-Based Awards Table
(1) The amounts in column (d) were paid to the named executive officers in connection with the initial public offering of BGH. In early 2006, BGH’s predecessor and its owner Carlyle/Riverstone communicated to the named executive officers their desire to complete an initial public offering of BGH’s common units. The board of directors of BGH’s predecessor informed the named executive officers that it had established a pool of up to $2.0 million for the payment of cash awards to the named executive officers and other employees upon the consummation of an initial public offering of BGH common units. Following the completion of the BGH initial public offering on August 9, 2006, BGH paid a total of $1,737,500 to the named executive officers as set forth in the Grants of Plan-Based Awards Table. These amounts were not paid in respect of services rendered by the named executive officers to us, but they are included here for the sake of completeness.
2006 Outstanding Equity Awards at Fiscal Year-End Table
(1) The amounts in columns (b) and (c) relate to options to purchase our limited partner units under our Unit Option and Distribution Equivalent Plan which were granted prior to 2006. All options vest after the expiration of three years from the grant date of the option. The options reported in column (c) vested on February 26, 2007. Our named executive officers do not participate in the plan. The options set forth above were granted prior to Mr. Gustafson becoming a named executive officer.
(2) The Partnership limited partner unit awards reported in column (g) relate to BGH management units, which vest at the rate of 33 1/3% per year. The remaining vesting dates for BGH management units are May 4, 2007, 2008 and 2009.
(3) The closing market price of BGH’s common units was $16.38 on December 29, 2006.
2006 Option Exercises and Stock Vested Table
(1) Coincident with the initial public offering of BGH, the equity interests of MainLine L.P. (BGH’s predecessor company) were exchanged for the equity interests in BGH. The named executive officers held equity interests in MainLine L.P. that entitled them to receive an aggregate amount of 1,021,500 limited partner units of BGH upon vesting. The limited partner units of BGH that are subject to vesting are known as management units. The management units shown in column (d) represent the management units that vested in 2006 which amounted to fifty percent of the total management units granted to the named executive officers at the end of 2006. Twenty percent of the management units vested in prior years (based on the vesting of the MainLine L.P. limited partner units for which they were exchanged), bringing the vested management units to seventy percent of the total management units. The remaining thirty percent of the management units vest over a three year period with vesting on each May 4 of 2007, 2008 and 2009.
(2) The value shown in column (e) is calculated by multiplying the number of limited partner units vested from column (d) by $17.00 which was the August 9, 2006 initial public offering price of BGH common units. This value was used because, although 50% of the management units vested prior to such date (through the vesting of the MainLine L.P. limited partner units for which they were exchanged), there was no market for such units at the time of vesting, and the value of such units at vesting cannot be determined. Accordingly, the value of the fully vested management units that were issued in connection with the exchange on August 9, 2006 was used.
2006 Nonqualified Deferred Compensation Table
(1) The aggregate amounts of contributions in the last fiscal year for each named executive officer are included in column (i) of the Summary Compensation Table above.
The amounts reflected in the table above were credited to accounts of the named executive officers under the Buckeye Pipe Line Services Company Benefit Equalization Plan. The equalization plan is a non-qualified deferred compensation plan and provides that any employee whose company contributions to qualified pension and savings plans have been limited due to IRS limits on compensation allowable for calculating benefits under qualified plans will receive an equivalent benefit under the Equalization Plan for company contributed amounts they would have received under qualified plans if there were no IRS limits on compensation levels. Employee deferrals are not allowed under the equalization plan. In addition, the
equalization plan provides that any employee with a balance in the plan will be credited with earnings on that balance at a rate that is equivalent to the actual earnings that the employee realizes on his or her investments in the Buckeye Pipe Line Services Company Retirement and Savings Plan. Employees may periodically change their investment elections in the Retirement and Savings Plan in accordance with its terms and the terms of the documents governing the investments in which they currently participate. Amounts accumulated by an employee in the equalization plan are payable to the employee in a lump sum upon termination of employment. The employee may also receive a distribution of all or a portion of his or her account balance in the event of a “hardship” as defined in the plan document and upon determination by the committee that administers the plan, and an employee may receive payment of a portion (as described in the plan) of the employee’s account balance in the event of the death of the employee. The table below shows the fund options available under the Retirement and Savings Plan and their annual rate of return for the year ended December 31, 2006.
Potential Payments upon Termination or Change in Control
Severance and Continued Benefits
Mr. Shea is party to a benefits continuation agreement with BGH that is dated January 1, 2004. Pursuant to the benefits continuation agreement, upon the termination of Mr. Shea’s employment for any reason within two years following a change in control of us, Mr. Shea will be entitled to continued coverage by BGH for 36 months after the effective date of such termination under our medical and dental benefits and disability insurance plans and policies at the same level of coverage that Mr. Shea enjoyed prior to such termination. Mr. Shea’s eligibility to continue receiving these medical, dental and disability insurance benefits will cease if Mr. Shea obtains new employment that provides him with eligibility for medical, dental and disability insurance benefits without a pre-existing condition limitation. For purposes of Mr. Shea’s benefits continuation agreement, a “change of control” is defined as the acquisition (other than by our general partner and its affiliates) of 80 percent or more of our LP Units, 51 percent or more of the general partnership interests owned by our general partner or 50 percent or more of the voting equity interest of us and our general partner on a combined basis.
Mr. Muther’s employment and severance agreement also provides that BGH will pay severance payments and allow Mr. Muther to continue certain medical and dental benefits following a termination of Mr. Muther’s employment by BGH (and its affiliates). This agreement replaced and amended earlier employment and severance agreements under which we were obligated to provide certain severance payments to Mr. Muther on termination. Although BGH is obligated for Mr. Muther’s compensation, severance and benefits under the current employment and severance agreement, we remain liable for certain severance costs to the extent we would have been liable for them under the old agreements and for amounts that accrued in Mr. Muther’s retirement plans prior to the 1997 date of the original exchange agreement discussed above. Under the employment and severance agreement, Mr. Muther is entitled to
the payment of severance and the continuation of certain benefits following (a) an involuntary termination of Mr. Muther’s employment for any reason other than for “cause” or (b) a voluntary termination of employment by Mr. Muther for “good reason,” which includes, in certain circumstances, a termination in connection with a change of control of us. Under either of these circumstances, Mr. Muther would receive a cash severance payment from BGH of 3.0 times his annualized base salary at the time of his termination. Assuming a qualifying termination of employment on December 31, 2006, Mr. Muther would receive a lump-sum severance payment equal to $900,000. In addition, BGH will provide certain continued medical and dental benefits to Mr. Muther under our plans for a period of 18 months following his termination (36 months if his termination were in connection with a change of control). Mr. Muther’s eligibility to continue receiving these medical and dental benefits will cease if Mr. Muther obtains new employment that provides him with eligibility for medical benefits without a pre-existing condition limitation. Also, if the first day of the calendar month on or following Mr. Muther’s 62nd birthday will be less than 18 months after his termination (36 months if his termination was in connection with a change of control), then the cash severance payment described above will be reduced to an amount equal to a fraction of such amount, the numerator of which is the number of days from the date of Mr. Muther’s termination to the first day of the calendar month on or following Mr. Muther’s 62nd birthday and the denominator of which is 548 (1095 if Mr. Muther’s termination was in connection with a change of control). For purposes of Mr. Muther’s employment agreement, “change of control” is defined similarly to such term in Mr. Shea’s benefits continuation agreement discussed above. Mr. Muther is also eligible for severance under the Severance Pay Plan for Employees of Buckeye Pipe Line Services Company, which is described below in the discussion regarding Mr. Gustafson. If Mr. Muther is terminated such that both plans are triggered, however, the amount of the payments he would receive pursuant to his employment and severance agreement will be reduced by any amounts he receives pursuant to the severance pay plan. As of December 31, 2006, the severance payable to Mr. Muther pursuant to his employment and severance agreement exceeds the amount payable under the severance pay plan.
BGH and Mr. Wallace are parties to a severance agreement, dated as of September 1, 2004, which provides for the payment of severance and the continuation of certain benefits under our medical and dental plans and policies following a voluntary termination of employment by Mr. Wallace after a change of control has occurred and upon the occurrence of certain specified adverse changes in Mr. Wallace’s employment conditions (such as a decrease in salary, material reduction of duties or authority, removal from eligibility to participate in benefit plans or transfer to a work location that is more than 100 miles from his current work location). Mr. Wallace’s severance agreement provides for a severance payment from BGH of 2.0 times Mr. Wallace’s annualized base salary at the time of termination. Assuming a qualifying termination of employment on December 31, 2006, Mr. Wallace would receive a lump-sum severance payment equal to $600,000. In addition, BGH will provide certain continued benefits to Mr. Wallace under our medical and dental plans and policies for a period of 12 months following his termination. Mr. Wallace’s eligibility to continue receiving these medical and dental benefits will cease if he obtains new employment that provides him with eligibility for medical benefits without a pre-existing condition limitation. For purposes of Mr. Wallace’s severance agreement, “change of control” is defined similarly to such term in Mr. Shea’s benefits continuation agreement discussed above.
In addition to any applicable severance payments described above, assuming Mr. Shea, Mr. Muther and Mr. Wallace were each terminated as of December 31, 2006, under circumstances that entitled them to receive the continued medical, dental and disability benefits described above, the value of such benefits is estimated to be approximately $44,181 for Mr. Shea, $24,726 for Mr. Muther and $16,484 for Mr. Wallace, except if Mr. Muther’s termination were in connection with a change of control, the value of his benefits would be $49,452. In valuing these benefits, we used the estimated rates applicable under the Comprehenisve Omnibus Budget Reconciliation Act (COBRA) for terminated employees. Upon termination, all named executive officers would be entitled to coverage under COBRA. COBRA coverage
for Messrs. Shea, Wallace and Muther would begin upon the expiration of their respective benefit continuation periods set forth above.
If Mr. Gustafson’s employment were terminated involuntarily, he would be eligible for severance payments under the Severance Pay Plan for Employees of Buckeye Pipe Line Services Company. Subject to certain limitations, upon an involuntary termination, Mr. Gustafson would be entitled to receive a lump-sum severance payment equal to eight weeks of his base pay plus two weeks’ base pay for each year of service over 4 years. Except in the case of a change of control (as defined in the plan), however, the severance payment cannot exceed one year’s base pay, which for Mr. Gustafson is $300,000. Assuming an involuntary termination of employment on December 31, 2006, Mr. Gustafson would receive severance payments equal to approximately $272,000. If Mr. Gustafson were to be involuntarily terminated within two years after a “change of control,” he would be entitled to receive one year’s base pay plus the severance pay allowance he would have been entitled to receive under the above formula, or approximately $565,000. For the purposes of the severance pay plan, a “change of control” will occur if any person (as such term is used in sections 13(d) and 14(d) of the Securities Exchange Act of 1934), except us or our affiliates becomes the beneficial owner, or the holder of proxies, in the aggregate of 80% or more of our limited partner units then outstanding.
Plan Payouts
Upon termination, each named executive officer would become entitled to distributions of the aggregate balances of his benefits equalization plan account and ESOP account. If such officers had been terminated as of December 31, 2006, each of them would be entitled to receive the amounts set forth opposite his name in column (f) of the “Nonqualified Deferred Compensation Table” for his benefits equalization plan balance. As of December 31, 2006, the value of Mr. Shea’s ESOP account was $452,254, Mr. Wallace’s ESOP account was $64,890, Mr. Muther’s ESOP account was $501,836 and Mr. Gustafson’s ESOP account was $460,890.
As noted in the “Outstanding Equity Awards at Fiscal Year-End Table” above, Mr. Gustafson owns 3,700 unvested options to purchase our units pursuant to the Unit Option and Distribution Equivalent Plan. Under the terms of the plan, if we experience a change of control as defined in the plan, and the acquiring entity does not assume the options under the plan or otherwise provide for options to purchase the acquiror’s equity securities of equal value, then Mr. Gustafson’s unvested options would become vested upon the change of control. Upon vesting in connection with a change of control, Mr. Gustafson would realize value equal to 3,700 options times the amount, if any, by which the then current market price of our limited partner units exceeds $42.10, the exercise price for such options. Under the Unit Option and Distribution Equivalent Plan, a change of control of the Partnership would occur if (1) our unitholders approve a merger or consolidation of us with any other entity, other than a merger or consolidation which would result in the our unitholders retaining at least 75% of the total equity interest of the surviving entity, as represented by the percentage of units or equity securities of us or such surviving entity held by the our unitholders immediately after such merger or consolidation, (2) a plan of complete dissolution of us is adopted or our unitholders approve an agreement for the sale or disposition by us (in one transaction or a series of transactions) of all or substantially all of our assets, or (3) our general partner is removed, or any person or entity except one or more of the equity interest holders of our general partner or any employee benefit plan of our general partner, together with all affiliates of such person or entity, becomes the beneficial owner, or the holder of proxies, in the aggregate of 51% or more of our general partnership interests.
Finally, upon a sale of BGH as set forth in the unit agreements that govern the vesting of management units, all unvested management units will immediately vest. If a sale of BGH had occurred on December 31, 2006, the 30% of unvested management units described in the narrative accompanying the Summary Compensation Table under the heading “Conversion of MainLine B Units to Buckeye GP
Holdings L.P. Management Units,” would have immediately vested. In connection with such vesting, Mr. Shea would have realized $2,007,860; Mr. Wallace would have realized $669,287; Mr. Muther would have realized $1,338,574 and Mr. Gustafson would have realized $1,003,930. For purposes of the unit agreements, a sale of BGH would occur if:
· a third party or group of third parties acting in concert acquire all or substantially all of the equity securities of BGH or all or substantially all of BGH’s consolidated assets (in either case, whether by merger, consolidation, recapitalization, transfer of equity securities or otherwise); or
· Carlyle/Riverstone ceases to hold at least 20% of the BGH Common Units it held immediately prior to BGH’s initial public offering.
Under the unit agreements, the issuance of new common units by BGH cannot be deemed to cause a sale of BGH, however.
2006 Director Compensation Table
The amount reported in column (g) represents a payment made pursuant to the Director Recognition Program upon Mr. Sowinski’s retirement from our board of directors. (See the narrative discussion immediately following this table for further discussion).
Director Compensation
In 2006, directors of our general partner received an annual fee of $35,000 plus $1,000 for each board of directors and committee meeting attended. Additionally, the Chairman of the Audit Committee receives an annual fee of $10,000. Messrs. Hoffman, Jones, Shea and Ward do not receive any fees for service as directors. Directors’ fees paid by our general partner in 2006 to its directors amounted to $240,333. The directors’ fees were reimbursed by us. Effective February 21, 2007, the annual director fee will be increased to $50,000 plus $1,250 for each board of directors and committee meeting attended.
Director Recognition Program
Our general partner has maintained a Director Recognition Program since September 1997. This recognition program provides that, upon retirement or death and subject to certain conditions, directors receive a benefit of up to three times their annual director’s fees (excluding attendance and committee fees) based upon their years of service as a member of the board of directors of our general partner and its predecessors. A minimum of three full years of service as a member of the board of directors is required for eligibility under the recognition program. Members of the board of directors who are concurrently serving as an officer or employee of our general partner or its affiliates are not eligible for the Recognition Program. We recorded $70,000 of expense under this program in 2006 and $120,000 of expense in 2004. No expenses were recorded under this program during 2005.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
Services Company owns approximately 5.9% of the outstanding LP Units as of February 15, 2007. No other person or group is known to be the beneficial owner of more than 5% of the LP Units as of February 15, 2007.
The following table sets forth certain information, as of February 26, 2007, concerning the beneficial ownership of LP Units by each director of our general partner, the Chief Executive Officer of our general partner, the other named executive officers of our general partner and by all directors and executive officers of our general partner as a group. Such information is based on data furnished by the persons named. Based on information furnished to our general partner by such persons, no director or executive officer of our general partner owned beneficially, as of such date, more than 1% of any class of our equity securities or those of our subsidiaries outstanding at that date.
(1) Unless otherwise indicated, the persons named above have sole voting and investment power over the LP Units reported.
(2) Includes the 80,000 Units owned by Buckeye GP Holdings L.P., over which the indicated persons share voting and investment power by virtue of their membership on the Board of Managers of MainLine Management LLC, which is the general partner of Buckeye GP Holdings L.P. Such individuals expressly disclaim beneficial ownership of such Units.
(3) The 80,000 Units owned by Buckeye GP Holdings L.P. are included in the total only once.
(4) Includes 18,800 LP Units for which the person indicated shares voting and investment power with his spouse.
Equity Compensation Plan Information
The following table sets forth information as of December 31, 2006 with respect to compensation plans under which our equity securities are authorized for issuance.
(1) This plan is our Amended and Restated Unit Option and Distribution Equivalent Plan.
Changes in Control
BGH, the owner of our general partner, is party to a $10.0 million credit agreement with SunTrust Bank. We are not a party to this credit agreement. BGH’s credit agreement is secured by the pledge of the outstanding limited liability company interests of our general partner. If BGH defaults on its obligations under its credit agreement, the lender could exercise its rights under this pledge, which could result in a future change of control of us.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
General Partner Reimbursement and Distributions
Reimbursement of General Partner Costs and Expenses
Our general partner manages us and our operating subsidiaries that are limited partnerships pursuant to our Amended and Restated Agreement of Limited Partnership, the several Amended and Restated Agreements of Limited Partnership of those operating subsidiaries and the several Management Agreements between an affiliate of our general partner and those operating subsidiaries. Under these agreements and the limited liability company agreements of our operating subsidiaries that are limited liability companies, our general partner and certain related parties are entitled to reimbursement of all direct and indirect costs and expenses related to managing us and our operating subsidiaries, except as otherwise provided by the Exchange Agreement (as discussed below).
As part of a restructuring of our ESOP in 1997, we and certain of our operating subsidiaries entered into an Exchange Agreement with our general partner’s predecessors, pursuant to which we and our operating subsidiaries were permanently released from our obligations to reimburse the general partner for certain compensation and fringe benefit costs for executive level duties performed by our general partner with respect to operations, finance, legal, marketing and business development, and treasury, as well as the President of our general partner (but excluding certain of our obligations to pay severance and certain retirement obligations that had accrued for the benefit of such persons prior to the date of the
exchange agreement). In connection with a restructuring of the general partner in 2004, the Exchange Agreement was amended to provide that such release included the compensation and fringe benefit costs for the four highest salaried officers of our general partner (which correspond to our “named executive officers”). As a result, we are not generally responsible for the compensation and fringe benefit costs for our named executive officers, but rather these costs are borne by our general partner.
Management Fee
BGH’s general partner is entitled to be paid an annual management fee for certain management functions it provides to our general partner pursuant to a Management Agreement between it and our general partner. Our general partner charges the management fee to us. The management fee includes an annual “Senior Administrative Charge” of not less than $975,000 and reimbursement for certain costs and expenses. The disinterested directors of our general partner approve the amount of the management fee on an annual basis. Amounts paid to BGH’s general partner and its predecessors in 2006 amounted to $1,900,000 for the Senior Administrative Charge. There were no other reimbursed expenses in 2006.
Distribution Rights
Our general partner is entitled to receive distributions from us. Our general partner’s approximate 1% general partner interest in us entitles it to receive approximately 1% of the cash we distribute to our partners each quarter. Additionally, our general partner is entitled to receive incentive distributions from us. Pursuant to our Partnership Agreement and the Fifth Amended and Restated Incentive Compensation Agreement between our general partner and us, subject to certain limitations and adjustments, if a quarterly cash distribution exceeds a target of $0.325 per limited partner unit, we will pay our general partner, in respect of each outstanding limited partner unit, incentive compensation equal to (i) 15% of that portion of the distribution per limited partner unit which exceeds the target quarterly amount of $0.325 but is not more than $0.35, plus (ii) 25% of the amount, if any, by which the quarterly distribution per limited partner unit exceeds $0.35 but is not more than $0.375, plus (iii) 30% of the amount, if any, by which the quarterly distribution per limited partner unit exceeds $0.375 but is not more than $0.40, plus (iv) 35% of the amount, if any, by which the quarterly distribution per limited partner unit exceeds $0.40 but is not more than $0.425, plus (v) 40% of the amount, if any, by which the quarterly distribution per limited partner unit exceeds $0.425 but is not more than $0.525, plus (vi) 45% of the amount, if any, by which the quarterly distribution per limited partner unit exceeds $0.525. Our general partner is also entitled to an incentive distribution, under a comparable formula, in respect of special cash distributions exceeding a target special distribution amount per limited partner unit. The target special distribution amount generally means the amount which, together with all amounts distributed per limited partner unit prior to the special distribution compounded quarterly at 13% per annum, would equal $10.00 (the initial public offering price of the limited partner units split two-for-one) compounded quarterly at 13% per annum from the date of the closing of our initial public offering in December 1986. Incentive payments paid by us for quarterly cash distributions totaled $24,866,000, $20,180,000 and $14,002,000 in 2006, 2005 and 2004, respectively. No special cash distributions have ever been paid by us.
Ownership of Buckeye GP Holdings L.P.
BGH is owned by affiliates of Carlyle/Riverstone Global Energy and Power Fund II, L.P., certain directors and members of management of our general partner or trusts for the benefit of their families (including Messrs. Shea, Wallace, Muther and Gustafson) and the public. BGH owns our general partner, and, therefore, benefits from payments made by us to our general partner, such as the distributions described above. Because BGH distributes substantially all of its available cash to its unitholders quarterly and because certain members of management (including Messrs. Shea, Wallace, Muther and Gustafson) receive these distributions as unitholders of BGH, these members of management may have an indirect material interest in such payments.
Except for compensation that we pay, the material portions of which are described in this report, our policy is to avoid transactions between us and our directors and officers (including members of their families) in which such persons would have a material interest. In furtherance of this policy, we have adopted Corporate Governance Guidelines, a Code of Ethics for Directors, Executive Officers and Senior Financial Employees and a Business Code of Conduct for all employees, which generally require the reporting to management of transactions or opportunities that constitute conflicts of interest so that they may be avoided. These guidelines and codes are available on our web site at www.buckeye.com.
Except for our services arrangement with Services Company for the provision of our workforce, we also have a policy of avoiding transactions between us and holders of 5% or more of our limited partner units.
Pursuant to our Corporate Governance Guidelines, any transaction between us and our officers and directors or holders of 5% of more of our limited partner units that should be avoided pursuant to these policies must be reviewed and approved by our Board of Directors (other than any board member having a material interest in the transaction in question). The Board of Directors will only approve transactions that are fair and reasonable to us. Our partnership agreement states that a transaction will be deemed fair and reasonable to us if it is approved by our Audit Committee, if it is on terms objectively demonstrable to be no less favorable to us than those generally being provided to or available from unrelated third parties, or if it is otherwise determined to be fair to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
Director Independence
Section 303A.00 of the NYSE Listed Company Manual states that the NYSE listing standards requiring a majority of directors to be independent do not apply to publicly traded limited partnerships like us. However, four of the general partner’s eight directors are “independent” as that term is defined in the applicable NYSE rules and Rule 10A-3 of the Exchange Act. In determining the independence of each director, our general partner has adopted certain categorical standards. Our general partner’s independent directors as determined in accordance with those standards, are: Brian F. Billings, Edward F. Kosnik, Joseph A. LaSala and Jonathan O’Herron. Prior to his resignation on August 9, 2006, Frank S. Sowinski was also an independent director. Pursuant to such categorical standards, a director will not be deemed independent if:
· the director is, or has been within the last three years, our employee, or an immediate family member is, or has been within the last three years, our executive officer;
· the director has received, or has an immediate family member who has received, during any twelve-month period within the last three years, more than $100,000 in direct compensation from us, other than director and committee fees and pension or other forms of deferred compensation for prior service (provided such compensation is not contingent in any way on continued service);
· (i) the director or an immediate family member is a current partner of a firm that is our internal or external auditor; (ii) the director is a current employee of such a firm; (iii) the director has an immediate family member who is a current employee of such a firm and who participates in the firm’s audit, assurance or tax compliance (but not tax planning) practice; or (iv) the director or an immediate family member was within the last three years (but is no longer) a partner or employee of such a firm and personally worked on our audit within that time;
· the director or an immediate family member is, or has been within the last three years, employed as an executive officer of another company where any of our present executive officers at the same time serve or served on that company’s compensation committee;
· the director is a current employee, or an immediate family member is a current executive officer, of a company that has made payments to, or received payments from, us for property or services in an
amount which, in any of the last three fiscal years, exceeds the greater of $1 million, or 2% of such other company’s consolidated gross revenues; or
· the director serves as an executive officer of a charitable organization and, during any of the past three fiscal years, we made charitable contributions to the charitable organization in any single fiscal year that exceeded $1 million or two percent, whichever is greater, of the charitable organization’s consolidated gross revenues.
For the purposes of these categorical standards, the term “immediate family member” includes a person’s spouse, parents, children, siblings, mothers and fathers-in-law, sons and daughters-in-law, brothers and sisters-in-law, and anyone (other than domestic employees) who shares such person’s home.
Meetings of Non-Management Directors
Our non-management directors meet in executive session at least two times per year outside of the presence of any management directors and any other members of our management who may otherwise be present. During at least one session per year, only independent directors are present. The directors present at each executive session select a presiding director for that session.
Director Attendance of Meetings
Our general partner’s board of directors held seven meetings in fiscal year 2006. Each director attended more than 75 percent of the aggregate of the total number of meetings of the board and the total number of meetings of the committees on which he served during the portions of the year that such person was a director.
Item 14.
Item 14. Principal Accountant Fees and Services
The following table summarizes the aggregate fees billed to the Partnership by Deloitte & Touche, LLP, the member firm of Deloitte Touche Tohmatsu, and their respective affiliates (collectively, the “Deloitte Entities”).
(1) Audit fees include fees for the audit of the Partnership’s consolidated financial statements as well as the audit of the internal control over financial reporting, reviews of the Partnership’s quarterly consolidated financial statements and comfort letters, consents and other services related to Securities and Exchange Commission (“SEC”) matters.
(2) Audit-related fees consist principally of fees for audits of financial statements of certain employee benefits plans.
(3) Tax fees consist of fees for tax consultation and tax compliance services.
Procedures for Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Auditor
As outlined in its charter, the Audit Committee of the board of directors is responsible for reviewing and approving, in advance, any audit and any permissible non-audit engagement or relationship between us and our independent auditors. The Deloitte Entities’ engagement to conduct our audit was pre-approved by the Audit Committee. Additionally, all permissible non-audit services by the Deloitte Entities have been reviewed and pre-approved by the Audit Committee, as outlined in the pre-approval policies and procedures established by the Audit Committee.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(a) The following documents are filed as a part of this Report:
(1) Financial Statements-see Index to Financial Statements appearing on page xx.
(2) Exhibits, including those incorporated by reference. The following is a list of exhibits filed as part of this Annual Report on Form 10-K. Where so indicated by footnote, exhibits which were previously filed are incorporated by reference. For exhibits incorporated by reference, the location of the exhibit in the previous filing is indicated in parentheses.
Exhibit Number (Referenced to Item 601 of Regulation S-K)
* Represents management contract or compensatory plan or arrangement.
(1) The Amended and Restated Agreements of Limited Partnership of the other Operating Partnerships are not filed because they are substantially identical to Exhibit 10.1 except for the identity of the partnership.
(2) The Management Agreements of the other Operating Partnerships are not filed because they are substantially identical to Exhibit 10.2 except for the identity of the partnership.
SIGNATURES
Pursuant to the requirements of Section 13 of 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.
BUCKEYE PARTNERS, L.P.
(Registrant)
By:
Buckeye GP LLC,
as General Partner
Dated: February 26,
By:
/s/ WILLIAM H. SHEA, JR.
William H. Shea, Jr.
(Principal Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Dated: February 26,
By:
/s/ BRIAN F. BILLINGS
Brian F. Billings
Director
Dated: February 26, 2007
By:
/s/ MICHAEL B. HOFFMAN
Michael B. Hoffman
Director
Dated: February 26, 2007
By:
/s/ EDWARD F. KOSNIK
Edward F. Kosnik
Director
Dated: February 26, 2007
By:
/s/ JOSEPH A. LASALA, JR.
Joseph A. LaSala, Jr.
Director
Dated: February 26, 2007
By:
/s/ E. BARTOW JONES
E. Bartow Jones
Director
Dated: February 26, 2007
By:
/s/ JONATHAN O’HERRON
Jonathan O’Herron
Director
Dated: February 26, 2007
By:
/s/ WILLIAM H. SHEA, JR.
William H. Shea, Jr.
Director
Dated: February 26, 2007
By:
/s/ ROBERT B. WALLACE
Robert B. Wallace
(Principal Financial Officer and
Principal Accounting Officer)
Dated: February 26, 2007
By:
/s/ ANDREW W. WARD
Andrew W. Ward
Director