UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

 

For the transition period from                  to

Commission file number 1-9356

Buckeye Partners, L.P.

(Exact name of registrant as specified in its charter)

 

Registrant’s telephone number, including area code: (610) 904-4000

Securities registered pursuant to Section 12(b) of the Act:

 

Securities registered pursuant to Section 12(g) of the Act:

None
(Title of class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ   No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o   No þ

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  þ      Accelerated filer o      Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act) Yes o   No þ

At June 30, 2006, the aggregate market value of the registrant’s LP Units held by non-affiliates was $1.6 billion. The calculation of such market value should not be construed as an admission or conclusion by the registrant that any person is in fact an affiliate of the registrant.

LP Units outstanding as of February 15, 2007: 39,472,446

TABLE OF CONTENTS

				Page
PART I
Item 1.		Business			2
Item 1A.		Risk Factors			22
Item 1B.		Unresolved Staff Comments			31
Item 2.		Properties			31
Item 3.		Legal Proceedings			31
Item 4.		Submission of Matters to a Vote of Security Holders			32
PART II
Item 5.		Market for the Registrant’s LP Units, Related Unitholder Matters, and Issuer Purchases of LP Units			33
Item 6.		Selected Financial Data			34
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			34
Item 7A.		Quantitative and Qualitative Disclosures About Market Risk			55
Item 8.		Financial Statements and Supplementary Data			57
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			96
Item 9A.		Controls and Procedures			96
Item 9B.		Other Information			96
PART III
Item 10.		Directors, Executive Officers and Corporate Governance			97
Item 11.		Executive Compensation			101
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters			114
Item 13.		Certain Relationships and Related Transactions and Director Independence			115
Item 14.		Principal Accountant Fees and Services			118
PART IV
Item 15.		Exhibits and Financial Statement Schedule			119

 

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PART I

Item 1.                        Business

Introduction

Buckeye Partners, L.P. (the “Partnership”) is a publicly traded (NYSE symbol: BPL) master limited partnership organized in 1986 under the laws of the State of Delaware. The Partnership is principally engaged in the transportation, terminalling and storage of refined petroleum products for major integrated oil companies, large refined products marketing companies and major end users of petroleum products on a fee basis through facilities owned and operated by the Partnership. The Partnership also operates pipelines owned by third parties under contracts with major integrated oil and chemical companies and performs pipeline construction activities, generally for these same customers. Buckeye GP LLC (the “General Partner”), a Delaware limited liability company, is the general partner of the Partnership.

The Partnership owns and operates one of the largest independent refined petroleum products pipeline systems in the United States in terms of volumes delivered, with approximately 5,400 miles of pipeline, serving 17 states, and operates approximately 2,500 miles of other pipelines under agreements with major oil and chemical companies. The Partnership also owns and operates 45 active refined petroleum products terminals with aggregate storage capacity of approximately 17.6 million barrels in Illinois, Indiana, Massachusetts, Michigan, Missouri, New York, Ohio and Pennsylvania.

The Partnership’s pipelines service approximately 100 delivery locations, transporting refined petroleum products, including gasoline, jet fuel, diesel fuel, heating oil, kerosene and natural gas liquids from major supply sources to terminals and airports located within end-use markets. These pipelines also transport other refined products, such as propane and butane, refinery feedstocks and blending components. The Partnership’s transportation services are typically provided on a common carrier basis under published tariffs for customers. The Partnership’s geographical diversity, connections to multiple sources of supply and extensive delivery system help create a stable base business. The Partnership is an independent transportation provider that is not affiliated with any oil company or marketer of refined petroleum products and generally does not own the petroleum products that it transports.

The Partnership currently conducts all of its operations through seven operating subsidiaries, which are referred to as the “Operating Subsidiaries”:

·       Buckeye Pipe Line Company, L.P. (“Buckeye”), which owns an approximately 2,643-mile interstate common carrier refined petroleum products pipeline system serving major population centers in eight states. It is the primary jet fuel transporter to John F. Kennedy International Airport (“JFK”), LaGuardia Airport, Newark Liberty International Airport and certain other airports within its service territory.

·       Laurel Pipe Line Company, L.P. (“Laurel”), which owns an approximately 345-mile refined petroleum products pipeline connecting five Philadelphia area refineries to 10 delivery points across Pennsylvania.

·       Wood River Pipe Lines LLC (“Wood River”), which owns six refined petroleum products pipelines with aggregate mileage of approximately 925 miles located in Illinois, Indiana, Missouri and Ohio.

·       Buckeye Pipe Line Transportation LLC (“BPL Transportation”), which owns a refined petroleum  products pipeline system with aggregate mileage of approximately 478 miles located in New Jersey, New York, and Pennsylvania.

·       Everglades Pipe Line Company, L.P. (“Everglades”), which owns an approximately 37-mile intrastate common carrier refined petroleum products pipeline connecting Port Everglades, Florida to

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Ft. Lauderdale-Hollywood International Airport and Miami International Airport. It is the primary jet fuel provider to Miami International Airport.

·       Buckeye NGL Pipe Lines LLC (“Buckeye NGL”), which owns an approximate 350-mile  natural gas liquids pipeline, acquired in January 2006, extending generally from the Wattenberg, Colorado area to Bushton, Kansas.

·       Buckeye Pipe Line Holdings, L.P. (“BPH”), which, through its subsidiary Buckeye Terminals, LLC (“Buckeye Terminals”), owns (or in certain instances leases from other Operating Subsidiaries) and operates 45 refined petroleum products terminals with aggregate storage capacity of approximately 17.6 million barrels. BPH also owns interests in 574 miles of pipelines in the Midwest, Southwest and West Coast. BPH operates, through its subsidiary Buckeye Gulf Coast Pipe Lines, L.P. (“BGC”), pipelines in the Gulf Coast region for third parties. BPH also holds minority stock interests in two midwest refined petroleum products pipelines and a natural gas liquids pipeline system.

Beginning in the fourth quarter of 2004 and continuing into 2006, the Partnership substantially expanded its business operations through equity investments and asset acquisitions of approximately $850.0 million. As a result , in 2005 the Partnership redesigned the financial information it regularly provides to management and, based on the nature of the new information, determined in the fourth quarter of 2005 that its operations are appropriately presented in three reportable operating segments: (i) Pipeline Operations, (ii) Terminalling and Storage and (iii) Other Operations.

Significant Events in 2006

Asset Acquisitions

On January 1, 2006, the Partnership acquired a refined petroleum products terminal located in Niles, Michigan from affiliates of Shell Oil Products, U.S. (“Shell”) for $13.0 million.

On January 31, 2006, the Partnership acquired a natural gas liquids pipeline, which extends generally from Wattenberg, Colorado to Bushton, Kansas, from BP Pipelines (North America) Inc. for approximately $87.0 million.

Initial Public Offering of the Parent of the General Partner

On August 9, 2006, Buckeye GP Holdings L.P. (“BGH”), the owner of the General Partner, sold 10.5 million common units in an underwritten initial public offering (“IPO”), the net proceeds of which were approximately $167.4 million. BGH used the net proceeds from the IPO, along with cash on hand, to repay certain outstanding indebtedness under its term loan and to make distributions to its pre-IPO equity owners. Following the IPO, approximately 54% of the limited partner units of BGH are owned by affiliates of Carlyle/Riverstone Global Energy and Power Fund II L.P. (“Carlyle Riverstone”), approximately 9% are owned by certain members of senior management of the Partnership and the remaining approximately 37% is owned by the public.

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The following chart depicts the Partnership’s and BGH’s ownership structure as of December 31, 2006.

Ownership of Buckeye Partners, L.P. and Buckeye GP Holdings L.P.

Ownership percentages in the chart are approximate.

Business Activities

The following discussion describes the business activities of the Partnership’s operating segments. Detailed information regarding revenues, operating income and total assets of each segment can be found in Note 20, Segment Information, to the Partnership’s consolidated financial statements.

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Pipeline Operations

The Partnership owns and operates petroleum products pipelines which receive petroleum products from refineries, connecting pipelines and bulk and marine terminals, and transports those products to other locations. In 2006, the Pipeline Operations segment accounted for approximately 76% of the Partnership’s consolidated revenues.

The Partnership transported an average of approximately 1,450,300 barrels of petroleum products per day in 2006. The following table shows the volume and percentage of refined petroleum products transported over the last three years.

Volume and Percentage of Petroleum Products Transported(1)
(Volume in thousands of barrels per day)

(1)          Excludes local product transfers.

(2)          Includes diesel fuel, heating oil, kerosene and other middle distillates.

The Partnership provides pipeline transportation service in the following states: California, Colorado, Connecticut, Florida, Illinois, Indiana, Kansas, Massachusetts, Michigan, Missouri, New Jersey, Nevada, New York, Ohio, Pennsylvania and Tennessee.

Pennsylvania—New York—New Jersey

Buckeye serves major population centers in Pennsylvania, New York and New Jersey through approximately 928 miles of pipeline. Refined petroleum products are received at Linden, New Jersey from 17 major source points, including two refineries, six connecting pipelines and nine storage and terminalling facilities. Products are then transported through two lines from Linden, New Jersey to Macungie, Pennsylvania. From Macungie, the pipeline continues west through a connection with the Laurel pipeline to Pittsburgh, Pennsylvania (serving Reading, Harrisburg, Altoona/Johnstown and Pittsburgh, Pennsylvania) and north through eastern Pennsylvania into New York (serving Scranton/Wilkes-Barre, Binghamton, Syracuse, Utica, Rochester and, via a connecting carrier, Buffalo, New York). Buckeye leases capacity in one of the pipelines extending from Pennsylvania to upstate New York to a major oil pipeline company. Products received at Linden, New Jersey are also transported through one line to Newark International Airport and through two additional lines to JFK and LaGuardia airports and to commercial refined petroleum products terminals at Long Island City and Inwood, New York. These pipelines supply JFK, LaGuardia and Newark airports with substantially all of each airport’s jet fuel requirements.

In addition, BPL Transportation’s pipeline system delivers refined petroleum products from the Valero refinery located in Paulsboro, New Jersey to destinations in New Jersey, Pennsylvania, and New York. A portion of the pipeline system extends from Paulsboro, New Jersey to deliver products to Malvern, Pennsylvania. From Malvern, a pipeline segment delivers refined products to locations in upstate New York, while another segment delivers products to central Pennsylvania. Two shorter pipeline

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segments connect the Valero refinery to the Colonial pipeline system and the Philadelphia International Airport, respectively.

The Laurel pipeline system transports refined petroleum products through a 345-mile pipeline extending westward from five refineries and a connection to the Colonial pipeline system in the Philadelphia area to Reading, Harrisburg, Altoona/Johnstown and Pittsburgh, Pennsylvania.

Illinois—Indiana—Michigan—Missouri—Ohio

Buckeye and Norco Pipe Line Company, LLC (“Norco”), a subsidiary of BPH, transport refined petroleum products through 2,025 miles of pipeline in northern Illinois, central Indiana, eastern Michigan, western and northern Ohio and western Pennsylvania. A number of receiving lines and delivery lines connect to a central corridor which runs from Lima, Ohio through Toledo, Ohio to Detroit, Michigan. Refined petroleum products are received at a refinery and other pipeline connection points near Toledo, Lima, Detroit and East Chicago, Indiana. Major market areas served include Peoria, Illinois; Huntington/Fort Wayne, Indianapolis and South Bend, Indiana; Bay City, Detroit and Flint, Michigan; Cleveland, Columbus, Lima and Toledo, Ohio and Pittsburgh, Pennsylvania.

Wood River owns six refined petroleum products pipelines with aggregate mileage of approximately 925 miles located in the midwestern United States. Refined petroleum products are received at the ConocoPhillips Wood River refinery in Illinois and transported to the Chicago area, to a terminal in the St. Louis, Missouri area to the Lambert-St. Louis Airport, to receiving points across Illinois and Indiana and to Buckeye’s pipeline in Lima, Ohio. At the Partnership’s tank farm located in Hartford, Illinois, one of Wood River’s pipelines also receives refined petroleum products from the Explorer pipeline, which are transported to the Partnership’s 1.3 million barrel terminal located on the Ohio River in Mt. Vernon, Indiana.  Wood River also owns an approximately 26-mile pipeline that extends from Marathon’s Wood River Station in southern Illinois to a third party terminal in the East St. Louis, Missouri area.

Colorado—Kansas

Buckeye NGL transports natural gas liquids via an approximately 350-mile pipeline, acquired in January 2006, that extends generally from the Wattenberg, Colorado area to Bushton, Kansas.

Other Refined Products Pipelines

Buckeye serves Connecticut and Massachusetts through an approximately 112-mile pipeline (the “Jet Lines System”) that carries refined petroleum products from New Haven, Connecticut to Hartford, Connecticut and Springfield, Massachusetts.

Everglades transports primarily jet fuel on an approximately 37-mile pipeline from Port Everglades, Florida to Ft. Lauderdale-Hollywood International Airport and Miami International Airport. Everglades supplies Miami International Airport with substantially all of its jet fuel requirements.

WesPac Pipelines—Reno LLC (“WesPac Reno”) owns an approximately 3.0 mile pipeline serving the Reno/Tahoe International Airport. WesPac Pipelines—San Diego LLC (“WesPac San Diego”) owns an approximately 4.3 mile pipeline serving the San Diego International Airport. WesPac Pipelines—Memphis LLC (“WesPac Memphis”) owns and operates an approximately 11-mile pipeline and related terminal facilities that  primarily serve Federal Express Corporation at the Memphis International Airport. Each of the WesPac entities originally was a joint venture between BPH and Kealine Partners LLC. In May 2005, BPH purchased the membership interest in WesPac Reno owned by Kealine Partners for approximately $2.5 million. Since this purchase, BPH has owned 100% of WesPac Reno. BPH has a 75% ownership interest in WesPac Memphis and a 50% ownership interest in WesPac San Diego. Kealine

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Partners owns the remaining interest in these two joint ventures. As of December 31, 2006, the Partnership had provided $52.8 million in intercompany financing  to these WesPac entities.

Equity Investments

BPH owns a 24.99% equity interest in West Shore Pipe Line Company (“West Shore”). West Shore owns a pipeline system that originates in the Chicago, Illinois area and extends north to Green Bay, Wisconsin and west and then north to Madison, Wisconsin. The pipeline system transports refined petroleum products to markets in northern Illinois and Wisconsin. The other equity holders of West Shore are major oil companies. The pipeline is operated under contract by Citgo Pipeline Company.

BPH also owns a 20% equity interest in West Texas LPG Pipeline Limited Partnership (“WTP”). WTP owns a pipeline system that delivers natural gas liquids to Mont Belvieu, Texas for fractionation.  The natural gas liquids are delivered to the WTP pipeline system from the Rocky Mountain region via connecting pipelines and from gathering fields located in west and central Texas. The majority owners and the operators of WTP are affiliates of ChevronTexaco, Inc.

BPH also owns a 40% equity interest in Muskegon Pipeline LLC (“Muskegon”). The majority owner of Muskegon is Marathon Pipe Line LLC (“Marathon”). Muskegon owns an approximately 170-mile pipeline that delivers petroleum products from Griffith, Indiana to Muskegon, Michigan. The pipeline is operated by Marathon Pipe Line LLC.

Terminalling and Storage

Through BPH and its subsidiary, Buckeye Terminals, the Partnership’s Terminalling and Storage segment owns and operates 45 terminals located in Illinois, Indiana, Massachusetts, Michigan, Missouri, New York, Ohio and Pennsylvania that provide bulk storage and throughput services and have the capacity to store an aggregate of approximately 17.6 million barrels of refined petroleum products. In addition, Buckeye Terminals owns four currently idle terminals with an aggregate storage capacity of approximately 863,000 barrels. In 2006, the Terminalling and Storage segment accounted for approximately 18% of the Partnership’s consolidated revenue.

The Partnership’s refined petroleum products terminals receive products from pipelines (and, in certain cases, barges) and distribute them to third parties, who in turn deliver them to end-users and retail outlets. The Partnership’s refined petroleum products terminals play a key role in moving refined products to the end-user market by providing storage and inventory management, distribution, blending to achieve specified grades of gasoline, and other ancillary services that include the injection of ethanol and other additives. Typically, the Partnership’s terminal facilities consist of multiple storage tanks and are equipped with automated truck loading equipment that is available 24 hours a day.

The Partnership’s refined petroleum products terminals derive most of their revenues from terminalling fees paid by customers. A fee is charged for receiving refined petroleum products into the terminal and delivering them to trucks, barges, or pipelines. In addition to terminalling fees, the Partnership’s revenues are generated by charging customers fees for blending and injecting additives, and, in certain instances, leasing terminal capacity to customers on either a short-term or long-term basis. Of the Partnership’s 45 refined petroleum products terminals, 32 are connected to the Partnership’s pipelines and 13 are not.

The table below sets forth the total average daily throughput for the refined petroleum products terminals in each of the years presented:

 

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The following table outlines the number of terminals and storage capacity in barrels (“bbls”) by state as of December 31, 2006:

Other Operations

The business of the Partnership’s Other Operations segment consists primarily of pipeline operation and maintenance services and pipeline construction services for third parties pursuant to contractual arrangements. BGC is a contract operator of pipelines owned in Texas by major petrochemical companies. BGC currently has 14 operations and maintenance contracts in place to operate and maintain approximately 2,500 miles of pipeline. In addition, BGC owns an approximately 23-mile pipeline located in Texas and leases a portion of the pipeline to a third-party chemical company. Subsidiaries of BGC also own an approximate 63% interest in a crude butadiene pipeline between Deer Park, Texas and Port Arthur, Texas. Volumes of crude butadiene are transported on this line, known as the Sabina pipeline. BGC also owns and operates an ammonia pipeline located in Texas that was acquired in November 2005. In addition, BGC also provides engineering and construction management services to major chemical companies in the Gulf Coast area. In 2006, the Other Operations segment accounted for approximately 6% of the Partnership’s consolidated revenue.

Competition and Other Business Considerations

The Operating Subsidiaries conduct business without the benefit of exclusive franchises from government entities. In addition, the Operating Subsidiaries’ pipeline operations generally operate as common carriers, providing transportation services at posted tariffs and without long-term contracts. The Operating Subsidiaries generally do not own the products they transport. Demand for the services provided by the Operating Subsidiaries derives from demand from end users for petroleum products in the regions served and the ability and willingness of refiners and marketers to supply such demand by deliveries through the Operating Subsidiaries’ pipelines. Demand for refined petroleum products is primarily a function of price, prevailing general economic conditions and weather. The Operating Subsidiaries’ businesses are, therefore, subject to a variety of factors partially or entirely beyond their control. Multiple sources of pipeline entry and multiple points of delivery, however, have historically helped maintain stable total volumes even when volumes at particular source or destination points have changed.

The consolidated Partnership customer base was approximately 214 customers in 2006 and 160 customers in 2005. Affiliates of Shell contributed 11% in 2006 and 13% in 2005 of consolidated Partnership revenue. For the year ended December 31, 2004, no customer contributed more than 10% of consolidated revenue. Approximately 5% of the 2006 consolidated revenue was generated by Shell in the Pipeline Operations segment; the remaining 6% of consolidated revenue was in the Terminalling and Storage segment. The 20 largest customers accounted for 53% and 63% of consolidated Partnership revenue in 2006 and 2005, respectively.

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Generally, pipelines are the lowest cost method for long-haul overland movement of refined petroleum products. Therefore, the Operating Subsidiaries’ most significant competitors for large volume shipments are other pipelines, some of which are owned or controlled by major integrated oil companies. Although it is unlikely that a pipeline system comparable in size and scope to the Operating Subsidiaries’ pipeline system will be built in the foreseeable future, new pipelines (including pipeline segments that connect with existing pipeline systems) could be built to effectively compete with the Operating Subsidiaries in particular locations.

The Operating Subsidiaries compete with marine transportation in some areas. Tankers and barges on the Great Lakes account for some of the volume to certain Michigan, Ohio and upstate New York locations during the approximately eight non-winter months of the year. Barges are presently a competitive factor for deliveries to the New York City area, the Pittsburgh area, Connecticut and locations on the Ohio River such as Mt. Vernon, Indiana and Cincinnati, Ohio, and locations on the Mississippi River such as St. Louis, Missouri.

Trucks competitively deliver refined products in a number of areas served by the Operating Subsidiaries. While their costs may not be competitive for longer hauls or large volume shipments, trucks compete effectively for smaller volumes in many local areas served by the Operating Subsidiaries. The availability of truck transportation places a significant competitive constraint on the ability of the Operating Subsidiaries to increase their tariff rates.

Privately arranged exchanges of refined petroleum products between marketers in different locations are another form of competition. Generally, such exchanges reduce both parties’ costs by eliminating or reducing transportation charges. In addition, consolidation among refiners and marketers that has accelerated in recent years has altered distribution patterns, reducing demand for transportation services in some markets and increasing them in other markets.

Distribution of refined petroleum products depends to a large extent upon the location and capacity of refineries. However, because the Partnership’s business is largely driven by the consumption of fuel in its delivery areas and the Operating Subsidiaries’ pipelines have numerous source points, the General Partner does not believe that the expansion or shutdown of any particular refinery is likely, in most instances, to have a material effect on the business of the Partnership. Certain of the pipelines which were acquired from Shell on October 1, 2004 emanate from a refinery owned by ConocoPhillips and located in the vicinity of Wood River, Illinois. While these pipelines are, in part, supplied by connecting pipelines, a temporary or permanent closure of the ConocoPhillips Wood River refinery could have a negative impact on volumes delivered through these pipelines.  See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Forward-Looking Information—Competition and Other Business Conditions.”

The Operating Subsidiaries’ mix of products transported tends to vary seasonally. Declines in demand for heating oil during the summer months are, to a certain extent, offset by increased demand for gasoline and jet fuel. Overall, operations have been only moderately seasonal, with somewhat lower than average volumes being transported during March, April and May and somewhat higher than average volumes being transported in November, December and January.

Many of the general competitive factors discussed above, such as demand for refined petroleum products and competitive threats from methods of transportation other than pipelines, also impact the Partnership’s terminal operations. In addition, the Partnership’s terminals generally compete with other terminals in the same geographic market.  Many competitive terminals are owned by major integrated oil companies. These major oil companies may have the opportunity for product exchanges that are not available to the Partnership’s terminals. While the Partnership’s terminal throughput fees are not regulated, they are subject to price competition from competitive terminals and alternate modes of transporting refined petroleum products to end users such as retail gas stations.

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Other independent pipeline companies, engineering firms, major integrated oil companies and petrochemical companies compete with BGC to operate and maintain pipelines for third-party owners. In addition, in many instances it is more cost-effective for petrochemical companies to operate and maintain their own pipelines than to enter into agreements for BGC to operate and maintain such pipelines. Numerous engineering and construction firms compete with BGC for pipeline construction business.

Employees

Neither the Partnership nor any of the Operating Subsidiaries has any employees. The Operating Subsidiaries are managed and operated by employees of Buckeye Pipe Line Services Company, a Pennsylvania corporation (“Services Company”). Services Company is reimbursed by the Operating Subsidiaries pursuant to a services agreement for the cost of providing employee services. In December 2006, Services Company had a total of 867 full-time employees, 171 of whom were represented by two labor unions. The Operating Subsidiaries (and their predecessors) have never experienced any work stoppages or other significant labor problems.

 

Capital Expenditures

The Partnership makes capital expenditures in order to maintain and enhance the safety and integrity of its pipelines, terminals and related assets, to expand the reach or capacity of its pipelines and terminals, to improve the efficiency of its operations and to pursue new business opportunities. See “Pipeline and Terminal Maintenance and Safety Regulation” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

During 2006, the Partnership made approximately $92.7 million of capital expenditures, of which $30.2 million related to maintenance and integrity projects and $62.5 million related to expansion and cost reduction projects.

In 2007, the Partnership anticipates capital expenditures of approximately $80.0 million, of which approximately $30.0 million is projected to be sustaining capital expenditures for maintenance and integrity projects and approximately $50.0 million is projected to be for expansion and cost reduction projects. See “Pipeline and Terminal Maintenance and Safety Regulation” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

Regulation

General

Buckeye, Wood River, BPL Transportation, Buckeye NGL and Norco operate pipelines subject to the regulatory jurisdiction of the Federal Energy Regulatory Commission (“FERC”) under the Interstate Commerce Act and the Department of Energy Organization Act. FERC regulations require that interstate oil pipeline rates be posted publicly and that these rates be “just and reasonable” and non-discriminatory. FERC regulations also enforce common carrier obligations and specify a uniform system of accounts. In addition, the Operating Subsidiaries are subject to the jurisdiction of certain other federal agencies with respect to environmental and pipeline safety matters.

The Operating Subsidiaries are also subject to the jurisdiction of various state and local agencies, including, in some states, public utility commissions which have jurisdiction over, among other things, intrastate tariffs, the issuance of debt and equity securities, transfers of assets and pipeline safety. The Partnership’s Laurel subsidiary operates a pipeline in intrastate service across Pennsylvania, and its tariff rates are regulated by the Pennsylvania Public Utility Commission. The Partnership’s Wood River subsidiary operates a pipeline in intrastate service in Illinois and tariff rates related to this pipeline are regulated by the Illinois Commerce Commission.

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FERC Rate Regulation

The generic oil pipeline regulations issued under the Energy Policy Act of 1992 rely primarily on an index methodology, that allows a pipeline to change its rates in accordance with an index (currently the change in the Producer Price Index plus 1.3%) that FERC believes reflects cost changes appropriate for application to pipeline rates. The tariff rates of each of Wood River, BPL Transportation, Buckeye NGL and Norco are governed by this generic FERC index methodology, and therefore are subject to change annually according to the index. If PPI +1.3% is negative, then Wood River, BPL Transportation, Buckeye NGL and Norco could be required to reduce their rates if they exceed the new maximum allowable rate.

In addition, FERC had a longstanding rule that pass-through entities, like the Partnership and the Operating Subsidiaries, may not claim an income tax allowance for income attributable to non-corporate limited partners in justifying the reasonableness of their rates that are based on their cost of service. (The General Partner believes only a small percentage of the Partnership’s limited partnership units are held by corporations). Further, in a July 2004 decision involving an unrelated pipeline limited partner, the United States Court of Appeals for the District of Columbia Circuit overruled a prior FERC decision allowing a limited partnership to claim a partial income tax allowance.  On May 4, 2005, the FERC adopted a new policy providing that all entities owning public utility assets—oil and gas pipelines and electric utilities—would be permitted to include an income tax allowance in their cost-of-service rates to reflect the actual or potential income tax liability attributable to their public utility income, regardless of the form of ownership. FERC determined that any pass-through entity seeking an income tax allowance in a rate proceeding must establish that its partners have an actual or potential income tax obligation on the entity’s public utility income. The amount of any income tax allowance will be reduced accordingly to the extent that any of the partners do not have an actual or potential income tax obligation. This reduction will be reflected in the weighted income tax liability of the entity’s partners. Whether a pipeline’s owners have an actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. This policy was applied by FERC in June 2005 with an order involving an unrelated pipeline limited partnership. FERC concluded that the pipeline should be afforded an income tax allowance on all of its partnership interests to the extent that the ultimate owners of those interests had an actual or potential income tax obligation during the periods at issue.  In December 2005, FERC reaffirmed its new income tax allowance policy as it applied to that pipeline.  FERC’s tax allowance policy has been appealed to the United States Court of Appeals for the District of Columbia Circuit.  The ultimate outcome of these proceedings is not certain and could result in changes to the FERC’s treatment of income tax allowances.

A shipper or FERC could cite these decisions in a protest or complaint challenging indexed rates maintained by certain of the Partnership’s Operating Subsidiaries. If a challenge were brought and FERC were to find that some of the indexed rates exceed either the maximum allowable rate or levels justified by the cost of service, FERC could order a reduction in the indexed rates and could require reparations. As a result, the Partnership’s results of operations could be adversely affected.

Under FERC’s rules, as an alternative to indexed rates, a pipeline is also allowed to charge market-based rates if the pipeline establishes that it does not possess significant market power in a particular market. The final rules became effective on January 1, 1995.

Buckeye’s rates are governed by an exception to the rules discussed above, pursuant to specific FERC authorization. Buckeye’s market-based rate regulation program was initially approved by FERC in March 1991 and was subsequently extended in 1994. Under this program, in markets where Buckeye does not have significant market power, individual rate increases: (a) will not exceed a real (i.e., exclusive of inflation) increase of 15% over any two-year period (the “rate cap”), and (b) will be allowed to become effective without suspension or investigation if they do not exceed a “trigger” equal to the change in the Gross Domestic Product implicit price deflator since the date on which the individual rate was last increased, plus 2%. Individual rate decreases will be presumptively valid upon a showing that the proposed rate exceeds marginal costs. In markets where Buckeye was found to have significant market power and in

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certain markets where no market power finding was made: (i) individual rate increases cannot exceed the volume-weighted average rate increase in markets where Buckeye does not have significant market power since the date on which the individual rate was last increased, and (ii) any volume-weighted average rate decrease in markets where Buckeye does not have significant market power must be accompanied by a corresponding decrease in all of Buckeye’s rates in markets where it does have significant market power. Shippers retain the right to file complaints or protests following notice of a rate increase, but are required to show that the proposed rates violate or have not been adequately justified under the market-based rate regulation program, that the proposed rates are unduly discriminatory, or that Buckeye has acquired significant market power in markets previously found to be competitive.

The Buckeye program was subject to review by FERC in 2000 when FERC reviewed the index selected in the generic oil pipeline regulations. FERC decided to continue the generic oil pipeline regulations with no material changes and did not modify or discontinue Buckeye’s program. The General Partner cannot predict the impact that any change to Buckeye’s rate program would have on Buckeye’s operations. Independent of regulatory considerations, it is expected that tariff rates will continue to be constrained by competition and other market factors.

Environmental Regulation

The Operating Subsidiaries are subject to federal, state and local laws and regulations relating to the protection of the environment. Although the General Partner believes that the operations of the Operating Subsidiaries comply in all material respects with applicable environmental laws and regulations, risks of substantial liabilities are inherent in pipeline operations, and there can be no assurance that material environmental liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly rigorous environmental laws, regulations and enforcement policies, and claims for damages to property or injuries to persons resulting from the operations of the Operating Subsidiaries, could result in substantial costs and liabilities to the Partnership. See “Legal Proceedings” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Environmental Matters.”

The Oil Pollution Act of 1990 (“OPA”) amended certain provisions of the federal Water Pollution Control Act of 1972, commonly referred to as the Clean Water Act (“CWA”), and other statutes as they pertain to the prevention of and response to petroleum product spills into navigable waters. The OPA subjects owners of facilities to strict joint and several liability for all containment and clean-up costs and certain other damages arising from a spill. The CWA provides penalties for the discharge of petroleum products in reportable quantities and imposes substantial liability for the costs of removing a spill. State laws for the control of water pollution also provide varying civil and criminal penalties and liabilities in the case of releases of petroleum or its derivatives into surface waters or into the ground.

Contamination resulting from spills or releases of refined petroleum products sometimes occurs in the petroleum pipeline industry. The Operating Subsidiaries’ pipelines cross numerous navigable rivers and streams. Although the General Partner believes that the Operating Subsidiaries comply in all material respects with the spill prevention, control and countermeasure requirements of federal laws, any spill or other release of petroleum products into navigable waters may result in material costs and liabilities to the Partnership.

The Resource Conservation and Recovery Act (“RCRA”), as amended, establishes a comprehensive program of regulation of “hazardous wastes.” Hazardous waste generators, transporters, and owners or operators of treatment, storage and disposal facilities must comply with regulations designed to ensure detailed tracking, handling and monitoring of these wastes. RCRA also regulates the disposal of certain non-hazardous wastes. As a result of these regulations, certain wastes typically generated by pipeline operations are considered “hazardous wastes.”

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The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”), also known as “Superfund,” governs the release or threat of release of a “hazardous substance.” Releases of a hazardous substance, whether on or off-site, may subject the generator of that substance to liability under CERCLA for the costs of clean-up and other remedial action. Pipeline maintenance and other activities in the ordinary course of business generate “hazardous substances.”  As a result, to the extent a hazardous substance generated by the Operating Subsidiaries or their predecessors may have been released or disposed of in the past, the Operating Subsidiaries may in the future be required to remediate contaminated property. Governmental authorities such as the Environmental Protection Agency (“EPA”), and in some instances third parties, are authorized under CERCLA to seek to recover remediation and other costs from responsible persons, without regard to fault or the legality of the original disposal. In addition to its potential liability as a generator of a “hazardous substance,” the property or right-of-way of the Operating Subsidiaries may be adjacent to or in the immediate vicinity of Superfund and other hazardous waste sites. Accordingly, the Operating Subsidiaries may be responsible under CERCLA for all or part of the costs required to cleanup such sites, which costs could be material.

The Clean Air Act, amended by the Clean Air Act Amendments of 1990 (the “Amendments”), imposes controls on the emission of pollutants into the air. The Amendments required states to develop facility-wide permitting programs over the past several years to comply with new federal programs. Existing operating and air-emission requirements like those currently imposed on the Operating Subsidiaries are being reviewed by appropriate state agencies in connection with the new facility-wide permitting program. It is possible that new or more stringent controls will be imposed on the Operating Subsidiaries through this program.

The Operating Subsidiaries are also subject to environmental laws and regulations adopted by the various states in which they operate. In certain instances, the regulatory standards adopted by the states are more stringent than applicable federal laws.

Pipeline and Terminal Maintenance and Safety Regulation

The pipelines operated by the Operating Subsidiaries are subject to regulation by the United States Department of Transportation (“DOT”) under the Hazardous Liquid Pipeline Safety Act of 1979 (“HLPSA”), which governs the design, installation, testing, construction, operation, replacement and management of pipeline facilities. HLPSA covers petroleum and petroleum products and requires any entity that owns or operates pipeline facilities to comply with applicable safety standards, to establish and maintain a plan of inspection and maintenance and to comply with such plans.

The Pipeline Safety Reauthorization Act of 1988 requires coordination of safety regulation between federal and state agencies, testing and certification of pipeline personnel, and authorization of safety-related feasibility studies. The Partnership has a drug and alcohol testing program that complies in all material respects with the regulations promulgated by the Office of Pipeline Safety and DOT.

HLPSA also requires, among other things, that the Secretary of Transportation consider the need for the protection of the environment in issuing federal safety standards for the transportation of hazardous liquids by pipeline. The legislation also requires the Secretary of Transportation to issue regulations concerning, among other things, the identification by pipeline operators of environmentally sensitive areas; the circumstances under which emergency flow restricting devices should be required on pipelines; training and qualification standards for personnel involved in maintenance and operation of pipelines; and the periodic integrity testing of pipelines in unusually sensitive and high-density population areas by internal inspection devices or by hydrostatic testing. Effective in August 1999, the DOT issued its Operator Qualification Rule, which required a written program by April 27, 2001, for ensuring operators are qualified to perform tasks covered by the pipeline safety rules. All persons performing covered tasks were required to be qualified under the program by October 28, 2002. The Partnership filed its written plan and has qualified its employees and contractors as required and requalified the employees under its plan in

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2005. On March 31, 2001, DOT’s rule for Pipeline Integrity Management in High Consequence Areas (Hazardous Liquid Operators with 500 or more Miles of Pipeline) became effective. This rule sets forth regulations that require pipeline operators to assess, evaluate, repair and validate the integrity of hazardous liquid pipeline segments that, in the event of a leak or failure, could affect populated areas, areas unusually sensitive to environmental damage or commercially navigable waterways. Under the rule, pipeline operators were required to identify line segments which could impact high consequence areas by December 31, 2001. Pipeline operators were required to develop “Baseline Assessment Plans” for evaluating the integrity of each pipeline segment by March 31, 2002 and to complete an assessment of the highest risk 50% of line segments by September 30, 2004, with full assessment of the remaining 50% by March 31, 2008. Pipeline operators will thereafter be required to re-assess each affected segment in intervals not to exceed five years. The Partnership has implemented an Integrity Management Program in compliance with the requirements of this rule.

In December 2002, the Pipeline Safety Improvement Act of 2002 (“PSIA”) became effective. The PSIA imposes additional obligations on pipeline operators, increases penalties for statutory and regulatory violations, and includes provisions prohibiting employers from taking adverse employment action against pipeline employees and contractors who raise concerns about pipeline safety within the company or with government agencies or the press. Many of the provisions of the PSIA are subject to regulations to be issued by the Department of Transportation. The PSIA also requires public education programs for residents, public officials and emergency responders and a measurement system to ensure the effectiveness of the public education program. The Partnership implemented a public education program that complies with these requirements and the requirements of the American Petroleum Institute Recommended Practice 1162. While the PSIA imposes additional operating requirements on pipeline operators, the Partnership does not believe that costs of compliance with the PSIA are likely to be material.

The Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 (“PIPES Act”), which became effective on December 24, 2006, among other things, reauthorized HLPSA, strengthened damage prevention measures designed to protect pipelines from excavation damage, removed the exemption from regulation of pipelines operating at less than 20 percent of maximum yield strength in rural areas, and required pipeline operators to manage human factors in pipeline control centers, including controller fatigue. While the PIPES Act imposes additional operating requirements on pipeline operators, the Partnership does not believe that costs of compliance with the PIPES Act are likely to be material.

The Partnership also has certain contractual obligations to Shell for testing and maintenance of certain of the pipelines that the Partnership acquired from Shell in October 2004. In 2003, Shell entered into a consent decree with the EPA arising out of a June 1999 incident unrelated to the assets acquired by the Partnership. The consent decree included requirements for testing and maintenance of two of the pipelines (the “North Line” and the “East Line”) acquired from Shell, the creation of a damage prevention program, submission to independent monitoring and various reporting requirements. In the purchase agreement with Shell, the Partnership agreed to perform, at its own expense, the work required of Shell on the North Line and the East Line under the consent decree. The Partnership’s obligations to Shell with respect to the consent decree extend to approximately 2008, a date five years from the date of the consent decree.

The Partnership believes that the Operating Subsidiaries currently comply in all material respects with HLPSA, the PSIA, the PIPES Act and other pipeline safety laws and regulations. However, the industry, including the Partnership, will incur additional pipeline and tank integrity expenditures in the future, and the Partnership is likely to incur increased operating costs based on these and other government regulations. During 2006, the Partnership’s integrity expenditures for these programs were approximately $20.1 million (of which $9.6 million was capitalized and $10.5 million was expensed). The Partnership expects 2007 integrity expenditures for these programs to be approximately $23 million of which approximately $13 million will be capitalized and $10 million will be expense.

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The Operating Subsidiaries are also subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The Partnership believes that the Operating Subsidiaries’ operations comply in all material respects with OSHA requirements, including general industry standards, record-keeping, hazard communication requirements, training and monitoring of occupational exposure to benzene, asbestos and other regulated substances.

The Partnership cannot predict whether or in what form any new legislation or regulatory requirements might be enacted or adopted or the costs of compliance. In general, any such new regulations could increase operating costs and impose additional capital expenditure requirements, but the Partnership does not presently expect that such costs or capital expenditure requirements would have a material adverse effect on its results of operations or financial condition.

Tax Considerations for Unitholders

This section is a summary of material tax considerations that may be relevant to the holders (“Unitholders”) of the Partnership’s limited partner units (“LP Units”). It is based upon the Internal Revenue Code of 1986, as amended (the “Code”), regulations promulgated thereunder and current administrative rulings and court decisions, all of which are subject to change. Subsequent changes in such authorities may cause the tax consequences to vary substantially from the consequences described below.

No attempt has been made in the following discussion to comment on all federal income tax matters affecting the Partnership or the Unitholders. Moreover, the discussion focuses on Unitholders who are individuals and who are citizens or residents of the United States and has only limited application to corporations, estates, trusts, non-resident aliens or other Unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts, REITs or mutual funds.

UNITHOLDERS ARE URGED TO CONSULT, AND SHOULD DEPEND ON, THEIR OWN TAX ADVISORS IN ANALYZING THE FEDERAL, STATE, LOCAL AND FOREIGN TAX CONSEQUENCES TO THEM OF THE OWNERSHIP OR DISPOSITION OF LP UNITS.

Characterization of the Partnership for Tax Purposes

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, partners are required to take into account their respective allocable shares of the items of income, gain, loss and deduction of the partnership in computing their federal income tax liability, regardless of whether distributions are made. Distributions of cash by a partnership to a partner are generally not taxable unless the amount of cash distributed to a partner is in excess of the partner’s tax basis in his partnership interest. Allocable shares of partnership tax items are generally determined by a partnership agreement. However, the IRS may disregard such an agreement in certain instances and re-determine the tax consequences of partnership operations to the partners.

Section 7704 of the Code provides that publicly traded partnerships (such as the Partnership) will, as a general rule, be taxed as corporations. However, an exception to this rule exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year of the partnership’s existence consists of “qualifying income.”  Qualifying income includes interest, dividends, real property rents, gains from the sale or disposition of real property, and most importantly for Unitholders “income and gains derived from the exploration, development, mining or production, processing, refining, transportation (including pipelines transporting gas, oil or products thereof), or the marketing of any mineral or natural resource (including fertilizer, geothermal energy and timber),” and gain from the sale or disposition of capital assets that produce such income.

The Partnership is engaged primarily in the refined petroleum products transportation business. The General Partner believes that at least 90% or more of the Partnership’s gross income constitutes, and has

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constituted, qualifying income and, accordingly, that the Partnership will continue to be classified as a partnership and not as a corporation for federal income tax purposes.

If we fail to meet the Qualifying Income Exception, other than a failure that is determine by the IRS to be inadvertent and that is cured within a reasonable time after discovery, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to our Unitholders in liquidation of their interests in us.  This contribution and liquidation should be tax-free to Unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we were taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to the Unitholders, and our net income would be taxed to us at corporate rates. If we were taxable as a corporation, losses recognized by us would not flow through to our Unitholders. In addition, any distribution made by us to a Unitholder would be treated as either taxable dividend income, to the extent of current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the Unitholder’s tax basis in his units, or taxable capital gain, after the Unitholder’s tax basis in his units is reduced to zero.

Allocation of Partnership Income, Gain, Loss and Deduction

The Partnership’s items of income, gain, loss and deduction will generally be allocated among the General Partner and the Unitholders in accordance with their respective percentage interests in the Partnership.

Certain items of the Partnership’s income, gain, loss or deduction will be allocated as required or permitted by Section 704(c) of the Internal Revenue Code to account for the difference between the tax basis and fair market value of property contributed to the Partnership. Allocations will also be made to account for the difference between the fair market value of the Partnership’s assets and their tax basis at the time of any offering.

In addition, certain items of recapture income which the Partnership recognizes on the sale of any of its assets will be allocated to the extent provided in regulations and the partnership agreement which generally require such depreciation recapture to be allocated to the partner who (or whose predecessor in interest) was allocated the deduction giving rise to the treatment of such gain as recapture income.

Treatment of Partnership Distributions

The Partnership’s distributions to a Unitholder generally will not be taxable for federal income tax purposes to the extent of the Unitholder’s tax basis in its LP Units immediately before the distribution. Distributions in excess of a Unitholder’s tax basis generally will be gain from the sale or exchange of the LP Units, taxable in accordance with the rules described under “Disposition of LP Units,” below. Any reduction in a Unitholder’s share of the Partnership’s liabilities for which no partner, including the General Partner, bears the economic risk of loss (“nonrecourse liabilities”) will be treated as a distribution of cash to that Unitholder.

A non-pro rata distribution of money or property may result in ordinary income to a Unitholder if such distribution reduces the Unitholder’s share of the Partnership’s  “unrealized receivables,” including depreciation recapture or substantially appreciated “inventory items,” both as defined in Section 751 of the Internal Revenue Code (collectively, “Section 751 Assets”).

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Basis of LP Units

A Unitholder will have an initial tax basis for its LP Units equal to the amount paid for the LP Units plus its share of the Partnership’s liabilities. A Unitholder’s tax basis will be increased by his share of the Partnership’s income and by any increase in his share of the Partnership’s liabilities. A Unitholder’s tax basis will be decreased, but not below zero, by its share of the Partnership’s distributions, by its share of the Partnership’s losses, by any decrease in its share of the Partnership’s liabilities and by its share of the Partnership’s expenditures that are not deductible in computing the Partnership’s taxable income and are not required to be capitalized.

Tax Treatment of Operations

The Partnership uses the adjusted tax basis of its various assets for purposes of computing depreciation and cost recovery deductions and gain or loss on any disposition of such assets. If the Partnership disposes of depreciable property, all or a portion of any gain may be subject to the recapture rules and taxed as ordinary income rather than capital gain.

The costs incurred in promoting the issuance of LP Units (i.e., syndication expenses) must be capitalized and cannot be deducted by the Partnership currently, ratably or upon the Partnership’s termination. Uncertainties exist regarding the classification of costs as organization expenses, which may be amortized, and as syndication expenses, which may not be amortized, but underwriters’ discounts and commissions are treated as syndication costs.

Section 754 Election

The Partnership has made the election permitted by Section 754 of the Code, which effectively permits the Partnership to adjust the tax basis of its assets to each purchaser of the Partnership’s LP Units from another Unitholder pursuant to Section 743(b) of the Internal Revenue Code to reflect the purchaser’s purchase price. The Section 743(b) adjustment is intended to provide a purchaser with the equivalent of an adjusted tax basis in the purchaser’s share of the Partnership’s assets equal to the value of such share that is indicated by the amount that the purchaser paid for the LP Units.

A Section 754 election is advantageous if the transferee’s tax basis in the transferee’s LP Units is higher than such LP Units’ share of the aggregate tax basis of the Partnership’s assets immediately prior to the transfer because the transferee would have, as a result of the election, a higher tax basis in the transferee’s share of the Partnership’s assets. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in the transferee’s LP Units is lower than such LP Units’ share of the aggregate tax basis of the Partnership’s assets immediately prior to the transfer. The Section 754 election is irrevocable without the consent of the IRS.

The Partnership intends to compute the effect of the Section 743(b) adjustment so as to preserve the ability to determine the tax attributes of an LP Unit from its date of purchase and the amount paid therefor. In that regard, the Partnership has adopted depreciation and amortization conventions that may not conform with all aspects of applicable Treasury regulations, though the Partnership believes that they do conform to Section 743(b) of the Code.

The calculations involved in the Section 754 election are complex and are made by the Partnership on the basis of certain assumptions as to the value of assets and other matters. There is no assurance that the determinations made by the Partnership will prevail if challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether.

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Notification Requirements

A Unitholder who sells or exchanges LP Units is required to notify the Partnership in writing of that sale or exchange within 30 days after the sale or exchange and in any event by no later than January 15 of the year following the calendar year in which the sale or exchange occurred. The Partnership is required to notify the IRS of that transaction and to furnish certain information to the transferor and transferee. However, these reporting requirements do not apply with respect to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker. Failure to satisfy these reporting obligations may lead to the imposition of substantial penalties.

Constructive Termination

The Partnership will be considered terminated if there is a sale or exchange of 50% or more of the total interests in its capital and profits within a 12-month period. Any such termination would result in the closing of the Partnership’s taxable year for all Unitholders. In the case of a Unitholder reporting on a taxable year that does not end with the Partnership’s taxable year, the closing of the taxable year may result in more than 12 months of taxable income or loss being includable in that Unitholder’s taxable income for the year of termination. New tax elections required to be made by the Partnership, including a new election under Section 754 of the Internal Revenue Code, must be made subsequent to a termination and a termination could result in a deferral of deductions for depreciation. A termination could also result in penalties if the Partnership was unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject the Partnership to, any tax legislation enacted prior to the termination.

Alternative Minimum Tax

Each Unitholder will be required to take into account his share of items of income, gain, loss or deduction for purposes of the alternative minimum tax. A portion of depreciation deductions may be treated as an item of tax preference for this purpose. A Unitholder’s alternative minimum taxable income derived from the Partnership may be higher than his share of the Partnership’s net income because the Partnership may use accelerated methods of depreciation for federal income tax purposes. Prospective Unitholders should consult their tax advisors as to the impact of an investment in LP Units on their liability for the alternative minimum tax.

Loss Limitations

The deduction by a Unitholder of that Unitholder’s allocable share of the Partnership’s losses will be limited to the amount of that Unitholder’s tax basis in his or her LP Units and, in the case of an individual Unitholder or a corporate Unitholder who is subject to the “at risk” rules (generally, certain closely-held corporations), to the amount for which the Unitholder is considered to be “at risk” with respect to the Partnership’s activities, if that is less than the Unitholder’s tax basis. A Unitholder must recapture losses deducted in previous years to the extent that distributions cause the Unitholder’s at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a Unitholder or recaptured as a result of these limitations will carry forward and will be allowable to the extent that the Unitholder’s tax basis or at risk amount, whichever is the limiting factor, subsequently increases. Upon the taxable disposition of an LP Unit, any gain recognized by a Unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation.

In general, a Unitholder will be at risk to the extent of the Unitholder’s tax basis in the Unitholder’s LP Units, excluding any portion of that basis attributable to the Unitholder’s share of the Partnership’s nonrecourse liabilities, reduced by any amount of money the Unitholder borrows to acquire or hold the Unitholder’s LP Units if the lender of such borrowed funds owns an interest in the Partnership, is related

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to such a person or can look only to LP Units for repayment. A Unitholder’s at risk amount will increase or decrease as the tax basis of the Unitholder’s LP Units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in the Unitholder’s share of the Partnership’s nonrecourse liabilities.

The passive loss limitations generally provide that individuals, estates, trusts, certain closely-held corporations and personal service corporations can deduct losses from passive activities, which include any trade or business activity in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. Moreover, the passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses generated by the Partnership will only be available to Unitholders who are subject to the passive loss rules to offset future passive income generated by the Partnership and, in particular, will not be available to offset income from other passive activities, investments or salary. Passive losses that are not deductible because they exceed a Unitholder’s share of income may be deducted in full when the Unitholder disposes of the Unitholder’s entire investment in the Partnership in a fully taxable transaction to an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions such as the at-risk rules and the basis limitation.

Deductibility of Interest Expense

The Code generally provides that investment interest expense is deductible only to the extent of a non-corporate taxpayer’s net investment income. In general, net investment income for purposes of this limitation includes gross income from property held for investment, gain attributable to the disposition of property held for investment (except for net capital gains for which the taxpayer has elected to be taxed at special capital gains rates) and portfolio income (determined pursuant to the passive loss rules as income not derived from a trade or business) reduced by certain expenses (other than interest) which are directly connected with the production of such income. Property that generates passive losses under the passive loss rules is not generally treated as property held for investment. However, the IRS has issued a Notice which provides that net income from a publicly traded partnership (not otherwise treated as a corporation) may be included in net investment income for purposes of the limitation on the deductibility of investment interest. Furthermore, a Unitholder’s investment income attributable to its LP Units will also include its allocable share of the Partnership’s portfolio income. A Unitholder’s investment interest expense will include its allocable share of the Partnership’s interest expense attributable to portfolio investments.

Valuation of Partnership Properties

The federal income tax consequences of the ownership and disposition of LP Units will depend in part on the Partnership’s estimates of the fair market values and its determination of the adjusted tax basis of assets. Although the Partnership may from time to time consult with professional appraisers with respect to valuation matters, the Partnership will make many of the fair market value estimates itself. These estimates and determinations are subject to challenge and will not be binding on the IRS or the courts. If such estimates or determinations of basis are subsequently found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by Unitholders might change, and Unitholders might be required to adjust their tax liability for prior years.

Withholding

If the Partnership was required or elected under applicable law to pay any federal, state or local income tax on behalf of any Unitholder, the Partnership is authorized to pay those taxes from its funds. Such payment, if made, will be treated as a distribution of cash to the Unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, the Partnership is authorized to treat the payment as a distribution to a current Unitholder.

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Disposition of LP Units

A Unitholder will recognize gain or loss on a sale of LP Units equal to the difference between the amount realized and the Unitholder’s tax basis in the LP Units sold. A Unitholder’s amount realized is measured by the sum of the cash and the fair market value of other property received plus his share of liabilities. Because the amount realized includes a Unitholder’s share of the Partnership’s liabilities, the gain recognized on the sale of LP Units could result in a tax liability in excess of any cash received from such sale.

Gain or loss recognized by a Unitholder, other than a “dealer” in LP Units, on the sale or exchange of an LP Unit will generally be a capital gain or loss. Capital gain recognized on the sale of LP Units by an individual Unitholder held for more than one year will generally be taxed at a maximum rate of 15% (such rate to be increased to 20% for taxable years beginning after December 31, 2010). A portion of this gain or loss (which could be substantial), however, will be separately computed and will be classified as ordinary income or loss to the extent attributable to Section 751 Assets giving rise to depreciation recapture or other unrealized receivables or to inventory items owned by the Partnership. Ordinary income attributable to Section 751 may exceed net taxable gain realized upon the sale of the LP Units and will be recognized even if there is a net taxable loss realized on the sale of the LP Units. Thus, a Unitholder may recognize both ordinary income and a capital loss upon a disposition of LP Units. Net capital loss may offset no more than $3,000 ($1,500 in the case of a married individual filing a separate return) of ordinary income in the case of individuals and may only be used to offset capital gain in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis. Upon a sale or other disposition of less than all of such interests, a portion of that tax basis must be allocated to the interests sold based upon relative fair market values. On the other hand, a selling partner who can identify partnership interests transferred with an ascertainable holding period may elect to use the actual holding period of the partnership interests transferred. A partner electing to use the actual holding period of partnership interests transferred must consistently use that identification method for all later sales or exchanges of partnership interests.

Unrelated Business Taxable Income

Certain entities otherwise exempt from federal income taxes (such as individual retirement accounts, pension plans and charitable organizations) are nevertheless subject to federal income tax on net unrelated business taxable income and each such entity must file a tax return for each year in which it has more than $1,000 of gross income from unrelated business activities. The General Partner believes that substantially all of the Partnership’s gross income will be treated as derived from an unrelated trade or business and taxable to such entities. The tax-exempt entity’s share of the Partnership’s deductions directly connected with carrying on such unrelated trade or business are allowed in computing the entity’s taxable unrelated business income.  ACCORDINGLY, TAX-EXEMPT ENTITIES SUCH AS INDIVIDUAL RETIREMENT ACCOUNTS, PENSION PLANS AND CHARITABLE TRUSTS ARE ENCOURAGED TO CONSULT THEIR PROFESSIONAL TAX ADVISORS REGARDING THE TAX IMPLICATIONS OF THEIR OWNERSHIP OF L.P. UNITS.

Foreign Unitholders

Non-resident aliens and foreign corporations, trusts or estates which hold LP Units will be considered to be engaged in business in the United States on account of ownership of LP Units. As a consequence they will be required to file federal tax returns in respect of their share of the Partnership’s income, gain, loss or deduction and pay federal income tax at regular rates on any net income or gain. Generally, a partnership is required to pay a withholding tax on the portion of the partnership’s income which is effectively connected with the conduct of a United States trade or business and which is allocable to the

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foreign partners, regardless of whether any actual distributions have been made to such partners. However, under rules applicable to publicly traded partnerships, taxes may be withheld at the highest marginal rate applicable to individuals on actual cash distributions made to foreign Unitholders who obtain a taxpayer identification number from the IRS and submit that number to the transfer agent of the publicly traded partnership.

Because a foreign corporation that owns LP Units will be treated as engaged in a United States trade or business, such a corporation will also be subject to United States branch profits tax at a rate of 30% (or any applicable lower treaty rate) of the portion of any reduction in the foreign corporation’s “U.S. net equity,” which is the result of the Partnership’s activities. In addition, such Unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

In a published ruling, the IRS has taken the position that gain realized by a foreign partner who sells or otherwise disposes of a limited partner unit will be treated as effectively connected with a United States trade or business of the foreign partner, and thus subject to federal income tax, to the extent that such gain is attributable to appreciated personal property used by the limited partnership in a United States trade or business. Moreover, a foreign partner is subject to federal income tax on gain realized on the sale or disposition of a unit to the extent that such gain is attributable to appreciated United States real property interests; however, a foreign Unitholder will not be subject to federal income tax under this rule unless such foreign Unitholder has owned more than 5% in value of the Partnership’s LP Units during the five-year period ending on the date of the sale or disposition, provided the LP Units are regularly traded on an established securities market at the time of the sale or disposition.

Regulated Investment Companies

A regulated investment company, or “mutual fund,” is required to derive 90% or more of its gross income from specific sources including interest, dividends and gains from the sale of stocks or securities, foreign currency or specified related sources, and net income derived from the ownership of an interest in a “qualified publicly traded partnership.”  The Partnership expects that it will meet the definition of a “qualified publicly traded partnership.”

State Tax Treatment

During 2006, the Partnership owned property or conducted business in the states of California, Colorado Connecticut, Florida, Illinois, Indiana, Kansas, Massachusetts, Michigan, Missouri, Nevada, New Jersey, New York, Ohio, Pennsylvania, Tennessee and Texas. A Unitholder will likely be required to file state income tax returns and to pay applicable state income taxes in many of these states and may be subject to penalties for failure to comply with such requirements. Some of the states have proposed that the Partnership withhold a percentage of income attributable to Partnership operations within the state for Unitholders who are non-residents of the state. In the event that amounts are required to be withheld (which may be greater or less than a particular Unitholder’s income tax liability to the state), such withholding would generally not relieve the non-resident Unitholder from the obligation to file a state income tax return.

A new entity level tax on the portion of our income that is generated in Texas will begin in our tax year ending in 2007. Specifically, the Texas margin tax will be imposed at a maximum effective rate of 0.7% of our gross income apportioned to Texas.  Imposition of such a tax on us by Texas will reduce the cash available for distribution to our Unitholders.

Certain Tax Consequences to Unitholders

Upon formation of the Partnership in 1986, the General Partner elected twelve-year straight-line depreciation for tax purposes. For this reason, starting in 1999, the amount of depreciation available to the Partnership has been reduced significantly and taxable income has increased accordingly. Unitholders,

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however, will continue to offset Partnership income with the amortization of their respective Section 743(b) adjustments (which, effectively, allow Unitholders who purchase LP Units other than directly from the Partnership to increase their share of the common basis of the Partnership’s assets to their purchase price). Each Unitholder’s tax situation will differ depending upon the price paid and when LP Units were purchased. Notwithstanding the additional taxable income beginning in 1999, the current cash distributions exceed expected tax payments. In addition, gain recognized on the sale of LP Units will, generally, result in taxable ordinary income as a consequence of depreciation recapture. UNITHOLDERS ARE ENCOURAGED TO CONSULT THEIR PROFESSIONAL TAX ADVISORS REGARDING THE TAX IMPLICATIONS TO THEIR OWNERSHIP OF LP UNITS.

Available Information

The Partnership files annual, quarterly, and current reports and other documents with the Securities and Exchange Commission (the “SEC”) under the Securities Exchange Act of 1934. The public can obtain any documents that the Partnership files with the SEC at http://www.sec.gov. The Partnership also makes available free of charge its Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after filing such materials with, or furnishing such materials to, the SEC, on or through the Partnership’s Internet website, www.buckeye.com. The Partnership is not including the information contained on its website as a part of, or incorporating it by reference into, this Annual Report on Form 10-K.

You can also find information about the Partnership at the offices of the New York Stock Exchange (“NYSE”), 20 Broad Street, New York, New York 10005 or at the NYSE’s Internet site www.nyse.com. The NYSE requires the chief executive officer of each listed company to certify annually that he is not aware of any violation by the company of the NYSE corporate governance listing standards as of the date of the certification, qualifying the certification to the extent necessary. The Chief Executive Officer of the General Partner provided such certification to the NYSE in 2006 without qualification. In addition, the certifications of the General Partner’s Chief Executive Officer and Chief Financial Officer required by Sections 302 and 906 of the Sarbanes-Oxley Act have been included as exhibits to the Partnership’s Annual Report on Form 10-K.

Item 1A. Risk Factors

In this Item 1A, references to “we”, “us” and “our” mean Buckeye Partners, L.P. and its consolidated subsidiaries.

Risks Inherent to our Business

Changes in petroleum demand and distribution may adversely affect our business.

Demand for the services provided by our Operating Subsidiaries depends upon the demand for refined petroleum products in the regions served. Prevailing economic conditions, price and weather affect the demand for refined petroleum products. Changes in transportation and travel patterns in the areas served by our pipelines also affect the demand for refined petroleum products because a substantial portion of the refined petroleum products transported by our pipelines and throughput at our terminals is ultimately used as fuel for motor vehicles and aircraft. If these factors result in a decline in demand for refined petroleum products, the business of our Operating Subsidiaries would be particularly susceptible to adverse effects because they operate without the benefit of either exclusive franchises from government entities or long term contracts.

Energy conservation, changing sources of supply, structural changes in the oil industry and new energy technologies also could adversely affect our business. We cannot predict or control the effect of these factors on us or our Operating Subsidiaries.

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Competition could adversely affect our operating results.

Generally, pipelines are the lowest cost method for long-haul overland movement of refined petroleum products. Therefore, our most significant competitors for large volume shipments are other existing pipelines, some of which are owned or controlled by major integrated oil companies. In addition, new pipelines (including pipeline segments that connect with existing pipeline systems) could be built to effectively compete with us in particular locations.

We compete with marine transportation in some areas. Tankers and barges on the Great Lakes account for some of the volume to certain Michigan, Ohio and upstate New York locations during the approximately eight non-winter months of the year. Barges are presently a competitive factor for deliveries to the New York City area, the Pittsburgh area, Connecticut and locations on the Ohio River such as Mt. Vernon, Indiana and Cincinnati, Ohio, and locations on the Mississippi River such as St. Louis, Missouri.

Trucks competitively deliver refined petroleum products in a number of areas that we serve. While their costs may not be competitive for longer hauls or large volume shipments, trucks compete effectively for incremental and marginal volumes in many areas that we serve. The availability of truck transportation places a significant competitive constraint on our ability to increase our Operating Subsidiaries’ tariff rates.

Privately arranged exchanges of refined products between marketers in different locations are an increasing form of competition. Generally, these exchanges reduce both parties’ costs by eliminating or reducing transportation charges. In addition, consolidation among refiners and marketers that has accelerated in recent years has altered distribution patterns, reducing demand for transportation services in some markets and increasing them in other markets.

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

Mergers between existing customers could provide strong economic incentives for the combined entities to utilize their existing pipeline and terminal systems instead of ours. As a result, we could lose some or all of the volumes and associated revenues from these customers and we could experience difficulty in replacing those lost volumes and revenues. Because most of our operating costs are fixed, a reduction in volumes would result in not only a reduction of revenues, but also a decline in net income and cash flow of a similar magnitude, which would reduce our ability to meet our financial obligations and pay cash distributions.

We are a holding company and depend entirely on our Operating Subsidiaries’ distributions to service our debt obligations and pay cash distributions to our Unitholders.

We are a holding company with no material operations. If we do not receive cash distributions from our Operating Subsidiaries, we will not be able to meet our debt service obligations or to make cash distributions to our Unitholders. Among other things, this would adversely affect the market price of our limited partner units. We are currently bound by the terms of a revolving credit facility which prohibits us from making distributions to our Unitholders if a default under the credit facility exists at the time of the distribution or would result from the distribution. Our Operating Subsidiaries may from time to time incur additional indebtedness under agreements that contain restrictions which could further limit each Operating Subsidiary’s ability to make distributions to us.

We may incur liabilities from assets we have acquired.

Some of the assets we have acquired have been used for many years to distribute, store or transport petroleum products. Releases from terminals or along pipeline rights-of-way may have occurred prior to our acquisition. In addition, releases may have occurred in the past that have not yet been discovered, which could require costly future remediation. If a significant release or event occurred in the past and we

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are unable to recover from the seller, it could adversely affect our financial position and results of operations.

A decline in production at the ConocoPhillips Wood River refinery could materially reduce the volume of refined petroleum products we transport.

A decline in production at the ConocoPhillips Wood River refinery could materially reduce the volume of refined petroleum products we transport on certain of the pipelines owned by Wood River. As a result, our revenues and, therefore, our ability to pay cash distributions on our units could be adversely affected. The ConocoPhillips Wood River refinery could partially or completely shut down its operations, temporarily or permanently, due to factors such as unscheduled maintenance, catastrophes, labor difficulties, environmental proceedings or other litigation, loss of significant downstream customers; or legislation or regulation that adversely impacts the economics of refinery operations.

Potential future acquisitions and expansions, if any, may affect our business by substantially increasing the level of our indebtedness and contingent liabilities and increasing the risks of our being unable to effectively integrate these new operations.

From time to time, we evaluate and acquire assets and businesses that we believe complement our existing assets and businesses. Acquisitions may require substantial capital or the incurrence of substantial indebtedness. If we consummate any future acquisitions, our capitalization and results of operations may change significantly.

Acquisitions and business expansions involve numerous risks, including difficulties in the assimilation of the assets and operations of the acquired businesses, inefficiencies and difficulties that arise because of unfamiliarity with new assets and the businesses associated with them and new geographic areas and the diversion of management’s attention from other business concerns. Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. Following an acquisition, we may discover previously unknown liabilities associated with the acquired business for which we have no recourse under applicable indemnification provisions.

Debt securities we issue are, and will continue to be, junior to claims of  our Operating Subsidiaries’ creditors.

Our outstanding debt securities are structurally subordinated to the claims of our Operating Subsidiaries’ creditors. In addition, any debt securities we issue in the future will likewise be subordinated in the same manner. Holders of the debt securities will not be creditors of our Operating Subsidiaries. Our claim to the assets of our Operating Subsidiaries derives from our own ownership interests in those Operating Subsidiaries. Claims of our Operating Subsidiaries’ creditors will generally have priority as to the assets of our Operating Subsidiaries over our own ownership interests and will therefore have priority over the holders of our debt, including our debt securities.

Our Operating Subsidiaries’ rate structures are subject to regulation and change by the Federal Energy Regulatory Commission.

Buckeye, Wood River, BPL Transportation, Buckeye NGL and Norco are interstate common carriers regulated by the FERC, under the Interstate Commerce Act and the Department of Energy Organization Act. The FERC’s primary ratemaking methodology is price indexing. This methodology is used to establish rates on the pipelines owned by Wood River, BPL Transportation, Buckeye NGL and Norco. The indexing method presently allows a pipeline to increase its rates by a percentage equal to the change in the annual producer price index for finished goods plus 1.3%. If the change in PPI +1.3% is negative, we could be required to reduce the rates charged by Wood River, BPL Transportation, Buckeye NGL and Norco if

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they exceed the new maximum allowable rate. In addition, changes in the PPI might not fully reflect actual increases in the costs associated with these pipelines, thus hampering our ability to recover our costs.

Buckeye presently is authorized to charge rates set by market forces, subject to limitations, rather than by reference to costs historically incurred by the pipeline, in 15 regions and metropolitan areas. The Buckeye program is an exception to the generic oil pipeline regulations the FERC issued under the Energy Policy Act of 1992. The generic rules rely primarily on the index methodology described above.  In the alternative, a pipeline is allowed to charge market-based rates if the pipeline establishes that it does not possess significant market power in a particular market.

The Buckeye rate program was reevaluated by the FERC in July 2000, and was allowed to continue with no material changes. We cannot predict the impact, if any, that a change in the FERC’s method of regulating Buckeye would have on our operations, financial condition or results of operations.

Environmental regulation may impose significant costs and liabilities on us.

Our Operating Subsidiaries are subject to federal, state and local laws and regulations relating to the protection of the environment. Risks of substantial environmental liabilities are inherent in the Operating Subsidiaries’ operations, and we cannot assure you that the Operating Subsidiaries will not incur material environmental liabilities. Additionally, our costs could increase significantly and we could face substantial liabilities, if, among other developments:

·       environmental laws, regulations and enforcement policies become more rigorous; or

·       claims for property damage or personal injury resulting from the operations of the Operating Subsidiaries are filed.

Existing or future state or federal government regulations relating to certain chemicals or additives in gasoline or diesel fuel could require capital expenditures or result in lower pipeline volumes and thereby adversely affect our results of operations.

Changes made to governmental regulations governing the components of refined petroleum products may necessitate changes to our pipelines and terminals which may require significant capital expenditures or result in lower pipeline volumes. For instance, the increasing use of ethanol as a fuel additive, which is blended with gasoline at product terminals, may lead to reduced pipeline volumes and revenue which may not be totally offset by increased terminal blending fees we may receive at our terminals.

Department of Transportation regulations may impose significant costs and liabilities on us.

The Operating Subsidiaries’ pipeline operations are subject to regulation by the United States Department of Transportation. These regulations require, among other things, that pipeline operators engage in a regular program of pipeline integrity testing to assess, evaluate, repair and validate the integrity of their pipelines, which, in the event of a leak or failure, could affect populated areas, unusually sensitive environmental areas, or commercially navigable waterways. In response to these regulations, the Operating Subsidiaries conduct pipeline integrity tests on an ongoing and regular basis. Depending on the results of these integrity tests, the Operating Subsidiaries could incur significant and unexpected capital and operating expenditures, not accounted for in anticipated capital or operating budgets, in order to repair such pipelines to ensure their continued safe and reliable operation.

Terrorist attacks could adversely affect our business.

Since the attacks of September 11, 2001, the United States government has issued warnings that energy assets, specifically our nation’s pipeline infrastructure, may be the future target of terrorist organizations. These developments have subjected our operations to increased risks. Any future terrorist attack on our facilities, those of our customers and, in some cases, those of other pipelines, refineries or terminals, could have a material adverse effect on our business.

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Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.

Our Operating Subsidiaries’ operations are subject to operational hazards and unforeseen interruptions such as natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, and other events beyond our control. These events might result in a loss of equipment or life, injury, or extensive property damage, as well as an interruption in our operations. Our Operating Subsidiaries’ operations are currently covered by property, casualty, workers’ compensation and environmental insurance policies. In the future, however, we may not be able to maintain or obtain insurance of the type and amount desired at reasonable rates. As a result of market conditions, premiums and deductibles for certain insurance policies have increased substantially, and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. For example, insurance carriers are now requiring broad exclusions for losses due to war risk and terrorist acts. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position, thereby reducing our ability to make distributions to Unitholders, or payments to debt holders.

Risks Relating to Partnership Structure

Our partnership status may be a disadvantage to us in calculating cost of service for rate-making purposes.

In the past, the FERC ruled that pass-through entities, like us, may not claim an income tax allowance for income attributable to non-corporate limited partners in justifying the reasonableness of their rates that are based on their cost of service. Further, in a July 2004 decision involving an unrelated pipeline limited partnership, the United States Court of Appeals for the District of Columbia Circuit overruled a prior FERC decision allowing a limited partnership to claim a partial income tax allowance. On May 4, 2005, the FERC adopted a new policy providing that all entities owning public utility assets—oil and gas pipelines and electric utilities—would be permitted to include an income tax allowance in their cost-of-service rates to reflect the actual or potential income tax liability attributable to their public utility income, regardless of the form of ownership. FERC determined that any pass-through entity seeking an income tax allowance in a rate proceeding must establish that its partners have an actual or potential income tax obligation on the entity’s public utility income. The amount of any income tax allowance will be reduced accordingly to the extent that any of the partners do not have an actual or potential income tax obligation. This reduction will be reflected in the weighted income tax liability of the entity’s partners. Whether a pipeline’s ultimate owners have actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. Although this new policy is generally favorable for pipelines that are organized as pass-through entities, it still entails risk due to the case-by-case review requirement. This policy was applied by FERC in June 2005 with an order involving an unrelated pipeline limited partnership. FERC concluded that the pipeline should be afforded an income tax allowance on all of its partnership interests to the extent that the owners of those interests had an actual or potential income tax obligation during the periods at issue. In December 2005, FERC reaffirmed its new income tax allowance policy as it applied to that pipeline. FERC’s tax allowance policy has been appealed to the United States Court of Appeals for the District of Columbia Circuit. The ultimate outcome of these proceedings is not certain and could result in changes to the FERC’s treatment of income tax allowances.

A shipper or FERC could cite these decisions in a protest or complaint challenging indexed rates maintained by certain of our Operating Subsidiaries. If a challenge was brought and FERC were to find that some of the indexed rates exceed levels justified by the cost of service, FERC could order a reduction in the indexed rates and could require reparations. As a result, our results of operations could be adversely affected.

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We may sell additional limited partner units, diluting existing interests of Unitholders.

Our partnership agreement allows us to issue additional limited partner units and certain other equity securities without Unitholder approval. There is no limit on the total number of limited partner units and other equity securities we may issue. When we issue additional limited partner units or other equity securities, the proportionate partnership interest of our existing Unitholders will decrease. The issuance could negatively affect the amount of cash distributed to Unitholders and the market price of the limited partner units. Issuance of additional units will also diminish the relative voting strength of the previously outstanding units.

Our general partner and its affiliates may have conflicts with the Partnership.

The directors and officers of our general partner and its affiliates have fiduciary duties to manage the general partner in a manner that is beneficial to its sole member, BGH.  At the same time, the general partner has fiduciary duties to manage the Partnership in a manner that is beneficial to our partners. Therefore, the general partner’s duties to us may conflict with the duties of its officers and directors to its sole member.

Such conflicts may arise from, among others, the following factors:

·       decisions by our general partner regarding the amount and timing of our cash expenditures,       borrowings and issuances of additional limited partner units or other securities can affect the amount of incentive distribution payments we make to our general partner;

·       under our partnership agreement we reimburse the general partner for the costs of managing and operating the Partnership; and

·       under our partnership agreement, it is not a breach of our general partner’s fiduciary duties for affiliates of our general partner to engage in activities that compete with us.

Specifically, the parent company of our general partner, BGH, is owned by its public unitholders, certain members of senior management, and by an affiliate of the Carlyle/Riverstone Global Energy and Power Fund II, L.P., which also owns, through affiliates, an interest in the general partner of Magellan Midstream Partners, L.P., and an interest in the general partner of SemGroup, L.P. SemGroup transports and stores crude oil, natural gas, natural gas liquids, refined products and asphalt through its ownership and operation of proprietary and common carrier pipelines, terminals, storage tanks, processing plants, underground storage facilities and a transportation fleet.  Additionally, an affiliate of Carlyle/Riverstone is a member of a group of investors that has agreed to purchase Kinder Morgan, Inc., which owns the general partner interest in Kinder Morgan Energy Partners, L.P. (“Kinder Morgan”), a publicly traded partnership engaged in the transportation and distribution of petroleum products primarily in the midwestern United States. In January 2007, the Federal Trade Commission approved the closing of the transaction on the condition that Carlyle/Riverstone relinquish its control of Magellan Midstream Partners. Although neither the Partnership, on the one hand,  nor Magellan Midstream Partners or SemGroup on the other hand, has extensive operations in the geographic areas primarily served by the other entity, the Partnership will compete directly with Magellan Midstream Partners, SemGroup L.P., Kinder Morgan, and perhaps other entities in which Carlyle/Riverstone or its affiliates have an interest for acquisition opportunities and potentially will compete with one or more of these entities for new business or extensions of the existing services provided by our Operating Subsidiaries, creating actual and potential conflicts of interest between the Partnership and affiliates of our general partner.

A default under BGH’s Credit Facility could result in a change of control of our general partner which would be an event of default under our revolving credit facility.

BGH is a party to a $10.0 million credit agreement with SunTrust Bank, pursuant to which it has pledged its ownership interest in our general partner as collateral security for its obligations under this

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agreement. If BGH were to default on its obligations under its credit agreement, its lender could exercise its rights under this pledge which could result in a change of control of our general partner and a change of control of us. A change of control would constitute an event of default under our revolving credit facility and require the administrative agent, upon request of the lenders providing a majority of the loan commitments or outstanding loan amounts, to declare all amounts payable by us under our revolving credit facility immediately due and payable.

Unitholders have limited voting rights and control of management.

Our general partner manages and controls our activities and the activities of our Operating Subsidiaries. Unitholders have no right to elect the general partner or the directors of the general partner on an annual or other ongoing basis. However, if the general partner resigns or is removed, its successor must be elected by holders of a majority of the limited partner units. Unitholders may remove the general partner only by a vote of the holders of at least 80% of the limited partner units and only after receiving certain state regulatory approvals required for the transfer of control of a public utility. As a result, Unitholders will have limited influence on matters affecting our operations, and third parties may find it difficult to gain control of us or influence our actions.

Our partnership agreement limits the liability of our general partner.

Our general partner owes fiduciary duties to our Unitholders. Provisions of our partnership agreement and the partnership agreements for each of our operating partnerships, however, contain language limiting the liability of the general partner to the Unitholders for actions or omissions taken in good faith which do not involve gross negligence or willful misconduct. In addition, the partnership agreements grant broad rights of indemnification to the general partner and its directors, officers, employees and affiliates.

Unitholders may not have limited liability in some circumstances.

The limitations on the liability of holders of limited partnership interests for the obligations of a limited partnership have not been clearly established in some states. If it were determined that we had been conducting business in any state without compliance with the applicable limited partnership statute, or that the Unitholders as a group took any action pursuant to our partnership agreement that constituted participation in the “control” of our business, then the Unitholders could be held liable under some circumstances for our obligations to the same extent as a general partner.

Under applicable state law, our general partner has unlimited liability for our obligations, including our debts and environmental liabilities, if any, except for our contractual obligations that are expressly made without recourse to the general partner.

In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that under some circumstances a Unitholder may be liable to us for the amount of distributions paid to the Unitholder for a period of three years from the date of the distribution.

Tax Risks to Unitholders

Unitholders are urged to read the section above entitled “Tax Considerations for Unitholders” beginning on page 16 for a more complete discussion of the expected material federal income tax consequences of owning and disposing of limited partner units.

The IRS could treat us as a corporation for tax purposes or changes in law could subject us to entity-level taxation, which would substantially reduce the cash available for distribution to Unitholders.

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The availability to a Unitholder of the anticipated after tax economic benefits of an investment in limited partner units depends, in large part, on our classification as a partnership for federal income tax purposes. No ruling from the Internal Revenue Service, or the IRS, as to this status has been or is expected to be requested.

If we were classified as a corporation for federal income tax purposes, we would be required to pay tax on our taxable income at corporate tax rates (currently a 35% federal rate), and distributions received by the Unitholders would generally be taxed a second time as corporate distributions. Because a tax would be imposed upon us as an entity, the cash available for distribution to the Unitholders would be substantially reduced. Treatment of us as a corporation would cause a material reduction in the anticipated cash flow and after-tax return to the Unitholders, likely causing a substantial reduction in the value of the limited partner units.

The law could be changed so as to cause us to be treated as a corporation for federal income tax purposes or otherwise to be subject to entity-level taxation. For example, a new entity level tax on the portion of our income that is generated in Texas will begin in our tax year ending in 2007. Specifically, the Texas margin tax will be imposed at a maximum effective rate of 0.7% of our gross income apportioned to Texas. Imposition of such a tax on us by Texas will reduce the cash available for distribution to our Unitholders.

A successful IRS contest of the federal income tax positions that we take may adversely affect the market for limited partner units.

We have not requested a ruling from the IRS with respect to our classification as a partnership for federal income tax purposes. Accordingly, the IRS may adopt positions that differ from the conclusions expressed in this report or the positions taken by us. It may be necessary to resort to administrative or court proceedings in an effort to sustain some or all of such conclusions or the positions taken by us. A court may not concur with some or all of our positions. Any contest with the IRS may materially and adversely impact the market for the limited partner units and the prices at which they trade. In addition, the costs of any contest with the IRS will be borne directly or indirectly by the Unitholders and our general partner.

Unitholders may be required to pay taxes even if they do not receive any cash distributions.

A Unitholder will be required to pay federal income taxes and, in some cases, state and local income taxes on the Unitholder’s allocable share of our income, even if the Unitholder receives no cash distributions from us. We cannot guarantee that a Unitholder will receive cash distributions equal to the Unitholder’s allocable share of our taxable income or even the tax liability to the Unitholder resulting from that income. Further, if we incur a large amount of nonrecourse indebtedness, a Unitholder may incur a tax liability upon the sale of the Unitholder’s limited partner units in excess of the amount of cash received in the sale.

Ownership of limited partner units may have adverse tax consequences for tax-exempt organizations and certain other investors.

Investment in limited partner units by certain tax-exempt entities, regulated investment companies and foreign persons raises issues unique to them. For example, virtually all of our taxable income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and thus will be taxable to the Unitholder. Distributions to foreign persons will be reduced by withholding taxes. Further, Unitholders who are nonresident aliens, foreign corporations or other foreign persons will be required to file a federal income tax return and pay tax on their respective allocable shares of our taxable income because they will be regarded as being engaged in a trade or business in the United States as a result of their ownership of limited partner units.

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There are limits on the deductibility of our losses that may adversely affect Unitholders.

There are a number of limitations that may prevent Unitholders from using their allocable share of our losses as a deduction against unrelated income. In the case of taxpayers subject to the passive loss rules (generally, individuals and closely-held corporations), any losses generated by us will only be available to offset our future income and cannot be used to offset income from other activities, including other passive activities or investments. Unused losses may be deducted when the unitholder disposes of the Unitholder’s entire investment in us in a fully taxable transaction with an unrelated party. A Unitholder’s share of our net passive income may be offset by unused losses from us carried over from prior years, but not by losses from other passive activities, including losses from other publicly traded partnerships. Other limitations that may further restrict the deductibility of our losses include the at-risk rules and the prohibition against loss allocations in excess of limited partner unit tax basis.

Tax gain or loss on disposition of limited partner units could be different than expected.

A Unitholder who sells limited partner units will recognize gain or loss equal to the difference between the amount realized from the sale (which will include the Unitholder’s share of our liabilities to the extent deemed relieved in the sale) and the Unitholder’s adjusted tax basis in the sold limited partner units (which will include the Unitholder’s share of our liabilities only if not previously used to support loss allocations or to defer tax on our distributions). Prior distributions in excess of cumulative net taxable income allocated to a Unitholder with respect to a limited partner unit which decreased such Unitholder’s tax basis in that limited partner unit will, in effect, become taxable income if the limited partner unit is sold at a price greater than the Unitholder’s tax basis in that limited partner unit, even if the price is less than the unit’s original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income.

The reporting of partnership tax information is complicated and subject to audits.

We will furnish each Unitholder with a Schedule K-1 that sets forth the Unitholder’s share of our income, gains, losses and deductions. We cannot guarantee that these schedules will be prepared in a manner that conforms in all respects to statutory or regulatory requirements or to administrative pronouncements of the IRS. Further, our tax return may be audited, which could result in an audit of a Unitholder’s individual tax return and increased liabilities for taxes because of adjustments resulting from the audit.

There is a possibility of loss of tax benefits relating to nonconformity of limited partner units and nonconforming depreciation conventions.

Because we cannot match transferors and transferees of limited partner units, uniformity of the tax characteristics of the limited partner units to a purchaser of limited partner units of the same class must be maintained. To maintain uniformity and for other reasons, we have adopted certain depreciation and amortization conventions that may not conform with all aspects of applicable Treasury regulations. A successful challenge to those conventions by the IRS could adversely affect the amount and timing of tax benefits available to a purchaser of limited partner units, as well as the amount of gain recognized from a sale of the limited partner units, and could have a negative impact on the value of the limited partner units.

Unitholders will likely be subject to state, local and other taxes in states where they do not reside or as a result of an investment in the limited partner unit.

In addition to United States federal income taxes, Unitholders will likely be subject to other taxes, such as state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which the Unitholder resides or in which we do business or own property. A Unitholder will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of the various jurisdictions in which we do business or own property and

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may be subject to penalties for failure to comply with those requirements. It is the responsibility of each Unitholder to file all applicable United States federal, state, local and foreign tax returns.

Unitholders may have negative tax consequences if we default on our debt or sell assets.

If we default on any of our debt, the lenders will have the right to sue us for non-payment. This could cause an investment loss and negative tax consequences for Unitholders through the realization of taxable income by Unitholders without a corresponding cash distribution. Likewise, if we were to dispose of assets and realize a taxable gain while there is substantial debt outstanding and proceeds of the sale were applied to the debt, our Unitholders could have increased taxable income without a corresponding cash distribution.

Item 1B.               Unresolved Staff Comments

None.

Item 2.                        Properties

As of December 31, 2006, the principal facilities of the Partnership included approximately 5,400 miles of 6-inch to 24-inch diameter pipeline, approximately 100 delivery points and 45 active bulk storage and terminal facilities with aggregate capacity of approximately 17.6 million barrels. In addition, the Partnership owns four currently idle terminals with an aggregate storage capacity of 863,000 barrels. The Partnership’s pipelines are used by its Pipeline Operations segment and its terminals and storage facilities are used in its Terminalling and Storage segment. Properties used in the Partnership’s Other Operations segment include a 63% interest in a crude butadiene pipeline between Deer Park, Texas and Port Arthur, Texas, known as the Sabina pipeline, a 23-mile pipeline located in Texas that is leased to a third-party chemical company and a 29-mile ammonia pipeline located in Texas. The Operating Subsidiaries and their subsidiaries own substantially all of these facilities. The Partnership’s corporate headquarters in Breinigsville, Pennsylvania is approximately 75,000 square feet in size and is leased.

In general, the Partnership’s pipelines are located on land owned by others pursuant to rights granted under easements, leases, licenses and permits from railroads, utilities, governmental entities and private parties. Like other pipelines, certain of the Operating Subsidiaries’ rights are revocable at the election of the grantor or are subject to renewal at various intervals, and some require periodic payments. The Operating Subsidiaries have not experienced any revocations or lapses of such rights which were material to their business or operations, and the General Partner has no reason to expect any such revocation or lapse in the foreseeable future. Most delivery points, pumping stations and terminal facilities are located on land owned by the Operating Subsidiaries.

The General Partner believes that the Operating Subsidiaries have sufficient title to their material assets and properties, possess all material authorizations and revocable consents from state and local governmental and regulatory authorities and have all other material rights necessary to conduct their business substantially in accordance with past practice. Although in certain cases the Operating Subsidiaries’ title to assets and properties or their other rights, including their rights to occupy the land of others under easements, leases, licenses and permits, may be subject to encumbrances, restrictions and other imperfections, none of such imperfections are expected by the General Partner to interfere materially with the conduct of the Operating Subsidiaries’ businesses.

Item 3.                        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.

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With respect to environmental litigation, certain Operating Subsidiaries (or their predecessors) have been named in the past as defendants in lawsuits, or have been notified by federal or state authorities that they are potentially responsible parties (“PRPs”) under federal laws or a respondent under state laws relating to the generation, disposal or release of hazardous substances into the environment. In connection with actions brought under CERCLA and similar state statutes, the Operating Subsidiary is usually one of many PRPs for a particular site and its contribution of total waste at the site is usually de minimis.

Although there is no material environmental litigation pending against the Partnership or the Operating Subsidiaries at this time, claims may be asserted in the future under various federal and state laws, and the amount of any potential liability associated with such claims cannot be estimated. See “Business—Environmental Matters.”

In the third quarter of 2006 the Partnership received penalty assessments from the IRS in the aggregate amount of $4.3 million based on a failure to timely file excise tax information returns relating to its terminal operations from January 2005 through February 2006. The Partnership filed the information returns with the IRS on May 10, 2006. In January 2007, the Partnership agreed to pay the IRS approximately $0.6 million to settle and resolve the penalty assessment. The settlement is subject to the negotiation and execution of a closing agreement between the Partnership and the IRS. The negotiated penalty assessment has been recorded as an expense in the Partnership’s financial statements in the fourth quarter of 2006.

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

No matters were submitted to a vote of the holders of LP Units during the fourth quarter of the fiscal year ended December 31, 2006.

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PART II

Item 5.                        Market for the Registrant’s LP Units, Related Unitholder Matters, and Issuer Purchases of LP Units

The LP Units of the Partnership are listed and traded principally on the New York Stock Exchange. The high and low sales prices of the LP Units in 2006 and 2005, as reported in the New York Stock Exchange Composite Transactions, were as follows:

 

On February 7, 2005, the Partnership issued 1.1 million LP Units in an underwritten public offering at $45.00 per LP Unit. Proceeds from the offering, after the underwriter’s discount of $1.46 per unit and offering expenses, were approximately $47.7 million. Proceeds from the offering were used to repay, in part, amounts outstanding under the Partnership’s revolving line of credit and to fund the Partnership’s expansion and cost reduction capital expenditures.

On May 17, 2005, the Partnership issued 2.5 million LP Units in an underwritten public offering at $45.20 per LP Unit. Proceeds from the offering, after the underwriters’ discount of $1.80 per LP Unit and offering expenses, were approximately $108.4 million. Proceeds from the offering were used to repay $108 million that was outstanding under the Partnership’s revolving line of credit.

On March 7, 2006, the Partnership issued 1.5 million LP Units in an underwritten public offering at $44.22 per LP Unit. Proceeds from the offering, after the underwriter’s discount of $1.45 per LP Unit and offering expenses, were approximately $64.1 million.  Proceeds from the offering were used to repay amounts outstanding under the Partnership’s revolving line of credit.

The Partnership has gathered tax information from its known LP Unitholders and from brokers/nominees and, based on the information collected, the Partnership estimates its number of beneficial LP Unitholders to be approximately 50,000 at December 31, 2006.

Cash distributions paid during 2005 and 2006 were as follows:

 

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Item 6.                        Selected Financial Data

The following tables set forth, for the period and at the dates indicated, the Partnership’s income statement and balance sheet data for each of the last five years. The tables should be read in conjunction with the consolidated financial statements and notes thereto included elsewhere in this Report.

 

(1)          Net income in 2006 is $6.6 million higher due to the re-characterization, effective in the fourth quarter of 2006, of incentive compensation payments to the Partnership’s General Partner as equity distributions rather than compensation payments. See Note 21 to the Partnership’s financial statements for further discussion.

(2)          Net income in 2003 includes an expense of $45.5 million related to a yield maintenance premium paid on the retirement of the $240 million Senior Notes of Buckeye.

Item 7.                        Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion provides an analysis of the results for each of the Partnership’s operating segments, an overview of its liquidity and capital resources and other items related to the Partnership. The following discussion and analysis should be read in conjunction with the consolidated financial statements and related notes included in this Annual Report on Form 10-K for the year ended December 31, 2006.

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Overview

Buckeye Partners, L.P. (the “Partnership”) is a publicly traded master limited partnership (NYSE symbol: BPL) organized in 1986 under the laws of the state of Delaware. The Partnership’s principal line of business is the transportation, terminalling and storage of petroleum products in the United States for major integrated oil companies, large refined petroleum product marketing companies and major end users of petroleum products on a fee basis through facilities owned and operated by the Partnership. The Partnership also operates pipelines owned by third parties under contracts with major integrated oil and chemical companies, and performs certain construction activities, generally for the owners of those third-party pipelines.

The Partnership’s direct subsidiaries are Buckeye Pipe Line Company, L.P. (“Buckeye”), Laurel Pipe Line Company, L.P. (“Laurel”), Everglades Pipe Line Company, L.P. (“Everglades”), Buckeye Pipe Line Holdings, L.P. (“BPH”), Wood River Pipe Lines LLC (“Wood River”), Buckeye Pipe Line Transportation LLC (“BPL Transportation”) and Buckeye NGL Pipe Lines LLC (“Buckeye NGL”). Each of these entities is referred to as an “Operating Subsidiary” and they are collectively referred to as the “Operating Subsidiaries.” The Partnership owns an approximately 99% interest in each Operating Subsidiary except that it owns a 100% interest in each of Wood River, BPL Transportation and Buckeye NGL.

The Partnership’s pipeline system and terminals generate a substantial portion of the Partnership’s cash flows. The revenues generated by the Partnership’s businesses are significantly influenced by demand for refined petroleum products. Operating expenses are principally fixed costs related to routine maintenance and system integrity as well as field and support personnel. Other costs, including power, fluctuate with volumes transported in the Partnership’s pipelines or stored in its terminals. Expenses resulting from environmental remediation projects have historically included costs from projects relating both to current and past events. For further discussion of environmental matters, see “Business—Environmental Regulation” under Item 1 of this Annual Report on Form 10-K.

Strategic Actions

The Partnership’s primary business strategies are to generate stable cash flows, increase pipeline and terminal throughput and pursue strategic cash-flow accretive acquisitions that complement the Partnership’s existing asset base, improve operating efficiencies, and allow increased cash distributions to Unitholders. In the years 2004, 2005 and 2006, the Partnership significantly expanded its operations through the following asset acquisitions:

·       On October 1, 2004, the Partnership acquired five refined petroleum products pipelines with an aggregate mileage of approximately 900 miles and 24 refined products terminals with an aggregate storage capacity of 9.3 million barrels (the “Midwest Pipelines and Terminals”) from Shell Oil Products U.S. (“Shell”) for a purchase price of $517.0 million.

·       In May 2005, the Partnership acquired a refined petroleum products pipeline system comprising approximately 478 miles of pipeline and four refined products terminals with aggregate storage capacity of approximately 1.3 million barrels located principally in the northeastern United States (the “Northeast Pipelines and Terminals”) from affiliates of ExxonMobil Corporation (“ExxonMobil”) for a purchase price of $175.0 million.

·       In December 2005, the Partnership acquired a 26-mile pipeline and a 40% interest in a joint venture company that owns another refined petroleum products pipeline and terminal in the midwestern United States. It also acquired a refined petroleum products terminal and related assets (including certain railroad offloading facilities) located in Taylor, Michigan for a purchase price of $20.0 million.

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·       On January 1, 2006, the Partnership acquired a refined petroleum products terminal located in Niles, Michigan, with aggregate storage capacity of 630,000 barrels from affiliates of Shell for a purchase price of $13.0 million.

·       On January 31, 2006, the Partnership acquired a natural gas liquids pipeline (the “NGL Pipeline”) with aggregate mileage of approximately 350 miles from BP Pipelines (North America) Inc. for approximately $87.0 million, including a deposit of $7.7 million paid in December 2005. The NGL Pipeline extends generally from Wattenberg, Colorado to Bushton, Kansas.

The acquired assets have been included in the Partnership’s operations from their dates of acquisition.

Operating Segments

The Partnership has determined that its operations are appropriately presented in three operating segments:

·       Pipeline Operations,

·       Terminalling and Storage, and

·       Other Operations.

Pipeline Operations:

The Pipeline Operations segment receives petroleum products including gasoline, jet fuel, diesel fuel and other distillates and natural gas liquids from refineries, connecting pipelines and bulk and marine terminals and transports those products to other locations by pipeline for a fee. As of December 31, 2006, this segment owned and operated approximately 5,400 miles of pipelines in the following states: California, Colorado, Connecticut, Florida, Illinois, Indiana, Kansas, Massachusetts, Michigan, Missouri, New Jersey, Nevada, New York, Ohio, Pennsylvania and Tennessee.

Terminalling and Storage:

The Terminalling and Storage segment provides bulk storage and terminal throughput services. This segment consists of 45 active terminals that have the capacity to store an aggregate of approximately 17.6 million barrels of refined petroleum products. The terminals are located in Illinois, Indiana, Massachusetts, Michigan, Missouri, New York, Ohio and Pennsylvania.

Other Operations:

The Other Operations segment consists primarily of the Partnership’s operation of third-party pipelines owned principally by major petrochemical companies pursuant to operations and maintenance contracts. The third party pipelines are located primarily in Texas. This segment also includes the provision by the Partnership, through its Buckeye Gulf Coast subsidiary, of pipeline construction management services, typically on a cost plus a fixed fee basis. The Other Operations segment also includes the Partnership’s ownership and operation of an ammonia pipeline acquired in November 2005, and its majority ownership of a crude butadiene pipeline located in Texas.

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Results of Operations

Summary

Summary operating results for the Partnership were as follows:

 

The improvement in revenues, operating income and net income in 2006 compared to 2005, and 2005 compared to 2004, is generally due to the expansion of the Partnership’s operations through acquisitions, internal growth projects, and increases in interstate pipeline tariff rates and terminalling throughput fees.

The Partnership’s net income in 2006 reflects an amendment of the Partnership’s Incentive Compensation Agreement and Partnership Agreement between the General Partner and the Partnership which changed the incentive compensation paid to the General Partner from a compensation payment to a partnership distribution as described in Note 21 to the Partnership’s financial statements. These amendments affected the Partnership’s results of operations commencing in the fourth quarter of 2006. Accordingly, net income for 2006 was $6.6 million higher than it would have been if the Partnership Agreement had not been amended.

Earnings per limited partner unit as shown above were impacted by the issuance of 1.5 million LP Units in March 2006, 2.5 million LP Units in May 2005, 1.1 million LP Units in February 2005 and 5.5 million LP units in October 2004.

EBITDA and Adjusted EBITDA

The following table summarizes EBITDA and adjusted EBITDA for the Partnership for the years ended December 31, 2006, 2005 and 2004. EBITDA, a measure not defined under generally accepted accounting principles (“GAAP”) is defined by the Partnership as income before interest expense (including amortization and write-off of deferred debt financing costs), income taxes, depreciation and amortization. Adjusted EBITDA, also a non-GAAP measure, is defined as EBITDA plus the General Partner incentive compensation expense. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, operating profit, cash flow from operations or any other measure of financial performance presented in accordance with GAAP.

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Because EBITDA and Adjusted EBITDA exclude some items that affect net income and these items may vary among other companies, the EBITDA and Adjusted EBITDA data presented may not be comparable to similarly titled measures at other companies. The Partnership has provided Adjusted EBITDA in addition to EBITDA because, commencing in the fourth quarter of 2006, the Partnership reports incentive payments to the General Partner as equity distributions, rather than incentive compensation expense as reported in periods prior to the fourth quarter of 2006. See Note 21 to the Partnership’s consolidated financial statements for a further discussion of this change. Accordingly, the General Partner incentive compensation presented below includes only three quarters of incentive payments and does not include the $6.6 million incentive payment paid in the fourth quarter of 2006. Future periods will not reflect General Partner incentive payments as a component of net income. Management of the Partnership uses EBITDA and Adjusted EBITDA as performance measures to assist in the analysis and assessment of the Partnership’s operations, to evaluate the viability of proposed projects and to determine overall rates of return on alternative investment opportunities. The Partnership believes that investors benefit from having access to the same financial measures used by the Partnership’s management.

 

Revenues and operating income by operating segment for each of the three years ended December 31, 2006, 2005 and 2004, were as follows:

 

Results of operations are affected by factors that include general economic conditions, weather, competitive conditions, demand for refined petroleum products, seasonal factors and regulation. See Item 1—“Business—Competition and Other Business Considerations.”

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2006 Compared to 2005

Revenues

Total revenues for the year ended December 31, 2006 were $461.7 million and increased by $53.3 million or 13% from revenue of $408.4 million in 2005.

Operating income in 2006 increased to $177.1 million from  $161.3 million in 2005. The Partnership’s net income for 2006 was $110.2 million compared to net income in 2005 of $100.0 million. Net income per LP Unit was $2.64 in 2006 compared to net income per LP Unit of $2.69 in 2005. Net income per LP Unit in 2006 includes an increase in the average number of LP Units outstanding to 39.2 million from an average of 36.9 million LP Units outstanding during 2005.

Pipeline Operations:

Revenue from pipeline transportation of petroleum products was $350.9 million in 2006 compared to $306.8 million in 2005. The increase of $44.1 million was due primarily to higher volumes associated with pipeline assets acquired in 2006, or acquired in 2005 and operated for a full year in 2006, as well as tariff rate increases in connection with certain of the Partnership’s pipelines. More specifically, the increase in revenue in 2006 as compared to 2005 was due in part to:

·       BPL Transportation revenue of $6.9 million (BPL Transportation’s assets were acquired on May 5, 2005);

·       Buckeye NGL revenue of  $10.8 million (Buckeye NGL’s assets were acquired on January 31, 2006);

·       a 1.2% or $1.7 million increase  net of BPL Transportation, in gasoline transportation revenue, on a 2.3% decline in gasoline volumes;

·       a 13.0% or $6.4 million increase net of BPL Transportation, in jet fuel transportation revenue on an 8.2% increase in jet fuel volumes delivered;

·       an 8.7% or $5.9 million increase net of BPL Transportation, in distillate transportation revenue on comparable distillate volumes delivered;

·       a $4.0 million increase in incidental revenue primarily from increased revenues under a product supply arrangement in connection with WesPac—Reno;

·       a $6.5 million increase in other revenues principally resulting from commencement of the pipeline and terminal operations of WesPac—Memphis in April 2006;

·       a $5.5 million decrease in transportation settlement revenue, representing the settlement of overages and shortages on product deliveries.

Product deliveries for each of the three years ended December 31 were as follows:

 

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During the approximate eight months in 2005 that the Partnership owned the BPL Transportation pipeline system, volumes on the BPL Transportation pipeline system averaged 74,400 barrels per day. Volumes on all of the Partnership’s other pipelines (excluding the BPL Transportation pipeline system) averaged 1,335,800 barrels per day for 2005.

Terminalling and Storage:

Terminalling and Storage revenues were $81.3 million in 2006 and increased by $12.4 million from Terminalling and Storage revenues generated in 2005.

Terminal acquisitions increased Terminalling and Storage revenues by $5.9 million for the year ended December 31, 2006 compared to 2005. The increase in terminal revenue associated with acquisitions reflects terminals acquired in 2006 and terminals acquired in 2005 and operated for a full year in 2006.

Terminalling and Storage revenues at existing terminals owned by the Partnership were $75.4 million for the year ended December 31, 2006, an increase of $6.5 million from Terminalling and Storage revenues generated  by those terminals in 2005.

Average daily throughput for all refined petroleum products terminals for the years ended December 31 was as follows:

 

Other Operations:

Revenue from Other Operations of $29.6 million for the year ended December 31, 2006 decreased by $3.1 million from 2005 primarily as a result of the absence of a large construction project which provided approximately $7.7 million of revenue in 2005.

Operating Expenses

Costs and expenses for the years ended December 31, 2006, 2005 and 2004 were as follows:

 

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Payroll and payroll benefits costs were $78.5 million in 2006, an increase of $5.6 million from 2005. Of this increase, approximately $3.5 million was related to the hiring of additional employees as a result of recent acquisitions. Increases in salaries and wages of $6.0 million resulted from an increase in the number of employees and overtime pay due to the Partnership’s expanded operations and higher wage rates. The Partnership also experienced an increase in benefit costs of $0.4 million. These increases were partially offset by an increase of capitalized payroll of $0.8 million resulting from increased charges to capital projects by internal personnel and a decrease in severance pay. The Partnership incurred expense of $0.4 million for severance pay in 2005 which did not occur during 2006. Payroll and benefits expense was also reduced by $2.0 million as a result of a reduction in the fair value of the Partnership’s liability under the Services Agreement to make future cash payments to Services Company in amounts sufficient for Services Company’s ESOP to make payments due under its note agreement. The reduction in the fair value of this liability resulted from changes in estimates of future cash distributions likely to be paid on the Partnership’s LP Units owned by Services Company. Payroll and benefits expense was also reduced by $1.1 million in 2006 compared to 2005 as a result of lower incentive compensation accruals. In 2006, the Partnership accrued approximately $0.9 million in annual incentive compensation for employees, compared to approximately $2.0 million in 2005.

Depreciation and amortization expense of $44.0 million increased by $7.3 million in 2006 over 2005. Depreciation related to acquisitions completed in 2006 was $3.5 million. The Partnership incurred depreciation expense of $0.7 million related to the Memphis Terminal which commenced operations in April 2006. The remaining increase resulted from assets placed into service during 2006.

Operating power costs, consisting primarily of electricity required to operate pumping facilities, were $28.9 million in 2006, an increase of $2.7 million over 2005. Recent acquisitions added $2.1 million to operating power expense. The remainder of the increase was principally due to higher rates associated with purchases of electricity.

Outside services costs, consisting principally of third-party contract services for maintenance activities, were $35.7 million in 2006, an increase of $11.3 million over 2005. Outside services costs related to recent acquisitions were $1.1 million. The Partnership incurred an additional $6.8 million for pipeline inspection and maintenance costs related to an operating service contract. The remainder of the increase was due to additional pipeline and tank inspections and maintenance work that occurred during 2006 as compared to 2005.

Property and other taxes were $20.9 million in 2006, an increase of $4.3 million over 2005. Of this increase, $1.1 million related to acquisitions completed in 2006. As more fully discussed in Note 4 to the financial statements, the Partnership incurred a $0.6 million charge related to a penalty assessment received from the IRS for failure to file excise tax information in a timely fashion. These increases were offset by a reimbursement of $0.9 million in 2006 for certain property taxes under an operating service agreement. The remainder of the increase was due to increased real estate property assessments over the same period in 2005.

Construction management costs were $8.4 million in 2006, a decrease from the prior year of $0.5 million. The decrease was a result of the absence of a significant construction contract that was completed in 2005.

All other costs were $68.1 million in 2006 compared to $61.3 million in 2005, an increase of $6.8 million. The increase reflects $3.1 million of costs associated with fuel purchases by WesPac Reno related to a product supply arrangement, with corresponding revenue included in the Partnership’s incidental revenue. Other costs related to recent acquisitions were $2.4 million. The Partnership had an increase in other expenses of $3.5 million related to the Memphis Terminal which commenced operations in April 2006. These increases were partially offset by a decrease in casualty losses of $2.5 million. The

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remainder of the increases related to various pipeline operating costs resulting from the Partnership’s expanded operations.

Costs and expenses by segment for the years ended December 31, 2006, 2005, and 2004 were as follows:

 

Total other income (expense) for the years ended December 31, 2006, 2005 and 2004 were as follows:

 

Investment and equity income for the year ended December 31, 2006 was $1.4 million higher than 2005. The increase was principally a result of equity income earned from the Partnership’s approximate 40% interest in Muskegon Pipeline LLC which was acquired in December 2005.

Interest and debt expense for the year ended December 31, 2006 was $8.8 million higher than 2005. The Partnership incurred approximately $3.3 million of additional interest expense in 2006 because its 5.125% Notes   that were issued in June of 2005 were outstanding for all of 2006. The balance of the increase in interest expense in 2006 resulted from higher average balances outstanding and higher interest rates on the Partnership’s revolving credit facility.

General Partner incentive compensation was $18.3 million for the year ended December 2006, as compared to $20.2 million in 2005, a decrease of $1.9 million. Since the latter part of 2004, this expense has steadily increased due to issuances of additional LP Units as well as increases in the quarterly distributions paid on the LP Units. As noted above and in Note 21 to the Partnership’s financial statements, in connection with the initial public offering  of BGH, the Partnership’s Incentive Compensation Agreement and Partnership Agreement were amended to change the incentive payments to equity distributions rather than compensation payments. This change reduced the amount reported as a compensation expense in 2006 by $6.6 million and the Partnership will report no General Partner incentive compensation expense in 2007 and future years.

2005 Compared to 2004

Revenues

Total revenues for the year ended December 31, 2005 were $408.4 million and increased by $84.9 million or 26.2% from revenue of $323.5 million in 2004.

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Pipeline Operations:

Revenue from pipeline transportation of petroleum products was $306.8 million in 2005 compared to $264.0 million in 2004. The increase of $42.8 million in transportation revenue was primarily the result of:

·       a Wood River transportation revenue increase of $23.5 million (Wood River’s assets were acquired on October 1, 2004);

·       BPL Transportation revenue of $12.1 million (BPL Transportation’s assets were acquired on May 5, 2005);

·       a 3.7% average tariff rate increase effective May 1, 2005, and a 2.8% average tariff rate increase effective May 1, 2004;

·       a 2.8% or $3.5 million increase, net of Wood River and BPL Transportation, in gasoline transportation revenue on a 1.0% decrease in gasoline volumes delivered;

·       a 3.2% or $1.3 million increase, net of Wood River and BPL Transportation, in jet fuel transportation revenue on a 0.5% increase in jet fuel volumes delivered;

·       a 4.2% or $2.7 million increase, net of Wood River and BPL Transportation, in distillate transportation revenue on a 2.4% increase in distillate volumes delivered;

·       a decrease in liquefied petroleum gas (“LPG”) transportation revenue of $1.0 million as a result of lower LPG volumes delivered;

·       a decrease in transportation settlement revenue, representing the settlement of overages and shortages on product deliveries, of $3.4 million; and

·       a $3.7 million increase in incidental revenue primarily from increased revenues under a product supply arrangement in connection with WesPac Reno.

During the three months in 2004 that the Partnership owned the Wood River pipeline system, volumes on the Wood River pipeline system averaged 196,000 barrels per day. Volumes on all of the Partnership’s other pipelines (excluding the Wood River pipeline system) averaged 1,151,400 barrels per day for 2004.

During the approximate eight months in 2005 that the Partnership owned the BPL Transportation pipeline system, volumes on the BPL Transportation pipeline system averaged 74,400 barrels per day. Volumes on all of the Partnership’s other pipelines (excluding the BPL Transportation pipeline system) averaged 1,335,800 barrels per day for 2005.

Terminalling and Storage:

Terminalling and storage revenues were $68.8 million in 2005 and increased by $42.5 million from 2004.

The terminals acquired from Shell on October 1, 2004 (the “Shell Terminals”) generated terminalling and storage revenues of $48.9 million in 2005. This was $39.7 million greater than the terminalling and storage revenues generated by the Shell terminals during the three months they were owned by the Partnership in 2004. The terminals acquired from ExxonMobil on May 5, 2005 (the “ExxonMobil Terminals”) generated terminalling and storage revenues of $3.9 million in 2005.

Terminalling and storage revenues at other facilities owned by the Partnership were $16.0 million in 2005, a decline of $1.1 million from 2004. The decline in revenue resulted from a decrease in throughput charges of $1.8 million that was partially offset by a $0.7 million increase in rent and incidental charges.

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Other Operations:

Revenue from other operations of $32.8 million for the year ended December 31, 2005 decreased by $0.4 million from 2004. Revenues from other operating activities include revenue from pipeline construction activities of $12.0 million, contract operating services of $14.2 million and rental revenues of $6.6 million.

Operating Expenses

Payroll and payroll benefits costs were $72.9 million in 2005, an increase of $11.8 million over 2004. Of this increase, approximately $7.4 million, which represented payroll and payroll benefit costs for the first nine months of 2005, was related to employees added as a result of the acquisition of the Midwest Pipelines and Terminals on October 1, 2004. Employees hired in connection with the acquisition of the Northeast Pipelines and Terminals added $2.0 million of payroll and payroll benefits costs. Of the remaining increase of $2.4 million of payroll costs, approximately $1.8 million resulted from increases in wage rates in 2005 compared to 2004.

Depreciation and amortization expense of $36.8 million increased by $10.8 million in 2005 over 2004. Depreciation related to the Midwest Pipelines and Terminals for the first nine months of 2005 was $7.6 million. The Northeast Pipelines and Terminals added $2.3 million of depreciation expense in 2005. The remaining increase of $0.9 million resulted from the Partnership’s ongoing maintenance and expansion capital program.

Operating power costs, consisting primarily of electricity required to operate pumping facilities, were $26.2 million in 2005, an increase of $3.3 million over 2004. The Midwest Pipelines and Terminals added $2.3 million in operating power costs from January 1 through September 30, 2005, and the Northeast Pipelines and Terminals added $1.7 million in operating power costs from the date of acquisition in May 2005. Increases in operating power costs that resulted from the acquisitions of the Midwest Pipelines and Terminals and Northeast Pipelines and Terminals were partially offset by a decrease of $0.8 million at the Partnership’s Buckeye Gulf Coast subsidiary related to the loss of an operations and maintenance contract with a third party in 2004.

Outside services costs, consisting principally of third-party contract services for maintenance activities, were $24.4 million in 2005, an increase of $4.5 million over 2004. Outside services costs related to the Midwest Pipelines and Terminals  and Northeast Pipelines and Terminals for 2005 were $4.5 million and $0.8 million,  respectively.

Property and other taxes were $16.6 million in 2005, an increase of $3.3 million over 2004. Property and other taxes related to the Midwest Pipelines and Terminals were $1.9 million. The Northeast Pipelines and Terminals added $1.3 million of property and other taxes. Of the remaining increase, the Partnership experienced higher real property tax assessments in several states.

Construction management costs were $8.9 million in 2005, a decrease from the prior year of $3.4 million. The decrease in construction management costs was a result of the completion of a major construction contract with a chemical company which began in 2004 and was completed in the first quarter of 2005.

All other costs were $61.3 million in 2005 compared to $45.8 million in 2004, an increase of $15.5 million. Other costs related to the Midwest Pipelines and Terminals and Northeast Pipelines and Terminals were $7.1 million and $3.8 million, respectively. The Partnership experienced an increase of $3.5 million in costs related to a product supply arrangement over such costs in 2004. Casualty losses, net of the Midwest Pipelines and Terminals and Northeast Pipelines and Terminals, increased by $1.1 million primarily as a result of pipeline and terminal product releases in 2005.

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Other income (expense) was a net expense of $61.4 million in 2005, compared to a net expense of  $39.2 million in 2004.  Investment income in 2005 was consistent with investment income generated in 2004.

The Partnership incurred interest expense of $43.4 million in 2005 compared to $27.6 million in 2004, which is an increase of $15.8 million. Approximately $11.3 million of the interest expense incurred in 2005 related to the Partnership’s 5.300% Notes due 2014, which were issued in October 2004 in connection with the acquisition of the Midwest Pipelines and Terminals.  The Partnership incurred approximately $3.2 million in interest expense related to the 5.125% Notes due 2017, which were issued in June 2005 primarily in connection with the acquisition of the Northeast Pipelines and Terminals. Interest expense was reduced by $2.6 million in 2004 as a result of the interest rate swap in effect until December 2004. Increases in interest expense in 2005 were partially offset by an increase in capitalized interest which was due to an increase in capital projects in 2005.

General Partner incentive compensation was $20.2 million in 2005 compared to $14.0 million in 2004, an increase of $6.2 million. The increase in incentive compensation paid to the General Partner resulted from the issuance of 1.1 million LP Units in February 2005, the issuance of 2.5 million LP Units in May 2005, the full year impact of the issuance of the 5.5 million LP units in October 2004 and an increase in the quarterly distribution rate on the LP Units  to Unitholders in 2005 compared to 2004.

Liquidity and Capital Resources

The Partnership’s financial condition at December 31, 2006, 2005, and 2004 is highlighted in the following comparative summary:

Liquidity and Capital Indicators

(1)          current assets divided by current liabilities

(2)          current assets minus current liabilities

(3)          long-term debt divided by long-term debt plus total partners’ capital

(4)          total partners’ capital divided by total units outstanding at year-end.

During 2006, 2005 and 2004 the Partnership’s principal sources of cash were cash from operations, borrowings under its revolving credit facility and proceeds from the financing transactions described under “Cash Flows from Financing Activities” below. The Partnership’s principal uses of cash are capital expenditures, investments and acquisitions, distributions to Unitholders and repayments of borrowings.

At December 31, 2006, the Partnership had $995.0 million aggregate principal amount of long-term debt, which consisted of $300.0 million of the Partnership’s 4.625% Notes due 2013 (the “4.625% Notes”), $275.0 million of the Partnership’s 5.30% Notes due 2014 (the “5.30% Notes”), $150.0 million of the Partnership’s 6.75% Notes due 2033 (the “6.75% Notes”), $125.0 million of the Partnership’s 5.125% Notes due 2017 (the “5.125% Notes”) and $145.0 million outstanding under the Partnership’s revolving credit facility.

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On November 13, 2006 the Partnership entered into a new $400.0 million 5-year revolving credit facility (the “Credit Facility”) with a syndicate of banks. The Credit Facility, which replaced the Partnership’s previous $400.0 million credit facility, contains a one-time expansion feature up to $600.0 million subject to certain conditions. Borrowings under the Credit Facility are guaranteed by certain of the Partnership’s subsidiaries. The Credit Facility matures on November 13, 2011 but may be extended for up to two additional 12-month periods under certain circumstances. The weighted average interest rate on amounts outstanding under the Credit Facility at December 31, 2006 was 5.59%.

Borrowings under the Credit Facility bear interest under one of two rate options, selected by the Partnership, equal to either (i) the greater of (a) the federal funds rate plus 0.5% and (b) SunTrust Bank’s prime rate plus an applicable margin, or (ii) the London Interbank Offered Rate (“LIBOR”) plus an applicable margin. The applicable margin is determined based on the current utilization level of the Credit Facilitly and ratings assigned by Standard & Poor’s and Moody’s Investor Services for the Partnership’s senior unsecured non-credit enhanced long-term debt.  At December 31, 2006 and December 31, 2005, the Partnership had $145.0 million and $50.0 million outstanding under the Credit Facility and its predecessor credit facility, respectively, and had committed $2.1 million and $1.7 million in support of letters of credit, respectively.

The Credit Facility contains covenants and provisions that:

·       Restrict the Partnership and certain of its subsidiaries’ ability to incur additional indebtedness based on a Funded Debt ratio described below;

·       Prohibit the Partnership and certain of its subsidiaries from creating or incurring certain liens on their property;

·       Prohibit the Partnership and certain of its subsidiaries from disposing of property material to their operations; and

·       Limit consolidations, mergers and asset transfers by the Partnership and certain of its subsidiaries.

The Credit Facility requires that the Partnership and certain of its subsidiaries maintain a maximum “Funded Debt Ratio” which is calculated using “EBITDA” as defined in the Credit Facility. The Credit Facility’s definition of EBITDA is substantially the same as the Partnership’s definition above for EBITDA (for quarterly periods commencing with the fourth quarter of 2006) and Adjusted EBITDA (for quarterly periods commencing prior to the fourth quarter of 2006), except that the Credit Facility excludes the income of certain majority-owned subsidiaries and equity investments, though distributions from these excluded entities to the Partnership are included in EBITDA.

The Partnership’s Funded Debt Ratio at the end of any quarterly period equals the ratio of the long-term debt of the Partnership and certain of its subsidiaries (including the current portion, if any) to EBITDA for the previous four fiscal quarters. As of the end of any fiscal quarter, the Funded Debt Ratio may not exceed 4.75 to 1.00, subject to a provision for increases to 5.25 to 1.00 in connection with future acquisitions. At December 31, 2006 the Partnership’s Funded Debt Ratio was 4.40 to 1.00.

The Credit Facility provides for a “change of control” event of default that will be triggered if (i) Carlyle/Riverstone ceases to beneficially own 100% of the sole general partner of BGH, (ii) BGH ceases to own 100% of our general partner or (iii) our general partner ceases to be our sole general partner.

At December 31, 2006 the Partnership was in compliance with all of the covenants under the Credit Facility.

The Partnership’s financial strategy is to maintain an investment-grade credit rating, which involves, among other things, the issuance of additional LP Units in connection with the Partnership’s acquisitions

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and internal growth activities in order to maintain acceptable financial ratios, including total debt to total capital. From 2003 through 2006 the Partnership raised net proceeds of approximately $439.3 million from the issuance of its LP Units in support of its acquisition and growth strategies. The Partnership may issue additional LP Units in 2007 and beyond to partially fund acquisitions and internal growth activities, market conditions permitting. The Partnership is subject, however, to changes in the equity markets for its LP Units, and there can be no assurance the Partnership will be able or willing to access the public or private markets for its LP Units in the future. If the Partnership were unable to issue additional LP Units, the Partnership would be required to either restrict potential future acquisitions or pursue other debt financing alternatives, some of which could involve higher costs.

Cash Flows from Operations

The components of cash flows from operations for the years ended December 31, 2006, 2005 and 2004 were as follows:

 

Cash flows from operations were $149.0 million in 2006, compared to $142.5 million in 2005, an increase of $6.5 million. The principal reason for the increase was the increase in the Partnership’s net income of $10.3 million and an increase of $7.3 million in depreciation and amortization, a non-cash expense, which were partially offset by increased working capital requirements in 2006 as compared to 2005 of $9.8 million. Depreciation and amortization increased principally from the acquisition of new assets in 2005 and 2006, as well as the Partnership’s ongoing capital programs.

During 2006, the increase in cash used in working capital resulted primarily from increases in trade receivables of $12.2 million and prepaid insurance and other current assets of $22.8 million. The increase in trade receivables was principally due to the expansion of the Partnership’s business (the acquisition of the NGL Pipeline and certain terminals along with the commencement of operations at WesPac—Memphis), as well as the timing of pipeline billings at year-end. The increase in prepaid and other current assets resulted from receivables of $6.3 million related to activities on the ammonia pipeline purchased by the Partnership in November 2005, increases of $8.5 million resulting from amounts determined to be recoverable from insurance companies related to environmental remediation expenditures, an increase in prepaid insurance of $2.6 million as well as other increases totaling $4.4 million. A portion of the insurance receivables related to amounts billed to the insurance companies, with the balance relating to anticipated future expenditures at identified remediation sites. These decreases in cash were partially offset by an increase in accrued and other current liabilities of $18.0 million. Of this increase, $6.1 million related to payables arising from activity on the ammonia pipeline purchased in November 2005, $5.5 million related to the current portion of environmental liabilities (a portion of which is recoverable from insurance as described above) and $4.8 million related to other current liabilities. The change in other assets and liabilities resulted principally from the absence in 2006 of the accrual of certain long-term environmental liabilities which occurred in 2005.

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Cash flows from operations were $142.5 million in 2005, compared to $99.7 million in 2004, an increase of $42.8 million. The principal reason for the increase was the Partnership’s increase in net income of $17.0 million, coupled with an increase in depreciation and amortization of $10.8 million, a non-cash expense. Depreciation and amortization increased by $10.8 million as a result of the inclusion of the Midwest Pipelines and Terminals for twelve months in 2005 compared to three months in 2004, as well as the addition of the Northeast Pipelines and Terminals in May 2005, along with ongoing capital additions. Also, in 2004 the Partnership experienced a $13.4 million increase in working capital resulting from the operations it acquired with the Midwest Pipelines and Terminals which was not repeated in 2005 (working capital increased by $1.1 million). In 2005, an increase in trade and other receivables of $6.4 million and construction and pipeline relocation receivables of $1.2 million (related to timing of pipeline billings) were principally offset by a reduction in prepaid and other current assets of $5.9 million and an increase in accounts payable and accrued liabilities of $1.2 million. In 2004, trade receivables increased by $15.4 million and construction receivables increased by $4.4 million. The increase in trade receivables was related to increased outstanding billings related primarily to the terminal assets acquired as part of the Midwest Pipelines and Terminals. In connection with terminal revenue, the Partnership bills on a monthly basis, compared to the weekly basis used in pipeline billings. Construction and pipeline relocation receivables increased in 2004 due to an increase in construction activity in the fourth quarter. Prepaid and other current assets increased by $4.4 million in 2004, principally related to insurance receivables associated with environmental claims. Partially offsetting these reductions in 2004 cash from operations were increases in accounts payable of $0.7 million and accrued and other current liabilities of $10.3 million. The 2004 increase in accrued and other current liabilities resulted from an increase in accrued interest payable related to the timing of the semi-annual interest payments due on the Partnership’s 5.300% Notes issued in October 2004 and an increase in accrued environmental liabilities.

Cash Flows from Investing Activities

Net cash used in investing activities for the years ended December 31, 2006, 2005 and 2004 were as follows:

 

In 2006, the Partnership paid $94.3 million related to acquisitions, including $79.3 million related to the NGL Pipeline, $12.5 million related to the acquisition of the Niles, Michigan terminal and approximately $2.5 million for miscellaneous asset acquisitions.

In 2005, cash used for investments and acquisitions consisted of $176.3 million for the Northeast Pipelines and Terminals with the balance expended in connection with a terminal acquisition in Taylor, Michigan, a deposit of $7.7 million for the NGL Pipeline, the purchase of an ammonia pipeline located near Houston, TX and the acquisition of the 25% of WesPac - Reno not previously owned by the Partnership. In 2004, investments and acquisitions consisted of the acquisition of the Midwest Pipelines and Terminals. In addition, in December 2005, the Partnership acquired an approximately 26-mile pipeline and a 40% interest in Muskegon Pipeline LLC (“Muskegon”), which owns an approximately 170-mile pipeline which extends from Griffith, IN to Muskegon, MI (together, the “Pipeline Interests”). The Pipeline Interests were acquired in exchange for consideration that included capacity lease agreements (with purchase options) related to one of the Partnership’s pipelines and a terminal. The Partnership has

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recorded the Pipeline Interests at their estimated fair values of $20.1 million, with $4.8 million allocated to the 26-mile pipeline and $15.3 million allocated to the 40% interest in Muskegon.

Capital expenditures are summarized below:

 

In 2006, the Partnership incurred $30.2 million of sustaining capital expenditures and $62.5 million of expansion and cost reduction expenditures. The increase in sustaining capital expenditures related principally to construction of leasehold improvements to the Partnership’s new administrative offices in Breinigsville, PA and transition capital expenditures related to assets purchased in late 2005 and in 2006. Expansion projects in 2006 included $12.4 million to complete an approximate 11-mile pipeline and related terminal facilities to serve the Memphis International Airport, $12.1 million for the addition of pipelines, tankage and equipment to meet new handling requirements for ultra-low sulfur diesel, and $11.9 million for a capacity expansion in Illinois to handle additional LPG volumes. Other expansion projects underway in 2006 included various ethanol-blending and butane-blending projects at pipeline stations and terminals owned by the Partnership, and an expansion of pipeline and terminal infrastructure at the Memphis International Airport to accommodate a new generation of cargo planes for Federal Express Corporation. The Memphis International Airport project is owned by WesPac Pipelines—Memphis, a 75%-owned subsidiary of the Partnership.

The Partnership expects to spend approximately $80.0 million in capital expenditures in 2007, of which approximately $30.0 million is expected to relate to sustaining capital expenditures and $50.0 million is expected to relate to expansion and cost reduction projects. Sustaining capital expenditures include renewals and replacement of tank floors and roofs and upgrades to station and terminalling equipment, field instrumentation and cathodic protection systems.

During 2005, the Partnership’s capital expenditures of $77.8 million increased by $5.2 million from $72.6 million in capital expenditures in 2004. In 2005, sustaining capital expenditures decreased by $9.4 million to $23.4 million principally as a result of a reduction in pipeline and tank integrity capital expenditures of $11.3 million, which was only partially offset by an increase in operating infrastructure expenditures of $1.9 million. The reduction in pipeline and tank integrity expenditures occurred because (1) the Partnership completed much of the integrity work required, including electronic internal inspections, other integrity expenditures and associated repairs and improvements, as part of its comprehensive plan to comply with legal requirements and to improve the reliability of the Partnership’s pipelines and terminals (see “Business—Environmental Matters” and “Business—Pipeline Regulation and Safety Matters”) and (2) an increasing amount of the Partnership’s integrity expenditures were charged to expense in 2005 compared to 2004.

Until December 31, 2005, the Partnership’s initial integrity expenditures had been capitalized as part of pipeline cost when such expenditures improved or extended the life of the pipeline or related assets. Subsequent integrity expenditures have been expensed as incurred. As of January 1, 2006, the Partnership began charging all internal inspection integrity expenditures to expense, whether or not such expenditures were for the initial or subsequent internal inspection. In 2006, approximately $10.5 million of integrity costs

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were expensed compared to $3.0 million in 2005 and $0.9 million in 2004. The Partnership expects to charge approximately $10 million of integrity expenditures to expense in 2007.

Expansion and cost reduction capital expenditures were $54.4 million in 2005, an increase of $14.6 million from $39.8 million in 2004. The majority of these expenditures related to two major projects. During 2005, the Partnership expended $33.7 million on an approximately 11-mile pipeline and associated terminal to serve Federal Express at the Memphis International Airport. The project entered commercial service in the first quarter of 2006. In 2004, approximately $10.3 million was expended in connection with this project. Also in 2005, the Partnership expended approximately $9.3 million to complete a major expansion of the Partnership’s Laurel pipeline across Pennsylvania. In 2004, approximately $11.0 million was expended in connection with this project. The remaining $11.4 million of expansion and cost reduction capital expended in 2005 related to various other projects including a butane blending project associated with the Partnership’s Macungie, Pennsylvania station. In 2004, the Partnership expended approximately $12.8 million to complete the replacement of approximately 45 miles of pipeline in the Midwest between Lima, Ohio and Huntington, Indiana. The pipeline replacement project improved the reliability of the pipeline and expanded its capacity.

Total capital expenditures among the Partnership’s three operating segments were as follows:

 

Cash Flows from Financing Activities

In order to fund its acquisition and internal growth opportunities, the Partnership issued debt and equity securities and borrowed amounts under a Credit Facility (a portion of which were repaid with the proceeds from the issuance of debt and equity securities) in 2006, 2005 and 2004.

The Partnership’s financing transactions are summarized as follows:

Equity Securities:

On March 7, 2006, the Partnership issued 1.5 million LP Units in an underwritten public offering at $44.22 per LP Unit. Proceeds from the offering, after underwriter’s discount of $1.45 per LP Unit and offering expenses, were approximately $64.1 million and were used to reduce amounts outstanding under the Credit Facility.

On May 17, 2005, the Partnership issued 2.5 million LP Units in an underwritten public offering at $45.20 per LP Unit. Proceeds from the offering, after underwriters’ discount of $1.80 per LP Unit and offering expenses, were approximately $108.4 million. Proceeds from the offering were used to reduce amounts outstanding under the Credit Facility.

On February 7, 2005, the Partnership issued 1.1 million LP Units in an underwritten public offering at $45.00 per LP Unit. Proceeds from the offering, after underwriters’ discount of $1.46 per LP Unit and offering expenses, were approximately $47.7 million. Proceeds from the offering were used to reduce amounts outstanding under the Credit Facility and to fund the Partnership’s expansion and cost reduction capital expenditures.

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On October 19, 2004, the Partnership issued 5.5 million LP Units in an underwritten public offering at $42.50 per LP Unit. Proceeds from the LP Unit offering were approximately $223.3 million after underwriters’ discount of $1.806 per LP Unit and offering expenses and were used to reduce amounts outstanding under the Credit Facility.

Debt Securities:

On June 30, 2005, the Partnership sold $125 million aggregate principal amount of its 5.125% Notes due July 1, 2017 in an underwritten public offering. Proceeds from the note offering, after underwriters’ fees and expenses, were approximately $123.5 million. Proceeds from the offering were used in part to repay $122.0 million that was outstanding under the Credit Facility.

On October 1, 2004, in connection with the acquisition of the Midwest Pipelines and Terminals, the Partnership borrowed a total of $490.0 million, consisting of $300.0 million under a 364-day interim loan (the “Interim Loan”) and $190.0 million under the Credit Facility. On October 12, 2004, the Partnership sold $275.0 million aggregate principal amount of its 5.300% Notes due 2014 in an underwritten public offering. Proceeds from the note offering, after underwriter’s discount and commissions, were approximately $272.1 million. Proceeds from the note offering, together with additional borrowings under the Credit Facility, were used to repay the Interim Loan.

In addition to the above, the Partnership borrowed $177.0 million, $250.0 million and $320.0 million, and repaid $82.0 million, $273.0 million and $247.0 million under the Credit Facility (and its predecessor facility) in 2006, 2005 and 2004, respectively.

Distributions:

Distributions to Unitholders increased to $125.5 million in 2006 compared to $104.3 million in 2005 and $80.2 million in 2004. Distributions in 2006 increased over 2005 primarily as a result of increases in the unit distribution rate and the issuance of the 1.5 million LP Units in 2006. Additionally, distributions increased in 2006 by $6.6 million as a result of incentive payments to the General Partner being treated as distributions rather than compensation payments beginning in the fourth quarter of 2006. Distributions in 2005 increased over 2004 primarily as a result of increases in the unit distribution rate and the issuance of the 5.5 million LP Units in October 2004.

Debt Obligations, Credit Facilities and Other Financing

At December 31, 2006, the Partnership had $995.0 million in aggregate outstanding long-term debt, consisting of $125.0 million of the 5.125% Notes due 2017, $275.0 million of the 5.300% Notes due 2014, $300.0 million of the 4 5/8% Notes due 2013, $150.0 million of the 6 ¾% Notes due 2033 and $145.0 million outstanding under the Credit Facility. The terms of the Credit Facility are described in “Liquidity and Capital Resources” above. At December 31, 2006, the Partnership had $252.9 million available under the Credit Facility, with $2.1 million allocated in support of certain operational letters of credit.

In December 2004 the Partnership terminated an interest rate swap agreement and received proceeds of $2.0 million. Interest expense in the Partnership’s income statement was reduced by $2.6 million in 2004 as a result of the interest rate swap. The Partnership has deferred the $2.0 million gain as an adjustment to the fair value of the hedged portion of the Partnership’s debt and is amortizing the gain as a reduction of interest expense over the remaining life of the hedged debt. Interest expense was reduced by $0.2 million in both 2006 and 2005.

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Operating Leases

The Operating Subsidiaries lease certain land and rights-of-way. Minimum future lease payments for these leases as of December 31, 2006 were approximately $4.9 million for each of the next three years. Substantially all of these lease payments may be canceled at any time should the leased property no longer be required for operations.

The Partnership leases space in an office building and certain office equipment. Buckeye leases certain computing equipment and automobiles. Future minimum lease payments under these noncancelable operating leases at December 31, 2006 were as follows: $1.3 million for 2007, $1.1 million for 2008, $0.9 million for 2009, $1.0 million for 2010, $1.1 million for 2011 and $10.2 million in the aggregate thereafter.

Rent expense under operating leases was $10.3 million, $8.7 million and $8.5 million for 2006, 2005 and 2004, respectively.

Contractual Obligations

Contractual obligations are summarized in the following table:

 

Interest payable on fixed long-term debt obligations includes semi-annual payments required for the Partnership’s 4 5/8% Notes, its 6 3/4% Notes, its 5.300% Notes and its 5.125% Notes.

Amounts for acquisitions represents amounts for which the Partnership is contractually obligated to close in January 2007, including two refined petroleum products terminals located in Flint, Michigan and Woodhaven, Michigan.

Purchase obligations generally represent commitments for recurring operating expenses or capital projects.

The Partnership’s obligations related to its pension and postretirement benefit plans are discussed in Note 12 in the Partnership’s accompanying consolidated financial statements.

The Partnership’s interest payable under its Credit Facility is not reflected in the above table because such amounts depend on outstanding balances and interest rates which will vary from time to time. Based on balances outstanding and rates in effect at December 31, 2006, annual interest payments would be $8.1 million.

Environmental Matters

The Operating Subsidiaries are subject to federal, state and local laws and regulations relating to the protection of the environment. These laws and regulations, as well as the Partnership’s own standards

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relating to protection of the environment, cause the Operating Subsidiaries to incur current and ongoing operating and capital expenditures. Environmental expenses are incurred in connection with emergency response activities associated with the release of petroleum products to the environment from the Partnership’s pipelines and terminals, and in connection with longer term environmental remediation efforts which may involve, for example, groundwater monitoring and treatment. The Partnership regularly incurs expenses in connection with these environmental remediation activities. In 2006, the Operating Subsidiaries incurred operating expenses of $6.2 million and at December 31, 2006, had $29.2 million accrued for environmental matters. At December 31, 2006, the Partnership estimates that approximately $8.0 million of environmental expenditures incurred will be covered by insurance. These recovery amounts have not been included in expense in the Partnership’s financial statements. The Partnership maintains environmental liability insurance covering all of its pipelines and terminals with a per occurrence deductible in the amount of $3.0 million. Expenditures, both capital and operating, relating to environmental matters are expected to continue due to the Partnership’s commitment to maintaining high environmental standards and to comply with increasingly rigorous environmental laws.

Employee Stock Ownership Plan

Services Company provides an employee stock ownership plan (the “ESOP”) to the majority of its regular full-time employees hired before September 16, 2004. Effective September 16, 2004, new employees, including employees hired by Services Company from BGC, Buckeye Terminals and Norco on December 26, 2004, do not participate in the ESOP. The ESOP owns all of the outstanding common stock of Services Company. As of December 31, 2006, Services Company owned 2,313,395 LP Units of the Partnership. As of the same date, the ESOP was directly obligated to a third-party lender for $27.2 million of 3.60% Notes due 2011 (the “ESOP Notes”). The ESOP Notes were issued on May 4, 2004 to refinance Services Company’s 7.24% Notes which were originally issued to purchase Services Company common stock. The ESOP Notes are secured by 2,313,395 shares of Services Company’s common stock. The Partnership has committed that, in the event that the value of the LP Units owned by Services Company falls to less than 125% of the balance payable under the ESOP Notes, the Partnership will fund an escrow account with sufficient assets to bring the value of the total collateral (the value of the LP Units owned by Services Company and the escrow account) up to the 125% minimum. Amounts deposited in the escrow account are returned to the Partnership when the value of the LP Units owned by Services Company returns to an amount which exceeds the 125% minimum. At December 31, 2006, the value of the LP Units was approximately $108 million, which exceeded the 125% minimum requirement.

Services Company common stock is released to employee accounts in the proportion that current payments of principal and interest on the ESOP Notes bear to the total of all principal and interest payments due under the ESOP Notes. Individual employees are allocated shares based on the ratio of their eligible compensation to total eligible compensation. Eligible compensation generally includes base salary, overtime payments and certain bonuses.

The Partnership contributed 2,573,146 LP Units to Services Company in August 1997 in exchange for the elimination of the Partnership’s obligation to reimburse its general partner and the parent of its general partner for certain executive compensation costs, a reduction of the incentive compensation paid by the Partnership to its general partner, and other changes that made the ESOP a less expensive fringe benefit for the Partnership. Funding for the ESOP Notes is provided by distributions that Services Company receives on the LP Units that it owns and from cash payments from the Partnership, which are required to cover any shortfall between the distributions that Services Company receives on the LP Units that it owns and amounts currently due under the ESOP Notes (the “top-up reserve”), except that the Partnership has no obligation to fund the accelerated portion of the ESOP Notes upon a default. The Partnership also incurs routine ESOP-related administrative costs and taxes associated with taxable income incurred on the sale of LP Units, if any. In 2006, ESOP costs were reduced by $2.0 million as

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estimates of future shortfalls between the distributions that Services Company receives on the LP Units that it owns and amounts currently due under the ESOP Notes were reduced to reflect higher distributions on the LP Units than was previously anticipated. Total ESOP-related costs charged to earnings were $0.2 million and $0.6 million in 2005 and 2004, respectively.

Off-Balance Sheet Arrangements

The Partnership has no off-balance sheet arrangements except for operating leases.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to select appropriate accounting principles from those available, to apply those principles consistently and to make reasonable estimates and assumptions that affect revenues and associated costs as well as reported amounts of assets and liabilities.

Approximately 87% of the Partnership’s consolidated assets consist of property, plant and equipment. Property, plant and equipment consists of pipeline and related transportation facilities and equipment, including land, rights-of-way, buildings and leasehold improvements and machinery and equipment. Pipeline assets are generally self-constructed, using either contractors or the Partnership’s own employees. Additions and improvements to the pipeline are capitalized based on the cost of the improvement while repairs and maintenance are expensed.

As discussed under “Environmental Matters” above, the Operating Subsidiaries are subject to federal, state and local laws and regulations relating to the protection of the environment. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. Generally, the timing of these accruals coincides with the Partnership’s commitment to a formal plan of action. Accrued environmental remediation related expenses include estimates of direct costs of remediation and indirect costs related to the remediation effort, such as compensation and benefits for employees directly involved in the remediation activities and fees paid to outside engineering, consulting and law firms. The Partnership maintains insurance which may cover certain environmental expenditures. During 2006, the Operating Partnerships incurred operating expenses, net of insurance recoveries, of $6.2 million and, at December 31, 2006, had $29.2 million accrued for environmental matters. The environmental accruals are revised as new matters arise, or as new facts in connection with environmental remediation projects require a revision of estimates previously made with respect to the probable cost of such remediation projects.

Related Party Transactions

With respect to related party transactions see Note 16 to the consolidated financial statements and Item 13 “Certain Relationships and Related Transactions and Director Independence.”

Recent Accounting Pronouncements

See Note 2 to the Partnership’s consolidated financial statements for a description of certain new accounting pronouncements issued in the year ended December 31, 2006.

Forward-Looking Information

The information contained above in this Management’s Discussion and Analysis and elsewhere in this Annual Report on Form 10-K includes “forward-looking statements,” within the meaning of the Private

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Securities Litigation Reform Act of 1995. Such statements use forward-looking words such as “anticipate,” “continue,” “estimate,” “expect,” “may,” “believe,” “will,” or other similar words, although some forward-looking statements are expressed differently. These statements discuss future expectations and contain projections. Specific factors that could cause actual results to differ from those in the forward-looking statements include, but are not limited to: (1) price trends and overall demand for petroleum products in the United States in general and in our service areas in particular (economic activity, weather, alternative energy sources, conservation and technological advances may affect price trends and demands); (2) competitive pressures from other transportation services; (3) changes, if any, in laws and regulations, including, among others, safety, tax and accounting matters or Federal Energy Regulatory Commission regulation of our tariff rates; (4) liability for environmental claims; (5) security issues affecting our assets, including, among others, potential damage to our assets caused by vandalism, acts of war or terrorism; (6) unanticipated capital expenditures and operating expenses to repair or replace our assets; (7) availability and cost of insurance on our assets and operations; (8) our ability to successfully identify and complete strategic acquisitions and make cost saving changes in operations; (9) expansion in the operations of our competitors; (10) our ability to integrate any acquired operations into our existing operations; and to realize anticipated cost savings and other efficiencies; (11) shut-downs or cutbacks at major refineries that use our services; (12) deterioration in our labor relations; (13) changes in real property tax assessments; (14) regional economic conditions; (15) disruptions to the air travel system; (16) interest rate fluctuations and other capital market conditions; (17) market conditions in our industry; (18) availability and cost of insurance on our assets and operations; (19) conflicts of interest between us, our general partner, the owner of our general partner and its affiliates; (20) the treatment of us as a corporation for federal income tax purposes or if we become subject to entity-level taxation for state tax purposes; and (21) the impact of government legislation and regulation on us.

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on future results. Although the expectations in the forward-looking statements are based on our current beliefs and expectations, we do not assume responsibility for the accuracy and completeness of such statements. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Report on Form 10-K, including those described in the “Risk Factors” section of this Report. Further, we undertake no obligation to update publicly any forward-looking statement whether as a result of new information or future events.

Item 7A.                Quantitative and Qualitative Disclosures About Market Risk

Market Risk—Trading Instruments

Currently the Partnership has no derivative instruments and does not engage in hedging activity with respect to trading instruments.

Market Risk—Other than Trading Instruments

The Partnership is exposed to risk resulting from changes in interest rates. The Partnership does not have significant commodity or foreign exchange risk. The Partnership is exposed to fair value risk with respect to the fixed portion of its financing arrangements (the 5.125% Notes, the 5.300% Notes, the 4 5/8% Notes and the 6 ¾% Notes) and to cash flow risk with respect to its variable rate obligations (the Credit Facility). Fair value risk represents the risk that the value of the fixed portion of its financing arrangements will rise or fall depending on changes in interest rates. Cash flow risk represents the risk that interest costs related to the Credit Facility will rise or fall depending on changes in interest rates.

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The Partnership’s practice with respect to derivative transactions has been to have each transaction authorized by the board of directors of the General Partner.

At December 31, 2006, the Partnership had total fixed debt obligations at face value of $850.0 million, consisting of $125.0 million of the 5.125% Notes, $275.0 million of the 5.300% Notes, $300.0 million of the 4 5/8% Notes and $150.0 million of the 6 ¾% Notes. The fair value of these obligations at December 31, 2006 was approximately $882.0 million. The Partnership estimates that a 1% decrease or increase in rates for obligations of similar maturities would increase or decrease the fair value of these obligations by $63.0 million. The Partnership’s variable debt obligation under the Credit Facility was $145.0 million. Based on the balance outstanding at December 31, 2006, a 1% increase or decrease in interest rates would increase or decrease annual interest expense by $1.5 million.

In December 2004, the Partnership terminated an interest rate swap agreement associated with the 4.625% Notes due June 15, 2013 and received proceeds of $2.0 million. In 2004 interest expense was reduced by $2.6 million as a result of the swap agreement. In accordance with FASB Statement No. 133—“Accounting for Derivative Instruments and Hedging Activities”, the Partnership deferred the $2.0 million gain as an adjustment to the fair value of the hedged portion of the Partnership’s debt and is amortizing the gain as a reduction of interest expense over the remaining term of the hedged debt. Interest expense was reduced by $0.2 million during each of the years ended December 31, 2006 and 2005 related to the amortization of the gain on the interest rate swap.

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