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

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

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)

Title of each class		Name of each exchange on which registered
Common Units representing limited partnership interests		New York Stock Exchange

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
Item 1.		Business			3
Item 1A.		Risk Factors			29
Item 1B.		Unresolved Staff Comments			46
Item 2.		Properties			47
Item 3.		Legal Proceedings			47
Item 4.		[Reserved]			47
		PART II
Item 5.		Market for the Registrant’s Common Units, Related Unitholder Matters, and Issuer Purchases of Common Units			48
Item 6.		Selected Financial Data			49
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			50
Item 7A.		Quantitative and Qualitative Disclosures About Market Risk			74
Item 8.		Financial Statements and Supplementary Data			77
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			133
Item 9A.		Controls and Procedures			133
Item 9B.		Other Information			133
		PART III
Item 10.		Directors, Executive Officers and Corporate Governance			134
Item 11.		Executive Compensation			138
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters			139
Item 13.		Certain Relationships and Related Transactions and Director Independence			141
Item 14.		Principal Accounting Fees and Services			145
		PART IV
Item 15.		Exhibits, Financial Statement Schedules			146
EX-21.1
EX-23.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2

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.

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.

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).

•

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).

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;

	•		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.

  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.

  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.

     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	%

     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

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.

     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

     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

   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.

     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.

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.

     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.

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.

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

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.

     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,

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.

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

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

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

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;

	•		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

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

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

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.

     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.

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

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

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.

     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.

     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.

     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

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’

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,

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.

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.

     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;

	•		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.

     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.

     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

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.

     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

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.

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]

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.

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

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

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

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.

  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.

  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

  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

     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.

     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				—

  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

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.

  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.

     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.

     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.

  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.

     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

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.

     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	)

     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.

•

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.

     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.

	•		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.

     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.

     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

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

     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).

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.

     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

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

Item 8.		Financial Statements and Supplementary Data

		Page
Management’s Report On Internal Control Over Financial Reporting			78
Reports of Independent Registered Public Accounting Firm			79
Consolidated Statements of Operations for the Years Ended December 31, 2009, 2008 and 2007			81
Consolidated Balance Sheets as of December 31, 2009 and 2008			82
Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and 2007			83
Consolidated Statements of Partners’ Capital for the Years Ended December 31, 2009, 2008 and 2007			84
Notes to Consolidated Financial Statements:
1. Organization			85
2. Summary of Significant Accounting Policies			86
3. Reorganization			95
4. Acquisitions and Dispositions			95
5. Commitments and Contingencies			100
6. Inventories			102
7. Prepaid and Other Current Assets			103
8. Property, Plant and Equipment			103
9. Equity Investments			104
10. Goodwill and Intangible Assets			106
11. Other Non-Current Assets			107
12. Accrued and Other Current Liabilities			107
13. Debt Obligations			108
14. Other Non-Current Liabilities			111
15. Derivative Instruments, Hedging Activities and Fair Value Measurements			111
16. Pensions and Other Postretirement Benefits			117
17. Unit-Based Compensation Plans			122
18. Employee Stock Ownership Plan			127
19. Related Party Transactions			127
20. Cash Distributions			128
21. Earnings Per Partnership Unit			128
22. Business Segments			129
23. Supplemental Cash Flow Information			132
24. Quarterly Financial Data (Unaudited)			132