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Buckeye Partners 10-K 2006

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

 

 

x

 

Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2005

OR

o

 

Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

 

For the transition period from                to                  

Commission file number 1-9356

Buckeye Partners, L.P.

(Exact name of registrant as specified in its charter)

Delaware

 

23-2432497

(State or other jurisdiction of
incorporation or organization)

 

(IRS Employer
Identification number)

5002 Buckeye Road
P. O. Box 368
Emmaus, Pennsylvania

 

18049

(Address of principal executive offices)

 

(Zip Code)

 

Registrant’s telephone number, including area code: (484) 232-4000

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

Title of each class

 

 

 

Name of each exchange on
which registered

 

LP Units representing limited partnership interests

 

New York Stock Exchange

 

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 x 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 x

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 x 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. x

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 x

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 x

At June 30, 2005, 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 22, 2006: 37,926,446

 




TABLE OF CONTENTS

 

 

 

Page

 

PART I

 

 

 

 

 

 

 

Item 1.

 

Business

 

 

3

 

 

Item 1A.

 

Risk Factors

 

 

23

 

 

Item 2.

 

Properties

 

 

32

 

 

Item 3.

 

Legal Proceedings

 

 

33

 

 

Item 4.

 

Submission of Matters to a Vote of Security Holders

 

 

34

 

 

PART II

 

 

 

 

 

 

 

Item 5.

 

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

 

 

35

 

 

Item 6.

 

Selected Financial Data

 

 

36

 

 

Item 7.

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

 

36

 

 

Item 7A.

 

Quantitative and Qualitative Disclosures About Market Risk

 

 

57

 

 

Item 8.

 

Financial Statements and Supplementary Data

 

 

59

 

 

Item 9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

 

99

 

 

Item 9A.

 

Controls and Procedures

 

 

99

 

 

PART III

 

 

 

 

 

 

 

Item 10.

 

Directors and Executive Officers of the Registrant

 

 

100

 

 

Item 11.

 

Executive Compensation

 

 

105

 

 

Item 12.

 

Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

 

 

107

 

 

Item 13.

 

Certain Relationships and Related Transactions

 

 

108

 

 

Item 14.

 

Principal Accountant Fees and Services

 

 

111

 

 

PART IV

 

 

 

 

 

 

 

Item 15.

 

Exhibits and Financial Statement Schedule

 

 

112

 

 

 




PART I

Item 1.   Business

Introduction

Buckeye Partners, L.P. (the “Partnership”) is a master limited partnership organized in 1986 under the laws of the State of Delaware. The Partnership 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, a Delaware limited liability company, is the general partner of the Partnership (the “General Partner”).

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 5,000 miles of pipeline, serving 15 states, and operates another approximately 2,100 miles of pipeline under agreements with major oil and chemical companies. The Partnership also owns and operates 43 active refined petroleum products terminals with aggregate storage capacity of approximately 16.6 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, turbine fuel, diesel fuel, heating oil and kerosene from major supply sources to terminals and airports located within major 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 a 2,643-mile interstate common carrier refined petroleum products pipeline system serving major population centers in eight states. It is the primary turbine fuel provider to John F. Kennedy International Airport (“JFK”), LaGuardia Airport, Newark International Airport and certain other airports within its service territory.

·       Laurel Pipe Line Company, L.P. (“Laurel”), which owns a 345-mile intrastate common carrier refined 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. The Partnership acquired the majority of these pipelines from Shell Oil Products, U.S. (“Shell”) on October 1, 2004.

·       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 a 37-mile intrastate common carrier refined petroleum products pipeline connecting Port Everglades, Florida to Ft. Lauderdale-

3




Hollywood International Airport and Miami International Airport. It is the primary turbine 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 43 refined petroleum products terminals with aggregate storage capacity of approximately 16.6 million barrels. BPH also owns interests in 535 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 products pipelines and a natural gas liquids pipeline system.

The Partnership operates its business through three segments: Pipeline Operations, Terminalling and Storage and Other Operations.

Significant Partnership Events in 2005

Acquisition of Northeast Pipelines and Terminals

On May 4, 2005, the Partnership acquired from affiliates of ExxonMobil Corporation (“ExxonMobil”) a refined petroleum products pipeline system comprising approximately 478 miles of pipelines and four petroleum products terminals with aggregate storage capacity of approximately 1.3 million barrels located in the northeastern United States (the “Northeast Pipelines and Terminals”) for a purchase price of $175 million. BPL Transportation acquired the pipeline system, and Buckeye Terminals acquired the four petroleum products terminals.

In connection with the closing of the transaction, the Partnership entered into throughput agreements with ExxonMobil in connection with each of the acquired petroleum products terminals. The throughput agreements have an initial term of five years and renew automatically for five successive three-year terms unless terminated by ExxonMobil. The agreements provide that the Partnership will reserve storage capacity at the terminals for ExxonMobil. The parties also agreed on the terminalling fees to be charged to ExxonMobil for volumes throughput at the terminals by ExxonMobil. The amount of storage capacity reserved for ExxonMobil is based initially on historical usage, and will adjust periodically based on ExxonMobil’s actual usage.

The acquisition of these pipelines and terminals from ExxonMobil significantly expanded the Partnership’s presence in its core northeastern United States market area. The pipelines deliver refined petroleum products from a Valero refinery located in Paulsboro, New Jersey to destinations in New Jersey, Pennsylvania, and New York. At December 31, 2005, the Partnership was in the process of constructing a connection from one of the acquired pipelines to the Partnership’s Macungie, Pennsylvania tank farm. This connection will permit refined products originating at the Valero refinery to move into upstate New York on the Partnership’s Buckeye pipeline system and to move west across Pennsylvania on the Partnership’s Laurel pipeline system. At December 31, 2005, the acquired pipelines and terminals had been substantially integrated into the Partnership’s overall pipeline and terminal infrastructure.

4




The following chart depicts the Partnership’s ownership structure as of February 22, 2006.*

Ownership of Buckeye Partners, L.P.

GRAPHIC


(*)          Ownership percentages in chart are approximate.

(**)   Formed in connection with NGL Pipeline acquired in January 2006.

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 21 to the Partnership’s consolidated financial statements included elsewhere in this report.

5




Pipeline Operations

The Partnership owns and operates refined petroleum products pipelines which receive petroleum products from refineries, connecting pipelines and bulk and marine terminals, and transports those products to other locations. In 2005, refined petroleum products transportation accounted for approximately 75% of the Partnership’s consolidated revenues.

The Partnership transported an average of approximately 1,385,400 barrels per day of refined products in 2005. The following table shows the volume and percentage of refined petroleum products transported over the last three years.

Volume and Percentage of Refined Petroleum Products Transported(1)

(Volume in thousands of barrels per day)

 

 

Year ended December 31,

 

 

 

2005

 

2004

 

2003

 

 

 

Volume

 

Percent

 

Volume

 

Percent

 

Volume

 

Percent

 

Gasoline

 

721.2

 

 

52.0

%

 

609.0

 

 

50.7

%

 

578.8

 

 

50.9

%

 

Jet Fuels

 

323.6

 

 

23.4

 

 

273.1

 

 

22.8

 

 

248.5

 

 

21.9

 

 

Middle Distillates(2)

 

319.6

 

 

23.1

 

 

293.0

 

 

24.4

 

 

285.4

 

 

25.1

 

 

Other Products

 

21.0

 

 

1.5

 

 

25.5

 

 

2.1

 

 

23.7

 

 

2.1

 

 

Total

 

1,385.4

 

 

100.0

%

 

1,200.6

 

 

100.0

%

 

1,136.4

 

 

100.0

%

 


(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, Connecticut, Florida, Illinois, Indiana, 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 928 miles of pipeline. Refined petroleum products are received at Linden, New Jersey from approximately 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 products terminals at Long Island City and Inwood, New York. These pipelines supply JFK, LaGuardia and Newark International Airports with substantially all of each airport’s turbine fuel requirements.

In addition, BPL Transportation’s pipeline system acquired from ExxonMobil in May 2005 delivers refined 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 product to locations in upstate New York, while another segment delivers refined products to central Pennsylvania. Two

6




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

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

Illinois—Indiana—Michigan—Missouri—Ohio

Buckeye and Norco Pipe Line Company, LLC (“Norco”), a subsidiary of BPH, transport refined petroleum products through 2,025 miles of pipeline in northern Illinois, central Indiana, eastern Michigan, western and northern Ohio and western Pennsylvania. A number of receiving lines and delivery lines connect to a central corridor which runs from Lima, Ohio through Toledo, Ohio to Detroit, Michigan. Refined petroleum products are received at a refinery and other pipeline connection points near Toledo, Lima, Detroit and East Chicago, Illinois. 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 and 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.

Other Refined Products Pipelines

Buckeye serves Connecticut and Massachusetts through 112 miles of pipeline (the “Jet Lines System”) that carry refined products from New Haven, Connecticut to Hartford, Connecticut and Springfield, Massachusetts.

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

WesPac Pipelines—Reno LLC (“WesPac Reno”) owns a 3.0 mile pipeline serving the Reno/Tahoe International Airport. WesPac Pipelines—San Diego LLC (“WesPac San Diego”) owns a 4.3 mile pipeline serving the San Diego International Airport. WesPac Pipelines—Memphis LLC (“WesPac Memphis”) has constructed and operates an 11-mile pipeline and related terminal facilities to serve Memphis International Airport. Each of the WesPac entities originally was a joint venture between BPH and Kealine Partners. In May 2005, BPH purchased the membership interest in WesPac Reno owned by Kealine Partners for approximately $2.5 million. Thus, at December 31, 2005, BPH owns 100% of WesPac Reno. BPH has a 75% ownership interest in WesPac Memphis and a 50% ownership interest in WesPac San Diego. Kealine Partners owns the remaining interest in these two joint ventures. As of December 31, 2005, the Partnership had provided $40.3 million in intercompany debt financing to these WesPac entities.

Terminalling and Storage

Through BPH and its subsidiary, Buckeye Terminals, the Partnership’s Terminalling and Storage segment owns and operates 43 terminals located in Illinois, Indiana, Massachusetts, Michigan, Missouri,

7




New York, Ohio and Pennsylvania that provide bulk storage and throughput services and have the capacity to store an aggregate of approximately 16.6 million barrels of refined petroleum products. In addition, Buckeye Terminals owns five currently idled terminals with an aggregate storage capacity of approximately 924,000 barrels. Together, the Partnership’s terminalling and storage activities provided approximately 17% of total revenue in 2005.

The Partnership’s refined products terminals receive refined products from pipelines and distribute them to third parties, who in turn deliver them to end-users and retail outlets. The Partnership’s refined 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. This automated system provides for control of allocations, credit and carrier certification.

The Partnership’s refined products terminals derive most of their revenues from terminalling fees paid by customers. A fee is charged for receiving refined products into the terminal and delivering them to trucks, barges, or pipelines. In addition to terminalling fees, the Partnership’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 43 refined products terminals, 30 are connected to the Partnership’s pipelines, and 13 are not connected to the Partnership’s pipelines.

In December 2005, Buckeye Terminals acquired a refined products terminal located in Taylor, Michigan from affiliates of Atlas Oil Company. The terminal has aggregate storage capacity of approximately 260,000 barrels, as well as rail offloading capabilities used to offload ethanol for blending with gasoline at the terminal.

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

 

 

Year Ended December 31,

 

 

 

2005

 

2004

 

2003

 

Refined products throughput (barrels per day)

 

419,200

 

160,900

 

73,000

 

 

The following table outlines the number of terminals and storage capacity in barrels by state:

State

 

 

 

Number of
Terminals

 

Storage Capacity

 

 

 

 

 

(In thousands)

 

Illinois

 

 

5

 

 

 

1,574

 

 

Indiana

 

 

8

 

 

 

6,441

 

 

Massachusetts

 

 

1

 

 

 

106

 

 

Michigan

 

 

5

 

 

 

1,162

 

 

Missouri

 

 

2

 

 

 

345

 

 

New York

 

 

9

 

 

 

2,067

 

 

Ohio

 

 

9

 

 

 

3,501

 

 

Pennsylvania

 

 

4

 

 

 

1,372

 

 

Total

 

 

43

 

 

 

16,568

 

 

 

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

8




arrangements. BGC is a contract operator of pipelines owned in Texas by major petrochemical companies. BGC currently has 11 operations and maintenance contracts in place. In addition, BGC owns a 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 transported on this pipeline, known as the Sabina pipeline, are supported by a long-term throughput agreement with Sabina Petrochemicals, LLC. BGC also provides engineering and construction management services to major chemical companies in the Gulf Coast area.

Other Investments

BPH owns a 24.99% equity interest in West Shore Pipe Line Company (“West Shore”). West Shore owns and operates a pipeline system that originates in the Chicago, Illinois area and extends north to Green Bay, Wisconsin and west and then north to Madison, Wisconsin. The pipeline system transports refined petroleum products to markets in northern Illinois and Wisconsin. The other equity holders of West Shore are a number of 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 and operates a pipeline system that delivers natural gas liquids to Mont Belvieu, Texas for fractionation. The natural gas liquids are delivered to the WTP pipeline system from the Rocky Mountain 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. 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.

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 do not own the products they transport. Demand for the services provided by the Operating Subsidiaries derives from demand for petroleum products in the regions served and the ability and willingness of refiners, marketers and end-users to supply such demand by deliveries through the Operating 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 160 customers in 2005. Affiliates of Shell contributed 13% of consolidated Partnership revenue in 2005. This revenue was generated in the Pipeline Operations and Terminalling and Storage segments. Approximately, 6% of consolidated revenue generated by Shell was in the Pipeline Operations segment and the remaining 7% of consolidated revenue was generated in the Terminalling and Storage segment. The 20 largest customers accounted for 63% of consolidated Partnership revenue in 2005. For the years ended December 31, 2004 and 2003, no customer contributed more than 10% of consolidated revenue.

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

9




shipments are other pipelines, many of which are owned and operated by major integrated oil companies. Although it is unlikely that a pipeline system comparable in size and scope to the Operating 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.

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 certain volumes in many 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 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, the “Midwest Pipelines and Terminals,” emanate from a refinery owned by ConocoPhillips and are 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. In addition, Marathon Oil Company recently completed a significant expansion of its refinery located in the Detroit, Michigan area. The General Partner is unable to determine whether the expansion of this Marathon refinery will have an impact on the Partnership’s business. 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 volume being transported during March, April and May and somewhat higher than average volume 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 of refined products to end users other than pipelines, also impact the Partnership’s terminal operations. In addition, the Partnership’s terminals generally are in competition with other terminals in the same geographic market for terminal throughput business. Many competitive terminals are owned by major integrated oil companies. These major oil companies may have the opportunity for product exchanges which are not available to the Partnership’s terminals. In addition, the Partnership’s terminal throughput fees are not regulated. Terminal throughput

10




fees are subject to price competition from competitive terminals and alternate modes of transporting refined petroleum products to end users such as retail gas stations.

Other independent pipeline companies, engineering firms and major integrated oil companies and petrochemical companies compete with BGC to operate and maintain pipelines. 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”) which is reimbursed by the Operating Subsidiaries pursuant to a services agreement for the cost of providing employee services. At December 31, 2005, Services Company had a total of 801 full-time employees, 174 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 incurs capital expenditures in order to maintain and enhance the safety and integrity of its pipelines and terminals and related assets, to expand the reach or capacity of its pipelines and terminals, to improve the efficiency of its operations or 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 2005, the Partnership incurred approximately $77.8 million of capital expenditures, of which $23.4 million related to maintenance and integrity and $54.4 million related to expansion and cost reduction projects.

In 2006, the Partnership anticipates capital expenditures of approximately $80 million, of which approximately $30 million is projected to be sustaining capital expenditures for maintenance and integrity projects and approximately $50 million is projected 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 and Norco operate pipelines in interstate common carrier service subject to the regulatory jurisdiction of the Federal Energy Regulatory Commission (“FERC”) under the Interstate Commerce Act and the Department of Energy Organization Act. FERC regulation require that interstate oil pipeline rates be posted publicly and that these rates be “just and reasonable” and non-discriminatory. FERC regulations also enforces common carrier obligations and specifies a uniform system of accounts. In addition, Buckeye, Wood River, BPL Transportation, Norco and the other 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

11




rates are regulated by the Pennsylvania Public Utility Commission. The Partnership’s Wood River subsidiary operates a pipeline in intrastate service in Illinois and tariff rates related to this pipeline are regulated by the Illinois Commerce Commission.

FERC Rate Regulation

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

In addition, in decisions involving unrelated pipeline limited partnerships, 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. The General Partner believes only a small percentage of the Partnership’s limited partnership units (“LP Units”) are held by corporations. 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. This opinion suggested that in the future a limited partnership may not be able to claim any income tax allowance despite being partially owned by a corporation. In December 2004, the FERC issued a Notice of Inquiry seeking comments regarding whether the July 2004 appeals court decision applies only to the specific facts of that case, or whether it applies more broadly, and, if the latter, what effect that ruling might have on energy infrastructure investments. On May 4, 2005, the FERC adopted a policy statement 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 such 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 SFPP, L.P. FERC found that SFPP, L.P. 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 for the income of a jurisdictional pass-through entity. In December 2005, FERC reaffirmed its new income tax allowance policy as it applies to SFPP, L.P. It directed SFPP, L.P. to provide certain evidence necessary for determination of its income tax allowance. FERC’s remand decision of the July 2004 opinion and the new tax allowance policy have been appealed to the United States Court of Appeals for the District of Columbia Circuit. Rehearing of the December 2005 order has also been sought. The ultimate outcome of these proceedings is not certain and could result in changes to the FERC’s treatment of income tax allowances in cost of service. The Partnership expects the final adoption and implementation by FERC of the policy statement in individual cases will be subject to review by the United States Court of Appeals.

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 levels justified by the cost of service, FERC could order

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

Buckeye’s rates are governed by an exception to the rules discussed above, pursuant to specific FERC authorization. Buckeye’s market-based rate regulation program was initially approved by FERC in March 1991 and was subsequently extended in 1994. Under this program, in markets where Buckeye does not have significant market power, individual rate increases: (a) will not exceed a real (i.e., exclusive of inflation) increase of 15% over any two-year period (the “rate cap”), and (b) will be allowed to become effective without suspension or investigation if they do not exceed a “trigger” equal to the change in the Gross Domestic Product implicit price deflator since the date on which the individual rate was last increased, plus 2%. Individual rate decreases will be presumptively valid upon a showing that the proposed rate exceeds marginal costs. In markets where Buckeye was found to have significant market power and in certain markets where no market power finding was made: (i) individual rate increases cannot exceed the volume-weighted average rate increase in markets where Buckeye does not have significant market power since the date on which the individual rate was last increased, and (ii) any volume-weighted average rate decrease in markets where Buckeye does not have significant market power must be accompanied by a corresponding decrease in all of Buckeye’s rates in markets where it does have significant market power. Shippers retain the right to file complaints or protests following notice of a rate increase, but are required to show that the proposed rates violate or have not been adequately justified under the market-based rate regulation program, that the proposed rates are unduly discriminatory, or that Buckeye has acquired significant market power in markets previously found to be competitive.

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

Environmental Matters

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 thereunder, 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 any discharges of petroleum products in reportable quantities and imposes substantial liability for the costs of removing a spill. State

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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 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” which are subject to rigorous disposal requirements.

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

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”), and its subsequent re-authorizations relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. HLPSA covers petroleum and petroleum products and requires any entity that owns or operates pipeline facilities to comply with applicable safety standards, to establish and maintain a plan of inspection and maintenance and to comply with such plans.

The Pipeline Safety Reauthorization Act of 1988 requires coordination of safety regulation between federal and state agencies, testing and certification of pipeline personnel, and authorization of safety-

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related feasibility studies. The Partnership has a drug and alcohol testing program that complies in all material respects with the regulations promulgated by the Office of Pipeline Safety and DOT.

HLPSA also requires, among other things, that the Secretary of Transportation consider the need for the protection of the environment in issuing federal safety standards for the transportation of hazardous liquids by pipeline. The legislation also requires the Secretary of Transportation to issue regulations concerning, among other things, the identification by pipeline operators of environmentally sensitive areas; the circumstances under which emergency flow restricting devices should be required on pipelines; training and qualification standards for personnel involved in maintenance and operation of pipelines; and the periodic integrity testing of pipelines in unusually sensitive and high-density population areas by internal inspection devices or by hydrostatic testing. Effective in August 1999, the DOT issued its Operator Qualification Rule, which required a written program by April 27, 2001, for ensuring operators are qualified to perform tasks covered by the pipeline safety rules. All persons performing covered tasks were required to be qualified under the program by October 28, 2002. The Partnership filed its written plan and has qualified its employees and contractors as required and requalified the employees under its plan in 2005. On March 31, 2001, DOT’s rule for Pipeline Integrity Management in High Consequence Areas (Hazardous Liquid Operators with 500 or more Miles of Pipeline) became effective. This rule sets forth regulations that require pipeline operators to assess, evaluate, repair and validate the integrity of hazardous liquid pipeline segments that, in the event of a leak or failure, could affect populated areas, areas unusually sensitive to environmental damage or commercially navigable waterways. Under the rule, pipeline operators were required to identify line segments which could impact high consequence areas by December 31, 2001. Pipeline operators were required to develop “Baseline Assessment Plans” for evaluating the integrity of each pipeline segment by March 31, 2002 and to complete an assessment of the highest risk 50% of line segments by September 30, 2004, with full assessment of the remaining 50% by March 31, 2008. Pipeline operators will thereafter be required to re-assess each affected segment in intervals not to exceed five years. The Partnership has implemented an Integrity Management Program in compliance with the requirements of this rule.

In December 2002, the Pipeline Safety Improvement Act of 2002 (“PSIA”) became effective. The PSIA imposes additional obligations on pipeline operators, increases penalties for statutory and regulatory violations, and includes provisions prohibiting employers from taking adverse employment action against pipeline employees and contractors who raise concerns about pipeline safety within the company or with government agencies or the press. Many of the provisions of the PSIA are subject to regulations to be issued by the Department of Transportation. The PSIA also requires public education programs for residents, public officials and emergency responders and a measurement system to ensure the effectiveness of the public education program. The Partnership has commenced implementation of 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 cost of compliance with the PSIA is likely to be material.

The Partnership also has certain contractual obligations to Shell for testing and maintenance of pipelines. In 2003, Shell entered into a consent decree with the United States Environmental Protection Agency arising out of a June 1999 incident unrelated to the assets acquired. 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 North Line and 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.

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The Partnership believes that the Operating Subsidiaries currently comply in all material respects with HLPSA 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 2005, the Partnership’s integrity expenditures for these programs were approximately $13.5 million (of which $10.5 million was capital and $3.0 million was expense). The Partnership expects 2006 integrity expenditures for these programs to be approximately $26 million of which approximately $16 million will be capital and $10 million will be expense.

The Operating Subsidiaries are also subject to the requirements of the Federal 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 Unitholders. The following portion of this section is based upon the Internal Revenue Code of 1986, as amended (the “Code”), regulations 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 redetermine 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

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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 products pipeline transportation business. The General Partner believes that at least 90% or more of the Partnership’s gross income constitutes, and has constituted, qualifying income and, accordingly, that the Partnership will continue to be classified as a partnership and not as a corporation for federal income tax purposes.

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 heretofore contributed to the Partnership. Allocations may 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 tax Unitholder’s tax basis in his LP Units immediately before the distribution. Distributions in excess of a Unitholder’s tax basis generally will be gain from the sale or exchange of the LP Units, taxable in accordance with the rules described under “Disposition of LP Units,” below. Any reduction in a Unitholder’s share of the Partnership’s liabilities for which no partner, including the General Partner, bears the economic risk of loss (“nonrecourse liabilities”) will be treated as a distribution of cash to that Unitholder.

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

Basis of LP Units

A Unitholder will have an initial tax basis for its LP Units equal to the amount paid for the LP Units plus its share of the Partnership’s nonrecourse 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 nonrecourse 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 nonrecourse 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.

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Tax Treatment of Operations

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

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

Section 754 Election

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

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

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

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

Notification Requirements

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

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Constructive Termination

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

Alternative Minimum Tax

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

Loss Limitations

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

In general, a Unitholder will be at risk to the extent of the Unitholder’s tax basis in the Unitholder’s LP Units, excluding any portion of that basis attributable to the Unitholder’s share of the Partnership’s nonrecourse liabilities, reduced by any amount of money the Unitholder borrows to acquire or hold the Unitholder’s LP Units if the lender of such borrowed funds owns an interest in the Partnership, is related to such a person or can look only to LP Units for repayment. A Unitholder’s at risk amount will increase or decrease as the tax basis of the Unitholder’s LP Units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in the Unitholder’s share of the Partnership’s nonrecourse liabilities.

The passive loss limitations generally provide that individuals, estates, trusts, certain closely-held corporations and personal service corporations can deduct losses from passive activities, which include any trade or business activity in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. Moreover, the passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses generated by

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the Partnership will only be available to Unitholders who are subject to the passive loss rules to offset future passive income generated by the Partnership and, in particular, will not be available to offset income from other passive activities, investments or salary. Passive losses that are not deductible because they exceed a Unitholder’s share of income may be deducted in full when the Unitholder disposes of the Unitholder’s entire investment in the Partnership in a fully taxable transaction to an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions such as the at-risk rules and the basis limitation.

Deductibility of Interest Expense

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

Valuation of Partnership Properties

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

Withholding

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

Disposition of LP Units

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

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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, 2008). 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, INVESTMENT IN THE PARTNERSHIP BY TAX-EXEMPT ENTITIES SUCH AS INDIVIDUAL RETIREMENT ACCOUNTS, PENSION PLANS AND CHARITABLE TRUSTS MAY NOT BE ADVISABLE.

Foreign Unitholders

Non-resident aliens and foreign corporations, trusts or estates which hold LP Units will be considered to be engaged in business in the United States on account of ownership of LP Units. As a consequence they will be required to file federal tax returns in respect of their share of the Partnership’s income, gain, loss or deduction and pay federal income tax at regular rates on any net income or gain. Generally, a partnership is required to pay a withholding tax on the portion of the partnership’s income which is effectively connected with the conduct of a United States trade or business and which is allocable to the foreign partners, regardless of whether any actual distributions have been made to such partners. However, under rules applicable to publicly traded partnerships, taxes may be withheld at the highest marginal rate applicable to individuals on actual cash distributions made to foreign Unitholders who obtain a taxpayer identification number from the IRS and submit that number to the transfer agent of the publicly traded partnership.

Because a foreign corporation that owns LP Units will be treated as engaged in a United States trade or business, such a corporation will also be subject to United States branch profits tax at a rate of 30% (or any applicable lower treaty rate) of the portion of any reduction in the foreign corporation’s “U.S. net

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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 partnership 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 2005, the Partnership owned property or conducted business in the states of California, Connecticut, Florida, Illinois, Indiana, 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.

Certain Tax Consequences to Unitholders

Upon formation of the Partnership in 1986, the General Partner elected twelve-year straight-line depreciation for tax purposes. For this reason, starting in 1999, the amount of depreciation available to the Partnership has been reduced significantly and taxable income has increased accordingly. Unitholders, however, will continue to offset Partnership income with the amortization of their respective Section 743(b) adjustments (which, effectively, allow Unitholders who purchase LP Units other than directly from the Partnership to increase their share of the common basis of the Partnership’s assets to their purchase price). Each Unitholder’s tax situation will differ depending upon the price paid and when LP Units were purchased. Notwithstanding the additional taxable income beginning in 1999, the current cash distributions exceed expected tax payments. In addition, gain recognized on the sale of LP Units will, generally, result in taxable ordinary income as a consequence of depreciation recapture. UNITHOLDERS ARE ENCOURAGED TO CONSULT THEIR PROFESSIONAL TAX ADVISORS REGARDING THE TAX IMPLICATIONS TO THEIR OWNERSHIP OF LP UNITS.

Available Information

The Partnership files annual, quarterly, and current reports and other documents with the Securities and Exchange Commission (the “SEC”) under the Securities Exchange Act of 1934. The public can obtain

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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 2005 without qualification. In addition, the certifications of the General Partner’s Chief Executive Officer and Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act have been included as exhibits to the Partnership’s Annual Report on Form 10-K.

Item 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 petroleum products in the regions served. Prevailing economic conditions, price and weather affect the demand for petroleum products. Changes in transportation and travel patterns in the areas served by our pipelines also affect the demand for 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 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 each of these factors on us or our Operating Subsidiaries.

Competition could adversely affect our operating results.

Generally, pipelines are the lowest cost method for long-haul overland movement of refined petroleum products. Therefore, our most significant competitors for large volume shipments are other existing pipelines, many of which are owned and operated 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.

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Trucks competitively deliver refined 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 but non-quantified 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 partnership 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. These costs and liabilities may not be covered by indemnification rights we have against the sellers of the assets.

Some of the assets we have acquired have been used for many years to distribute, store or transport petroleum products. Releases may have occurred prior to our acquisition from terminals or along pipeline rights-of-way that require remediation. 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 the liability for which was not retained by the seller or for which indemnification from the seller is not available, 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 affecting its ability to produce refined petroleum products such as:

·       unscheduled maintenance or catastrophic events, such as a fire, flood, explosion or power outage;

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·       labor difficulties that result in a work stoppage or slowdown;

·       environmental proceedings or other litigation that require the halting of all or a portion of the operations at the refinery;

·       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 our risks of being unable to effectively integrate these new operations.

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

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 our Operating Subsidiaries’ debt.

Our outstanding debt securities are structurally subordinated to the claims of our Operating Subsidiaries’ creditors. Any debt securities we issue in the future will likewise be so subordinated. 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 interest claims 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 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 and Norco. The indexing method allows a pipeline to increase its rates by a percentage equal to the change in the annual producer price index for finished goods, or PPI. If the PPI is negative, we could be required to reduce the rates charged by Wood River, Transportation and Norco if they exceed the new maximum allowable rate. In addition, changes in the PPI might not fully reflect actual increases in the costs associated with these pipelines, thus hampering our ability to recover our costs.

Buckeye presently is authorized to charge rates set by market forces, subject to limitations, rather than by reference to costs historically incurred by the pipeline, in 15 regions and metropolitan areas. The Buckeye program is an exception to the generic oil pipeline regulations the FERC issued under the Energy Policy Act of 1992. The generic rules rely primarily on an index methodology that allows a pipeline to change its rates in accordance with an index that the FERC believes reflects cost changes appropriate for

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application to pipeline rates. 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 Partnership’s 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 example, new requirements for the use of ultra low-sulfur diesel fuel, which will be phased in commencing in 2006 through 2010. The Partnership expects to spend $15–18 million in capital expenditures in 2006 at certain locations in order to permit our facilities to handle this new product grade. We may not be able to recover all of our costs related to these expenditures from our pipeline shippers. In addition, the introduction of ultra low sulfur diesel fuel may cause other dislocations in the refined product distribution chain that we cannot predict at this time. Moreover, 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 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 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. 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. This opinion suggested that in the future a limited partnership may not be able to claim any income tax allowance despite being partially owned by a corporation. In December 2004, the FERC issued a Notice of Inquiry seeking comments regarding whether the July 2004 Appeals Court decision applies only to the specific facts of that case, or whether it applies more broadly, and, if the latter, what effect that ruling might have on energy infrastructure investments. On May 4, 2005, the FERC adopted a Policy Statement 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 such 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 SFPP, L.P. FERC found that SFPP, L.P. 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 for the income of a jurisdictional pass-through entity. In December 2005, FERC reaffirmed its new income tax allowance policy as it applies to SFPP, L.P. FERC directed SFPP, L.P. to provide certain evidence necessary for determination of its income tax allowance. Requests for rehearing of the December 2005 order have been filed. In addition, FERC’s remand decision of the July 2004 opinion and the new tax allowance policy have 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 in cost of service. We expect the final

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adoption and implementation by FERC of the Policy Statement in individual cases will be subject to review by the United States Court of Appeals.

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 were brought and FERC were to find that some of the indexed rates exceed levels justified by the cost of service, FERC could order a reduction in the indexed rates and could require reparations. As a result, our results of operations could be adversely affected.

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

Our partnership agreement allows us to issue additional limited partnership units and certain other equity securities without Unitholder approval. There is no limit on the total number of limited partnership units and other equity securities we may issue. When we issue additional limited partnership 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 partnership 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. 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 partnership units or other securities can affect the amount of incentive compensation payments we make to the parent company of 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, our General Partner is owned by certain members of our General Partner’s 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. Although neither the Partnership nor Magellan Midstream Partners 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., and perhaps other entities in which Carlyle/Riverstone or its affiliates have an interest for acquisition opportunities throughout the United States and potentially will compete with Magellan Midstream Partners and these other 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.

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The owner of our General Partner has a substantial amount of debt. A default under such debt could result in a change of control of our General Partner which would be an event of default under our revolving credit facility.

MainLine L.P., or MainLine, the indirect owner of our General Partner, financed its purchase of MainLine Sub LLC, or MainLine Sub, the direct owner of our General Partner, through a combination of equity capital and the proceeds from a senior secured credit and guaranty agreement. MainLine’s existing credit and guaranty agreement is secured by pledges of substantially all of the assets of MainLine and MainLine Sub, including the interest in our General Partner. MainLine’s indebtedness under its credit and guaranty agreement is rated BB- by S&P and Ba3 by Moody’s. If MainLine were to default on its obligations under its credit and guaranty agreement, its lenders could exercise their rights under these pledges 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 partnership units. Unitholders may remove the General Partner only by a vote of the holders of at least 80% of the limited partnership 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 a distribution for a period of three years from the date of the distribution.

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Cost reimbursements for management fees and certain other expenses due to MainLine Sub and our general partner may be substantial and could reduce our cash available for distributions.

Prior to making any distribution to Unitholders, we will reimburse our general partner for certain expenses incurred in connection with its general partner duties and MainLine Sub for certain expenses incurred while performing services for our general partner. MainLine Sub is entitled to receive an annual management fee for functions it provides to our general partner pursuant to a management agreement between MainLine Sub and our general partner. This management fee includes a senior administrative charge and reimbursement for certain costs and expenses. The disinterested directors of our general partner approve the amount of the management fee on an annual basis. In recognition of increased services from MainLine Sub in the form of assistance with business development opportunities, financing strategies, insurance, investment banking and corporate development advice, the disinterested directors of our general partner have approved a senior administrative charge for 2005 of $1.9 million, and MainLine Sub has agreed not to request an additional increase in the senior administrative charge for calendar year 2006 (other than adjustments for inflation capped at the Consumer Price Index) unless there is a material change in the nature of the services rendered to our general partner by MainLine Sub. The payment of management fees and the reimbursement of expenses could adversely affect our ability to pay cash distributions.

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 partnership units.

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

The availability to a Unitholder of the anticipated federal income tax benefits of an investment in limited partnership 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 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 partnership 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. Further, because of budgetary considerations, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax on us, the cash available for distribution to you would be reduced.

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

We have not requested a ruling from the IRS with respect to our classification as a partnership for federal income tax purposes, the classification of any of the revenue from our operations as “qualifying income” under Section 7704 of the Internal Revenue Code (which is necessary to prevent entity level taxation of our income at corporate tax rates), or any other matter affecting us. Accordingly, the IRS may

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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 partnership 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 partnership units in excess of the amount of cash received in the sale.

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

Investment in limited partnership 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 partnership units.

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

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

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

A Unitholder who sells limited partnership 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 partnership 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 partnership unit which decreased such Unitholder’s tax basis in that limited partnership unit will, in effect, become taxable income if the limited partnership unit is sold at a price greater than the Unitholder’s tax basis in that limited partnership unit,

31




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 partnership units and nonconforming depreciation conventions.

Because we cannot match transferors and transferees of limited partnership units, uniformity of the tax characteristics of the limited partnership units to a purchaser of limited partnership 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 partnership units, as well as the amount of gain recognized from a sale of the limited partnership units, and could have a negative impact on the value of the limited partnership units.

Unitholders will likely be subject to state, local and other taxes in states where they or as a result of an investment in the limited partnership units.

In addition to United States federal income taxes, Unitholders will likely be subject to other taxes, such as state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which the Unitholder resides or in which we do business or own property. A Unitholder will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of the various jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. It is the responsibility of each Unitholder to file all applicable United States federal, state, local and foreign tax returns.

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

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

Item 2.   Properties

As of December 31, 2005, the principal facilities of the Partnership included approximately 5,000 miles of 6-inch to 24-inch diameter pipeline, approximately 100 delivery points and 43 active bulk storage and terminal facilities with aggregate capacity of approximately 16.6 million 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 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.

32




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.

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 late October 2005, the Partnership experienced a release of approximately 43,000 gallons of unleaded gasoline at its Macungie, Pennsylvania station and tank farm complex. The Partnership estimates that it has recovered approximately 60% of the released gasoline. The Partnership is actively engaged in delineation of impacted soils and groundwater and has instituted product recovery through remediation systems. At December 31, 2005, the Partnership had expended approximately $1.2 million on emergency response and environmental remediation efforts. In addition, the Partnership accrued an additional $1.3 million of expense as of the end of 2005 in connection with additional costs anticipated to be incurred in 2006. The Partnership expects that insurance reimbursements will cover expenses in connection with environmental remediation costs in excess of $2.5 million.

The Partnership is working with the United States Environmental Protection Agency (“EPA”) and the Pennsylvania Department of Environmental Protection (“PA DEP”) in connection with the delineation of the contamination and the development of a long-term remediation plan for the site. In February 2006, the EPA and the Partnership entered into an Administrative Consent Order setting forth certain environmental delineation and remediation requirements in connection with the site. The Partnership is also in discussions with the PA DEP concerning a potential Consent Order. The Partnership is unable to

33




estimate with any degree of certainty any penalties, if any, that might be assessed by the EPA or the PA DEP in connection with the release.

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, 2005.

34




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 2005 and 2004, as reported in the New York Stock Exchange Composite Transactions, were as follows:

 

 

2005

 

2004

 

Quarter

 

 

 

High

 

Low

 

High

 

Low

 

First

 

$

46.00

 

$

42.00

 

$

46.00

 

$

40.00

 

Second

 

49.15

 

43.12

 

43.67

 

35.60

 

Third

 

50.80

 

44.65

 

44.40

 

40.70

 

Fourth

 

48.25

 

40.93

 

45.00

 

39.10

 

 

On October 19, 2004, the Partnership sold 5.5 million LP Units in an underwritten public offering at a price of $42.50 per Unit. Proceeds to the Partnership, net of underwriters’ discount of $1.81 per unit and offering expenses, were approximately $223.3 million. The principal use of proceeds was to reduce the Partnership’s indebtedness under its Credit Facility, which was used to fund the Partnership’s Midwest Pipelines and Terminals acquisition.

On February 7, 2005, the Partnership sold 1.1 million LP Units in an underwritten public offering at a price of $45.00 per unit. Proceeds to the Partnership, net of underwriter’s discount of $1.46 per unit and offering expenses, were approximately $47.6 million. The principal use of proceeds was to repay, in part, amounts outstanding under the Partnership’s revolving line of credit.

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 in part to repay $108 million that was outstanding under the Credit Facility, which was repaid on May 17, 2005.

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 44,000 at December 31, 2005.

Cash distributions paid during 2004 and 2005 were as follows:

Record Date

 

 

 

Payment Date

 

Amount
Per Unit

 

February 4, 2004

 

February 27, 2004

 

$

0.6500

 

May 5, 2004

 

May 28, 2004

 

0.6500

 

August 9, 2004

 

August 31, 2004

 

0.6625

 

November 8, 2004

 

November 30, 2004

 

0.6750

 

February 7, 2005

 

February 28, 2005

 

$

0.6875

 

May 9, 2005

 

May 31, 2005

 

0.7000

 

August 9, 2005

 

August 31, 2005

 

0.7125

 

November 7, 2005

 

November 30, 2005

 

0.7250

 

 

35




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.

 

 

Year Ended December 31,

 

 

 

2005

 

2004

 

2003

 

2002

 

2001

 

 

 

(In thousands, except per unit amounts)

 

Income Statement Data:

 

 

 

 

 

 

 

 

 

 

 

Revenue

 

$

408,446

 

$

323,543

 

$

272,947

 

$

247,345

 

$

232,397

 

Depreciation and amortization(1)

 

36,760

 

25,983

 

22,562

 

20,703

 

20,002

 

Operating income(1)

 

161,313

 

122,144

 

109,335

 

102,362

 

98,331

 

Interest and debt expense

 

43,357

 

27,614

 

22,758

 

20,527

 

18,882

 

Net income(2)

 

99,958

 

82,962

 

30,154

 

71,902

 

69,402

 

Net income per unit

 

2.69

 

2.76

 

1.05

 

2.65

 

2.56

 

Distributions per unit

 

2.83

 

2.64

 

2.54

 

2.50

 

2.45

 

 

 

 

December 31,

 

 

 

2005

 

2004

 

2003

 

2002

 

2001

 

 

 

(In thousands)

 

Balance Sheet Data:

 

 

 

 

 

 

 

 

 

 

 

Total assets

 

$

1,816,867

 

$

1,534,119

 

$

937,896

 

$

856,171

 

$

807,560

 

Long-term debt

 

899,077

 

797,270

 

448,050

 

405,000

 

373,000

 

General Partner’s capital

 

2,529

 

2,549

 

2,514

 

2,870

 

2,834

 

Limited Partners’ capital

 

756,531

 

603,409

 

376,158

 

355,475

 

351,057

 

Receivable from exercise of options

 

(483

)

(535

)

(912

)

(913

)

(995

)

Accumulated other comprehensive income

 

 

 

(348

)

 

 


(1)          Depreciation and amortization includes $832,000 in 2001 related to goodwill acquired in the 2000 acquisition of six petroleum products terminals. Goodwill amortization ceased effective January 1, 2002 with the adoption of Statement of Financial Accounting Standards. No. 142—“Goodwill and Other Intangible Assets.” See Note 5 to the Partnership’s consolidated financial statements.

(2)          Net income in 2003 includes a charge 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 is a discussion of the results of operations and the liquidity and capital resources of the Partnership for the periods indicated below. This discussion should be read in conjunction with the Partnership’s consolidated financial statements and notes thereto, which are included elsewhere in this report.

Overview

The Partnership is a master limited partnership which operates through subsidiary entities (the “Operating Subsidiaries”) in the transportation, terminalling and storage of refined petroleum products on a fee basis through facilities owned and operated by the Partnership. The Partnership also operates pipelines owned by third parties under contracts with major integrated oil and chemical companies, and performs certain construction activities, generally for the owners of these third-party pipelines.

36




During 2004 and 2005, the Partnership significantly expanded its operations through acquisitions. On October 1, 2004, the Partnership acquired 5 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 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 Exxon Mobil Corporation (“ExxonMobil”). The assets acquired in these two acquisitions added $95.2 million and $17.7 million of revenue in 2005 and 2004, respectively. In November 2005 the Partnership acquired a 29-mile ammonia pipeline located in Texas. 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.

As a result of the expansion of the Partnership’s operations, in the fourth quarter of 2005, the Partnership determined that its operations are most appropriately presented in three operating segments: Pipeline Operations, Terminalling and Storage and Other Operations. The business of each operating segment is:

Pipeline Operations:

The Pipeline Operations segment receives refined petroleum products including gasoline, jet and diesel fuel and other distillates from refineries, connecting pipelines, bulk and marine terminals and transports those products to other locations for a fee. As of December 31, 2005, this segment owned and operated approximately 5,000 miles of pipeline systems in the following states: California, Connecticut, Florida, Illinois, Indiana, Massachusetts, Michigan, Missouri, New Jersey, Nevada, New York, Ohio, Pennsylvania and Tennessee.

Terminalling and Storage:

The Terminalling and Storage segment provides bulk storage and terminal throughput services. This segment owns and operates 43 active terminals that have the capacity to store an aggregate of approximately 16.6 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 operations of third-party pipelines owned principally by major petrochemical companies pursuant to operations and maintenance contracts. The third party pipelines are located in Texas. This segment also includes the provision by the Partnership, through its BGC subsidiary, of pipeline construction management services, typically for cost plus a fixed fee. 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 (the “Sabina Pipeline”).

The Partnership entered into equity and debt financings to fund its asset acquisitions in 2005 and 2004. These financings are more fully described under “Liquidity and Capital Resources” in this Management’s Discussion and Analysis of Financial Condition and Results of Operations.

37




Results of Operations

Summary operating results for the Partnership were as follows:

 

 

Year Ended December 31,

 

 

 

2005

 

2004

 

2003

 

 

 

(In thousands, except per unit amounts)

 

Revenue

 

$

408,446

 

$

323,543

 

$

272,947

 

Costs and expenses

 

247,133

 

201,399

 

163,612

 

Operating income

 

161,313

 

122,144

 

109,335

 

Other income (expenses)

 

(61,355

)

(39,182

)

(79,181

)

Net income

 

$

99,958

 

$

82,962

 

$

30,154

 

Earnings per unit—basic

 

$

2.69

 

$

2.76

 

$

1.05

 

Earnings per unit—assuming dilution

 

$

2.69

 

$

2.75

 

$

1.05

 

 

In 2003, the Partnership repaid $240 million of Senior Notes of Buckeye. In conjunction with this repayment, the Partnership incurred a yield maintenance premium of $45.5 million, which has been reflected in other income (expenses) in the Partnership’s financial statements. The Partnership’s 2003 net income before the yield maintenance premium was $75.6 million, or $2.64 per unit.

To supplement its financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”), the Partnership’s management has used the financial measure of “net income before the yield maintenance premium.” The Partnership has presented net income before the yield maintenance premium in this discussion to enhance an investor’s overall understanding of the way that management analyzes the Partnership’s financial performance. Specifically, the Partnership’s management used the presentation of net income before the yield maintenance premium to allow for a more meaningful comparison of the Partnership’s operating results in 2005 and 2004 (which were not impacted by the yield maintenance premium) to 2003 (which were impacted by the yield maintenance premium). The presentation of this additional information is not meant to be considered in isolation or as a substitute for results prepared in accordance with GAAP.

A reconciliation of 2003 net income before the yield maintenance premium to 2003 net income, which is the most directly comparable financial measure calculated and presented in accordance with GAAP, is as follows:

 

 

(In thousands)

 

Net income before the yield maintenance premium

 

 

$

75,618

 

 

Yield maintenance premium

 

 

(45,464

)

 

Net income

 

 

$

30,154

 

 

 

The improvement in revenues and operating income in 2005 compared to 2004, and 2004 compared to 2003, is generally due to the expansion of the Partnership’s operations through the addition of the Northeast Pipelines and Terminals in 2005 and the Midwest Pipelines and Terminals in 2004. Earnings per unit were impacted by the issuance of 5.5 million LP Units in October 2004, 1.1 million LP Units in February 2005 and 2.5 million LP Units in May 2005.

38




Revenues and operating income by operating segment for each of the three years ended December 31, 2005, 2004 and 2003 were as follows:

 

 

Year Ended December 31,

 

 

 

2005

 

2004

 

2003

 

 

 

(In thousands)

 

Revenues:

 

 

 

 

 

 

 

Pipeline Operations

 

$

306,849

 

$

264,010

 

$

234,012

 

Terminalling and Storage

 

68,822

 

26,362

 

15,352

 

Other Operations

 

32,775

 

33,171

 

23,583

 

Total

 

$

408,446

 

$

323,543

 

$

272,947

 

Operating income:

 

 

 

 

 

 

 

Pipeline Operations

 

$

124,245

 

$

104,227

 

$

98,459

 

Terminalling and Storage

 

29,666

 

11,900

 

4,570

 

Other Operations

 

7,402

 

6,017

 

6,306

 

Total

 

$

161,313

 

$

122,144

 

$

109,335

 

 

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.”

2005 Compared to 2004

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

Pipeline Operations:

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

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

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

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

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

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

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

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

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

39




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

Product deliveries for each of the three years ended December 31, including Wood River and BPL Transportation product deliveries, were as follows:

 

 

Average Barrels per Day

 

 

 

2005

 

2004

 

2003

 

Product

 

 

 

 

 

 

 

Gasoline

 

721,200

 

609,000

 

578,800

 

Distillate

 

323,600

 

293,000

 

285,400

 

Turbine Fuel

 

319,600

 

273,100

 

248,500

 

LPG’s

 

16,300

 

21,100

 

19,100

 

Other

 

4,700

 

4,400

 

4,600

 

Total

 

1,385,400

 

1,200,600

 

1,136,400

 

 

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 of $68.8 million in 2005 increased by $42.5 million from the comparable period in 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.

Average daily throughput for the refined products terminals for the years ended December 31 were as follows:

 

 

Year Ended December 31,

 

 

 

2005

 

2004

 

2003

 

Refined products throughput (barrels per day)

 

419,200

 

160,900

 

73,000

 

 

Other Operations:

Revenue from other operations of $32.8 million for the year ended December 31, 2005 decreased by $0.4 million from the comparable period in 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.

40




Operating Expenses

Costs and expenses for the years ended December 31, 2005, 2004 and 2003 were as follows:

 

 

Operating Expenses

 

 

 

2005

 

2004

 

2003

 

 

 

(In thousands)

 

Payroll and payroll benefits

 

$

72,882

 

$

61,094

 

$

54,685

 

Depreciation and amortization

 

36,760

 

25,983

 

22,562

 

Operating power

 

26,240

 

22,976

 

21,899

 

Outside services

 

24,408

 

19,896

 

18,806

 

Property and other taxes

 

16,579

 

13,316

 

10,437

 

Construction management

 

8,932

 

12,287

 

 

All other

 

61,332

 

45,847

 

35,223

 

Total

 

$

247,133

 

$

201,399

 

$

163,612

 

 

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 represent payroll and payroll benefit costs for the first nine months of 2005, is 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, consisting primarily of electricity required to operate pumping facilities, was $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 BGC 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, an increase of $4.5 million over 2004. Outside services costs related to the Midwest Pipelines and Terminals and Northeast Pipelines and Terminals were $4.5 million for the first nine months of 2005 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 for the first nine months in 2005. The Northeast Pipelines and Terminals added $1.3 million of property and other taxes since its date of acquisition in May 2005. 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 by $3.4 million. The decrease in construction management costs is 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.

41




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 during the first nine months of 2005 and Northeast Pipelines and Terminals since their acquisition in May 2005 added $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.

Costs and expenses by segment for the years ended December 31, 2005, 2004 and 2003 were as follows:

 

 

Year Ended December 31,

 

 

 

2005

 

2004

 

2003

 

 

 

(In thousands)

 

Total costs and expenses

 

 

 

 

 

 

 

Pipeline Operations

 

$

182,604

 

$

159,783

 

$

135,553

 

Terminalling and Storage

 

39,156

 

14,462

 

10,782

 

Other Operations

 

25,373

 

27,154

 

17,277

 

Total

 

$

247,133

 

$

201,399

 

$

163,612

 

 

Total other income (expenses) for the years ended December 31, 2005, 2004 and 2003 were as follows:

 

 

Year Ended December 31,

 

 

 

2005

 

2004

 

2003

 

 

 

(In thousands)

 

Investment and equity income

 

$

5,940

 

$

6,005

 

$

3,628

 

Interest and debt expense

 

(43,357

)

(27,614

)

(22,758

)

Premium paid on retirement of debt

 

 

 

(45,464

)

General Partner incentive compensation

 

(20,180

)

(14,002

)

(11,877

)

Minority interests and other

 

(3,758

)

(3,571

)

(2,710

)

Total

 

$

(61,355

)

$

(39,182

)

$

(79,181

)

 

Other income (expenses) 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 interest expense of $27.6 million incurred in 2004, which is an increase of $15.8 million. Approximately $11.3 million of the interest expense incurred in 2005 related to its 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 is due to an increase in the number of 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 to Unitholders in 2005 compared to 2004.

42




2004 compared to 2003

Total revenues for the year ended December 31, 2004 were $323.5 million, $50.6 million or 18.5% greater than revenue of $272.9 million in 2003.

Pipeline Operations:

Revenue from Pipeline Operations was $264.0 million in 2004 compared to $234.0 million in 2003. The increase of $30.0 million in transportation revenue was primarily the result of:

·       Wood River transportation revenue of $8.4 million;

·       a 2.8% average tariff rate increase effective May 1, 2004 and a 2.4% average tariff increase effective May 1, 2003;

·       a 3.0% increase, net of Wood River, in gasoline transportation revenue of $3.6 million on a 0.2% decrease in gasoline volumes delivered;

·       a 7.5% increase, net of Wood River, in jet fuel transportation revenue of $2.9 million with a 5.2% increase in jet fuel volumes delivered. Deliveries to New York City (LaGuardia, JFK and Newark) airports increased by 8.4% but were partially offset by a 16.9% decline in deliveries to the Pittsburgh Airport due to US Airways’ schedule reductions and a 55.0% decline in deliveries to Ludlow Air Force Base;

·       a 2.0% increase, net of Wood River, in distillate transportation revenue of $1.3 million on a 0.4% increase in distillate volumes delivered;

·       a 25.0% increase in LPG transportation revenue of $0.9 million on a 10.8% increase in LPG volumes delivered; and

·       $7.5 million related to a product supply arrangement and certain refined products pipeline maintenance services being recorded on a gross basis rather than the net-of-cost basis previously used.

Terminalling and Storage:

Terminalling and Storage revenues of $26.4 million in 2004 increased by $11.0 million from the comparable period in 2003. Of this increase, $9.2 million related to throughput revenue generated by the terminals acquired from Shell on October 1, 2004. The remaining increase of $1.8 million was primarily due to increases in rent and incidental revenues.

Other Operations:

Contract operations revenue of $33.2 million for the year ended December 31, 2004 increased by $9.6 million from the comparable period in 2003. Revenue from pipeline construction activities increased by $12.7 million in 2004, due to a new contract, but was partially offset by a decline in contract operation service revenue of $3.2 million which resulted from the loss of an operations and maintenance contract with a third party.

Operating Expenses

Payroll and payroll benefits costs were $61.1 million in 2004, an increase of $6.4 million over 2003. Of this increase, approximately $3.9 million is related to employees added as a result of the acquisition of the Midwest Pipelines and Terminals on October 1, 2004. The Partnership hired approximately 104 employees in 2004, most of whom previously worked for Shell primarily on the Midwest Pipelines and Terminals. The employees were hired as employees of Services Company. Of the remaining increase of $2.5 million of

43




payroll costs in 2004, approximately $1.2 million resulted from recording expenses from operation services contracts on a gross basis, rather than the net-of-cost basis previously used. The balance of the increase resulted principally from increases in wage rates in 2004 compared to 2003, as well as increased employee benefits (principally related to retiree medical costs), partially offset by increased salaries and wages capitalized as part of maintenance and expansion capital projects.

Depreciation and amortization expense of $26.0 million increased by $3.4 million in 2004 over 2003. Depreciation related to the Midwest Pipelines and Terminals was $2.5 million. The remaining increase of $0.9 million resulted from the Partnership’s ongoing expansion capital program.

Operating power, consisting primarily of electricity required to operate pumping facilities, was $23.0 million in 2004, an increase of $1.1 million over 2003. The Midwest Pipelines and Terminals added $0.7 million in operating power costs from the date of their acquisition on October 1, 2004. Of the remaining increase of $0.4 million, in operating power costs, increases at Buckeye and Laurel of $1.4 million (related to higher volumes) were partially offset by a decrease of $1.0 million at BGC 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 $19.9 million, an increase of $1.1 million over 2003. Outside services costs related to the Midwest Pipelines and Terminals were $1.6 million. Pipeline and terminals operations added approximately $0.7 million related to ongoing maintenance activities, which were more than offset by reductions of $1.2 million at BGC that resulted from the loss of an operations and maintenance contract with a third party in 2004.

Property and other taxes were $13.3 million in 2004, an increase of $2.8 million over 2003. Property and other taxes related to the Midwest Pipelines and Terminals were $0.6 million. Of the remaining increases of $2.2 million, the Partnership experienced higher real property tax assessments in several states.

Construction management costs were $12.3 million in 2004 as a result of a significant construction contract with a major chemical company. Construction management costs were minimal in 2003.

All other costs were $45.8 million in 2004 compared to $35.2 million in 2003, an increase of $10.6 million. Of this increase, $3.7 million resulted from recording certain expenses on a gross basis compared to the net-of-cost basis previously used, including fuel purchases by WesPac Reno ($3.0 million) and costs related to an operation services contract ($0.7 million). Other costs related to the Midwest Pipelines and Terminals added $2.3 million. Casualty losses increased by $1.4 million in 2004 primarily as a result of pipeline and terminal releases. In addition, in August 2004, BGC elected to be treated as a corporation for Federal income tax purposes. The Partnership accrued $0.5 million, included in operating expenses, related to these income taxes incurred during the period after BGC elected to be treated as a corporation for Federal income tax purposes. Professional fees increased by $1.2 million, principally associated with Sarbanes-Oxley compliance and a restructuring of certain agreements between the General Partner’s entities and the Partnership. The remainder of the increases related to various other pipeline operating costs.

Other income (expense) was a net expense of $39.2 million in 2004 compared to net expense of $79.2 million in 2003. In 2003, the Partnership paid a yield maintenance premium of $45.5 million on the retirement of the $240 million Senior Notes of Buckeye. No such premium was incurred in 2004. Investment income of $6.0 million in 2004 increased by $2.4 million from 2003, which resulted from a full year’s investment income from West Texas LPG Pipeline, L.P. (“WTP”) compared to five months of such investment income in 2003 (the Partnership’s 20% interest in WTP was acquired in August 2003) and increased earnings from the Partnership’s ownership interest in West Shore. Interest expense was $27.6 million in 2004 compared to $22.8 million in 2003, an increase of $4.8 million. The Partnership

44




incurred approximately $3.3 million in interest related to its 5.300% Notes due 2014 which were issued in October 2004 in connection with the acquisition of the Midwest Pipelines and Terminals. The balance of the increase in interest expense resulted from higher average balances outstanding on the Partnership’s 5-year revolving line of credit in the second half of the 2004 compared to 2003, a portion of which was related to the acquisition of the Midwest Pipelines and Terminals.

General Partner incentive compensation was $14.0 million in 2004 compared to $11.9 million in 2003 as a result of the issuance of 5.5 million LP Units in October 2004 as well as a higher limited partnership cash distributions paid throughout 2004 compared to 2003. Minority interests and other of $3.6 million increased by $0.9 million.

Liquidity and Capital Resources

The Partnership’s financial condition at December 31, 2005, 2004, and 2003 is highlighted in the following comparative summary:

Liquidity and Capital Indicators

 

 

As of December 31,

 

 

 

2005

 

2004

 

2003

 

Current ratio(1)

 

1.6 to 1

 

1.5 to 1

 

1.4 to 1

 

Ratio of cash, cash equivalents and trade receivables to current liabilities

 

1.0 to 1

 

.8 to 1

 

.8 to 1

 

Working capital (in thousands)(2)

 

$

36,215

 

$

27,435

 

$

17,720

 

Ratio of total debt to total capital(3)

 

.54 to 1

 

.57 to 1

 

.54 to 1

 

Book value (per Unit)(4)

 

$

19.88

 

$

17.53

 

$

13.03

 


(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 2005, 2004 and 2003, 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, 2005, the Partnership had $900.0 million aggregate face amount of long-term debt, which consisted of $300 million of the Partnership’s 45¤8% Notes due 2013 (the “45¤8% Notes”), $275 million of the Partnership’s 5.30% Notes due 2014 (the “5.30% Notes”), $150 million of the Partnership’s 6¾% Notes due 2033 (the “6¾% Notes”) and $125 million of the Partnership’s 5.125% Notes due 2017 (the “5.125% Notes”) along with $50 million borrowed under the Partnership’s revolving credit facility described below.

On August 6, 2004, the Partnership entered into a $400 million 5-year revolving credit facility (the “Credit Facility”) with a syndicate of banks led by SunTrust Bank. The Credit Facility contains a one-time expansion feature to $550 million subject to certain conditions. Borrowings under the Credit Facility are guaranteed by certain of the Partnership’s subsidiaries. The Credit Facility matures on August 6, 2009.

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 one half of one percent and (b) SunTrust Bank’s prime rate or (ii) the London Interbank Offered Rate (“LIBOR”) plus an applicable

45




margin. The applicable margin is determined based upon ratings assigned by Standard and Poors and Moody’s Investor Services for the Partnership’s senior unsecured non-credit enhanced long-term debt. The applicable margin, which was 0.5% at December 31, 2005, will increase during any period in which the Partnership’s Funded Debt Ratio (described below) exceeds 5.25 to 1.0. At December 31, 2005, the Partnership had $50.0 million outstanding under the Credit Facility and the weighted average interest rate was 5.85%, consisting of $30 million borrowed at a LIBOR rate of 4.91% and $20 million borrowed at the base rate of 7.25%.

The Credit Facility contains covenants and provisions that:

·       Restrict the Partnership’s and certain subsidiaries’ ability to incur additional indebtedness based on certain ratios described below;

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

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

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

The Credit Facility requires that the Partnership and its subsidiaries maintain a maximum “Funded Debt Ratio” and a minimum “Fixed Charge Coverage Ratio.” The Funded Debt Ratio equals the ratio of the long-term debt of the Partnership (including the current portion, if any) to the Partnership’s earnings before interest, taxes, depreciation, depletion and amortization and incentive compensation payments to the General Partner (“Adjusted EBITDA”), for the four preceding 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, 2005, the Partnership’s Funded Debt Ratio was 4.37 to 1.00.

The Fixed Charge Coverage Ratio is defined as the ratio of Adjusted EBITDA for the four preceding fiscal quarters to the sum of payments for interest and principal on debt plus certain capital expenditures required for the ongoing maintenance and operation of the Partnership’s assets. The Partnership is required to maintain a Fixed Charge Coverage Ratio of greater than 1.25 to 1.00 as of the end of any fiscal quarter. As of December 31, 2005, the Partnership’s Fixed Charge Coverage Ratio was 2.98 to 1.00.

At December 31, 2005, the Partnership was in compliance with the remainder of its covenants under the Credit Facility.

In January 2006, the Partnership borrowed an additional $93 million under the Credit Facility in order to fund the acquisitions of a terminal in Niles, Michigan and a natural gas liquids pipeline located in Colorado and Kansas.

The Partnership’s financial strategy is to maintain an investment-grade credit rating, which involves, among other things, the issuance of additional LP Units in connection with the Partnership’s acquisitions and internal growth activities in order to maintain acceptable financial ratios, including total debt to total capital. From 2003 through 2005, the Partnership has issued approximately $439.3 million of its LP Units in support of its acquisition and growth strategies and has not experienced any difficulties in accessing equity capital. The Partnership may issue additional LP Units in 2006 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 or unwilling 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.

46




Based on the Partnership’s existing operations, however, the Partnership anticipates that cash from operations plus amounts available under the Credit Facility will be sufficient to fund its cash requirements for 2006.

Cash Flows from Operations

The components of cash flows from operations for the years ended December 31, 2005, 2004 and 2003 are as follows:

 

 

Cash Flows from Operations

 

 

 

2005

 

2004

 

2003

 

 

 

(In thousands)

 

Net income

 

$

99,958

 

$

82,962

 

$

30,154

 

Premium paid on retirement of long-term debt

 

 

 

45,464

 

Depreciation and amortization

 

36,760

 

25,983

 

22,562

 

Minority interests

 

3,758

 

3,571

 

2,722

 

Changes in current assets and liabilities

 

(1,086

)

(13,405

)

6,887

 

Changes in other assets and liabilities

 

4,587

 

825

 

1,583

 

Other

 

(1,499

)

(191

)

(5

)

Total

 

$

142,478

 

$

99,745

 

$

109,367

 

 

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 operations were $99.7 million in 2004 compared to $109.4 million in 2003, a decrease of $9.7 million. The principal reason for the decrease was the 2004 increase in working capital of $13.4 million described above compared to a decrease in working capital of $6.9 million in 2003. In 2003, an increase in prepaid and other current assets of $9.9 million was more than offset by increases in accounts payable of $6.4 million and accrued and other current liabilities of $11.7 million. During 2003 trade receivables balances were essentially unchanged. In 2003, accounts payable increased by $6.4 million

47




mostly due to certain insurance amounts payable at year-end. Accrued and other liabilities increased in 2003 by $11.7 million principally due to an increase in accrued interest related to the timing of the semi-annual interest payments due on the Partnership’s 4 5/8% and 6 ¾% Notes. These changes more than offset the increase in net income of $7.3 million in 2004 to $82.9 million compared to net income before the yield maintenance premium of $75.6 million in 2003. Depreciation and amortization, a non-cash expense, increased by $3.4 million in 2004 compared to 2003 as a result of the addition of the Midwest Pipelines and Terminals and ongoing capital additions.

Cash Flows from Investing Activities

Net cash used in investing activities for the years ended December 31, 2005, 2004 and 2003 are as follows:

 

 

Investing Activities

 

 

 

2005

 

2004

 

2003

 

 

 

(In millions)

 

Capital expenditures

 

$

77.8

 

$

72.6

 

$

42.2

 

Acquisitions and investments

 

210.2

 

518.8

 

36.0

 

Other

 

 

(3.6

)

0.8

 

Total

 

$

288.0

 

$

587.8

 

$

79.0

 

 

In 2005, cash used for investments and acquisitions consisted of the Northeast Pipelines and Terminals ($176.3 million), with the balance expended in connection with a terminal acquisition in Taylor, Michigan, a deposit for a natural gas liquids pipeline acquired in January 2006, an ammonia pipeline located near Houston, TX and the acquisition of the remainder of WesPac Reno. In 2004, investments and acquisitions consisted of the acquisition of the Midwest Pipelines and Terminals. In 2003, the Partnership invested $36.0 million for a 20% interest in WTP ($28.5 million) and an additional 7% interest in West Shore ($7.5 million). In addition, in December 2005, the Partnership acquired an approximately 26-mile pipeline and a 40% interest in Muskegon Pipeline LLC (“Muskegon”), which owns an approximately 170-mile pipeline which extends from Griffith, IN to Muskegon MI (together, the “Pipeline Interests”). The Pipeline Interests were acquired in exchange for consideration that included capacity lease agreements (with purchase options) related to one of the Partnership’s pipelines and a terminal. The Partnership has recorded the Pipeline Interests at their estimated fair values of $20.1 million, with $4.8 million allocated to the 26-mile pipeline and $15.3 million allocated to the 40% interest in Muskegon.

Capital expenditures are summarized below:

 

 

Capital Expenditures

 

 

 

2005

 

2004

 

2003

 

 

 

(In millions)

 

Sustaining capital expenditures:

 

 

 

 

 

 

 

Operating infrastructure

 

$

12.9

 

$

11.0

 

$

9.5

 

Pipeline and tank integrity

 

10.5

 

21.8

 

18.9

 

Total sustaining

 

23.4

 

32.8

 

28.4

 

Expansion and cost reduction

 

54.4

 

39.8

 

13.8

 

Total

 

$

77.8

 

$

72.6

 

$

42.2

 

 

During 2005, the Partnership’s capital expenditures of $77.8 million increased by $5.2 million from $72.6 million 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

48




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.

As discussed under Critical Accounting Policies and Estimates below, until December 31, 2005, the Partnership’s initial integrity expenditures have been capitalized as part of pipeline cost when such expenditures improve or extend the life of the pipeline or related assets. Subsequent integrity expenditures have been expensed as incurred. In 2005, approximately $3.0 million of integrity expenditures were expensed, compared to $0.9 million in 2004. As of January 1, 2006, the Partnership will begin charging all internal inspection integrity expenditures to expense, whether or not such expenditures are the initial or subsequent internal inspection. The Partnership expects to charge $7 million to $10 million of internal integrity expenditures to expense in 2006.

Operating infrastructure expenditures increased to $12.9 million principally as a result of $5.3 million of integration expenditures undertaken in connection with the acquisition of the Midwest Pipelines and Terminals in October 2004 and the acquisition of the Northeast Pipelines and Terminals in May 2005. The Partnership does not anticipate significant capital expenditures related to the integration of these assets in 2006.

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. This project is being implemented by WesPac Pipelines-Memphis, LLC, a 75%-owned affiliate of the Partnership. The pipeline and terminal construction project is supported by a long-term throughput and deficiency agreement entered into between WesPac Pipelines-Memphis, LLC and Federal Express. The project is expected to be commissioned and enter 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. The project involved the construction of two new pump stations, and the expansion of an existing pump station at Macungie, Pennsylvania, and increased the capacity of the Laurel pipeline by approximately 17%. 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.

During 2004, the Partnership’s capital expenditures of $72.6 million increased by $30.4 million from 2003. During 2004, the Partnership’s sustaining capital expenditures of $32.8 million increased by $4.4 million over 2003. In 2004 and 2003, the Partnership continued to emphasize its pipeline and tank integrity projects, including electronic internal inspections and other integrity assessments and associated repairs, as part of its comprehensive program to comply with legal requirements and to improve the reliability of the Partnership’s pipelines and terminals.

Expansion and cost reduction expenditures of $39.8 million increased by $26.0 million in 2004 over 2003. These expenditures related primarily to three projects. The first project, which commenced in 2003, involved the replacement of approximately 45 miles of pipeline in the Midwest between Lima, Ohio and Huntington, Indiana, for which approximately $12.8 million was expended in 2004. The remaining projects,

49




which are mentioned above, included the Laurel pipeline expansion and the 11-mile pipeline and associated terminal construction project serving Federal Express at the Memphis International Airport.

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

 

 

Year Ended December 31,

 

 

 

2005

 

2004

 

2003

 

 

 

(In millions)

 

Pipeline Operations

 

$

70.3

 

$

67.3

 

$

34.8

 

Terminalling and Storage

 

7.0

 

3.6

 

2.6

 

Other Operations

 

.5

 

1.7

 

4.8

 

Total

 

$

77.8

 

$

72.6

 

$

42.2

 

 

The Partnership expects to spend approximately $80 million in capital expenditures in 2006, of which approximately $30 million is expected to relate to sustaining capital expenditures and $50 million is expected to relate to expansion and cost reduction projects. Sustaining capital expenditures include renewals and replacement of tank floors and roofs, upgrades to station and terminalling equipment, field instrumentation and cathodic protection systems.

Expansion and cost reduction expenditures include projects to facilitate increased pipeline volumes, extend the pipeline incrementally to new facilities, expand terminal facilities or improve the efficiency of operations. Among the projects expected to be substantially completed in 2006 are a pipeline connection from a propane storage facility in Illinois to our Wood River pipeline system and the acquisition of a terminal in Indiana expected to enhance pipeline volumes on the Wood River pipeline system.

Cash Flows from Financing Activities

In order to fund its acquisition and internal growth opportunities (including the May 2005 acquisition of the Northeast Pipelines and Terminals and the October 2004 acquisition of the Midwest Pipelines and Terminals), the Partnership issued debt and equity securities in each of 2005, 2004 and 2003, and borrowed amounts under the Credit Facility (a portion of which were repaid with the proceeds from the issuance of debt and equity securities).

The Partnership’s financing transactions are summarized as follows:

Equity Securities:

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 in part to repay $108 million that was outstanding under the Credit Facility.

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

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

50




On February 28, 2003, the Partnership issued 1,750,000 LP Units in an underwritten public offering at $36.01 per LP unit. Net proceeds from the Partnership, after underwriters’ discount of $1.62 per LP Unit and offering costs, were approximately $59.9 million. The net proceeds were used to repay a portion of amounts outstanding under the Partnership’s credit facility.

Debt Securities:

On June 30, 2005, the Partnership sold $125 million aggregate principal of its 5.125% Notes due July 1, 2017 in an underwritten public offering. Proceeds from the note offering, after underwriters’ fees and expenses, were approximately $123.5 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.

On July 7, 2003, the Partnership sold $300 million aggregate principal amount of its 4.625% Notes due 2013 in an underwritten public offering. Proceeds from the note offering, after underwriters’ fees and expenses, were approximately $296.4 million. On August 14, 2003, the Partnership sold $150 million aggregate principal amount of its 63¤4% Notes due 2033 in a Rule 144A offering. The Notes were subsequently exchanged for equivalent notes which are publicly traded. Proceeds from the note offering, after underwriters’ fees and expenses, were approximately $148.1 million. Proceeds from these offerings were used in part to repay all amounts then outstanding under the Partnership’s prior credit facility and to repay the Buckeye $240 million Senior Notes and applicable yield maintenance premium of $45.5 million.

In connection with the repayment of the $240 million Senior Notes, Buckeye was required to pay a yield maintenance premium of $45.5 million. The yield maintenance premium was charged to expense in 2003 in the Partnership’s consolidated financial statements.

In addition to the above, the Partnership borrowed $250 million, $320 million and $24 million, and repaid $273 million, $247 million and $189 million under the Credit Facility or its prior credit facilities in 2005, 2004 and 2003, respectively.

Distributions to Unitholders increased to $104.3 million in 2005, compared to $80.2 million in 2004 and $72.4 million in 2003. Distributions in 2005 increased over 2004 as a result of increases in the unit distribution rate, the issuance of the 3.6 million LP Units in 2005 and the payment of four quarters of distributions on the 5.5 million LP Units issued in October 2004 compared to only one quarter in 2004. Distributions in 2004 increased over 2003 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, 2005, the Partnership had $900.0 million in aggregate outstanding long-term debt, consisting of $125 million of the 5.125% Notes due 2017, $275 million of the 5.300% Notes due 2014, $300 million of the 4 5/8% Notes due 2013, $150.0 million of the 6¾% Notes due 2033 and $50 million outstanding under the Credit Facility. The terms of the Credit Facility are described in “Liquidity and Capital Resources” above. At December 31, 2005, the Partnership had $348.7 million available under the Credit Facility, with $1.3 million allocated in support of certain operational letters of credit.

51




In order to hedge a portion of its fair value risk related to the 45¤8% Notes due 2013, on October 28, 2003, the Partnership entered into an interest rate swap agreement with a financial institution. The notional amount of the swap agreement was $100 million. The swap agreement called for the Partnership to receive fixed payments from the financial institution at a rate of 45¤8% of the notional amount in exchange for floating rate payments from the Partnership based on the notional amount using a rate equal to the six-month LIBOR (determined in arrears) minus 0.28%. The swap agreement was scheduled to terminate on the maturity date of the 45¤8% Notes and interest amounts under the swap agreement were payable semiannually on the same date as interest payments on the 45¤8% Notes. The Partnership designated the swap agreement as a fair value hedge at the inception of the agreement and elected to use the short-cut method provided for in SFAS No. 133, which assumes no ineffectiveness will result from the use of the hedge.

The Partnership terminated the interest rate swap agreement on December 8, 2004 and received proceeds of $2.0 million. 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 in the Partnership’s income statement was reduced by $2.6 million in 2004 and by $0.6 million in 2003 as a result of the interest rate swap agreement.

Operating Leases

The Operating Subsidiaries lease certain land and rights-of-way. Minimum future lease payments for these leases as of December 31, 2005 are approximately $4.2 million for each of the next five years. Substantially all of these lease payments may be canceled at any time should the leased property no longer be required for operations.

The General Partner leases space in an office building and certain office equipment and charges these costs to the Operating Subsidiaries. Buckeye leases certain computing equipment and automobiles. Future minimum lease payments under these noncancelable operating leases at December 31, 2005 were as follows: $888,000 for 2006, $435,000 for 2007, $305,000 for 2008 and none thereafter.

Buckeye is a party to an energy services agreement for certain pumping equipment and the natural gas requirements to fuel this equipment at its Linden, New Jersey facility. Under the energy services agreement, which is designed to reduce power costs at the Linden facility, Buckeye is required to pay a minimum of $1,743,000 annually over the next six years. This minimum payment is based on an annual minimum usage requirement of the natural gas engines at the rate of $0.049 per kilowatt hour equivalent. In addition to the annual usage requirement, Buckeye is subject to minimum usage requirements during peak and off-peak periods. Buckeye’s use of the natural gas engines has exceeded the minimum annual requirement in 2003, 2004, and 2005.

Rent expense under operating leases was $8,740,000, $8,477,000 and $7,824,000 for 2005, 2004 and 2003, respectively.

52




Contractual Obligations

Contractual obligations are summarized in the following table:

 

 

Payments Due by Period

 


Contractual Obligations

 

 

 


Total

 

Less than
1 year

 


1-3 years

 


3-5 years

 

More than
5 years

 

 

 

(In thousands)

 

Long-term debt

 

$

900,000

 

$

 

$

 

$

50,000

 

$

850,000

 

Interest payable on fixed long-term debt obligations

 

586,137

 

44,981

 

89,963

 

89,963

 

361,230

 

Acquisitions

 

92,300

 

92,300

 

 

 

 

Operating leases

 

1,628

 

888

 

740

 

 

 

Other long-term obligations

 

10,458

 

1,743

 

3,486

 

3,486

 

1,743

 

Rights-of-way payments

 

20,930

 

4,186

 

8,372

 

8,372

 

 

Purchase obligations

 

16,933

 

16,933

 

 

 

 

Total contractual cash obligations

 

$

1,628,386

 

$

161,031

 

$

102,561

 

$

151,821

 

$

1,212,973

 

 

Interest payable on fixed long-term debt obligations include semi-annual payments required for the Partnership’s 45¤8% Notes, its 63¤4% Notes, its 5.300% Notes and its 5.125% Notes.

Amounts for acquisitions represents amounts for which the Partnership was contractually obligated to close, in January 2006, including a refined petroleum products terminal located in Niles, Michigan and a 350-mile natural gas liquids pipeline.

Other long-term obligations represent the minimum payments due under the energy services agreement for the purchase of natural gas to fuel the pumping equipment at Linden, New Jersey discussed above.

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.

Environmental Matters

The Operating Subsidiaries are subject to federal, state and local laws and regulations relating to the protection of the environment. These laws and regulations, as well as the Partnership’s own standards relating to protection of the environment, cause the Operating Subsidiaries to incur current and ongoing operating and capital expenditures. Environmental expenses are incurred in connection with emergency response activities associated with the release of petroleum products to the environment from the Partnership’s pipelines and terminals, and in connection with longer term environmental remediation efforts which may involve groundwater monitoring and treatment. The Partnership regularly incurs expenses in connection with these environmental remediation activities. In 2005, the Operating Subsidiaries incurred operating expenses of $9.3 million and, at December 31, 2005, had $21.4 million accrued for environmental matters. At December 31, 2005, the Partnership estimates that approximately $8 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 $2.5 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 increasingly rigorous environmental laws.

53




Competition and Other Business Conditions

Several major refiners and marketers of petroleum products announced strategic alliances or mergers in recent years. These alliances or mergers have the potential to alter refined product supply and distribution patterns within the Operating Subsidiaries’ market area resulting in both gains and losses of volume and revenue. While the General Partner believes that individual delivery locations within its market area may have significant gains or losses, it is not possible to predict the overall impact these alliances or mergers may have on the Operating Subsidiaries’ business.

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 do not participate in the ESOP including employees hired by Services Company from BGC, Buckeye Terminals and Norco on December 26, 2004. The ESOP owns all of the outstanding common stock of Services Company. Services Company owns 2,359,996 LP Units of the Partnership. At December 31, 2005, the ESOP was directly obligated to a third-party lender for $33.6 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 2,359,996 shares of Services Company’s common stock. The Partnership has committed that, in the event that the value of the 2,359,996 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 Services Company LP Units 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 Services Company LP Units returns to an amount which exceeds the 125% minimum. At December 31, 2005, the value of the LP Units was approximately $100 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. Except for the period March 1, 2003 through November 1, 2004, Services Company stock held in employee accounts received stock dividends in lieu of cash. The ESOP was amended to eliminate the payment of stock dividends on allocations made after February 28, 2003. Based upon provisions contained in the American Jobs Creation Act of 2004, the plan was amended further to reinstate this feature on allocations made after November 1, 2004.

The Partnership contributed 2,573,146 LP Units to Services Company in August 1997 in exchange for the elimination of the Partnership’s obligation to reimburse 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 will also incur ESOP-related costs for routine administrative costs and taxes associated with annual taxable income on the sale of LP Units, if any. Total ESOP related costs charged to earnings were $0.2 million in 2005, $0.6 million in 2004 and $1.1 million in 2003.

54




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 improvement to the pipeline are capitalized based on the cost of the improvement while repairs and maintenance are expensed.

Prior to January 1, 2006, pipeline integrity expenditures were capitalized the first time such expenditures were incurred, when such expenditures improved or extended the life of the pipeline or related assets. Subsequent integrity expenditures were expensed as incurred. During 2005, 2004 and 2003, the Partnership capitalized $10.5 million, $21.8 million and, $18.9 million, respectively, of integrity expenditures. In 2005 and 2004, the Partnership also charged approximately $3.0 million and $0.9 million of similar integrity expenditures to expense.

On June 30, 2005, FERC issued an Order on Accounting for Pipeline Assessment Costs (the “Order”) to address what had been diverse practice by FERC-regulated companies (including natural gas pipelines and refined products petroleum product pipelines like the Partnership) and to enhance comparability of financial statements filed with FERC. The Order, which is effective prospectively commencing January 1, 2006, requires companies to record certain integrity expenditures as capital and other costs as operating expenses in financial reports filed with FERC. The Partnership has determined that, effective January 1, 2006, it will adopt the requirements of the Order for GAAP purposes as well as regulatory purposes. The Partnership does not expect the adoption of the FERC Order for GAAP purposes will have a material effect on the Partnership’s financial statements.

As discussed under “Environmental Matters above, the Operating Partnerships are subject to federal, state and local laws and regulations relating to the protection of the environment. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. Generally, the timing of these accruals coincides with the Partnership’s commitment to a formal plan of action. Accrued environmental remediation related expenses include estimates of direct costs of remediation and indirect costs related to the remediation effort, such as compensation and benefits for employees directly involved in the remediation activities and fees paid to outside engineering, consulting and law firms. The Partnership maintains insurance which may cover certain environmental expenditures. During 2005, the Operating Partnerships incurred operating expenses, net of insurance recoveries, of $9.3 million and, at December 31, 2005, had $21.4 million accrued for environmental matters. The environmental accruals are revised as new matters arise, or as new facts in connection with environmental remediation projects require a revision of estimates previously made with respect to the probable cost of such remediation projects.

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.”

55




Recent Accounting Pronouncements

In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement No. 123 (Revised 2004) “Share-Based Payment” (“SFAS No. 123R”) which requires that compensation costs related to share-based payment transactions be recognized in the Partnership’s financial statements and effectively eliminates the intrinsic value method permitted by APB 25. SFAS No. 123R is effective for the Partnership by January 1, 2006. The Partnership intends to adopt SFAS No. 123R using the modified prospective method, as permitted under the Statement. The Partnership does not expect the adoption of SFAS No. 123R to have a material effect on the Partnership’s financial statements.

In December 2004, the FASB issued Statement of Financial Accounting Standards No. 153, “Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29” (“SFAS No. 153”) which addresses the measurement of exchanges of nonmonetary assets. It eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets in paragraph 21(b) of APB Opinion No. 29, “Accounting for Nonmonetary Transactions”, and replaces it with an exception for exchanges that do not have commercial substance. SFAS No. 153 specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. SFAS No. 153 is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005.

In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”). FIN 47 clarifies the term conditional asset retirement obligation as used in FASB Statement No. 143, “Accounting for Asset Retirement Obligations” as a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. This interpretation became effective for the Partnership in the fiscal quarter ended December 31, 2005. The adoption of FIN 47 did not have a material effect on the Partnership’s consolidated financial statements.

In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections” (“SFAS No. 154”). SFAS No. 154 provides guidance on the accounting for and reporting of changes in accounting principles, estimates, and error corrections. This statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005.

On June 30, 2005, the Federal Energy Regulatory Commission (“FERC”) issued an Order on Accounting for Pipeline Assessment Costs to address what has been diverse practice by FERC-regulated pipeline companies (including natural gas pipelines and refined petroleum product pipelines like the Partnership) and to enhance comparability of financial statements filed with FERC. The Order, which is effective prospectively commencing January 1, 2006, requires companies to record certain costs related to pipeline integrity programs as capital and other costs as operating expenses in financial reports filed with FERC. The Partnership has disclosed its practice is to capitalize integrity management expenditures when such expenditures improve or extend the life of the pipeline or related assets. Other integrity management costs are expensed as incurred. The Partnership follows this practice for both reports prepared under GAAP and periodic regulatory reports to FERC. The Partnership has determined that, effective January 1, 2006, it will adopt the requirements of the Order for GAAP purposes as well as regulatory purposes. The Partnership does not expect the adoption of the FERC Order for GAAP purposes will have a material effect on the Partnership’s financial statements.

Forward-Looking Information

The information contained above in this Management’s Discussion and Analysis and elsewhere in this Report on Form 10-K includes “forward-looking, statements,” within the meaning of the Private Securities Litigation Reform Act of 1995. Such statements use forward-looking words such as “anticipate,”

56




“continue,” “estimate,” “expect,” “may,” ‘will,” or other similar words, although some forward-looking statements are expressed differently. These statements discuss future expectations or contain projections. Specific factors which could cause actual results to differ from those in the forward-looking statements include: (1) price trends and overall demand for refined petroleum products in the United States in general and in our service areas in particular (economic activity, weather, alternative energy sources, conservation and technological advances may affect price trends and demands); (2) changes, if any, in laws and regulations, including, among others, safety, tax and accounting matters or Federal Energy Regulatory Commission regulation of the Partnership’s tariff rates; (3) liability for environmental claims; (4) security issues affecting our assets, including, among others, potential damage to our assets caused by acts of war or terrorism; (5) unanticipated capital expenditures and operating expenses to repair or replace the Partnership’s assets; (6) availability and cost of insurance on the Partnership’s assets and operations; (7) the Partnership’s ability to successfully identify and complete strategic acquisitions and make cost saving changes in operations; (8) expansion in the operations of the Partnership’s competitors; (9) the Partnership’s ability to integrate any acquired operations into its existing operations; (10) shut-downs or cutbacks at major refineries that use the Partnership’s services; (11) deterioration in the Partnership’s labor relations; (12) changes in real property tax assessments; (13) disruptions to the air travel system; and (14) interest rate fluctuations and other capital market conditions.

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of the Partnership’s 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 current beliefs and expectations, the Partnership does not assume responsibility for the accuracy and completeness of such statements. Further, the Partnership undertakes 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 45¤8% Notes and the 6¾% Notes) and to cash flow risk with respect to its variable rate obligations (the Credit Facility). Fair value risk represents the risk that the value of the fixed portion of its financing arrangements will rise or fall depending on changes in interest rates. Cash flow risk represents the risk that interest costs related to the Credit Facility will rise or fall depending on changes in interest rates.

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

At December 31, 2005, the Partnership had total fixed debt obligations at face value of $850 million, consisting of $125 million of the 5.125% Notes, $275 million of the 5.300% Notes, $300 million of the 45¤8% Notes and $150 million of the 6¾% Notes. The fair value of these obligations at December 31, 2005 was approximately $858 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 $73 million. The Partnership’s variable debt obligation under the Credit Facility was $50 million. Based on

57




the balance outstanding at December 31, 2005, a 1% increase or decrease in interest rates would increase or decrease annual interest expense by $0.5 million.

On October 28, 2003, the Partnership entered into an interest rate swap agreement with a financial institution in order to hedge a portion of its fair value risk associated with its 45¤8% Notes. The notional amount of the swap agreement was $100 million. The swap agreement called for the Partnership to receive fixed payments from the financial institution at a rate of 45¤8% of the notional amount in exchange for floating rate payments from the Partnership based on the notional amount using a rate equal to the six-month LIBOR (determined in arrears) minus 0.28%. The swap agreement was scheduled to settle on the maturity date of the 45¤8% Notes and interest amounts under the swap agreement were payable semiannually on the same date as interest payments on the 45¤8% Notes. The Partnership designated the swap agreement as a fair value hedge at the inception of the agreement and elected to use the short-cut method provided for in SFAS No. 133, which assumes no ineffectiveness will result from the use of the hedge.

The Partnership terminated the interest rate swap agreement on December 8, 2004 and received proceeds of $2.0 million. 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 in the Partnership’s income statement was reduced by $2.6 million in 2004 and by $0.6 million in 2003 as a result of the interest rate swap agreement.

58




Item 8.  Financial Statements and Supplementary Data

BUCKEYE PARTNERS, L.P.

Index to Financial Statements

 

Schedules are omitted because they are either not applicable or not required or the information required is included in the consolidated financial statements or notes thereto.

59




MANAGEMENT’S REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING

Management of Buckeye GP LLC (the “General Partner”), as general partner of Buckeye Partners, L.P. (the “Partnership”), is responsible for establishing and maintaining adequate internal control over financial reporting of the Partnership Internal control over financial reporting is a process designed to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. A company’s internal control over financial reporting includes those policies and procedures that  pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and  provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management evaluated the General Partner’s internal control over financial reporting of the Partnership as of December 31, 2005. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (COSO). As a result of this assessment and based on the criteria in the COSO framework, management has concluded that, as of December 31, 2005, the General Partner’s internal control over financial reporting of the Partnership was effective.

The Partnership’s independent registered public accounting firm, Deloitte & Touche LLP, has audited management’s assessment of the General Partner’s internal control over financial reporting for the Partnership. Their opinion on management’s assessment and their opinion on the effectiveness of the General Partner’s internal control over financial reporting for the Partnership appears herein.

WILLIAM H. SHEA, JR.

 

ROBERT B. WALLACE

Chief Executive Officer

 

Senior Vice President, Finance and

 

 

Chief Financial Officer

 

February 24, 2006

60




REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of Buckeye Partners, L.P.

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Buckeye Partners, L.P. and subsidiaries (the “Partnership”) maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Partnership’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that the Partnership maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

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We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2005 of the Partnership and our report dated February 24, 2006 expressed an unqualified opinion on those financial statements.

DELOITTE & TOUCHE LLP

Philadelphia, Pennsylvania
February 24, 2006

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of Buckeye Partners, L.P.

We have audited the accompanying consolidated balance sheets of Buckeye Partners, L.P. and subsidiaries (the “Partnership”) as of December 31, 2005 and 2004, and the related consolidated statements of income, and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Buckeye Partners, L.P. and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2006 expressed an unqualified opinion on management’s assessment of the effectiveness of the Partnership’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.

DELOITTE & TOUCHE LLP

Philadelphia, Pennsylvania
February 24, 2006

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BUCKEYE PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per unit amounts)

 

 

 

 

Year Ended December 31,

 

 

 

Notes

 

2005

 

2004

 

2003

 

Revenue

 

2

 

$

408,446