Item 1.
Business
Introduction
Buckeye Partners, L.P. (the “Partnership”), is a master limited partnership 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 for major integrated oil companies, large refined 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.
The Partnership conducts all 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”) and Buckeye Pipe Line Holdings, L.P. (“BPH”). Each of Buckeye, Laurel, Everglades and BPH is referred to individually as an “Operating Partnership” and collectively as the “Operating Partnerships”. The Partnership owns approximately a 99 percent interest in each of the Operating Partnerships. BPH owns directly, or indirectly, a 100 percent interest in each of Buckeye Terminals, LLC (“BT”), Norco Pipe Line Company, LLC (“Norco”) and Buckeye Gulf Coast Pipe Lines, L.P. (“BGC”). BPH also owns a 75 percent interest in WesPac Pipelines - Reno LLC, WesPac Pipelines - San Diego LLC, WesPac Pipelines - Memphis LLC and related WesPac entities (collectively known as “WesPac”), an approximate 25 percent interest in West Shore Pipe Line Company and a 20 percent interest in West Texas LPG Pipeline Limited Partnership. Subsidiaries of BGC also own approximately 63 percent of a crude butadiene pipeline between Deer Park, Texas and Port Arthur, Texas that was completed in March 2003 (the “Sabina Pipeline”).
Buckeye Pipe Line Company (the “General Partner”) serves as the general partner to the Partnership. As of December 31, 2003, the General Partner owned approximately a 1 percent general partnership interest in the Partnership and approximately a 1 percent general partnership interest in each Operating Partnership, for an approximate 2 percent interest in the Partnership. The General Partner is a wholly-owned subsidiary of Buckeye Management Company (“BMC”). BMC is a wholly-owned subsidiary of Glenmoor, Ltd. (“Glenmoor”). Glenmoor is owned by certain directors and members of senior management of the General Partner and trusts for the benefit of their families and by certain other management employees of Buckeye Pipe Line Services Company (“Services Company”).
On March 5, 2004, the stockholders of Glenmoor entered into a definitive agreement to sell Glenmoor to a new entity formed by Carlyle/ Riverstone Global Energy and Power Fund II, L.P. The transaction is scheduled to close in the second quarter of 2004, and is subject to certain conditions, including applicable regulatory approvals and other customary closing conditions. The parties did not disclose the financial terms of the transaction.
Services Company employs approximately 81 percent of the employees that work for the Operating Partnerships. At December 31, 2003, Services Company had 504 employees. Pursuant to a Services Agreement dated August 12, 1997, BMC and the General Partner reimburse Services Company for its direct and indirect expenses. These expenses are reimbursed to the General Partner by the Operating Partnerships except for certain executive compensation costs and related benefits expenses. BT, Norco and BGC directly employed 116 full-time employees at December 31, 2003.
Buckeye is one of the largest independent pipeline common carriers of refined petroleum products in the United States, with 2,909 miles of pipeline serving 9 states. Laurel owns a 345-mile common carrier refined products pipeline located principally in Pennsylvania. Norco owns a 482-mile pipeline in Indiana, Illinois and Ohio. Everglades owns 37 miles of refined petroleum products pipeline in Florida. Buckeye, Laurel, Norco and Everglades conduct the Partnership’s refined products pipeline business. BPH, through facilities it owns in Taylor, Michigan, provides bulk storage service with an aggregate capacity of 260,000 barrels of refined petroleum products. BT, with facilities located in New York, Pennsylvania, Ohio, Indiana and Illinois provides
bulk storage services with an aggregate capacity of 4,848,000 barrels of refined petroleum products. BGC owns and operates petrochemical pipelines in the Gulf Coast area. BGC also provides engineering and construction management services to major chemical companies in the Gulf Coast area. WesPac provides turbine fuel transportation services to the Reno/ Tahoe International Airport through a 3.0-mile pipeline and to the San Diego International Airport through a 4.3-mile pipeline.
On July 31, 2001, the Partnership acquired a refined products pipeline system and related terminals from affiliates of TransMontaigne Inc. for approximately $62.3 million. The assets included a 482-mile refined petroleum products pipeline that runs from Hartsdale, Indiana west to Fort Madison, Iowa and east to Toledo, Ohio, with an 11-mile pipeline connection between major storage terminals in Hartsdale and East Chicago, Indiana. These assets are operated by the Partnership under the name of Norco Pipe Line Company, LLC. The acquired assets also included 3.2 million barrels of pipeline storage and trans-shipment facilities in Hartsdale and East Chicago, Indiana and Toledo, Ohio; and four petroleum products terminals located in Bryan, Ohio; South Bend and Indianapolis, Indiana; and Peoria, Illinois. The storage and terminal assets are operated by Buckeye Terminals, LLC.
On October 29, 2001, the Partnership acquired 6,805 shares of common stock of West Shore Pipe Line Company (“West Shore”) for approximately $23.3 million. On September 30, 2003, the Partnership acquired an additional 2,304 shares of West Shore for approximately $7.5 million. At December 31, 2003, the Partnership owned approximately 25% of the outstanding common stock of West Shore. West Shore owns and operates 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 users in northern Illinois and Wisconsin. The other stockholders of West Shore are major oil companies. The pipeline is operated under contract by Citgo Pipeline Company. The investment in West Shore is accounted for using the equity basis of accounting.
On August 8, 2003, the Partnership acquired a 20% interest in West Texas LPG Pipeline Limited Partnership (“WTP”) for $28.5 million. WTP owns and operates 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 area via connecting pipelines and from gathering fields located in West and Central Texas. The majority owner and the operator of WTP are affiliates of Chevron Texaco, Inc. The investment in WTP is accounted for using the equity basis of accounting.
Refined Products Transportation
The Partnership receives petroleum products from refineries, connecting pipelines and bulk and marine terminals, and transports those products to other locations. In 2003, refined petroleum products transportation accounted for approximately 83.8% of the Partnership’s consolidated revenues.
The Partnership transported an average of approximately 1,136,400 barrels per day of refined products in 2003. The following table shows the volume and percentage of refined petroleum products transported over the last three years.
Volume and Percentage of Refined 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 refined product pipeline service in the following states: Pennsylvania, New York, New Jersey, Indiana, Ohio, Michigan, Illinois, Connecticut, Massachusetts, Nevada, California and Florida.
Pennsylvania - New York - New Jersey
Buckeye serves major population centers in the states of Pennsylvania, New York and New Jersey through 943 miles of pipeline. Refined petroleum products are received at Linden, New Jersey from approximately 17 major source points, including 2 refineries, 6 connecting pipelines and 9 storage and terminalling facilities. Products are then transported through two lines from Linden, New Jersey to Allentown, Pennsylvania. From Allentown, the pipeline continues west, through a connection with Laurel, to Pittsburgh, Pennsylvania (serving Reading, Harrisburg, Altoona/ Johnstown and Pittsburgh) and north through eastern Pennsylvania into New York (serving Scranton/ Wilkes-Barre, Binghamton, Syracuse, Utica and Rochester and, via a connecting carrier, Buffalo). 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 J.F. Kennedy International and LaGuardia airports and to commercial bulk terminals at Long Island City and Inwood, New York. These pipelines supply J.F. Kennedy, LaGuardia and Newark airports with substantially all of each airport’s jet fuel requirements.
Laurel transports refined petroleum products through a 345-mile pipeline extending westward from five refineries and a connection to Colonial Pipeline Company in the Philadelphia area to Reading, Harrisburg, Altoona/ Johnstown and Pittsburgh, Pennsylvania.
Indiana - Ohio - Michigan - Illinois
Buckeye and Norco transport refined petroleum products through 2,336 miles of pipeline (of which 246 miles are jointly owned with other pipeline companies) in southern Illinois, central Indiana, eastern Michigan, western and northern Ohio and western Pennsylvania. A number of receiving and delivery lines connect to a central corridor which runs from Lima, Ohio, through Toledo, Ohio to Detroit, Michigan. Products are received at East Chicago, Indiana; Robinson, Illinois and at refinery and other pipeline connection points near Detroit, Toledo and Lima. 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.
Other Refined Products Pipelines
Buckeye serves Connecticut and Massachusetts through 112 miles of pipeline (the “Jet Lines System”) that carry refined products from New Haven, Connecticut to Hartford, Connecticut and Springfield, Massachusetts.
Everglades transports primarily turbine fuel on a 37-mile pipeline from Port Everglades, Florida to Hollywood-Ft. Lauderdale International Airport and Miami International Airport. Everglades supplies Miami International Airport with substantially all of its turbine fuel requirements.
WesPac Pipeline Reno LLC owns a 3.0-mile pipeline serving the Reno/ Tahoe International Airport. WesPac Pipeline - San Diego LLC owns a 4.3-mile pipeline serving the San Diego International Airport. Both of these pipelines transport turbine fuel. Each of these WesPac entities is a joint venture between BPH and Kealine Partners in which BPH owns a 75 percent interest. As of December 31, 2003, the Partnership has provided approximately $8.7 million in debt financing to WesPac entities.
Other Business Activities
BPH provides bulk storage services through facilities located in Taylor, Michigan that have the capacity to store an aggregate of approximately 260,000 barrels of refined petroleum products. BT, a wholly-owned subsidiary of BPH, operates 15 terminals located in New York, Pennsylvania, Ohio, Indiana and Illinois that provide bulk storage and throughput services and have the capacity to store an aggregate of approximately 4,848,000 barrels of refined petroleum products. Together, these terminalling and storage activities provided approximately 9.7% of the Partnership’s revenue in 2003. BPH also owns a 25 percent stock interest in West Shore and a 20% interest in WTP.
BGC, a wholly-owned subsidiary of BPH, is a contract operator of pipelines owned by major chemical companies in the state of Texas. BGC currently has seven operations and maintenance contracts in place. In addition, BGC owns a 16-mile pipeline located in the state of Texas that it leases to a third-party chemical company. Subsidiaries of BGC also own approximately 63 percent of the Sabina Pipeline. In 2003, BGC’s contract operations provided approximately 6.5% of the Partnership’s revenue. BGC also provides engineering and construction management services to major chemical companies in the Gulf Coast area.
Competition and Other Business Considerations
The Operating Partnerships conduct business without the benefit of exclusive franchises from government entities. In addition, the Operating Partnerships pipeline operations generally operate as common carriers, providing transportation services at posted tariffs and without long-term contracts. The Operating Partnerships do not own the products they transport. Demand for the services provided by the Operating Partnerships derives from demand for petroleum products in the regions served and the ability and willingness of refiners, marketers and end-users to supply such demand by deliveries through the Operating Partnerships’ pipelines. Demand for refined petroleum products is primarily a function of price, prevailing general economic conditions and weather. The Operating Partnerships’ 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 Partnership’s business may in the future be affected by changing oil prices or other factors affecting demand for oil and other fuels. The Partnership’s business may also be impacted by energy conservation, changing sources of supply, structural changes in the oil industry and new energy technologies. The General Partner is unable to predict the effect of such factors.
Changes in transportation and travel patterns in the areas served by the Partnership’s pipelines as well as further improvements in average fuel efficiency could adversely affect the Partnership’s results of operations and financial condition.
In 2003, the pipeline transportation business had approximately 90 customers, most of which were either major integrated oil companies or large refined product marketing companies. The largest two customers accounted for 9.4 percent and 6.7 percent, respectively, of consolidated transportation revenues, while the 20 largest customers accounted for 66.6 percent of consolidated transportation revenues.
Generally, pipelines are the lowest cost method for long-haul overland movement of refined petroleum products. Therefore, the Operating Partnerships’ most significant competitors for large volume shipments are other pipelines, many of which are owned and operated by major integrated oil companies. Although it is unlikely that a pipeline system comparable in size and scope to the Operating Partnerships’ 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 Partnerships in particular locations. In the Midwest, several petroleum product pipeline expansions and two new petroleum product pipeline construction projects have recently been completed. Generally, these projects have increased the capacity to bring additional refined products into the Partnership’s service area. However, because the Operating Partnerships own multiple pipelines throughout the Partnership’s service area and these projects do not impact local petroleum product supply and demand, the General Partner believes that the these pipeline projects may result in volumes shifting from one Operating Partnership pipeline segment to another, but will not, in the aggregate, have a material adverse effect on the Operating Partnership’s results of operations or financial condition.
The Operating Partnerships 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 Ohio.
Trucks competitively deliver product in a number of areas served by the Operating Partnerships. 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 served by the Operating Partnerships. The availability of truck transportation places a significant competitive constraint on the ability of the Operating Partnerships to increase their tariff rates.
Privately arranged exchanges of product 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 Partnerships’ pipelines have numerous source points, the General Partner does not believe that the expansion or shutdown of any particular refinery would have a material effect on the business of the Partnership. The General Partner is unable to determine whether refinery expansions or shutdowns will occur or what their specific effect would be. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Forward-Looking Information - Competition and Other Business Conditions.”
The Operating Partnerships’ 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 volume being transported during March, April and May and somewhat higher than average volume being transported in November, December and January.
Neither the Partnership nor any of the Operating Partnerships, other than BPH’s subsidiaries, has any employees. The Operating Partnerships are managed and operated by employees of Services Company, BGC, Norco and BT. In addition, Glenmoor provides certain management services to BMC, the General Partner and Services Company. At December 31, 2003, Services Company had a total of 504 full-time employees, 145
of whom were represented by two labor unions. At December 31, 2003, BGC had a total of 64 full-time, non-union employees, Norco had a total of 29 full-time, non-union employees and BT had a total of 23 full-time, non-union employees. The Operating Partnerships (and their predecessors) have never experienced any work stoppages or other significant labor problems.
Capital Expenditures
The Partnership incurs capital expenditures in order to maintain and enhance the safety and integrity of its pipelines and related assets, to expand the reach or capacity of its pipelines, to improve the efficiency of its operations or to pursue new business opportunities. During 2003 the Partnership incurred approximately $42.2 million of capital expenditures, of which $28.4 million related to maintenance and integrity, $11.4 million related to expansion or cost reduction projects and $2.4 million related to the completion of the Sabina Pipeline.
In 2004, the Partnership anticipates capital expenditures of approximately $80 million, of which approximately $30 million is projected for maintenance and integrity projects and approximately $50 million is projected for expansion and cost reduction projects. See “Pipeline Regulation and Safety Matters” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources.”
Regulation
General
Buckeye and Norco are interstate common carriers 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 regulation requires that interstate oil pipeline rates be posted publicly and that these rates be “just and reasonable” and non-discriminatory. FERC regulation also enforces common carrier obligations and specifies a uniform system of accounts. In addition, Buckeye, Norco and the other Operating Partnerships are subject to the jurisdiction of certain other federal agencies with respect to environmental and pipeline safety matters.
The Operating Partnerships 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.
FERC Rate Regulation
Buckeye’s rates are governed by a market-based rate regulation program initially approved by FERC in March 1991 and subsequently extended. 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 percent 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 percent. 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 is an exception to the generic oil pipeline regulations issued under the Energy Policy Act of 1992. The generic rules rely primarily on an index methodology, whereby a pipeline is allowed to change its rates in accordance with an index (currently the Producer Price Index) that FERC believes reflects cost changes appropriate for application to pipeline rates. Alternatively, 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. In addition, the rules provide for the rights of both pipelines and shippers to demonstrate that the index should not apply to an individual pipeline’s rates in light of the pipeline’s costs. The final rules became effective on January 1, 1995.
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.
Norco’s tariff rates are governed by the generic FERC index methodology, and therefore are subject to change annually according to the index.
Environmental Matters
The Operating Partnerships 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 Partnerships 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 thereunder, and claims for damages to property or injuries to persons resulting from the operations of the Operating Partnerships, 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 any discharges 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. Regulations are currently being developed under OPA and state laws that may impose additional regulatory burdens on the Partnership.
Contamination resulting from spills or releases of refined petroleum products is not unusual in the petroleum pipeline industry. The Operating Partnerships’ pipelines cross numerous navigable rivers and streams. Although the General Partner believes that the Operating Partnerships 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” which are subject to rigorous disposal requirements.
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 Partnerships or their predecessors may have been released or disposed of in the past, the Operating Partnerships may in the future be required to remedy contaminated property. Governmental authorities such as the Environmental Protection Agency, 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 Partnerships may be adjacent to or in the immediate vicinity of Superfund and other hazardous waste sites. Accordingly, the Operating Partnerships 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 Partnerships 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 upon the Operating Partnerships through this permit review process.
The Operating Partnerships 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.
In 1986, certain predecessor companies acquired by the Partnership, namely Buckeye Pipe Line Company and its subsidiaries (“Pipe Line”), entered into an Administrative Consent Order (“ACO”) with the New Jersey Department of Environmental Protection and Energy under the New Jersey Environmental Cleanup Responsibility Act of 1983 (“ECRA”) relating to all six of Pipe Line’s facilities in New Jersey. The ACO permitted the 1986 acquisition of Pipe Line to be completed prior to full compliance with ECRA, but required Pipe Line to conduct in a timely manner a sampling plan for environmental conditions at the New Jersey facilities and to implement any required clean-up plan. Sampling continues in an effort to identify areas of contamination at the New Jersey facilities, while clean-up operations have begun and have been completed at certain of the sites. The obligations of Pipe Line were not assumed by the Partnership and the costs of compliance have been and will continue to be paid by American Financial Group, Inc.
Pipeline Regulation and Safety Matters
The Operating Partnerships are subject to regulation by the United States Department of Transportation (“DOT”) under the Hazardous Liquid Pipeline Safety Act of 1979 (“HLPSA”), and its subsequent re-authorizations relating to 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 General Partner 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 General Partner has filed its written plan and has qualified its employees and contractors as required. In addition, 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 percent of line segments by September 30, 2004, with full assessment of the remaining 50 percent by March 31, 2008. Pipeline operators will thereafter be required to re-assess each affected segment in intervals not to exceed five years. The General Partner 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 General Partner has commenced implementation of a public education program that complies with these requirements. While the PSIA imposes additional operating requirements on pipeline operators, the General Partner does not believe that cost of compliance with the PSIA is likely to be material in the context of the Partnership’s operations.
The General Partner believes that the Operating Partnerships currently comply in all material respects with HLPSA and other pipeline safety laws and regulations. However, the industry, including the Partnership, will, in the future, incur additional pipeline and tank integrity expenditures and the Partnership is likely to incur increased operating costs based on these and other government regulations. During 2003, the Partnership’s integrity expenditures were approximately $19 million. The General Partner expects integrity expenditures to continue at approximately this level during 2004 in order to complete the balance of its initial pipeline assessment and pipeline improvements required by HLPSA. Once this initial assessment is complete, re-assessments are expected to cost significantly less and a greater portion of the expenditures are expected to be expensed. The General Partner believes these additional capital and operating expenditures with respect to HLSPA requirements will be offset, to some degree, by a reduced need for other facility improvements and lower operating expenses associated with improved pipeline facilities.
The Operating Partnerships are also subject to the requirements of the Federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The General Partner believes that the Operating Partnerships’ 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 General Partner 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 on the Partnership, but the General Partner does not presently expect that such costs or capital expenditure requirements would have a material adverse effect on the Partnership’s results of operations or financial condition.
Tax Treatment of Publicly Traded Partnerships under the Internal Revenue Code
The Internal Revenue Code of 1986, as amended (the “Code”), imposes certain limitations on the current deductibility of losses attributable to investments in publicly traded partnerships and treats certain publicly traded partnerships as corporations for federal income tax purposes. The following discussion briefly describes certain aspects of the Code that apply to individuals who are citizens or residents of the United States without commenting on all of the federal income tax matters affecting the Partnership or the holders of LP units (“Unitholders”), and is qualified in its entirety by reference to the Code. UNITHOLDERS ARE URGED TO CONSULT THEIR OWN TAX ADVISOR ABOUT THE FEDERAL, STATE, LOCAL AND FOREIGN TAX CONSEQUENCES TO THEM OF AN INVESTMENT IN THE PARTNERSHIP.
Characterization of the Partnership for Tax Purposes
The Code treats a publicly traded partnership that existed on December 17, 1987, such as the Partnership, as a corporation for federal income tax purposes, unless, for each taxable year of the Partnership, under Section 7704(d) of the Code, 90 percent or more of its gross income consists of “qualifying income.” Qualifying income includes interest, dividends, real property rents, gains from the sale or disposition of real property, 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. Because the Partnership is engaged primarily in the refined products pipeline transportation business, the General Partner believes that 90 percent or more of the Partnership’s gross income has been qualifying income. If this continues to be true and no subsequent legislation amends that provision, the Partnership will continue to be classified as a partnership and not as a corporation for federal income tax purposes.
Passive Activity Loss Rules
The Code provides that an individual, estate, trust or personal service corporation generally may not deduct losses from passive business activities, to the extent they exceed income from all such passive activities, against other (active) income. Income that may not be offset by passive activity losses includes not only salary and active business income, but also portfolio income such as interest, dividends or royalties or gain from the sale of property that produces portfolio income. Credits from passive activities are also limited to the tax attributable to any income from passive activities. The passive activity loss rules are applied after other applicable limitations on deductions, such as the at-risk rules and basis limitations. Certain closely held corporations are subject to slightly different rules that can also limit their ability to offset passive losses against certain types of income.
Under the Code, net income from publicly traded partnerships is not treated as passive income for purposes of the passive loss rule, but is treated as non-passive income. Net losses and credits attributable to an interest in a publicly traded partnership are not allowed to offset a partner’s other income. Thus, a Unitholder’s proportionate share of the Partnership’s net losses may be used to offset only Partnership net income from its trade or business in succeeding taxable years or, upon a complete disposition of a Unitholder’s interest in the Partnership to an unrelated person in a fully taxable transaction, may be used to (i) offset gain recognized upon the disposition, and (ii) then against all other income of the Unitholder. In effect, net losses are suspended and carried forward indefinitely until utilized to offset net income of the Partnership from its trade or business or allowed upon the complete disposition to an unrelated person in a fully taxable transaction of the Unitholder’s interest in the Partnership. A Unitholder’s share of Partnership net income may not be offset by passive activity losses generated by other passive activities. In addition, a Unitholder’s proportionate share of the Partnership’s portfolio income, including portfolio income arising from the investment of the Partnership’s working capital, is not treated as income from a passive activity and may not be offset by such Unitholder’s share of net losses of the Partnership.
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) reduced by certain expenses (other than interest) which are directly connected with the production of such income. Property subject to the passive loss rules is not 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. A Unitholder’s investment income attributable to its interest in the Partnership will include both its allocable share of the Partnership’s portfolio income and trade or business income. A Unitholder’s investment interest expense will include its allocable share of the Partnership’s interest expense attributable to portfolio investments.
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, INVESTMENT IN THE PARTNERSHIP BY TAX-EXEMPT ENTITIES SUCH AS INDIVIDUAL RETIREMENT ACCOUNTS, PENSION PLANS AND CHARITABLE TRUSTS MAY NOT BE ADVISABLE.
State Tax Treatment
During 2003, the Partnership owned property or conducted business in the states of Pennsylvania, New York, New Jersey, Indiana, Ohio, Louisiana, Michigan, Illinois, Connecticut, Massachusetts, Florida, Texas, Nevada and California. 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.
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 individual LP Unit depreciation under their IRC section 754 election. Each Unitholder’s tax situation will differ depending upon the price paid and when LP Units were purchased. Unitholders are reminded that, in spite of the additional taxable income beginning in 1999, the current level of 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 INVESTMENT IN LP UNITS.
Available Information
The Partnership files annual, quarterly, and current reports and other documents with the SEC under the Securities Exchange Act of 1934. The public can obtain any documents that we file with the SEC at http://www.sec.gov. We also make available free of charge our 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 our Internet website, www.buckeye.com. We are not including the information contained on our website as a part of, or incorporating it by reference into, this Annual Report on Form 10-K.
Item 2.
Item 2.
Properties
As of December 31, 2003, the principal facilities of the Partnership included approximately 3,800 miles of 6-inch to 24-inch diameter pipeline, 49 pumping stations, 90 delivery points, various sized tanks having an aggregate capacity of approximately 14.7 million barrels and 15 bulk storage and terminal facilities. The Operating Partnerships and their subsidiaries own substantially all of these facilities.
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 Partnerships’ and their 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 Partnerships and their 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 Partnerships or their subsidiaries.
The General Partner believes that the Operating Partnerships and their 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 Partnerships’ and their 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 Partnerships’ or their 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. Although it is possible that one or more of these claims or proceedings, if adversely determined, could, depending on the relative amounts involved, have a material effect on the Partnership for a future period, the General Partner does not believe that their outcome will have a material effect on the Partnership’s consolidated financial condition or results of operations.
With respect to environmental litigation, certain Operating Partnerships (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 Partnership is usually one of many PRPs for a particular site and its contribution of total waste at the site is usually de minimis. However, because CERCLA and similar statutes impose liability without regard to fault and on a joint and several basis, the liability of an Operating Partnership in connection with such a proceeding could be material.
Although there is no material environmental litigation pending against the Partnership or the Operating Partnerships 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.”
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, 2003.
PART II
Item 5.
Item 5.
Market for the Registrant’s LP Units and Related Unitholder Matters
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 2003 and 2002, as reported in the New York Stock Exchange Composite Transactions, were as follows:
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 27,000 at December 31, 2003.
On February 28, 2003, the Partnership sold 1,750,000 LP units in an underwritten public offering at a price of $36.01 per LP unit. Proceeds to the Partnership, net of underwriters’ discount of $1.62 per LP unit and offering expenses, were approximately $59.9 million.
Cash distributions paid during 2002 and 2003 were as follows:
In general, the Partnership makes quarterly cash distributions of substantially all of its available cash less such retentions for working capital, anticipated expenditures and contingencies as the General Partner deems appropriate.
On January 28, 2004, the Partnership announced a quarterly distribution of $0.65 per LP Unit payable on February 27, 2004, to Unitholders of record on February 4, 2004. The distribution was paid on February 27, 2004.
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)
Depreciation and amortization includes $832,000 and $461,000 in 2001 and 2000 related to goodwill acquired in the 2000 acquisition of six petroleum products terminals. Goodwill amortization ceased effective January 1, 2002 with the adoption of Statement of Financial Accounting Standards. No. 142 - “Goodwill and Other Intangible Assets.” See Note 6 to the Partnership’s consolidated financial statements.
(2)
Operating income for 1999 includes a one-time property tax expense reduction of $11.0 million following the settlement of a real property tax dispute with the City and State of New York.
(3)
Income from continuing operations and net income in 2003 include a special charge of $45.5 million related to a yield maintenance premium paid on the retirement of the $240 million Senior Notes of Buckeye Pipe Line Company L.P.
(4)
Net income includes income from discontinued operations of $5,682,000 in 2000 and $5,182,000 in 1999 and, in 2000, the gain on the sale of Buckeye Refining Company, a former subsidiary of BPH, of $26,182,000.
Item 7.
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following is a discussion of the results of operations and the liquidity and capital resources of the Partnership for the periods indicated below. This discussion should be read in conjunction with the Partnership’s consolidated financial statements and notes thereto, which are included elsewhere in this report.
Overview
During 2003, the Partnership executed a financing strategy to lower its overall cost of capital and expand the Partnership’s ability to grow through acquisitions and capital projects. This strategy involved raising both equity and debt capital to refinance certain debt obligations and to provide additional financial flexibility to pursue these projects. These transactions included the following:
•
On February 28, 2003, the Partnership issued 1,750,000 LP units in an underwritten public offering at $36.01 per LP unit. Net proceeds from the Partnership, after underwriters’ discount of $1.62 per LP unit and offering costs, were approximately $59.9 million.
•
On July 7, 2003, the Partnership sold $300 million aggregate principal amount of 4 5/8% Notes due 2013 (the “4 5/8% Notes”) in an underwritten public offering. Proceeds from the note offering after underwriters’ fees and expenses were approximately $296.4 million.
•
On August 14, 2003, the Partnership sold $150 million aggregate principal amount of 6 3/4% Notes due 2033 (the “6 3/4% Notes”) in a Rule 144A offering. Proceeds from the 6 3/4% Notes after fees and expenses were approximately $148.1 million. The Notes were subsequently exchanged for equivalent notes which are publicly traded.
•
On September 4, 2003, the Partnership entered into a new 364-day Revolving Credit Agreement for $100 million with a syndicate of banks led by SunTrust Bank. This agreement replaces the Partnership’s $85 million 364-day agreement which was scheduled to expire in September 2003. The 364-day facility, together with the Partnership’s existing $277.5 million Revolving Credit Agreement, which expires in September 2006 (collectively, the “Credit Facilities”) provide for up to $377.5 million of credit available to the Partnership.
•
On October 28, 2003, the Partnership entered into an interest rate swap agreement with a financial institution with respect to $100 million principal amount (the “notional amount”) of the 4 5/8% Notes. The contract calls for the Partnership to receive fixed payments from the financial institution at a rate of 4 5/8% of the notional amount in exchange for floating rate payments from the Partnership based on the notional amount using a rate equal to the six-month London Interbank Offered Rate (LIBOR), determined in arrears, minus 0.28%. The Partnership entered into the agreement in order to hedge its fair value risk associated with a portion of the 4 5/8% Notes. The agreement terminates on the maturity date of the 4 5/8% Notes and interest amounts under the agreement are payable semiannually on the same date as the interest payments on the 4 5/8% Notes. At the inception of the agreement, the Partnership designated the agreement as a fair value hedge and determined that no ineffectiveness will result from the use of the hedge. During the two months of 2003 that the hedge was outstanding, the Partnership saved $0.6 million and, based on LIBOR at December 31, 2003, the Partnership would save approximately $3.8 million per year compared to interest expense the Partnership would have incurred had the Partnership not engaged into this transaction. Changes in LIBOR, however, will impact the interest rate expense incurred in connection with the interest rate swap. For example, a 1% increase or decrease in LIBOR would increase or decrease interest expense by $1 million per year.
The proceeds of these transactions were used, in part, to repay all amounts outstanding under the Credit Facilities (which were $165.0 million at December 31, 2002), repay the $240 million Buckeye Pipe Line Company, L.P. Senior Notes, which were scheduled to mature in 2024, and to fund the Partnership’s investments in WTP and West Shore. In connection with the repayment of the $240 million Senior Notes, Buckeye Pipe Line Company, L.P. was required to pay a yield maintenance premium of $45.5 million to the holders of the Senior Notes. The yield maintenance premium has been charged to expense in the Partnership’s consolidated financial statements.
These transactions improved the Partnership’s financial structure by (1) reducing the Partnership’s average cost of debt, (2) removing certain restrictive covenants contained in the $240 million Senior Notes of Buckeye Pipe Line Company, L.P., (3) improving the Partnership’s credit rating by removing debt outstanding at the operating partnership level and (4) providing capacity under the Credit Facilities to facilitate potential future acquisitions or capital projects.
In 2003, the Partnership invested $36.0 million to acquire a 20 percent interest in West Texas LPG Pipe Line, L.P. and an additional 2,304 shares (or an additional 7 percent ownership interest) of West Shore Pipe Line Company. At December 31, 2003, the Partnership owns approximately 25 percent of the shares of West Shore.
Including the $45.5 million charge related to the payment of the yield maintenance premium associated with the $240 million Senior Notes, the Partnership had net income of $30.2 million or $1.05 per unit, for the year ended December 31, 2003. The Partnership’s net income before the yield maintenance premium was $75.6 million, or $2.64 per unit, compared to net income of $71.9 million, or $2.65 per unit, in 2002 and $69.4 million, or $2.56 per unit in 2001.
To supplement its financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”), the Partnership has presented in this discussion the measure of “net income before the yield maintenance premium” to enhance the user’s overall understanding of the Partnership’s current financial performance. Specifically, the Partnership believes that the presentation of net income before the yield maintenance premium provides useful information to both management and investors by allowing a meaningful comparison of the Partnership’s current operating results (which were impacted by the payment of the $45.5 million yield maintenance premium) and the operating results of prior periods (which were not impacted by the yield maintenance premium). The presentation of this additional information is not meant to be considered in isolation or as a substitute for results prepared in accordance with accounting principles generally accepted in the United States.
Through its Operating Partnerships and their subsidiaries, the Partnership is principally engaged in the pipeline transportation of refined petroleum products. The Partnership’s revenues derived from the transportation of refined petroleum products are principally a function of the volumes of these products transported by the Partnership, which are in turn a function of the demand for refined petroleum products in the regions served by the Partnership’s pipelines, and the tariffs or transportation fees charged for such transportation.
The Partnership is also engaged, through BPH, BT and BGC, in the terminalling and storage of petroleum products and in contract operation of pipelines for third parties.
Results of Operations
Revenues for each of the three years in the period ended December 31, 2003 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 “Business - Competition and Other Business Considerations.”
2003 Compared With 2002
Total revenue for the year ended December 31, 2003 was $272.9 million, $25.6 million or 10.4 percent greater than revenue of $247.3 million in 2002. Revenue from pipeline transportation of petroleum products was $228.7 million in 2003 compared to $214.1 million in 2002. Volumes of petroleum products delivered during 2003 averaged 1,136,400 barrels per day, 35,000 barrels per day or 3.2 percent greater than volume of 1,101,400 barrels per day delivered in 2002.
Revenue from the transportation of gasoline of $122.3 million increased by $8.2 million, or 7.2 percent, from 2002 levels. Total gasoline volumes of 578,800 barrels per day in 2003 were 22,400 barrels per day, or 4.0 percent greater than 2002 volumes of 556,400 barrels per day. In the East, gasoline volumes of 256,900 barrels per day were approximately 11,200 barrels per day, or 4.6 percent, greater than 2002 volumes. The increase was primarily due to greater deliveries to the upstate New York and the Pittsburgh and Sinking Spring, Pennsylvania areas. In the Midwest, gasoline volumes of 173,800 barrels per day were 9,800 barrels per day, or 6.0 percent, greater than gasoline volumes delivered during 2002. Deliveries to the Cleveland, Ohio area increased by 7,500 barrels per day, or 21.3 percent. Deliveries to the Detroit, Michigan area and Toledo, Ohio also increased and were partially offset by declines in deliveries to the Bay City and Flint, Michigan areas. Long Island System gasoline volumes of 112,700 barrels per day were up 1,400 barrels per day, or 1.3 percent. Jet Lines System gasoline volumes of 16,200 barrels per day were 2,000 barrels per day, or 10.9 percent, less than 2002 volumes primarily due to the closure of a customer’s terminal in Hartford, Connecticut. Norco gasoline volumes of 19,200 barrels per day were 2,000 barrels per day, or 11.6 percent, greater than gasoline volumes delivered during 2002 on increased business at Toledo, Ohio and Peoria, Illinois.
Revenue from the transportation of distillate of $63.3 million increased by $5.6 million, or 9.7 percent, from 2002 levels. Total distillate volumes of 285,400 barrels per day in 2003 were 20,000 barrels per day, or 7.5 percent greater than 2002 distillate volumes of 265,400 barrels per day. In the East, distillate volumes of 157,100 barrels per day were approximately 12,100 barrels per day, or 8.3 percent, greater than 2002 volumes. Deliveries of distillate increased throughout the region and were particularly strong to the Pittsburgh, Pennsylvania area. In the Midwest, distillate volumes of 74,800 barrels per day were 6,700 barrels per day, or 9.8 percent, greater than volumes delivered during 2002 with the largest gains occurring in the Cleveland, Ohio market area. Long Island System distillate volumes of 19,800 barrels per day were 1,400 barrels per day or 7.6 percent greater than volumes delivered during 2002 as suppliers are showing an increased preference for pipeline transportation over competing barge transportation. On the Jet Lines system, distillate volumes of 23,300 barrels per day were 2,600 barrels per day, or 12.6 percent, greater than 2002 volumes primarily due to colder weather during the first quarter 2003 compared to the first quarter 2002. Norco distillate volumes of 10,300 barrels per day were 2,600 barrels per day, or 20.2 percent, less than distillate volumes delivered during 2002 as a result of decreased business to the Toledo, Ohio area.
Revenue from the transportation of jet fuel of $38.2 million increased by $1.3 million, or 3.5 percent, from 2002 levels. Total jet fuel volumes of 248,500 barrels per day in 2003 were 2,400 barrels per day, or 1.0 percent less than 2002 jet fuel volumes of 250,900 barrels per day. Revenues increased despite the volume decline due to tariff increases. In the East, jet fuel volume of 11,900 barrels per day were 1,200 barrels per day, or 9.2 percent, less than 2002 volumes primarily due to declines in deliveries to the Pittsburgh, Pennsylvania and Syracuse, New York. In the Midwest, jet fuel of 35,500 barrels per day were 2,000 barrels per day, or 6.0 percent, greater than volumes delivered during 2002 on stronger demand at Detroit Airport. Long Island System jet fuel volumes of 129,300 barrels per day were 1,500 barrels per day or 1.1 percent less than jet fuel volumes delivered during 2002. Deliveries to New York City airports declined by 1,300 barrels per day, or 1.0 percent.
Revenue from the transportation of liquefied petroleum gas (LPG) of $3.6 million decreased by $1.2 million, or 24.4 percent, from 2002 levels. Total LPG volumes of 19,100 barrels per day in 2003 were 2,800 barrels per day, or 12.8 percent less than 2002 LPG volumes of 21,900 barrels per day on decreased deliveries to Lima, Ohio.
Terminalling, storage and rental revenue of $26.4 million increased by $7.5 million from 2002 levels. Approximately $6.9 million of this increase reflects lease revenue received with respect to the Sabina Pipeline.
Contract operation services revenue of $17.8 million for 2003 increased by $3.4 million over contract operation services revenues for 2002. The increase in contract services revenues was due to increased operations services provided by BGC as a result of additional contracts obtained during 2002, as well as the commencement of the Sabina Pipeline operation and maintenance agreement effective January 1, 2003. Contract operations revenues typically consist of costs reimbursable under the contracts plus an operator’s fee. Accordingly, revenues from these operations carry a lower gross profit percentage than revenues from pipeline transportation or terminalling, storage and rentals.
Costs and expenses for the years ended December 31, 2003, 2002 and 2001 were as follows:
Payroll and payroll benefits increased to $54.7 million in 2003, or $5.1 million over 2002 amounts, principally due to increases in benefits costs ($2.3 million) related to the Partnership’s defined benefit pension plan, retiree medical plan and other medical costs. In addition, payroll costs increased at BGC ($1.0 million) due to additional staff associated with expanded contract operations. Payroll costs rose in pipeline, terminalling and administrative activities due to wage increases ($1.8 million).
Depreciation and amortization expense increased to $22.6 million, or $1.9 million due to commencement of depreciation on the Sabina Pipeline ($0.6 million), depreciation related to the Partnership’s new Enterprise Asset Management (EAM) information system implemented January 2003 ($0.5 million) and other capital additions to the Partnership’s pipeline and terminalling assets ($0.8 million).
Operating power, consisting primarily of electricity required to operate pumping facilities, increased to $21.9 million, $2.9 million over operating power costs incurred in 2002. Expanded contract operations at BGC caused $1.0 million of this increase. The remainder was due to additional pipeline volumes experienced by the Partnership’s pipeline operations.
Outside services costs, consisting principally of third-party contract services for maintenance activities, remained relatively stable in 2003 compared to 2002.
Property and other taxes in 2003 increased to $10.4 million or $1.9 million over 2002 amounts. The Partnership recorded a favorable settlement of $1.2 million related to certain state real property tax issues in 2002 which was not repeated in 2003. Additionally, state property and other taxes increased in 2003 by $0.7 million.
All other costs increased to $35.2 million, or $6.5 million in 2003 compared to 2002. Casualty losses increased by $2.0 million related to two environmental incidents which occurred in 2003 and a reimbursement of $0.5 million from a third party in 2002 which did not recur in 2003. Insurance costs increased by $1.4 million due to higher premiums charged by insurance carriers. Professional fees increased by $1.3 million related to accounting and legal costs associated with investment, acquisition and other activities. Communications costs increased by $0.5 million as the Partnership expanded its communications infrastructure in support of the new EAM system. The remainder of the cost increases of $1.3 million relate to a number of operating cost categories principally associated with the increased volume in 2003 compared to 2002.
Other income (expense) for the years ended December 31, 2003, 2002 and 2001 was as follows:
Other income (expense) increased to $79.2 million in 2003 compared to $30.5 million in 2002. As noted above, in 2003 the Partnership paid a yield maintenance premium of $45.5 million on the retirement of the $240 million Buckeye Pipe Line Company L.P. Senior Notes. Investment income of $3.6 million increased by $1.7 million over 2002 as a result of equity income from the Partnership’s 20% interest in West Texas LPG Pipe Line, L.P. (acquired August 8, 2003) and increased earnings from the Partnership’s interest in West Shore Pipe Line Company. In September 2003, the Partnership increased its interest in West Shore to approximately 25% from 18% previously.
Interest expense was $22.8 million in 2003, an increase of $2.2 million over 2002. The increase in interest expense resulted from a combination of the timing of the Partnership’s refinancing activities in 2003 ($1.9 million), reduced interest expense capitalized in 2003 ($1.6 million) and higher rates and balances on the Partnership’s new debt facilities, partially offset by a combination of lower interest rates on the Credit Facilities (for the period in 2003 that the Credit Facilities were outstanding), the repayment of $60 million of the Credit Facilities in February 2003 with the proceeds of the Partnership’s equity offering and the benefits of the interest rate swap transaction entered into in late October 2003.
Minority interest and other of $14.6 million in 2003 increased by $2.7 million over 2002 as a result of increased minority interest expense principally related to the minority interest share of income of the Sabina Pipeline ($2.1 million) (see “Liquidity and Capital Resources - Cash Flows from Investing Activities” below) and higher incentive payments to the General Partner ($1.0 million), resulting from the increase in the distribution rate and additional units outstanding.
2002 Compared With 2001
Total revenue for the year ended December 31, 2002 was $247.3 million, $14.9 million or 6.4 percent greater than revenue of $232.4 million in 2001. Revenue from pipeline transportation was $214.1 million in 2002 compared to $206.3 million in 2001. Of the $7.8 million increase in pipeline transportation revenue, $4.3 million is related to a full-year of Norco operations in 2002 compared to five months of Norco operations in 2001. Volumes delivered during 2002 averaged 1,101,400 barrels per day, 11,000 barrels per day or 1.0 percent greater than volume of 1,090,400 barrels per day delivered in 2001.
Revenue from the transportation of gasoline of $114.1 million increased by $6.5 million, or 6.0 percent, from 2001 levels. $2.0 million of the increase in gasoline transportation revenue was related to a full-year of Norco operations. Total gasoline volumes of 556,400 barrels per day in 2002 were 15,700 barrels per day, or 2.9 percent greater than 2001 volumes of 540,700 barrels per day. Norco gasoline volumes for a full-year of operations in 2002 were 17,200 barrels per day compared to 16,800 barrels per day for five months of operations in 2001. In the East, gasoline volumes of 245,700 barrels per day were approximately 9,400 barrels per day, or 4.0 percent, greater than 2001 volumes. The increase was primarily due to greater deliveries to the upstate New York and Pittsburgh, Pennsylvania areas. In the Midwest, gasoline volumes of 164,000 barrels per day were 6,900 barrels per day, or 4.0 percent, less than gasoline volumes delivered during 2001. Demand for gasoline transportation was generally lower throughout the region with the largest declines occurring in the Detroit and Bay City, Michigan areas. Long Island System gasoline volumes of 111,300 barrels per day were up 5,700 barrels per day, or 5.4 percent, due to additional available capacity on this system following reductions in turbine fuel demand after September 11, 2001. On the Jet Lines System, gasoline volumes of
18,200 barrels per day were 2,700 barrels per day, or 12.8 percent, less than 2001 volumes due to lower transportation demand in the Hartford, Connecticut area.
Revenue from the transportation of distillate of $57.7 million increased by $0.4 million, or 0.7 percent, from 2001 levels. Norco’s distillate transportation revenue increased by $1.9 million in 2002 reflecting a full year of operations. Total volumes of 265,400 barrels per day in 2002 were 1,400 barrels per day, or 0.5 percent less than 2001 distillate volumes of 266,800 barrels per day. Norco distillate volumes for a full-year of operations in 2002 were 12,900 barrels per day compared to 12,800 barrels per for five months of operations in 2001. In the East, distillate volumes of 145,000 barrels per day were approximately 5,300 barrels per day, or 3.5 percent, less than 2001 volumes. In the Midwest, distillate volumes of 68,100 barrels per day were 1,200 barrels per day, or 1.8 percent, less than volumes delivered during 2001. Long Island System distillate volumes of 18,400 barrels per day were down 700 barrels per day or 3.9 percent less than volumes delivered during 2001. On the Jet Lines system, distillate volumes of 20,700 barrels per day were 1,800 barrels per day, or 8.1 percent, less than 2001 volumes. Distillate volumes declined during the first quarter of 2002 compared to the first quarter 2001 due to milder than normal winter conditions. During the fourth quarter 2002, distillate volumes increased over fourth quarter 2001 volumes as winter conditions returned to more normal levels. The increase, however, did not fully offset the decline that occurred during the first quarter of the year.
Revenue from the transportation of jet fuel of $36.9 million decreased by $0.4 million, or 1.0 percent, from 2001 levels. Norco does not transport turbine fuel. In May, 2001 WesPac commenced turbine fuel deliveries to San Diego airport. WesPac’s turbine fuel revenue was up $0.9 million primarily due to a full-year of deliveries to San Diego Airport during 2002. Total jet fuel volumes of 250,900 barrels per day in 2002 were 9,100 barrels per day, or 3.5 percent less than 2001 jet fuel volumes of 260,000 barrels per day. WesPac’s jet fuel volumes of 11,700 barrels per day were up 3,600 barrels per day due to a full year of deliveries to San Diego Airport. Deliveries to New York City airports declined by 9,100 barrels per day, or 6.6 percent. Deliveries to Pittsburgh Airport declined by 2,100 barrels per day, or 18.0 percent, while deliveries to Miami airport declined 2,900 barrels per day, or 5.4 percent. Volumes to all major airports declined as a result of reduced airline travel following the terrorist attacks on September 11, 2001.
Terminalling, storage and rental revenue of $18.9 million increased by $2.5 million in 2002 primarily due to a full year of Norco operations.
Contract operation services revenue of $14.4 million increased by $4.7 million due to additional contracts obtained by BGC during 2002 and 2001. Contract operations revenues typically consist of costs reimbursable under the contracts plus an operator’s fee. Accordingly, revenues from these operations carry a lower gross profit percentage than revenues from pipeline transportation or terminalling, storage and rentals.
The Partnership’s costs and expenses for 2002 were $145.0 million compared to $134.1 million for 2001. BGC’s costs and expenses increased by $4.5 million over 2001 as a result of additional contract services provided. A full year of Norco operations resulted in an additional $4.4 million of operating expense. Other increases of $2.0 million are primarily related to general wage increases, increases in payroll overhead costs, increases in the use of outside services, increases in power costs related to additional pipeline volumes and higher insurance premiums.
Other income and expense for 2002 was a net cost of $30.5 million compared to $28.9 million in 2001. The increase was primarily due to higher interest expense on additional borrowings during 2002 and 2001 related to acquisitions and certain expansion capital expenditures.
Tariff Changes
Effective May 1, 2003, certain of the Operating Partnerships implemented tariff increases that were expected to generate $4.8 million in additional annual revenue. Effective July 1, 2002, certain of the Operating Partnerships implemented tariff increases that generated approximately $3.8 million in additional annual revenue. Effective July 1, 2001, certain of the Operating Partnerships implemented tariff increases that generated approximately $4.1 million in additional revenue per year.
Liquidity and Capital Resources
The Partnership’s financial condition at December 31, 2003, 2002, and 2001 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 Units outstanding at year-end.
During 2003, the Partnership’s principal sources of cash were cash from operations as well as the strategic financing transactions described in “Overview” above, including $59.9 million from the offering of 1,750,000 LP units, $296.4 million from the issuance of the 4 5/8% Notes and $148.1 million from the issuance of the 6 3/4% Notes. During 2002 and 2001, the Partnership’s principal sources of cash were cash from operations and borrowings under the Credit Facilities. The Partnership’s principal uses of cash are capital expenditures, investments and acquisitions, distributions to Unitholders and, in 2003, repayment of the $240 million Senior Notes (along with the associated yield maintenance premium) and amounts outstanding under the Credit Facilities.
The Partnership anticipates that cash from operations plus amounts available under the Credit Facilities will be sufficient to fund its cash requirements for 2004.
Cash Flows from Operations
Cash flows from operations were $109.4 million in 2003 compared to $93.1 million in 2002. The increase in operating cash flows of $16.3 million resulted from an increase in net income before the yield maintenance premium to $75.6 million, or $3.7 million, over net income of $71.9 million in 2002, an increase in depreciation and amortization, a non-cash expense, of $1.9 million to $22.6 million in 2003 compared to $20.7 million in 2002, an increase in minority interest expense of $1.7 million to $2.7 million in 2003, favorable changes in current assets and liabilities (excluding cash) of $6.3 million, and favorable changes in noncurrent assets and liabilities of $2.7 million. In 2003, increases in accounts payable and accrued liabilities of $18.1 million more than offset an increase in prepaid and other current assets of $10.5 million. The increase in accounts payable was caused by an increase in outstanding vouchers payable at year-end, while the increase in accrued liabilities resulted from the timing of interest payments on the 4 5/8% Notes and the 6 3/4% Notes, both of which are due semiannually, compared to the interest payments on the $240 million Senior Notes and the Credit Facilities, which were due monthly and quarterly, respectively. The increase in prepaid and other current assets resulted from the timing of the Partnership’s insurance payments in 2003 compared to 2002, along with an increase in insurance receivables related to certain environmental claims.
Cash flows from operations of $93.1 million in 2002 increased by $12.1 million over 2001. Net income increased by $2.5 million to $71.9 million in 2002 compared to $69.4 million in 2001. Changes in current assets and liabilities resulted in a net cash source of $0.6 million in 2002 compared to a net cash use of $5.3 million in 2001. In 2002, increases in trade receivables and inventories were more than offset by increases
in prepaid and other assets of $4.5 million, principally related to operations at BGC. Changes in other noncurrent assets and liabilities resulted in a net cash use of $1.2 million in 2002 compared to a net cash use of $3.5 million in 2001.
Cash Flows from Investing Activities
Net cash used in investing activities was $79.0 million in 2003 compared to 72.8 million in 2002 and $122.3 million in 2001. Investing activities are summarized below:
As noted above, in 2003, the Partnership invested $36.0 million for a 20 percent interest in WTP ($28.5 million) and an additional 7% interest in West Shore ($7.5 million). At December 31, 2003, the Partnership owned approximately 25% of West Shore. The Partnership had no investments or acquisitions in 2002. In 2001, the Partnership invested $62.3 million in the acquisition of Norco and $23.3 million for an approximate 18% interest in West Shore.
Capital expenditures are summarized below:
During 2003, the Partnership’s capital expenditures of $39.8 million increased by $5.0 million from $34.8 million in 2002 (excluding $2.4 million in 2003 and $36.8 million in 2002 related to the Sabina Pipeline discussed below). During 2003, sustaining capital expenditures of $28.4 million remained approximately the same as 2002 amounts of $28.2 million and increased by $2.5 million over 2001 amounts of $25.9 million. In 2003, the Partnership continued to emphasize its pipeline and tank integrity projects, including electronic internal inspections, other integrity assessments and associated repairs, as part of its comprehensive program to meet increased safety and environmental standards (see Part I, “Business - Environmental Matters” and “Business - Pipeline Regulation and Safety Matters”). Expansion and cost reduction expenditures increased by $4.8 million in 2003 to $11.4 million, principally related to a capacity expansion project in Ohio and Indiana.
Under an agreement with three major petrochemical companies (the “Agreement”), BGC constructed the Sabina Pipeline. The pipeline originates at a Shell Chemicals, L.P. facility in Deer Park, Texas and terminates at a chemical plant owned by Sabina Petrochemicals, LLC in Port Arthur, Texas. The Partnership expended approximately $2.4 million in 2003 and $36.8 million in 2002 related to the Sabina Pipeline, which amounts are included in capital expenditures in the Partnership’s financial statements. In addition, the
Partnership received $2.2 million and $14.2 million in 2003 and 2002 from two of the three petrochemical companies based on certain construction milestones. These amounts represented these companies’ equity contributions to the Sabina Pipeline. Subsidiaries of BGC hold an approximate 63 percent interest in the Sabina Pipeline and the two petrochemical companies own the remaining 37 percent minority interest.
The Sabina Pipeline has entered into a long-term agreement with Sabina Petrochemicals, LLC to provide pipeline transportation throughput services. Separately, BGC entered into an agreement to operate and maintain the Sabina Pipeline. The pipeline was completed in March 2003 and commenced deliveries in February 2004. Under the throughput services agreement, throughput services payments commenced in January 2003.
The Partnership expects to spend approximately $80 million in capital expenditures in 2004, of which approximately $30 million is projected relating to sustaining expenditures and $50 million is projected relating to expansion and cost reduction projects. Sustaining capital expenditures, in addition to pipeline integrity, include renewals and replacement of tank floors and roofs, upgrades to field instrumentation and cathodic protection systems. Of the planned 2004 sustaining expenditures, approximately $20 million relate to pipeline and tank integrity projects. During 2003, 2002 and 2001, the Partnership accelerated its expenditures related to pipeline and tank integrity projects and anticipates that such expenditures will begin to decline commencing in 2005 upon completion of the Partnership’s first 5-year cycle of pipeline integrity inspections.
As discussed under Critical Accounting Policies and Estimates below, the Partnership’s initial integrity expenditures are capitalized as part of pipeline cost when such expenditures improve or extend the life of the pipeline or related assets. Subsequent integrity expenditures are expensed as incurred. Accordingly, over time, integrity expenditures will shift from capital to operating expenditures.
Expansion and cost reduction expenditures include projects to facilitate increased pipeline volumes, extend the pipeline incrementally to new facilities, expand terminal facilities or improve the efficiency of operations. The expected increase in 2004 expansion expenditures relates principally to the continued investment in the Ohio - Indiana project, additional capacity expansions in the Partnership’s eastern operations and a joint venture project with WesPac to construct an airport delivery and terminalling facility.
Cash Flows from Financing Activities
During 2003, the Partnership initiated the strategic financing activities outlined in the “Overview” section above. As a result of these transactions, approximately $59.9 million, net of offering costs, was provided by the issuance of 1,750,000 LP units and $444.5 million, net of underwriters’ fees and expenses, was provided by the issuance of the 4 5/8% Notes and the 6 3/4% Notes. All of the amounts outstanding under the Credit Facilities, totaling $165 million at December 31, 2002 were repaid. Additionally, the Partnership borrowed $24 million in 2003 under the Credit Facilities, all of which was repaid. The Partnership retired the $240 million Senior Notes of Buckeye Pipe Line Company, L.P. The total repayment, including the yield maintenance premium, was $285.5 million.
During 2002, the Partnership increased its borrowings under the Credit Facilities by $32 million, principally to fund its investment in the Sabina Pipeline as well as a portion of its other expansion capital expenditures. During 2001, the Partnership increased its borrowings under the Credit Facilities by $90 million, principally to fund the Norco acquisition and its initial investment in West Shore as well as a portion of its expansion capital expenditures.
During 2003, the Partnership received $2.2 million from its minority interest partners in the Sabina Pipeline project, compared to $14.2 million in 2002 because construction activity declined in 2003 with the completion of the pipeline. No contributions were received in 2001.
Distributions to Unitholders increased to $72.4 million in 2003 compared to $67.9 million in 2002 and $66.5 million in 2001. Distributions in 2003 increased as a result of an increase in the unit distribution rate and the issuance of 1,750,000 LP units in February 2003. Distributions in 2002 increased principally due to an increase in the unit distribution rate.
Debt Obligations, Credit Facilities and Other Financing
At December 31, 2003, the Partnership had $450.0 million in outstanding long-term debt, consisting of $300 million of the 4 5/8% Notes due 2013 and $150.0 million of the 6 3/4% Notes due 2033. No amounts are outstanding under the Credit Facilities. The Credit Facilities consist of a 5-year $277.5 million Revolving Credit Agreement which was entered into in September 2001 with a syndicate of banks led by SunTrust Bank and a 364-day Revolving Credit Agreement entered into in September 2003 with another syndicate of banks also led by SunTrust Bank. Together, the Credit facilities permit borrowings up to $377.5 million subject to certain limitations contained in the Credit Facility agreements. Borrowings bear interest at SunTrust Bank’s base rate or, at the Partnership’s option, a rate based on LIBOR. The $377.5 million is available under the Credit Facilities until September 2004 with $277.5 million available thereafter until September 2006. The Partnership anticipates renewing the 364-day facility prior to its expiration in September 2004.
The Credit Facilities contain covenants which (a) limit outstanding indebtedness of the Partnership based on certain financial ratios, (b) prohibit the Partnership from creating or incurring certain liens on its property, (c) prohibit the Partnership from disposing of property which is material to its operations and (d) limit consolidation, merger and asset transfers by the Partnership. These covenants apply to the Partnership and all of its direct and substantially all of its indirect subsidiaries. At December 31, 2003, the Partnership and its subsidiaries were in compliance with these covenants. At December 31, 2003, the Partnership had $377.0 million available under the Credit Facilities, with $0.5 million allocated in support of certain operational letters of credit.
In order to hedge a portion of its fair value risk related to the 4 5/8% Notes, on October 28, 2003, the Partnership entered into an interest rate swap agreement with a financial institution with respect to $100 million principal amount (the “notional amount”) of the 4 5/8% Notes. The contract calls for the Partnership to receive fixed payments from the financial institution at a rate of 4 5/8% of the notional amount in exchange for floating rate payments from the Partnership based on the notional amount using a rate equal to the six-month London Interbank Offered Rate (LIBOR), determined in arrears, minus 0.28%. The agreement terminates on the maturity date of the 4 5/8% Notes and interest amounts under the agreement are payable semiannually on the same date as the interest payments on the 4 5/8% Notes. At the inception of the agreement, the Partnership designated the agreement as a fair value hedge and determined that no ineffectiveness will result from the use of the hedge. During the two months of 2003 that the hedge was outstanding, the Partnership saved $0.6 million of interest expense and, based on LIBOR at December 31, 2003, the Partnership would save approximately $3.8 million per year compared to interest expense the Partnership would incur had the Partnership not engaged in this transaction. Changes in LIBOR, however, will impact the interest rate expense incurred in connection with the interest rate swap. For example, a 1% increase or decrease in LIBOR would increase or decrease interest expense by $1 million per year. The fair market value of the interest rate swap was a gain of approximately $0.2 million at December 31, 2003.
Off Balance Sheet Arrangements
None.
Operating Leases
The Operating Partnerships lease certain land and rights-of-way. Minimum future lease payments for these leases as of December 31, 2003 are approximately $3.8 million for each of the next five years. Substantially all of these lease payments may be canceled at any time should the leased property no longer be required for operations.
The General Partner leases space in an office building and certain office equipment and charges these costs to the Operating Partnerships. Buckeye leases certain computing equipment and automobiles. Future minimum lease payments under these noncancelable operating leases at December 31, 2003 were as follows: $704,000 for 2004, $712,000 for 2005, $538,000 for 2006, $114,000 for 2007, $14,000 for 2008 and none thereafter.
Buckeye entered into an energy services agreement for certain main line pumping equipment and the natural gas requirements to fuel this equipment at its Linden, New Jersey facility. Under the energy services agreement, which is designed to reduce power costs at the Linden facility, Buckeye is required to pay a minimum of $1,743,000 annually over the next eight years. This minimum payment is based on an annual minimum usage requirement of the natural gas engines at the rate of $0.049 per kilowatt hour equivalent. In addition to the annual usage requirement, Buckeye is subject to minimum usage requirements during peak and off-peak periods. Buckeye’s use of the natural gas engines has exceeded the minimum annual requirement in each of the three years ended December 31, 2003.
Rent expense under operating leases was $7,824,000, $7,285,000 and $7,700,000 for 2003, 2002 and 2001, respectively.
Contractual obligations are summarized in the follow table:
Other long-term obligations represent the minimum payments due under an energy services agreement for the purchase of natural gas to fuel main line pumping equipment at Linden, New Jersey.
Purchase obligations generally represent commitments for recurring operating expenses or capital projects.
Environmental Matters
The Operating Partnerships 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 Partnerships 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 groundwater monitoring and treatment. The Partnership regularly incurs expenses in connection with these environmental remediation activities. In 2003, the Operating Partnerships incurred operating expenses of $4.9 million and, at December 31, 2003, had $7.4 million accrued for environmental matters. Of the expenses incurred in 2003, approximately $2.3 million was incurred in connection with a product release from underground piping at the Partnership’s Rochester, New York terminal, and approximately $500,000 was incurred in connection with a pipeline release in Illinois. Approximately $3.1 million of additional expense associated with the Illinois release is expected to be reimbursed by the Partnership’s insurance carriers. Expenditures, both capital and operating, relating to environmental matters are expected to continue due to the Partnership’s commitment to maintain high environmental standards and to increasingly rigorous environmental laws.
Various claims for the cost of cleaning up releases of hazardous substances and for damage to the environment resulting from the activities of the Operating Partnerships or their predecessors have been asserted and may be asserted in the future under various federal and state laws. The General Partner believes that the generation, handling and disposal of hazardous substances by the Operating Partnerships and their predecessors have been in material compliance with applicable environmental and regulatory requirements.
The total potential remediation costs to be borne by the Operating Partnerships relating to these clean-up sites cannot be reasonably estimated and could be material. With respect to certain sites, however, the Operating Partnership involved is one of several or as many as several hundred PRPs that would share in the total costs of clean-up under the principle of joint and several liability. Although the Partnership has made a provision for certain legal expenses relating to these and other environmental matters, the General Partner is unable to determine the timing or outcome of any pending proceedings or future claims or proceedings. See “Business - Environmental Matters” and “Legal Proceedings.”
Competition and Other Business Conditions
Several major refiners and marketers of petroleum products announced strategic alliances or mergers in recent years. These alliances or mergers have the potential to alter refined product supply and distribution patterns within the Operating Partnerships’ market area resulting in both gains and losses of volume and revenue. While the General Partner believes that individual delivery locations within its market area may have significant gains or losses, it is not possible to predict the overall impact these alliances or mergers may have on the Operating Partnerships’ business. However, the General Partner does not believe that these alliances or mergers will have a material adverse effect on the Partnership’s results of operations or financial condition.
In the Midwest, several petroleum product pipeline expansions and two new petroleum product pipeline construction projects have recently been completed. While these projects may alter supply sources with respect to the Partnership’s service area, they are not expected to have a material adverse effect on the Operating Partnership’s results of operations or financial condition.
Certain changes in refined petroleum product specifications are likely to impact the transportation of refined petroleum products over the next several years. Methyl-Tertiary-Butyl-Ether (“MTBE”), a gasoline additive used for air pollution control purposes, is scheduled to be phased out of use in certain states commencing in 2004. The phase-out of MTBE may result in a reduction in gasoline volumes delivered in the Partnership’s service area. The Partnership is unable to quantify the amount by which its transportation volumes might be affected by the phase-out of MTBE. In addition, new requirements for the use of ultra low-sulfur diesel fuel, which will be phased in commencing in 2006 through 2010, could require significant capital expenditures at certain locations in order to permit the Partnership to handle this new product grade. At this time the Partnership is unable to predict the timing or amount of capital or operating expenditures that would be required to enable the Partnership to transport and store ultra low-sulfur diesel fuel.
Employee Stock Ownership Plan
Services Company provides an employee stock ownership plan (the “ESOP”) to substantially all of its regular full-time employees, except those covered by certain labor contracts. The ESOP owns all of the outstanding common stock of Services Company. At December 31, 2003, the ESOP was directly obligated to a third-party lender for $43.1 million of 7.24 percent Notes (the “ESOP Notes”). The ESOP Notes are secured by 2,441,510 shares of Services Company common stock and are guaranteed by Glenmoor and certain of its affiliates. The proceeds from the issuance of the ESOP Notes were used to purchase Services Company common stock. 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 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 BMC for certain executive compensation costs, a reduction of the incentive compensation paid by the Partnership to BMC under the existing 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 “top-up reserve”). The Partnership will also incur ESOP-related costs for routine administrative costs and taxes associated with annual taxable income or the sale of LP units, if any. Total ESOP related costs charged to earnings were $1.1 million in 2003, $1.2 million in 2002 and $1.1 million in 2001.
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.
Generally, the timing and amount of revenue recognized by an organization is among the most critical of accounting policies to be adopted. For its pipeline operations, which constitutes approximately 84% the Partnership’s revenues, the Partnership recognizes revenue as the product is delivered to customers. Terminalling and storage revenues, representing approximately 9.7% of the Partnership’s revenues, are recognized as the services are provided. Revenues from contract pipeline operations, representing approximately 6% of the Partnership’s revenues, are recognized as the services are provided. Revenues for contract operations include both direct costs to be reimbursed by the customer under the contract and an operating fee. In all cases, the Partnership’s revenue recognition approximates billings to the customer.
Because the Partnership’s customers generally consist of major integrated oil companies, petroleum refiners and petrochemical companies, collections experience has historically been good and the Partnership has not required an allowance for bad debts. Some of the Partnership’s customers consist of major airlines, some of whom have experienced financial difficulties or even bankruptcy following the events of September 11, 2001. However, the Partnership’s credit monitoring policies, coupled with its ability to require prepayment of transportation charges, has limited its exposure to losses from potentially uncollectible accounts. Bad debts are written off as incurred.
Approximately 80% 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 improvement to the pipeline are capitalized based on the cost of the improvement while repairs and maintenance are expensed. Pipeline integrity expenditures are capitalized the first time such expenditures are incurred, when such expenditures improve or extend the life of the pipeline or related assets. Subsequent integrity expenditures are expensed as incurred. During 2003, 2002 and 2001, the Partnership capitalized $18.9 million, $21.2 million and $15.8 million, respectively, of integrity expenditures. Over the next several years, the Partnership expects integrity expenditures, both capital and operating, to range between $15 million and $20 million per year. During this time, the portion of expenditures capitalized is expected to decrease and the portion recorded as expense is expected to increase.
As discussed under Environmental Matters above, the Operating Partnerships 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 in whole or in part certain environmental expenditures. During 2003, the Operating Partnerships incurred operating expenses of $4.9 million and, at December 31, 2003, had $7.4 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.
In the event a known environmental liability results in expenditures that exceed the amount that has been accrued in connection with the matter, the additional expenditures would result in an increase in expenses and a reduction in income, in the period when the additional expense is incurred. Based on its experience, however, the Partnership believes that the amounts it has accrued for the future costs related to environmental liabilities is reasonable.
Related Party Transactions
With respect to related party transactions see Note 17 to the consolidated financial statements and Item 13 of Part III included elsewhere in this report.
Recent Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 143 “Accounting for Asset Retirement Obligations.” 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. 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 Partnership adopted SFAS No. 143 effective January 1, 2003. The Operating Partnerships’ assets generally consist of underground refined products pipelines installed along rights of way acquired from land owners and related above-ground facilities that are owned by the Operating Partnerships. The Partnership is unable to predict if and when its pipelines, which generally serve high-population and high-demand markets, would become completely obsolete and require decommissioning. Further, the Operating Partnerships’ 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 because the future dismantlement and removal dates of the Partnership’s assets, and the amount of any associated costs are indeterminate.
In May 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections”. SFAS 145 rescinds the automatic treatment of gains or losses from extinguishments of debt as extraordinary unless they meet the criteria for extraordinary items as outlined in APB No. 30, “Reporting the Results of Operations, Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions”. SFAS No. 145 also requires sale-leaseback accounting for certain lease modifications that have economic effects similar to a sale-leaseback transaction and makes various technical corrections to existing pronouncements. SFAS No. 145 was effective for fiscal years beginning after December 31, 2002. As a result of the adoption of SFAS No. 145, the yield maintenance premium of $45.5 million paid in the third quarter 2003 has been recorded as other income (expense) in the accompanying financial statements rather than as an extraordinary item.
In June 2002 the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS No. 146 nullifies the guidance provided in Emerging Issues Task Force (“EITF”) Issue 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” Generally, SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred, rather than when management commits to a plan of exit or disposal as is called for by EITF Issue No. 94-3. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002. The adoption of SFAS No. 146 did not have a material effect on the Partnership’s financial statements.
In November 2002, the FASB issued Interpretation No. 45 “Guarantor’s Accounting Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (“FIN 45”). FIN 45 established requirements for accounting and disclosure of guarantees issued to third parties for various transactions. The accounting requirements of FIN 45 are applicable to guarantees issued after December 31, 2002. The disclosure requirements of FIN 45 are applicable to financial statements issued for periods ending after December 15, 2002. The adoption of FIN 45 did not have a material effect on the Partnership’s financial statements.
In December 2002 the FASB issued SFAS No. 148 “Accounting for Stock-Based Compensation - Transition and Disclosure”, SFAS 148 amended the implementation provisions of SFAS 123 and required changes in disclosures in financial statements. The provisions of SFAS 148 were applicable for years ending after December 15, 2002 except for certain quarterly disclosures, which were applicable for interim periods beginning after December 15, 2002. The Partnership has not changed its method of accounting for stock-based compensation and, therefore, is subject only to the revised disclosure provisions of SFAS 148. Such disclosures have been provided in the Partnership’s consolidated financial statements.
In January 2003, the FASB issued Interpretation No. 46 “Consolidation of Variable Interest Entities (“FIN 46”), which was subsequently modified and reissued in December 2003. FIN 46 establishes accounting and disclosure requirements for ownership interests in entities that have certain financial or ownership characteristics. FIN 46, as revised, is generally applicable for the first fiscal year or interim accounting period ending after March 15, 2004. The adoption of the provisions of FIN 46 have not, nor are they expected to, have a material effect on the Partnership’s financial statements.
In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activity”. SFAS No. 149 amends certain provisions related to Statement No. 133, and is generally effective for transactions entered into after June 30, 2003. The adoption of SFAS No. 149 did not have a material effect on the Partnership’s consolidated financial position or results of operations.
In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity”. SFAS No. 150 affects how an entity measures and reports financial instruments that have characteristics of both liabilities and equity, and is effective for financial instruments entered into or modified after May 31, 2003 and is otherwise effective at the beginning of the first interim period beginning after June 15, 2003. The FASB continues to address certain implementation issues associated with the application of SFAS No. 150, including those related to mandatory redeemable financial instruments representing non-controlling interests in subsidiaries’ consolidated financial statements. The Partnership will continue to monitor the actions of the FASB and assess the impact, if any, on its consolidated financial statements. The effective provisions of SFAS No. 150 did not have a material impact on the Partnership’s consolidated financial position or results of operations.
In May 2003 the Emerging Issues Task Force (EITF) of the FASB issued Consensus No. 01-8 “Determining Whether an Arrangement Contains a Lease.” Consensus No. 01-8 establishes criteria for determining when certain contracts, or portions of contracts, should be subject to the provisions of SFAS No. 13 - “Accounting for Leases” and related pronouncements. EITF Consensus No. 01-8 generally is effective for arrangements entered into or modified in the first quarter beginning after May 28, 2003. The adoption of EITF Consensus No. 01-8 did not have a material effect on the Partnership’s financial condition or results of operations.
In December 2003, the FASB issued SFAS No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits.” SFAS No. 132 (as revised) requires additional disclosures regarding pensions and postretirement benefits beyond those previously required in the original version of SFAS No. 132. SFAS No. 132 (revised 2003) is effective for fiscal years and interim periods ending after December 15, 2003, except for certain provisions which generally are not applicable to the Partnership. The Partnership has adopted the provisions of SFAS No. 132 (revised) and has included the appropriate disclosures in the accompanying financial statements.
In January 2004, the staff of the FASB issued FASB Staff Position No. 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” The purpose of FASB Staff Position No. 106-1 is to provide guidance on how recent Federal legislation which provides certain prescription drug benefits and subsidies to sponsors of certain medical plans which substitute benefits for Medicare Part D is to be incorporated into a plan sponsor’s calculation of retiree medical liabilities. There are significant uncertainties about how this Federal legislation will ultimately affect plan sponsors’ liabilities with respect to retiree medical costs.
FASB Staff Position No. 106-1, which is effective for fiscal years ending after December 7, 2003, permits plan sponsors, like the Partnership, to defer the accounting effects of the legislation until authoritative guidance on how to account for the Federal legislation is provided, or a significant event occurs, such as a plan amendment, settlement or curtailment, which would require a remeasurement of a plan’s assets and obligations.
The Partnership has elected to defer the accounting recognition of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 until such time as authoritative guidance is provided. Accordingly, measures related to the Accumulated Benefit Obligation and net periodic postretirement benefit cost in the Partnership’s financial statements do not reflect the effects of the Act on the Plan. When authoritative guidance to plan sponsors is provided, such guidance could cause financial information related to retiree medical benefits previously reported to change. The Partnership has not yet evaluated the provisions of the Act in order to determine how the prescription drug benefits and potential subsidies will affect the Partnership.
Forward-Looking Information
The information contained above in this Management’s Discussion and Analysis and elsewhere in this 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,” “will,” or other similar words, although some forward-looking statements are expressed differently. These statements discuss future expectations or contain projections. Specific factors which could cause actual results to differ from those in the forward-looking statements include: (1) price trends and overall demand for refined 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) 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; (3) liability for environmental claims; (4) security issues affecting our assets, including, among others, potential damage to our assets caused by acts of war or terrorism; (5) unanticipated capital expenditures and operating expenses to repair or replace our assets; (6) availability and cost of insurance on our assets and operations; (7) our ability to successfully identify and complete strategic acquisitions and make cost saving changes in operations; (8) expansion in the operations of our competitors; (9) our ability to integrate any acquired operations into our existing operations; (10) shut-downs or cutbacks at major refineries that use our services; (11) deterioration in our labor relations; (12) changes in real property tax assessments; (13) disruptions to the air travel system; and (14) interest rate fluctuations and other capital market conditions.
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. 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 4 5/8% Notes and the 6 3/4% Notes) and to cash flow risk with respect to its variable rate obligations. 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 variable portion of its financing arrangements (the Credit Facilities) will rise or fall depending on changes in interest rates.
At December 31, 2003, the Partnership had total debt of $450 million, consisting of $300 million of the 4 5/8% Notes and $150 million of the 6 3/4% Notes. The fair value of these obligations at December 31, 2003 was approximately $429 million. The Partnership estimates that a 1% decrease in rates for obligations of similar maturities would increase the fair value of these obligations by $42 million.
In order to hedge a portion of its fair value risk related to the 4 5/8% Notes, on October 28, 2003, the Partnership entered into an interest rate swap agreement with a financial institution with respect to $100 million principal amount (the “notional amount”) of the 4 5/8% Notes. The contract calls for the Partnership to receive fixed payments from the financial institution at a rate of 4 5/8% of the notional amount in exchange for floating rate payments from the Partnership based on the notional amount using a rate equal to the six-month London Interbank Offered Rate (LIBOR), determined in arrears, minus 0.28%. The agreement terminates on the maturity date of the 4 5/8% Notes and interest amounts under the agreement are payable semiannually on the same date as the interest payments on the 4 5/8% Notes. At the inception of the agreement, the Partnership designated the agreement as a fair value hedge and determined that no ineffectiveness will result from the use of the hedge. During the two months of 2003 that the hedge was outstanding, the Partnership saved $0.6 million and, based on LIBOR at December 31, 2003, the Partnership would save approximately $3.8 million per year compared to interest expense the Partnership would incur had the Partnership not engaged in this transaction. Changes in LIBOR, however, will impact the interest rate expense incurred in connection with the interest rate swap. For example, a 1% increase or decrease in LIBOR would increase or decrease interest expense by $1 million per year. The fair market value of the interest rate swap was a gain of approximately $0.2 million at December 31, 2003.
The Partnership’s practice with respect to hedge transactions has been to have each transaction authorized by the Board of Directors of the General Partner.
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.
INDEPENDENT AUDITORS’ REPORT
To the Partners of Buckeye Partners, L.P.:
We have audited the accompanying consolidated balance sheets of Buckeye Partners, L.P. and its subsidiaries (the “Partnership”) as of December 31, 2003 and 2002, and the related consolidated statements of income and cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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 the Partnership as of December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 6 to the consolidated financial statements, effective January 1, 2002, the Partnership changed its method of accounting for goodwill and other intangible assets to conform to Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets.”
DELOITTE & TOUCHE LLP
Philadelphia, Pennsylvania
March 11, 2004
BUCKEYE PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF INCOME
See Notes to consolidated financial statements.
BUCKEYE PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
See Notes to consolidated financial statements.
BUCKEYE PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
See Notes to consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2003 AND 2002 AND
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
1.
Organization
Buckeye Partners, L.P. (the “Partnership”) is a master limited partnership organized in 1986 under the laws of the state of Delaware. The Partnership’s principal line of business is the transportation of refined petroleum products for major integrated oil companies, large refined 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.
The Partnership owns approximately 99 percent limited partnership interests in Buckeye Pipe Line Company, L.P. (“Buckeye”), Laurel Pipe Line Company, L.P. (“Laurel”), Everglades Pipe Line Company, L.P. (“Everglades”) and Buckeye Pipe Line Holdings, L.P. (“BPH” formerly Buckeye Tank Terminals Company, L.P.) These entities are hereinafter referred to as the “Operating Partnerships.” BPH owns directly, or indirectly, a 100 percent interest in each of Buckeye Terminals, LLC (“BT”), Norco Pipe Line Company, LLC (“Norco”) and Buckeye Gulf Coast Pipe Lines, L.P. (“BGC”). BPH also owns a 75 percent interest in WesPac Pipelines - Reno LLC, WesPac Pipelines - San Diego LLC, WesPac Pipelines - Memphis LLC and related WesPac entities (collectively known as “WesPac”), an approximate 25 percent interest in West Shore Pipe Line Company (“West Shore”) and a 20 percent interest in West Texas LPG Pipeline Limited Partnership (“WTP”). Subsidiaries of BGC also own approximately 63 percent of a crude butadiene pipeline between Deer Park, Texas and Port Arthur, Texas that was completed in March 2003 (the “Sabina Pipeline”).
Buckeye Pipe Line Company (the “General Partner”) serves as the general partner to the Partnership. As of December 31, 2003, the General Partner owned approximately a 1 percent general partnership interest in the Partnership and approximately a 1 percent general partnership interest in each Operating Partnership, for an approximate 2 percent interest in the Partnership. The General Partner is a wholly-owned subsidiary of Buckeye Management Company (“BMC”). BMC is a wholly-owned subsidiary of Glenmoor, Ltd. (“Glenmoor”). Glenmoor is owned by certain directors and members of senior management of the General Partner and trusts for the benefit of their families and by certain other management employees of Buckeye Pipe Line Services Company (“Services Company”).
Services Company employs approximately 81 percent of the employees that work for the Operating Partnerships. At December 31, 2003, Services Company had 504 employees. Pursuant to a Services Agreement dated August 12, 1997, BMC and the General Partner reimburse Services Company for its direct and indirect expenses. These expenses are reimbursed to the General Partner by the Operating Partnerships except for certain executive compensation costs and related benefits expenses (See Note 17). BT, Norco and BGC directly employed 116 full-time employees at December 31, 2003.
Buckeye is one of the largest independent pipeline common carriers of refined petroleum products in the United States, with 2,909 miles of pipeline serving 9 states. Laurel owns a 345-mile common carrier refined products pipeline located principally in Pennsylvania. Norco owns a 482-mile refined products pipeline system located primarily in Illinois, Indiana and Ohio. Everglades owns a 37-mile refined products pipeline in Florida. Buckeye, Laurel, Norco and Everglades conduct the Partnership’s refined products pipeline business. BPH and its subsidiaries provide bulk storage service through facilities with an aggregate capacity of 5.1 million barrels of refined petroleum products. WesPac provides pipeline transportation services to Reno/Tahoe International and San Diego International airports.
BGC is an owner and contract operator of pipelines owned by major chemical companies in the Gulf Coast area. BGC leases its 16-mile pipeline to a chemical company. In March 2003, BGC completed construction of the Sabina Pipeline. The Sabina Pipeline originates at a Shell Chemicals, L.P. facility in Deer Park, Texas and terminates at a chemical plant owned by Sabina Petrochemicals, LLC in Port Arthur, Texas. Subsidiaries of BGC hold an approximate 63 percent interest in the Sabina Pipeline. Two petrochemical
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2003 AND 2002 AND
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 - (Continued)
companies own the remaining 37 percent minority interest. The Sabina Pipeline has entered into a long-term agreement with Sabina Petrochemicals LCC to provide pipeline transportation throughput services. Revenues under the throughput services agreement commenced January 2003, although the pipeline did not commence shipping product until February 2004. Separately, BGC entered into an agreement to operate and maintain the Sabina Pipeline.
On July 31, 2001, the Partnership acquired a refined products pipeline system and related terminals from affiliates of TransMontaigne Inc. for approximately $62.3 million. The assets included a 482-mile refined petroleum products pipeline that runs from Hartsdale, Indiana west to Fort Madison, Iowa and east to Toledo, Ohio, with an 11-mile pipeline connection between major storage terminals in Hartsdale and East Chicago, Indiana. These assets are operated by the Partnership under the name of Norco Pipe Line Company, LLC. The acquired assets also included 3.2 million barrels of pipeline storage and trans-shipment facilities in Hartsdale and East Chicago, Indiana and Toledo, Ohio; and four petroleum products terminals located in Bryan, Ohio; South Bend and Indianapolis, Indiana; and Peoria, Illinois. The storage and terminal assets are operated by Buckeye Terminals, LLC.
On October 29, 2001, the Partnership acquired 6,805 shares of common stock of West Shore (approximately 18%) for approximately $23.3 million. An additional 2,340 shares of West Shore (approximately 7%) were acquired on September 30, 2003 for approximately $7.5 million. The common stock represents an approximate 25% percent ownership interest in West Shore. West Shore owns and operates 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 users in northern Illinois and Wisconsin. The other stockholders of West Shore are major oil companies. The pipeline is operated under contract by Citgo Pipeline Company. During 2004, the Partnership changed its accounting method from the cost to the equity method as a result of its increased ownership in West Shore. This change did not have a significant effect on the financial statements of the Partnership.
On August 8, 2003, the Partnership acquired a 20 percent interest in WTP from certain affiliates of the Williams Companies, Inc. for $28.5 million. WTP owns and operates 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 area via connecting pipelines and from gathering fields located in West and Central Texas. The majority owners and operators of WTP are affiliates of Chevron Pipeline Company. The investment in WTP is accounted for using the equity basis of accounting.
The Partnership maintains its accounts in accordance with the Uniform System of Accounts for Pipeline Companies, as prescribed by the Federal Energy Regulatory Commission (“FERC”). Buckeye and Norco are subject to rate regulation as promulgated by FERC. Reports to FERC differ from the accompanying consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America (“generally accepted accounting principles”), generally in that such reports calculate depreciation over estimated useful lives of the assets as prescribed by FERC.
2.
Summary of Significant Accounting Policies
Basis of Presentation
The financial statements include the accounts of the Operating Partnerships on a consolidated basis. All significant intercompany transactions have been eliminated in consolidation.
Use of Estimates
The preparation of the Partnership’s consolidated financial statements in conformity with accounting principles generally accepted in the United States of America necessarily requires management to make
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2003 AND 2002 AND
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 - (Continued)
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.
Fair Value and Hedging Activities
The fair values of financial instruments are determined by reference to various market data and other valuation techniques as appropriate. Unless otherwise disclosed, the fair values of financial instruments approximate their fair values (see Note 11).
The Partnership accounts for hedging activities in accordance with SFAS No. 133 “Accounting for Financial Instruments and Hedging Activities” and SFAS No. 138 “Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of FASB Statement No. 133.” 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 Partnership adopted SFAS No. 133 effective January 1, 2001, with no effect on the Partnership’s financial statements because the Partnership had no derivative instruments outstanding at that time.
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.
The Partnership had no derivative instruments during 2002 or 2001. On October 28, 2003, the Partnership entered into an interest rate swap contract with a financial institution in order to hedge the fair value risk associated with a portion of its 4 5/8% Notes due 2013 (the “4 5/8% Notes”). 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.
By 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.
Cash and Cash Equivalents
All highly liquid debt instruments purchased with a maturity of three months or less are classified as cash equivalents.
Revenue Recognition
Revenue from the transportation of refined petroleum products is recognized as products are delivered to customers. Such customers include major integrated oil companies, major petroleum refiners, major petrochemical companies, large regional marketing companies and large commercial airlines. The consolidated Partnership’s customer base was approximately 90 in 2003. No customer contributed more than
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2003 AND 2002 AND
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 - (Continued)
10 percent of total revenue during 2003. The Partnership does not maintain an allowance for doubtful accounts due to its favorable collections experience.
The Partnership also derives revenue from terminalling operations, rentals and contract services for the operation of facilities and pipelines not directly owned by the Partnership. Revenue from such operations is recognized as the services are performed. Contract services revenue typically includes costs to be reimbursed by the customer plus an operator fee.
Inventories
Inventories, consisting of materials and supplies such as: pipe, 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.
Property, Plant and Equipment
Property, plant and equipment consist primarily of pipeline and related transportation facilities and equipment. For financial reporting purposes, depreciation on pipe 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
Effective January 1, 2002, the Partnership no longer amortizes goodwill. In 2001 the Partnership amortized goodwill on a straight-line basis over a period of fifteen years (see Note 6). The Partnership assesses its goodwill annually for potential impairment based on the market value of its business compared to its book value.
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 is based on the undiscounted future cash flows of the asset.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2003 AND 2002 AND
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 - (Continued)
Income Taxes
For federal and state income tax purposes, the Partnership and Operating Partnerships are not taxable entities. Accordingly, the taxable income or loss of the Partnership and Operating Partnerships, 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, 2003 and 2002, the Partnership’s reported amount of net assets for financial reporting purposes exceeded its tax basis by approximately $348 million and $327 million, respectively.
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 paid to outside engineering, consulting and law firms. The Partnership maintains insurance which may cover in whole or in part certain environmental expenditures.
Pensions
Services Company maintains a defined contribution plan (see Note 13), defined benefit plans (see Note 13) and an employee stock ownership plan (see Note 15) which provide retirement benefits to substantially all of its regular full-time employees, Norco employees, BGC employees and BT employees. Certain hourly employees of Services Company are covered by a defined contribution plan under a union agreement (see Note 13).
Postretirement Benefits Other Than Pensions
Services Company provides postretirement health care and life insurance benefits for certain of its retirees (see Note 13). Certain other retired employees are covered by a health and welfare plan under a union agreement (see Note 13).
Unit Option and Distribution Equivalent Plan
The Partnership has adopted Statement of Financial Accounting Standards No. 123 (“SFAS 123”), “Accounting for Stock-Based Compensation,” which requires expanded disclosures of stock-based compensation arrangements with employees. SFAS 123 encourages, but does not require, compensation cost to be measured based on the fair value of the equity instrument awarded. It allows the Partnership to continue to measure compensation cost for these plans using the intrinsic value based method of accounting prescribed by Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”). The Partnership has elected to continue to recognize compensation cost based on the intrinsic value of the equity instrument awarded as promulgated in APB 25.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2003 AND 2002 AND
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 - (Continued)
If compensation cost had been determined based on the fair value at the time of the grant dates for awards consistent with SFAS 123, the Partnership’s net income and earnings per share would have been as indicated by the proforma amounts below:
Comprehensive Income
The Partnership accounts for comprehensive income in accordance with Statement of Financial Accounting Standards No. 130, “Reporting Comprehensive Income”. 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. As of December 31, 2003 and for the year then ended, the Partnership had comprehensive income related to the minimum pension liability of $348,000 which is displayed in Note 18 “Partners’ Capital”. Including this adjustment comprehensive income was $29,806,000 compared to net income of $30,154,000. In 2002 and 2001, comprehensive income equaled net income.
Recent Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 143 “Accounting for Asset Retirement Obligations.” 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. 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 Partnership adopted SFAS No. 143 effective January 1, 2003. The Operating Partnerships’ assets generally consist of underground refined products pipelines installed along rights of way acquired from land owners and related above-ground facilities that are owned by the Operating Partnerships. The Partnership is unable to predict if and when its pipelines, which generally serve high-population and high-demand markets, would become completely obsolete and require decommissioning. Further, the Operating Partnerships’ 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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2003 AND 2002 AND
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 - (Continued)
SFAS No. 143 because the future dismantlement and removal dates of the Partnership’s assets, and the amount of any associated costs are indeterminate.
In May 2002, the FASB issued SFAS No. 145, “Recission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections”. SFAS 145 rescinds the automatic treatment of gains or losses from extinguishments of debt as extraordinary unless they meet the criteria for extraordinary items as outlined in APB No. 30, “Reporting the Results of Operations, Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions”. SFAS No. 145 also requires sale-leaseback accounting for certain lease modifications that have economic effects similar to a sale-leaseback transaction and makes various technical corrections to existing pronouncements. SFAS No. 145 was effective for fiscal years beginning after December 31, 2002. As a result of the adoption of SFAS No. 145, the yield maintenance premium of $45.5 million paid in the third quarter 2003 has been recorded as other income (expense) in the accompanying financial statements rather than as an extraordinary item.
In June 2002 the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS No. 146 nullifies the guidance provided in Emerging Issues Task Force (“EITF”) Issue 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” Generally, SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred, rather than when management commits to a plan of exit or disposal as is called for by EITF Issue No. 94-3. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002. The adoption of SFAS No. 146 did not have a material effect on the Partnership’s financial statements.
In November 2002, the FASB issued Interpretation No. 45 “Guarantor’s Accounting Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (“FIN 45”). FIN 45 established requirements for accounting and disclosure of guarantees issued to third parties for various transactions. The accounting requirements of FIN 45 are applicable to guarantees issued after December 31, 2002. The disclosure requirements of FIN 45 are applicable to financial statements issued for periods ending after December 15, 2002. The adoption of FIN 45 did not have a material effect on the Partnership’s financial statements.
In December 2002 the FASB issued SFAS No. 148 “Accounting for Stock-Based Compensation - Transition and Disclosure”, SFAS 148 amended the implementation provisions of SFAS 123 and required changes in disclosures in financial statements. The provisions of SFAS 148 were applicable for years ending after December 15, 2002 except for certain quarterly disclosures, which were applicable for interim periods beginning after December 15, 2002. The Partnership has not changed its method of accounting for stock-based compensation and, therefore, is subject only to the revised disclosure provisions of SFAS 148. Such disclosures have been provided in the Partnership’s consolidated financial statements.
In January 2003, the FASB issued Interpretation No. 46 “Consolidation of Variable Interest Entities (“FIN 46”), which was subsequently modified and reissued in December 2003. FIN 46 establishes accounting and disclosure requirements for ownership interests in entities that have certain financial or ownership characteristics. FIN 46, as revised, is generally applicable for the first fiscal year or interim accounting period ending after March 15, 2004. The adoption of the provisions of FIN 46 have not, nor are they expected to, have a material effect on the Partnership’s financial statements.
In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activity”. SFAS No. 149 amends certain provisions related to Statement No. 133, and is generally effective for transactions entered into after June 30, 2003. The adoption of SFAS No. 149 did not have a material effect on the Partnership’s consolidated financial position or results of operations.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2003 AND 2002 AND
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 - (Continued)
In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity”. SFAS No. 150 affects how an entity measures and reports financial instruments that have characteristics of both liabilities and equity, and is effective for financial instruments entered into or modified after May 31, 2003 and is otherwise effective at the beginning of the first interim period beginning after June 15, 2003. The FASB continues to address certain implementation issues associated with the application of SFAS No. 150, including those related to mandatory redeemable financial instruments representing non-controlling interests in subsidiaries’ consolidated financial statements. The Partnership will continue to monitor the actions of the FASB and assess the impact, if any, on its consolidated financial statements. The effective provisions of SFAS No. 150 did not have a material impact on the Partnership’s consolidated financial position or results of operations.
In May 2003 the Emerging Issues Task Force (EITF) of the FASB issued Consensus No. 01-8 “Determining Whether an Arrangement Contains a Lease.” Consensus No. 01-8 establishes criteria for determining when certain contracts, or portions of contracts, should be subject to the provisions of SFAS No. 13 - “Accounting for Leases” and related pronouncements. EITF Consensus No. 01-8 generally is effective for arrangements entered into or modified in the first quarter beginning after May 28, 2003. The adoption of EITF Consensus No. 01-8 did not have a material effect on the Partnership’s financial condition or results of operations.
In December 2003, the FASB issued SFAS No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits.” SFAS No. 132 (as revised) requires additional disclosures regarding pensions and postretirement benefits beyond those previously required in the original version of SFAS No. 132. SFAS No. 132 (revised 2003) is effective for fiscal years and interim periods ending after December 15, 2003, except for certain provisions which generally are not applicable to the Partnership. The Partnership has adopted the provisions of SFAS No. 132 (revised) and has included the appropriate disclosures in the accompanying financial statements.
In January 2004, the staff of the FASB issued FASB Staff Position No. 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” The purpose of FASB Staff Position No. 106-1 is to provide guidance on how recent Federal legislation which provides certain prescription drug benefits and subsidies to sponsors of certain medical plans which substitute benefits for Medicare Part D is to be incorporated into a plan sponsor’s calculation of retiree medical liabilities. There are significant uncertainties about how this Federal legislation will ultimately affect plan sponsors’ liabilities with respect to retiree medical costs.
FASB Staff Position No. 106-1, which is effective for fiscal years ending after December 7, 2003, permits plan sponsors, like the Partnership, to defer the accounting effects of the legislation until authoritative guidance on how to account for the Federal legislation is provided, or a significant event occurs, such as a plan amendment, settlement or curtailment, which would require a remeasurement of a plan’s assets and obligations.
The Partnership has elected to defer the accounting recognition of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 until such time as authoritative guidance is provided. Accordingly, measures related to the Accumulated Benefit Obligation and net periodic postretirement benefit cost in the Partnership’s financial statements do not reflect the effects of the Act on the Plan. When authoritative guidance to plan sponsors is provided, such guidance could cause financial information related to retiree medical benefits previously reported to change. The Partnership has not yet evaluated the provisions of the Act in order to determine how the prescription drug benefits and potential subsidies will affect the Partnership.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2003 AND 2002 AND
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 - (Continued)
3.
Acquisitions
Norco Pipe Line Company, LLC
On July 31, 2001, a subsidiary of the Partnership acquired a petroleum products pipeline system and related terminals from affiliates of TransMontaigne Inc. for a total purchase price of $61,750,000. Additional costs incurred in connection with the acquisition amounted to $533,000. The assets included a 482-mile refined petroleum products pipeline that runs from Hartsdale, Indiana west to Fort Madison, Iowa and east to Toledo, Ohio, with an 11-mile pipeline connection between major storage terminals in Hartsdale and East Chicago, Indiana. The assets also included 3.2 million barrels of pipeline storage and trans-shipment facilities in Hartsdale and East Chicago, Indiana and Toledo, Ohio; and four petroleum products terminals located in Bryan, Ohio; South Bend and Indianapolis, Indiana; and Peoria, Illinois. The pipeline system is operated under the name of Norco Pipe Line Co., LLC. The terminal assets became part of BTT’s operations. The pipeline system and related terminals are collectively referred to as the “Norco Assets” or “Norco Operations”. The allocated fair value of assets acquired is summarized as follows:
Pro forma results of operations for the Partnership, assuming the acquisition of the Norco Operations’ assets had been acquired at the beginning of 2001, were as follows:
The unaudited pro forma results have been prepared for comparative purposes only and do not purport to be indicative of the results of operations which actually would have resulted had the combinations been in effect at the beginning of the period presented, or of future results of operations of the entities.
4.
Segment Information
The Partnership has one segment, the transportation segment. The transportation segment derives its revenues primarily from the transportation of refined petroleum products that it receives from refineries, connecting pipelines and marine terminals. Terminalling and storage operations are ancillary to the Partnership’s pipeline operations. Contract operations of third-party pipelines are similar to the operations of the Partnership’s pipelines except that the Partnership does not own the facilities being operated.
5.
Contingencies
The Partnership and the Operating Partnerships in the ordinary course of business are 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. Although it is possible that one or more of these claims or proceedings, if adversely determined, could, depending on the relative amounts
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2003 AND 2002 AND
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 - (Continued)
involved, have a material effect on the Partnership for a future period, the General Partner does not believe that their outcome will have a material effect on the Partnership’s consolidated financial condition or annual results of operations.
Environmental
In accordance with its accounting policy on environmental expenditures, the Partnership recorded operating expenses of $4.9 million, $1.9 million and $2.2 million for 2003, 2002 and 2001, respectively, which were related to the environment. Expenditures, both capital and operating, relating to environmental matters are expected to continue due to the Partnership’s commitment to maintain high environmental standards and to increasingly strict environmental laws and government enforcement policies.
Various claims for the cost of cleaning up releases of hazardous substances and for damage to the environment resulting from the activities of the Operating Partnerships or their predecessors have been asserted and may be asserted in the future under various federal and state laws. The General Partner believes that the generation, handling and disposal of hazardous substances by the Operating Partnerships and their predecessors have been in material compliance with applicable environmental and regulatory requirements. The total potential remediation costs to be borne by the Operating Partnerships relating to these clean-up sites cannot be reasonably estimated and could be material. Although the Partnership has made a provision for certain legal and remediation expenses relating to these matters, the General Partner is unable to determine the timing or outcome of current environmental remediation activities, or any pending proceedings or of any future claims and proceedings.
6.
Goodwill and Intangible Assets
Effective January 1, 2002, the Partnership adopted Statement of Financial Accounting Standards (“SFAS”) No. 142, “Goodwill and Other Intangible Assets,” which establishes financial accounting and reporting 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.
The Partnership has completed the transitional impairment test required upon adoption of SFAS No. 142. The transitional test, which involved the use of estimates related to the fair market value of the business operations associated with the goodwill, did not result in an impairment loss. The Partnership continues to evaluate its goodwill at least annually, and has determined that no impairment was required in 2002 or 2003.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2003 AND 2002 AND
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 - (Continued)
The following represents pro-forma information as if SFAS No. 142 had been adopted at the beginning of the year and that goodwill amortization had been eliminated. The impact on net income, and basic and diluted earnings per share for the periods indicated below are as follows:
The Partnership’s amortizable intangible assets consist of pipeline rights-of-way and contracts. The contracts were acquired in connection with the acquisition of BGC in March 1999. At December 31, 2003, the gross carrying amount of the pipeline rights-of-way was $40,674,000 and accumulated amortization was $5,107,000. At December 31, 2002, the gross carrying amount of the pipeline rights-of-way was $25,328,000 and accumulated amortization was $3,909,000. Pipeline rights-of-way are included in property, plant and equipment in the accompanying balance sheet.
At December 31, 2003, the gross carrying amount of the contracts was $3,600,000 and accumulated amortization was $1,140,000. At December 31, 2002 the gross carrying amount of the contracts was $3,600,000 and the accumulated amortization was $900,000. For the years 2003, 2002 and 2001, amortization expense related to amortizable intangible assets was $1,053,000, and $749,000 and $727,000 respectively. Aggregate amortization expense related to amortizable intangible assets is estimated to be $1,053,000 per year for each of the next five years.
The Partnership’s only intangible asset not subject to amortization is goodwill that was recorded in connection with the acquisition of Buckeye Terminals, LLC in June 2000. The carrying amount of the goodwill was $11,355,000 at December 31, 2003 and 2002. During the reporting period of 2001, goodwill was amortized on a straight-line basis over a period of fifteen years. Goodwill amortization expense related to continuing operations was $832,000 in 2001.
7.
Prepaid and Other Current Assets
Prepaid and other current assets consist primarily of receivables from third parties for pipeline relocations and other work either completed or in-progress. Prepaid and other current assets also include prepaid insurance, prepaid taxes and other miscellaneous items.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2003 AND 2002 AND
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 - (Continued)
8.
Property, Plant and Equipment
Property, plant and equipment consist of the following:
Depreciation expense was $17,624,000, $15,765,000 and $14,232,000 for the years 2003, 2002 and 2001, respectively.
9.
Other Non-current Assets
Other non-current assets consist of the following:
The $64.2 million market value of limited partnership units (“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 164 months (see Note 15). Amortization of the deferred charge related to the ESOP Restructuring was $4,698,000 in 2003, 2002 and 2001. Amortization expense related to the contracts acquired from acquisition was $240,000 in each of 2003, 2002 and 2001.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2003 AND 2002 AND
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 - (Continued)
10.
Accrued and Other Current Liabilities
Accrued and other current liabilities consist of the following:
11.
Long-term Debt and Credit Facilities
Long-term debt consists of the following:
At December 31, 2003, $300.0 million of debt was scheduled to mature on June 15, 2013 and $150.0 million was scheduled to mature on August 15, 2033.
The fair value of the Partnership’s debt was estimated to be $429 million as of both December 31, 2003 and December 31, 2002. The values at December 31, 2003 and December 31, 2002 were calculated using interest rates currently available to the Partnership for issuance of debt with similar terms and remaining maturities.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2003 AND 2002 AND
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 - (Continued)
On July 7, 2003, the Partnership sold $300 million aggregate principal of its 4.625% Notes due 2013 in an underwritten public offering. Proceeds from the note offering, after underwriters’ fees and expenses, were approximately $296.4 million.
On August 14, 2003, the Partnership sold $150 million aggregate principal of its 6.75% Notes due 2033 in a Rule 144A offering. Proceeds from the note offering, after underwriters’ fees and expenses were approximately $148.1 million.
Proceeds from these offerings were used in part to repay all amounts outstanding under the Partnership’s 5-year Revolving Credit Agreement ($117 million at the date of repayment) and to repay the Buckeye Pipe Line Company, L.P. $240 million Senior Notes, which were scheduled to mature in 2024. The amounts outstanding under the 5-year Revolving Credit Agreement were repaid on July 10, 2003 and the $240 Senior Notes were repaid on August 19, 2003.
In connection with the repayment of the $240 million Senior Notes, Buckeye Pipe Line Company, L.P. was required to pay a yield maintenance premium of $45.5 million to the holders of the Senior Notes. The yield maintenance premium has been charged to expense in the accompanying consolidated financial statements.
The Partnership has a $277.5 million Revolving Credit Agreement with a syndicate of banks led by SunTrust Bank that expires in September 2006. In September 2003, the Partnership entered into a 364-day Revolving Credit Agreement for $100 million with another syndicate of banks also led by SunTrust Bank. The new agreement replaces the Partnership’s $85 million 364-day agreement which was set to expire in September 2003. Together, the $277.5 million and $100 million agreements are referred to as the “Credit Facilities.” At December 31, 2003, the Partnership had no amounts outstanding under the Credit Facilities.
The Credit Facilities contain certain covenants that affect the Partnership. Generally, the Credit Facilities (a) limit outstanding indebtedness of the Partnership based on certain financial ratios contained in the Credit Facilities, (b) prohibit the Partnership from creating or incurring certain liens on its property (c) prohibit the Partnership from disposing of property that is material to its operations (d) limit consolidations, mergers and asset transfers by the Partnership. At December 31, 2003, the Partnership was in compliance with the covenants contained in the Credit Facilities.
On October 28, 2003, the Partnership entered into an interest rate swap agreement with a financial institution in order to hedge a portion of its fair value risk associated with its 4 5/8% Notes. The notional amount of the swap agreement was $100 million. The swap agreement calls for the Partnership to receive fixed payments from the financial institution with at a rate of 4 5/8% of the notional amount in exchange for floating rate payments from the Partnership based on the notional amount using a rate equal to the six-month LIBOR (determined in arrears) minus 0.28%. The swap agreement terminates on the maturity date of the 4 5/8% Notes and interest amounts under the swap agreement are payable semiannually on the same date as interest payments on the 4 5/8% Notes. The Partnership designated the swap agreement as a fair value hedge at the inception of the agreement and elected to use the short-cut method provided for in SFAS No. 133, which assumes no ineffectiveness will result from the use of the hedge.
Interest expense in the Partnership’s income statement was reduced by $0.6 million in 2003 for the period that the hedge was outstanding. Assuming interest rates in effect at December 31, 2003, the Partnership’s interest expense would be reduced by approximately $3.8 million compared to interest expense that the Partnership would incur had it not entered into the swap agreement. Changes in LIBOR, however, will impact the interest rate expense incurred in connection with the swap agreement. A 1% increase or decrease in LIBOR would increase or decrease interest expense by $1 million.
The fair value of the swap agreement at December 31, 2003 was a gain of $0.2 million, which has been reflected in other long-term assets in the accompanying consolidated balance sheet of the Partnership. The
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2003 AND 2002 AND
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 - (Continued)
change in the fair value of the hedged debt at December 31, 2003 was a loss of $0.2 million, which has been reflected as an increase in the carrying value of the hedged debt in the accompanying consolidated balance sheet of the Partnership.
12.
Other Non-current Liabilities
Other non-current liabilities consist of the following:
13.
Pensions and Other Postretirement Benefits
Services Company sponsors a retirement income guarantee plan (a defined benefit plan) 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 postretirement 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.
A reconciliation of the beginning and ending balances of the benefit obligations under the retirement income guarantee plan and the postretirement health care and life insurance plan is as follows:
(1)
During 2001, the retirement income guaranty plan was amended to (i) exclude bonus payments, beginning with bonuses payable in 2003 and thereafter, from the definition of compensation used to calculate benefits under the plan, and (ii) provide that the annuity equivalent of the 5 percent company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2003 AND 2002 AND
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 - (Continued)
contribution, used as an offset to benefits payable under the plan, will be calculated using a 7.5 percent discount rate in lieu of the 30-year Treasury Bond rate. The 7.5 percent discount rate in lieu of the 30-year Treasury Bond rate was lowered to 7.25 percent in 2002.
A reconciliation of the beginning and ending balances of the fair value of plan assets under the retirement income guarantee plan and the postretirement health care and life insurance plan is as follows:
Amounts recognized in the Partnership’s consolidated balance sheets consist of:
Information for the Partnership’s plan with an accumulated benefit obligation in excess of plan assets is as follows:
During the year the minimum liability included in other comprehensive income increased by $348,000 related to the Partnership’s pension plans.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2003 AND 2002 AND
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 - (Continued)
The weighted average assumptions used in accounting for the retirement income guarantee plan and the postretirement health care and life insurance plan were as follows:
The assumed rate of cost increase in the postretirement health care and life insurance plan in 2003 was 10 percent for both non-Medicare eligible and Medicare eligible retirees. The assumed annual rates of cost increase decline each year through 2011 to a rate of 4.50 percent, and remain at 4.50 percent 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 percent change in the health care cost trend rate for each future year would have had the following effects on 2003 results:
The components of the net periodic benefit cost recognized for the retirement income guarantee plan and the postretirement health care and life insurance plan were as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2003 AND 2002 AND
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 - (Continued)
The Partnership estimates the following benefit payments, which reflect expected future service, as appropriate, will be paid:
The Partnership expects to contribute $1,905,000 to its pension plan in 2004.
The Partnership does not fund the postretirement health care and life insurance plan and, accordingly, no assets are invested in the plan. A summary of investments of the retirement income guarantee plan are as follows at December 31, 2003 and 2002:
The Partnership’s investment policy does not target specific asset classes, but seeks to balance the preservation and growth of capital in the Partnership’s mutual fund investment with the income derived with proceeds from the coal lease.
Services Company sponsors a retirement and savings plan (the “Retirement Plan”) through which it provides retirement benefits to substantially all of its regular full-time employees, except those covered by certain labor contracts. Norco, BGC and BT also participate in the Retirement Plan and substantially all of their regular full-time employees are covered by the Retirement Plan. Pursuant to the terms of the retirement plan, each participating company contributes 5 percent of each eligible employee’s covered salary to an employee’s separate account maintained in the Retirement Plan. In addition, Norco, BGC and BT make a matching contribution of up to 6 percent of an employee’s contributions to the Retirement Plan. Total costs of the Retirement Plan were approximately $2,488,000 in 2003, $2,222,000 in 2002 and $2,024,000 in 2001.
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 $167,000, $146,000 and $170,000 for 2003, 2002 and 2001, 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 $116,000, $101,000 and $98,000 for 2003, 2002 and 2001, respectively.
14.
Unit Option and Distribution Equivalent Plan
The Partnership has a Unit Option and Distribution Equivalent Plan (the “Option Plan”), which was approved by the Board of Directors of the General Partner on April 25, 1991 and by holders of the LP Units on October 22, 1991. The Option Plan was amended and restated on July 14, 1998. On April 24, 2002, the Board approved an Amended and Restated Unit Option and Distribution Equivalent Plan to extend the term thereof for an additional ten years and to make certain administrative changes in the Plan, the Unit Option
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2003 AND 2002 AND
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 - (Continued)
Loan Program of the General Partner and related documents. The Option Plan authorizes the granting of options (the “Options”) to acquire LP Units to selected key employees (the “Optionees”) not to exceed 720,000 LP Units in the aggregate. The price at which each LP Unit may be purchased pursuant to an Option granted under the Option Plan is generally equal to the market value on the date of the grant. Options granted prior to 1998 were granted with a feature that allowed Optionees to apply accrued credit balances (the “Distribution Equivalents”) as an adjustment to the aggregate purchase price of such Options. The Distribution Equivalents are an amount equal to (i) the Partnership’s per LP Unit regular quarterly distribution, multiplied by (ii) the number of LP Units subject to such Options that have not vested. With respect to options granted after 1997, Distribution Equivalents are paid as independent cash bonuses on the date Options vest dependent upon the percentage attainment of 3-year cash distribution targets.
Generally, options vest three years after the date of grant and are exercisable for up to 7 years following the date on which they vest. The Partnership did not record any compensation expense in 2003 related to the Option Plan. The Partnership recorded compensation expense related to the Option Plan of $1,000 in 2002 and $7,000 in 2001. Compensation and benefit costs of executive officers were not charged to the Partnership after August 12, 1997 (see Note 17).
The fair value of each option is estimated on the date of grant using the Black-Scholes option-pricing model. A portion of each option granted prior to 1998 vests after three, four and five years following the date of the grant. The assumptions used for options granted in 2003, 2002 and 2001 are indicated below.
A summary of the changes in the LP Unit options outstanding under the Option Plan as of December 31, 2003, 2002 and 2001 is as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2003 AND 2002 AND
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 - (Continued)
The following table summarizes information relating to LP Unit options outstanding under the Option Plan at December 31, 2003:
At December 31, 2003, there were 106,000 LP Units available for future grants under the Option Plan.
The Partnership also offers a unit option loan program whereby Optionees may borrow, at market rates, up to 95 percent of the purchase price of the LP Units and up to 100 percent of the applicable income tax withholding obligation in connection with such exercise. At December 31, 2003, 9 employees had outstanding loans under the unit option loan program. The aggregate borrowings outstanding at December 31, 2003 and 2002 were $1,357,000 and $1,430,000, respectively, of which $912,000 and $913,000, respectively, were related to the purchase price of the LP Units.
15.
Employee Stock Ownership Plan
Services Company provides an employee stock ownership plan (the “ESOP”) to substantially all of its regular full-time employees, except those covered by certain labor contracts. The ESOP owns all of the outstanding common stock of Services Company. At December 31, 2003, the ESOP was directly obligated to a third-party lender for $43.1 million of 7.24 percent notes (the “ESOP Notes”). The ESOP Notes are secured by Services Company common stock and are guaranteed by Glenmoor and certain of its affiliates. The proceeds from the issuance of the ESOP Notes were used to purchase Services Company common stock. 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. Prior to March 1, 2003, 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.
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 BMC for certain executive compensation costs, a reduction of the incentive compensation paid by the Partnership to BMC under the existing 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 “top-up reserve”). The Partnership will also incur ESOP-related costs for taxes associated with the sale and annual taxable income of the LP Units and for routine administrative costs.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2003 AND 2002 AND
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 - (Continued)
Total ESOP related costs charged to earnings were $1,100,000 in 2003, $1,162,000 in 2002 and $1,100,000 in 2001.
16.
Leases and Commitments
The Operating Partnerships lease certain land and rights-of-way. Minimum future lease payments for these leases as of December 31, 2003 are approximately $3.8 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 Partnerships. Buckeye leases certain computing equipment and automobiles. Future minimum lease payments under these noncancelable operating leases at December 31, 2003 were as follows: $704,000 for 2004, $712,000 for 2005, $538,000 for 2006, $114,000 for 2007, $14,000 for 2008 and none thereafter.
Buckeye entered into an energy services agreement for certain main line pumping equipment and the natural gas requirements to fuel this equipment at its Linden, New Jersey facility. Under the energy services agreement, which is designed to reduce power costs at the Linden facility, Buckeye is required to pay a minimum of $1,743,000 annually over the next eight years. This minimum payment is based on an annual minimum usage requirement of the natural gas engines at the rate of $0.049 per kilowatt hour equivalent. In addition to the annual usage requirement, Buckeye is subject to minimum usage requirements during peak and off-peak periods. Buckeye’s use of the natural gas engines has exceeded the minimum requirement in 2001, 2002 and 2003.
Rent expense under operating leases was $7,824,000, $7,285,000, and $7,700,000 for 2003, 2002 and 2001, respectively.
17.
Related Party Transactions
The Partnership and the Operating Partnerships are managed by the General Partner. Under certain partnership agreements and management agreements, BMC, the General Partner, Services Company and certain related parties are entitled to reimbursement of substantially all direct and indirect costs related to the business activities of the Partnership and the Operating Partnerships.
On May 1, 2002, an Amended and Restated Exchange Agreement (the “Amended Exchange Agreement”), among the Partnership, the Operating Partnerships, the General Partner, BMC and Glenmoor was approved in accordance with the terms of the Partnership’s Limited Partnership Agreement. The Amended Exchange Agreement, which is designed to better align the interests of the General Partner and the Partnership, was approved by the Board of Directors of Buckeye Pipe Line Company based upon a recommendation of a special committee of disinterested directors of the Board. The principal change reflected in the Amended Exchange Agreement was the elimination of the forfeiture payment provision contained in the original Exchange Agreement. The Amended Exchange Agreement also includes certain definitional and other minor changes.
As a condition of entering into the Amended Exchange Agreement, Glenmoor and the Partnership entered into an Acknowledgement and Agreement under which Glenmoor acknowledged and agreed that any tax liabilities of Glenmoor resulting from the Amended Exchange Agreement were the responsibility of Glenmoor and its subsidiaries and not the Partnership and that any funds borrowed by Glenmoor from third party lenders to pay those tax liabilities would be the responsibility of Glenmoor and its subsidiaries and not the Partnership.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2003 AND 2002 AND
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 - (Continued)
Services Company employs a significant portion of the employees that work for the Operating Partnerships. Services Company entered into a Services Agreement with BMC and the General Partner in August 1997 to provide services to the Partnership and the Operating Partnerships through March 2011. Services Company is reimbursed by BMC or the General Partner for its direct and indirect expenses, other than with respect to certain executive compensation. BMC and the General Partner are then reimbursed by the Partnership and the Operating Partnerships. Costs reimbursed to BMC, the General Partner or Services Company by the Partnership and the Operating Partnerships totaled $65.4 million, $60.5 million and $58.4 million in 2003, 2002 and 2001, 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 2,441,510 LP Units (approximately 8.5 percent of the LP Units outstanding) as of December 31, 2003. Distributions received by Services Company on such LP Units are used to fund obligations of the ESOP. Distributions paid to Services Company totaled $6,226,000, $6,188,000 and $6,121,000 in 2003, 2002 and 2001, respectively. In addition, the Partnership recorded ESOP-related costs of $1,100,000, $1,162,000 and $1,100,000 in 2003, 2002 and 2001, respectively (see Note 15).
Glenmoor and BMC are entitled to receive an annual management fee for certain management functions they provide to the General Partner pursuant to a Management Agreement among Glenmoor, BMC and the General Partner. The disinterested directors of the General Partner approve the amount on a annual basis. The management fee includes a Senior Administrative Charge of not less than $975,000 and reimbursement for certain costs and expenses. Amounts paid to Glenmoor and BMC in 2003 amounted to $1,929,000, including $975,000 for the Senior Administrative Charge and $954,000 of reimbursed expenses. Amounts paid to Glenmoor and BMC in each of the years 2002 and 2001 for management fees were $1,906,000 and $1,984,000, respectively, including $975,000 for the Senior Administrative Charge and $931,000 and $1,009,000, respectively of reimbursed expenses. The Senior Administration charge and reimbursed expenses are charged to the Partnership.
The General Partner receives incentive compensation payments from the Partnership pursuant to an incentive compensation agreement based upon the level of quarterly cash distributions paid per LP Unit. Incentive compensation payments totaled $11,877,000, $10,838,000 and $10,272,000 in 2003, 2002 and 2001, respectively. The incentive compensation payments are included in “minority interests and other” expense on the Consolidated Statements of Income. In April 2001, in order to better align the interests of the Partnership and the General Partner, the Partnership and the General Partner entered into the Second Amended and Restated Incentive Compensation Agreement (“Incentive Compensation Agreement”). The principal change reflected in the Incentive Compensation Agreement was the elimination prospectively of a cap on aggregate incentive compensation payments to the General Partner effective December 31, 2005, or earlier, if distributions on LP Units equal or exceed $.6375 per LP Unit for four consecutive quarterly periods ($2.55 annually) (see Note 19). The amendment was approved in accordance with the Partnership Agreement by the Board of Directors of the General Partner based upon a recommendation of a special committee of disinterested members of the Board.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2003 AND 2002 AND
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 - (Continued)
18.
Partners’ Capital
Changes in partners’ capital for the years ended December 31, 2001, 2002, and 2003 were as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2003 AND 2002 AND
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 - (Continued)
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 additional LP Units of a class or series having preferences or other special or senior rights over the LP Units.
The receivable from the exercise of options is due from Services Company for notes issued under the unit option loan program (see Note 14). The notes are full recourse promissory notes due from Optionees, bearing market rates of interest.
On February 28, 2003, the Partnership sold 1,750,000 LP units in an underwritten public offering at a price of $36.01 per LP unit. Proceeds to the Partnership, net of underwriters’ discount of $1.62 per LP unit and offering expenses, were approximately $59.9 million.
19.
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. In 2003, a quarterly distribution of $0.625 per GP and LP Unit was paid in February, and distributions of $0.6375 per GP and LP Unit were paid in May, August and November. In 2002, quarterly distributions of $0.625 per GP and LP Unit were paid in February, May, August and November. In 2001, quarterly distributions of $0.60 per GP and LP Unit were paid in February and May, and $0.625 per GP and LP Unit were paid in August and November. All such distributions were paid on the then outstanding GP and LP Units. Cash distributions aggregated $72,375,000 in 2003, $67,932,000 in 2002 and $66,464,000 in 2001.
On January 28, 2004, the Partnership announced a quarterly distribution of $0.65 per unit payable on February 27, 2004 to Unitholders of record on February 4, 2004. The distribution was paid on February 27, 2004 and represented the fourth consecutive quarterly distribution equal to or greater than $.6375 per LP Unit, and therefore met the requirement to eliminate a previous cap on aggregate incentive compensation payments to the General Partner (see Note 17).
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2003 AND 2002 AND
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 - (Continued)
20.
Quarterly Financial Data (Unaudited)
Summarized quarterly financial data for 2003 and 2002 are set forth below. Quarterly results were influenced by seasonal and other factors inherent in the Partnership’s business.
21.
Earnings Per Unit
The following is a reconciliation of basic and dilutive income from continuing operations per LP Unit for the years ended December 31, 2003, 2002 and 2001:
Options reported as dilutive securities are related to unexercised options outstanding under the Option Plan (see Note 14).
22.
Subsequent Event
On March 5, 2004, the stockholders of Glenmoor entered into a definitive agreement to sell Glenmoor to a new entity formed by Carlyle/ Riverstone Global Energy and Power Fund II, L.P. The transaction is scheduled to close in the second quarter of 2004, and is subject to certain conditions, including applicable regulatory approvals and other customary closing conditions. The parties did not disclose the financial terms of the transaction.
Item 9.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not applicable.
Item 9A.
Item 9A.
Controls and Procedures
(a) Evaluation of disclosure controls and procedures.
The management of the General Partner, with the participation of the General Partner’s principal executive officer and its principal financial officer, evaluated the effectiveness of the Partnership’s disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the General Partner’s principal executive officer and its principal financial officer concluded that the partnership’s disclosure controls and procedures as of the end of the period covered by this report have been designed and are functioning effectively to provide reasonable assurance that the information required to be disclosed by the Partnership in reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The Partnership believes that a controls system, no matter how well designed and operated, cannot provide absolute assurance 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) Changes in internal controls.
No change in the Partnership’s internal control over financial reporting occurred during the Partnership’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Partnership’s internal control over financial reporting.
PART III
Item 10.
Item 10.
Directors and Executive Officers of the Registrant
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 Partnerships in their capacities as officers and directors of the General Partner and Services Company. Directors and officers of the General Partner are selected by BMC. See “Certain Relationships and Related Transactions.”
Directors of the General Partner
Set forth below is certain information concerning the directors of the General Partner.
*
Also a director of Services Company.
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 BMC and Services Company.
Name, Age and
Business Experience During
Present Position
Past Five Years
Stephen C. Muther, 54
Senior Vice President - Administration, General Counsel and Secretary
Mr. Muther has been Senior Vice President - Administration, General Counsel and Secretary of the General Partner for more than five years.
Steven C. Ramsey, 49
Senior Vice President - Finance and Chief Financial Officer
Mr. Ramsey has been Senior Vice President - Finance and Chief Financial Officer of the General Partner for more than five years.
Section 16(a) Beneficial Ownership Reporting Compliance
Pursuant to Section 16 (a) of the Exchange Act, the Company’s executive officers and directors, and persons beneficially owning more than 10 percent of the Partnership’s LP Units, are required to file with the Commission reports of their initial ownership and changes in ownership of common shares. The Company believes that for 2003, its executive officers and directors who were required to file reports under Section 16 (a) complied with such requirements in all material respects.
The Board of Directors
Audit Committee
The General Partner has an audit committee (the “Audit Committee”) comprised of four board members who are “independent” as that term is defined in Rule 10A-3 of the Exchange Act and as that term is used in applicable listing standards of the New York Stock Exchange. The members of the Audit
Committee are Brian F. Billings (Chairman), Edward F. Kosnik, Frank S. Sowinski and Jonathan O’Herron. The members of the Audit Committee are non-employee directors of the General Partner and are not officers, directors or otherwise affiliated with the General Partner or its parent companies. Our Board of Directors has determined that no Audit Committee member has a material relationship with the Company. Our Board of Directors has also determined that each member of the Audit Committee qualifies as an audit committee financial expert as defined in Item 401(h) of Regulations S-K.
The Audit Committee provides independent oversight with respect to our internal controls, accounting policies, financial reporting, internal audit function and the independent auditors. The Audit Committee also reviews the scope and quality, including the 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 charter of the Audit Committee is available at our website at www.buckeye.com.
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 our website at www.buckeye.com.
Finance Committee
The General Partner has a Finance Committee, which currently consists of three directors: Edward F. Kosnik, Jonathan O’Herron and Ernest R. Varalli. 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 of any of the foregoing upon receipt of a written request.
Item 11.
Item 11.
Executive Compensation
Director Compensation
The fee schedule for directors of the General Partner is as follows: annual fee, $25,000; attendance fee for each Board of Directors meeting, $1,000; and attendance fee for each committee meeting, $750. Messrs. Alfred and David Martinelli, Shea, and Varalli do not receive any fees as directors. Directors’ fees paid by the General Partner in 2003 to its directors amounted to $215,000. The directors’ fees were reimbursed by the Partnership. Members of the Board of Directors of BMC and Services Company are not separately compensated for their services as directors.
Executive Compensation
As part of a restructuring of the ESOP in 1997, the Partnership and the Operating Partnerships were permanently released from their 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.
Executive Officer Severance Agreements
BMC, Services Company and Glenmoor have entered into severance agreements with Stephen C. Muther, Senior Vice President - Administration, General Counsel and Secretary and Steven C. Ramsey, Senior Vice President - Finance and Chief Financial Officer. The severance agreements provide for 1.5 times the officer’s annual base salary and incentive compensation as of May 1997 (the “Severance Compensation Amount”) upon termination of such individual’s employment without “cause” under certain circumstances not involving a “change of control” of the Partnership, and 2.99 times such individual’s Severance Compensation Amount (subject to certain limitations) following a “change of control.” For purposes of the severance agreements, a “change of control” is defined as the acquisition (other than by the General Partner and its affiliates) of 80 percent or more of the LP Units of the Partnership, 51 percent or more of the general partnership interests owned by the General Partner or 50 percent or more of the voting equity interest of the Partnership and the General Partner on a combined basis. Certain costs incurred under the severance agreements are to be reimbursed by the Partnership.
Equity Compensation Plan Information
The following table sets forth information as of December 31, 2003 with respect to compensation plans under which equity securities of the Partnership are authorized for issuance.
(1)
This plan is the Amended and Restated Unit Option and Distribution Equivalent Plan of the Partnership.
Director Recognition Program
The General Partner has adopted the Director Recognition Program (the “Recognition Program”) that had been instituted by BMC in September 1997. The Recognition Program provides that, upon retirement or death and subject to certain conditions, directors receive a recognition 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 the General Partner or BMC. 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 the General Partner or its affiliates are not eligible for the Recognition Program. No expenses were recorded under this program during 2003, 2002 and 2001. Mr. Hahl, who resigned from the Board of Directors in April 2001, was paid $75,000 under the Recognition Program at the time of his resignation.
Item 12.
Item 12.
Security Ownership of Certain Beneficial Owners and Management
Services Company owns approximately 8.5 percent of the outstanding LP Units as of February 23, 2004. No other person or group is known to be the beneficial owner of more than 5 percent of the LP Units as of February 23, 2004.
The following table sets forth certain information, as of March 11, 2004, concerning the beneficial ownership of LP Units by each director of the General Partner, the Chief Executive Officer of the General
Partner, the four most highly compensated officers of the General Partner and by all directors and executive officers of the General Partner as a group. Such information is based on data furnished by the persons named. Based on information furnished to the General Partner by such persons, no director or executive officer of the General Partner owned beneficially, as of March 11, 2004, more than 1 percent of any class of equity securities of the Partnership or any of its 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)
The LP Units owned by the persons indicated have shared voting and investment power with their respective spouses.
(3)
4,600 of the LP Units have shared voting and investment power with his spouse.
Item 13.
Item 13.
Certain Relationships and Related Transactions
The Partnership and the Operating Partnerships are managed by the General Partner pursuant to the Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”), the several Amended and Restated Agreements of Limited Partnership of the Operating Partnerships (the “Operating Partnership Agreements”) and the several Management Agreements between the General Partner and the Operating Partnerships (the “Management Agreements”). BMC, which had been general partner of the Partnership, contributed its general partnership interest and certain other assets to the General Partner effective December 31, 1998. The General Partner is a wholly-owned subsidiary of BMC.
Under the Partnership Agreement and the Operating Partnership Agreements, as well as the Management Agreements, the General Partner and certain related parties are entitled to reimbursement of all direct and indirect costs and expenses related to the business activities of the Partnership and the Operating Partnerships, except as otherwise provided by the Exchange Agreement (as discussed below). These costs and expenses include insurance fees, consulting fees, general and administrative costs, compensation and benefits payable to employees of the General Partner (other than certain executive officers), tax information and reporting costs, legal and audit fees and an allocable portion of overhead expenses. Such reimbursed amounts constitute a substantial portion of the revenues of the General Partner.
Glenmoor owns all of the common stock of BMC. Glenmoor is owned by certain directors and members of senior management of the General Partner or trusts for the benefit of their families and certain director-level employees of Services Company.
Glenmoor and BMC are entitled to receive an annual management fee for certain management functions they provide to the General Partner pursuant to a Management Agreement among Glenmoor, BMC and the General Partner. The disinterested directors of the General Partner approve the amount on a periodic basis. The management fee includes a Senior Administrative Charge of not less than $975,000 and reimbursement
for certain costs and expenses. Amounts paid to Glenmoor and BMC in 2003 amounted to $1,929,000 million, including $975,000 for the Senior Administrative Charge and $954,000 million of reimbursed expenses. Amounts paid to Glenmoor and BMC in the years 2002 and 2001 for management fees equaled $1,906,000 and $1,984,000 respectively, including $975,000 for the Senior Administrative Charge in each year. The management fee also included $931,000 and $1,009,000, respectively of reimbursed expenses in years 2002 and 2001.
The General Partner receives incentive compensation payments from the Partnership pursuant to an incentive compensation agreement. In April 2001, the Partnership and the General Partner entered into the Second Amended and Restated Incentive Compensation Agreement (the “Incentive Compensation Agreement”). The Incentive Compensation Agreement provides that, subject to certain limitations and adjustments, if a quarterly cash distribution exceeds a target of $0.325 per LP Unit, the Partnership will pay the General Partner, in respect of each outstanding LP Unit, incentive compensation equal to (i) 15 percent of that portion of the distribution per LP Unit which exceeds the target quarterly amount of $0.325 but is not more than $0.35, plus (ii) 25 percent of the amount, if any, by which the quarterly distribution per LP Unit exceeds $0.35 but is not more than $0.375, plus (iii) 30 percent of the amount, if any, by which the quarterly distribution per LP Unit exceeds $0.375 but is not more than $0.40, plus (iv) 35 percent of the amount, if any, by which the quarterly distribution per LP Unit exceeds $0.40 but is not more than $0.425, plus (v) 40 percent of the amount, if any, by which the quarterly distribution per LP Unit exceeds $0.425 but is not more than $0.525, plus (vi) 45 percent of the amount, if any, by which the quarterly distribution per LP Unit exceeds $0.525. The General Partner is also entitled to incentive compensation, under a comparable formula, in respect of special cash distributions exceeding a target special distribution amount per LP Unit. The target special distribution amount generally means the amount which, together with all amounts distributed per LP Unit prior to the special distribution compounded quarterly at 13 percent per annum, would equal $10.00 (the initial public offering price of the LP Units split two-for-one) compounded quarterly at 13 percent per annum from the date of the closing of the initial public offering in December 1986. The principal change reflected in the Incentive Compensation Agreement was the elimination prospectively of a cap on aggregate incentive compensation payments to the General Partner effective December 31, 2005, or earlier if distributions on LP Units equal or exceed $.6375 per LP Unit for four consecutive quarterly periods ($2.55 annually). The amendments, which were designed to more closely align the interests of the General Partner and the Partnership, were approved by the Board of Directors of the General Partner based on a recommendation of a special committee of disinterested members of the Board. Incentive compensation paid by the Partnership for quarterly cash distributions totaled $11,877,000, $10,838,000, and $10,272,000 in 2003, 2002 and 2001, respectively. No special cash distributions have ever been paid by the Partnership.
On January 28, 2004, the Partnership announced a quarterly distribution of $0.65 per unit payable on February 27, 2004 to Unitholders of record on February 4, 2004. The distribution was paid on February 27, 2004 and represented the fourth consecutive quarterly distribution equal to or greater than $.6375 per LP Unit, and therefore met the requirement to eliminate a previous cap on aggregate incentive compensation payments to the General Partner.
The following chart depicts the ownership relationships among the Partnership, the General Partner and various other parties:
CHART OF BUCKEYE-RELATED ORGANIZATIONS
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 of the Partnership’s annual financial statements, reviews of the Partnership’s quarterly financial statements, and comfort letters, consents and other services related to Security and Exchange Commission (“SEC”) matters.
(2)
Audit-related fees consist principally of fees for audits of financial statements of certain employee benefits plans and Glenmoor.
(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, Financial Statement Schedules, and Reports on Form 8-K
(a) The following documents are filed as a part of this Report:
(1) and (2) Financial Statements and Financial Statement Schedule - see Index to Financial Statements and Financial Statement Schedule appearing on page 33.
(3) 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.
*
filed herewith
(1)
Previously filed with the Securities and Exchange Commission as the Exhibit to the Buckeye Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended March 31, 2002.
(2)
The Amended and Restated Agreements of Limited Partnership of the other Operating Partnerships are not filed because they are identical to Exhibit 10.1 except for the identity of the partnership.
(3)
The Management Agreements of the other Operating Partnerships are not filed because they are identical to Exhibit 10.2 except for the identity of the partnership.
(4)
Represents management contract or compensatory plan or arrangement.
(5)
Previously filed with the Securities and Exchange Commission as the Exhibit to the Buckeye Partners, L.P. Annual Report on Form 10-K for the year 1997.
(6)
Previously filed with the Securities and Exchange Commission as the Exhibit to the Buckeye Partners, L.P. Annual Report on Form 10-K for the year 1998.
(7)
Previously filed with the Securities and Exchange Commission as the Exhibit to the Buckeye Partners, L.P. Annual Report on Form 10-K for the year 1999.
(8)
Previously filed with the Securities and Exchange Commission as the Exhibit to the Buckeye Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended June 30, 2001.
(9)
Previously filed with the Securities and Exchange Commission as the Exhibit to the Buckeye Partners, L.P. Annual Report on Form 10-K for the year 2001.
(10)
Previously filed with the Securities and Exchange Commission as the Exhibit to the Buckeye Partners, L.P. Annual Report on Form 10-K for the year 2002.
(11)
Previously filed as an exhibit to the registrant’s Registration Statement on Form S-4 (Registration No. 333-108969) filed on September 19, 2003.
(12)
Previously filed with the Securities and Exchange Commission as the Exhibit to the Buckeye Partners, L.P. Annual Report on Form 10-Q for the quarter ended September 30, 2003.
(b) Reports on Form 8-K during the quarter ended December 31, 2003.
(1) On October 24, 2003, the Partnership filed a Current Report on Form 8-K for the purpose of furnishing the press release announcing its earnings for the third quarter 2003.
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 Pipe Line Company,
as General Partner
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.