e10vk
Table of Contents

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
     
þ   Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2009
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 1-32963
Buckeye GP Holdings L.P.
(Exact name of registrant as specified in its charter)
     
Delaware   11-3776228
     
(State or other jurisdiction of
incorporation or organization)
  (IRS Employer
Identification number)
     
One Greenway Plaza
Suite 600
Houston, TX
  77046
     
(Address of principal executive offices)   (Zip Code)
Registrant’s telephone number, including area code: (832) 615-8600
Securities registered pursuant to Section 12(b) of the Act:
     
 Title of each class   Name of each exchange on
which registered
     
     
Common Units representing limited partnership interests   New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
     Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ
     Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
     Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Date File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o
     Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
             
Large accelerated filer o   Accelerated filer þ   Non-accelerated filer o   Smaller reporting company o
        (Do not check if a smaller reporting company)    
     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No þ
     At June 30, 2009, the aggregate market value of the registrant’s Common Units held by non-affiliates was $206.2 million. 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.
     As of March 1, 2010, there were 27,774,043 Common Units and 525,957 Management Units outstanding.
 
 

 


 

TABLE OF CONTENTS
             
        Page
 
  PART I        
  Business     3  
  Risk Factors     29  
  Unresolved Staff Comments     46  
  Properties     47  
  Legal Proceedings     47  
  [Reserved]     47  
 
           
 
  PART II        
  Market for the Registrant’s Common Units, Related Unitholder Matters, and Issuer Purchases of Common Units     48  
  Selected Financial Data     49  
  Management’s Discussion and Analysis of Financial Condition and Results of Operations     50  
  Quantitative and Qualitative Disclosures About Market Risk     74  
  Financial Statements and Supplementary Data     77  
  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     133  
  Controls and Procedures     133  
  Other Information     133  
 
           
 
  PART III        
  Directors, Executive Officers and Corporate Governance     134  
  Executive Compensation     138  
  Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters     139  
  Certain Relationships and Related Transactions and Director Independence     141  
  Principal Accounting Fees and Services     145  
 
           
 
  PART IV        
  Exhibits, Financial Statement Schedules     146  
 EX-21.1
 EX-23.1
 EX-31.1
 EX-31.2
 EX-32.1
 EX-32.2

1


Table of Contents

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
     The information contained in this Annual Report on Form 10-K (this “Report”) include “forward-looking statements.” All statements that express belief, expectation, estimates or intentions, as well as those that are not statements of historical facts, are forward-looking statements. Such statements use forward-looking words such as “proposed,” “anticipate,” “project,” “potential,” “could,” “should,” “continue,” “estimate,” “expect,” “may,” “believe,” “will,” “plan,” “seek,” “outlook” and other similar expressions that are intended to identify forward-looking statements, although some forward-looking statements are expressed differently. These statements discuss future expectations and contain projections. Specific factors that could cause actual results to differ from those in the forward-looking statements include, but are not limited to: (1) our ability to pay distributions to our unitholders; (2) our expected receipt of distributions and incentive distributions from Buckeye Partners, L.P. (“Buckeye”); (3) anticipated trends in Buckeye’s business; (4) price trends and overall demand for refined petroleum products and natural gas in the United States in general and in Buckeye’s service areas in particular (economic activity, weather, alternative energy sources, conservation and technological advances may affect price trends and demands); (5) competitive pressures from other transportation services or alternative fuel sources; (6) changes, if any, in laws and regulations, including, among others, safety, environmental, tax and accounting matters or Federal Energy Regulatory Commission regulation of Buckeye’s tariff rates; (7) liability for environmental claims; (8) nonpayment or nonperformance by Buckeye’s customers; (9) security issues affecting Buckeye’s assets, including, among others, potential damage to its assets caused by vandalism, acts of war or terrorism; (10) construction costs, unanticipated capital expenditures and operating expenses to repair or replace Buckeye’s assets; (11) availability and cost of insurance on our and Buckeye’s assets and operations; (12) Buckeye’s ability to successfully identify, complete and integrate strategic acquisitions and make cost saving changes in operations; (13) expansion in the operations of Buckeye’s competitors; (14) shut-downs or production cutbacks at major refineries that use Buckeye’s services; (15) deterioration in Buckeye’s labor relations; (16) regional economic conditions; (17) changes in real property tax assessments; (18) disruptions to the air travel system; (19) interest rate fluctuations and other capital market conditions; (20) our future results of operations; (21) our liquidity and ability to finance our activities; (22) market conditions in Buckeye’s industry; (23) conflicts of interest between Buckeye, its general partner and us; (24) the treatment of Buckeye or us as a corporation for federal income tax purposes or if we or Buckeye become subject to entity-level taxation for state tax purposes; and (25) the ability to realize the anticipated benefits from Buckeye’s organizational restructuring. These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other known or unpredictable factors could also have material adverse effects on future results. Consequently, all of the forward-looking statements made in this document are qualified by these cautionary statements, and we cannot assure you that actual results or developments that we anticipate will be realized or, even if substantially realized, will have the expected consequences to or effect on us or our business or operations. Also note that we provide additional cautionary discussion of risks and uncertainties under the captions “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Report.
     The forward-looking statements contained in this Report speak only as of the date hereof. Although the expectations in the forward-looking statements are based on our current beliefs and expectations, we do not assume responsibility for the accuracy and completeness of such statements. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason. All forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this Report and in our future periodic reports filed with the U.S. Securities and Exchange Commission (“SEC”). In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this Report may not occur.

2


Table of Contents

PART I
Item 1. Business
Buckeye GP Holdings L.P.
     We are a publicly traded Delaware master limited partnership (“MLP”) organized on June 15, 2006. Our common units (“Common Units”) are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “BGH.” Our initial public offering (“IPO”) occurred on August 9, 2006 and, prior to such date, we had no activity. Our Common Units sold in the IPO represented approximately 37% of our outstanding equity. Our outstanding equity includes our Common Units and management units (“Management Units”).
     We own 100% of Buckeye GP LLC (“Buckeye GP”), which is the general partner of Buckeye Partners, L.P. (“Buckeye”). Buckeye is a publicly traded Delaware MLP that was organized in 1986 and is separately traded on the NYSE under the ticker symbol “BPL.” Approximately 62% of our aggregate outstanding Common Units and Management Units are owned by BGH GP Holdings, LLC (“BGH GP”), and approximately 38% by the public. BGH GP is owned by affiliates of ArcLight Capital Partners, LLC (“ArcLight”), Kelso & Company (“Kelso”), and certain investments funds along with certain members of senior management of Buckeye GP. MainLine Management LLC, a Delaware limited liability company (“MainLine Management”), is our general partner, and is wholly-owned by BGH GP. Unless the context requires otherwise, references to “we,” “us,” “our,” or “BGH” are intended to mean the business and operations of Buckeye GP Holdings L.P. and our consolidated operations, including those of Buckeye. References to “Buckeye” mean Buckeye Partners, L.P. and its consolidated subsidiaries.
     Our only business is the ownership of Buckeye GP. Buckeye GP’s only business is the management of Buckeye and its subsidiaries. At December 31, 2009, Buckeye GP owned an approximate 0.5% general partner interest in Buckeye.
     Buckeye Pipe Line Services Company (“Services Company”) was formed in 1996 in connection with the establishment of the Buckeye Pipe Line Services Company Employee Stock Ownership Plan (the “ESOP”). At December 31, 2009, Services Company owned approximately 3.2% of the publicly traded limited partner units of Buckeye (the “LP Units”). Services Company employees provide services to the operating subsidiaries through which Buckeye conducts its operations. Pursuant to a services agreement entered into in December 2004 (the “Services Agreement”), Buckeye’s operating subsidiaries reimburse Services Company for the costs of the services it provides. Pursuant to the Services Agreement and an executive employment agreement, through December 31, 2008, executive compensation costs and related benefits paid to Buckeye GP’s four highest salaried officers were not reimbursed by Buckeye or its operating subsidiaries but were reimbursed to Services Company by us. Effective January 1, 2009, Buckeye and its operating subsidiaries have paid for all executive compensation and benefits earned by Buckeye GP’s four highest salaried officers in return for an annual fixed payment from us of $3.6 million. Services Company has been consolidated in our financial statements.
     Our consolidated balance sheets include a noncontrolling capital account that reflects the portion of Buckeye owned by its partners other than us and Services Company. Similarly, our consolidated statements of operations include income attributable to noncontrolling interests that reflect the portion of the earnings due to Buckeye’s partners other than us and Services Company. We have determined that consolidation of Buckeye into our financial statements is appropriate, as we indirectly control Buckeye through our ownership of Buckeye GP.
     Our only cash-generating asset is our ownership interest in Buckeye GP. Buckeye GP generates cash and earnings primarily through its ownership of the general partner interest along with incentive distribution rights in Buckeye, and its approximate one percent general partner interest in certain of Buckeye’s operating subsidiaries. Our cash flow is, therefore, directly dependent upon the ability of Buckeye and its operating subsidiaries to make cash distributions to its partners. The actual amount of cash that we will have available for distribution will depend primarily on Buckeye’s ability to generate cash beyond its working capital requirements.

3


Table of Contents

Buckeye Partners, L.P.
     Buckeye has one of the largest independent refined petroleum products pipeline systems in the United States in terms of volumes delivered with approximately 5,400 miles of pipeline and 67 active products terminals that provide aggregate storage capacity of approximately 27.2 million barrels. In addition, Buckeye operates and maintains approximately 2,400 miles of other pipelines under agreements with major oil and chemical companies. Buckeye also owns and operates a major natural gas storage facility in northern California which provides approximately 40 billion cubic feet (“Bcf”) of total natural gas storage capacity (including pad gas), and is a wholesale distributor of refined petroleum products in the United States in areas also served by Buckeye’s pipelines and terminals.
     Buckeye operates and reports in five business segments: Pipeline Operations; Terminalling and Storage; Natural Gas Storage; Energy Services; and Development and Logistics. Buckeye previously referred to the Development and Logistics segment as the Other Operations segment. Buckeye renamed this segment to better describe the business activities conducted within the segment. Buckeye conducts all of its operations through operating subsidiaries, which are referred to herein as the “Operating Subsidiaries”:
    Buckeye Pipe Line Company, L.P. (“Buckeye Pipe Line”), which owns an approximately 2,643-mile refined petroleum products pipeline system serving major population centers in eight states. As a part of its service territory, Buckeye Pipe Line is the primary jet fuel transporter to certain airports, including John F. Kennedy International Airport (“JFK Airport”), LaGuardia Airport and Newark Liberty International Airport (“Newark Airport”).
 
    Laurel Pipe Line Company, L.P. (“Laurel”), which owns an approximately 345-mile refined petroleum products pipeline connecting four Philadelphia area refineries to ten delivery points across Pennsylvania.
 
    Wood River Pipe Lines LLC (“Wood River”), which owns eight refined petroleum products pipelines with aggregate mileage of approximately 1,287 miles located in Illinois, Indiana, Missouri and Ohio. Wood River includes two pipelines that Buckeye acquired from ConocoPhillips in November 2009. See “2009 Developments” below for further information.
 
    Buckeye Pipe Line Transportation LLC (“BPL Transportation”), which owns a refined petroleum products pipeline system with aggregate mileage of approximately 478 miles located in New Jersey, New York and Pennsylvania.
 
    Everglades Pipe Line Company, L.P. (“Everglades”), which owns an approximately 37-mile refined petroleum products pipeline connecting Port Everglades, Florida to Ft. Lauderdale-Hollywood International Airport and Miami International Airport. Everglades is the primary jet fuel transporter to Miami International Airport.
 
    Buckeye Pipe Line Holdings, L.P. (“BPH”), which, through certain of its subsidiaries, owns (or in certain instances leases from Buckeye’s other Operating Subsidiaries) 62 refined petroleum and other products terminals (of which 59 are included in our Terminalling and Storage segment and three are included in our Pipeline Operations segment) with aggregate storage capacity of approximately 26.2 million barrels and 574 miles of pipelines in the Midwest and West Coast. BPH’s terminal holdings include three terminals that we acquired from ConocoPhillips in November 2009. See “2009 Developments” below for further information. BPH operates, through its subsidiaries, terminals and pipelines for third parties. BPH also holds noncontrolling stock interests in two Midwest refined petroleum products pipelines and a natural gas liquids (“NGLs”) pipeline system.
 
    Buckeye Gas Storage LLC (“Buckeye Gas”), which, through its subsidiary Lodi Gas Storage, L.L.C. (“Lodi Gas”), owns a natural gas storage facility in northern California that provides approximately 40 Bcf of total natural gas storage capacity (including pad gas).

4


Table of Contents

    Buckeye Energy Holdings LLC (“Buckeye Energy”), which, through its subsidiary Buckeye Energy Services LLC (“BES”), markets refined petroleum products in areas served by our pipelines and terminals and also owns five refined petroleum product terminals with aggregate storage capacity of 1.0 million barrels located in northeastern and central Pennsylvania.
     The following chart depicts our and Buckeye’s ownership structure as of December 31, 2009 (ownership percentages in the chart are approximate).
(GRAPHIC)
Business Strategy
     Our primary objective is to increase cash available for distribution to our common unitholders (“Unitholders”) and, accordingly, the value of our Common Units, through our investment in Buckeye.
     Buckeye’s primary business objective is to provide stable and sustainable cash distributions to its unitholders, while maintaining a relatively low investment risk profile. The key elements of its strategy are to:
    Generate stable cash flows;
 
    Improve operating efficiencies and asset utilization;

5


Table of Contents

    Generate increased cash distributions to its unitholders;
 
    Grow its portfolio of predictable and stable fee-based businesses combined with opportunistic revenue generating capabilities;
 
    Operate in a safe and environmentally responsible manner; and
 
    Maintain an investment-grade credit rating.
     Buckeye intends to achieve its strategy by:
    Acquiring, building and operating high quality, strategically located assets;
    Maintaining stable long-term customer relationships, including by providing superior customer service;
 
    Maintaining and enhancing the integrity of its pipelines, terminals and storage assets;
 
    Maintaining a solid, conservative financial position;
 
    Optimizing its portfolio of pipeline, terminalling and storage assets;
 
    Pursuing strategic cash flow accretive acquisitions that:
    Complement its existing footprint;
 
    Provide geographic, product and/or asset class diversity;
 
    Leverage existing management capabilities and infrastructure; and
    Building an experienced management team with the objective to grow its business.
2009 Developments
  Reorganization
     In early 2009, we began a “best practices” review of our business processes and organizational structure to identify improved business practices, operating efficiencies and cost savings in anticipation of changing needs in the energy markets. This review culminated in the approval by the Board of Directors of Buckeye GP of an organizational restructuring.
     The organizational restructuring included a workforce reduction of approximately 230 employees, in excess of 20% of our workforce. The program was initiated in the second quarter of 2009 and was substantially complete by the end of 2009. As part of the workforce reduction, we offered certain eligible employees the option of enrolling in a voluntary early retirement program, which approximately 80 employees accepted. The remaining affected positions have been eliminated involuntarily under our ongoing severance plan. Most terminations were effective as of July 20, 2009. The restructuring also included the relocation of some employees consistent with the goals of the reorganization. We have incurred $32.1 million of expenses in connection with this organizational restructuring for the year ended December 31, 2009. See Note 3 in the Notes to Consolidated Financial Statements for further discussion.
  Asset Impairment and Subsequent Sale of the Assets
     During the second quarter of 2009, we received notification that several of the shippers on the NGL pipeline owned by Buckeye NGL Pipe Lines LLC (“Buckeye NGL”) intended to migrate their business to a competing pipeline that recently went into service. In connection with this notification, there was a significant decline in shipment volumes as compared to historical averages. This significant loss in the customer base utilizing Buckeye’s NGL pipeline, in conjunction with the authorization by the Board of Directors of Buckeye GP to pursue the sale of Buckeye NGL, triggered an evaluation of a potential asset impairment that resulted in a non-cash charge to earnings of $72.5 million in the Pipeline Operations segment in the second quarter of 2009. Effective January 1, 2010, we sold our ownership interest in Buckeye NGL for $22.0 million. The sales proceeds exceeded the previously impaired carrying value of the assets of Buckeye NGL by $12.8 million resulting in the reversal of $12.8 million of the previously recorded asset impairment expense in the fourth quarter of 2009. The impairment and subsequent reversal are reflected within the category “Asset Impairment Expense” on our consolidated statements of operations. See Note 8 in the Notes to Consolidated Financial Statements for further discussion.

6


Table of Contents

  Refined Petroleum Product Terminals and Pipeline Assets Acquisition
     In November 2009, we acquired from ConocoPhillips certain refined petroleum product terminals and pipeline assets for approximately $47.1 million in cash. In addition, we acquired certain inventory on hand for $7.3 million and entered into certain commercial contracts with ConocoPhillips that are associated with the acquired facilities. The assets that we acquired include over 300 miles of active pipelines that provide connectivity between the East St. Louis, Illinois and East Chicago, Indiana markets and three terminals providing 2.3 million barrels of storage. The acquisition was funded through cash flows from operations and borrowings under Buckeye’s existing credit facility. See Note 4 in the Notes to Consolidated Financial Statements for further discussion.
  Completion of Kirby Hills Phase II Expansion Project
     In June 2009, we completed the Kirby Hills Phase II expansion project. The Kirby Hills Phase II expansion project provides approximately 100,000 million cubic feet per day (“MMcf/day”) of additional injection capability and 200,000 MMcf/day of additional withdrawal capability at Lodi Gas’s natural gas storage facility. See “Natural Gas Storage Segment” below for further information.
  Debt Financings
     In August 2009, Buckeye sold $275.0 million aggregate principal amount of 5.500% Notes due 2019 (the “5.500% Notes”) in an underwritten public offering. The notes were issued at 99.35% of their principal amount. Total proceeds from this offering, after underwriters’ fees, expenses and debt issuance costs of $1.8 million, were approximately $271.4 million, and were used to reduce amounts outstanding under Buckeye’s credit facility and for general partnership purposes.
     In August 2009, we amended the BES credit agreement (“BES Credit Agreement”) to increase the borrowing capacity from $175.0 million to $250.0 million. Buckeye’s unsecured revolving credit agreement (the “Credit Facility”) was also amended to reduce the borrowing capacity from $600.0 million to $580.0 million. See Note 13 in the Notes to Consolidated Financial Statements for further discussion.
  Equity Offering
     On March 31, 2009, Buckeye issued 2.6 million LP Units in an underwritten public offering at $35.08 per LP Unit. On April 29, 2009, the underwriters of the equity offering exercised their option to purchase an additional 390,000 LP Units at $35.08 per LP Unit. Total proceeds from the offering, including the overallotment option and after the underwriter’s discount of $1.17 per LP Unit and offering expenses, were approximately $104.6 million, and were used to reduce amounts outstanding under Buckeye’s Credit Facility.
  2009 LTIP
     In March 2009, the 2009 Long-Term Incentive Plan of Buckeye Partners, L.P. (the “2009 LTIP”) became effective after the approval by a majority of Buckeye’s unitholders. The 2009 LTIP, which is administered by the Compensation Committee of the Board of Directors of Buckeye GP (the “Compensation Committee”), provides for the grant of phantom units, performance units, and in certain cases, distribution equivalent rights, which provide the participant a right to receive payments based on distributions Buckeye makes on its LP Units. The number of LP Units that may be granted under the 2009 LTIP may not exceed 1,500,000 subject to certain adjustments.
     On December 16, 2009, the Compensation Committee approved the terms of the Buckeye Partners, L.P. Unit Deferral and Incentive Plan (“Deferral Plan”). The Compensation Committee is expressly authorized to adopt the Deferral Plan under the terms of the 2009 LTIP, which grants the Compensation Committee the authority to establish a program pursuant to which Buckeye’s phantom units may be awarded in lieu of cash compensation at the election of the employee. At December 31, 2009, eligible employees were allowed to defer up to 50% of their 2009 compensation award under our Annual Incentive Compensation Plan (“AIC Plan”) or other discretionary bonus programs in exchange for grants of phantom units equal in value to the amount of their cash award deferral (each such unit, a “Deferral Unit”). Participants also receive one matching phantom unit for each Deferral Unit. See Note 18 in the Notes to Consolidated Financial Statements for further discussion.

7


Table of Contents

  Business Activities
     The following discussion describes the business activities of our business segments for 2009, which are the same as Buckeye’s operating segments and include Pipeline Operations, Terminalling and Storage, Natural Gas Storage, Energy Services and Development and Logistics. The Pipeline Operations and Energy Services segments derive a nominal amount of their revenue from U.S. governmental agencies. Otherwise, none of our business segments have contracts or subcontracts with the U.S. government. All of our assets are located in the continental United States. Detailed financial information regarding revenues, operating income and total assets of each segment can be found in Note 22 in the Notes to Consolidated Financial Statements. The following table shows our consolidated revenues and each segment’s percentage of consolidated revenue for the periods indicated (revenue in thousands):
                                                 
    Year Ended December 31,  
    2009     2008     2007  
    Revenue     Percent     Revenue     Percent     Revenue     Percent  
Pipeline Operations
  $ 392,667       22.3 %   $ 387,267       20.4 %   $ 379,345       73.0 %
Terminalling and Storage
    136,576       7.7 %     119,155       6.3 %     103,782       20.0 %
Natural Gas Storage
    99,163       5.6 %     61,791       3.3 %            
Energy Services
    1,125,013       63.5 %     1,295,925       68.3 %            
Development and Logistics
    34,136       1.9 %     43,498       2.3 %     36,220       7.0 %
Intersegment
    (17,183 )     -1.0 %     (10,984 )     -0.6 %            
 
                                   
Total
  $ 1,770,372       100.0 %   $ 1,896,652       100.0 %   $ 519,347       100.0 %
 
                                   
  Pipeline Operations Segment
     The Pipeline Operations segment owns and operates approximately 5,400 miles of pipeline located primarily in the northeastern and upper midwestern portions of the United States and services approximately 100 delivery locations. This segment transports refined petroleum products, including gasoline, jet fuel, diesel fuel, heating oil and kerosene, from major supply sources to terminals and airports located within end-use markets. The pipelines within this segment also transport other refined petroleum products, such as propane and butane, refinery feedstock and blending components. The segment’s geographical diversity, connections to multiple sources of supply and extensive delivery system help create a stable base business.
     The Pipeline Operations segment conducts business without the benefit of exclusive franchises from government entities. In addition, the Pipeline Operations segment generally operates as a common carrier, providing transportation services at posted tariffs and without long-term contracts. Demand for the services provided by the Pipeline Operations segment derives from end users’ demand for refined petroleum products in the regions served and the ability and willingness of refiners and marketers to supply such demand by deliveries through our pipelines. Factors affecting demand for refined petroleum products include price and prevailing general economic conditions. Demand for the services provided by the Pipeline Operations segment is, therefore, subject to a variety of factors partially or entirely beyond our control. Typically, this segment’s pipelines receive refined petroleum products from refineries, connecting pipelines, and bulk and marine terminals and transport those products to other locations for a fee.

8


Table of Contents

     The following table shows the volume and percentage of refined petroleum products transported by the Pipelines Operations segment for the periods indicated (volume in thousands of barrels per day):
                                                 
    Year Ended December 31,  
    2009     2008     2007  
    Volume     Percent     Volume     Percent     Volume     Percent  
Gasoline
    650.1       49.6 %     673.5       48.7 %     717.9       49.6 %
Jet fuel
    336.7       25.7 %     354.7       25.7 %     362.7       25.1 %
Middle distillates (1)
    284.7       21.7 %     304.2       22.0 %     320.1       22.1 %
NGLs (2)
    13.9       1.1 %     20.9       1.5 %     20.4       1.4 %
Other products
    24.5       1.9 %     28.9       2.1 %     26.3       1.8 %
 
                                   
Total (3)
    1,309.9       100.0 %     1,382.2       100.0 %     1,447.4       100.0 %
 
                                   
 
(1)   Includes diesel fuel, heating oil, kerosene and other middle distillates.
 
(2)   Represents volumes transported by the Buckeye NGL pipeline, which we sold effective January 1, 2010.
 
(3)   Excludes local product transfers.
     We provide pipeline transportation services in the following states: California, Connecticut, Florida, Illinois, Indiana, Massachusetts, Michigan, Missouri, Nevada, New Jersey, New York, Ohio, Pennsylvania, Tennessee and Texas. The geographical location and description of these pipelines is as follows:
  Pennsylvania—New York—New Jersey
     Buckeye Pipe Line serves major population centers in Pennsylvania, New York and New Jersey through approximately 928 miles of pipeline. Refined petroleum products are received at Linden, New Jersey from 17 major source points, including two refineries, six connecting pipelines and nine storage and terminalling facilities. Products are then transported through two lines from Linden, New Jersey to Macungie, Pennsylvania. From Macungie, the pipeline continues west through a connection with the Laurel pipeline to Pittsburgh, Pennsylvania (serving Reading, Harrisburg, Altoona/Johnstown and Pittsburgh, Pennsylvania) and north through eastern Pennsylvania into New York (serving Scranton/Wilkes-Barre, Pennsylvania and Binghamton, Syracuse, Utica, Rochester and, via a connecting carrier, Buffalo, New York). We lease 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 Airport and through two additional lines to JFK Airport and LaGuardia Airport and to commercial refined petroleum products terminals at Long Island City and Inwood, New York. These pipelines supply JFK Airport, LaGuardia Airport and Newark Airport with substantially all of each airport’s jet fuel requirements.
     BPL Transportation’s pipeline system delivers refined petroleum products from Valero Energy Corporation’s (“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 Malvern, Pennsylvania. From Malvern, a pipeline segment delivers refined petroleum products to locations in upstate New York, while another segment delivers products to central Pennsylvania. Two shorter pipeline segments connect Valero’s 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 four 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 Pipe Line 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 and Lima, Ohio; Detroit, Michigan; and East

9


Table of Contents

Chicago, Indiana. Major market areas served include Peoria, Illinois; Huntington/Fort Wayne, Indianapolis and South Bend, Indiana; Bay City, Detroit and Flint, Michigan; Cleveland, Columbus, Lima and Toledo, Ohio; and Pittsburgh, Pennsylvania.
     Wood River owns eight refined petroleum products pipelines with aggregate mileage of approximately 1,287 miles located in the midwestern United States. Refined petroleum products are received from ConocoPhillips’ Wood River refinery in Illinois and transported to the Chicago area, to our terminal in the St. Louis, Missouri area and to the Lambert-St. Louis Airport, to receiving points across Illinois and Indiana and to our pipeline in Lima, Ohio. Petroleum products are also transported from the East St. Louis, Illinois area to the East Chicago, Indiana area with delivery points in Illinois and Indiana, and from the East Chicago, Indiana area to the Kankakee, Illinois area. At our 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 our 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 Pipe Line LLC’s (“Marathon”) Wood River Station in southern Illinois to the East St. Louis, Illinois area.
  Other Refined Petroleum Products Pipelines
     Buckeye Pipe Line serves Connecticut and Massachusetts through an approximately 112-mile pipeline that carries refined petroleum products from New Haven, Connecticut to Hartford, Connecticut and Springfield, Massachusetts. This pipeline also serves Bradley International Airport in Windsor Locks, Connecticut.
     Everglades transports primarily jet fuel through an approximately 37-mile pipeline from Port Everglades, Florida to Ft. Lauderdale-Hollywood International Airport and Miami International Airport. Everglades supplies Miami International Airport with substantially all of its jet fuel requirements.
     WesPac Pipelines – Reno LLC (“WesPac Reno”) owns an approximately 3.0-mile pipeline serving the Reno/Tahoe International Airport. WesPac Pipelines – San Diego LLC (“WesPac San Diego”) owns an approximately 4.3-mile pipeline serving the San Diego International Airport. WesPac Pipelines – Memphis LLC (“WesPac Memphis”) owns an approximately 11-mile pipeline and a related terminal facility that primarily serves Federal Express Corporation at the Memphis International Airport. WesPac Reno, WesPac San Diego and WesPac Memphis, collectively, have terminal facilities with aggregate storage capacity of 0.5 million barrels. Each of WesPac Reno, WesPac San Diego and WesPac Memphis was originally created as a joint venture between BPH and Kealine LLC (“Kealine”). BPH currently owns 100% of WesPac Reno and WesPac San Diego. BPH and Kealine each have a 50% ownership interest in WesPac Memphis. As of December 31, 2009, we had provided $43.9 million in intercompany financing to WesPac Memphis. Each of these entities has been consolidated into our financial statements.
  Equity Investments
     BPH owns a 25% equity interest in West Shore Pipe Line Company (“West Shore”). West Shore owns an approximately 652-mile pipeline system that originates in the Chicago, Illinois area and extends north to Green Bay, Wisconsin and west and then north to Madison, Wisconsin. The pipeline system transports refined petroleum products to markets in northern Illinois and Wisconsin. The other equity holders of West Shore are major oil companies. Prior to January 1, 2009, the West Shore pipeline system was operated by Citgo Pipeline Company. Effective January 1, 2009, we have assumed the operations of the West Shore pipeline system on behalf of West Shore.
     BPH also owns a 20% equity interest in West Texas LPG Pipeline Limited Partnership (“WT LPG”). WT LPG owns an approximately 2,295-mile pipeline system that delivers raw mix NGLs to Mont Belvieu, Texas for fractionation. The NGLs are delivered to the WT LPG pipeline system from the Rocky Mountain region via connecting pipelines and from gathering fields and plants located in west, central and east Texas. The majority owner and the operator of WT LPG are affiliates of Chevron Corporation.
     BPH also owns a 40% equity interest in Muskegon Pipeline LLC (“Muskegon”). Marathon is the majority owner and operator of Muskegon. Muskegon owns an approximately 170-mile pipeline that delivers petroleum products from Griffith, Indiana to Muskegon, Michigan.

10


Table of Contents

     Buckeye Pipe Line owns a 25% equity interest in Transport4, LLC (“Transport4”). Transport4 provides an internet-based shipper information system that allows its customers, including shippers, suppliers and tankage partners to access nominations, schedules, tickets, inventories, invoices and bulletins over a secure internet connection.
   Terminalling and Storage Segment
     The Terminalling and Storage segment owns 59 terminals that provide bulk storage and throughput services with respect to refined petroleum products and other renewable fuels, including ethanol, and has an aggregate storage capacity of approximately 25.7 million barrels. Of our 59 terminals in the Terminalling and Storage segment, 45 are connected to our pipelines and 14 are not. We own the property on which the terminals are located with the exception of the Albany terminal, which is primarily located on leased property.
     The Terminalling and Storage segment’s terminals receive products from pipelines and, in certain cases, barges and railroads, and distribute them to third parties, who in turn deliver them to end-users and retail outlets. This segment’s terminals play a key role in moving products to the end-user market by providing efficient product receipt, storage and distribution capabilities, inventory management, ethanol and biodiesel blending, and other ancillary services that include the injection of various additives. Typically, the Terminalling and Storage segment’s terminal facilities consist of multiple storage tanks and are equipped with automated truck loading equipment that is available 24 hours a day.
     The segment’s terminals derive most of their revenues from various fees paid by customers. A throughput fee is charged for receiving products into the terminal and delivering them to trucks, barges or pipelines. In addition to these throughput fees, revenues are generated by charging customers fees for blending with renewable fuels, injecting additives and leasing terminal capacity to customers on either a short-term or long-term basis. The terminals also derive revenue from recovering and selling vapors emitted during truck loading.
     The following table sets forth the total average daily throughput for the Terminalling and Storage segment’s products terminals for the periods indicated (volume in average barrels per day):
                         
    Year Ended December 31,  
    2009     2008     2007  
Products throughput (1)
    444,900       457,400       482,300  
 
                 
 
(1)   Reported quantities exclude transfer volumes, which are non-revenue generating transfers among our various terminals. For the years ended December 31, 2008 and 2007, we previously reported 537.7 thousand and 568.6 thousand barrels, respectively, which included transfer volumes.

11


Table of Contents

     The following table sets forth the number of terminals and storage capacity in barrels by state for terminals reported in the Terminalling and Storage segment as of December 31, 2009:
                 
            Storage  
    Number of     Capacity  
State   Terminals (1)     (000s Barrels)  
Connecticut
    1       345  
Illinois
    9       3,161  
Indiana
    10       8,910  
Massachusetts
    1       106  
Michigan
    11       3,992  
Missouri
    2       345  
New York
    10       4,111  
Ohio
    8       2,871  
Pennsylvania
    4       1,131  
Wisconsin
    3       734  
 
           
Total
    59       25,706  
 
           
 
(1)   In addition, we have three terminals which are included in the Pipelines Operations segment for reporting purposes. There is a terminal in each of the states of California (with storage capacity of 0.1 million barrels), Nevada (with storage capacity of 0.1 million barrels) and Tennessee (with storage capacity of 0.3 million barrels). We also have five terminals in Pennsylvania with aggregate storage capacity of approximately 1.0 million barrels. These terminals are included in the Energy Services segment for reporting purposes (as discussed below).
   Natural Gas Storage Segment
     The Natural Gas Storage segment provides natural gas storage services through a facility located in northern California, which we acquired in January 2008 when we purchased all of the member interests in Lodi Gas for approximately $442.4 million. Currently, the facility provides approximately 40 Bcf of total natural gas storage capacity (including pad gas) and is connected to Pacific Gas and Electric’s intrastate gas pipeline system that services natural gas demand in the San Francisco and Sacramento, California areas.
     The original Lodi Gas facility is located approximately 30 miles south of Sacramento, near Lodi, California, and has been in service since January 2002. Its two storage reservoirs have daily maximum injection and withdrawal capability of 400 MMcf/day and 500 MMcf/day, respectively, utilizing 15 wells. Thirty-one miles of pipeline links the facility to an interconnect with Pacific Gas and Electric just north of Antioch, California.
     In January 2007, prior to our acquisition of Lodi Gas, Lodi Gas completed the Kirby Hills Phase I expansion. Kirby Hills is located approximately 30 miles west of Lodi in the Montezuma Hills, nine miles southeast of Fairfield, California. The Kirby Hills Phase I expansion added maximum injection and withdrawal capability of 50 MMcf/day utilizing six wells. Six miles of pipeline links the facility to an interconnect with Pacific Gas and Electric approximately six miles west of Rio Vista, California.
     In June 2009, we completed the Kirby Hills Phase II expansion project. The Kirby Hills Phase II expansion project provides approximately 100,000 MMcf/day of additional injection capability and 200,000 MMcf/day of additional withdrawal capability at Lodi Gas’ natural gas storage facility.
     The Natural Gas Storage segment’s operations are designed for overall high deliverability natural gas storage service and have a proven track record of safe and reliable operations. This segment is regulated by the California Public Utilities Commission. All services have been, and will continue to be, contracted under the Natural Gas Storage segment’s published California Public Utilities Commission tariff.

12


Table of Contents

     The Natural Gas Storage segment’s revenues consist of lease revenues and hub services revenues. Lease revenues are charges for the reservation of storage space for natural gas. Generally customers inject natural gas in the fall and spring and withdraw it for winter and summer use. Title to the stored gas remains with the customer. Hub services revenues consist of a variety of other storage services under interruptible storage agreements. The Natural Gas Storage segment does not trade or market natural gas.
   Energy Services Segment
     In February 2008, we acquired all of the member interests in Farm & Home Oil Company LLC (“Farm & Home”) for approximately $146.2 million. When Farm & Home was acquired, it also had retail operations, but we sold those operations in April 2008. The acquisition of Farm & Home’s wholesale operations provided an opportunity for us to increase the utilization of our existing pipeline and terminal system infrastructure by marketing refined petroleum products in areas served by that infrastructure.
     The Energy Services segment is a wholesale distributor of refined petroleum products in the United States in areas also served by our pipelines and terminals. The segment’s products include gasoline, propane and petroleum distillates such as heating oil, diesel fuel and kerosene. The segment has five terminals with aggregate storage capacity of approximately 1.0 million barrels. Each terminal is equipped with multiple storage tanks and automated truck loading equipment that is available 24 hours a day. We own the property on which the terminals are located.
     The following table sets forth the total gallons of refined petroleum products sold by the Energy Services segment for the periods indicated (in thousands):
                 
    Year Ended December 31,  
    2009     2008  
Sales volumes
    655,100       435,200  
 
           
     The Energy Services segment’s operations are segregated into three separate categories based on the type of fuel delivered and the delivery method:
    Wholesale Rack – liquid fuels and propane gas are delivered to distributors and large commercial customers. These customers take delivery of the products using the Energy Services segment’s automated truck loading equipment to fill their own trucks.
 
    Wholesale Delivered – liquid fuels are delivered to commercial customers, construction companies, school districts, and trucking companies using third-party carriers.
 
    Branded Gasoline – the Energy Services segment delivers, through third-party carriers, gasoline and on-highway diesel fuel to independently owned retail gas stations under many leading gasoline brands.
     Since the operations of the Energy Services segment exposes us to commodity price risk, the Energy Services segment enters into derivative instruments to mitigate the effect of commodity price fluctuations on the segment’s inventory and fixed-priced sales contracts. The fair value of our derivative instruments is recorded in our consolidated balance sheet, with the change in fair value recorded in earnings. The derivative instruments the Energy Services segment uses consist primarily of futures contracts traded on the New York Mercantile Exchange (“NYMEX”) for the purposes of hedging the outright price risk of its physical inventory and fixed-priced sales contracts. However, hedge accounting has not been used for all of the Energy Services segment’s derivative instruments. In the cases in which hedge accounting has not been used, changes in the fair values of the derivative instrument, which are included in cost of product sales, generally are offset by changes in the values of the fixed-priced sales contracts which are also derivative instruments whose changes in value are recognized in product sales. The Energy Services segment records revenues when products are delivered.

13


Table of Contents

Development and Logistics Segment
     The Development and Logistics segment consists primarily of terminal and pipeline operations and maintenance services and related construction services for third parties. The Development and Logistics segment is a contract operator of pipelines and terminals primarily located in Texas and Louisiana that are owned by major oil and gas, petrochemical and chemical companies. At December 31, 2009, our Development and Logistics segment had performance obligations under existing multi-year arrangements to operate and maintain approximately 2,400 miles of pipeline. Further, this segment owns an approximate 23-mile pipeline located in Texas and leases a portion of the pipeline to a third-party chemical company. The Development and Logistics segment also owns an approximately 63% interest in a crude butadiene pipeline between Deer Park, Texas and Port Arthur, Texas and owns and operates an ammonia pipeline located in Texas. In addition, the Development and Logistics segment provides engineering and construction management services to major chemical companies in the Gulf Coast area.
     We plan to continue the third-party contract operation and maintenance business in this segment, but we also intend to grow our footprint and asset capabilities through this segment by leveraging our project development capabilities, commercial management and operational competency and focusing on expanding outside our existing service area of pipeline and terminal assets through the provision of comprehensive project development services, including idea origination, securing necessary funding for the project, construction of the assets, and operations and commercial management following the project’s completion.
Competition and Customers
Competitive Strengths
     Buckeye believes that it has the following competitive strengths:
    Buckeye operates in a safe and environmentally responsible manner;
 
    Buckeye owns and operates high quality assets that are strategically located;
 
    Buckeye has stable, long-term relationships with its customers;
 
    Buckeye owns relatively predictable and stable fee-based businesses with opportunistic revenue generating capabilities;
 
    Buckeye maintains a conservative financial position with its investment-grade credit rating; and
 
    Buckeye has an experienced management team whose interests are aligned with those of its unitholders.
Pipeline Operations and Terminalling and Storage Segments
     Generally, pipelines are the lowest cost method for long-haul overland movement of refined petroleum products. Therefore, the Pipeline Operations segment’s most significant competitors for large volume shipments are other pipelines, some of which are owned or controlled by major integrated oil companies. Although it is unlikely that a pipeline system comparable in size and scope to the Pipeline Operations segment’s pipeline systems 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 Pipeline Operations segment in particular locations.
     The Pipeline Operations segment competes with marine transportation in some areas. Tankers and barges on the Great Lakes account for some of the volume to certain Michigan, Ohio and upstate New York locations during the approximately eight non-winter months of the year. Barges are presently a competitive factor for deliveries to the New York City area, the Pittsburgh area, Connecticut and locations on the Ohio River such as Mt. Vernon, Indiana and Cincinnati, Ohio and locations on the Mississippi River such as St. Louis, Missouri.
     Trucks competitively deliver refined petroleum products in a number of areas that the Pipeline Operations segment serves. While their costs may not be competitive for longer hauls or large volume shipments, trucks compete effectively for smaller volumes in many local areas. The availability of truck transportation places a significant competitive constraint on the ability of the Pipeline Operations segment to increase its tariff rates.

14


Table of Contents

     Privately arranged exchanges of refined petroleum products between marketers in different locations are another form of competition. Generally, such exchanges reduce both parties’ costs by eliminating or reducing transportation charges. In addition, consolidation among refiners and marketers that has accelerated in recent years has altered distribution patterns, reducing demand for transportation services in some markets and increasing them in other markets.
     The production and use of biofuels may be a competitive factor in that, to the extent the usage of biofuels increases, some alternative means of transport that compete with our pipelines may be able to provide transportation services for biofuels that our pipelines cannot because of safety or pipeline integrity issues. In particular, railroads, competitively deliver biofuels to a number of areas and, therefore are a significant competitor of pipelines with respect to biofuels. Biofuel usage may also create opportunities for additional pipeline transportation, if such biofuels can be transported on our pipeline, and additional blending opportunities within our Terminalling and Storage segment, although that potential cannot be quantified at present.
     Distribution of refined petroleum products depends to a large extent upon the location and capacity of refineries. However, because the Pipeline Operations segment’s business is largely driven by the consumption of fuel in its delivery areas and the Pipeline Operations’ pipelines have numerous source points, we do 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 Pipeline Operations segment. As discussed in “Item 1A. Risk Factors” below, however, a significant decline in production at the ConocoPhillips Wood River refinery, Valero Paulsboro refinery or Husky Lima refinery could materially impact the business of the Pipeline Operations segment.
     Many of the general competitive factors discussed above, such as demand for refined petroleum products and competitive threats from methods of transportation other than pipelines, also impacts our Terminalling and Storage segment. The Terminalling and Storage segment generally competes with other terminals in the same geographic market. Many competitive terminals are owned by major integrated oil companies. These major oil companies may have the opportunity for product exchanges that are not available to the Terminalling and Storage segment’s terminals. While the Terminalling and Storage segment’s terminal throughput fees are not regulated, they are subject to price competition from competitive terminals and alternate modes of transporting refined petroleum products to end users such as retail gas stations.
Natural Gas Storage Segment
     The Natural Gas Storage segment competes with other storage providers, including local distribution companies (“LDCs”), utilities and affiliates of LDCs and other independent utilities in the northern California natural gas storage market. Certain major pipeline companies have existing storage facilities connected to their systems that compete with the Natural Gas Storage segment’s facilities. Ongoing and proposed third-party construction of new capacity in northern California could have an adverse impact on the Natural Gas Storage segment’s competitive position.
Energy Services Segment
     The Energy Services segment competes with pipeline companies, the major integrated oil companies, their marketing affiliates and independent gatherers, investment banks that have established a trading platform, and brokers and marketers of widely varying sizes, financial resources and experience. Some of these competitors have capital resources greater than the Energy Services segment, and control greater supplies of refined petroleum products.
Development and Logistics
     The Development and Logistics segment competes with independent pipeline companies, engineering firms, major integrated oil companies and chemical companies to operate and maintain logistic assets for third-party owners. In addition, in many instances it is more cost-effective for certain companies to operate and maintain their own pipelines as opposed to contracting with the Development and Logistics segment to complete these tasks. Numerous engineering and construction firms compete with the Development and Logistics segment for construction management business.

15


Table of Contents

Customers
     For the years ended December 31, 2009 and 2008, no customer contributed more than 10% of our consolidated revenue. In 2007, Shell Oil Products U.S. (“Shell”) contributed 10% of our consolidated revenue. Approximately 3% of 2007 consolidated revenue was generated by Shell in the Pipeline Operations segment, and the remaining 7% of consolidated revenue generated by Shell was in the Terminalling and Storage segment.
Seasonality
     The Pipeline Operations and Terminalling and Storage segments’ mix and volume of products transported and stored 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, these segments have been only moderately seasonal, with somewhat lower than average volumes being transported and stored during March, April and May and somewhat higher than average volumes being transported and stored in November, December and January.
     The Natural Gas Storage segment typically has two injection and two withdrawal seasons during the year. Our natural gas storage facility is normally at capacity prior to the summer cooling season and prior to the winter heating season. Since our customers pay a demand fee, they are generally incentivized to maximize their use of the storage facility throughout the year.
     The Energy Services segment’s mix and volume of product sales tends to vary seasonally, with the fourth and first quarter volumes generally being higher than the second and third quarters, primarily due to the increased demand for home heating oil in the winter months.
Employees
     At December 31, 2009, BGH did not have any employees. Except as noted below, Buckeye and its Operating Subsidiaries are managed and operated by employees of Buckeye Pipe Line Services Company, a Pennsylvania corporation (“Services Company”), which is a consolidated affiliate of ours. At December 31, 2009, Services Company had approximately 846 full-time employees, 162 of whom were represented by two labor unions. Approximately 18 people are employed directly by Lodi Gas and 15 people are employed directly by a subsidiary of BPH. Services Company is reimbursed by the Operating Subsidiaries for the cost of providing those employee services pursuant to a services agreement. Buckeye and its Operating Subsidiaries have never experienced any work stoppages or other significant labor problems.
Capital Expenditures
     We make capital expenditures in order to maintain and enhance the safety and integrity of our pipelines, terminals, storage facilities and related assets, to expand the reach or capacity of those assets, to improve the efficiency of our operations and to pursue new business opportunities. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”
     During 2009, we spent approximately $87.3 million for capital expenditures, of which $23.5 million related to sustaining capital projects and $63.8 million related to expansion and cost reduction projects.
     We expect to spend approximately $90.0 million to $110.0 million for capital expenditures in 2010, of which approximately $25.0 million to $35.0 million is expected to relate to sustaining capital expenditures and $65.0 million to $75.0 million is expected to relate to expansion and cost reduction projects. Sustaining capital expenditures include renewals and replacement of pipeline sections, tank floors and tank roofs and upgrades to station and terminalling equipment, field instrumentation and cathodic protection systems. Major expansion and cost reduction expenditures in 2010 will include the completion of additional product storage tanks in the Midwest, the construction of a 4.4 mile pipeline in central Connecticut to connect our pipeline in Connecticut to a third-party electric generation plant currently under construction, various terminal expansions and upgrades and pipeline and terminal automation projects.

16


Table of Contents

Regulation
General
     We are subject to extensive laws and regulations as well as regulatory oversight by numerous federal, state and local departments and agencies, many of which are authorized by statute to issue rules and regulations binding on the pipeline industry, related businesses and individual participants. In some states, we are subject to the jurisdiction of public utility commissions, which have authority over, among other things, intrastate tariffs, the issuance of debt and equity securities, transfers of assets and safety. The failure to comply with such laws and regulations can result in substantial penalties. The regulatory burden on our operations increases our cost of doing business and, consequently, affects our profitability. However, except for certain exemptions that apply to smaller companies, we do not believe that we are affected in a significantly different manner by these laws and regulations than are our competitors.
     Following is a discussion of certain laws and regulations affecting us. However, you should not rely on such discussion as an exhaustive review of all regulatory considerations affecting our operations.
Rate Regulation
     Buckeye Pipe Line, Wood River, BPL Transportation and NORCO operate pipelines subject to the regulatory jurisdiction of the Federal Energy Regulatory Commission (“FERC”) under the Interstate Commerce Act and the Department of Energy Organization Act. FERC regulations require that interstate oil pipeline rates be posted publicly and that these rates be “just and reasonable” and not unduly discriminatory. FERC regulations also enforce common carrier obligations and specify a uniform system of accounts, among certain other obligations.
     The generic oil pipeline regulations issued under the Energy Policy Act of 1992 rely primarily on an index methodology that allows a pipeline to change its rates in accordance with an index (currently the change in the Producer Price Index (“PPI”) plus 1.3%) that FERC believes reflects cost changes appropriate for application to pipeline rates. Under FERC’s rules, as one 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. FERC is expected to reexamine the manner in which the index is calculated in 2010 as part of its regular five-year review.
     The tariff rates of Wood River, BPL Transportation and NORCO are governed by the generic FERC index methodology, and therefore are subject to change annually according to the index. If PPI + 1.3% is negative in a future period, then Wood River, BPL Transportation and NORCO could be required to reduce their rates if they exceed the new maximum allowable rate. For comparison, at December 31, 2009, the PPI + 1.3% for 2009 was estimated to be —1.24% based on preliminary data. Shippers may also file complaints against indexed rates as being unjust and unreasonable, subject to the FERC’s standards.
     Buckeye Pipe Line’s rates are governed by an exception to the rules discussed above, pursuant to specific FERC authorization. Buckeye Pipe Line’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 Pipe Line 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, 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 Pipe Line 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 Pipe Line 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 Pipe Line does not have significant market power must be accompanied by a corresponding decrease in all of Buckeye Pipe Line’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

17


Table of Contents

the market-based rate regulation program, that the proposed rates are unduly discriminatory, or that Buckeye Pipe Line has acquired significant market power in markets previously found to be competitive.
     The Buckeye Pipe Line 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 Pipe Line’s program. We cannot predict the impact that any change to Buckeye Pipe Line’s rate program would have on Buckeye Pipe Line’s operations. Independent of regulatory considerations, it is expected that tariff rates will continue to be constrained by competition and other market factors.
     Laurel operates a pipeline in intrastate service across Pennsylvania, and its tariff rates are regulated by the Pennsylvania Public Utility Commission. Wood River operates a pipeline in intrastate service in Illinois, and tariff rates related to this pipeline are regulated by the Illinois Commerce Commission.
     Lodi Gas owns and operates a natural gas storage facility in northern California under a Certificate of Public Convenience and Necessity originally granted by the California Public Utilities Commission (“CPUC”) in 2000 and expanded in 2006, 2008 and 2009. Under the Hinshaw exemption to the Natural Gas Act, Lodi Gas is not subject to FERC rate regulation, but is regulated by the CPUC and other state and local agencies in California. Consistent with California regulatory policy, however, Lodi Gas is authorized to charge market-based rates and is not otherwise subject to rate regulation.
Environmental Regulation
     We are subject to federal, state and local laws and regulations relating to the protection of the environment. Although we believe that our operations comply in all material respects with applicable environmental laws and regulations, risks of substantial liabilities are inherent in pipeline operations, and we cannot assure you that material environmental liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly rigorous environmental laws, regulations and enforcement policies, and claims for damages to property or injuries to persons resulting from our operations, could result in substantial costs and liabilities to us. See “Legal Proceedings.”
     The Oil Pollution Act of 1990 (“OPA”) amended certain provisions of the federal Water Pollution Control Act of 1972, commonly referred to as the Clean Water Act (“CWA”), and other statutes, as they pertain to the prevention of and response to petroleum product spills into navigable waters. The OPA subjects owners of facilities to strict joint and several liability for all containment and clean-up costs and certain other damages arising from a spill. The CWA provides penalties for the discharge of petroleum products in reportable quantities and imposes substantial liability for the costs of removing a spill. State laws for the control of water pollution also provide varying civil and criminal penalties and liabilities in the case of releases of petroleum or its derivatives into surface waters or into the ground.
     Contamination resulting from spills or releases of refined petroleum products sometimes occurs in the petroleum pipeline industry. Our pipelines cross numerous navigable rivers and streams. Although we believe that we 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 us.
     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.” Hazardous wastes are subject to more rigorous and costly disposal requirements than are non-hazardous wastes. Any changes in the regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses.

18


Table of Contents

     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 joint and several 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 us or our predecessors may have been released or disposed of in the past, we may in the future be required to remediate contaminated property. Governmental authorities such as the Environmental Protection Agency (“EPA”), and in some instances third parties, are authorized under CERCLA to seek to recover remediation and other costs from responsible persons, without regard to fault or the legality of the original disposal. In addition to our potential liability as a generator of a “hazardous substance,” our property or right-of-way may be adjacent to or in the immediate vicinity of Superfund and other hazardous waste sites. Accordingly, we may be responsible under CERCLA for all or part of the costs required to cleanup such sites which 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 to comply with new federal programs. Existing operating and air-emission requirements like those currently imposed on us are being reviewed by appropriate state agencies in connection with the new facility-wide permitting program. It is possible that new or more stringent controls will be imposed on us through this program.
     We are also subject to environmental laws and regulations adopted by the various states in which we 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 we operate are subject to regulation by the U.S. Department of Transportation (“DOT”) and its agency, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), under the Hazardous Liquid Pipeline Safety Act of 1979 (“HLPSA”), which governs the design, installation, testing, construction, operation, replacement and management of pipeline facilities. HLPSA covers petroleum and petroleum products pipelines and requires any entity that owns or operates pipeline facilities to comply with applicable safety standards, to establish and maintain a plan of inspection and maintenance and to comply with such plans.
     The Pipeline Safety Reauthorization Act of 1988 requires coordination of safety regulation between federal and state agencies, testing and certification of pipeline personnel, and authorization of safety-related feasibility studies. We have 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. We filed our written plan and have qualified our employees and contractors as required and requalified the employees under our plan again in 2005, and we have since implemented a formalized requalification program. 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,

19


Table of Contents

2008. Pipeline operators are now required to re-assess each affected segment in intervals not to exceed five years. We have 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 DOT. 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. We implemented a public education program that complies with these requirements and the requirements of the American Petroleum Institute Recommended Practice 1162.
     The Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (“PIPES Act”), which became effective on December 24, 2006, among other things, reauthorized HLPSA, strengthened damage prevention measures designed to protect pipelines from excavation damage, removed the exemption from regulation of pipelines operating at less than 20% of maximum yield strength in rural areas, and required pipeline operators to manage human factors in pipeline control centers, including controller fatigue. While the PIPES Act imposed additional operating requirements on pipeline operators, we do not believe that the costs of compliance with the PIPES Act are material, because many of the new requirements are already satisfied by our existing programs.
     Our natural gas storage operations are also subject to regulation by the DOT under the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”) as subsequently amended, which required the Secretary of Transportation to implement regulations imposing safety and reporting obligations.
     We believe that we currently comply in all material respects with HLPSA, the PSIA, the PIPES Act, the NGPSA and other pipeline safety laws and regulations. However, the industry, including us, will incur additional pipeline and tank integrity expenditures in the future, and we are likely to incur increased operating costs based on these and other government regulations.
     We are also subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes. We believe that our operations comply in all material respects with OSHA requirements, including general industry standards, record-keeping and the training and monitoring of occupational exposures.
     We 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 we do not presently expect that such costs or capital expenditure requirements would have a material adverse effect on our results of operations or financial condition.
Tax Considerations for Unitholders
     This section is a summary of material tax considerations that may be relevant to our Unitholders. It is based upon the Internal Revenue Code of 1986, as amended (the “Code”), regulations promulgated thereunder and current administrative rulings and court decisions, all of which are subject to change. Subsequent changes in such authorities may cause the tax consequences to vary substantially from the consequences described below.
     No attempt has been made in the following discussion to comment on all federal income tax matters affecting us or our 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 (“IRAs”), 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 COMMON UNITS.

20


Table of Contents

Characterization of BGH 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 our items of income, gain, loss and deduction in computing their federal income tax liability, regardless of whether cash 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 Internal Revenue Service (“IRS”) may disregard such an agreement in certain instances and re-determine the tax consequences of partnership operations to the partners.
     Section 7704 of the Code provides that publicly traded partnerships (such as us) will, as a general rule, be taxed as corporations. However, an exception to this rule exists with respect to any publicly traded partnerships of which 90% or more of its gross income for each taxable year consists of “qualifying income” (the “Qualifying Income Exception”). Qualifying income includes interest (other than interest generated by a financial or insurance business), 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)..., or the transportation or storage of [ethanol]...,” and gain from the sale or disposition of capital assets that produce such income.
     Buckeye is engaged primarily in the refined petroleum products transportation, storage and marketing businesses and natural gas storage business. We believe that at least 90% or more of Buckeye’s current gross income constitutes, and has constituted, qualifying income and, accordingly, that Buckeye will continue to be classified as a partnership and not as a corporation for federal income tax purposes. Our only cash generating asset is our ownership interest in Buckeye GP, which owns general partner interests and incentive distributions rights in Buckeye and general partner interests in certain of Buckeye’s Operating Subsidiaries. We believe that at least 90% or more of our current gross income constitutes, and has constituted, qualifying income and, accordingly, that we will continue to be classified as a partnership and not as a corporation for federal income tax purposes.
     If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to our Unitholders in liquidation of their interests in us. This contribution and liquidation should be tax-free to Unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.
     If we were taxed as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our Unitholders, and our net income would be taxed to us at corporate rates. Moreover, if Buckeye were taxed as a corporation, losses recognized by Buckeye would not flow through to us and losses we recognized would not flow through to our Unitholders. In addition, any distribution we made to a Unitholder (or by Buckeye to us) would be treated as either taxable dividend income, to the extent of current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the Unitholder’s tax basis in his units, or taxable capital gain, after the Unitholder’s tax basis in his units is reduced to zero. Accordingly, taxation of either us or Buckeye as a corporation would result in a material reduction in a Unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction in the value of the Common Units.
Flow-Through of Taxable Income
     We will not pay any federal income tax. Instead, each Unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether corresponding cash distributions are received by him. Consequently, we may allocate income to a Unitholder even if he has not received a cash distribution. Each Unitholder will be required to include in income his allocable share of our

21


Table of Contents

income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.
Potential U.S. Tax Legislation Change
     In response to recent public offerings of interests in the management operations of private equity funds and hedge funds, members of Congress have considered substantive changes to the definition of qualifying income under Section 7704(d) of the Code and changing the characterization of certain types of income received from partnerships. In particular, one proposal would have recharacterized certain income and gain received with respect to “investment services partnership interests” as ordinary income for the performance of services, which may not be treated as qualifying income for publicly traded partnerships. As such proposal is currently interpreted, a significant portion of our interests in Buckeye may be viewed as an investment services partnership interest; however, the proposal would not affect the qualifying nature of our income. Although MainLine Management is unable to predict whether the recently considered legislation, or any other proposals, will ultimately be enacted, the enactment of any such legislation could negatively impact the value of our Common Units.
Treatment of Our Distributions
     Our distributions generally will not be taxable to a Unitholder for federal income tax purposes to the extent that the distributions do not exceed the tax basis of a Unitholder’s Common Units immediately before the distribution. Our cash distributions in excess of a Unitholder’s tax basis generally will be considered to be a gain from the sale or exchange of the Common Units. Any reduction in a Unitholder’s share of our liabilities for which no partner, including MainLine Management, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution of cash to that Unitholder. To the extent our distributions cause a Unitholder’s “at risk” amount to be less than zero at the end of any taxable year, the Unitholder must recapture any losses deducted in previous years.
     A decrease in a Unitholder’s percentage interest in us because of our issuance of additional Common Units will decrease such Unitholder’s share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. This deemed distribution may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a Unitholder, regardless of his tax basis in his Common Units, if the distribution reduces the Unitholder’s share of our “unrealized receivables,” including depreciation recapture, and/or substantially appreciated “inventory items,” both as defined in the Code, and collectively, “Section 751 Assets.” To that extent, the Unitholder will be treated as having been distributed his proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the Unitholder’s realization of ordinary income, which will equal the excess of (1) the non-pro rata portion of that distribution over (2) the Unitholder’s tax basis for the share of Section 751 Assets deemed relinquished in the exchange.
Basis of Common Units
     A Unitholder will have an initial tax basis for its Common Units equal to the amount paid for the Common Units plus its share of our liabilities. A Unitholder’s tax basis will be increased by his share of our income and by any increase in his share of our liabilities. A Unitholder’s basis will be decreased, but not below zero, by its share of our distributions, by its share of our losses, by any decrease in its share of our liabilities and by its share of our expenditures that are not deductible in computing our taxable income and are not required to be capitalized.
Loss Limitations
     The deduction by a Unitholder of his share of our losses will be limited to the tax basis in his Common Units and, in the case of an individual Unitholder or a corporate Unitholder, if more than 50% of the value of the corporate Unitholder’s stock is owned directly or indirectly by five or fewer individuals or some tax-exempt organizations, to the amount for which the Unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A Unitholder must recapture losses deducted in previous years to the extent that distributions cause his 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 as a deduction to the extent that his at-risk

22


Table of Contents

amount is subsequently increased, provided such losses do not exceed such Unitholder’s tax basis in his Common Units. Upon the taxable disposition of a Common 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. Any excess loss above that gain previously suspended by the at risk or basis limitations is no longer utilizable.
     In general, a Unitholder will be at risk to the extent of the tax basis of his Common Units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money he borrows to acquire or hold his Common Units, if the lender of those borrowed funds owns an interest in us, is related to the Unitholder or can look only to the Common Units for repayment. A Unitholder’s at risk amount will increase or decrease as the tax basis of the Unitholder’s Common Units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.
     The passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally corporate or partnership activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. However, the application of the passive loss limitations to tiered publicly traded partnerships is uncertain. We will take the position that any passive losses we generate that are reasonably allocable to our investment in Buckeye will only be available to offset our passive income generated in the future that is reasonably allocable to our investment in Buckeye and will not be available to offset income from other passive activities or investments, including other investments in private businesses or investments we may make in other publicly traded partnerships, such as Buckeye, or salary or active business income. Further, a Unitholder’s share of our net income may be offset by any suspended passive losses from the Unitholder’s investment in us, but may not be offset by the Unitholder’s current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships. Passive losses that are not deductible because they exceed a Unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party.
     The IRS could take the position that for purposes of applying the passive loss limitation rules to tiered publicly traded partnerships, such as Buckeye and us, the related entities are treated as one publicly traded partnership. In that case, any passive losses we generate would be available to offset income from a Unitholder’s investment in Buckeye. However, passive losses that are not deductible because they exceed a Unitholder’s share of income we generate would not be deductible in full until a Unitholder disposes of his entire investment in both us and Buckeye in a fully taxable transaction with an unrelated party.
     The passive loss rules are applied after other applicable limitations on deductions, including 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.” Investment interest expense includes:
    interest on indebtedness properly allocable to property held for investment;
 
    our interest expense attributed to portfolio income; and
 
    the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.
     The computation of a Unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. The IRS has indicated that net

23


Table of Contents

passive income earned by a publicly traded partnership will be treated as investment income to its Unitholders. In addition, the Unitholder’s share of our portfolio income will be treated as investment income.
Entity Level Collections
     If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any Unitholder or our general partner or any former Unitholder, we are authorized to pay those taxes from our funds. That 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, we are authorized to treat the payment as a distribution to all current Unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of the Common Units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual Unitholder in which event the Unitholder would be required to file a claim in order to obtain a credit or refund.
Allocation of Income, Gain, Loss and Deduction
     In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our Unitholders in accordance with their percentage interests in us. If we have a net loss for the entire year, that loss will be allocated first to the Unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to our general partner MainLine Management.
     Specified items of our income, gain, loss and deduction will be allocated to account for the difference between the tax basis and fair market value of our assets at the time of the initial offering of our Common Units, referred to in this discussion as “Contributed Property.” The effect of these allocations to a Unitholder purchasing Common Units will be essentially the same as if the tax basis of our assets were equal to their fair market value at the time of the initial offering of the Common Units. In addition, items of recapture income will be allocated to the extent possible to the partner who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some Unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner to eliminate the negative balance as quickly as possible.
     An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Code to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a Unitholder’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:
    his relative contributions to us;
 
    the interests of all the Unitholders in profits and losses;
 
    the interest of all the Unitholders in cash flow; and
 
    the rights of all the Unitholders to distributions of capital upon liquidation.
Treatment of Short Sales
     A Unitholder whose Common Units are loaned to a “short seller” to cover a short sale of Common Units may be considered as having disposed of those Common Units. If so, the Unitholder would no longer be treated for tax purposes as a partner for those Common Units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:
    any of our income, gain, loss or deduction with respect to those units would not be reportable by the Unitholder;

24


Table of Contents

    any cash distributions received by the Unitholder as to those Common Units would be fully taxable; and
    all of these distributions would appear to be ordinary income.
     Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their Common Units.
Alternative Minimum Tax
     Each Unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.
Tax Rates
     In general, the highest effective United States federal income tax rate for an individual is currently 35% (such rate to be increased to 39.6% for taxable years beginning after December 31, 2010) and the maximum United States federal income tax rate for net capital gains of an individual is currently 15% (such rate to be increased to 20% for taxable years beginning after December 31, 2010) if the asset disposed of was held for more than 12 months at the time of disposition.
Section 754 Election
     We have made the election permitted by Section 754 of the Code. This election is irrevocable without the consent of the IRS. The election will generally permit us to adjust a Common Unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Code to reflect his purchase price. This election does not apply to a person who purchases Common Units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other Unitholders. For purposes of this discussion, a Unitholder’s inside basis in our assets will be considered to have two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.
     A Section 754 election is advantageous if the transferee’s tax basis in his Common Units is higher than the Common Units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation and depletion deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his Common Units is lower than those Common Units’ share of the aggregate tax basis of our assets immediately prior to the transfer. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property that has a substantial basis reduction. Generally a built-in loss or a basis reduction is substantial if it exceeds $250,000.
     The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. There is no assurance that the determinations we made will prevail if challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether.
Accounting Method and Taxable Year
     We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each Unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with the Unitholder’s taxable year. In addition, a Unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his Common Units following the close of our taxable year but before the close of the Unitholder’s taxable year must include his share of our

25


Table of Contents

income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction.
Tax Treatment of Operations
     We use the adjusted tax basis of our various assets for purposes of computing depreciation and cost recovery deductions and gain or loss on any disposition of such assets. If we or Buckeye 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 selling our Common Units (i.e., syndication expenses) must be capitalized and cannot be deducted by us currently, ratably or upon our 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.
Valuation of Properties
     The federal income tax consequences of the ownership and disposition of Common Units will depend in part on our estimates of the relative fair market values, and the initial tax basis, of our and Buckeye’s assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later 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 and incur interest and penalties with respect to those adjustments.
Disposition of Common Units
     A Unitholder will recognize gain or loss on a sale of Common Units equal to the difference between the amount realized and the Unitholder’s tax basis in the Common Units sold. A Unitholder’s amount realized will be measured by the sum of the cash and the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a Unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of Common Units could result in a tax liability in excess of any cash received from the sale.
     Prior distributions from us in excess of cumulative net taxable income for a Common Unit that decreased a Unitholder’s tax basis in that Common Unit will, in effect, become taxable income if the Common Unit is sold at a price greater than the Unitholder’s tax basis in that Common Unit, even if the price received is less than the Unitholder’s original cost.
     Except as noted below, gain or loss recognized by a Unitholder, other than a “dealer” in Common Units, on the sale or exchange of a Common Unit held for more than one year will generally be taxable as capital gain or loss. Capital gain recognized by an individual Unitholder on the sale of Common Units held for more than 12 months will generally be taxed at a maximum rate of 15% (such rate to be increased to 20% for taxable years beginning after December 31, 2010). However, a portion of this gain or loss will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” of us or Buckeye. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a Common Unit and may be recognized even if there is a net taxable loss realized on the sale of a Common Unit. Thus, a Unitholder may recognize both ordinary income and a capital loss upon a sale of Common Units. Net capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains 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 for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method. Treasury Regulations under Section 1223 of the Code allow a selling Unitholder who can

26


Table of Contents

identify Common Units transferred with an ascertainable holding period to elect to use the actual holding period of the Common Units transferred. Thus, according to the ruling, a Unitholder will be unable to select high or low basis Common Units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, may designate specific Common Units sold for purposes of determining the holding period of units transferred. A Unitholder electing to use the actual holding period of Common Units transferred must consistently use that identification method for all subsequent sales or exchanges of Common Units. A Unitholder considering the purchase of additional Common Units or a sale of Common Units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.
     Specific provisions of the Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:
    a short sale;
 
    an offsetting notional principal contract; or
 
    a futures or forward contract with respect to the partnership interest or substantially identical property.
     Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.
Allocations Between Transferors and Transferee
     In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the Unitholders in proportion to the number of Common Units owned by each of them as of the opening of the applicable exchange on the first business day of the month (the “Allocation Date”). However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the Unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a Unitholder transferring Common Units may be allocated income, gain, loss and deduction realized after the date of transfer.
     Although simplifying conventions are contemplated by the Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations. Recently, the Department of Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Existing publicly traded partnerships are entitled to rely on those proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the Unitholder’s interest, our taxable income or losses might be reallocated among the Unitholders. We are authorized to revise our method of allocation between Unitholders, as well as Unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.
     A Unitholder who owns Common Units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.
Notification Requirements
     A Unitholder who sells any of its Common Units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of such Common Units who purchases the Common Units from another Unitholder is also generally required to notify us in writing of that

27


Table of Contents

purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker who will satisfy such requirements.
Constructive Termination
     We will be considered terminated if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of measuring whether the 50% threshold is reached, multiple sales of the same interest are counted only once. Any such termination would result in the closing of our taxable year for all Unitholders. In the case of a Unitholder reporting on a taxable year that does not end with our 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 us, including a new election under Section 754 of the 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 we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted prior to the termination. The IRS has recently announced a publicly traded partnership technical termination relief program whereby, if the taxpayer requests relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.
Withholding
     If we were required or elected under applicable law to pay any federal, state or local income tax on behalf of any Unitholder, we are authorized to pay those taxes from our 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, we are authorized to treat the payment as a distribution to a current Unitholder.
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. MainLine Management believes that substantially all of our 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 our deductions directly connected with carrying on such unrelated trade or business are allowed in computing the entity’s taxable unrelated business income. ACCORDINGLY, TAX-EXEMPT ENTITIES SUCH AS INDIVIDUAL RETIREMENT ACCOUNTS, PENSION PLANS AND CHARITABLE TRUSTS ARE ENCOURAGED TO CONSULT THEIR PROFESSIONAL TAX ADVISORS REGARDING THE TAX IMPLICATIONS OF THEIR OWNERSHIP OF COMMON UNITS.
Foreign Unitholders
     Non-resident aliens and foreign corporations, trusts or estates that own Common Units will be considered to be engaged in business in the United States on account of the ownership of Common Units. As a consequence, they will be required to file U.S. federal tax returns to report their share of our income, gain, loss or deduction and pay U.S. federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, we withhold at the highest applicable effective tax rate from cash distributions made quarterly to foreign Unitholders. Each foreign Unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

28


Table of Contents

     In addition, because a foreign corporation that owns Common Units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” which are effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate Unitholder is a “qualified resident.” In addition, this type of Unitholder is subject to special information reporting requirements under Section 6038C of the Code.
     In a published ruling, the IRS has taken the position that gain realized by a foreign partner who sells or otherwise disposes of a limited partner unit will be treated as effectively connected with a United States trade or business of the foreign partner, and thus subject to federal income tax, to the extent that such gain is attributable to appreciated personal property used by the limited partnership in a United States trade or business. Moreover, a foreign partner is subject to federal income tax on gain realized on the sale or disposition of a Common 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 our Common Units during the five-year period ending on the date of the sale or disposition, provided the Common 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.” MainLine Management expects that we will meet the definition of a “qualified publicly traded partnership.”
State Tax Treatment
     During 2009, Buckeye owned property or conducted business in the states of California, Colorado, Connecticut, Delaware, Florida, Illinois, Indiana, Kansas, Louisiana, Maryland, Massachusetts, Michigan, Missouri, Nevada, New Jersey, New York, Ohio, Pennsylvania, Tennessee, Texas, Virginia, West Virginia and Wisconsin. 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 we withhold a percentage of income attributable to our 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
     It is the responsibility of each Unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. Accordingly, each Unitholder is urged to consult, and depend upon, his tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each Unitholder to file all state, local and foreign, as well as United States federal tax returns, that may be required of him.
Available Information
     We file annual, quarterly and current reports and other documents with the SEC under the Securities Exchange Act of 1934 (“the Exchange Act”). The public can obtain any documents that we file with the SEC at www.sec.gov. We also make available free of charge our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after filing such materials with, or furnishing such materials to, the SEC, on or through our Internet website, www.buckeyegp.com. We are not including the information contained on our website as a part of, or incorporating it by reference into, this Report.
     You can also find information about us at the offices of the NYSE, 20 Broad Street, New York, New York 10005 or at the NYSE’s Internet website, www.nyse.com.
Item 1A. Risk Factors
     There are many factors that may affect us and our investments. Security holders and potential investors in our securities should carefully consider the risk factors set forth below, as well as the discussion of other factors that could affect us or our investments included elsewhere in this Report. If one or more of these risks were to materialize, our business, financial position or results of operations could be materially and adversely affected. We are identifying these risk factors as important risk factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.

29


Table of Contents

Risks Inherent in our Dependence on Distributions from Buckeye
     Our primary cash-generating assets are our general partner interests in Buckeye, which consist primarily of general partner units and the incentive distribution rights in Buckeye. Our cash flow is, therefore, directly dependent upon the ability of Buckeye to make cash distributions to its partners.
     The amount of cash that Buckeye can distribute to its partners each quarter, including the amount of incentive distributions, principally depends upon the amount of cash Buckeye generates from its operations, which will fluctuate from quarter to quarter based on, among other things:
    fluctuations in prices for refined petroleum and natural gas products and overall demand for such products in the United States in general, and in Buckeye’s service areas in particular (economic activity, weather, alternative energy sources, conservation and technological advances may affect petroleum product prices and demand);
 
    changes in laws and regulations, including environmental, safety and tax laws and regulations and the regulation of Buckeye’s tariff rates;
 
    liability for environmental claims;
 
    availability and cost of insurance on Buckeye’s assets and operations;
 
    shut-downs or cutbacks at major refineries that supply petroleum products transported on Buckeye’s pipelines or stored in Buckeye’s terminals;
 
    deterioration in Buckeye’s labor relations;
 
    construction costs as well as unanticipated capital expenditures and operating expenses to repair or replace Buckeye’s assets;
 
    competitive pressures from other transportation services or alternative fuel sources;
 
    prevailing economic conditions; and
 
    disruptions to the air travel system.
     In addition, the actual amount of cash Buckeye will have available for distribution will depend on other factors, some of which are beyond its control, including:
    the level of capital expenditures it makes;
 
    the availability, if any, and cost of acquisitions;
 
    debt service requirements;
 
    fluctuations in working capital needs;
 
    restrictions on distributions contained in Buckeye’s Credit Facility, underwritten publicly issued notes and the BES Credit Agreement;
 
    Buckeye’s ability to borrow under its Credit Facility and the BES Credit Agreement; and
 
    the amount, if any, of cash reserves established by Buckeye’s general partner, Buckeye GP, in its discretion for the proper conduct of Buckeye’s business.
     Because of these factors, Buckeye may not have sufficient available cash each quarter to continue to pay distributions at the level of its most recent quarterly distribution of $0.9375 per LP Unit, or any other amount. You should also be aware that the amount of cash that Buckeye has available for distribution depends primarily upon its cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, Buckeye may be able to make cash distributions during periods when Buckeye records losses and may not be able to make cash distributions during periods when Buckeye records net income. Please read “Risk Factors—Risks Inherent in Buckeye’s Business” for a discussion of risks affecting Buckeye’s ability to generate cash flow.
     A reduction in Buckeye’s distributions will disproportionately affect the amount of cash distributions to which we are currently entitled.
     Our ownership of the incentive distribution rights in Buckeye entitles us to receive specified percentages of the amount of cash distributions made by Buckeye to its limited partners. Most of the cash we receive from Buckeye is attributable to our ownership of the incentive distribution rights. Accordingly, any reduction in quarterly cash

30


Table of Contents

distributions from Buckeye would have the effect of disproportionately reducing the amount of the distributions that we receive from Buckeye.
     Our right to receive incentive distributions will terminate if Buckeye’s general partner is removed.
     Our right to receive incentive distributions will terminate if Buckeye GP is removed as general partner of Buckeye, effective upon the date of such removal, which could occur upon an 80% vote of Buckeye’s LP Units or a default by BGH on its credit agreement.
     Buckeye may issue additional LP Units or other equity securities, which may increase the risk that Buckeye will not have sufficient available cash to maintain or increase its cash distribution level per LP Unit.
     Because Buckeye distributes to its partners most of the cash generated by its operations, it relies primarily upon external financing sources, including debt and equity issuances, to fund its acquisitions and expansion capital expenditures. Accordingly, Buckeye has wide latitude to issue additional LP Units on terms and conditions established by Buckeye GP. We receive cash distributions from Buckeye and its subsidiary operating partnerships on the general partner interests and incentive distribution rights that we own. Because most of the cash we receive from Buckeye is attributable to our ownership of the incentive distribution rights, payment of distributions on additional LP Units may increase the risk that Buckeye will be unable to maintain or increase its quarterly cash distribution per LP Unit, which in turn may reduce the amount of incentive distributions we receive and the available cash that we have to distribute to our Unitholders.
     In the future, we may not have sufficient cash to maintain the level of our quarterly distributions.
     Because our primary source of operating cash flow consists of cash distributions from Buckeye, the amount of distributions we are able to make to our Unitholders may fluctuate based on the level of distributions Buckeye makes to its partners, including us. Buckeye may not continue to make quarterly distributions at its current level of $0.9375 per LP Unit, or may not distribute any other amount, or increase its quarterly distributions in the future. In addition, while we would expect to increase or decrease distributions to our Unitholders if Buckeye increases or decreases distributions to us, the timing and amount of such changes in our distributions, if any, will not necessarily be comparable to the timing and amount of any changes in distributions made by Buckeye. Factors such as reserves established by the Board of Directors of Mainline Management, our general partner, for our estimated general and administrative expenses of being a public company as well as other operating expenses, reserves to satisfy our debt service requirements, if any, and reserves for future distributions by us may affect the distributions we make to our Unitholders. Prior to making any distributions to our Unitholders, we will reimburse our general partner and its affiliates for all direct and indirect expenses incurred by them on our behalf. Our general partner will determine the amount of these reimbursed expenses. The reimbursement of these expenses, in addition to the other factors listed above, could reduce the amount of available cash that we have to make distributions to our Unitholders.
     Buckeye’s practice of distributing all of its available cash may limit its ability to grow, which could impact distributions to us and the available cash that we have to distribute to our Unitholders.
     Because our primary cash-generating assets are general partner interests in Buckeye, including the incentive distribution rights, our growth will be dependent upon Buckeye’s ability to increase its quarterly cash distributions. Buckeye has historically distributed to its partners most of the cash generated by its operations. As a result, it relies primarily upon external financing sources, including debt and equity issuances, to fund its acquisitions and expansion capital expenditures. Accordingly, to the extent Buckeye is unable to finance growth externally, its ability to grow will be impaired because it distributes substantially all of its available cash. Also, if Buckeye incurs additional indebtedness to finance its growth, the increased interest expense associated with such indebtedness may reduce the amount of available cash that we can distribute to you.
     Restrictions in Buckeye’s Credit Facility could limit its ability to make distributions to us.
     Buckeye’s Credit Facility contains covenants limiting its ability to incur indebtedness, grant liens, engage in transactions with affiliates and make distributions to us. The facility also contains covenants requiring Buckeye to maintain certain financial ratios. Buckeye is prohibited from making any distribution to its unitholders if such

31


Table of Contents

distribution would cause an event of default or otherwise violate a covenant under this facility. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operation—Liquidity and Capital Resources” for more information about Buckeye’s Credit Facility.
Risks Inherent in Buckeye’s Business
     Because we are directly dependent on the distributions we receive from Buckeye, risks to Buckeye’s operations are also risks to us. We have set forth below risks to Buckeye’s business and operations, the occurrence of which could negatively impact Buckeye’s financial performance and decrease the amount of cash it is able to distribute to us.
     Changes in petroleum demand and distribution may adversely affect Buckeye’s business. In addition, the current economic downturn could result in lower demand for a sustained period of time.
     Demand for the services Buckeye provides depends upon the demand for refined petroleum products in the regions it serves and the supply of refined petroleum products in the regions connected to its pipelines. Prevailing economic conditions, refined petroleum product price levels and weather affect the demand for refined petroleum products. Changes in transportation and travel patterns in the areas served by Buckeye’s pipelines also affect the demand for refined petroleum products because a substantial portion of the refined petroleum products transported by its pipelines and throughput at its terminals is ultimately used as fuel for motor vehicles and aircraft. If these factors result in a decline in demand for refined petroleum products, Buckeye’s business would be particularly susceptible to adverse effects because it operates without the benefit of either exclusive franchises from government entities or long-term contracts.
     In addition, in December 2007, Congress enacted the “Energy Independence and Security Act of 2007,” which, among other provisions, mandated annually increasing levels for the use of renewable fuels such as ethanol, which commenced in 2008 and escalates for 15 years, as well as increasing energy efficiency goals, including higher fuel economy standards for motor vehicles, among other steps. These statutory mandates or other similar renewable fuel or energy efficiency statutory mandates enacted by states may have the impact over time of reducing the demand for refined petroleum products in certain markets, particularly with respect to gasoline. Other legislative changes may similarly alter the expected demand and supply projections for refined petroleum products in ways that cannot be predicted.
     Energy conservation, changing sources of supply, structural changes in the oil industry and new energy technologies also could adversely affect our business. Buckeye cannot predict or control the effect of these factors on it.
     Economic conditions worldwide have from time to time contributed to slowdowns in the oil and gas industry, as well as in the specific segments and markets in which Buckeye operates, resulting in reduced supply or demand and increased price competition for its products and services. In addition, economic conditions could result in a loss of customers in Buckeye’s operating segments because their access to the capital necessary to purchase services Buckeye provides is limited. Buckeye’s operating results may also be affected by uncertain or changing economic conditions in certain regions, including the challenges that are currently affecting economic conditions in the entire United States. If global economic and market conditions (including volatility in commodity markets) or economic conditions in the United States remain uncertain or persist, spread or deteriorate further, Buckeye may experience material impacts on its business, financial condition, results of operations or cash flows.
     Competition could adversely affect Buckeye’s operating results.
     Generally, pipelines are the lowest cost method for long-haul overland movement of refined petroleum products. Therefore, Buckeye’s most significant competitors for large volume shipments are other existing pipelines, some of which are owned or controlled by major integrated oil companies. In addition, new pipelines (including pipeline segments that connect with existing pipeline systems) could be built to effectively compete with Buckeye in particular locations.

32


Table of Contents

     Buckeye competes with marine transportation in some areas. Tankers and barges on the Great Lakes account for some of the volume to certain Michigan, Ohio and upstate New York locations during the approximately eight non-winter months of the year. Barges are presently a competitive factor for deliveries to the New York City area, the Pittsburgh area, Connecticut and locations on the Ohio River such as Mt. Vernon, Indiana and Cincinnati, Ohio and locations on the Mississippi River such as St. Louis, Missouri.
     Trucks competitively deliver refined petroleum products in a number of areas that Buckeye serves. 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 Buckeye serves. The availability of truck transportation places a significant competitive constraint on Buckeye’s ability to increase its tariff rates.
     Privately arranged exchanges of refined petroleum products between marketers in different locations are another 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.
     Additionally, Buckeye’s Natural Gas Storage segment competes primarily with other storage facilities and pipelines in the storage of natural gas. Some of Buckeye’s competitors may have greater financial resources. Some of these competitors may expand or construct transportation and storage systems that would create additional competition for the services Buckeye provides to its customers. Increased competition could reduce the volumes of natural gas stored by Buckeye and could adversely affect its ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows.
     Finally, Buckeye’s Energy Services segment buys and sells refined petroleum products in connection with its marketing activities, and must compete with the major integrated oil companies, their marketing affiliates and independent brokers and marketers of widely varying sizes, financial resources and experience. Some of these companies have superior access to capital resources, which could affect Buckeye’s ability to effectively compete with them.
     All of these competitive pressures could have a material adverse effect on Buckeye’s business, financial condition, results of operations and cash flows.
     Mergers among Buckeye’s customers and competitors could result in lower volumes being shipped on its pipelines and stored in its terminals, thereby reducing the amount of cash it generate.
     Mergers between existing customers could provide strong economic incentives for the combined entities to utilize their existing pipeline and terminal systems instead of Buckeye’s. As a result, Buckeye could lose some or all of the volumes and associated revenues from these customers, and Buckeye could experience difficulty in replacing those lost volumes and revenues. Because most of Buckeye’s 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 Buckeye’s ability to meet its financial obligations and pay cash distributions to BGH.
     Buckeye may incur liabilities from assets it has acquired.
     Some of the assets Buckeye has acquired have been used for many years to distribute, store or transport petroleum products. Releases from terminals or along pipeline rights-of-way may have occurred prior to its acquisition. In addition, releases may have occurred in the past that have not yet been discovered, which could require costly future remediation. If a significant release or event occurred in the past and Buckeye is responsible for all or a significant portion of the liability associated with such release or event, it could adversely affect Buckeye’s business financial position, results of operations and cash flows.

33


Table of Contents

     A significant decline in production at certain refineries served by certain of Buckeye’s pipelines and terminals could materially reduce the volume of refined petroleum products it transports and adversely impact its operating results.
     A refinery that Buckeye’s pipelines and terminals service could partially or completely shut down its operations, temporarily or permanently, due to factors such as unscheduled maintenance, catastrophes, labor difficulties, environmental proceedings or other litigation, loss of significant downstream customers; or legislation or regulation that adversely impacts the economics of refinery operations. For example, a significant decline in production at the ConocoPhillips Wood River refinery, Valero Paulsboro refinery or Husky Lima refinery could negatively impact the financial performance of such assets and adversely affect Buckeye’s business financial position, results of operations or cash flows.
     Potential future acquisitions and expansions, if any, may affect Buckeye’s business by substantially increasing the level of its indebtedness and contingent liabilities and increasing the risks of it being unable to effectively integrate these new operations.
     From time to time, Buckeye evaluates and acquires assets and businesses that it believes complement its existing assets and businesses. Acquisitions may require substantial capital or the incurrence of substantial indebtedness. If Buckeye consummates any future acquisitions, its 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, Buckeye may experience unanticipated delays in realizing the benefits of an acquisition or it may be unable to integrate certain assets it acquires as part of a larger acquisition to the extent such assets relate to a business for which Buckeye has no or limited experience. Following an acquisition, Buckeye may discover previously unknown liabilities associated with the acquired business for which Buckeye has no recourse under applicable indemnification provisions.
     Buckeye’s rate structures are subject to regulation and change by the FERC.
     Buckeye Pipe Line, 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. 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 indexing methodology is used to establish rates on the pipelines owned by Wood River, BPL Transportation and NORCO. The indexing method presently allows a pipeline to increase its rates by a percentage equal to the change in the PPI for finished goods plus 1.3%. If the change in PPI plus 1.3% were to be negative and it is anticipated that this will occur in 2010, Buckeye would be required to reduce the rates charged by Wood River, BPL Transportation and NORCO if they exceed the new maximum allowable rate. FERC is expected to reexamine the index in 2010, and it may change the manner in which it calculates the index. In addition, changes in the PPI might not fully reflect actual increases in the costs associated with these pipelines, thus hampering Buckeye’s ability to recover its costs. Shippers may also file complaints against indexed rates as being unjust and unreasonable, subject to the FERC’s cost-of-service standards.
     Buckeye Pipe Line 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 Pipe Line program is an exception to the generic oil pipeline regulations the FERC issued under the Energy Policy Act of 1992. The generic rules rely primarily on the index methodology described above.
     The Buckeye Pipe Line rate program was reevaluated by the FERC in July 2000, and was allowed to continue with no material changes. Buckeye cannot predict the impact, if any, that a change in the FERC’s method of regulating Buckeye Pipe Line would have on its business, financial condition, results of operations or cash flows.

34


Table of Contents

     Climate change legislation or regulations restricting emissions of “greenhouse gases” or setting fuel economy or air quality standards could result in increased operating costs or reduced demand for the refined petroleum products, natural gas and other hydrocarbon products that Buckeye transports, stores or otherwise handles in connection with its business.
     On December 15, 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other “greenhouse gases” endanger human health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act (“CAA”). In late September 2009, the EPA had proposed two sets of CAA regulations in anticipation of finalizing its endangerment findings that would require a reduction in emissions of greenhouse gases from motor vehicles and, also, could trigger permit review for greenhouse gas emissions from certain stationary sources. In addition, on September 22, 2009, the EPA issued a final CAA rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. These regulations will require reporting for some of Buckeye’s facilities, and additional EPA regulations that are expected to be adopted in 2010 will require certain of its other facilities to report their greenhouse gas emissions, possibly beginning in 2012 for emissions occurring in 2011. The adoption and implementation of any CAA regulations limiting emissions of greenhouse gases from Buckeye’s equipment and operations or any future laws or regulations that may be adopted to address greenhouse gas emissions could require it to incur costs to reduce emissions of greenhouse gases associated with its operations. The effect on Buckeye’s operations could include increased costs to operate and maintain its facilities, measure and report its emissions, install new emission controls on its facilities, acquire allowances to authorize its greenhouse gas emissions, pay any taxes related to its greenhouse gas emissions and administer and manage a greenhouse gas emissions program. While Buckeye may be able to include some or all of such increased costs in the rates it charges, such recovery of costs is uncertain and may depend on events beyond its control, including the outcome of future rate proceedings before the FERC and the provisions of any final regulations. In addition, laws or regulations regarding fuel economy, air quality, or greenhouse gas emissions could include efficiency requirements or other methods of curbing carbon emissions that could adversely affect demand for the refined petroleum products, natural gas and other hydrocarbon products that it transports, stores or otherwise handles in connection with its business. A significant decrease in demand for petroleum products would have a material adverse effect on our business, financial condition, results of operations or cash flows.
     Environmental regulation may impose significant costs and liabilities on Buckeye.
     Buckeye is subject to federal, state and local laws and regulations relating to the protection of the environment. Risks of substantial environmental liabilities are inherent in Buckeye’s operations, and Buckeye cannot assure you that it will not incur material environmental liabilities. Additionally, Buckeye’s costs could increase significantly, and Buckeye 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 its operations 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 Buckeye’s results of operations and cash flows.
     Changes made to governmental regulations governing the components of refined petroleum products may necessitate changes to Buckeye’s pipelines and terminals which may require significant capital expenditures or result in lower pipeline volumes. For instance, the increasing use of ethanol as a fuel additive, which is blended with gasoline at product terminals, may lead to reduced pipeline volumes and revenue which may not be totally offset by increased terminal blending fees Buckeye may receive at its terminals.
     DOT regulations may impose significant costs and liabilities on Buckeye.
     Buckeye’s pipeline operations and natural gas storage operations are subject to regulation by the DOT. These regulations require, among other things, that pipeline operators engage in a regular program of pipeline integrity

35


Table of Contents

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, Buckeye conducts pipeline integrity tests on an ongoing and regular basis. Depending on the results of these integrity tests, Buckeye 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.
     Buckeye’s business is exposed to customer credit risk, against which it may not be able to fully protect.
     Buckeye’s businesses are subject to the risks of nonpayment and nonperformance by its customers. Buckeye manages its exposure to credit risk through credit analysis and monitoring procedures, and sometimes use letters of credit, prepayments and guarantees. However, these procedures and policies cannot fully eliminate customer credit risk, and to the extent Buckeye’s policies and procedures prove to be inadequate, it could negatively affect Buckeye’s financial condition and results of operations. In addition, some of Buckeye’s customers, counterparties and suppliers may be highly leveraged and subject to their own operating and regulatory risks and, even if Buckeye’s credit review and analysis mechanisms work properly, Buckeye may experience financial losses in its dealings with such parties. Volatility in commodity prices might have an impact on many of Buckeye’s customers, which in turn could have a negative impact on their ability to meet their obligations to Buckeye.
     The marketing business in Buckeye’s Energy Services segment enters into sales contracts pursuant to which customers agree to buy refined petroleum products from it at a fixed-price on a future date. If Buckeye’s customers have not hedged their exposure to reductions in refined petroleum product prices and there is a price drop, then they could have a significant loss upon settlement of their fixed-price sales contracts with Buckeye, which could increase the risk of their nonpayment or nonperformance. In addition, Buckeye generally has entered into futures contracts to hedge its exposure under these fixed-price sales contracts to increases in refined petroleum product prices. If price levels are lower at settlement than when Buckeye entered into these futures contracts, then Buckeye will be required to make payments upon the settlement thereof. Ordinarily, this settlement payment is offset by the payment received from the customer pursuant to the associated fixed-price sales contract. Buckeye is, however, required to make the settlement payment under the futures contract even if a fixed-price sales contract customer does not perform. Nonperformance under fixed-price sales contracts by a significant number of Buckeye’s customers could have an adverse effect on its business financial condition, results of operations or cash flows.
     Terrorist attacks could adversely affect Buckeye’s 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 Buckeye’s operations to increased risks. Any future terrorist attack on Buckeye’s facilities, those of its customers and, in some cases, those of other pipelines, refineries or terminals, could have a material adverse effect on its business, financial condition, results of operations or cash flows.
     During 2007, the Department of Homeland Security promulgated the Chemical Facility Anti-Terrorism Standards (“CFATS”) to regulate the security of facilities considered to have “high risk” chemicals. Buckeye has submitted to the Department of Homeland Security certain required information concerning its facilities in compliance with CFATS and, as a result, several of Buckeye’s facilities have been determined to be initially tiered as “high risk” by the Department of Homeland Security. Due to this determination, Buckeye is required to prepare a security vulnerability assessment and possibly develop and implement site security plans required by CFATS. At this time, Buckeye does not believe that compliance with CFATS will have a material effect on its business, financial condition, results of operations or cash flows.
     Buckeye’s operations are subject to operational hazards and unforeseen interruptions for which it may not be insured.
     Buckeye’s 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 its control. These events might result in a loss of equipment or life, injury, or extensive property damage, as well as an interruption in Buckeye’s operations. Buckeye’s operations are currently covered by property, casualty, workers’

36


Table of Contents

compensation and environmental insurance policies. In the future, however, Buckeye 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 Buckeye were to incur a significant liability for which it were not fully insured, it could have a material adverse effect on its financial position, thereby reducing its ability to make distributions to its unitholders, or payments to debt holders.
     Buckeye may not be able to realize the benefits of the organizational restructuring commenced in the second quarter of 2009, which could adversely impact its business and financial results.
     In the second quarter of 2009, following Buckeye’s comprehensive “best practices” review of its business, Buckeye commenced a significant organizational restructuring designed to improve efficiencies and realize cost savings. If Buckeye is unable to successfully realize the efficiencies and benefits of its reorganization, its financial results may be adversely impacted. In addition, if Buckeye is unable to successfully realize the operational benefits of its reorganization, its relationships with customers, suppliers and employees may be adversely affected.
     Buckeye’s natural gas storage business depends on third party pipelines to transport natural gas.
     Buckeye depends on Pacific Gas and Electric’s intrastate gas pipelines to move its customers’ natural gas to and from its Lodi Gas facility. Any interruption of service or decline in utilization on the pipelines or adverse change in the terms and conditions of service for the pipelines could have a material adverse effect on the ability of Buckeye’s customers to transport natural gas to and from the Lodi Gas facility, and could have a corresponding material adverse effect on Buckeye’s storage revenues. In addition, the rates charged by the interconnected pipelines for transportation to and from Buckeye’s facilities could affect the utilization and value of its storage services.
     A significant decrease in the production of natural gas could have a significant financial impact on Buckeye.
     Buckeye’s profitability is materially affected by the volume of natural gas it stores. A material change in the supply or demand of natural gas could result in a decline in the volume of natural gas delivered to the Lodi Gas facility for storage and adversely impact our business, financial condition, results of operations or cash flows.
     Buckeye’s results could be adversely affected by volatility in the value of natural gas storage services, including hub services.
     The Natural Gas Storage segment stores natural gas for, and loans natural gas to, its customers for fixed periods of time. If the values of natural gas storage services change in a direction or manner that Buckeye does not anticipate, Buckeye could experience financial losses from these activities. Although the Natural Gas Storage segment does not purchase or sell natural gas, the value of natural gas storage services generally changes based on changes in the relative prices of natural gas over different delivery periods. In particular, the hub services portion of the Natural Gas Storage segment involves our entry into interruptible natural gas storage agreements with Buckeye’s customers. These agreements are entered into in order to maximize the daily utilization of the natural gas storage facility, while also attempting to capture value from seasonal price differences in the natural gas markets. To the extent that the seasonal price differences were to moderate, Buckeye’s business, financial condition, results of operations, or cash flows could be negatively impacted.
     Buckeye’s results could be adversely affected by volatility in the price of refined petroleum products.
     The Energy Services segment buys and sells refined petroleum products in connection with its marketing activities. If the values of refined petroleum products change in a direction or manner that Buckeye does not anticipate, Buckeye could experience financial losses from these activities. Furthermore, when refined petroleum product prices increase rapidly and dramatically, Buckeye may be unable to promptly pass its additional costs to its customers, resulting in lower margins for Buckeye which could adversely affect Buckeye’s results of operations. It is Buckeye’s practice to maintain a position that is substantially balanced between commodity purchases, on the one hand, and expected commodity sales or future delivery obligations, on the other hand. Through these transactions,

37


Table of Contents

Buckeye seeks to establish a margin for the commodity purchased by selling the same commodity for physical delivery to third party users, such as wholesalers or retailers. While Buckeye’s hedging policies are designed to minimize commodity risk, some degree of exposure to unforeseen fluctuations in market conditions remains. For example, any event that disrupts our anticipated physical supply could expose Buckeye to risk of loss resulting from price changes if Buckeye is required to obtain alternative supplies to cover these sales transactions. In addition, Buckeye is also exposed to basis risks in our hedging activities that arise when a commodity, such as ultra low sulfur diesel, is purchased at one pricing index but must be hedged against another commodity type, such as heating oil, because of limitations in the markets for derivative products. Buckeye is also susceptible to basis risk created when Buckeye hedges a commodity based on prices at a certain location, such as the New York Harbor, and enters into a sale or exchange of that commodity at another location, such as Macungie, Pennsylvania, where prices and price changes might differ from the prices and price changes at the location upon which the hedging instrument is based.
     Buckeye’s risk management policies cannot eliminate all commodity risk and any noncompliance with Buckeye’s risk management policies could result in significant financial losses.
     Buckeye’s Energy Services segment follows risk management practices that are designed to minimize its commodity risk, and its Natural Gas Storage segment has adopted risk management policies that are designed to manage the risks associated with its storage business. These practices and policies cannot, however, eliminate all price and price-related risks and there is also the risk of noncompliance with such practices and policies. Buckeye cannot make any assurances that Buckeye will detect and prevent all violations of Buckeye’s risk management practices and policies, particularly if deception or other intentional misconduct is involved. Any violations of these practices or policies by Buckeye’s employees or agents could result in significant financial losses.
Risks Inherent in Ownership of Our Common Units
     Cost reimbursements due our general partner, MainLine Management, may be substantial and will reduce our cash available for distribution to our Unitholders.
     Prior to making any distribution on our units, we will reimburse our general partner for expenses it incurs on our behalf. The reimbursement of expenses could reduce the amount of cash we have to make distributions to our Unitholders. Our general partner will determine the amount of these expenses. In addition, our general partner and its affiliates may perform other services for us for which we will be charged fees as determined by our general partner.
     Our Unitholders do not elect our general partner or vote on our general partner’s directors. An affiliate of our general partner owns a sufficient number of Common Units to allow it to block any attempt to remove our general partner.
     Unlike the holders of common stock in a corporation, our Unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our public Unitholders did not elect our general partner or the directors of our general partner and will have no right to elect our general partner or the directors of our general partner on an annual or other continuing basis in the future.
     Furthermore, if our public Unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. Our general partner may not be removed except upon the vote of the holders of at least 80% of the outstanding common and management units voting together as a single class. Because affiliates of our general partner own more than 20% of our outstanding units, our general partner currently cannot be removed without the consent of our general partner and its affiliates.
     Our Unitholders’ voting rights are further restricted by the provision in our partnership agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner and its affiliates, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of our Unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our Unitholders’ ability to influence the manner or direction of our management.

38


Table of Contents

Additionally, our partnership agreement provides that our general partner, in its sole discretion, may at any time adopt a unitholder rights plan similar to a shareholder rights plan for corporations.
     As a result of these provisions, the price at which our Common Units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.
     BGH GP owns a controlling interest in us and owns our general partner and can determine the outcome of all matters voted upon by our Unitholders.
     BGH GP owns approximately 62% of our limited partner interests and owns our general partner. As a result, BGH GP is able to control the outcome of any matter that comes before a Unitholder vote.
     The control of our general partner may be transferred to a third party, and that party could replace our current management team, in each case, without unitholder consent.
     Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our Unitholders. Furthermore, the owner of our general partner may transfer its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner and to control the decisions taken by the board of directors and officers.
     Increases in interest rates may cause the market price of our Common Units to decline.
     An increase in interest rates may cause a corresponding decline in demand for equity investments in general, and in particular for yield-based equity investments such as our Common Units. Any such increase in interest rates or reduction in demand for our Common Units may cause the trading price of our Common Units to decline.
     If in the future we cease to manage and control Buckeye through our ownership of the general partner interests in Buckeye, we may be deemed to be an investment company under the Investment Company Act of 1940.
     If we cease to manage and control Buckeye and are deemed to be an investment company under the Investment Company Act of 1940, we would either have to register as an investment company under the Investment Company Act of 1940, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us and our affiliates, and reduce the price of our Common Units.
     You may not have limited liability if a court finds that Unitholder action constitutes control of our business.
     Under Delaware law, you could be held liable for our obligations to the same extent as a general partner if a court determined that the right or the exercise of the right by our Unitholders as a group to remove or replace our general partner, to approve some amendments to the partnership agreement or to take other action under our partnership agreement constituted participation in the “control” of our business. Additionally, the limitations on the liability of holders of limited partner interests for the liabilities of a limited partnership have not been clearly established in many jurisdictions.
     Our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those contractual obligations that are expressly made without recourse to our 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.

39


Table of Contents

     We are directly dependent on Buckeye for our growth. As a result of the fiduciary obligations of Buckeye’s general partner, which is our wholly owned subsidiary, to the unitholders of Buckeye, our ability to pursue business opportunities independently may be limited.
     We currently intend to grow primarily through the growth of Buckeye. While we are not precluded from pursuing business opportunities independent of Buckeye, Buckeye’s general partner, which is our wholly owned subsidiary, has fiduciary duties to Buckeye’s unitholders which could make it difficult for us to engage in any business activity that is competitive with Buckeye. Those fiduciary duties are applicable to us because we control the general partner through our ability to elect all of its directors. Accordingly, we may be unable to diversify our sources of revenue in order to increase cash distributions to you.
     Our credit agreement contains operating and financial restrictions that may limit our business and financing activities and a default thereunder could result in a change in control of Buckeye GP.
     The operating and financial restrictions and covenants in our five-year, $10.0 million unsecured revolving credit facility with SunTrust Bank, as both administrative agent and lender (“BGH Credit Agreement”) could restrict our ability to finance future operations or capital needs or to expand or pursue its business activities. For example, our credit agreement restricts our ability to:
    make distributions if any default or event of default occurs;
 
    incur additional indebtedness or guarantee other indebtedness;
 
    grant liens or make certain negative pledges;
 
    make certain loans or investments;
 
    make any material change to the nature of our business, including consolidations, liquidations and dissolutions; or
 
    enter into a merger, consolidation, sale and leaseback transaction or sale of assets.
     If we violate any of the restrictions, covenants, ratios or tests in our credit agreement, a significant portion of our indebtedness may become immediately due and payable, and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. Our member interests in Buckeye GP are pledged to secure our obligations under our credit agreement. If we default in the performance of those obligations, our lenders may foreclose upon and take control of our member interests in Buckeye GP.
Risks Related to Conflicts of Interest
     Buckeye GP owes fiduciary duties to Buckeye and Buckeye’s Unitholders, which may conflict with our interests.
     Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, including Buckeye’s general partner, on one hand, and Buckeye and its limited partners, on the other hand. The directors and officers of Buckeye GP have fiduciary duties to manage Buckeye in a manner beneficial to us, Buckeye GP’s owner. At the same time, Buckeye GP has a fiduciary duty to manage Buckeye in a manner beneficial to Buckeye and its limited partners. The Board of Directors of Buckeye GP may resolve any such conflict of interest and has broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest or that of our Unitholders.
     For example, conflicts of interest may arise in the following situations:
    the allocation of shared overhead expenses to Buckeye and us;
 
    the interpretation and enforcement of contractual obligations between us and our affiliates, on one hand, and Buckeye, on the other hand;
 
    the determination of the amount of cash to be distributed to Buckeye’s partners and the amount of cash to be reserved for the future conduct of Buckeye’s business;
 
    the determination of whether Buckeye should make acquisitions and on what terms;

40


Table of Contents

    the determination of whether Buckeye should use cash on hand, borrow or issue equity to raise cash to finance acquisitions or expansion capital projects, repay indebtedness, meet working capital needs, pay distributions or otherwise; and
 
    any decision we make in the future to engage in business activities independent of Buckeye.
     The fiduciary duties of our general partner may conflict with the fiduciary duties of Buckeye’s general partner.
     Conflicts of interest may arise because of the relationships among Buckeye GP, Buckeye and us. Our general partner has fiduciary duties to manage our business in a manner beneficial to us and our Unitholders and the owner of our general partner. Simultaneously, certain of our general partner’s directors and all of its officers are also directors and officers of Buckeye GP, which has fiduciary duties to manage the business of Buckeye in a manner beneficial to Buckeye and Buckeye’s unitholders. Our partnership agreement contains various provisions modifying and restricting the fiduciary duties that might otherwise be owed by our general partner. The resolution of these conflicts may not always be in our best interest or that of our Unitholders.
     Potential conflicts of interest may arise among our general partner, its affiliates and us. Our general partner has limited fiduciary duties to us and our Unitholders, which may permit it to favor its own interests to the detriment of us and our Unitholders.
     Affiliates of our general partner, together with the executive officers of our general partner, own an approximate 63% limited partner interest in us, represented by common and management units. In addition, BGH GP owns our general partner. Conflicts of interest may arise among our general partner and its affiliates, on the one hand, and us and our Unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our Unitholders. These conflicts include, among others, the following situations:
     Conflicts Relating to Control:
    our general partner is allowed to take into account the interests of parties other than us in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our Unitholders;
 
    our general partner determines whether we incur debt and that decision may affect our or Buckeye’s credit ratings;
 
    our general partner has limited its liability and has reduced its fiduciary duties under our partnership agreement, while also restricting the remedies available to our Unitholders for actions that, without these limitations and reductions, might constitute breaches of fiduciary duty. As a result of purchasing units, our Unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law;
 
    our general partner controls the enforcement of obligations owed to us by it and its affiliates;
 
    our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and
 
    our partnership agreement gives our general partner broad discretion in establishing financial reserves for the proper conduct of our business. These reserves also will affect the amount of cash available for distribution.
     Conflicts relating to costs:
    our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available to be distributed to our Unitholders;
 
    our general partner determines which costs incurred by it and its affiliates are reimbursable by us; and
 
    our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf.

41


Table of Contents

     Our reimbursement of expenses of our general partner will limit our cash available for distribution.
     Our general partner may make expenditures on our behalf for which it will seek reimbursement from us. In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash available for distribution to our Unitholders and cause the value of our Common Units to decline.
     Our partnership agreement contains provisions that reduce the remedies available to Unitholders for actions that might otherwise constitute a breach of fiduciary duty by our general partner. It will be difficult for a Unitholder to challenge a resolution of a conflict of interest by our general partner or by its audit committee.
     Whenever our general partner makes a determination or takes or declines to take any action in its capacity as our general partner, it will be obligated to act in good faith, which means it must reasonably believe that the determination or other action is in our best interests. Whenever a potential conflict of interest exists between us and our general partner, the board of directors of our general partner may resolve such conflict of interest. If the board of directors of our general partner determines that its resolution of the conflict of interest is on terms no less favorable to us than those generally being provided to or available from unrelated third parties or is fair and reasonable to us, taking into account the totality of the relationships between us and our general partner, then it shall be presumed that in making this determination, our general partner acted in good faith. A Unitholder seeking to challenge this resolution of the conflict of interest would bear the burden of overcoming such presumption. This is different from the situation of Delaware corporations, where a conflict resolution by an interested party would be presumed to be unfair and the interested party would have the burden of demonstrating that the resolution was fair.
     Furthermore, if our general partner obtains the approval of its audit committee, the resolution will be conclusively deemed to be fair and reasonable to us and not a breach by our general partner of any duties it may owe to us or our Unitholders. This is different from the situation of Delaware corporations, where a conflict resolution by a committee consisting solely of independent directors would merely shift the burden of demonstrating unfairness to the plaintiff. As a result, Unitholders will effectively not be able to challenge a decision by the audit committee.
     Our general partner’s affiliates may compete with Buckeye and us.
     Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership of interests in us. Affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. As a result, BGH GP or its affiliates may compete directly with entities in which Buckeye has an interest for acquisition opportunities throughout the United States and potentially will compete with one or more of these entities for new business or extensions of the existing services provided by Buckeye’s Operating Subsidiaries, creating actual and potential conflicts of interest between Buckeye and our affiliates.
     Our executive officers face conflicts in the allocation of their time to our business.
     Our general partner shares administrative personnel with Buckeye’s general partner to operate both our business and Buckeye’s business. Our general partner’s officers, who are also the officers of Buckeye’s general partner, have responsibility for overseeing the allocation of time spent by administrative personnel on our behalf and on behalf of Buckeye. These officers face conflicts regarding these time allocations which may adversely affect our or Buckeye’s results of operations, cash flows, and financial condition. These allocations may not necessarily be the result of arms-length negotiations between Buckeye’s general partner and our general partner.

42


Table of Contents

     Our general partner may cause us to issue additional Common Units or other equity securities without your approval, which would dilute your ownership interests.
     Our general partner may cause us to issue an unlimited number of additional Common Units or other equity securities of equal rank with the Common Units, without Unitholder approval. The issuance of additional Common Units or other equity securities of equal rank will have the following effects:
    our Unitholders’ proportionate ownership interest in us will decrease;
 
    the amount of cash available for distribution on each Common Unit may decrease;
 
    the relative voting strength of each previously outstanding Common Unit may be diminished; and
 
    the market price of the Common Units may decline.
     Our general partner has a call right that may require you to sell your Common Units at an undesirable time or price.
     If at any time more than 90% of the outstanding Common Units are owned by our general partner and its affiliates, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the remaining Common Units held by unaffiliated persons at a price equal to the greater of (x) the average of the daily closing prices of the Common Units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (y) the highest price paid by our general partner or any of its affiliates for Common Units during the 90 day period preceding the date such notice is first mailed. As a result, you may be required to sell your Common Units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your Common Units. Our general partner and its affiliates currently own approximately 63% of the Common and Management Units.
Tax Risks to Common Unitholders
     Unitholders are urged to read the section above entitled “Tax Considerations for Unitholders” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of Common Units.
     Our and Buckeye’s tax treatment depends on their status as a partnership for federal income tax purposes as well as not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat either us or Buckeye as a corporation for federal income tax purposes or they were to become subject to additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to you would be substantially reduced.
     The value of our investment in Buckeye depends largely on Buckeye being treated as a partnership for federal income tax purposes, which requires that 90% or more of Buckeye’s gross income for every taxable year consist of qualifying income, as defined in Section 7704 of the Code. Buckeye may not meet this requirement or current law may change so as to cause, in either event, Buckeye to be treated as a corporation for federal income tax purposes or otherwise be subject to federal income tax. Moreover, the anticipated after-tax economic benefit of an investment in our Common Units depends largely on us being treated as a partnership for federal income tax purposes. We have not requested, and does not plan to request, a ruling from the IRS as to our or Buckeye’s treatment as a partnership for federal income tax purposes.
     Despite the fact that we and Buckeye are limited partnerships under Delaware law, it is possible in certain circumstances for a partnership such as us or Buckeye to be treated as a corporation for federal income tax purposes. Although we do not believe based upon the current operations of us and Buckeye that either we or Buckeye is so treated, a change in our or Buckeye’s business (or a change in current law) could cause them to be treated as a corporation for federal income tax purposes or otherwise subject them to taxation as an entity.
     If either we or Buckeye were treated as a corporation for federal income tax purposes, they would pay federal income tax on their taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to us from Buckeye would generally be taxed again as

43


Table of Contents

corporate distributions, and no income, gains, losses, deductions or credits would flow through to us. Further, distributions to you would generally be taxed again as corporate distributions as well, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of either us or Buckeye as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our holders of Common Units, likely causing a substantial reduction in the value of our Common Units.
     Current law may change so as to cause us or Buckeye to be treated as a corporation for federal income tax purposes or otherwise subject us or Buckeye to entity-level taxation. At the federal level, legislation has been proposed that would eliminate partnership tax treatment for certain publicly traded partnerships and recharacterize certain types of income received for partnerships. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Moreover, any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Any such changes could negatively impact the value of an investment in our Common Units. At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, Buckeye is required to pay Texas franchise tax at a maximum effective rate of 0.7% of Buckeye’s gross income apportioned to Texas in the prior year. Imposition of such a tax on us or Buckeye by any other state will reduce the cash available for distribution to you.
     If the IRS contests the federal income tax positions that we or Buckeye take, the market for our Common Units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to you.
     We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or certain other matters that affect us. Moreover, Buckeye has not requested any ruling from the IRS with respect to its treatment as a partnership for federal income tax purposes or any other matter that affects Buckeye. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions taken by us or Buckeye. A court may not agree with some or all of the positions we or Buckeye take. Any contest with the IRS may materially and adversely impact the market for our Common Units and Buckeye’s limited partnership units and the prices at which they trade. In addition, the cost of any contest between Buckeye and the IRS will result in a reduction in cash available for distribution to us and the costs of any contest between us and the IRS will be borne indirectly by our Unitholders and its general partner because the costs will reduce our cash available for distribution.
     You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.
     Because our Unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you receive no cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from that income.
     Tax gain or loss on the disposition of our Common Units could be more or less than expected.
     If you sell your Common Units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those Common Units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your Common Units, the amount, if any, of such prior excess distributions with respect to the Common Units you sell will, in effect, become taxable income to you if you sell such Common Units at a price greater than your tax basis in those Common Units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depletion and depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your Common Units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

44


Table of Contents

     Tax-exempt entities and non-U.S. persons face unique tax issues from owning Common Units that may result in adverse tax consequences to them.
     Investment in Common Units by tax-exempt entities, such as employee benefit plans and IRAs, and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal tax returns and pay tax on their share of our taxable income. If you are a tax exempt entity or a non-U.S. person, you should consult your tax advisor before investing in Common Units.
     We will treat each purchaser of Common Units as having the same tax benefits without regard to the actual Common Units purchased. The IRS may challenge this treatment, which could adversely affect the value of the Common Units.
     Because we cannot match transferors and transferees of Common Units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing U.S. Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of Common Units and could have a negative impact on the value of Common Units or result in audit adjustments to your tax returns.
     We prorate items of income, gain, loss and deduction between transferors and transferees of Common Units each month based upon the ownership of Common Units on the first day of each month, instead of on the basis of the date a particular Common Unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our Unitholders.
     We prorate items of income, gain, loss and deduction between transferors and transferees of Common Units each month based upon the ownership of Common Units on the first day of each month, instead of on the basis of the date a particular Common Unit is transferred. The use of this proration method may not be permitted under existing U.S. Treasury regulations. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our Unitholders.
     A Unitholder whose Common Units are loaned to a “short seller” to cover a short sale of Common Units may be considered as having disposed of those Common Units. If so, the Unitholder would no longer be treated for tax purposes as a partner with respect to those Common Units during the period of the loan and may recognize gain or loss from the disposition.
     Because a Unitholder whose Common Units are loaned to a “short seller” to cover a short sale of Common Units may be considered as having disposed of the loaned Common Units, the Unitholder may no longer be treated for tax purposes as a partner with respect to those Common Units during the period of the loan to the short seller and the Unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those Common Units may not be reportable by the Unitholder and any cash distributions received by the Unitholder as to those Common Units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their Common Units.
     We will adopt certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the Unitholders. The IRS may challenge this treatment, which could adversely affect the value of Common Units.
     When we issue additional Common Units or engage in certain other transactions, we will determine the fair market value of its assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of its Unitholders and its general partner. Our methodology may be viewed as understating the value of our assets. In

45


Table of Contents

that case, there may be a shift of income, gain, loss and deduction between certain Unitholders and the general partner, which may be unfavorable to such Unitholders. Moreover, under our valuation methods, subsequent purchasers of Common Units may have a greater portion of their Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our Unitholders. A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our Unitholders. It also could affect the amount of gain from our Unitholders’ sale of Common Units and could have a negative impact on the value of the Common Units or result in audit adjustments to our Unitholders’ tax returns without the benefit of additional deductions.
     The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
     We will be considered to have terminated as a partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. A termination would, among other things, result in the closing of our taxable year for all Unitholders, which would result in us filing two tax returns (and each Unitholder could receive two Schedules K-1 from us) for one fiscal year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income for the year in which the termination occurs. In the case of a Unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in the Unitholder’s taxable income for the year of termination. A termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has recently announced a publicly traded partnership technical termination relief program whereby, if the taxpayer requests relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.
     As a result of investing in Common Units, you may become subject to state and local taxes and return filing requirements in jurisdictions where Buckeye operates or owns or acquires property.
     In addition to federal income taxes, you will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which Buckeye conducts business or owns property now or in the future, even if you do not live in any of those jurisdictions. You will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. Buckeye owns property and conducts business in a number of states in the United States. Most of these states impose an income tax on individuals, corporations and other entities. As Buckeye makes acquisitions or expands its business, Buckeye may own assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. It is your responsibility to file all foreign, federal, state and local tax returns.
     Buckeye has a subsidiary that is treated as a corporation for federal income tax purposes and subject to corporate-level income taxes.
     Buckeye conducts a portion of our operations through a subsidiary that is a corporation for federal income tax purposes. Buckeye may elect to conduct additional operations in corporate form in the future. The corporate subsidiary will be subject to corporate-level tax, which will reduce the cash available for distribution to Buckeye and, in turn, impact Buckeye’s cash available for distribution. If the IRS were to successfully assert that the corporate subsidiary has more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, Buckeye’s cash available for distribution to its Unitholders, including us, would be further reduced.
Item 1B. Unresolved Staff Comments
     None.

46


Table of Contents

Item 2. Properties
     We and Buckeye are managed primarily from two leased commercial business offices located in Breinigsville, Pennsylvania and Houston, Texas that are approximately 75,000 and 27,000 square feet in size, respectively.
     In general, Buckeye’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 our rights are revocable at the election of the grantor or are subject to renewal at various intervals, and some require periodic payments. We have not experienced any revocations or lapses of such rights which were material to our business or operations, and we have 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 that we own. We have leases for subsurface underground gas storage rights and surface rights in connection with our operations in the Natural Gas Storage segment.
     See Item 1 for a description of the location and general character of our material property.
     We believe that we have sufficient title to our 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 our business substantially in accordance with past practice. Although in certain cases our title to assets and properties or our other rights, including our rights to occupy the land of others under easements, leases, licenses and permits, may be subject to encumbrances, restrictions and other imperfections, we do not expect any of such imperfections to interfere materially with the conduct of our businesses.
Item 3. Legal Proceedings
     We, in the ordinary course of business, are involved in various claims and legal proceedings, some of which are covered in whole or in part by insurance. We are unable to predict the timing or outcome of these claims and proceedings.
     With respect to environmental litigation, we 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, we are usually one of many PRPs for a particular site and our contribution of total waste at the site is usually not material.
     Although there is no material environmental litigation pending against us 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.
Item 4. [Reserved]

47


Table of Contents

PART II
Item 5. Market for the Registrant’s Common Units, Related Unitholder Matters, and Issuer Purchases of Common Units
     Our Common Units are listed and traded on the NYSE under the symbol “BGH.” The high and low sales prices of our Common Units during the years ended December 31, 2009 and 2008, as reported in the NYSE Composite Transactions, were as follows:
                                 
    2009     2008  
Quarter   High     Low     High     Low  
First
  $ 17.25     $ 12.75     $ 29.92     $ 21.65  
Second
    20.56       14.90       26.44       18.00  
Third
    30.00       18.17       22.70       13.35  
Fourth
    30.00       23.01       18.72       9.51  
     We have gathered tax information from our known Common and Management Unitholders and from brokers/nominees and, based on the information collected, we estimate our number of beneficial Common and Management Unitholders to be approximately 9,967 at December 31, 2009.
     Cash distributions paid to Unitholders for the years ended December 31, 2009 and 2008 were as follows:
             
        Amount Per  
Record Date   Payment Date   Common Unit  
February 5, 2008
  February 29, 2008   $ 0.285  
May 9, 2008
  May 30, 2008     0.300  
August 8, 2008
  August 29, 2008     0.310  
November 7, 2008
  November 28, 2008     0.320  
 
           
February 12, 2009
  February 27, 2009   $ 0.330  
May 11, 2009
  May 29, 2009     0.350  
August 7, 2009
  August 31, 2009     0.370  
November 12, 2009
  November 30, 2009     0.390  
     On February 5, 2010, we announced a quarterly distribution of $0.41 per Common Unit that was paid on February 26, 2010, to Unitholders of record on February 16, 2010. Total cash distributed to Unitholders on February 26, 2010 was approximately $11.6 million.
     We generally make quarterly cash distributions of substantially all of our available cash, generally defined as consolidated cash receipts less consolidated cash expenditures and such retentions for working capital, anticipated cash expenditures and contingencies as MainLine Management deems appropriate. Distributions of cash paid by us to a Unitholder will not result in taxable gain or income except to the extent the aggregate amount distributed exceeds the tax basis of the Common Units owned by the Unitholder.
     We are a publicly traded MLP and are not subject to federal income tax. Instead, Unitholders are required to report their allocable share of our income, gain, loss and deduction, regardless of whether we make distributions.
Recent Sales of Unregistered Securities
     None.
Units Authorized for Issuance under Equity Compensation Plan
     None.

48


Table of Contents

Issuer Purchases of Equity Securities
     None.
Item 6. Selected Financial Data
     The following tables set forth, for the periods and at the dates indicated, our selected consolidated financial data for each of the last five years which is derived from our audited consolidated financial statements. The tables should be read in conjunction with the consolidated financial statements and notes thereto included elsewhere in this Report (in thousands, except per unit amounts).
     Because we own and control the general partner of Buckeye, the statements reflect our ownership interest in Buckeye on a consolidated basis, which means that Buckeye’s financial results are consolidated with our financial results. The financial statements of Services Company, which employs the employees who manage and operate us and Buckeye, are also consolidated into our financial statements. We have no separate operating activities apart from those conducted by Buckeye, and our cash flows consist primarily of incentive distributions from Buckeye with respect to the partnership interests that we own. Accordingly, the summary historical consolidated financial data set forth in the following table primarily reflects the operating activities and results of operations of Buckeye. The limited partner interests in Buckeye not owned by us or our affiliates are reflected as noncontrolling interest on our balance sheet and the non-affiliated partners’ share of income from Buckeye is reflected as income attributable to noncontrolling interest in our results of operations.
                                         
    Year Ended December 31,  
    2009     2008     2007     2006     2005  
Income Statement Data:
                                       
Revenue (1)
  $ 1,770,372     $ 1,896,652     $ 519,347     $ 461,760     $ 408,446  
Depreciation and amortization
    54,699       50,834       40,236       39,629       32,408  
Asset impairment expense
    59,724                          
Reorganization expense
    32,057                          
Operating income (1) (2)
    203,800       246,492       195,353       164,873       155,869  
Interest and debt expense
    75,147       75,410       51,721       60,702       55,366  
Net income (2)
    141,637       180,623       152,675       111,800       106,690  
Net income attributable to Buckeye GP Holdings L.P. (1)
    49,594       26,477       22,921       8,734       6,986  
Net income from August 9 to December 31, 2006
                      2,599        
 
                                       
Earnings per limited partner unit — diluted (3)
  $ 1.75     $ 0.94     $ 0.81     $ 0.09     $  
Distributions per limited partner unit
    1.44       1.22       0.98       0.13        
                                         
    December 31,  
    2009     2008     2007     2006     2005  
Balance Sheet Data:
                                       
Total assets (1)
  $ 3,486,571     $ 3,263,097     $ 2,354,326     $ 2,212,585     $ 2,040,832  
Total debt, including current portion
    1,746,473       1,555,719       869,463       1,020,449       1,104,660  
Total Buckeye GP Holdings L.P. capital
    242,334       232,060       238,330       240,617       80,442  
Noncontrolling interests (4)
    1,209,960       1,166,774       1,066,143       772,525       711,722  
 
(1)   Substantial increases in revenue, operating income, net income and total assets for the year ended December 31, 2007 through the year ended December 31, 2008 resulted from the acquisitions of Lodi Gas and Farm & Home in the first quarter of 2008. See Note 4 in the Notes to Consolidated Financial Statements for further discussion.

49


Table of Contents

(2)   Operating income and net income for the year ended December 31, 2009 include a non-cash charge of $59.7 million related to an asset impairment (see Note 8 in the Notes to Consolidated Financial Statements) and $32.1 million of expenses incurred in connection with an organization restructuring (see Note 3 in the Notes to Consolidated Financial Statements).
 
(3)   Earnings per limited partner unit — diluted is presented only for the period since August 9, 2006, the date we became a public company.
 
(4)   For periods prior to January 1, 2009, noncontrolling interests liability has been reclassified into partners’ capital on the consolidated balance sheets due to the adoption of guidance regarding accounting and reporting standards for the noncontrolling interests in a subsidiary. See Note 2 in the Notes to Consolidated Financial Statements for further information.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
     The following information should be read in conjunction with our consolidated financial statements and our accompanying notes thereto included in Item 8 of this Report. Our discussion and analysis includes the following:
    Overview of BGH;
 
    Overview of Buckeye;
 
    General Outlook for 2010;
 
    2009 Developments — discusses major items impacting our results in 2009;
 
    Results of Operations — discusses material year-to-year variances in the consolidated statements of operations;
 
    Liquidity and Capital Resources — addresses available sources of liquidity and capital resources and includes a discussion of our capital spending;
 
    Critical Accounting Policies and Estimates — presents accounting policies that are among the most critical to the portrayal of our financial position and results of operations;
 
    Other Items — includes information related to contractual obligations, off-balance sheet arrangements, and other matters; and
 
    Recent Accounting Pronouncements.
     This discussion contains forward-looking statements based on current expectations that are subject to risks and uncertainties, such as statements of our plans, objectives, expectations and intentions. Our actual results and the timing of events could differ materially from those anticipated or implied by the forward-looking statements discussed here as a result of various factors, including, among others, those set forth under “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” herein.
     Our consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”).
Overview of BGH
     We own and control Buckeye GP, which is the general partner of Buckeye. We are managed by our general partner, MainLine Management, which is owned by BGH GP. Our only cash-generating assets are our partnership interests in Buckeye, comprised primarily of the following:
    the incentive distribution rights in Buckeye;
 
    the indirect ownership of the general partner interests in certain of Buckeye’s Operating Subsidiaries (representing an approximate 1% interest in each of such Operating Subsidiaries);
 
    the general partner interests in Buckeye (representing 243,914 general partner units (the “GP Units”), or an approximate 0.5% interest in Buckeye); and
 
    80,000 of Buckeye’s LP Units.
     The incentive distribution rights noted above entitle us to receive amounts equal to specified percentages of the incremental amount of cash distributed by Buckeye to the holders of LP Units when target distribution levels for each quarter are exceeded. The 2,573,146 LP Units originally issued to the ESOP are excluded for the purpose of calculating incentive distributions. The target distribution levels begin at $0.325 and increase in steps to the highest

50


Table of Contents

target distribution level of $0.525 per eligible LP Unit. When Buckeye makes quarterly distributions above this level, the incentive distributions include an amount equal to 45% of the incremental cash distributed to each eligible unitholder for the quarter, or approximately 29.5% of total incremental cash distributed by Buckeye above $0.525 per LP Unit.
     Our earnings and cash flows are, therefore, directly dependent upon the ability of Buckeye and its Operating Subsidiaries to make cash distributions to its unitholders. The actual amount of cash that Buckeye will have available for distribution will depend primarily on its ability to generate earnings and cash flows beyond its working capital requirements.
     The following table summarizes the cash we received for the years ended December 31, 2009, 2008 and 2007 as a result of our partnership interests in Buckeye (in thousands, except unit amounts):
                         
    Year Ended December 31,  
    2009     2008     2007  
Incentive payments from Buckeye
  $ 45,739     $ 38,895     $ 29,978  
Distributions from the indirect 1% ownership in certain of Buckeye’s operating subsidiaries
    1,955       1,131       1,292  
Distributions from the ownership of 243,914 of Buckeye’s GP Units
    884       835       786  
Distributions from the ownership of 80,000 of Buckeye’s LP Units
    290       274       258  
                   
 
  $ 48,868     $ 41,135     $ 32,314  
                   
Overview of Buckeye Partners, L.P.
     Buckeye’s primary business strategies are to generate stable cash flows, increase pipeline and terminal throughput and pursue strategic cash-flow accretive acquisitions that complement its existing asset base and improve operating efficiencies to allow increased cash distributions to its unitholders.
     We, through Buckeye, operate and report in five business segments: Pipeline Operations; Terminalling and Storage; Natural Gas Storage; Energy Services; and Development and Logistics. We previously referred to the Development and Logistics segment as the Other Operations segment. We renamed the segment to better describe the business activities conducted within the segment. See Note 22 in the Notes to Consolidated Financial Statements for a more detailed discussion of these business segments.
     Buckeye’s principal line of business is the transportation, terminalling, storage and marketing of refined petroleum products in the United States for major integrated oil companies, large refined petroleum product marketing companies and major end users of refined petroleum products on a fee basis through facilities it owns and operates. Buckeye owns a major natural gas storage facility in northern California. Buckeye also operates pipelines owned by third parties under contracts with major integrated oil and chemical companies, and performs certain construction activities, generally for the owners of those third-party pipelines.
General Outlook for 2010
     During 2008 and 2009, demand for refined petroleum products was adversely impacted by the slowdown in the overall economy. In 2010, however, we anticipate that demand will level out as underlying economic conditions stabilize or improve. We expect that the aggregate rates for our transportation and storage services in 2010 will show modest increases despite the impact of negative economic conditions during 2009. Ultimately, our ability to maintain or increase transportation and storage volumes and rates in 2010 will be largely dependent upon the strength of the overall economy and demand for refined petroleum products in the areas we serve.
     The capital markets strengthened considerably in 2009, compared to 2008, and Buckeye successfully accessed both the debt and equity markets to fund its 2009 growth initiatives. Although Buckeye has no specific plans to

51


Table of Contents

access the capital markets in 2010, should Buckeye elect to raise capital, we believe that, under current financial market conditions, Buckeye would be able to raise capital in both the debt and equity markets on acceptable terms.
     We expect that our earnings in 2010 will be positively impacted by the full year contribution from the refined petroleum products pipelines and terminals acquired from ConocoPhillips in November 2009, cost savings from the organizational restructuring completed in 2009, and incremental revenue from growth capital expenditures in 2009 and 2010.
     Throughout 2010, we will continue to evaluate opportunities to acquire or construct assets that are complementary to our business and support our long term growth strategy and will determine the appropriate financing structure for any opportunity we pursue.
2009 Developments
     Major items impacting our results in 2009 include:
  Consolidated Statements of Operations
    In early 2009, we began a “best practices” review of our business and organization structure to identify improved business practices, operating efficiencies and cost savings in anticipation of changing needs in the energy markets. This review culminated in the approval by the Board of Directors of Buckeye GP of an organizational restructuring. The organizational restructuring included a workforce reduction of approximately 230 employees, in excess of 20% of our workforce. The program was initiated in the second quarter of 2009 and was substantially complete by the end of 2009. As part of the workforce reduction, we offered certain eligible employees the option of enrolling in a voluntary early retirement program, which approximately 80 employees accepted. The remaining affected positions have been eliminated involuntarily under our ongoing severance plan. Most terminations were effective as of July 20, 2009. The restructuring also included the relocation of some employees consistent with the goals of the reorganization. We have incurred $32.1 million of expenses in connection with this organizational restructuring for the year ended December 31, 2009. See Note 3 in the Notes to Consolidated Financial Statements for further discussion.
 
    We recorded a non-cash charge of $59.7 million during the year ended December 31, 2009 related to an impairment of Buckeye NGL. During the second quarter of 2009, we recorded a non-cash charge of $72.5 million. Effective January 1, 2010, we sold our interest in Buckeye NGL for $22.0 million. The sales proceeds exceeded the previously impaired carrying value of the NGL pipeline by $12.8 million resulting in the reversal of $12.8 million of the previously recorded asset impairment expense in the fourth quarter of 2009. The impairment and subsequent reversal is reflected within the category “Asset Impairment Expense” on our consolidated statements of operations. See Note 8 in the Notes to Consolidated Financial Statements for further discussion.
 
    We experienced a delay in the startup of the Kirby Hills Phase II expansion project in our Natural Gas Storage segment, which we initially expected to occur in April 2009. The project was ultimately placed into service in June 2009.
 
    We experienced lower Pipeline Operations product transportation volumes of 5.2% in 2009 as compared to 2008, which resulted in an approximate $19.0 million reduction in revenues.
 
    We recorded a favorable property tax settlement of $7.2 million from the City of New York in our Pipeline Operations segment, which is reflected within the category “Total costs and expenses” in our consolidated statements of operations.

52


Table of Contents

  Consolidated Balance Sheet and Capital Structure
    We completed an acquisition in 2009 of certain refined petroleum product terminals and pipeline assets from ConocoPhillips for approximately $54.4 million that was financed with borrowings under Buckeye’s Credit Facility.
 
    We incurred capital expenditures for internal growth projects of $63.8 million.
 
    We sold $275.0 million aggregate principal amount of 5.500% Notes due 2019 for net proceeds of $271.4 million in an underwritten public offering.
 
    We issued approximately 3.0 million of Buckeye’s LP Units in 2009 for net proceeds of approximately $104.6 million in an underwritten public offering.
 
    We amended the BES Credit Agreement to increase the borrowing capacity from $175.0 million to $250.0 million. Buckeye’s Credit Facility was also amended to reduce the borrowing capacity from $600.0 million to $580.0 million.
Results of Operations
     The results of operations discussed below principally reflect the activities of Buckeye. Since our consolidated financial statements include the consolidated results of Buckeye, our consolidated financial statements are substantially similar to Buckeye’s except as noted below:
    Interest of noncontrolling partners in Buckeye — Our consolidated balance sheets include a noncontrolling interests capital account that reflects the proportion of Buckeye owned by its partners other than us. Similarly, the ownership interests in Buckeye held by its partners other than us are reflected in our consolidated statements of operations as income attributable to noncontrolling interest. These noncontrolling interest accounts are not reflected in Buckeye’s consolidated financial statements.
 
    Our capital structure — In addition to incorporating the assets and liabilities of Buckeye, our consolidated balance sheets include our own indebtedness and related debt placement costs, and the partners’ capital on our consolidated balance sheets represent our partners’ capital as opposed to the capital reflected in Buckeye’s balance sheets, which reflects the ownership interest of all its partners, including its owners other than us or Services Company. Consequently, our consolidated statements of operations reflect additional interest expense, interest income and debt amortization expense that is not reflected in Buckeye’s consolidated financial statements.
 
    Inclusion of Services Company — The financial statements of Services Company, which employs the employees who manage and operate our assets, are consolidated into our financial statements. The consolidated financial statements of Buckeye do not include the financial statements of Services Company.
 
    Our general and administrative expenses — We incur general and administrative expenses that are independent from Buckeye’s operations and are not reflected in Buckeye’s consolidated financial statements.
 
    Elimination of intercompany transactions — Intercompany obligations and payments among Buckeye and its consolidated subsidiaries, us and Services Company are reflected in Buckeye’s consolidated financial statements but are eliminated in our consolidated financial statements.

53


Table of Contents

  Consolidated Summary
     Our revenues, operating income and net income decreased during the year ended December 31, 2009 compared to the year ended December 31, 2008, primarily due to the recognition of expenses in connection with our organizational restructuring, a non-cash charge for an asset impairment and, in the case of our revenue decrease, lower overall pipeline and terminalling and storage volumes resulting in lower revenues. Our revenues, operating income and net income increased during the year ended December 31, 2008 compared to the year ended December 31, 2007, primarily due to the expansion of our operations through acquisitions and to increases in interstate pipeline tariff rates and terminalling throughput fees. Overall pipeline volumes declined by 5.2% during the year ended December 31, 2009 compared to the year ended December 31, 2008 and 4.5% during the year ended December 31, 2008 compared to the year ended December 31, 2007.
     Our summary operating results were as follows for the periods indicated (in thousands):
                         
    Year Ended December 31,  
    2009     2008     2007  
Revenues
  $ 1,770,372     $ 1,896,652     $ 519,347  
Costs and expenses
    1,566,572       1,650,160       323,994  
 
                 
Operating income
    203,800       246,492       195,353  
Other expense
    (74,694 )     (73,857 )     (50,231 )
 
                 
Income before earnings from equity investments
    129,106       172,635       145,122  
Earnings from equity investments
    12,531       7,988       7,553  
 
                 
Net income
    141,637       180,623       152,675  
Less: net income attributable to noncontrolling interest
    (92,043 )     (154,146 )     (129,754 )
 
                 
Net income attributable to Buckeye GP Holdings L.P.
  $ 49,594     $ 26,477     $ 22,921  
 
                 
Earnings per partnership unit — diluted
  $ 1.75     $ 0.94     $ 0.81  
 
                 

54


Table of Contents

  Segment Results
     A summary of financial information by business segment follows for the periods indicated (in thousands):
                         
    Year Ended December 31,  
    2009     2008     2007  
Revenues:
                       
Pipeline Operations
  $ 392,667     $ 387,267     $ 379,345  
Terminalling and Storage
    136,576       119,155       103,782  
Natural Gas Storage
    99,163       61,791        
Energy Services
    1,125,013       1,295,925        
Development and Logistics
    34,136       43,498       36,220  
Intersegment
    (17,183 )     (10,984 )      
 
                 
Total revenues
  $ 1,770,372     $ 1,896,652     $ 519,347  
 
                 
Total costs and expenses: (1)
                       
Pipeline Operations
  $ 298,710     $ 237,918     $ 232,468  
Terminalling and Storage
    75,492       67,022       63,200  
Natural Gas Storage
    68,589       29,556        
Energy Services
    1,111,927       1,290,020        
Development and Logistics
    29,037       36,628       28,326  
Intersegment
    (17,183 )     (10,984 )      
 
                 
Total costs and expenses
  $ 1,566,572     $ 1,650,160     $ 323,994  
 
                 
Depreciation and amortization:
                       
Pipeline Operations
  $ 35,533     $ 35,188     $ 32,996  
Terminalling and Storage
    7,258       6,051       5,610  
Natural Gas Storage
    5,971       4,599        
Energy Services
    4,204       3,386        
Development and Logistics
    1,733       1,610       1,630  
 
                 
Total depreciation and amortization
  $ 54,699     $ 50,834     $ 40,236  
 
                 
Asset impairment expense:
                       
Pipeline Operations
  $ 59,724     $     $  
 
                 
Reorganization expense:
                       
Pipeline Operations
  $ 26,127     $     $  
Terminalling and Storage
    2,735              
Natural Gas Storage
    495              
Energy Services
    1,207              
Development and Logistics
    1,493              
 
                 
Total reorganization expense
  $ 32,057     $     $  
 
                 
Operating Income:
                       
Pipeline Operations
  $ 93,957     $ 149,349     $ 146,878  
Terminalling and Storage
    61,084       52,133       40,581  
Natural Gas Storage
    30,574       32,235        
Energy Services
    13,086       5,905        
Development and Logistics
    5,099       6,870       7,894  
 
                 
Total operating income
  $ 203,800     $ 246,492     $ 195,353  
 
                 
 
(1)   Includes depreciation and amortization, asset impairment expense and reorganization expense.

55


Table of Contents

     Costs and expenses attributable to Buckeye, Services Company and us were as follows (in thousands):
                         
    Year Ended December 31,  
    2009     2008     2007  
Attributable to Buckeye
  $ 1,561,929     $ 1,643,031     $ 317,267  
Elimination of Buckeye deferred charge
    (4,698 )     (4,698 )     (4,698 )
Net effect of ESOP charges
    1,952       2,517       5,069  
Attributable to BGH
    7,389       9,310       6,356  
 
                 
Total costs and expenses
  $ 1,566,572     $ 1,650,160     $ 323,994  
 
                 
     Amounts attributable to us were as follows (in thousands):
                         
    Year Ended December 31,  
    2009     2008     2007  
Payroll and payroll benefits
  $ 4,620     $ 5,000     $ 3,975  
Professional fees
    635       3,172       1,485  
Other
    2,134       1,138       896  
 
                 
Total
  $ 7,389     $ 9,310     $ 6,356  
 
                 
     Payroll and benefits costs include salaries and benefits for the four highest paid executives performing services on behalf of Buckeye, as well as allocations of the cost of Buckeye personnel performing administrative services directly for BGH. As described in Note 1 in the Notes to Consolidated Financial Statements, effective January 1, 2009, Buckeye and its Operating Subsidiaries began paying for all executive compensation and benefits earned by Buckeye GP’s four highest salaried officers in return for an annual fixed payment from us of $3.6 million. The $3.6 million annual fixed payment consists of the anticipated 2009 salaries, incentive compensation and benefits of these officers plus 15%. Salaries and benefits for 2009 include salaries, incentive compensation and benefits of these officers offset by the $3.6 million annual fixed payment, plus allocations of the cost of Buckeye personnel performing administrative services directly for us. Salaries and benefits costs in 2008 include salaries and benefits for the four highest paid executives performing services on behalf of Buckeye under the prior arrangement plus the allocated administrative salaries.
     Non-recurring professional fees in 2008 include approximately $1.6 million due to fees incurred in connection with a tender offer for outstanding BGH Common Units made by BGH GP in the latter part of 2008, which tender offer was subsequently withdrawn. Other costs include certain state franchise taxes, insurance costs and miscellaneous other expenses.

56


Table of Contents

     The following table presents our product volumes transported in the Pipeline Operations segment and average daily throughput for the Terminalling and Storage segment in barrels per day and total volumes sold in gallons for the Energy Services segment for the periods indicated:
                         
    Year Ended December 31,  
    2009     2008     2007  
Pipeline Operations: (average barrels per day)
                       
Gasoline
    650,100       673,500       717,900  
Distillate
    284,700       304,200       320,100  
Jet Fuel
    336,700       354,700       362,700  
LPGs
    16,500       17,500       19,300  
NGLs
    13,900       20,900       20,400  
Other products
    8,000       11,400       7,000  
 
                 
Total Pipeline Operations
    1,309,900       1,382,200       1,447,400  
 
                 
Terminalling and Storage: (average barrels per day)
                       
Products throughput (1)
    444,900       457,400       482,300  
 
                 
Energy Services: (in thousands of gallons)
                       
Sales volumes (2)
    655,100       435,200        
 
                 
 
(1)   Reported quantities exclude transfer volumes, which are non-revenue generating transfers among our various terminals. For the years ended December 31, 2008 and 2007, we previously reported 537.7 thousand and 568.6 thousand barrels, respectively, which included transfer volumes.
 
(2)   Our Energy Services segment business was acquired on February 8, 2008.
  2009 Compared to 2008
  Consolidated
     Consolidated income attributable to our Unitholders was $49.6 million for the year ended December 31, 2009 compared to $26.5 million for the year ended December 31, 2008. The increase in income attributable to our Unitholders was due to increases in Buckeye’s quarterly distribution. As mentioned above, the incentive distribution rights entitle us to receive amounts equal to specified percentages of the incremental amount of cash distributed by Buckeye to the holders of Buckeye’s LP Units when target distribution levels for a quarter are exceeded. As a result, increases in Buckeye’s distributions causes increases in income attributable to our Unitholders. During 2009, Buckeye paid a $3.63 per LP Unit distribution as compared to a $3.43 per LP Unit distribution in 2008, which resulted in an increase of $6.8 million in incentive distribution rights in 2009 as compared to 2008.
     Revenue was $1,770.4 million for the year ended December 31, 2009, which is a decrease of $126.3 million or 6.7% from the year ended December 31, 2008. This overall decrease was caused primarily by a decrease in revenues from the Energy Services segment of $170.9 million due to an overall reduction in refined petroleum product prices in 2009 as compared to 2008, and a decrease in the Development and Logistics segment’s revenue of $9.4 million primarily due to decreased construction activities. This decrease was partially offset by increased revenues from the Natural Gas Storage segment of $37.4 million from increased activity from the commencement of operations of the Kirby Hills Phase II expansion project, increased revenues from the Terminalling and Storage segment of $17.4 million primarily from terminals acquired at various times in 2008 and in November of 2009, fees and storage and rental revenue growth and increased revenues from the Pipeline Operations segment of $5.4 million primarily due to increased tariffs and more favorable settlement experience, partially offset by lower volumes.
     Total costs and expenses were $1,566.6 million for the year ended December 31, 2009, which is a decrease of $83.6 million or 5.1% from the corresponding period in 2008. Total costs and expenses reflect a decrease in refined petroleum product prices, which resulted in a $178.1 million decrease in the Energy Services segment’s cost of product sales in 2009 as compared to 2008, partially offset by increased volumes in 2009. In addition, total costs

57


Table of Contents

and expenses reflect the effectiveness of overall cost management efforts we implemented in 2009. These decreases in total costs and expenses were partially offset by a $59.7 million asset impairment expense, a $32.1 million reorganization expense (see Notes 8 and 3, respectively, in the Notes to Consolidated Financial Statements) and a $3.9 million increase in depreciation and amortization. Other factors impacting total costs and expenses include increased operating costs for terminals acquired at various times in 2008 and in November of 2009 in the Terminalling and Storage segment and increased expenses associated with certain hub services transactions stemming from delays in the Kirby Hills Phase II expansion project in the Natural Gas Storage segment and general market conditions.
     Operating income was $203.8 million for the year ended December 31, 2009 compared to operating income of $246.5 million for the year ended December 31, 2008, of which $59.7 million and $32.1 million of the decrease is due to the asset impairment expense and reorganization expense, respectively, discussed above. Depreciation and amortization increased $3.9 million for 2009 from the corresponding period in 2008, primarily due to acquisitions made in 2008, the assets utilized with respect to the Kirby Hills Phase II expansion project which were placed in service in the second half of 2009 and software which was placed in service in the fourth quarter of 2009. The 2009 results also include a decrease of $0.3 million in interest and debt expense from $75.4 million in 2008. Income from equity investments increased $4.5 million in 2009 compared to 2008. Others revenue and expense items impacting operating income are discussed above.
     Income attributable to noncontrolling interests, which represents the allocation of Buckeye’s income to its limited partner interests not owned by us or Services Company, was $92.0 million for 2009 compared to income attributable to noncontrolling interests of $154.1 million in 2008.
  Pipeline Operations
     Revenue was $392.7 million for the year ended December 31, 2009, which is an increase of $5.4 million or 1.4% from the corresponding period in 2008. Net transportation revenues were up $20.4 million, primarily due to increased tariffs and settlement experience of $37.3 million, partially offset by a $19.0 million decrease due a 5.2% decrease in transportation volumes. Tariff increases of 3.7% and 3.8% were implemented on January 1, 2009 and July 1, 2009, respectively. Revenues from a product supply arrangement, rentals and other incidental services decreased $15.1 million from the prior year period. The decrease in these revenues is primarily a result of reduced product volumes sold to a wholesale distributor and a decrease in contract service activities at customer facilities connected to our refined petroleum products pipelines.
     Total costs and expenses were $298.7 million for the year ended December 31, 2009, which is an increase of $60.8 million or 25.6% from the corresponding period in 2008. Total costs and expenses include $59.7 million of asset impairment expense and $26.2 million of reorganization expense (see Notes 8 and 3, respectively, in the Notes to Consolidated Financial Statements). Total costs and expenses also include decreases in (i) property taxes of $6.6 million primarily due to a favorable property tax settlement with the City of New York of $7.2 million (see Note 5 in the Notes to Consolidated Financial Statements); (ii) product costs of $12.0 million as a result of reduced product volumes sold to a wholesale distributor; (iii) contract service activities of $2.9 million at customer facilities connected to our refined petroleum products pipelines; (iv) operating power of $2.8 million due to a decrease in volumes; and (v) professional fees of $1.7 million. These decreases were partially offset by an increase of $2.7 million in integrity program expenditures.
     Operating income was $94.0 million for the year ended December 31, 2009 compared to operating income of $149.4 million for the year ended December 31, 2008. Asset impairment expense and reorganization expense of $59.7 million and $26.2 million, respectively, as discussed above, contributed to the decrease in operating income. Depreciation and amortization of $35.5 million for the year ended December 31, 2009 was consistent with 2008. Other revenue and expense items impacting operating income are discussed above.

58


Table of Contents

  Terminalling and Storage
     Revenue was $136.6 million for the year ended December 31, 2009, which is an increase of $17.4 million or 14.6% from the corresponding period in 2008. This increase resulted primarily from $13.5 million of revenue in 2009 from terminals that were acquired at various times in 2008 and in November of 2009 (see Note 4 in the Notes to Consolidated Financial Statements for terminal acquisitions) and increased fees and storage and rental revenue of $14.1 million. These increases were partially offset by a $7.9 million decrease in settlement experience and a 2.7% decrease in terminal volumes resulting in a $2.3 million decrease in revenues in 2009 as compared to 2008.
     Total costs and expenses were $75.5 million for the year ended December 31, 2009, which is an increase of $8.5 million or 12.6% from the corresponding period in 2008. Total costs and expenses include $2.7 million of reorganization expense (see Note 3 in the Notes to Consolidated Financial Statements) and an increase of $1.3 million in depreciation and amortization. Total costs and expenses also include an increase of $4.5 million of operating expenses for terminals acquired at various times in 2008 and in November of 2009 and an increase in remediation expenses and integrity program expenditures totaling $2.3 million.
     Operating income was $61.1 million for the year ended December 31, 2009 compared to operating income of $52.1 million for the year ended December 31, 2008. Depreciation and amortization increased $1.3 million for the year ended December 31, 2009 as a result of terminals acquired at various times in 2008. Other revenue and expense items impacting operating income are discussed above.
  Natural Gas Storage
     Revenue was $99.2 million for the year ended December 31, 2009, which is an increase of $37.4 million or 60.5% from the corresponding period in 2008. This overall increase resulted primarily from increased hub services revenues in 2009 driven by increased activity from the operations of the Kirby Hills Phase II expansion project, which was placed in service in June 2009, and the inclusion of a full year of revenue in 2009 compared to approximately eleven and one half months in the corresponding period in 2008, reflecting our purchase of Lodi Gas on January 18, 2008. Lease revenue increased $5.9 million and hub services and other revenue increased $31.5 million from the year ended December 31, 2008.
     Total costs and expenses were $68.6 million for the year ended December 31, 2009, which is an increase of $39.0 million or 132.1% from the corresponding period in 2008. Total costs and expenses include $0.5 million of reorganization expense (see Note 3 in the Notes to Consolidated Financial Statements) and an increase of $1.4 million in depreciation and amortization. Total costs and expenses include expenses from certain hub services transactions stemming from delays in the Kirby Hills Phase II expansion project and from general market conditions, increased costs from the operations of the Kirby Hills Phase II expansion project for the second half of 2009 when it was placed into service and expenses related to the timing of the acquisition of Lodi Gas, which was included in our results for a full year of activity in 2009 versus eleven and one half months in 2008.
     Operating income was $30.5 million for the year ended December 31, 2009 compared to operating income of $32.2 million for the year ended December 31, 2008. Depreciation and amortization increased $1.4 million for 2009 from the corresponding period in 2008 due to depreciation expense on the assets utilized with respect to the Kirby Hills Phase II expansion project, which was placed in service in the second half of 2009. Other revenue and expense items impacting operating income are discussed above.
  Energy Services
     Revenue was $1,125.0 million for the year ended December 31, 2009, which is a decrease of $170.9 million or 13.2% from the corresponding period in 2008. This overall decrease was primarily due to a decline in refined petroleum product prices, which correspondingly lowers the cost of products sales, partially offset by a 50.5% increase in volumes due to increased sales activity and the inclusion of a full year in 2009 compared to approximately ten and one half months in the corresponding period in 2008 following the acquisition of Farm & Home.

59


Table of Contents

     Total costs and expenses were $1,111.9 million for the year ended December 31, 2009, which is a decrease of $178.1 million or 13.8% from the corresponding period in 2008. Total costs and expenses include $1.2 million of reorganization expense (see Note 3 in the Notes to Consolidated Financial Statements) and an increase of $0.8 million in depreciation and amortization. Total costs and expenses include a decrease of $182.7 million in cost of product sales primarily related to a decrease in commodity prices in 2009 as compared to the same period in 2008. This decrease in total costs and expenses was partially offset by the inclusion of a full year of operations in 2009 compared to approximately ten and one half months in the corresponding period in 2008 following the acquisition of Farm & Home.
     Operating income was $13.1 million for the year ended December 31, 2009 compared to operating income of $5.9 million for the year ended December 31, 2008. Depreciation and amortization increased $0.8 million for 2009 from the corresponding period in 2008 due to amortization of software that was placed in service in the fourth quarter of 2009. Other revenue and expense items impacting operating income are discussed above.
  Development and Logistics
     Revenue, which consists principally of our contract operations and engineering services for third-party pipelines, was $34.1 million for the year ended December 31, 2009, which is a decrease of $9.4 million or 21.5% from the corresponding period in 2008. The decrease in revenues resulted from reduced operating services and a reduction in construction contract revenues, reflecting a customer’s termination of a contract in the second quarter of 2008. These construction activities are principally conducted on a time and material basis.
     Total costs and expenses were $29.1 million for the year ended December 31, 2009, which is a decrease of $7.6 million or 20.7% from the corresponding period in 2008. Total costs and expenses include $1.5 million of reorganization expense (see Note 3 in the Notes to Consolidated Financial Statements). The decrease in total costs and expenses compared to 2008 are a result of reduced operating expenses associated with a terminated customer contract, reduced construction contract activity and reduced operating services activities.
     Operating income was $5.1 million for the year ended December 31, 2009 compared to operating income of $6.9 million for the year ended December 31, 2008. Depreciation and amortization of $1.7 million for the year ended December 31, 2009 was relatively consistent with the same period in 2008, and income taxes decreased $1.1 million for the year ended December 31, 2009 due to lower earnings in the 2009 period. Other revenue and expense items impacting operating income are discussed above.
  2008 Compared to 2007
  Consolidated
     Consolidated income attributable to our Unitholders was $26.5 million for the year ended December 31, 2008 compared to $22.9 million for the year ended December 31, 2007. The increase in income attributable to our Unitholders was due to increases in Buckeye’s quarterly distribution. As mentioned above, the incentive distribution rights entitle us to receive amounts equal to specified percentages of the incremental amount of cash distributed by Buckeye to the holders of Buckeye’s LP Units when target distribution levels for a quarter are exceeded. As a result, increases in Buckeye’s distributions causes increases in income attributable to our Unitholders. During 2008, Buckeye paid a $3.43 per LP Unit distribution as compared to a $3.23 per LP Unit distribution in 2007, which resulted in an increase of $8.9 million in incentive distribution rights in 2008 as compared to 2007.
     Revenue was $1,896.7 million for the year ended December 31, 2008, which is an increase of $1,377.3 million or 265.2% from the year ended December 31, 2007. This overall increase was caused primarily by revenues from our Energy Services and Natural Gas Storage segments of $1,295.9 million and $61.8 million due to the acquisitions of Farm & Home and Lodi Gas, respectively, in 2008. The Terminalling and Storage segment revenues increased $15.4 million from the acquisition of terminals in 2008 and 2007, and the Pipeline Operations segment revenues increased $7.9 million due to increased tariffs. The Development and Logistics segment reported higher revenue of $7.3 million due to increased construction activities.

60


Table of Contents

     Total costs and expenses were $1,650.2 million for the year ended December 31, 2008, which is an increase of $1,326.2 million or 409.3% from the year ended December 31, 2007. Total costs and expenses include expenses of $1,290.0 million and $29.6 million due to the acquisitions for Farm & Home and Lodi Gas, respectively, in 2008 in the Energy Services segment and the Natural Gas Storage segment, respectively. Total costs and expenses also includes increased payroll and benefits expenses resulting primarily from an increase in the number of employees due to our expanded operations, increased casualty losses due to an increase in the cost of remediating environmental incidents and increased construction management costs resulting from an increase in construction contracts that were substantially completed at December 31, 2008, partially offset by a decrease in pipeline and terminal maintenance activities, decreased operating power costs due to lower volumes transported in the Pipeline Operations segment, and decreased supplies expenses due to decreased throughput at our terminals in the Terminalling and Storage segment.
     Operating income was $246.5 million for the year ended December 31, 2008 compared to operating income of $195.4 million for the year ended December 31, 2007. The 2008 period results also include an increase of $23.7 million in interest and debt expense from $51.7 million in 2007. Approximately $17.7 million of the increase was attributable to expenses associated with Buckeye’s 6.050% Notes which were issued by Buckeye in January 2008. The remainder of the increase is due to interest expense related to working capital requirements of the Energy Services segment and amounts outstanding under Buckeye’s Credit Facility. Income from equity investments increased $0.4 million primarily due to increased equity income earned from our interest in WT LPG. In addition, depreciation and amortization increased by $10.6 million due to acquisitions made during 2008.
     Income attributable to noncontrolling interests, which represents the allocation of Buckeye’s income to its limited partner interests not owned by us or Services Company, was $154.2 million for 2008 compared to income attributable to noncontrolling interests of $129.8 million in 2007.
  Pipeline Operations
     Revenue was $387.3 million for the year ended December 31, 2008, which is an increase of $7.9 million or 2.1% from the corresponding period in 2007. Net transportation revenues increased $1.2 million in 2008 compared to 2007 primarily as a result of tariff increases implemented on May 1, 2008 and July 1, 2008. The benefit of the tariff increases were substantially offset by reduced product volumes of 4.5% in 2008 as compared to 2007. We believe that the reduced volumes in 2008 were caused primarily by reduced demand for gasoline resulting from higher retail gasoline prices, reduced production at ConocoPhillip’s Wood River Refinery due to maintenance activities, and the continued introduction of ethanol into retail gasoline products as well as reduced demand for distillates resulting from higher retail distillate prices and the slowdown in the U.S. economy. Incidental revenues increased $4.7 million principally related to a product supply arrangement, and revenues from additional construction management and rental revenues increased $1.5 million from the corresponding period in 2007.
     Total costs and expenses were $237.9 million for the year ended December 31, 2008, which is an increase of $5.5 million or 2.3% from the corresponding period in 2007. Total costs and expenses include an increase of $2.2 million in depreciation and amortization. The increase in total costs and expenses is primarily attributable to: (i) an increase of $4.6 million primarily associated with fuel purchases related to a product supply arrangement; (ii) an increase of $2.3 million in casualty losses, which is due to an increase in the cost of remediating environmental incidents compared to 2007, as well as $0.5 million related to a product contamination incident that occurred in the third quarter of 2008; and (iii) an increase of $1.2 million in payroll and payroll benefits primarily resulting from an increase in the number of employees due to our expanded operations. These increases were partially offset by a decrease of $2.8 million in pipeline maintenance activities compared to 2007 and a decrease of $1.0 million in operating power costs due to lower volumes transported.
     Operating income was $149.4 million for the year ended December 31, 2008 compared to operating income of $146.9 million for the year ended December 31, 2007. Depreciation and amortization increased $2.2 million for the year ended December 31, 2008 from the corresponding period in 2007 due to our ongoing expansion capital program. Other revenue and expense items impacting operating income are discussed above.

61


Table of Contents

  Terminalling and Storage
     Revenue was $119.2 million for the year ended December 31, 2008, which is an increase of $15.4 million or 14.8% from the corresponding period in 2007. This overall increase resulted primarily from (i) $6.5 million of incremental revenue in 2008 from the acquisitions of the Niles, Michigan, Ferrysburg, Michigan, Wethersfield, Connecticut, and Albany, New York terminals in 2008, combined with the effect of having a full year of revenue in 2008 from the six terminals that were acquired at in the first quarter of 2007; (ii) $6.1 million of revenue related to increases in blending fees for product additives and product recoveries from vapor recovery units, which were offset by an approximately 5.4% decline in throughput volumes, caused in part by increased commodity prices, in 2008 compared to 2007; and (iii) $2.8 million from the settlement of a dispute with a customer regarding product handling charges.
     Total costs and expenses were $67.0 million for the year ended December 31, 2008, which is an increase of $3.8 million or 6.0% from the corresponding period in 2007. Total costs and expenses include an increase of $0.4 million in depreciation and amortization. The increase in total costs and expenses is primarily due to an increase of $2.1 million in operating expenses for the terminal acquisitions made at various times in 2007 and 2008 and an increase of $1.6 million in payroll and payroll benefits in 2008 resulting primarily from an increase in the number of employees due to our expanded operations, partially offset by a decrease of $1.2 million in terminal additive expense related to decreased throughput volumes at our terminals.
     Operating income was $52.1 million for the year ended December 31, 2008 compared to operating income of $40.6 million for the year ended December 31, 2007. Depreciation and amortization of $6.0 million increased during the year ended December 31, 2008 by $0.4 million from $5.6 million for the year ended December 31, 2007 as a result of terminals acquired at various times in 2008 and 2007. Other revenue and expense items impacting operating income are discussed above.
  Natural Gas Storage
     Revenue was $61.8 million for the year ended December 31, 2008. Approximately 70.2% of this revenue represented lease storage revenues and 29.8% represented hub services revenues. All of this revenue was derived from Lodi Gas’ operations, which we acquired on January 18, 2008.
     Total costs and expenses were $29.6 million for the year ended December 31, 2008. Costs and expenses were from Lodi Gas’ legacy operations, which we acquired on January 18, 2008, and included $4.6 million of depreciation and amortization and $4.6 million of non-cash deferred lease expense. The Natural Gas Storage segment incurred $4.1 million of payroll and payroll benefits expense, $4.2 million of outside services costs, of which $3.2 million related to well work-over costs, $2.4 million of property and other taxes, $2.7 million of rental expense, $0.9 million of insurance costs and $3.6 million of other costs in 2008.
     Operating income was $32.2 million for the year ended December 31, 2008. Depreciation and amortization was $4.6 million for the year ended December 31, 2008. Other revenue and expense items impacting operating income are discussed above.
  Energy Services
     Revenue was $1,295.9 million for the year ended December 31, 2008. Substantially all of this revenue was derived from Farm & Home’s legacy wholesale operations, which we acquired on February 8, 2008. During 2008, approximately 435.2 million gallons of products were sold. Products sold include gasoline, propane and petroleum distillates such as heating oil, diesel fuel and kerosene.
     Total costs and expenses were $1,290.0 million for the year ended December 31, 2008 and included $3.4 million of depreciation and amortization. Substantially all of these costs and expenses were derived from Farm & Home’s legacy wholesale operations. Approximately $1,269.6 million was attributable to products sold by the Energy Services segment. Additionally, the Energy Services segment incurred $7.3 million of payroll and payroll benefits expense, $1.1 million of outside service costs, $0.7 million of property and other taxes, $0.6 million of rental expense, $0.4 million of insurance costs and $6.9 million of other costs in 2008.

62


Table of Contents

     Operating income was $5.9 million for the year ended December 31, 2008. Depreciation and amortization was $3.4 million for the year ended December 31, 2008. Other revenue and expense items impacting operating income are discussed above.
  Development and Logistics
     Revenue was $43.5 million for the year ended December 31, 2008, which is an increase of $7.3 million or 20.1% from the corresponding period in 2007. The increase in revenues in 2008 was primarily the result of an increase of $7.0 million in construction management revenue related to construction contracts that were substantially completed at December 31, 2008. These construction activities are principally conducted on a time and material basis.
     Total costs and expenses were $36.7 million for the year ended December 31, 2008, which is an increase of $8.3 million or 29.3% from the corresponding period in 2007. Total costs and expenses include $1.6 million of depreciation and amortization. The increase in total costs and expenses is associated with increased construction contract activity. Construction management costs were $12.6 million in 2008, which is an increase of $5.3 million over 2007. The increase in 2008 was primarily the result of an increase in construction contracts that were substantially completed at December 31, 2008. Additionally, outside services costs increased $2.4 million and payroll and payroll benefits expense increased approximately $0.7 million due to the increased construction activities.
     Operating income was $6.9 million for the year ended December 31, 2008 compared to operating income of $7.9 million for the year ended December 31, 2007. Depreciation and amortization was $1.6 million for the year ended December 31, 2008, which was relatively consistent with the same period in 2008. Income tax expense of $0.8 million was consistent with the same period in 2007. Other revenue and expense items impacting operating income are discussed above.
Liquidity and Capital Resources
  BGH
     We currently have no capital requirements apart from Buckeye’s capital requirements. Buckeye’s capital requirements consist of maintenance and capital expenditures, expenditures for acquisitions and debt service requirements.
     Our only cash-generating asset is our ownership interest in Buckeye GP. Our cash flow is, therefore, directly dependent upon the ability of Buckeye and its Operating Subsidiaries to make cash distributions to Buckeye’s partners. The actual amount of cash that Buckeye will have available for distribution depends primarily on Buckeye’s ability to generate cash beyond its working capital requirements. Buckeye’s primary future sources of liquidity are cash flows from operations, proceeds from borrowings under Buckeye’s Credit Facility and proceeds from the issuance of its LP Units or public debt.
     Our principal uses of cash are the payment of our operating expenses and distributions to our Unitholders. We generally make quarterly cash distributions of substantially all of our available cash, generally defined as consolidated cash receipts less consolidated cash expenditures and such retentions for working capital, anticipated cash expenditures and contingencies as MainLine Management deems appropriate. In 2009, we paid cash distributions of $0.39 per unit on November 30, 2009, $0.37 per unit on August 31, 2009, $0.35 per unit on May 29, 2009 and $0.33 per unit on February 28, 2009. In 2008, we paid cash distributions of $0.32 per unit on November 28, 2008, $0.31 per unit on August 29, 2008, $0.30 per unit on May 30, 2008 and $0.285 per unit on February 29, 2008. Total cash distributed to our Unitholders for the years ended December 31, 2009 and 2008 was approximately $40.8 million and $34.4 million, respectively.
  Buckeye
     Buckeye’s primary cash requirements, in additional to normal operating expenses and debt service, are for working capital, capital expenditures, business acquisitions and distributions to partners. Buckeye’s principal

63


Table of Contents

sources of liquidity are cash from operations, borrowings under its Credit Facility and proceeds from the issuance of its LP Units. Buckeye will, from time to time, issue debt securities to permanently finance amounts borrowed under the Credit Facility. BES funds its working capital needs principally from operations and the BES Credit Agreement. Buckeye’s financial policy has been to fund sustaining capital expenditures with cash from operations. Expansion and cost improvement capital expenditures, along with acquisitions, have typically been funded from external sources including the Credit Facility as well as debt and equity offerings. Buckeye’s goal has been to fund at least half of these expenditures with proceeds from equity offerings in order to maintain its investment-grade credit rating.
     Buckeye continues to evaluate the conditions of the debt and equity capital markets, and in March 2009, Buckeye issued 2.6 million LP Units in an underwritten public offering at $35.08 per LP Unit. On April 29, 2009, the underwriters of the equity offering exercised their option to purchase an additional 390,000 LP Units at $35.08 per LP Unit. Total proceeds from the offering, including the overallotment option and after the underwriter’s discount of $1.17 per LP Unit and offering expenses, were approximately $104.6 million, and were used to reduce amounts outstanding under Buckeye’s Credit Facility. In August 2009, Buckeye sold 5.500% Notes in an underwritten public offering. The 5.500% Notes were issued at 99.35% of their principal amount. Total proceeds from the offering, after underwriters’ fees, expenses and debt issuance costs of $1.8 million, were approximately $271.4 million, and were used to reduce amounts outstanding under Buckeye’s Credit Facility and for general partnership purposes.
     As a result of our actions to minimize external financing requirements and the fact that no debt facilities mature prior to 2011, we believe that availabilities under our credit facilities, coupled with ongoing cash flows from operations, will be sufficient to fund our operations for 2010. We will continue to evaluate a variety of financing sources, including the debt and equity markets described above, throughout 2010. However, continuing volatility in the debt and equity markets will make the timing and cost of any such potential financing uncertain.
  Debt
     BGH
     At December 31, 2009 and 2008, we had no amounts outstanding under the BGH Credit Agreement. See Note 13 in the Notes to Consolidated Financial Statements for a description of the terms of our BGH Credit Agreement.
     Services Company
     At December 31, 2009 and 2008, Services Company had total debt outstanding of $7.7 million and $14.0 million, respectively, consisting of 3.60% Senior Secured Notes (the “3.60% ESOP Notes”) due March 28, 2011 payable by the ESOP to a third-party lender. The 3.60% ESOP Notes were issued on May 4, 2004. The 3.60% ESOP Notes are collateralized by Services Company’s common stock and are guaranteed by Services Company. In addition, Buckeye has committed that, in the event that the value of Buckeye’s LP Units owned by Services Company falls below 125% of the balance payable under the 3.60% ESOP Notes, Buckeye will fund an escrow account with sufficient assets to bring the value of the total collateral (the value of Buckeye’s LP Units owned by Services Company and the escrow account) up to the 125% minimum. Amounts deposited in the escrow account are returned to Buckeye when the value of Buckeye’s LP Units owned by Services Company’s returns to an amount that exceeds the 125% minimum. At December 31, 2009, the value of Buckeye’s LP Units owned by Services Company exceeded the 125% requirement.
     Buckeye’s Outstanding Debt
     At December 31, 2009, Buckeye had $34.6 million of cash and cash equivalents on hand and approximately $401.9 million of available credit under its Credit Facility, after application of the facility’s funded debt ratio covenant. In addition, BES had $10.2 million of available credit under the BES Credit Agreement, pursuant to certain borrowing base calculations under that agreement. See Note 13 in the Notes to Consolidated Financial Statements for further information about these credit facilities.

64


Table of Contents

     At December 31, 2009, Buckeye had an aggregate face amount of $1,742.8 million of debt, which consisted of the following:
    $300.0 million of the 4.625% Notes due 2013 (the “4.625% Notes”);
 
    $275.0 million of the 5.300% Notes due 2014 (the “5.300% Notes”);
 
    $125.0 million of the 5.125% Notes due 2017 (the “5.125% Notes”);
 
    $300.0 million of the 6.050% Notes due 2018 (the “6.050% Notes”);
 
    $275.0 million of the 5.500% Notes due 2019;
 
    $150.0 million of the 6.750% Notes due 2033 (the “6.750% Notes”);
 
    $78.0 million outstanding under Buckeye’s Credit Facility; and
 
    $239.8 million outstanding under the BES Credit Agreement.
     See Note 13 in the Notes to Consolidated Financial Statements for more information about the terms of the debt discussed above.
     The fair values of Buckeye’s aggregate debt and credit facilities were estimated to be $1,762.1 million and $1,367.7 million at December 31, 2009 and 2008, respectively. The fair values of the fixed-rate debt at December 31, 2009 and 2008 were estimated by market-observed trading prices and by comparing the historic market prices of Buckeye’s publicly-issued debt with the market prices of other MLPs’ publicly-issued debt with similar credit ratings and terms. The fair values of Buckeye’s variable-rate debt are their carrying amounts as the carrying amount reasonably approximates fair value due to the variability of the interest rate.
  Registration Statement
     Buckeye may issue equity or debt securities to assist it in meeting its liquidity and capital spending requirements. Buckeye has a universal shelf registration statement on file with the SEC that would allow it to issue an unlimited amount of debt and equity securities for general partnership purposes.
  Credit Ratings
     Buckeye’s debt securities are rated BBB by Standard & Poor’s Ratings Service and Baa2 by Moody’s Investors Service, Inc., both with stable outlooks. Such ratings reflect only the view of the rating agency and should not be interpreted as a recommendation to buy, sell or hold Buckeye’s securities. These ratings may be revised or withdrawn at any time by the agencies at their discretion and should be evaluated independently of any other rating.
  Cash Flows from Operating, Investing and Financing Activities
     The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated (in thousands):
                         
    Year Ended December 31,  
    2009     2008     2007  
Cash provided by (used in):
                       
Operating activities
  $ 47,662     $ 208,557     $ 191,736  
Investing activities
    (144,203 )     (735,776 )     (108,605 )
Financing activities
    72,834       494,014       (8,865 )

65


Table of Contents

     Operating Activities
     2009 Compared to 2008. Net cash flow provided by operating activities was $47.7 million for the year ended December 31, 2009 compared to $208.6 million for the year ended December 31, 2008. The following were the principal factors resulting in the $160.9 million decrease in net cash flows provided by operating activities:
    We recognized $32.1 million of reorganization expenses in the 2009 period.
 
    The net change in fair values of derivatives was an increase of $20.5 million, resulting from the decrease in value related to fixed-price sales contracts compared to a lower level of opposite fluctuations in futures contracts purchased to hedge such fluctuations.
 
    The net impact of working capital changes was a decrease of $229.7 million to cash flows from operating activities for the year ended December 31, 2009. The principal factors affecting the working capital changes were:
    Inventories increased $177.3 million due to an increase in inventory purchases within the Energy Services segment which are hedged with futures contracts that expire primarily in the winter months. As a result of energy market conditions, we significantly increased our physical inventory purchases in 2009.
 
    Trade receivables increased $44.1 million primarily due to increased activity from our Energy Services segment due to higher volumes in the 2009 period.
 
    Prepaid and other current assets increased $28.9 million primarily due to increases in prepaid services and unbilled revenue within the Natural Gas Storage segment and an increase in receivables due to a favorable property tax settlement, partially offset by a decrease in a receivable related to ammonia purchases and a decrease in margin deposits on futures contracts in our Energy Services segment.
 
    Accrued and other current liabilities increased $1.3 million primarily due to costs related to the reorganization.
 
    Accounts payable increased $14.6 million due to activity within the Energy Services segment.
 
    Construction and pipeline relocation receivables decreased $7.4 million primarily due to a decrease in construction activity in the 2009 period.
     2008 Compared to 2007. Net cash flow provided by operating activities was $208.6 million for the year ended December 31, 2008 compared to $191.7 million for the year ended December 31, 2008. The following were the principal factors resulting in the $16.9 million increase in net cash flows provided by operating activities:
    Our net income increased $27.9 million for the year ended December 31, 2008 compared with the year ended December 31 2007, primarily due to our acquisitions of Lodi Gas and Farm & Home in 2008.
 
    The net change in fair values of derivatives was a decrease of $24.2 million, resulting from the increase in value related to fixed-price sales contracts compared to a lower level of opposite fluctuations in futures contracts purchased to hedge such fluctuations. We did not utilize futures contracts to economically hedge a portion of the fixed-price sales contracts because we had purchased inventory to fulfill a portion of those commitments.
 
    The net impact of working capital changes was a decrease of $6.4 million to cash flows from operations for the year ended December 31, 2008. The principal factors affecting the working capital changes were:
    Prepaid and other current assets increased $27.8 million, primarily due to an increase in a receivable related to ammonia purchases as well as additional margin deposits associated with liabilities for derivative instruments.
 
    Construction and pipeline relocation receivables increased $8.9 million due to an increase in construction activity in the latter part of 2008.
 
    Inventories increased $4.4 million due to inventory purchases within the Energy Services segment.
 
    Accounts payable decreased $10.6 million due to activity within the Energy Services segment since the acquisition of Farm & Home.
 
    Trade receivables decreased $36.1 million due to an increase in collections within the Energy Services segment since the acquisition of Farm & Home.

66


Table of Contents

    Accrued and other current liabilities increased $9.3 million primarily due to increases in accrued taxes, environmental liabilities and interest expense.
     Investing Activities
     2009 Compared to 2008. Net cash flow used in investing activities was $144.2 million for the year ended December 31, 2009 compared to $735.8 million for the year ended December 31, 2008. The following were the principal factors resulting in the $591.6 million decrease in net cash flows used in investing activities:
    Cash used for acquisitions and equity investments, net of cash acquired, was $58.3 million for the year ended December 31, 2009, of which $54.4 million was used for the acquisition of refined petroleum product terminals and pipeline assets from ConocoPhillips. We also invested an additional $3.9 million in WT LPG in 2009. Cash used for acquisitions and equity investments, net of cash acquired, was $667.5 million for the year ended December 31, 2008, of which $438.8 million was used for the acquisition of Lodi Gas, $143.3 million was used for the acquisition of Farm & Home and an aggregate of $75.6 million was used for the acquisitions of four terminals in Albany, New York, Niles and Ferrysburg, Michigan, and Wethersfield, Connecticut and the acquisition of the remaining 50% member interest in Wespac — San Diego that we did not already own. We also invested an additional $9.8 million in WT LPG in 2008. See Note 4 in the Notes to Consolidated Financial Statements for further information.
 
    Capital expenditures decreased $33.2 million for the year ended December 31, 2009 compared with the year ended December 31, 2008. See below for a discussion of capital spending.
 
    Cash proceeds from the sale of the retail operations of Farm & Home was $52.6 million.
     2008 Compared to 2007. Net cash flow used in investing activities was $735.8 million for the year ended December 31, 2008 compared to $108.6 million for the year ended December 31, 2007. The following were the principal factors resulting in the $627.2 million increase in net cash flows used in investing activities:
    Cash used for acquisitions and equity investments, net of cash acquired was $667.5 million for the year ended December 31, 2008 as discussed above. Cash used for acquisitions and equity investments, net of cash acquired was $40.7 million for the year ended December 31, 2007, of which $39.8 million was used for the acquisition of terminals and related assets and $0.9 million was used for an additional investment in WT LPG. See Note 4 in the Notes to Consolidated Financial Statements for further information.
 
    Capital expenditures increased $52.6 million for the year ended December 31, 2008 compared with the year ended December 31, 2007. See below for a discussion of capital spending.
 
    Cash proceeds from the sale of the retail operations of Farm & Home was $52.6 million.
     Capital expenditures are summarized below (net of non-cash changes in accruals for capital expenditures for the years ended December 31, 2009, 2008 and 2007) for the periods indicated (in thousands):
                         
    Year Ended December 31,  
    2009     2008     2007  
Sustaining capital expenditures
  $ 23,496     $ 28,936     $ 33,838  
Expansion and cost reduction
    63,813       91,536       34,029  
 
                 
Total
  $ 87,309     $ 120,472     $ 67,867  
 
                 
     In 2009 and 2008, expansion and cost reduction projects included the Kirby Hills Phase II expansion project, ethanol and butane blending projects at certain of our terminals, the construction of three additional tanks with capacity of 0.4 million barrels in Linden, New Jersey and various other pipeline and terminal operating infrastructure projects. Construction costs of the Kirby Hills Phase II expansion project in 2009 and 2008 totaled approximately $17.0 million and $49.6 million, respectively. In 2007, expansion and cost reduction projects included a capacity expansion project in Illinois to handle additional liquefied petroleum gas volumes and ongoing capacity improvements at facilities to serve the Memphis International Airport.

67


Table of Contents

     We expect to spend approximately $90.0 million to $110.0 million for capital expenditures in 2010, of which approximately $25.0 million to $35.0 million is expected to relate to sustaining capital expenditures and $65.0 million to $75.0 million is expected to relate to expansion and cost reduction projects. Sustaining capital expenditures include renewals and replacement of pipeline sections, tank floors and tank roofs and upgrades to station and terminalling equipment, field instrumentation and cathodic protection systems. Major expansion and cost reduction expenditures in 2010 will include the completion of additional product storage tanks in the Midwest, the construction of a 4.4 mile pipeline in central Connecticut to connect our pipeline in Connecticut to a third party electric generation plant currently under construction, various terminal expansions and upgrades and pipeline and terminal automation projects.
     Financing Activities
     2009 Compared to 2008. Net cash flow provided by financing activities was $72.8 million for the year ended December 31, 2009 compared to $494.0 million for the year ended December 31, 2008. The following were the principal factors resulting in the $421.2 million decrease in net cash flows provided by financing activities:
    Borrowings were $317.1 million and $558.6 million and repayments were $537.4 million and $260.3 million under Buckeye’s Credit Facility in 2009 and 2008, respectively. Repayments under the Services Company 3.60% ESOP Notes were $6.3 million in each of 2009 and 2008. There were no borrowings or repayments under the BGH Credit Agreement in 2009 and 2008.
 
    Net borrowings under the BES Credit Agreement were $143.8 million in 2009, while net repayments under the BES Credit Agreement (and its predecessor facility which was replaced in May 2008) were $4.0 million in 2008.
 
    We received $271.4 million (net of debt issuance costs of $1.8 million) from Buckeye’s issuance in August 2009 of $275.0 million in aggregate principal amount of the 5.500% Notes in an underwritten public offering. Proceeds from this offering were used to reduce amounts outstanding under Buckeye’s Credit Facility. We received $298.0 million from Buckeye’s issuance in January 2008 of $300.0 million in aggregate principal amount of the 6.050% Notes in an underwritten public offering. Proceeds from this offering were used to partially pre-fund the Lodi Gas acquisition. In connection with this debt offering, we settled two interest rate swaps associated with the 6.050% Notes, which resulted in a settlement payment of $9.6 million that is being amortized as interest expense over the ten-year term of the 6.050% Notes.
 
    We received $104.6 million in net proceeds from Buckeye’s underwritten equity offering in March 2009 from the public issuance of 3.0 million LP Units. In 2008, we received $113.1 million in net proceeds from Buckeye’s public issuance of 2.6 million LP Units.
 
    Distributions to noncontrolling interests, consisting primarily of Buckeye’s distributions to holders of its LP Units, were $180.0 million in 2009 compared to $159.3 million in 2008. The increase in distributions resulted primarily from increases in Buckeye’s per LP Unit distribution rate and the issuance of 3.0 million LP Units in 2009.
 
    Cash distributions paid to our partners increased $6.4 million year-to-year due to an increase in our quarterly cash distribution rate per Common Unit. We paid cash distributions of $40.9 million ($1.44 per Common Unit) and $34.4 million ($1.22 per Common Unit) during the years ended December 31, 2009 and 2008, respectively.
     2008 Compared to 2007. Net cash flow provided by financing activities was $494.0 million for the year ended December 31, 2008 compared to net cash used in financing activities of $8.9 million for the year ended December 31, 2007. The following were the principal factors resulting in the $502.9 million increase in net cash flows provided by financing activities:
    Borrowings were $558.6 million and $155.0 million and repayments were $260.3 million and $300.0 million under Buckeye’s Credit Facility (and its predecessor facility) in 2008 and 2007, respectively. Repayments under the Services Company 3.60% ESOP Notes were $6.3 million in 2008 and $6.0 million in 2007. Borrowings and repayments under the BGH Credit Agreement were $2.5 million in 2007. There were no borrowings or repayments under the BGH Credit Agreement in 2008.

68


Table of Contents

    Net repayments under the BES Credit Agreement (and its predecessor facility which was replaced in May 2008) were $4.0 million in 2008.
 
    We received $298.1 million from Buckeye’s issuance in January 2008 of $300.0 million in aggregate principal amount of the 6.050% Notes in an underwritten public offering as discussed above.
 
    We received $113.1 million in net proceeds from Buckeye’s underwritten equity offering in March 2008 from the public issuance of 2.6 million LP Units. In 2007, we received $296.4 million in net proceeds from Buckeye’s underwritten equity offerings in March, August and December 2007 from the public issuance of 6.2 million LP Units.
 
    Distributions to noncontrolling interests, consisting primarily of Buckeye’s distributions to holders of its LP Units, were $159.3 million in 2008 compared to $128.8 million in 2007. The increase in distributions resulted primarily from increases in Buckeye’s per LP Unit distribution rate and the issuance of 2.6 million LP Units in 2008.
 
    Cash distributions paid to our partners increased $6.7 million year-to-year due to an increase in our quarterly cash distribution rate per Common Unit. We paid cash distributions of $34.4 million ($1.22 per Common Unit) and $27.7 million ($0.98 per Common Unit) during the years ended December 31, 2008 and 2007, respectively.
Derivatives
     See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk — Market Risk — Non Trading Instruments” for a discussion of commodity derivatives used by our Energy Services segment.
Critical Accounting Policies
     The preparation of consolidated financial statements in conformity with GAAP 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. The following describes the estimated risks underlying our critical accounting policies and estimates:
  Depreciation Methods, Estimated Useful Lives and Disposals of Property, Plant and Equipment
     In general, depreciation is the systematic and rational allocation of an asset’s cost or fair value, less its residual value (if any), to the periods it benefits. Property, plant and equipment consist primarily of pipelines, wells, storage and terminal facilities, pad gas and pumping and compression equipment. Depreciation on pipelines and terminals is generally calculated using the straight-line method over the estimated useful lives ranging from 44 to 50 years. Plant and equipment associated with our natural gas storage business is generally depreciated over 44 years, except for pad gas. The Natural Gas Storage segment maintains a level of natural gas in its underground storage facility generally known as pad gas, which is not routinely cycled but, instead, serves the function of maintaining the necessary pressure to allow routine injection and withdrawal to meet demand. Pad gas is considered to be a component of the facility and as such is not depreciated because it is expected to ultimately be recovered and sold. Other plant and equipment is generally depreciated on a straight-line basis over an estimated life of 5 to 50 years. Straight line depreciation results in depreciation expense being incurred evenly over the life of an asset.
     Additions to property, plant and equipment, including major replacements or betterments, are recorded at cost. We charge maintenance and repairs to expense in the period incurred. The cost of property, plant and equipment sold or retired and the related depreciation, except for certain pipeline system assets, are removed from our consolidated balance sheet in the period of sale or disposition, and any resulting gain or loss is included in income. For our pipeline system assets, we generally charge the original cost of property sold or retired to accumulated depreciation and amortization, net of salvage and cost of removal. When a separately identifiable group of assets, such as a stand-alone pipeline system, is sold, we will recognize a gain or loss in our consolidated statements of operations for the difference between the cash received and the net book value of the assets sold.
     The determination of an asset’s useful life requires assumptions regarding a number of factors including technological change, normal depreciation and actual physical usage. If any of these assumptions subsequently change, the estimated useful life of the asset could change and result in an increase or decrease in depreciation expense that could have a material impact on our consolidated financial statements.

69


Table of Contents

     At both December 31, 2009 and 2008, the net book value of our property, plant and equipment was $2.2 billion. Property, plant and equipment is generally recorded at its original acquisition cost and its carrying value accounted for approximately 64.2% of our consolidated assets at December 31, 2009. Depreciation expense was $50.9 million, $47.42 million and $39.6 million for the years ended December 31, 2009, 2008 and 2007, respectively. We do not believe that there is a reasonable likelihood that there will be a material change in the future estimated useful life of our property, plant and equipment. In the past, we have generally not deemed it necessary to materially change the depreciable lives of our assets. An increase or decrease in the depreciable lives of these assets, for example a 5-year increase or decrease in the depreciable lives of our pipeline assets, currently estimated as 50 years, would decrease or increase, respectively, annual depreciation expense, and increase or decrease operating income, respectively, by approximately $5.0 million annually.
  Reserves for Environmental Matters
     We 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 existing conditions caused by past operations, and which 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 based upon past experience and advice of outside engineering, consulting and law firms. Generally, the timing of these accruals coincides with our 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. Historically, our estimates of direct and indirect costs related to remediation efforts have generally not required material adjustments. However, the accounting estimates related to environmental matters are uncertain because (1) estimated future expenditures related to environmental matters are subject to cost fluctuations and can change materially, (2) unanticipated liabilities may arise in connection with environmental remediation projects and may impact cost estimates, and (3) changes in federal, state and local environmental laws and regulations can significantly increase the cost or potential liabilities related to environmental matters. None of our estimated environmental remediation liabilities are discounted to present value since the ultimate amount and timing of cash payments for such liabilities are not readily determinable. We maintain insurance that may cover certain environmental expenditures.
     During the years ended December 31, 2009, 2008 and 2007, we incurred environmental expenses, net of insurance recoveries, of $10.6 million, $10.1 million and $7.4 million, respectively. At December 31, 2009 and 2008, we had accrued $29.9 million and $27.0 million, respectively, 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. Changes in estimates of environmental remediation for each remediation project will affect operating income on a dollar-for-dollar basis up to our self-insurance limit. Our self-insurance limit is currently $3.0 million per occurrence.
  Fair Value of Derivatives
     Our Energy Services segment primarily uses exchange-traded refined petroleum product futures contracts to manage the risk of market price volatility on its refined petroleum product inventories and its fixed-price sales contracts. See Note 8 in the Notes to Consolidated Financial Statements for further discussion. The Energy Services segment has not used hedge accounting with respect to its fixed-price sales contracts. Therefore, its fixed-price sales contracts and the related futures contracts used to offset those fixed-price sales contracts are all marked-to-market on our balance sheet with gains and losses being recognized in earnings during the period. At December 31, 2009, we included in our consolidated financial statements as assets fixed-price sales contracts with asset values of approximately $2.4 million. We have entered into futures contracts to hedge against changes in value of these fixed price sales contracts. These futures contracts have a net value of approximately $7.1 million at December 31, 2009 and have been recognized as assets on our balance sheet. We have determined that the exchange-traded futures contracts represent Level 1 fair value measurements because the prices for such futures contracts are established on liquid exchanges with willing buyers and sellers and with prices which are readily available on a daily basis.

70


Table of Contents

     We have determined that the fixed-price sales contracts represent Level 2 fair value measurements because their value is derived from similar contracts for similar delivery and settlement terms which are traded on established exchanges. However, because the fixed-price sales contracts are privately negotiated with customers of the Energy Services segment who are generally smaller, private companies that may not have established credit ratings, the determination of an adjustment to fair value to reflect counterparty credit risk (a “credit valuation adjustment”) requires significant management judgment. At December 31, 2009, we had reduced the fair value of the fixed-price sales contracts by a $0.9 million credit valuation adjustment to reflect this counterparty credit risk. The delivery periods for the contracts range from one to 13 months, with the substantial majority of deliveries concentrated in the first four months of 2010.
     Because little or no public credit information is available for the Energy Services segment’s customers who have fixed-price sales contracts, we specifically analyzed each customer and contract to evaluate (i) the historical payment patterns of the customer, (ii) the current outstanding receivables balances for each customer and contract and (iii) the level of performance of each customer with respect to volumes called for in the contract. We then evaluated the specific risks and expected outcomes of nonpayment or nonperformance by each customer and contract. Based on our credit and performance risk evaluation, we recorded the credit valuation adjustment of $0.9 million. If actual customer performance under these fixed-price sales contracts deteriorates (either through nonperformance with respect to contracted volumes or nonpayment of amounts due), then the fair value of these contracts could be materially less. For example, a 10% shortfall in delivered volumes over the average life of the contracts would reduce the fair value of the contracts and, accordingly, net income, by $0.2 million. We continue to monitor and evaluate performance and collections with respect to these fixed-price sales contracts.
  Measuring the Fair Value of Goodwill
     Goodwill represents the excess of purchase prices paid by us in certain business combinations over the fair values assigned to the respective net tangible and identifiable intangible assets. We do not amortize goodwill; rather, we test our goodwill (at the reporting unit level) for impairment on January 1 of each fiscal year, and more frequently if circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. Goodwill is tested for impairment at a level of reporting referred to as a reporting unit. A reporting unit is a business segment or one level below a business segment for which discrete financial information is available and regularly reviewed by segment management. Our reporting units are our business segments. An estimate of the fair value of a reporting unit is determined using a combination of a market multiple valuation method and an expected present value of future cash flows valuation method. The principal assumptions utilized in this valuation model include: (1) discrete financial forecasts for the assets contained within the reporting unit, which rely on management’s estimates of revenue, operating expenses and volumes; (2) long-term growth rates for cash flows beyond the discrete forecast period; (3) appropriate discount rates; and (4) determination of appropriate market multiples from comparable companies.
     If the fair value of the reporting unit (including its inherent goodwill) is less than its carrying value, a charge to earnings is required to reduce the carrying value of the goodwill to its implied fair value. At December 31, 2009 and 2008, the carrying value of our goodwill was $432.1 million and $433.9 million, respectively. Goodwill decreased by $1.8 million as of December 31, 2009 from December 31, 2008 due to the finalization of the purchase price allocation relating to the acquisition of a terminal in Albany, New York in 2008; this $1.8 million was allocated to property, plant and equipment. We did not record any goodwill impairment charges during the years ended December 31, 2009, 2008 and 2007. A 10% decrease in the estimated fair value of any of our reporting units would have had no impact on the carrying value of goodwill at the annual measurement date.
  Measuring Recoverability of Long-Lived Assets and Equity Method Investments
     In general, long-lived assets (including intangible assets with finite useful lives and property, plant and equipment) are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Such events or changes include, among other factors: operating losses, unused capacity; market value declines; technological developments resulting in obsolescence; changes in demand for products in a market area; changes in competition and competitive practices; and changes in governmental regulations or actions. Recoverability of the carrying amount of assets to be held and used is measured by a comparison of the carrying amount of the asset to estimated future undiscounted net cash flows expected to be

71


Table of Contents

generated by the asset. Estimates of future undiscounted net cash flows include anticipated future revenues, expected future operating costs and other estimates. Such estimates of future undiscounted net cash flows are highly subjective and are based on numerous assumptions about future operations and market conditions. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or estimated fair value less costs to sell. We recorded an impairment of $59.7 million during the year ended December 31, 2009 related to an impairment of Buckeye NGL. A significant loss in the customer base utilizing Buckeye’s NGL pipeline, in conjunction with the authorization by the Board of Directors of Buckeye GP to pursue the sale of Buckeye NGL, triggered an evaluation of a potential asset impairment that resulted in a non-cash charge to earnings of $72.5 million in the Pipeline Operations segment in the second quarter of 2009. Effective January 1, 2010, we sold our ownership interest in Buckeye NGL for $22.0 million. The sales proceeds exceeded the previously impaired carrying value of the assets of Buckeye NGL by $12.8 million resulting in the reversal of $12.8 million of the previously recorded asset impairment expense in the fourth quarter of 2009. See Note 8 in the Notes to Consolidated Financial Statements for further discussion.
     An equity method investment is evaluated for impairment whenever events or changes in circumstances indicate that there is a possible other than temporary loss in value of the investment. Examples of such events include sustained operating losses of the investee or long-term negative changes in the investee’s industry. The carrying value of an equity method investment is not recoverable if it exceeds the sum of discounted estimated cash flow expected to be derived from the investment. This estimate of discounted cash flows is based on a number of assumptions including discount rates; probabilities assigned to different cash flow scenarios; anticipated margins and volumes and estimated useful life of the investment. A significant change in these underlying assumptions could result in our recording an impairment charge.
Other Considerations
Contractual Obligations
     The following table summarizes our contractual obligations as of December 31, 2009 (in thousands):
                                         
    Payments Due by Period  
            Less than 1                     More than 5  
    Total     year     1-3 years     3-5 years     years  
     
Long-term debt (1)
  $ 1,510,703     $ 6,178     $ 79,525     $ 575,000     $ 850,000  
Interest payments (2)
    709,646       78,256       156,512       133,139       341,739  
 
                                       
Operating leases: (3)
                                       
Office space and other
    18,978       1,528       3,075       3,178       11,197  
Land leases (4)
    311,747       2,945       6,341       6,951       295,510  
 
                                       
Purchase obligations (5)
    32,480       32,480                    
Capital expenditure obligations (6)
    1,611       1,611                    
 
                             
Total contractual cash obligations
  $ 2,585,165     $ 122,998     $ 245,453     $ 718,268     $ 1,498,446  
 
                             
 
(1)   We have long-term payment obligations under Buckeye’s Credit Facility, Buckeye’s underwritten publicly issued notes and the 3.60% ESOP Notes. Amounts shown in the table represent the scheduled future maturities of long-term debt principal for the periods indicated. We have assumed that the borrowings under Buckeye’s Credit Facility as of December 31, 2009 will not be repaid until the maturity date of the facility. See Note 13 in the Notes to Consolidated Financial Statements for additional information regarding our debt obligations.
 
(2)   Interest payments include amounts due on Buckeye’s underwritten publicly issued notes and interest payments and commitment fees due on Buckeye’s Credit Facility. The interest amount calculated on Buckeye’s Credit Facility is based on the assumption that the amount outstanding and the interest rate charged both remain at their current levels.

72


Table of Contents

(3)   We lease certain property, plant and equipment under noncancelable and cancelable operating leases. Amounts shown in the table represent minimum lease payment obligations under our operating leases with terms in excess of one year for the periods indicated. Lease expense is charged to operating expenses on a straight line basis over the period of expected benefit. Contingent rental payments are expensed as incurred. Total rental expense for the years ended December 31, 2009, 2008 and 2007 was $21.2 million, $20.2 million and $11.7 million, respectively.
 
(4)   We have leases for subsurface underground gas storage rights and surface rights in connection with our operations in the Natural Gas Storage segment. We may cancel these leases if the storage reservoir is not used for underground storage of natural gas or the removal or injection thereof for a continuous period of two consecutive years. Lease expense associated with these leases is being recognized on a straight line basis over 44 years. For the year ended December 31, 2009, the Natural Gas Storage segment’s lease expense was $7.4 million, including $4.5 million recorded as an increase in our deferred lease liability. We estimate that the deferred lease liability will continue to increase through 2032, at which time our deferred lease liability is estimated to be approximately $64.7 million. Our deferred lease liability will then be reduced over the remaining 19 years of the lease, since the expected annual lease payments will exceed the amount of lease expense.
 
(5)   We have long and short-term purchase obligations for products and services with third-party suppliers. The prices that we are obligated to pay under these contracts approximate current market prices. The table shows our commitments and estimated payment obligations under these contracts for the periods indicated. Our estimated future payment obligations are based on the contractual price under each contract for products and services at December 31, 2009.
 
(6)   We have short-term payment obligations relating to capital projects we have initiated. These commitments represent unconditional payment obligations that we have agreed to pay vendors for services rendered or products purchased.
     In addition, our obligations related to our pension and postretirement benefit plans are discussed in Note 16 in the Notes to Consolidated Financial Statements.
Employee Stock Ownership Plan
     Services Company provides the ESOP to the majority of its employees hired before September 16, 2004. Employees hired by Services Company after September 15, 2004, and certain employees covered by a union multiemployer pension plan do not participate in the ESOP. The ESOP owns all of the outstanding common stock of Services Company.
     At December 31, 2009, the ESOP was directly obligated to a third-party lender for $7.7 million with respect to the 3.60% ESOP Notes. The 3.60% ESOP Notes were issued on May 4, 2004 to refinance Services Company’s 7.24% ESOP Notes which were originally issued to purchase Services Company common stock. The 3.60% ESOP Notes are collateralized by Services Company common stock and are guaranteed by Services Company. Buckeye has committed that, in the event that the value of its LP Units owned by Services Company falls to less than 125% of the balance payable under the 3.60% ESOP Notes, Buckeye will fund an escrow account with sufficient assets to bring the value of the total collateral (the value of LP Units owned by Services Company and the escrow account) up to the 125% minimum. Amounts deposited in the escrow account are returned to Buckeye when the value of the LP Units owned by Services Company returns to an amount which exceeds the 125% minimum. At December 31, 2009, the value of the LP Units owned by Services Company was approximately $89.3 million, which exceeded the 125% requirement.
     Services Company stock is released to employee accounts in the proportion that current payments of principal and interest on the 3.60% ESOP Notes bear to the total of all principal and interest payments due under the 3.60% ESOP Notes. Individual employees are allocated shares based upon the ratio of their eligible compensation to total eligible compensation. See Note 18 in the Notes to Consolidated Financial Statements for further information.
Off-Balance Sheet Arrangements
     We have no off-balance sheet arrangements except for operating leases and outstanding letters of credit (see Note 13 in the Notes to Consolidated Financial Statements).

73


Table of Contents

Related Party Transactions
     With respect to related party transactions, see Note 19 in the Notes to Consolidated Financial Statements and Item 13, “Certain Relationships and Related Transactions and Director Independence.”
Recent Accounting Pronouncements
     See Note 2 in the Notes to Consolidated Financial Statements for a description of certain new accounting pronouncements that will or may affect our consolidated financial statements.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Market Risk — Trading Instruments
     We have no trading derivative instruments and do not engage in hedging activity with respect to trading instruments.
Market Risk — Non-Trading Instruments
     We are exposed to financial market risk resulting from changes in commodity prices and interest rates. We do not currently have foreign exchange risk.
Commodity Risk
     Our Energy Services segment primarily uses exchange-traded refined petroleum product futures contracts to manage the risk of market price volatility on its refined petroleum product inventories and its fixed-price sales contracts. The derivative contracts used to hedge refined petroleum product inventories are classified as fair value hedges. Accordingly, our method of measuring ineffectiveness compares the changes in the fair value of NYMEX futures contracts to the change in fair value of our hedged fuel inventory.
     The Energy Services segment has not used hedge accounting with respect to its fixed-price sales contracts. Therefore, its fixed-price sales contracts and the related futures contracts used to offset those fixed-price sales contracts are all marked-to-market on the balance sheet with gains and losses being recognized in earnings during each reporting period.
     As of December 31, 2009, the Energy Services segment had derivative assets and liabilities as follows (in thousands):
         
    December 31,  
    2009  
Assets:
       
Fixed-price sales contracts
  $ 4,959  
Liabilities:
       
Fixed-price sales contracts
    (3,662 )
Futures contracts for inventory and fixed-price sales contracts
    (11,003 )
 
     
Total
  $ (9,706 )
 
     
     Substantially all of the unrealized loss at December 31, 2009 for inventory hedges represented by futures contracts will be realized by the second quarter of 2010 as the related inventory is sold. Gains recorded on inventory hedges that were ineffective were approximately $2.6 million for the year ended December 31, 2009. As of December 31, 2009, open refined petroleum product derivative contracts (represented by the fixed-price sales contracts and futures contracts for fixed-price sales contracts and inventory noted above) varied in duration, but did not extend beyond December 2010. In addition, at December 31, 2009, we had refined petroleum product inventories which we intend to use to satisfy a portion of the fixed-price sales contracts.

74


Table of Contents

     Based on a hypothetical 10% movement in the underlying quoted market prices of the commodity financial instruments outstanding at December 31, 2009, the estimated fair value of the portfolio of commodity financial instruments would be as follows (in thousands):
                 
            Commodity  
            Financial  
            Instrument  
    Resulting     Portfolio  
Scenario   Classification     Fair Value  
Fair value assuming no change in underlying commodity prices (as is)
  Liability   $ (9,706 )
Fair value assuming 10% increase in underlying commodity prices
  Liability   $ (40,642 )
Fair value assuming 10% decrease in underlying commodity prices
  Asset   $ 21,223  
     The value of the open futures contract positions noted above were based upon quoted market prices obtained from NYMEX. The value of the fixed-price sales contracts was based on observable market data related to the obligation to provide refined petroleum products to customers.
Interest Rate Risk
     Buckeye manages a portion of its interest rate exposure by utilizing interest rate swaps to effectively convert a portion of its variable-rate debt into fixed-rate debt. In addition, Buckeye utilizes forward-starting interest rate swaps to manage interest rate risk related to forecasted interest payments on anticipated debt issuances. This strategy is a component in controlling its cost of capital associated with such borrowings. When entering into interest rate swap transactions, Buckeye becomes exposed to both credit risk and market risk. Buckeye is subject to credit risk when the value of the swap transaction is positive and the risk exists that the counterparty will fail to perform under the terms of the contract. Buckeye is subject to market risk with respect to changes in the underlying benchmark interest rate that impact the fair value of the swaps. Buckeye manages its credit risk by only entering into swap transactions with major financial institutions with investment-grade credit ratings. Buckeye manages its market risk by associating each swap transaction with an existing debt obligation or a specified expected debt issuance generally associated with the maturity of an existing debt obligation.
     Buckeye’s practice with respect to derivative transactions related to interest rate risk has been to have each transaction in connection with non-routine borrowings authorized by the Board of Directors of Buckeye GP. In January 2009, Buckeye GP’s Board of Directors adopted an interest rate hedging policy which permits Buckeye to enter into certain short-term interest rate hedge agreements to manage our interest rate and cash flow risks associated with its Credit Facility. In addition, in July 2009, Buckeye GP’s Board of Directors authorized Buckeye to enter into certain transactions, such as forward-starting interest rate swaps, to manage its interest rate and cash flow risks related to certain expected debt issuances associated with the maturity of an existing debt obligation.
     At December 31, 2009, Buckeye had total fixed-rate debt obligations at face value of $1,425.0 million, consisting of $125.0 million of the 5.125% Notes, $275.0 million of the 5.300% Notes, $300.0 million of the 4.625% Notes, $150.0 million of the 6.750% Notes, $300.0 million of the 6.050% Notes and $275.0 million of the 5.500% Notes. The fair value of these fixed-rate debt obligations at December 31, 2009 was approximately $1,444.3 million. Buckeye estimates that a 1% decrease in rates for obligations of similar maturities would increase the fair value of these fixed-rate debt obligations by $88.4 million. Buckeye’s variable-rate obligation was $78.0 million under its Credit Facility and $239.8 million under the BES Credit Agreement at December 31, 2009. Based on the balances outstanding at December 31, 2009, a hypothetical 100 basis point increase or decrease in interest rates would increase or decrease annual interest expense by $3.2 million.
     Buckeye expects to issue new fixed-rate debt (i) on or before July 15, 2013 to repay the $300.0 million of 4.625% Notes that are due on July 15, 2013 and (ii) on or before October 15, 2014 to repay the $275.0 million of 5.300% Notes that are due on October 15, 2014, although no assurances can be given that the issuance of fixed-rate

75


Table of Contents

debt will be possible on acceptable terms. During 2009, Buckeye entered into four forward-starting interest rate swaps with a total aggregate notional amount of $200.0 million related to the anticipated issuance of debt on or before July 15, 2013 and three forward-starting interest rate swaps with a total aggregate notional amount of $150.0 million related to the anticipated issuance of debt on or before October 15, 2014. The purpose of these swaps is to hedge the variability of the forecasted interest payments on these expected debt issuances that may result from changes in the benchmark interest rate until the expected debt is issued. Unrealized gains of $17.2 million were recorded in Buckeye’s accumulated other comprehensive loss to reflect the change in the fair values of the forward-starting interest rate swaps as of December 31, 2009. Buckeye designated the swap agreements as cash flow hedges at inception and expects the changes in values to be highly correlated with the changes in value of the underlying borrowings.
     The following table presents the effect of hypothetical price movements on the estimated fair value of Buckeye’s interest rate swap portfolio and the related change in fair value of the underlying debt at December 31, 2009 (in thousands):
                 
            Financial  
            Instrument  
    Resulting     Portfolio  
Scenario   Classification     Fair Value  
Fair value assuming no change in underlying interest rates (as is)
  Asset   $ 17,204  
Fair value assuming 10% increase in underlying interest rates
  Asset   $ 26,886  
Fair value assuming 10% decrease in underlying interest rates
  Asset   $ 667  

76


Table of Contents

Item 8.   Financial Statements and Supplementary Data
         
    Page  
    78  
    79  
    81  
    82  
    83  
    84  
       
    85  
    86  
    95  
    95  
    100  
    102  
    103  
    103  
    104  
    106  
    107  
    107  
    108  
    111  
    111  
    117  
    122  
    127  
    127  
    128  
    128  
    129  
    132  
    132  

77


Table of Contents

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
     Management of MainLine Management LLC (“MainLine Management”), as general partner of Buckeye GP Holdings L.P. (“BGH”), is responsible for establishing and maintaining adequate internal control over financial reporting of BGH. 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 MainLine Management’s internal control over financial reporting of BGH as of December 31, 2009. 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, 2009, MainLine Management’s internal control over financial reporting of BGH was effective.
     BGH’s independent registered public accounting firm, Deloitte & Touche LLP, has audited MainLine Management’s internal control over financial reporting of BGH. Their opinion on the effectiveness of MainLine Management’s internal control over financial reporting of BGH appears herein.
     
/s/ FORREST E. WYLIE
  /s/ KEITH E. ST.CLAIR
     
Forrest E. Wylie
  Keith E. St.Clair
Chief Executive Officer
  Chief Financial Officer
March 2, 2010

78


Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners of Buckeye GP Holdings L.P.
We have audited the internal control over financial reporting of Buckeye GP Holdings L.P. and subsidiaries (“BGH”) as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. BGH’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, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on BGH’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, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed 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, BGH maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2009 of BGH and our report dated March 2, 2010 expressed an unqualified opinion on those consolidated financial statements and included an explanatory paragraph regarding BGH’s change in its method of accounting for noncontrolling interests in 2009.
/s/ DELOITTE & TOUCHE LLP
Philadelphia, Pennsylvania
March 2, 2010

79


Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners of Buckeye GP Holdings L.P.
We have audited the accompanying consolidated balance sheets of Buckeye GP Holdings L.P. and subsidiaries (“BGH”) as of December 31, 2009 and 2008, and the related consolidated statements of operations, cash flows, and partners’ capital for each of the three years in the period ended December 31, 2009. These financial statements are the responsibility of BGH’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 BGH and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 2 to the consolidated financial statements, BGH changed its method of accounting for noncontrolling interests in 2009.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), BGH’s internal control over financial reporting as of December 31, 2009, 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 March 2, 2010 expressed an unqualified opinion on BGH’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
Philadelphia, Pennsylvania
March 2, 2010

80


Table of Contents

BUCKEYE GP HOLDINGS L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
                         
    Year Ended December 31,  
    2009     2008     2007  
Revenues:
                       
Product sales
  $ 1,125,653     $ 1,304,097     $ 10,680  
Transportation and other services
    644,719       592,555       508,667  
 
                 
Total revenue
    1,770,372       1,896,652       519,347  
 
                 
 
                       
Costs and expenses:
                       
Cost of product sales and natural gas storage services
    1,103,015       1,274,135       10,473  
Operating expenses
    275,930       281,965       245,271  
Depreciation and amortization
    54,699       50,834       40,236  
Asset impairment expense
    59,724              
General and administrative
    41,147       43,226       28,014  
Reorganization expense
    32,057              
 
                 
Total costs and expenses
    1,566,572       1,650,160       323,994  
 
                 
 
                       
Operating income
    203,800       246,492       195,353  
 
                 
 
                       
Other income (expense):
                       
Investment income
    453       1,553       1,490  
Interest and debt expense
    (75,147 )     (75,410 )     (51,721 )
 
                 
Total other expense
    (74,694 )     (73,857 )     (50,231 )
 
                 
 
                       
Income before earnings from equity investments
    129,106       172,635       145,122  
Earnings from equity investments
    12,531       7,988       7,553  
 
                 
Net income
    141,637       180,623       152,675  
Less: net income attributable to noncontrolling interest
    (92,043 )     (154,146 )     (129,754 )
 
                 
 
                       
Net income attributable to Buckeye GP Holdings L.P.
  $ 49,594     $ 26,477     $ 22,921  
 
                 
 
                       
Earnings per partnership unit:
                       
Basic
  $ 1.75     $ 0.94     $ 0.81  
 
                 
Diluted
  $ 1.75     $ 0.94     $ 0.81  
 
                 
 
                       
Weighted average number of common units outstanding:
                       
Basic
    28,300       28,300       28,142  
 
                 
Diluted
    28,300       28,300       28,300  
 
                 
See Notes to Consolidated Financial Statements.

81


Table of Contents

BUCKEYE GP HOLDINGS L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands, except unit amounts)
                 
    December 31,  
    2009     2008  
Assets:
               
Current assets:
               
Cash and cash equivalents
  $ 37,574     $ 61,281  
Trade receivables, net
    124,165       79,969  
Construction and pipeline relocation receivables
    14,095       21,501  
Inventories
    310,214       84,229  
Derivative assets
    4,959       97,375  
Assets held for sale
    22,000        
Prepaid and other current assets
    104,251       75,406  
 
           
Total current assets
    617,258       419,761  
 
               
Property, plant and equipment, net
    2,238,321       2,241,612  
 
               
Equity investments
    96,851       90,110  
Goodwill
    432,124       433,892  
Intangible assets, net
    45,157       44,114  
Other non-current assets
    56,860       33,608  
 
           
 
               
Total assets
  $ 3,486,571     $ 3,263,097  
 
           
 
               
Liabilities and partners’ capital:
               
Current liabilities:
               
Line of credit
  $ 239,800     $ 96,000  
Current portion of long-term debt
    6,178       6,294  
Accounts payable
    56,723       42,098  
Derivative liabilities
    14,665       48,623  
Accrued and other current liabilities
    113,474       116,464  
 
           
Total current liabilities
    430,840       309,479  
 
               
Long-term debt
    1,500,495       1,453,425  
Other non-current liabilities
    102,942       101,359  
 
           
Total liabilities
    2,034,277       1,864,263  
 
           
 
               
Commitments and contingent liabilities
           
 
               
Partners’ capital:
               
Buckeye GP Holdings L.P. capital:
               
General Partner (2,830 common units outstanding as of December 31, 2009 and 2008)
    7       7  
Limited Partners (27,771,213 and 27,766,817 common units outstanding as of December 31, 2009 and 2008, respectively)
    236,545       226,565  
Management (525,957 and 530,353 units outstanding as of December 31, 2009 and 2008, respectively)
    3,225       3,037  
Equity gains on issuance of Buckeye Partners, L.P. limited partner units
    2,557       2,451  
 
           
Total Buckeye GP Holdings L.P. capital
    242,334       232,060  
Noncontrolling interests
    1,209,960       1,166,774  
 
           
Total partners’ capital
    1,452,294       1,398,834  
 
           
 
               
Total liabilities and partners’ capital
  $ 3,486,571     $ 3,263,097  
 
           
See Notes to Consolidated Financial Statements.

82


Table of Contents

BUCKEYE GP HOLDINGS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
                         
    Year Ended December 31,  
    2009     2008     2007  
Cash flows from operating activities:
                       
Net income
  $ 141,637     $ 180,623     $ 152,675  
 
                 
Adjustments to reconcile net income
                       
to net cash provided by operating activities:
                       
Value of ESOP shares released
    1,641       2,202       4,470  
Depreciation and amortization
    54,699       50,834       40,236  
Asset impairment expense
    59,724              
Gain on the sale of assets
                (828 )
Net changes in fair value of derivatives
    20,531       (24,228 )      
Non-cash deferred lease expense
    4,500       4,598        
Earnings from equity investments of Buckeye Partners, L.P.
    (12,531 )     (7,988 )     (7,553 )
Distributions from equity investments of Buckeye Partners, L.P.
    9,660       5,113       7,418  
Amortization of other non-cash items
    8,257       4,643       2,197  
Change in assets and liabilities, net of amounts related to acquisitions:
                       
Trade receivables
    (44,112 )     36,060       3,432  
Construction and pipeline relocation receivables
    7,406       (8,930 )     (382 )
Inventories
    (177,309 )     (4,362 )     (863 )
Prepaid and other current assets
    (28,937 )     (27,823 )     1,467  
Accounts payable
    14,569       (10,647 )     (6,282 )
Accrued and other current liabilities
    (1,296 )     9,336       733  
Other non-current assets
    (9,916 )     9,520       1,999  
Other non-current liabilities
    (861 )     (10,394 )     (6,983 )
 
                 
Total adjustments from operating activities
    (93,975 )     27,934       39,061  
 
                 
Net cash provided by operating activities
    47,662       208,557       191,736  
 
                 
 
                       
Cash flows from investing activities:
                       
Capital expenditures
    (87,309 )     (120,472 )     (67,867 )
Acquisitions and equity investments, net of cash acquired
    (58,313 )     (667,523 )     (40,726 )
Net proceeds (expenditures) for disposal of property, plant and equipment
    1,419       (365 )     (12 )
Proceeds from the sale of Farm & Home retail operations
          52,584        
 
                 
Net cash used in investing activities
    (144,203 )     (735,776 )     (108,605 )
 
                 
 
                       
Cash flows from financing activities:
                       
Net proceeds from issuance of Buckeye Partners, L.P. limited partner units
    104,632       113,111       296,361  
Proceeds from exercise of Buckeye Partners, L.P. unit options
    3,204       316       2,497  
Issuance of long-term debt
    273,210       298,050        
Repayment of long term-debt
    (6,294 )     (6,289 )     (6,037 )
Borrowings under credit facilities
    317,120       558,554       157,500  
Repayments under credit facilities
    (537,387 )     (260,288 )     (302,499 )
Net borrowings (repayments) under BES credit agreement
    143,800       (4,000 )      
Debt issuance costs
    (4,691 )     (2,111 )     (178 )
Distributions paid to noncontrolling partners of Buckeye Partners, L.P.
    (180,008 )     (159,306 )     (128,775 )
Settlement payment of interest rate swaps
          (9,638 )      
Distributions paid to partners
    (40,752 )     (34,385 )     (27,734 )
 
                 
Net cash provided by (used in) financing activities
    72,834       494,014       (8,865 )
 
                 
Net increase (decrease) in cash and cash equivalents
    (23,707 )     (33,205 )     74,266  
Cash and cash equivalents — Beginning of year
    61,281       94,486       20,220  
 
                 
Cash and cash equivalents — End of year
  $ 37,574     $ 61,281     $ 94,486  
 
                 
See Notes to Consolidated Financial Statements.

83


Table of Contents

BUCKEYE GP HOLDINGS L.P.
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(In thousands)
                                                 
    Buckeye GP Holdings L.P. Unitholders              
                            Equity Gains              
    General     Limited             on Issuance              
    Partner     Partner             of Buckeye’s              
    Common     Common     Management     Limited     Noncontrolling        
    Units     Units     Units     Partner Units     Interests     Total  
Partners’ capital — January 1, 2007
  $ 7     $ 232,202     $ 6,926     $ 1,482     $ 772,525     $ 1,013,142  
Net income*
          22,921                   129,754       152,675  
Distributions paid to partners
          (27,734 )                       (27,734 )
Recognition of value of Management Units
                1,179                   1,179  
Conversion of Management Units
          4,949       (4,949 )                  
Recognition of unit-based compensation charges
          590                         590  
Equity gains on issuance of Buckeye LP Units
                      757       (757 )      
Net proceeds from issuance of 6.2 million of Buckeye’s limited partner units
                                    296,361       296,361  
Amortization of Buckeye’s limited partner unit options
                            378       378  
Exercise of limited partner unit options
                            2,497       2,497  
Services Company’s non-cash ESOP distributions
                            (5,015 )     (5,015 )
Distributions paid to noncontrolling interests
                            (128,775 )     (128,775 )
Other
                            (825 )     (825 )
 
                                   
Partners’ capital — December 31, 2007
    7       232,928       3,156       2,239       1,066,143       1,304,473  
Net income*
          25,981       496             154,146       180,623  
Distributions paid to partners
          (33,741 )     (644 )                 (34,385 )
Recognition of unit-based compensation charges
          1,397       29                   1,426  
Equity gains on issuance of Buckeye LP Units
                      212       (212 )      
Net proceeds from issuance of 2.6 million of Buckeye’s limited partner units
                            113,111       113,111  
Amortization of Buckeye’s limited partner unit options
                            486       486  
Exercise of limited partner unit options
                            316       316  
Services Company’s non-cash ESOP distributions
                            (5,685 )     (5,685 )
Acquired noncontrolling interests not previously owned
                            (1,537 )     (1,537 )
Distributions paid to noncontrolling interests
                            (159,306 )     (159,306 )
Other
                            (688 )     (688 )
 
                                   
Partners’ capital — December 31, 2008
    7       226,565       3,037       2,451       1,166,774       1,398,834  
Net income*
          48,668       926             92,043       141,637  
Distributions paid to partners
          (39,990 )     (762 )                 (40,752 )
Recognition of unit-based compensation charges
          1,302       24                   1,326  
Equity gains on issuance of Buckeye LP Units
                      106       (106 )      
Net proceeds from issuance of 3.0 million of Buckeye’s limited partner units
                            104,632       104,632  
Amortization of Buckeye’s limited partner unit options
                            3,079       3,079  
Exercise of limited partner unit options
                            3,204       3,204  
Services Company’s non-cash ESOP distributions
                            (6,073 )     (6,073 )
Distributions paid to noncontrolling interests
                            (180,008 )     (180,008 )
Change in value of derivatives
                            17,722       17,722  
Amortization of interest rate swaps
                            961       961  
Other
                            7,732       7,732  
 
                                   
Partners’ capital — December 31, 2009
  $ 7     $ 236,545     $ 3,225     $ 2,557     $ 1,209,960     $ 1,452,294  
 
                                   
 
*   Comprehensive income equals net income.
See Notes to Consolidated Financial Statements.

84


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
     Except for per unit amounts, or as otherwise noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands.
1. ORGANIZATION
     Buckeye GP Holdings L.P. is a publicly traded Delaware master limited partnership (“MLP”) organized on June 15, 2006. Our common units (“Common Units”) are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “BGH.” We own 100% of Buckeye GP LLC (“Buckeye GP”), which is the general partner of Buckeye Partners, L.P. (“Buckeye”). Buckeye is also a publicly traded Delaware MLP which was organized in 1986 and its limited partner units (“LP Units”) are separately traded on the NYSE under the ticker symbol “BPL.” Approximately 62% of our outstanding equity, which includes Common Units and management units (“Management Units”) are owned by BGH GP Holdings, LLC (“BGH GP”) and approximately 38% by the public. BGH GP is owned by affiliates of ArcLight Capital Partners, LLC (“ArcLight”), Kelso & Company (“Kelso”), and certain investment funds along with certain members of senior management of Buckeye GP. MainLine Management LLC, a Delaware limited liability company (“MainLine Management”), is our general partner and is wholly owned by BGH GP. As used in these Notes to Consolidated Financial Statements, unless the context requires otherwise, references to “we,” “us,” “our,” or “BGH” are intended to mean the business and operations of Buckeye GP Holdings L.P. on a consolidated basis, including those of Buckeye. References to “Buckeye” mean Buckeye Partners, L.P. and its consolidated subsidiaries.
     Our only business is the ownership of Buckeye GP. Buckeye GP’s only business is the management of Buckeye and its subsidiaries. At December 31, 2009, Buckeye GP owned an approximate 0.5% general partner interest in Buckeye.
     Buckeye owns and operates one of the largest independent refined petroleum products pipeline systems in the United States in terms of volumes delivered with approximately 5,400 miles of pipeline and 67 active products terminals that provide aggregate storage capacity of approximately 27.2 million barrels. In addition, Buckeye operates and maintains approximately 2,400 miles of other pipelines under agreements with major oil and chemical companies. Buckeye also owns and operates a major natural gas storage facility in northern California, which provides approximately 40 billion cubic feet (“Bcf”) of natural gas storage capacity (including pad gas), and is a wholesale distributor of refined petroleum products in the United States in areas also served by its pipelines and terminals.
     Buckeye Pipe Line Services Company (“Services Company”) was formed in 1996 in connection with the establishment of the Buckeye Pipe Line Services Company Employee Stock Ownership Plan (the “ESOP”). At December 31, 2009, Services Company owned approximately 3.2% of Buckeye’s LP Units. Services Company employees provide services to Buckeye’s operating subsidiaries. Pursuant to a services agreement entered into in December 2004 (the “Services Agreement”), Buckeye’s operating subsidiaries reimburse Services Company for the costs of the services provided by Services Company. Pursuant to the Services Agreement and an executive employment agreement, through December 31, 2008, executive compensation costs and related benefits paid to Buckeye GP’s four highest salaried officers were not reimbursed by Buckeye or its operating subsidiaries but were reimbursed to Services Company by us. Since January 1, 2009, Buckeye and its operating subsidiaries have paid for all executive compensation and benefits earned by Buckeye GP’s four highest salaried officers in return for an annual fixed payment from us of $3.6 million.

85


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
     We adhere to the following significant accounting policies in the preparation of our consolidated financial statements.
Basis of Presentation and Principles of Consolidation
     The consolidated financial statements and the accompanying notes are prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) and the rules of the U.S. Securities and Exchange Commission (“SEC”). The financial statements include our accounts on a consolidated basis. We have eliminated all intercompany transactions in consolidation. The consolidated financial statements also include the accounts of our wholly-owned subsidiaries, as well as the accounts of Buckeye and Services Company, on a consolidated basis.
Business Segments
     We operate and report in five business segments: Pipeline Operations; Terminalling and Storage; Natural Gas Storage; Energy Services; and Development and Logistics. We previously referred to the Development and Logistics segment as the Other Operations segment. We renamed the segment to better describe the business activities conducted within the segment. See Note 22 for a more detailed discussion of our business segments.
Asset Retirement Obligations
     We regularly assess our legal obligations with respect to estimated retirements of certain of our long-lived assets to determine if an asset retirement obligation (“ARO”) exists. GAAP requires that the fair value of a liability related to the retirement of long-lived assets be recorded at the time a legal obligation is incurred including obligations to perform an asset retirement activity in which the timing or method of settlement are conditional on a future event that may or may not be within the control of the entity. If an ARO is identified and a liability is recorded, a corresponding asset is recorded concurrently and is depreciated over the remaining useful life of the asset. After the initial measurement, the liability is periodically adjusted to reflect changes in the ARO’s fair value. Generally, the fair value of any liability is determined based on estimates and assumptions related to future retirement costs, future inflation rates and credit-adjusted risk-free interest rates.
     Other than assets in the Natural Gas Storage segment, our assets generally consist of underground refined petroleum products pipelines installed along rights-of-way acquired from land owners and related above-ground facilities and terminals that we own. We are unable to predict if and when our pipelines, which generally serve high-population and high-demand markets, will become completely obsolete and require decommissioning. Further, our rights-of-way agreements typically do not require the dismantling and removal of the pipelines and reclamation of the rights-of-way upon permanent removal of the pipelines from service. Accordingly, other than with respect to the Natural Gas Storage segment, we have recorded no liabilities, or corresponding assets, because the future dismantlement and removal dates of the majority of our assets, and the amount of any associated costs, are indeterminable.
     The Natural Gas Storage segment’s pipelines and surface facilities are located on land that is leased. An ARO asset and liability was established due to a requirement in the land leases to remove certain assets in the event that the site is abandoned. The ARO liability will be adjusted prospectively for costs incurred or settled, accretion expense, and any revisions made to the assumptions related to the retirement costs. See Note 8 for further discussion of our AROs.
Capitalization of Interest
     Interest on borrowed funds is capitalized on projects during construction based on the approximate average interest rate of our debt. Interest capitalized for the years ended December 31, 2009, 2008 and 2007 was $3.4

86


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
million, $2.3 million and $1.5 million, respectively. The weighted average rates used to capitalize interest on borrowed funds was 5.4% for the years ended December 31, 2009, 2008 and 2007.
Cash and Cash Equivalents
     Cash equivalents represent all highly marketable securities with original maturities of three months or less. The carrying value of cash equivalents approximates fair value because of the short term nature of these investments.
     Our consolidated statements of cash flows are prepared using the indirect method. The indirect method derives net cash flows from operating activities by adjusting net income to remove (i) the effects of all deferrals of past operating cash receipts and payments, such as changes during the period in inventory, deferred income and similar transactions, (ii) the effects of all accruals of expected future operating cash receipts and cash payments, such as changes during the period in receivables and payables, (iii) the effects of all items classified as investing or financing cash flows, such as gains or losses on sale of property, plant and equipment or extinguishment of debt, and (iv) other non-cash amounts such as depreciation, amortization and changes in the fair market value of financial instruments.
Construction and Pipeline Relocation Receivables
     Construction and pipeline relocation receivables represent valid claims against non-affiliated customers for services rendered in constructing or relocating pipelines and are recognized when services are rendered.
Contingencies
     Certain conditions may exist as of the date our consolidated financial statements are issued that may result in a loss to us, but which will only be resolved when one or more future events occur or fail to occur. Our management, with input from legal counsel, assesses such contingent liabilities, and such assessment inherently involves an exercise in judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in proceedings, our management, with input from legal counsel, evaluates the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.
     If the assessment of a contingency indicates that it is probable that a material loss has been incurred and the amount of liability can be estimated, then the estimated liability would be accrued in our consolidated financial statements. If the assessment indicates that a potentially material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss if determinable and material, is disclosed.
     Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed.
Cost of Product Sales and Natural Gas Storage Services
     Cost of product sales relates to sales of refined petroleum products, consisting primarily of gasoline, heating oil and diesel fuel, and includes the direct costs of product acquisition as well as the effects of hedges of such product acquisition costs and hedges of fixed-price sales contracts. In addition, costs related to hub service agreements, which consist of a variety of gas storage services under interruptible storage agreements, for which we will be required to make payment to a third party, are recognized as cost of natural gas storage services. These services principally include park and loan transactions. Parks occur when gas from a third party is injected and stored for a specified period. The third party then is obligated to withdraw its stored gas at a future date. Title to the gas remains with the third party. Loans occur when gas is delivered to a third party in a specified period. The third party then has the obligation to redeliver gas at a future date. Costs related to park and loan transactions for which we are required to make payment are recognized ratably over the term of the agreement.

87


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Debt Issuance Costs
     Costs incurred upon the issuance of our debt instruments are capitalized and amortized over the life of the associated debt instrument on a straight-line basis, which approximates the effective interest method. If the debt instrument is retired before its scheduled maturity date, any remaining issuance costs associated with that debt instrument are expensed in the same period. Deferred debt issuance costs were $18.1 million and $13.7 million at December 31, 2009 and 2008, respectively. Accumulated amortization was approximately $7.0 million and $4.8 million at December 31, 2009 and 2008, respectively.
Earnings per Partnership Unit
     Basic earnings per partnership unit is determined by dividing the net income attributable to us by the weighted average number of Common Units and vested Management Units outstanding for the period. Diluted earnings per partnership unit is calculated using the weighted average of all partnership units outstanding, including Common Units and Management Units.
Environmental Expenditures
     We accrue for environmental costs that relate to existing conditions caused by past operations, including, in some cases, pre-existing conditions related to acquired assets. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Environmental costs include initial site surveys and environmental studies of potentially contaminated sites, costs for remediation and restoration of sites determined to be contaminated and ongoing monitoring costs, as well as damages and other costs, when estimable. We monitor the balance of accrued undiscounted environmental liabilities on a regular basis. We record liabilities for environmental costs at a specific site when our liability for such costs is probable and a reasonable estimate of the associated costs can be made. Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information developed in subsequent periods. Estimates of our ultimate liabilities associated with environmental costs are particularly difficult to make with certainty due to the number of variables involved, including the early stage of investigation at certain sites, the lengthy time frames required to complete remediation alternatives available and the evolving nature of environmental laws and regulations. None of our estimated environmental remediation liabilities are discounted to present value since the ultimate amount and timing of cash payments for such liabilities are not readily determinable. Expenditures to mitigate or prevent future environmental contamination are capitalized. We maintain insurance which may cover certain environmental expenditures.
     At December 31, 2009 and 2008, our accrued liabilities for environmental remediation projects totaled $29.9 million and $27.0 million, respectively. These amounts were derived from a range of reasonable estimates based upon studies and site surveys. Unanticipated changes in circumstances and/or legal requirements could result in expenses being incurred in future periods in addition to an increase in expenditures required to remediate contamination for which we are responsible.
Equity Investments
     We account for investments in entities in which we do not exercise control, but have significant influence, using the equity method. Under this method, an investment is recorded at acquisition cost plus our equity in undistributed earnings or losses since acquisition, reduced by distributions received and amortization of excess net investment. Excess investment is the amount by which the initial investment exceeds the proportionate share of the book value of the net assets of the investment. We evaluate equity method investments for impairment whenever events or circumstances indicate that there is a loss in value of the investment which is other than temporary. In the event that the loss in value of an investment is other than temporary, we record a charge to earnings to adjust the carrying value to fair value. There were no impairments of our equity investments during the years ended December 31, 2009, 2008 or 2007.

88


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Estimates
     The preparation of consolidated financial statements in conformity with GAAP requires our management to make estimates and assumptions. These estimates and assumptions, which may differ from actual results, will affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements, as well as the reported amounts of revenue and expense during the reporting periods.
Fair Value
     Cash and cash equivalents, trade receivables, construction and pipeline relocation receivables, margin deposits, prepaid and other current assets and all current liabilities are reported in the consolidated balance sheets at amounts which approximate fair value due to the relatively short period to maturity of these financial instruments. The fair value of our debt was calculated using interest rates currently available to us for issuance of debt with similar terms and remaining maturities and approximate market values on the respective dates. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Our Energy Services segment also has derivative assets and liabilities. These assets and liabilities consist of exchange–traded futures contracts and fixed-price sales contracts with customers. These assets and liabilities are measured and reported at fair values. We consider the impact of credit valuation adjustments with respect to the fixed-price sales contracts. See Note 15 for further discussion.
Financial Instruments
     We use financial instruments such as swaps, forwards, futures and other contracts to manage market price risks associated with inventories, firm commitments, interest rates and certain anticipated transactions. We recognize these transactions on our consolidated balance sheet as assets and liabilities based on the instrument’s fair value. Changes in fair value of financial instrument derivative contracts are recognized in the current period in earnings unless specific hedge accounting criteria are met. If the financial instrument is designated as a hedging instrument in a fair value hedge, gains and losses incurred on the instrument will be recorded in earnings to offset corresponding losses and gains on the hedged item. If the financial instrument is designated as a hedging instrument in a cash flow hedge, gains and losses incurred on the instrument are recorded in other comprehensive income. In both cases, any gains or losses incurred on the instrument that are not effective in offsetting changes in fair value or cash flows of the hedged item are recognized immediately in earnings. Gains and losses on cash flow hedges are reclassified from other comprehensive income to earnings when the forecasted transaction occurs or, as appropriate, over the economic life of the underlying asset or liability. A financial instrument designated as a hedge of an anticipated transaction that is no longer likely to occur is immediately recognized in earnings.
     To qualify as a hedge, the item to be hedged must expose us to risk and we must have an expectation that the related hedging instrument will be effective at reducing or mitigating that exposure. Certain other hedging requirements, such as documentation at inception as discussed below, must also be met.
     Documentation of all hedging relationships is completed at inception and includes a description of the risk-management objective and strategy for undertaking the hedge, identification of the hedging instrument, the hedged item, the nature of the risk being hedged, the method for assessing effectiveness of the hedging instrument in offsetting the hedged risk and the method of measuring any ineffectiveness. This process includes linking all derivatives that are designated as fair value or cash flow hedges to specific assets and liabilities on the consolidated balance sheets or to specific firm commitments or forecasted transactions. We also formally assess, both at the hedge’s inception and on an ongoing basis at least quarterly, whether the derivatives that are used in designated hedging relationships are highly effective in offsetting changes in fair values or cash flows of hedged items. If it is determined that a derivative is not highly effective as a hedge or that it has ceased to be a highly effective hedge, we discontinue hedge accounting prospectively.

89


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Goodwill
     Goodwill represents the excess of purchase price over fair value of net assets acquired. Our goodwill amounts are assessed for impairment (i) on an annual basis on January 1 of each year or (ii) on an interim basis if circumstances indicate it is more likely than not the fair value of a reporting unit is less than its fair value. Goodwill is tested for impairment at a level of reporting referred to as a reporting unit. A reporting unit is a business segment or one level below a business segment for which discrete financial information is available and regularly reviewed by segment management. Our reporting units are our business segments. A goodwill impairment assessment requires that the estimated fair value of the reporting unit to which the goodwill is assigned be determined and compared to its book value. If the fair value of the reporting unit including associated goodwill amounts is less than its book value, including associated goodwill amounts, a charge to earnings is recorded to reduce the carrying value of the goodwill to its implied fair value. We have not recognized any impairment losses related to goodwill for any of the periods presented.
Income Taxes
     For federal and state income tax purposes, we and our subsidiaries, including Buckeye, except for Buckeye Gulf Coast Pipe Lines, L.P. (“BGC”), a Buckeye operating subsidiary, are not taxable entities. Accordingly, our taxable income or loss, which may vary substantially from income or loss reported for financial reporting purposes, is generally includable in the federal and state income tax returns of our individual partners. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner’s tax attributes is not available to us.
     Effective August 1, 2004, BGC elected to be treated as a taxable corporation for federal income tax purposes. Accordingly, it has recognized deferred tax assets and liabilities for temporary differences between the amounts of assets and liabilities measured for financial reporting purposes and the amounts measured for federal income tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance when the amount of any tax benefit is not expected to be realized. We recorded a deferred tax liability of $0.4 million and $0.8 million as of December 31, 2009 and 2008, respectively, which is recorded in non-current liabilities.
     Income tax benefit for the year ended December 31, 2009 was $0.3 million. Income tax expense for the years ended December 31, 2008 and 2007 was $0.8 million for both periods. Income tax benefit/expense is included in operating expenses in the consolidated statements of operations.
Intangible Assets
     Intangible assets with finite useful lives are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Intangible assets that have finite useful lives are amortized over their useful lives.
Inventories
     We generally maintain two types of inventory. Within our Energy Services segment, we principally maintain refined petroleum products inventory, which consists primarily of gasoline, heating oil and diesel fuel, which are valued at the lower of cost or market, unless such inventories are hedged.
     We also maintain, principally within our Pipeline Operations segment, an inventory of materials and supplies such as pipes, valves, pumps, electrical/electronic components, drag reducing agent and other miscellaneous items that are valued at the lower of cost or market based on the first-in, first-out method (see Note 6).

90


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Long-Lived Assets
     We assess the recoverability of our long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. We assess recoverability based on estimated undiscounted future cash flows expected to result from the use of the asset and its eventual disposal. The measurement of an impairment loss, if recognition of any loss is required, is based on the difference between the carrying amount and fair value of the asset. During the year ended December 31, 2009, we recorded a non-cash charge of $59.7 million related to an asset impairment (see Note 8).
Noncontrolling Interests
     The consolidated balance sheets include noncontrolling interests that relate to the portions of Buckeye and Services Company that is not owned by us. Similarly, the consolidated statements of operations include noncontrolling interests that reflect amounts not attributable to us. On January 1, 2009, we adopted guidance that established accounting and reporting standards for the noncontrolling interests in a subsidiary and for the deconsolidation of a subsidiary. These accounting and reporting standards require entities that prepare consolidated financial statements to: (a) present noncontrolling interests as a component of equity, separate from the parent’s equity; (b) separately present the amount of consolidated net income attributable to noncontrolling interests in the income statement; (c) consistently account for changes in a parent’s ownership interests in a subsidiary in which the parent entity has a controlling financial interest as equity transactions; (d) require an entity to measure at fair value its remaining interest in a subsidiary that is deconsolidated; and (e) require an entity to provide sufficient disclosures that identify and clearly distinguish between interests of the parent and interests of noncontrolling owners. Accordingly, for all periods presented in our consolidated financial statements, we have reclassified our noncontrolling interests liability into partners’ capital on the consolidated balance sheets and have separately presented and allocated income attributable to noncontrolling interests on the consolidated statements of operations and consolidated statements of partners’ capital.
Pensions
     Services Company sponsors a defined contribution plan (see Note 16), defined benefit plans (see Note 16) and the ESOP (see Note 16) that provide retirement benefits to certain regular full-time employees. Certain hourly employees of Services Company are covered by a defined contribution plan under a union agreement (see Note 16).
Postretirement Benefits Other Than Pensions
     Services Company provides post-retirement health care and life insurance benefits for certain of its retirees. Certain other retired employees are covered by a health and welfare plan under a union agreement (see Note 16).
Property, Plant and Equipment
     We record property, plant and equipment at its original acquisition cost. Property, plant and equipment consist primarily of pipelines, wells, storage and terminal facilities, pad gas and pumping and compression equipment. Depreciation on pipelines and terminals is generally calculated using the straight-line method over the estimated useful lives ranging from 44 to 50 years. Plant and equipment associated with natural gas storage is generally depreciated over 44 years, except for pad gas. The Natural Gas Storage segment maintains a level of natural gas in its underground storage facility generally known as pad gas, which is not routinely cycled but, instead, serves the function of maintaining the necessary pressure to allow routine injection and withdrawal to meet demand. The pad gas is considered to be a component of the facility and as such is not depreciated because it is expected to ultimately be recovered and sold. Other plant and equipment is generally depreciated on a straight-line basis over an estimated life of 5 to 50 years.

91


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
     Additions to property, plant and equipment, including major replacements or betterments, are recorded at cost. We charge maintenance and repairs to expense in the period incurred. The cost of property, plant and equipment sold or retired and the related depreciation, except for certain pipeline system assets, are removed from our consolidated balance sheet in the period of sale or disposition, and any resulting gain or loss is included in income. For our pipeline system assets, we generally charge the original cost of property sold or retired to accumulated depreciation and amortization, net of salvage and cost of removal. When a separately identifiable group of assets, such as a stand-alone pipeline system is sold, we will recognize a gain or loss in our consolidated statements of operations for the difference between the cash received and the net book value of the assets sold.
     The following table represents the depreciation life for the major components of our assets:
       
    Life in years  
Right of way
  44-50  
Line pipe and fittings
  44-50  
Buildings
  50  
Wells
  44  
Pumping and compression equipment
  44-50  
Oil tanks
  50  
Office furniture and equipment
  18  
Vehicles and other work equipment
  11  
Servers and software
  5  
Recent Accounting Developments
     In June 2009, the Financial Accounting Standards Board (“FASB”) established the FASB Accounting Standards Codification (“ASC”). Beginning in the third quarter of 2009, the ASC became the single source for all authoritative nongovernmental GAAP recognized by the FASB and is required to be applied to financial statements issued for interim and annual periods ending after September 15, 2009. The ASC replaces other sources of authoritative GAAP with the exception of rules and interpretive releases of the SEC, which will continue to be authoritative. The issuance of the ASC is not intended to significantly change GAAP and did not impact our results of operations, cash flows or financial position.
     Consolidation of Variable Interest Entities (“VIEs”). In June 2009, the FASB amended consolidation guidance for VIEs. The objective of this new guidance is to improve financial reporting by companies involved with VIEs. This guidance requires companies to perform an analysis to determine whether the companies’ variable interest or interests give it a controlling financial interest in a VIE. The new guidance is effective as of the beginning of each reporting company’s first annual reporting period that begins after November 15, 2009, for interim periods within that first annual reporting period, and for interim and annual reporting periods thereafter. Earlier application is prohibited. This guidance is effective for us on January 1, 2010. We are currently evaluating the impact the adoption of this guidance will have on our consolidated financial statements.
     Fair Value Measurements. In August 2009, the FASB issued new guidance that clarifies how an entity should estimate the fair value of liabilities. If a quoted price in an active market for an identical liability is not available, a company must measure the fair value of the liability using one of several valuation techniques (e.g., quoted prices for similar liabilities or present value of cash flows). Our adoption of this new guidance on October 1, 2009 did not have any impact on our consolidated financial statements or related disclosures.
     In January 2010, the FASB issued new guidance that amends, clarifies and provides additional disclosure requirements related to recurring and non-recurring fair value measurements and employers’ disclosures about postretirement benefit plan assets. This new guidance became effective for us on January 1, 2010. We are currently evaluating the impact the adoption of this guidance will have on our consolidated financial statements.

92


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Reclassifications
     Certain prior year amounts have been reclassified in the consolidated statements of cash flows to conform to the current-year presentation. Specifically, we have separately disclosed cash flows from the issuance of long-term debt and borrowings under credit facilities for the year ended December 31, 2008. These amounts had been included within the same line item in the 2008 period. There were no issuances of long-term debt during the year ended December 31, 2007.
Regulatory Reporting
     The majority of our refined petroleum products pipelines are subject to regulation by the Federal Energy Regulatory Commission (“FERC”), which prescribes certain accounting principles and practices for the annual Form 6 Report filed with the FERC that differ from those used in these consolidated financial statements. Reports to FERC differ from the consolidated financial statements, which have been prepared in accordance with GAAP, generally in that such reports calculate depreciation over estimated useful lives of the assets as prescribed by FERC.
Revenue Recognition
     We recognize revenues as follows (by segment):
    Pipeline Operations segment:
  o   Revenue from the transportation of refined petroleum products is recognized as products are delivered.
    Terminalling and Storage segment:
  o   Revenues from terminalling, storage and rental operations are recognized as the services are performed.
    Natural Gas Storage segment:
  o   Revenue from natural gas storage, which consists of demand charges, or lease revenues, for the reservation of storage space under firm storage agreements, is recognized over the term of the related storage agreement. The demand charge entitles the customer to a fixed amount of storage space and certain injection and withdrawal rights. Title to the stored gas remains with the customer.
 
  o   Revenues from hub services, which consist of a variety of other gas storage services under interruptible storage agreements, are recognized ratably over the term of the agreement. These services principally include park and loan transactions. Parks occur when gas from a customer is injected and stored for a specified period. The customer then has the obligation to withdraw its stored gas at a future date. Title to the gas remains with the customer. Loans occur when gas is delivered to a customer in a specified period. The customer then has the obligation to redeliver gas at a future date.
    Energy Services segment:
  o   Revenue from the sale of refined petroleum products, which are sold on a wholesale basis, is recognized when such products are delivered to the customer purchasing the products.
    Development and Logistics segment:
  o   Revenues from contract operation and construction services of facilities and pipelines not directly owned by us are recognized as the services are performed. Contract and construction services revenue typically includes costs to be reimbursed by the customer plus an operator fee.

93


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Trade Receivables and Concentration of Credit Risk
     Trade receivables represent valid claims against non-affiliated customers and are recognized when products are sold or services are rendered. We extend credit terms to certain customers based on historical dealings and to other customers after a full review of various financial credit indicators, including the customers’ credit rating (if available), and verified trade references. Our allowance for doubtful accounts is determined based on specific identification and estimates of future uncollectible accounts. Our Energy Services segment has established an allowance for doubtful accounts, while our other segments do not maintain an allowance for doubtful accounts due to their favorable collections experience.
     Our Energy Services segment’s allowance for doubtful accounts was $1.5 million and $2.1 million at December 31, 2009 and 2008, respectively, and is included in trade receivables in the consolidated balance sheets. Our procedure for determining the allowance for doubtful accounts is based on (i) historical experience with customers, (ii) the perceived financial stability of customers based on our research, and (iii) the levels of credit the Energy Services segment grants to customers. In addition, the Energy Services segment may increase the allowance for doubtful accounts in response to the specific identification of customers involved in bankruptcy proceedings and similar financial difficulties. On a routine basis, we review estimates associated with the allowance for doubtful accounts to ensure that we have recorded sufficient reserves to cover potential losses.
     We have a concentration of trade receivables due from major integrated oil companies and their marketing affiliates, major petroleum refiners, major chemical companies, large regional marketing companies and large commercial airlines. Additionally, we have trade receivables from gas marketing companies, independent gatherers, investment banks that have established a trading platform, and brokers and marketers. These concentrations of customers may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors.
     For the years ended December 31, 2009 and 2008, no customer contributed more than 10% of consolidated revenue. For the year ended December 31, 2007, Shell Oil Products U.S. (“Shell”) contributed 10% of consolidated revenue. Approximately 3% of 2007 consolidated revenue was generated by Shell in the Pipeline Operations segment, and the remaining 7% of consolidated revenue generated by Shell was in the Terminalling and Storage segment.
     We manage our exposure to credit risk through credit analysis and monitoring procedures, and sometimes use letters of credit, prepayments and guarantees. The Pipeline Operations and Energy Services segments bill their customers on a weekly basis, and the Terminalling and Storage, Natural Gas Storage and Development and Logistics segments bill on a monthly basis. We believe that these billing practices may reduce credit risk.
Unit-Based Compensation
     We have Management Units and a GP Equity Compensation Plan (see Note 17 for a discussion of BGH GP’s override units). Buckeye formerly awarded options to acquire its LP Units to employees pursuant to a Unit Option and Distribution Equivalent Plan (the “Option Plan”). In addition, in March 2009, Buckeye’s 2009 Long-Term Incentive Plan (the “2009 LTIP”) became effective. All unit-based payments to employees under these plans, including grants of employee unit options, phantom units and performance units, are recognized in the consolidated statements of operations based on their fair values. See Note 17 for further discussion of unit-based compensation plans.

94


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3. REORGANIZATION
     On July 20, 2009, we announced the completion of a company-wide, “best practices” review. During the period ended June 30, 2009, we commenced a restructuring of our operations as a result of this review, including a reorganization of our field operations to combine five of our original pipeline and terminal districts into three districts, as well as a restructuring of certain corporate functions and related corporate support functions. These efforts redefined the roles and responsibilities of certain positions and called for the elimination of resources devoted to such activities. Approximately 230 positions have been affected as a result of these restructuring activities.
     As part of the restructuring efforts, we executed a reduction in force comprised of a Voluntary Early Retirement Plan (the “VERP”) and an involuntary plan. The terms of the VERP were agreed to by approximately 80 employees during the period ended June 30, 2009. An additional group of approximately 150 employees were impacted by the involuntary reduction in workforce under our ongoing severance plan. Affected employees receive severance benefits, post-employment benefits including extended medical and dental coverage, and other services including retirement counseling and outplacement services. Most terminations were effective as of July 20, 2009.
     For the year ended December 31, 2009, we recorded reorganization expense of $32.1 million for post-employment costs related to these restructuring activities which include: (1) termination benefits pursuant to voluntary and involuntary severance plans of $16.0 million; (2) post-retirement benefits of $6.4 million (see Note 16); and (3) other related costs of $9.7 million.
     The reorganization expenses incurred by segment, including certain allocated amounts, for the year ended December 31, 2009 were as follows:
         
Pipeline Operations
  $ 26,127  
Terminalling and Storage
    2,735  
Natural Gas Storage
    495  
Energy Services
    1,207  
Development and Logistics
    1,493  
 
     
Total reorganization expenses
  $ 32,057  
 
     
4. ACQUISITIONS AND DISPOSITIONS
Business Combinations
     Our 2009 acquisition of pipeline and terminal assets from ConocoPhillips and the 2008 acquisitions of Lodi Gas Storage, L.L.C. (“Lodi Gas”), Farm & Home and a terminal in Albany, New York (“Albany Terminal”) have been accounted for as business combinations. The total purchase price was allocated to the fair value of the assets acquired and the liabilities assumed based on an assessment of their fair values at the acquisition date, with amounts exceeding the fair values being recorded as goodwill. All goodwill recorded in these business combinations is deductible for tax purposes. The results of their operations have been included in our consolidated financial statements since their respective acquisition dates.
Refined Petroleum Products Terminals and Pipeline Assets
     On November 18, 2009, we acquired from ConocoPhillips certain refined petroleum product terminals and pipeline assets for approximately $47.1 million in cash. In addition, we acquired certain inventory on hand upon completion of the transaction for additional consideration of $7.3 million. The assets include over 300 miles of active pipeline that provide connectivity between the East St. Louis, Illinois and East Chicago, Indiana markets and three terminals providing 2.3 million barrels of storage tankage. ConocoPhillips entered into certain commercial contracts with us concurrent with our acquisition regarding usage of the acquired facilities. We believe the acquisition of these assets gives us greater access to markets and refinery operations in the Midwest and increases

95


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
the commercial value to our customers by offering enhanced distribution connectivity and flexible storage capabilities. The operations of our combined assets will be reported in the Pipeline Operations and Terminalling and Storage segments. The purchase price has been allocated to the tangible and intangible assets acquired, on a preliminary basis, as follows:
         
Inventory
  $ 7,287  
Property, plant and equipment
    44,400  
Intangible assets
    4,580  
Environmental and other liabilities
    (1,834 )
 
     
Allocated purchase price
  $ 54,433  
 
     
Lodi Gas
     On January 18, 2008, we acquired all of the member interests in Lodi Gas from Lodi Holdings, L.L.C. Lodi Holdings, L.L.C. was owned by affiliates of ArcLight, which owns an indirect interest in our general partner. The cost of Lodi Gas was approximately $442.4 million in cash and consisted of the following:
         
Contractual purchase price
  $ 440,000  
Working capital adjustments and fees
    2,367  
 
     
Total purchase price
  $ 442,367  
 
     
     Of the contractual purchase price, $428.0 million was paid at closing and an additional $12.0 million was paid on March 6, 2008 upon receipt of approval from the California Public Utilities Commission for an expansion project known as Kirby Hills Phase II. We believed the acquisition of Lodi Gas represented an attractive opportunity to expand and diversify our storage and throughput operations into a new geographic area, northern California, and a new commodity type, natural gas, and provides us a platform for growth in the natural gas storage industry. These advantageous factors resulted in the recognition of goodwill in the amount that the fair value of the assets acquired and the liabilities assumed at the acquisition date exceeded the total purchase price. The activities of Lodi Gas are reported in the Natural Gas Storage segment. The purchase price has been allocated to the tangible and intangible assets acquired, including goodwill, as follows:
         
Current assets
  $ 8,240  
Property, plant and equipment
    274,880  
Goodwill
    169,560  
Current liabilities
    (9,096 )
Other liabilities
    (1,217 )
 
     
Allocated purchase price
  $ 442,367  
 
     

96


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Farm & Home
     On February 8, 2008, we acquired all of the member interests of Farm & Home for approximately $146.2 million. We believed that the wholesale distribution operations of Farm & Home represented an attractive opportunity to further our strategy of improving overall profitability by increasing the utilization of our existing pipeline and terminal system infrastructure by marketing refined petroleum products in areas served by that infrastructure. These advantageous factors resulted in the recognition of goodwill in the amount that the fair value of the assets acquired and the liabilities assumed at the acquisition date exceeded the total purchase price. The operations of Farm & Home are reported in the Energy Services segment. The purchase price has been allocated to the tangible and intangible assets acquired, including goodwill, as follows:
         
Current assets
  $ 79,144  
Inventory
    93,332  
Property, plant and equipment
    33,880  
Goodwill
    1,132  
Customer relationships
    38,300  
Other assets
    3,688  
Assets held for sale, net of liability of $0.7 million
    51,645  
Debt
    (100,000 )
Current liabilities
    (53,208 )
Other liabilities
    (1,740 )
 
     
Allocated purchase price
  $ 146,173  
 
     
     On April 15, 2008, we completed the sale of the retail operations of Farm & Home to a wholly-owned subsidiary of Inergy, L.P. for approximately $52.6 million. The retail assets sold consisted primarily of property, plant and equipment, inventory and receivables. We recorded no gain or loss on the sale of Farm & Home’s retail operations. The retail operations of Farm & Home were not an integral part of our core operations and strategy. Revenues from the retail operations for the period February 8, 2008 to April 15, 2008 were approximately $19.0 million. On July 31, 2008, Farm & Home was merged with and into its wholly owned subsidiary, Buckeye Energy Services LLC (“BES”), with BES continuing as the surviving entity of the merger.

97


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Albany Terminal
     On August 28, 2008, we completed the purchase of the Albany Terminal, an ethanol and refined petroleum products terminal in Albany, New York, from LogiBio Albany Terminal, LLC. The purchase price for the terminal was $46.5 million in cash, with an additional $1.5 million payable if the terminal operations meet certain performance goals over the next three years. We also assumed environmental remediation costs for the Albany Terminal estimated to be $5.6 million. The Albany Terminal has an active storage capacity of 1.8 million barrels. The Albany Terminal’s operations are reported in the Terminalling and Storage segment. We believe that the Albany Terminal’s operations represented an attractive opportunity to increase our participation in the ethanol services market in the northeast United States. These advantageous factors resulted in the recognition of goodwill in the amount that the fair value of the assets acquired and the liabilities assumed at the acquisition date exceeded the total purchase price. The purchase price has been allocated to the tangible and intangible assets acquired, including goodwill, as follows:
         
Current assets
  $ 78  
Property, plant and equipment
    25,172  
Goodwill
    26,829  
Other assets
    1,920  
Other liabilities
    (7,144 )
 
     
Allocated purchase price
  $ 46,855  
 
     
Unaudited Pro forma Financial Results
     The following unaudited summarized pro forma consolidated statements of operations information for the years ended December 31, 2008 and 2007 assumes that the acquisitions of Lodi Gas, Farm & Home and the Albany Terminal occurred as of the beginning of the years presented.
     The pro forma presentation below assumes that Buckeye’s equity offerings that were used in part to fund the acquisition of Lodi Gas occurred effective January 1, 2007. In the 2008 pro forma presentation, approximately $2.6 million of disposition-related expenses incurred by Lodi Gas in the period from January 1, 2008 to January 17, 2008 (prior to Buckeye’s ownership) have been excluded because these expenses were a nonrecurring item. For Farm & Home, the results of the retail operations have been excluded from both periods presented. These pro forma unaudited financial results were prepared for comparative purposes only and are not indicative of actual results that would have occurred if we had completed these acquisitions as of the beginning of the periods presented or the results that may be attained in the future:

98


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                 
    Year Ended December 31,  
    2008     2007  
Revenues:
               
As reported
  $ 1,896,652     $ 519,347  
Pro forma adjustments
    180,422       1,155,655  
 
           
Pro forma revenue
  $ 2,077,074     $ 1,675,002  
 
           
 
               
Net income:
               
As reported
  $ 180,623     $ 152,675  
Pro forma adjustments
    768       6,308  
 
           
Pro forma net income
  $ 181,391     $ 158,983  
 
           
 
               
Pro forma earnings per partnership unit:
               
Basic
  $ 0.96     $ 1.04  
 
           
Diluted
  $ 0.96     $ 1.03  
 
           
 
               
Pro forma weighted average number of limited partner units outstanding:
               
Basic
    28,300       28,142  
 
           
Diluted
    28,300       28,300  
 
           
Asset Acquisitions
     The acquisitions noted below were accounted for as asset acquisitions. Accordingly, the total purchase price has been allocated to the fair value of the assets acquired and the liabilities assumed based on fair values at the acquisition date. We determined that substantially all of the value of these purchases relate to the physical assets acquired, which are generally depreciated over 50 years. The acquired pipelines and related assets were allocated to the Pipeline Operations segment and the acquired terminals and related assets were allocated to the Terminalling and Storage segment. See Note 22 for a summary of the allocation of acquisitions by segment.
     On February 19, 2008, we acquired a refined petroleum products terminal in Niles, Michigan and a 50% ownership interest in a refined petroleum products terminal in Ferrysburg, Michigan from an affiliate of ExxonMobil Corporation for approximately $13.9 million. The approximate fair value allocation of the acquired assets is as follows:
         
Land
  $ 592  
Buildings
    1,621  
Machinery, equipment, and office furnishings
    11,714  
 
     
Allocated purchase price
  $ 13,927  
 
     
     Effective May 1, 2008, we purchased the 50% member interest in WesPac Pipelines – San Diego LLC not already owned by us from Kealine LLC for $9.3 million. The operations of WesPac Pipelines – San Diego LLC are reported in the Pipeline Operations segment. The purchase price was allocated principally to property, plant and equipment.
     On June 20, 2008, we acquired a refined petroleum products terminal in Wethersfield, Connecticut from Hess Corporation for approximately $5.5 million. The purchase price was allocated principally to property, plant and equipment.

99


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
     On January 16, 2007, we acquired two refined petroleum products terminals located in Flint and Woodhaven, Michigan for approximately $22.2 million, including a deposit of $1.0 million that was paid in 2006. The fair value allocation of the acquired assets is as follows:
         
Land
  $ 8,663  
Buildings
    3,481  
Machinery, equipment, and office furnishings
    10,024  
 
     
Allocated purchase price
  $ 22,168  
 
     
     On February 27, 2007, we acquired a refined petroleum products terminal in Marcy, New York for approximately $2.3 million. The purchase price was allocated principally to property, plant and equipment.
     On March 15, 2007, we completed the acquisition of two refined petroleum products terminals located in Green Bay and Madison, Wisconsin and the purchase of a 50% interest in a third terminal located in Milwaukee, Wisconsin for approximately $15.2 million. The fair value allocation of the acquired assets is as follow:
         
Land
  $ 3,400  
Buildings
    1,100  
Machinery, equipment, and office furnishings
    10,660  
 
     
Allocated purchase price
  $ 15,160  
 
     
5. COMMITMENTS AND CONTINGENCIES
   Claims and Proceedings
     In the ordinary course of business, we are involved in various claims and legal proceedings, some of which are covered by insurance. We are generally unable to predict the timing or outcome of these claims and proceedings. Based upon our evaluation of existing claims and proceedings and the probability of losses relating to such contingencies, we have accrued certain amounts relating to such claims and proceedings, none of which are considered material.
     On December 10, 2009, we entered into a Stipulation and Order of Settlement with the Tax Commission of the City of New York and the Commissioner of Finance of the City of New York with respect to a dispute over property tax assessments related to the years 2004 through 2009. We had previously paid the taxes for those years but protested portions of those property taxes, as permitted by state law. As a result of this settlement, we agreed to withdraw the protest and are entitled to receive a refund of approximately $7.2 million of the previously paid property taxes.
     In March 2007, Buckeye was named as a defendant in an action entitled Madigan v. Buckeye Partners, L.P. filed in the U.S. District Court for the Central District of Illinois. The action was brought by the State of Illinois Attorney General acting on behalf of the Illinois Environmental Protection Agency. The complaint alleged that we violated various Illinois state environmental laws in connection with a product release from our terminal located in Harristown, Illinois on or about June 11, 2006 and various other product releases from our terminals and pipelines in the State of Illinois during the period of 2001 through 2006. Pursuant to a Consent Decree that was filed with the U.S. District Court for the Central District of Illinois on October 7, 2009, we agreed to settle and compromise the disputed claims without admitting any of the allegations set forth in the complaint. Under the terms of the Consent Decree, we paid approximately $0.4 million in October 2009 to the Illinois Environmental Protection Agency and agreed to continue to perform monitoring and certain remediation activities at the sites involved, and the State of Illinois agreed to release us from any further liability with respect to the claims involved.

100


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
   Environmental Contingencies
     In accordance with our accounting policy, we recorded operating expenses, net of insurance recoveries, of $10.6 million, $10.1 million and $7.4 million during the years ended December 31, 2009, 2008 and 2007, respectively, related to environmental expenditures unrelated to claims and proceedings.
   Ammonia Contract Contingencies
     On November 30, 2005, BGC purchased an ammonia pipeline and other assets from El Paso Merchant Energy-Petroleum Company (“EPME”), a subsidiary of El Paso Corporation (“El Paso”). As part of the transaction, BGC assumed the obligations of EPME under several contracts involving monthly purchases and sales of ammonia. EPME and BGC agreed, however, that EPME would retain the economic risks and benefits associated with those contracts until their expiration at the end of 2012. To effectuate this agreement, BGC passes through to EPME both the cost of purchasing ammonia under a supply contract and the proceeds from selling ammonia under three sales contracts. For the vast majority of monthly periods since the closing of the pipeline acquisition, the pricing terms of the ammonia contracts have resulted in ammonia costs exceeding ammonia sales proceeds. The amount of the shortfall generally increases as the market price of ammonia increases.
     EPME has informed BGC that, notwithstanding the parties’ agreement, it will not continue to pay BGC for shortfalls created by the pass-through of ammonia costs in excess of ammonia revenues. EPME encouraged BGC to seek payment by invoking a $40.0 million guaranty made by El Paso which guaranteed EPME’s obligations to BGC. If EPME fails to reimburse BGC for these shortfalls for a significant period during the remainder of the term of the ammonia agreements, then such unreimbursed shortfalls could exceed the $40.0 million cap on El Paso’s guaranty. To the extent the unreimbursed shortfalls significantly exceed the $40.0 million cap, the resulting costs incurred by BGC could adversely affect our financial position, results of operations and cash flows. To date, BGC has continued to receive payment for ammonia costs under the contracts at issue. BGC has not called on El Paso’s guaranty and believes only BGC may invoke the guaranty. EPME, however, contends that El Paso’s guaranty is the source of payment for the shortfalls, but has not clarified the extent to which it believes the guaranty has been exhausted. Given the uncertainty of future ammonia prices and EPME’s future actions, we are unable to estimate the amount of any such losses we might incur in the future. We are assessing our options, including potential recourse against EPME and El Paso, with respect to this matter.
   Leases —Where We are Lessee
     We lease certain property, plant and equipment under noncancelable and cancelable operating leases. Lease expense is charged to operating expenses on a straight-line basis over the period of expected benefit. Contingent rental payments are expensed as incurred. Total rental expense for the years ended December 31, 2009, 2008 and 2007 was $21.2 million, $20.2 million and $11.7 million, respectively. The following table presents minimum lease payment obligations under our operating leases with terms in excess of one year for the years ending December 31:
                         
    Office space     Land        
    and other (1)     Leases (2)     Total  
2010
  $ 1,528     $ 2,945     $ 4,473  
2011
    1,536       3,059       4,595  
2012
    1,539       3,282       4,821  
2013
    1,563       3,409       4,972  
2014
    1,615       3,542       5,157  
Thereafter
    11,197       295,510       306,707  
 
                 
Total
  $ 18,978     $ 311,747     $ 330,725  
 
                 
 
(1)   We lease certain other land and space in office buildings.

101


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(2)   We have leases for subsurface underground gas storage rights and surface rights in connection with our operations in the Natural Gas Storage segment. We may cancel these leases if the storage reservoir is not used for underground storage of natural gas or the removal or injection thereof for a continuous period of two consecutive years. Lease expense associated with these leases is being recognized on a straight-line basis over 44 years. For the years ended December 31, 2009 and 2008, the Natural Gas Storage segment’s lease expense was approximately $7.4 million and $7.1 million, respectively. At December 31, 2009 and 2008, $4.5 million and $4.6 million, respectively, was recorded as an increase in our deferred lease liability. We estimate that the deferred lease liability will continue to increase through 2032, at which time our deferred lease liability is estimated to be approximately $64.7 million. Our deferred lease liability will then be reduced over the remaining 19 years of the lease, since the expected annual lease payments will exceed the amount of lease expense.
   Leases — Where We are Lessor
     We have entered into capacity leases with remaining terms from 5 to 13 years that are accounted for as operating leases. All of the agreements provide for negotiated extensions. Future minimum lease payments to be received under such operating leasing arrangements as of December 31, 2009 are as follows:
         
    Years Ending  
    December 31,  
2010
  $ 8,839  
2011
    8,839  
2012
    8,839  
2013
    8,839  
2014
    6,819  
Thereafter
    48,446  
 
     
Total
  $ 90,621  
 
     
6. INVENTORIES
     Our inventory amounts were as follows at the dates indicated:
                 
    December 31,  
    2009     2008  
Refined petroleum products (1)
  $ 299,473     $ 69,568  
Materials and supplies
    10,741       14,661  
 
           
Total inventories
  $ 310,214     $ 84,229  
 
           
 
(1)   Ending inventory was 141.7 million and 47.7 million gallons of refined petroleum products at December 31, 2009 and 2008, respectively.
     At December 31, 2009 and 2008, approximately 99% and 78%, respectively, of our inventory was hedged. Hedged inventory is valued at current market prices with the change in value of the inventory reflected in the consolidated statements of operations. At December 31, 2009 and 2008, 0% and 17%, respectively, of our inventory was committed against fixed-priced sales contracts and such inventory was valued at the lower of cost or market.

102


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
7. PREPAID AND OTHER CURRENT ASSETS
     Prepaid and other current assets consist of the following at the dates indicated:
                 
    December 31,  
    2009     2008  
Prepaid insurance
  $ 7,088     $ 7,889  
Insurance receivables
    13,544       5,101  
Ammonia receivable
    7,429       12,058  
Margin deposits
    21,037       32,345  
Prepaid services
    21,571        
Unbilled revenue
    13,201       1,074  
Tax receivable
    7,162        
Other
    13,219       16,939  
 
           
Total prepaid and other current assets
  $ 104,251     $ 75,406  
 
           
8. PROPERTY, PLANT AND EQUIPMENT
     Property, plant and equipment consist of the following at the dates indicated:
                 
    December 31,  
    2009     2008  
Land
  $ 64,712     $ 62,139  
Rights-of-way
    97,309       97,724  
Pad gas
    29,346       29,346  
Buildings and leasehold improvements
    103,535       92,668  
Machinery, equipment and office furnishings
    2,130,552       2,009,591  
Construction in progress
    78,363       173,691  
 
           
Total property, plant and equipment
    2,503,817       2,465,159  
Less: Accumulated depreciation
    (265,496 )     (223,547 )
 
           
Total property, plant and equipment, net
  $ 2,238,321     $ 2,241,612  
 
           
     Depreciation expense was $50.9 million, $47.4 million and $39.6 million for the years December 31, 2009, 2008 and 2007, respectively.
   Impairment of Long-Lived Assets and Assets Held for Sale
     We owned and operated an approximately 350-mile natural gas liquids pipeline (the “Buckeye NGL Pipeline”) that runs from Wattenberg, Colorado to Bushton, Kansas. During the second quarter of 2009, we received notification that several of our shippers, which were then using the Buckeye NGL Pipeline, intended to migrate their business to a competing pipeline that recently went into service. In connection with this notification, there was a significant decline in shipment volumes as compared to historical averages. This significant loss in the customer base utilizing Buckeye’s NGL pipeline, in conjunction with the authorization of the Board of Directors of Buckeye GP to pursue the sale of Buckeye NGL Pipe Lines LLC (“Buckeye NGL”), the entity which owned the Buckeye NGL Pipeline, triggered an evaluation of a potential asset impairment that resulted in a non-cash charge to earnings in the second quarter of 2009 of $72.5 million in the Pipeline Operations segment.
     We ceased depreciation of the assets as of July 1, 2009 and reclassified the assets of Buckeye NGL to “Assets held for sale” on the December 31, 2009 consolidated balance sheet. Effective January 1, 2010, we sold our

103


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
ownership interest in Buckeye NGL for $22.0 million. The sales proceeds exceeded the previously impaired carrying value of the Buckeye NGL Pipeline by $12.8 million, resulting in the reversal of $12.8 million of the previously recorded asset impairment expense in the fourth quarter of 2009, yielding a net impairment of $59.7 million for the year ended December 31, 2009. This impairment and the reversal are reflected within the category “Asset Impairment Expense” on our consolidated statements of operations.
     The carrying amounts of the major classes of assets held for sale by Buckeye NGL at December 31, 2009 were as follows:
         
Inventories
  $ 629  
Property, plant and equipment, net
    21,371  
 
     
Assets held for sale
  $ 22,000  
 
     
     Revenues for Buckeye NGL for the year ended December 31, 2009 were $9.3 million.
AROs
     The following table presents information regarding our AROs:
         
ARO liability balance, January 1, 2008
  $  
Liabilities assumed with Lodi Gas acquisition
    665  
Additional ARO for Kirby Hills Phase II
    194  
Accretion expense
    60  
 
     
ARO liability balance, December 31, 2008
    919  
Accretion expense
    101  
 
     
ARO liability balance, December 31, 2009 (1)
  $ 1,020  
 
     
 
(1)   Amount is included in other non-current liabilities.
9. EQUITY INVESTMENTS
     We own interests in related businesses that are accounted for using the equity method of accounting. The following table presents our equity investments, all included within the Pipeline Operations segment, at the dates indicated:
                         
            December 31,  
    Ownership     2009     2008  
Muskegon Pipeline LLC
    40.0 %   $ 15,273     $ 14,967  
Transport4, LLC
    25.0 %     379       332  
West Shore Pipe Line Company
    24.9 %     30,320       30,340  
West Texas LPG Pipeline Limited Partnership
    20.0 %     50,879       44,471  
 
                   
Total equity investments
          $ 96,851     $ 90,110  
 
                   
     During the years ended December 31, 2009, 2008 and 2007, we invested an additional $3.9 million, $9.8 million and $0.9 million, respectively, in West Texas LPG Pipeline Limited Partnership (“WT LPG”) as our pro-rata contribution for an expansion project that was required to meet increased pipeline demand caused by increased product production in the Fort Worth basin and East Texas regions. The expansion project consists of the construction of 39 miles of 12-inch pipeline and installation of multiple booster stations. The WT LPG expansion project became operational in February 2009. Affiliates of Chevron Corporation own the remaining 80% interest in, and operate, WT LPG.

104


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
     The following table presents earnings from equity investments for the periods indicated:
                         
    Year Ended December 31,  
    2009     2008     2007  
Muskegon Pipeline LLC
  $ 1,437     $ 1,367     $ 1,385  
Transport4, LLC
    147       70       43  
West Shore Pipe Line Company
    4,809       3,133       3,511  
WT LPG
    6,138       3,418       2,614  
 
                 
Total earnings from equity investments
  $ 12,531     $ 7,988     $ 7,553  
 
                 
     Combined balance sheet data as of the dates indicated and income statement data for the periods indicated for our equity method investments are summarized below:
                 
    December 31,  
    2009     2008  
BALANCE SHEET DATA:
               
Current assets
  $ 43,154     $ 65,919  
Noncurrent assets
    204,843       195,478  
 
           
Total assets
  $ 247,997     $ 261,397  
 
           
 
               
Current liabilities
  $ 32,592     $ 57,554  
Other liabilities
    10,922       11,742  
Combined equity
    204,483       192,101  
 
           
Total liabilities and combined equity
  $ 247,997     $ 261,397  
 
           
                         
    Year Ended December 31,  
    2009     2008     2007  
INCOME STATEMENT DATA:
                       
Revenues
  $ 134,786     $ 127,885     $ 122,622  
Costs and expenses
    67,694       86,273       80,977  
Non-operating expense
    12,914       9,036       10,559  
Net income
    54,178       32,576       31,086  

105


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
10. GOODWILL AND INTANGIBLE ASSETS
   Goodwill
     Goodwill represents the excess of the purchase price of an acquired business over the amounts assigned to assets acquired and liabilities assumed in the transaction. Goodwill is not amortized; however, it is subject to annual impairment testing. The following table summarizes our goodwill amounts by segment at the dates indicated:
                 
    December 31,  
    2009     2008  
Pipeline Operations:
               
Purchase of general partner interests in 2004
  $ 198,632     $ 198,632  
 
           
Terminalling and Storage:
               
Acquisition of six terminals in June 2000
    11,355       11,355  
Purchase of general partner interests in 2004
    11,434       11,434  
Acquisition of Albany Terminal in 2008 (1)
    26,829       28,597  
 
           
Subtotal
    49,618       51,386  
 
           
Natural Gas Storage:
               
Acquisition of Lodi Gas in 2008
    169,560       169,560  
 
           
Energy Services:
               
Acquisition of Farm & Home in 2008
    1,132       1,132  
 
           
Other Operations:
               
Purchase of general partner interests in 2004
    13,182       13,182  
 
           
Total goodwill
  $ 432,124     $ 433,892  
 
           
 
(1)   Goodwill decreased by $1.8 million as of December 31, 2009 from December 31, 2008 due to the finalization of the purchase price allocation of the Albany Terminal; the difference was allocated to property, plant and equipment.
   Intangible Assets
     Intangible assets include customer relationships and contracts. These intangible assets have definite lives and are being amortized on a straight-line basis over their estimated useful lives ranging from 5 to 25 years. The weighted average useful life of intangible assets is 14 years. Our amortizable customer contracts are contracts that were acquired in connection with the acquisition of BGC in March 1999, the acquisition of the Taylor, Michigan terminal in December 2005 and the acquisition of certain pipeline and terminal assets from ConocoPhillips in November 2009. The customer contracts are being amortized over their contractual life, 5 years in the case of the acquisition of certain pipeline and terminal assets from ConocoPhillips. The customer relationships resulted from the acquisition of Farm & Home (see Note 4 for further discussion). We determined, through an analysis of historical customer attrition rates at Farm & Home, that an appropriate recovery period for customer relationships is approximately 12 years. Intangible assets consist of the following at the dates indicated:

106


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                 
    December 31,  
    2009     2008  
Customer relationships
  $ 38,300     $ 38,300  
Accumulated amortization
    (5,631 )     (2,662 )
 
           
Net carrying amount
    32,669       35,638  
 
           
 
               
Customer contracts
    16,380       11,800  
Accumulated amortization
    (3,892 )     (3,324 )
 
           
Net carrying amount
    12,488       8,476  
 
           
Total intangible assets
  $ 45,157     $ 44,114  
 
           
     For the years ended December 31, 2009, 2008, and 2007, amortization expense related to intangible assets was $3.5 million, $3.2 million and $0.5 million, respectively. Amortization expense related to intangible assets is expected to be approximately $4.8 million for each of the next five years.
11. OTHER NON-CURRENT ASSETS
     Other non-current assets consist of the following at the dates indicated:
                 
    December 31,  
    2009     2008  
Prepaid services
  $ 11,640     $  
Long-term derivative assets
    17,204       6,273  
Debt issuance costs
    11,058       8,944  
Insurance receivables
    7,265       6,518  
Other
    9,693       11,873  
 
           
Total other non-current assets
  $ 56,860     $ 33,608  
 
           
12. ACCRUED AND OTHER CURRENT LIABILITIES
     Accrued and other current liabilities consist of the following at the dates indicated:
                 
    December 31,  
    2009     2008  
Taxes — other than income
  $ 15,487     $ 14,092  
Accrued employee benefit liability
    3,287       2,297  
Environmental liabilities
    10,799       12,337  
Interest payable
    30,613       25,551  
Payable for ammonia purchase
    7,015       9,373  
Unearned revenue
    6,829       12,186  
Compensation and vacation
    11,385       15,642  
Accrued capital expenditures
    1,611       4,902  
Reorganization
    2,133        
Deferred consideration
    1,675        
Other
    22,640       20,084  
 
           
Total accrued and other current liabilities
  $ 113,474     $ 116,464  
 
           

107


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
13. DEBT OBLIGATIONS
     Long-term debt consists of the following at the dates indicated:
                 
    December 31,  
    2009     2008  
BGH:
               
BGH Credit Agreement
  $     $  
Services Company:
               
3.60% ESOP Notes due March 28, 2011
    7,790       14,255  
Retirement premium
    (87 )     (258 )
Buckeye:
               
4.625% Notes due July 15, 2013 (1)
    300,000       300,000  
5.300% Notes due October 15, 2014 (1)
    275,000       275,000  
5.125% Notes due July 1, 2017 (1)
    125,000       125,000  
6.050% Notes due January 15, 2018 (1)
    300,000       300,000  
5.500% Notes due August 15, 2019 (1)
    275,000        
6.750% Notes due August 15, 2033 (1)
    150,000       150,000  
Borrowings under the Credit Facility
    78,000       298,267  
BES Credit Agreement
    239,800       96,000  
 
           
Total debt
  $ 1,750,503     $ 1,558,264  
Other, including unamortized discounts and fair value hedges
    (4,030 )     (2,545 )
 
           
Subtotal debt
    1,746,473       1,555,719  
Less: current portion of long-term debt
    (245,978 )     (102,294 )
 
           
Total long-term debt
  $ 1,500,495     $ 1,453,425  
 
           
 
(1)   We make semi-annual interest payments on these notes based on the rates noted above with the principal balances outstanding to be paid on or before the due dates as shown above.
     The following table presents the scheduled maturities of principal amounts of our debt obligations for the next five years and in total thereafter:
         
    Years Ending  
    December 31,  
2010
  $ 245,978  
2011
    1,525  
2012
    78,000  
2013
    300,000  
2014
    275,000  
Thereafter
    850,000  
 
     
Total
  $ 1,750,503  
 
     
     The fair values of our aggregate debt and credit facilities were estimated to be $1,769.8 million and $1,381.2 million at December 31, 2009 and 2008, respectively. The fair values of the fixed-rate debt at December 31, 2009 and 2008 were estimated by market-observed trading prices and by comparing the historic market prices of our publicly-issued debt with the market prices of other MLPs’ publicly-issued debt with similar credit ratings and terms. The fair values of the variable-rate debt are their carrying amounts as the carrying amount reasonably approximates fair value due to the variability of the interest rate.

108


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
     On August 18, 2009, Buckeye sold $275.0 million aggregate principal amount of 5.500% Notes due 2019 (the “5.500% Notes”) in an underwritten public offering. The notes were issued at 99.35% of their principal amount. Total proceeds from this offering, after underwriters’ fees, expenses and debt issuance costs of $1.8 million, were approximately $271.4 million and were used to reduce amounts outstanding under Buckeye’s credit facility and for working capital purposes.
     On January 11, 2008, Buckeye sold $300.0 million aggregate principal amount of 6.050% Notes due 2018 (the “6.050% Notes”) in an underwritten public offering. Proceeds from this offering, after underwriters’ fees and expenses, were approximately $298.0 million and were used to partially pre-fund the Lodi Gas acquisition. In connection with this debt offering, we settled two forward-starting interest rates swaps (see Note 15), which resulted in a settlement payment of $9.6 million that is being amortized as interest expense over the ten-year term of the 6.050% Notes.
   BGH
     We have a five-year, $10.0 million unsecured revolving credit facility with SunTrust Bank, as both administrative agent and lender (the “BGH Credit Agreement”). The BGH Credit Agreement may be used for working capital and other partnership purposes. We have pledged all of the limited liability company interests in Buckeye GP as security for our obligations under the BGH Credit Agreement. Borrowings under the BGH Credit Agreement bear interest under one of two rate options, selected by us, equal to either (i) the greater of (a) the federal funds rate plus 0.5% and (b) SunTrust Bank’s prime commercial lending rate; or (ii) the London Interbank Official Rate (“LIBOR”), plus a margin which can range from 0.40% to 1.40%, based on the ratings assigned by Standard & Poor’s Rating Services and Moody’s Investor Services to our senior unsecured non-credit enhanced long-term debt. We did not have amounts outstanding under the BGH Credit Agreement at December 31, 2009 or 2008.
     The BGH Credit Agreement requires us to maintain leverage and funded debt coverage ratios. The leverage ratio covenant requires us to maintain, as of the last day of each fiscal quarter, a ratio of the total funded indebtedness of us and our Restricted Subsidiaries (as defined below), measured as of the last day of each fiscal quarter, to the aggregate dividends and distributions received by us and the Restricted Subsidiaries from Buckeye, plus all other cash received by us and the Restricted Subsidiaries, measured for the preceding twelve months, less expenses, of not more than 2.50 to 1.00. The BGH Credit Agreement defines “Restricted Subsidiaries” as certain of our wholly owned subsidiaries. The funded debt coverage ratio covenant requires us to maintain, as of the last day of each fiscal quarter, a ratio of us and all of our consolidated subsidiaries total consolidated funded debt to the consolidated EBITDA, as defined in the BGH Credit Agreement, of us and all of our subsidiaries, measured for the preceding twelve months, of not more than 5.25 to 1.00, subject to a provision for increases to 5.75 to 1.00 in connection with future acquisitions. At December 31, 2009, our funded debt coverage ratio was 5.0 to 1.00.
     The BGH Credit Agreement contains other covenants that prohibit us from taking certain actions, including but not limited to, declaring dividends or distributions if any default or event of default has occurred or would result from such a declaration and limiting our ability to incur additional indebtedness, creating negative pledges and granting certain liens, making certain loans, acquisitions, and investments, making material changes to the nature of us and our Restricted Subsidiaries’ business, and entering into a merger, consolidation, or sale of assets. At December 31, 2009, we were not aware of any instances of noncompliance with the covenants under the BGH Credit Agreement.
   Services Company ESOP Notes
     Services Company had total debt outstanding of $7.7 million and $14.0 million at December 31, 2009 and 2008, respectively, consisting of 3.60% Senior Secured Notes (the “3.60% ESOP Notes”) due March 28, 2011 payable by the ESOP to a third-party lender. The 3.60% ESOP Notes were issued on May 4, 2004. The 3.60% ESOP Notes are collateralized by Services Company’s common stock and are guaranteed by Services Company. In addition, Buckeye has committed that, in the event that the value of Buckeye’s LP Units owned by Services Company falls below 125% of the balance payable under the 3.60% ESOP Notes, Buckeye will fund an escrow account with

109


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
sufficient assets to bring the value of the total collateral (the value of Buckeye’s LP Units owned by Services Company and the escrow account) up to the 125% minimum. Amounts deposited in the escrow account are returned to Buckeye when the value of Buckeye’s LP Units owned by Services Company’s returns to an amount that exceeds the 125% minimum. At December 31, 2009, the value of Buckeye’s LP Units owned by Services Company exceeded the 125% requirement.
   Credit Facility
     Buckeye has a borrowing capacity of $580.0 million under an unsecured revolving credit agreement (the “Credit Facility”) with SunTrust Bank, as administrative agent, which may be expanded up to $780.0 million subject to certain conditions and upon the further approval of the lenders. The Credit Facility’s maturity date is August 24, 2012, which we may extend for up to two additional one-year periods. Borrowings under the Credit Facility bear interest under one of two rate options, selected by us, equal to either (i) the greater of (a) the federal funds rate plus 0.5% and (b) SunTrust Bank’s prime rate plus an applicable margin, or (ii) LIBOR plus an applicable margin. The applicable margin is determined based on the current utilization level of the Credit Facility and ratings assigned by Standard & Poor’s and Moody’s Investor Services for Buckeye’s senior unsecured non-credit enhanced long-term debt. At December 31, 2009 and 2008, $78.0 million and $298.3 million, respectively, were outstanding under the Credit Facility. The weighted average interest rate for borrowings outstanding under Buckeye’s Credit Facility was 0.6% at December 31, 2009.
     The Credit Facility requires Buckeye to maintain a specified ratio (the “Funded Debt Ratio”) of no greater than 5.00 to 1.00 subject to a provision that allows for increases to 5.50 to 1.00 in connection with certain future acquisitions. The Funded Debt Ratio is calculated by dividing consolidated debt by annualized EBITDA, which is defined in the Credit Facility as earnings before interest, taxes, depreciation, depletion and amortization, in each case excluding the income of certain of our majority-owned subsidiaries and equity investments (but including distributions from those majority-owned subsidiaries and equity investments). At December 31, 2009, Buckeye’s Funded Debt Ratio was approximately 4.4 to 1.00. As permitted by the Credit Facility, the $239.8 million of borrowings by BES under its separate credit agreement (discussed below) and the $59.7 million impairment of Buckeye NGL (see Note 8) were excluded from the calculation of the Funded Debt Ratio.
     In addition, the Credit Facility contains other covenants including, but not limited to, covenants limiting our ability to incur additional indebtedness, to create or incur liens on our property, to dispose of property material to our operations, and to consolidate, merge or transfer assets. At December 31, 2009, we were not aware of any instances of noncompliance with the covenants under our Credit Facility.
     On August 21, 2009, Buckeye Energy Holdings LLC (“BEH”), our wholly owned subsidiary, bought the outstanding loans and commitments of Aurora Bank FSB (formerly Lehman Brother Bank, FSB), a lender under the Credit Facility, through a sale and assignment agreement. Concurrent with this transaction, we repaid the $213.5 million outstanding balance of the Credit Facility, plus accrued interest and fees. The Credit Facility was subsequently amended to remove BEH as a lender by terminating its commitment in full, thus reducing the borrowing capacity of the Credit Facility from $600.0 million to $580.0 million and the expansion option amount from $800.0 million to $780.0 million.
     At December 31, 2009 and 2008, Buckeye had committed $1.4 million and $1.3 million in support of letters of credit, respectively. The obligations for letters of credit are not reflected as debt on our consolidated balance sheets.
   BES Credit Agreement
     BES has a credit agreement (the “BES Credit Agreement”) that, prior to August 2009, provided for borrowings of up to $175.0 million. In August 2009, the BES Credit Agreement was amended to provide for total borrowings of up to $250.0 million. Under the BES Credit Agreement, borrowings accrue interest under one of three rate options, at BES’s election, equal to (i) the Administrative Agent’s Cost of Funds (as defined in the BES Credit Agreement) plus 1.75%, (ii) the Eurodollar Rate (as defined in the BES Credit Agreement) plus 1.75% or (iii) the Base Rate (as

110


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
defined in the BES Credit Agreement) plus 0.25%. The BES Credit Agreement also permits Daylight Overdraft Loans (as defined in the BES Credit Agreement), Swingline Loans (as defined in the BES Credit Agreement) and letters of credit. Such alternative extensions of credit are subject to certain conditions as specified in the BES Credit Agreement. The BES Credit Agreement is secured by liens on certain assets of BES, including its inventory, cash deposits (other than certain accounts), investments and hedging accounts, receivables and intangibles.
     The balances outstanding under the BES Credit Agreement were approximately $239.8 million and $96.0 million at December 31, 2009 and 2008, respectively, all of which were classified as current liabilities. The BES Credit Agreement requires BES to meet certain financial covenants, which are defined in the BES Credit Agreement and summarized below (in millions, except for the leverage ratio):
             
Borrowings   Minimum   Minimum   Maximum
outstanding on   Consolidated Tangible   Consolidated Net   Consolidated
BES Credit Agreement   Net Worth   Working Capital   Leverage Ratio
$150   $40   $30   7.0 to 1.0
Above $150 up to $200   $50   $40   7.0 to 1.0
Above $200 up to $250   $60   $50   7.0 to 1.0
     At December 31, 2009, BES’s Consolidated Tangible Net Worth and Consolidated Net Working Capital were $126.1 million and $78.2 million, respectively, and the Consolidated Leverage Ratio was 2.6 to 1.0. The weighted average interest rate for borrowings outstanding under the BES Credit Agreement was 2.0% at December 31, 2009.
     In addition, the BES Credit Agreement contains other covenants, including, but not limited to, covenants limiting BES’s ability to incur additional indebtedness, to create or incur certain liens on its property, to consolidate, merge or transfer its assets, to make dividends or distributions, to dispose of its property, to make investments, to modify its risk management policy, or to engage in business activities materially different from those presently conducted. At December 31, 2009, we were not aware of any instances of noncompliance with the covenants under the BES Credit Agreement.
14. OTHER NON-CURRENT LIABILITIES
     Other non-current liabilities consist of the following at the dates indicated:
                 
    December 31,  
    2009     2008  
Accrued employee benefit liabilities (see Note 16)
  $ 45,837     $ 49,281  
Accrued environmental liabilities
    19,053       14,684  
Deferred consideration
    18,425       20,100  
Deferred rent
    9,158       4,658  
Other
    10,469       12,636  
 
           
Total other non-current liabilities
  $ 102,942     $ 101,359  
 
           
15. DERIVATIVE INSTRUMENTS, HEDGING ACTIVITIES AND FAIR VALUE MEASUREMENTS
     We are exposed to certain risks, including changes in interest rates and commodity prices in the course of our normal business operations. We use derivative instruments to manage risks associated with certain identifiable and anticipated transactions. Derivatives are financial instruments whose fair value is determined by changes in a specified benchmark such as interest rates or commodity prices. Typical derivative instruments include futures, forward contracts, swaps and other instruments with similar characteristics. We have no trading derivative instruments and do not engage in hedging activity with respect to trading instruments.

111


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
     Our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategies for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives used in a transaction are highly effective in offsetting changes in cash flows or the fair value of hedged items. A discussion of our derivative activities by risk category follows.
  Interest Rate Derivatives
     Buckeye manages a portion of its interest rate exposure by utilizing interest rate swaps to effectively convert a portion of its variable-rate debt into fixed-rate debt. In addition, Buckeye utilizes forward-starting interest rate swaps to manage interest rate risk related to forecasted interest payments on anticipated debt issuances. This strategy is a component in controlling its cost of capital associated with such borrowings. When entering into interest rate swap transactions, Buckeye becomes exposed to both credit risk and market risk. Buckeye is subject to credit risk when the value of the swap transaction is positive and the risk exists that the counterparty will fail to perform under the terms of the contract. Buckeye is subject to market risk with respect to changes in the underlying benchmark interest rate that impacts the fair value of the swaps. Buckeye manages its credit risk by only entering into swap transactions with major financial institutions with investment-grade credit ratings. Buckeye manages its market risk by associating each swap transaction with an existing debt obligation or a specified expected debt issuance generally associated with the maturity of an existing debt obligation.
     Buckeye’s practice with respect to derivative transactions related to interest rate risk has been to have each transaction in connection with non-routine borrowings authorized by the Board of Directors of Buckeye GP. In January 2009, Buckeye GP’s Board of Directors adopted an interest rate hedging policy which permits Buckeye to enter into certain short-term interest rate swap agreements to manage its interest rate and cash flow risks associated with its Credit Facility. In addition, in July 2009, Buckeye GP’s Board of Directors authorized Buckeye to enter into certain transactions, such as forward-starting interest rate swaps, to manage its interest rate and cash flow risks related to certain expected debt issuances associated with the maturity of an existing debt obligation.
     In October 2008, January 2009 and April 2009, Buckeye entered into interest rate swap agreements for notional amounts of $50.0 million each to hedge its variable interest rate risk with respect to borrowings under its Credit Facility. Under each swap agreement, Buckeye paid a fixed rate of interest of 3.15%, 0.81% and 0.63%, respectively, for 180 days and, in exchange, received a series of six monthly payments calculated based on the 30-day LIBOR rate in effect at the beginning of each monthly period. The amounts Buckeye received corresponded to the 30-day LIBOR rates that it paid on the respective $50.0 million borrowed under its Credit Facility. Buckeye designated all of the swap agreements as cash flow hedges, and changes in value between the trade date and the designation date were recognized in earnings. The October 2008 swap settled on April 20, 2009, and the January 2009 swap settled on July 28, 2009. On August 27, 2009, in conjunction with the repayment of the outstanding balance under the Credit Facility, the April 2009 swap was terminated.
     Buckeye expects to issue new fixed-rate debt (i) on or before July 15, 2013, to repay the $300.0 million of 4.625% Notes that are due on July 15, 2013, and (ii) on or before October 15, 2014, to repay the $275.0 million of 5.300% Notes that are due on October 15, 2014, although no assurances can be given that the issuance of fixed-rate debt will be possible on acceptable terms. During 2009, Buckeye entered into four forward-starting interest rate swaps with a total aggregate notional amount of $200.0 million related to the anticipated issuance of debt on or before July 15, 2013 and three forward-starting interest rate swaps with a total aggregate notional amount of $150.0 million related to the anticipated issuance of debt on or before October 15, 2014. The purpose of these swaps is to hedge the variability of the forecasted interest payments on these expected debt issuances that may result from changes in the benchmark interest rate until the expected debt is issued. Unrealized gains of $17.2 million were recorded in Buckeye’s accumulated other comprehensive income (loss) to reflect the change in the fair values of the forward-starting interest rate swaps as of December 31, 2009. Buckeye designated the swap agreements as cash flow hedges at inception and expects the changes in values to be highly correlated with the changes in value of the underlying borrowings.

112


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
     In January 2008, Buckeye terminated two forward-starting interest rate swap agreements associated with the 6.050% Notes and made a payment of $9.6 million in connection with the termination. Buckeye has recorded the amount in other comprehensive income and is amortizing the amount of the payment into interest expense over the ten-year term of the 6.050% Notes. Over the next twelve months, Buckeye expects to reclassify $1.0 million of accumulated other comprehensive loss that was generated by these interest rate swap agreements as an increase to interest expense.
  Commodity Derivatives
     Our Energy Services segment primarily uses exchange-traded refined petroleum product futures contracts to manage the risk of market price volatility on its refined petroleum product inventories and its fixed-price sales contracts. The derivative contracts used to hedge refined petroleum product inventories are designated as fair value hedges. Accordingly, our method of measuring ineffectiveness compares the change in the fair value of New York Mercantile Exchange (“NYMEX”) futures contracts to the change in fair value of our hedged fuel inventory. Hedge accounting is discontinued when the hedged fuel inventory is sold or when the related derivative contracts expire. In addition, we periodically enter into offsetting exchange-traded futures contracts to economically close-out an existing futures contract based on a near-term expectation to sell a portion of our fuel inventory. These offsetting derivative contracts are not designated as hedging instruments and any resulting gains or losses are recognized in earnings during the period. Presentations of futures contracts for inventory designated as hedging instruments in the following tables have been presented net of these offsetting futures contracts.
     Our Energy Services segment has not used hedge accounting with respect to its fixed-price sales contracts. Therefore, our fixed-price sales contracts and the related futures contracts used to offset those fixed-price sales contracts are all marked-to-market on the consolidated balance sheets with gains and losses being recognized in earnings during the period.
     In order to hedge the cost of natural gas used to operate our turbine engines at our Linden, New Jersey location, our Pipeline Operations segment bought natural gas futures contracts in March 2009 with terms that coincide with the remaining term of an ongoing natural gas supply contract (January 2010 through July 2011) for a price of $5.47 per million British thermal unit (“MMBtu”). We designated the futures contract as a cash flow hedge at inception. Unrealized gains of $0.3 million were recorded in accumulated other comprehensive income (loss) to reflect the change in the fair values of the contract as of December 31, 2009.
     The following table summarizes our commodity derivative instruments outstanding at December 31, 2009 (amounts in thousands of gallons, except as noted):
                         
    Volume(1)     Accounting  
Derivative Purpose   Current     Long-Term(2)     Treatment  
Derivatives NOT designated as hedging instruments:
                       
Fixed-price sales contracts
    33,428           Mark-to-market
Futures contracts for fixed-price sales contracts
    21,000           Mark-to-market
 
                       
Derivatives designated as hedging instruments:
                       
Futures contracts for inventory
    132,090           Fair Value Hedge
Futures contract for natural gas (MMBtu)
    360,000       210,000     Cash Flow Hedge
 
(1)   Volume represents net notional position.
 
(2)   The maximum term for derivatives included in the long-term column is July 2011.

113


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
     The following table sets forth the fair value of each classification of derivative instruments at the date indicated:
                         
    December 31, 2009  
                    Derivative  
Derivatives NOT designated as   Assets     (Liabilities)     Net Carrying  
hedging instruments:   Fair value     Fair value     Value  
Fixed-price sales contracts
  $ 4,959     $ (3,662 )   $ 1,297  
Futures contracts for fixed-price sales contracts
    7,594       (384 )     7,210  
 
                       
Derivatives designated as hedging instruments:
                       
Futures contracts for inventory
  $ 1,992     $ (20,517 )   $ (18,525 )
Futures contract for natural gas
    312             312  
Interest rate contracts
    17,204             17,204  
 
                     
 
                       
Total
                  $ 7,498  
 
                     
         
    December 31,  
Balance Sheet Locations:   2009  
     
Derivative assets
  $ 4,959  
Other non-current assets
    17,204  
Derivative liabilities
    (14,665 )
 
     
 
       
Total
  $ 7,498  
 
     
     Substantially all of the unrealized net loss of $18.5 million at December 31, 2009 for inventory hedges represented by futures contracts will be realized by the second quarter of 2010 as the related inventory is sold. Gains recorded on inventory hedges that were ineffective were approximately $2.6 million for the year ended December 31, 2009. As of December 31, 2009, open refined petroleum product derivative contracts (represented by the fixed-price sales contracts and futures contracts for fixed-price sales contracts noted above) varied in duration, but did not extend beyond December 2010. In addition, at December 31, 2009, we had refined petroleum product inventories which we intend to use to satisfy a portion of the fixed-price sales contracts.

114


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
     The gains and losses on our derivative instruments recognized in income, the gains and losses reclassified from accumulated other comprehensive income (“AOCI”) to income and the change in value recognized in other comprehensive income (“OCI”) on our derivatives were as follows for the year ended December 31, 2009:
             
        Gain (Loss)  
        Recognized in  
Derivatives NOT designated as       Income on  
hedging instruments   Location   Derivatives  
Fixed-price sales contracts
  Product sales   $ (6,881 )
Futures contracts for fixed-price sales contracts
  Cost of product sales and natural gas storage services     15,653  
 
Derivatives designated as            
hedging instruments   Location        
Futures contracts for inventory
  Cost of product sales and natural gas storage services   $ (47,012 )
Futures contract for natural gas
  Cost of product sales and natural gas storage services     (3 )
Interest rate contracts
  Interest and debt expense     (224 )
                     
                Change in  
                Value  
                Recognized  
Derivatives designated as   Gain (Loss) Reclassified from AOCI to Income     in OCI on  
hedging instruments   Location   Amount     Derivatives  
Futures contract for natural gas
  Cost of product sales and natural gas storage services   $ (409 )   $ 296  
Interest rate contracts
  Interest and debt expense     (218 )     17,204  
Fair Value Measurements
     Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Our fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. Recognized valuation techniques employ inputs such as product prices, operating costs, discount factors and business growth rates. These inputs may be either readily observable, corroborated by market data or generally unobservable. In developing our estimates of fair value, we endeavor to utilize the best information available and apply market-based data to the extent possible. Accordingly, we utilize valuation techniques (such as the income or market approach) that maximize the use of observable inputs and minimize the use of unobservable inputs.
     A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements based on the observability of inputs used to estimate such fair values. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). At each balance sheet reporting date, we categorize our financial assets and liabilities using this hierarchy. The characteristics of fair value amounts classified within each level of the hierarchy are described as follows.
    Level 1 inputs are based on quoted prices, which are available in active markets for identical assets or liabilities as of the reporting date. Active markets are defined as those in which transactions for identical assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

115


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
    Level 2 inputs are based on pricing inputs other than quoted prices in active markets and are either directly or indirectly observable as of the measurement date. Level 2 fair values include instruments that are valued using financial models or other appropriate valuation methodologies and include the following:
    Quoted prices in active markets for similar assets or liabilities.
 
    Quoted prices in markets that are not active for identical or similar assets or liabilities.
 
    Inputs other than quoted prices that are observable for the asset or liability.
 
    Inputs that are derived primarily from or corroborated by observable market data by correlation or other means.
    Level 3 inputs are based on unobservable inputs for the asset or liability. Unobservable inputs are used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. Unobservable inputs reflect the reporting entity’s own ideas about the assumptions that market participants would use in pricing an asset or liability (including assumptions about risk). Unobservable inputs are based on the best information available in the circumstances, which might include the reporting entity’s internally developed data. The reporting entity must not ignore information about market participant assumptions that is reasonably available without undue cost and effort. Level 3 inputs are typically used in connection with internally developed valuation methodologies where management makes its best estimate of an instrument’s fair value.
Recurring
     The following table sets forth financial assets and liabilities, measured at fair value on a recurring basis, as of the measurement dates, December 31, 2009 and 2008, and the basis for that measurement, by level within the fair value hierarchy:
                                 
    December 31, 2009     December 31, 2008  
            Significant             Significant  
    Quoted Prices     Other     Quoted Prices     Other  
    in Active     Observable     in Active     Observable  
    Markets     Inputs     Markets     Inputs  
    (Level 1)     (Level 2)     (Level 1)     (Level 2)  
Financial assets:
                               
Commodity derivatives
  $     $ 4,959     $ 25,225     $ 79,322  
Asset held in trust
    1,793             3,648        
Interest rate derivative
          17,204              
 
                               
Financial liabilities:
                               
Interest rate derivative
                      (333 )
Commodity derivatives
    (11,003 )     (3,662 )     (50,806 )     (1,045 )
 
                       
Total
  $ (9,210 )   $ 18,501     $ (21,933 )   $ 77,944  
 
                       
     The value of the Level 1 commodity derivative assets and liabilities were based on quoted market prices obtained from the NYMEX. The value of the Level 1 asset held in trust was obtained from quoted market prices. The value of the Level 2 commodity derivative assets and liabilities were based on observable market data related to the obligations to provide petroleum products. The value of the Level 2 interest rate derivative was based on observable market data related to similar obligations.

116


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
     The commodity derivative assets of $5.0 million and $79.3 million as of December 31, 2009 and 2008, respectively, are net of a credit valuation adjustment (“CVA”) of ($0.9) million and ($0.6) million, respectively. Because few of the Energy Services segment’s customers entering into these fixed-price sales contracts are large organizations with nationally-recognized credit ratings, the Energy Services segment determined that a CVA, which is based on the credit risk of such contracts, is appropriate. The CVA is based on the historical and expected payment history of each customer, the amount of product contracted for under the agreement, and the customer’s historical and expected purchase performance under each contract.
Non-Recurring
     Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments in certain circumstances, such as when there is evidence of possible impairment. The following table presents the fair value of an asset carried on the consolidated balance sheet by asset classification and by level within the valuation hierarchy (as described above) at the date indicated for which a nonrecurring change in fair value has been recorded during the year ended December 31, 2009:
                                         
    December 31,                             Total  
    2009     Level 1     Level 2     Level 3     Losses  
Assets held for sale (1)
  $ 22,000     $ 22,000     $     $     $ 59,724  
 
(1)   Represents inventory and property, plant and equipment included in assets held for sale (see Note 8).
     As a result of a loss in the customer base utilizing Buckeye’s NGL pipeline, we recorded a non-cash impairment charge of $59.7 million during the year ended December 31, 2009. The estimated fair value was based on the proceeds from the sale of our ownership interest in Buckeye NGL in January 2010.
16. PENSIONS AND OTHER POSTRETIREMENT BENEFITS
RIGP and Retiree Medical Plan
     Services Company, which employs the majority of our workforce, sponsors a retirement income guarantee plan (“RIGP”), which is a defined benefit plan that generally guarantees employees hired before January 1, 1986 a retirement benefit based on years of service and the employee’s highest compensation for any consecutive 5-year period during the last 10 years of service or other compensation measures as defined under the respective plan provisions. The retirement benefit is subject to reduction at varying percentages for certain offsetting amounts, including benefits payable under a retirement and savings plan discussed further below. Services Company funds the plan through contributions to pension trust assets, generally subject to minimum funding requirements as provided by applicable law.
     In addition, Services Company sponsors an unfunded post-retirement benefit plan (the “Retiree Medical Plan”), which provides health care and life insurance benefits to certain of its retirees. To be eligible for these benefits, an employee must have been hired prior to January 1, 1991 and meet certain service requirements.
     Pursuant to the previously mentioned VERP and involuntary reduction in workforce (see Note 3), we recognized a settlement in the RIGP of approximately $14.0 million for the year ended December 31, 2009 as a result of participants in the RIGP receiving lump sum benefit payments. In addition, we recorded a curtailment in the Retiree Medical Plan of approximately $1.1 million for the year ended December 31, 2009 as a result of certain participants affected by the VERP and involuntary reduction in workforce being eligible for benefits under the Retiree Medical Plan.
     Certain employees who were eligible for RIGP benefits retired in 2008. The RIGP provides an option for the retiree to elect a calculated lump sum payment, rather than a retirement annuity, after the participant’s retirement date. The RIGP recognizes pension settlements when payments exceed the sum of service and interest cost

117


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
components of net periodic pension cost for the plan for the fiscal year. The RIGP settled about 10% of the unrecognized losses related to these lump sum payments which resulted in a one-time charge of $1.4 million.
     The following table provides a reconciliation of projected benefit obligations, plan assets and the funded status of the RIGP and the Retiree Medical Plan for the periods indicated:
                                 
    RIGP     Retiree Medical Plan  
    Year Ended December 31,     Year Ended December 31,  
    2009     2008     2009     2008  
Change in benefit obligation:
                               
Benefit obligation at beginning of year
  $ 27,134     $ 20,240     $ 34,877     $ 36,663  
Service cost
    495       723       339       382  
Interest cost
    1,182       1,018       1,941       1,947  
Plan participants’ contributions
                295        
Part D reimbursement
                245        
Actuarial loss (gain)
    4,399       8,299       (964 )     (2,669 )
Curtailments
                1,091        
Settlements
    (13,977 )     (2,990 )            
Benefit payments
    (130 )     (156 )     (2,375 )     (1,446 )
 
                       
Benefit obligation at end of year
  $ 19,103     $ 27,134     $ 35,449     $ 34,877  
 
                       
 
                               
Change in plan assets:
                               
Fair value of plan assets at beginning of year
  $ 10,433     $ 12,915     $     $  
Actual return on plan assets
    (358 )     (189 )            
Plan participants’ contributions
                295        
Part D reimbursement
                245        
Employer contribution
    9,459       853       1,835       1,446  
Settlements
    (13,977 )     (2,990 )            
Benefits paid
    (130 )     (156 )     (2,375 )     (1,446 )
 
                       
Fair value of plan assets at end of year
  $ 5,427     $ 10,433     $     $  
 
                       
 
                               
Funded status at end of year
  $ (13,676 )   $ (16,701 )   $ (35,449 )   $ (34,877 )
 
                       

118


Table of Contents

BUCKEYE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
     Amounts recognized in our consolidated balance sheets consist of the following at the dates indicated:
                                 
    RIGP     Retiree Medical Plan  
    December 31,     December 31,  
    2009     2008     2009     2008  
Liabilities:
                               
Accrued employee benefit liabilities — current
  $     $     $ 3,287