Buckeye Partners (BPL) 10-Q 2011 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2011

OR

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

For the transition period from             to             

Commission file number 1-9356

Buckeye Partners, L.P.

(Exact name of registrant as specified in its charter)

Delaware	23-2432497
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification number)
One Greenway Plaza Suite 600 Houston, TX	77046
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (832) 615-8600

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data 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  x    No  ¨

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	x	Accelerated filer	¨
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	Smaller reporting company	¨

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

Limited partner units and Class B units outstanding as of August 3, 2011: 85,880,404 and 7,042,771, respectively.

TABLE OF CONTENTS

		Page
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June  30, 2011 and 2010 (Unaudited)		2
	Condensed Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June  30, 2011 and 2010 (Unaudited)		3
	Condensed Consolidated Balance Sheets as of June 30, 2011 and December 31, 2010 (Unaudited)		4
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June  30, 2011 and 2010 (Unaudited)		5
	Condensed Consolidated Statements of Partners’ Capital for the Six Months Ended June  30, 2011 and 2010 (Unaudited)		6
	Notes to Unaudited Condensed Consolidated Financial Statements:
	1.      Organization and Basis of Presentation		7
	2.      Acquisitions and Dispositions		9
	3.      Commitments and Contingencies		14
	4.      Inventories		17
	5.      Prepaid and Other Current Assets		18
	6.      Property, Plant and Equipment		18
	7.      Equity Investments		19
	8.      Goodwill and Intangible Assets		20
	9.      Other Non-Current Assets		21
	10.    Accrued and Other Current Liabilities		22
	11.    Debt Obligations		22
	12.    Other Non-Current Liabilities		25
	13.    Accumulated Other Comprehensive Income (Loss)		26
	14.    Derivative Instruments, Hedging Activities and Fair Value Measurements		26
	15.    Pensions and Other Postretirement Benefits		34
	16.    Unit-Based Compensation Plans		35
	17.    Related Party Transactions		39
	18.    Partners’ Capital and Distributions		39
	19.    Earnings Per Unit		40
	20.    Business Segments		41
	21.    Supplemental Cash Flow Information		45
	22.    Subsequent Events		46
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		47
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		70
Item 4.	Controls and Procedures		74
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings		74
Item 1A.	Risk Factors		74
Item 6.	Exhibits		75
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

1

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

BUCKEYE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit amounts)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Revenues:
Product sales	$	853,706		$	501,744		$	1,891,262		$	1,069,914
Transportation and other services		223,386			165,532			438,366			328,536
Total revenue		1,077,092			667,276			2,329,628			1,398,450
Costs and expenses:
Cost of product sales and natural gas storage services		854,341			498,645			1,892,303			1,068,382
Operating expenses		89,869			68,769			170,133			135,352
Depreciation and amortization		29,756			14,669			55,997			29,197
General and administrative		17,191			13,254			32,697			24,089
Total costs and expenses		991,157			595,337			2,151,130			1,257,020
Operating income		85,935			71,939			178,498			141,430
Other income (expense):
Earnings from equity investments		2,034			2,764			5,381			5,416
Gain on sale of equity investment		34,112			—			34,112			—
Interest and debt expense		(28,596	)		(21,350	)		(57,093	)		(43,006	)
Other income		107			85			507			240
Total other income (expense)		7,657			(18,501	)		(17,093	)		(37,350	)
Net income		93,592			53,438			161,405			104,080
Less: net income attributable to noncontrolling interests		(1,571	)		(41,931	)		(2,891	)		(81,303	)
Net income attributable to Buckeye Partners, L.P.	$	92,021		$	11,507		$	158,514		$	22,777
Earnings per unit:
Basic	$	1.00		$	0.58		$	1.81		$	1.14
Diluted	$	1.00		$	0.58		$	1.80		$	1.14
Weighted average number of units outstanding:
Basic		91,743			19,952			87,728			19,952
Diluted		92,088			19,952			88,042			19,952

See Notes to Unaudited Condensed Consolidated Financial Statements.

2

BUCKEYE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)

(Unaudited)

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2011			2010		2011			2010
Net income	$	93,592		$	53,438	$	161,405		$	104,080
Other comprehensive income (loss):
Change in value of derivatives		(13,700	)		—		(9,094	)		—
Amortization of interest rate swaps		241			—		482			—
Gain on settlement of treasury lock, net of amortization		(13	)		—		476			—
Amortization of benefit plan costs		(130	)		—		(240	)		—
Total other comprehensive loss		(13,602	)		—		(8,376	)		—
Comprehensive income	$	79,990		$	53,438	$	153,029		$	104,080

See Notes to Unaudited Condensed Consolidated Financial Statements.

3

BUCKEYE PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except unit amounts)

(Unaudited)

	June 30,			December 31,
	2011			2010
Assets:
Current assets:
Cash and cash equivalents	$	18,133		$	13,626
Trade receivables, net		158,926			167,274
Construction and pipeline relocation receivables		5,040			6,803
Inventories		345,712			351,605
Derivative assets		749			1,634
Prepaid and other current assets		88,470			85,689
Total current assets		617,030			626,631
Property, plant and equipment, net		3,665,288			2,305,884
Equity investments		59,503			107,047
Goodwill		929,578			432,124
Intangible assets, net		243,783			44,067
Other non-current assets		51,439			58,463
Total assets	$	5,566,621		$	3,574,216
Liabilities and partners’ capital:
Current liabilities:
Line of credit	$	267,200		$	284,300
Current portion of long-term debt		—			1,525
Accounts payable		67,036			68,530
Derivative liabilities		2,500			17,285
Accrued and other current liabilities		202,662			144,880
Total current liabilities		539,398			516,520
Long-term debt		2,189,238			1,519,393
Other non-current liabilities		198,101			128,043
Total liabilities		2,926,737			2,163,956
Commitments and contingent liabilities		—			—
Partners’ capital:
Buckeye Partners, L.P. capital:
Limited Partners (85,879,280 and 71,436,099 units outstanding as of June 30, 2011 and December 31, 2010, respectively)		2,253,820			1,413,664
Class B Units (7,042,771 and 0 units outstanding as of June 30, 2011 and December 31, 2010, respectively)		398,734			—
Accumulated other comprehensive loss		(29,635	)		(21,259	)
Total Buckeye Partners, L.P. capital		2,622,919			1,392,405
Noncontrolling interests		16,965			17,855
Total partners’ capital		2,639,884			1,410,260
Total liabilities and partners’ capital	$	5,566,621		$	3,574,216

See Notes to Unaudited Condensed Consolidated Financial Statements.

4

BUCKEYE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Six Months Ended
	June 30,
	2011			2010
Cash flows from operating activities:
Net income	$	161,405		$	104,080
Adjustments to reconcile net income to net cash provided by operating activities:
Gain on sale of equity investment		(34,112	)		—
Value of ESOP shares released		1,183			2,271
Depreciation and amortization		55,997			29,197
Net changes in fair value of derivatives		(68,542	)		(12,901	)
Non-cash deferred lease expense		2,061			2,117
Amortization of unfavorable storage contracts		(4,328	)		—
Earnings from equity investments		(5,381	)		(5,416	)
Distributions from equity investments		1,792			3,700
Amortization of other non-cash items		7,081			5,060
Change in assets and liabilities, net of amounts related to acquisitions:
Trade receivables		18,840			10,589
Construction and pipeline relocation receivables		1,763			2,469
Inventories		58,140			28,065
Prepaid and other current assets		334			36,962
Accounts payable		(23,715	)		7,629
Accrued and other current liabilities		2,243			11,058
Other non-current assets		6,845			3,370
Other non-current liabilities		3,249			3,701
Total adjustments from operating activities		23,450			127,871
Net cash provided by operating activities		184,855			231,951
Cash flows from investing activities:
Capital expenditures		(100,461	)		(27,572	)
Deposit in anticipation of acquisition		(1,811	)		—
Acquisitions, net of cash acquired		(1,061,232	)		—
Proceeds from sale of equity investment		85,000			—
Net proceeds from disposal of property, plant and equipment		433			22,274
Net cash used in investing activities		(1,078,071	)		(5,298	)
Cash flows from financing activities:
Net proceeds from issuance of units		736,997			—
Proceeds from exercise of unit options		435			2,976
Issuance of long-term debt		647,530			—
Repayment of long term-debt		(1,525	)		(3,104	)
Borrowings under credit facility		683,532			95,000
Repayments under credit facility		(661,532	)		(173,000	)
Net repayments under BES credit agreement		(17,100	)		(45,621	)
Debt issuance costs		(4,919	)		(3,227	)
Repayment of debt assumed in BORCO acquisition		(318,167	)		—
Costs associated with agreement and plan of merger		(1,350	)		(1,547	)
Distributions paid to noncontrolling partners of Buckeye Partners, L.P.		(3,768	)		(96,435	)
Proceeds from settlement of treasury lock		497			—
Distributions paid to partners of Buckeye GP Holdings L.P.		—			(23,772	)
Distributions paid to unitholders		(162,907	)		—
Net cash provided by (used in) financing activities		897,723			(248,730	)
Net increase (decrease) in cash and cash equivalents		4,507			(22,077	)
Cash and cash equivalents — Beginning of period		13,626			37,574
Cash and cash equivalents — End of period	$	18,133		$	15,497

See Notes to Unaudited Condensed Consolidated Financial Statements.

5

BUCKEYE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(In thousands)

(Unaudited)

	Buckeye Partners, L.P. Unitholders
	General Partner		Limited Partners			Class B Units			Management Units			Equity Gains on Issuance of Buckeye’s Limited Partner  Units		Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
Partners’ capital - January 1, 2011	$	—	$	1,413,664		$	—		$	—		$	—	$	(21,259	)	$	17,855		$	1,410,260
Net income		—		147,520			10,994			—			—		—			2,891			161,405
Acquisition of 80% interest in BORCO		—		—			—			—			—		—			276,508			276,508
Acquisition of remaining interest in BORCO		—		—			—			—			—		—			(278,211	)		(278,211	)
Costs associated with agreement and plan of merger		—		(1,350	)		—			—			—		—			—			(1,350	)
Distributions paid to partners		—		(162,907	)		—			—			—		—			—			(162,907	)
Issuance of units to First Reserve for BORCO acquisition		—		152,772			254,619			—			—		—			—			407,391
Issuance of units to Vopak for BORCO acquisition		—		36,041			60,069			—			—		—			—			96,110
Issuance of units to institutional investors		—		350,001			75,000			—			—		—			—			425,001
Equity issuance costs		—		(2,693	)		(1,948	)		—			—		—			—			(4,641	)
Net proceeds from issuance of LP Units in underwritten public offering		—		316,637			—			—			—		—			—			316,637
Amortization of unit-based compensation awards		—		4,753			—			—			—		—			—			4,753
Exercise of LP Unit options		—		435			—			—			—		—			—			435
Services Company’s non-cash ESOP distributions		—		—			—			—			—		—			(1,410	)		(1,410	)
Distributions paid to noncontrolling interests		—		—			—			—			—		—			(3,768	)		(3,768	)
Amortization of benefit plan costs		—		—			—			—			—		(240	)		—			(240	)
Change in value of derivatives		—		—			—			—			—		(9,094	)		—			(9,094	)
Amortization of interest rate swaps		—		—			—			—			—		482			—			482
Amortization of treasury lock settlement		—		—			—			—			—		(21	)		—			(21	)
Proceeds from settlement of treasury lock		—		—			—			—			—		497			—			497
Noncash accrual for distribution equivalent rights		—		(578	)		—			—			—		—			—			(578	)
Other		—		(475	)		—			—			—		—			3,100			2,625
Partners’ capital - June 30, 2011	$	—	$	2,253,820		$	398,734		$	—		$	—	$	(29,635	)	$	16,965		$	2,639,884
Partners’ capital - January 1, 2010	$	7	$	236,545		$	—		$	3,225		$	2,557	$	—		$	1,209,960		$	1,452,294
Net income		—		22,350			—			427			—		—			81,303			104,080
Costs associated with agreement and plan of merger		—		(1,941	)		—			(37	)		—		—			(1,846	)		(3,824	)
Distributions paid to partners of BGH		—		(23,327	)		—			(445	)		—		—			—			(23,772	)
Recognition of unit-based compensation charges		—		630			—			12			—		—			—			642
Amortization of unit-based compensation awards		—		—			—			—			—		—			3,596			3,596
Exercise of LP Unit options		—		—			—			—			—		—			2,976			2,976
Services Company’s non-cash ESOP distributions		—		—			—			—			—		—			(2,639	)		(2,639	)
Distributions paid to noncontrolling interests		—		—			—			—			—		—			(96,435	)		(96,435	)
Change in value of derivatives		—		—			—			—			—		—			(36,600	)		(36,600	)
BGH’s investment in LP units		—		—			—			—			—		—			4,503			4,503
Other		—		—			—			—			—		—			(991	)		(991	)
Partners’ capital - June 30, 2010	$	7	$	234,257		$	—		$	3,182		$	2,557	$	—		$	1,163,827		$	1,403,830

See Notes to Unaudited Condensed Consolidated Financial Statements.

6

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND BASIS OF PRESENTATION

Partnership Organization

Buckeye Partners, L.P. is a publicly traded Delaware master limited partnership (“MLP”), and its limited partnership units representing limited partner interests (“LP Units”) are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “BPL.” Buckeye GP LLC (“Buckeye GP”) is our general partner. Buckeye GP is a wholly owned subsidiary of Buckeye GP Holdings L.P. (“BGH”), a Delaware limited partnership that was previously publicly traded on the NYSE prior to BGH’s merger with a wholly owned subsidiary of Buckeye (see below for further information). As used in these Notes to Unaudited Condensed Consolidated Financial Statements, “we,” “us,” “our” and “Buckeye” mean Buckeye Partners, L.P. and, where the context requires, includes our subsidiaries.

We were formed in 1986 and own and operate one of the largest independent refined petroleum products pipeline systems in the United States in terms of volumes delivered with approximately 6,100 miles of pipeline and over 100 active products terminals that provide aggregate storage capacity of over 64 million barrels. In 2011, we acquired (i) the Bahamas Oil Refining Company International Limited (“BORCO”) terminal facility in Freeport, Grand Bahama, The Bahamas, with a total installed capacity of approximately 21.6 million barrels, (ii) 33 refined petroleum products terminals with a total storage capacity of over 10 million barrels and approximately 650 miles of refined petroleum products pipelines (see Note 2) and (iii) interests in two petroleum products terminals in Maine with a total storage capacity of approximately 0.9 million barrels and a 124-mile pipeline that connects the two terminals (see Note 22). In addition, we operate and maintain approximately 3,400 miles of other pipelines under agreements with major oil and gas, petrochemical and chemical companies, and perform certain engineering and construction management services for third parties. We also own and operate a high performance natural gas storage facility in northern California, and are a wholesale distributor of refined petroleum products in the United States in areas also served by our pipelines and terminals.

We operate and report in five business segments: Pipelines & Terminals; International Operations; Natural Gas Storage; Energy Services; and Development & Logistics. Effective January 1, 2011, we realigned our five business segments. We combined the Pipeline Operations and Terminalling & Storage segments into one segment, the Pipelines & Terminals segment, and moved our terminal in Yabucoa, Puerto Rico, previously included as part of the Terminalling & Storage segment, to a new International Operations segment with the BORCO facility. See Note 20 for a discussion of our business segments.

On November 19, 2010, we consummated a transaction pursuant to a plan and agreement of merger (the “Merger Agreement”) with our general partner, BGH, BGH’s general partner and Grand Ohio, LLC (“Merger Sub”), our subsidiary. Pursuant to the Merger Agreement, Merger Sub was merged into BGH, with BGH as the surviving entity (the “Merger”). In the transaction, the incentive compensation agreement (also referred to as the incentive distribution rights) held by our general partner was cancelled, the general partner units held by our general partner (representing an approximate 0.5% general partner interest in us) were converted to a non-economic general partner interest, all of the economic interest in BGH was acquired by us and BGH unitholders received aggregate consideration of approximately 20.0 million of our LP Units.

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 June 30, 2011, Services Company owned approximately 1.6% of our LP Units. Services Company employees provide services to our operating subsidiaries. Pursuant to a services agreement entered into in December 2004, our operating subsidiaries reimburse Services Company for the costs of the services provided by Services Company. Services Company has been consolidated into our financial statements.

Basis of Presentation and Principles of Consolidation

These consolidated financial statements reflect the financial results of BGH for periods prior to the effective date of the Merger. BGH is considered the surviving consolidated entity for accounting purposes, although Buckeye

7

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

is the surviving consolidated entity for legal and reporting purposes. The Merger was accounted for as an equity transaction. Therefore, changes in BGH’s ownership interest as a result of the Merger did not result in gain or loss recognition. Costs incurred associated with the Merger were charged directly to partners’ capital. Under applicable accounting guidance, the exchange of BGH’s units for our LP Units was accounted for as a BGH equity issuance and BGH was the surviving entity for accounting purposes. Consequently, the name on these financial statements for periods prior to the Merger has been changed from “Buckeye GP Holdings L.P.” to “Buckeye Partners, L.P.”

The reconciliation of Buckeye’s net income, as historically reported, to the net income reported in these financial statements for the three and six months ended June 30, 2010 is as follows (in thousands):

	Three Months Ended June 30, 2010			Six Months Ended June 30, 2010
Buckeye’s net income, as previously reported	$	55,425		$	107,703
Adjustments:
Depreciation and amortization (1)		1,117			2,233
Costs and expenses (2)		(3,017	)		(5,662	)
Other (3)		(87	)		(194	)
Net income	$	53,438		$	104,080

(1) Represents the amortization of the market value of LP Units issued in August 1997 in connection with the restructuring of Services Company’s ESOP. The market value of those LP Units was $64.2 million, and this amount was recorded as a deferred charge and is being amortized on a straight-line basis over 13.5 years. This deferred charge was not previously included in Buckeye’s net income because Services Company was consolidated with BGH, but not Buckeye, for periods prior to the effective date of the Merger.

(2) Amounts include payroll and benefits costs, professional fees, certain state franchise taxes, insurance costs and miscellaneous other expenses incurred by BGH.

(3) Includes interest expense on Services Company’s debt and commitment fees on BGH’s credit facility. The interest expense was not previously included in Buckeye’s net income because Services Company was consolidated with BGH, but not Buckeye, for periods prior to the effective date of the Merger.

Pursuant to the Merger Agreement, BGH’s unitholders received a total of approximately 20.0 million of Buckeye’s LP Units in the aggregate in exchange for all outstanding BGH common units and management units. As a result, the number of Buckeye’s LP Units outstanding increased from 51.6 million to 71.4 million on the date of the Merger. However, for historical reporting purposes, the impact of this change was accounted for as a reverse split of BGH’s units of 0.705 to 1.0, together with the addition of Buckeye’s existing LP Units. Therefore, since BGH was the surviving accounting entity, the weighted average number of LP Units outstanding used for basic and diluted earnings per unit calculations are BGH’s historical weighted average common units outstanding adjusted for the reverse unit split and the addition of Buckeye’s existing units. Amounts reflecting historical BGH unit and per unit amounts included in this report have been restated for the reverse unit split.

The condensed consolidated financial statements and the accompanying notes are prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) and the rules of the U.S. Securities and Exchange Commission (“SEC”). The financial statements include our accounts on a consolidated basis. We have eliminated all intercompany transactions in consolidation. The consolidated financial statements include the financial results of our wholly-owned subsidiaries and the financial results of Services Company on a consolidated basis.

Recent Accounting Developments

Fair Value Measurements. In January 2010, the Financial Accounting Standards Board (“FASB”) issued guidance that requires new disclosures related to fair value measurements. The new guidance requires expanded disclosures related to a gross presentation for Level 3 activity. The new accounting guidance was effective for fiscal years beginning after December 15, 2010 and for interim periods within those years. The new guidance became effective for us on January 1, 2011. We have included the enhanced disclosure requirements regarding fair value measurements in Note 14.

8

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

In May 2011, the FASB issued guidance that is intended to result in convergence between GAAP and International Financial Reporting Standards requirements for measurement of and disclosures about fair value. The amendments are not expected to have a significant impact on companies applying GAAP. Key provisions of the new guidance include: a prohibition on grouping financial instruments for purposes of determining fair value, except when an entity manages market and credit risks on the basis of the entity’s net exposure to the group; an extension of the prohibition against the use of a blockage factor to all fair value measurements (that prohibition currently applies only to financial instruments with quoted prices in active markets); and a requirement that for recurring Level 3 fair value measurements, entities disclose quantitative information about unobservable inputs, a description of the valuation process used and qualitative details about the sensitivity of the measurements. In addition, for items not carried at fair value but for which fair value is disclosed, entities will be required to disclose the level within the fair value hierarchy that applies to the fair value measurement disclosed. This new guidance is effective for interim and annual periods beginning after December 15, 2011. We do not expect the adoption of this guidance to have an impact on our consolidated financial statements.

Intangibles, Goodwill and Other. In December 2010, the FASB issued guidance that amended the goodwill impairment test for reporting units with zero or negative carrying amounts. The objective of this new guidance is to address questions about entities with reporting units with zero or negative carrying amounts because some entities concluded that the first step of the goodwill impairment test is passed in those circumstances because the fair value of their reporting unit will generally be greater than zero. The new guidance is effective for fiscal years and interim periods, within those years, beginning after December 15, 2010. We do not expect the adoption of this guidance to have an impact on our consolidated financial statements.

Business Combinations. In December 2010, the FASB issued guidance that clarifies disclosures related to pro forma information for business combinations that occurred in the current period. The amendments specify that if an entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The amendments also expand the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The new guidance is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. Early adoption is permitted. We have included the enhanced disclosure requirements regarding pro forma information for business combinations in Note 2.

Presentation of Comprehensive Income. In June 2011, the FASB issued guidance that will require companies to present the components of net income and other comprehensive income either as one continuous statement or as two consecutive statements. The guidance eliminates the option to present components of other comprehensive income as part of the statement of changes in unitholders’ equity. The guidance does not change the items which must be reported in other comprehensive income, how such items are measured or when they must be reclassified to net income. The new guidance is effective for interim and annual periods beginning after December 15, 2011. Because this guidance impacts presentation only, it will have no effect on our financial condition, results of operations or cash flows.

2. ACQUISITIONS AND DISPOSITIONS

Acquisitions

The acquisitions of terminals from an affiliate of Royal Dutch Shell plc (“Shell”) and from affiliates of FRC Founders Corporation (“First Reserve”) and Vopak Bahamas B.V. (“Vopak”) and the acquisition of pipeline and terminal assets from BP Products North America Inc. and its affiliates (“BP”) have been accounted for as business combinations. The total purchase price for these acquisitions was allocated to the fair value of the assets acquired

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

and the liabilities assumed based on an assessment of their fair values at the acquisition date, with amounts exceeding the fair values being recorded as goodwill. The results of their operations have been included in our condensed consolidated financial statements since their respective acquisition dates.

Puerto Rico Terminal Acquisition

On December 10, 2010, we, through a wholly owned subsidiary, acquired a refined petroleum products terminal in Yabucoa, Puerto Rico from an affiliate of Shell for $32.8 million, net of cash acquired of $3.5 million. The terminal includes 44 storage tanks with approximately 4.6 million barrels of gasoline, jet fuel, diesel, fuel oil and crude oil storage capacity. Shell entered into a commercial contract with us concurrent with the acquisition regarding usage of the acquired facility. We believe the acquisition of these assets furthers our geographic diversification efforts as this was our first acquisition outside the continental United States and enables us to participate in a growth market outside our existing system footprint. The operations of these acquired assets are reported in the International Operations segment. The purchase price has been allocated to tangible and intangible assets acquired as follows (in thousands):

Current assets	$	183
Inventory		867
Property, plant and equipment		31,770
Intangible assets		3,363
Other assets		17,720
Current liabilities		(3,413	)
Other liabilities		(17,720	)
Allocated purchase price	$	32,770

We completed the acquisition of the refined petroleum products terminal in Yabucoa, Puerto Rico through the acquisition of a Puerto Rican entity, which is undergoing an audit of its Puerto Rico income tax returns for the tax years 2002 through 2005. The Puerto Rico Treasury Department has notified the entity of certain areas for discussion but has not issued a preliminary or final notice of debt regarding such years. Pursuant to the purchase and sale agreement we entered into in connection with this acquisition, an affiliate of Shell has assumed the full responsibility, through an indemnity and hold harmless provision, for the payment of any income tax debt that may be assessed by the Puerto Rico Treasury Department under this audit. In the purchase price allocation above, we recorded a $17.7 million liability related to the uncertain outcome of the income tax audit with an offsetting indemnification asset from Shell for the same amount.

BORCO Acquisition

On December 18, 2010, we, through a wholly owned subsidiary, entered into a sale and purchase agreement with affiliates of First Reserve, pursuant to which we agreed to acquire First Reserve’s indirect 80% interest in FR Borco Coop Holdings, L.P. (“FRBCH”), the indirect owner of BORCO, for $1.15 billion, financed through a combination of debt and equity, including the issuance of Class B units representing limited partner interests (“Class B Units”) and LP Units to First Reserve. BORCO is the fourth largest oil and petroleum products storage terminal in the world and the largest petroleum products facility in the Caribbean with current storage capacity of approximately 21.6 million barrels. On January 18, 2011, we completed the purchase of First Reserve’s interest in BORCO through the acquisition by us of all of the partnership interests in FR Borco Topco, L.P., which indirectly owned First Reserve’s interest.

Vopak, which is based in The Netherlands, owned the remaining 20% interest in FRBCH. On February 16, 2011, Vopak sold its 20% interest in FRBCH to us for approximately $276.5 million of cash and equity, which is a proportionate price and on the same terms and conditions as those in the sale and purchase agreement with First Reserve.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the aggregate consideration paid or issued to complete the BORCO acquisition (in thousands):

	First Reserve		Vopak		Combined
Cash consideration	$	644,049	$	164,616	$	808,665
Fair value of LP Units and Class B Units issued (1)		407,391		96,110		503,501
Cash paid on behalf of the sellers (2)		96,241		15,780		112,021
Consideration issued to effect the transactions	$	1,147,681	$	276,506	$	1,424,187

(1) On January 18, 2011, we issued 2,483,444 LP Units and 4,382,889 Class B Units to First Reserve, which represented a negotiated value of $400.0 million of consideration. On February 16, 2011, we issued 620,861 LP Units and 1,095,722 Class B Units to Vopak, which represented a negotiated value of $100.0 million of consideration. In accordance with accounting for business combinations, the fair values of the units issued to First Reserve and Vopak on their respective acquisition dates were determined to be $407.4 million and $96.1 million, respectively.

(2) Approximately $79.3 million was to be held in escrow related to Bahamian transfer taxes payable, approximately $23.2 million was used to make certain payments to BORCO’s operator and indirect minority owner and to pay certain fees and expenses incurred by FRBCH and its affiliates in connection with the transaction and approximately $9.5 million was used to pay bonuses to employees that became payable as a result of the transaction.

On January 13, 2011, we issued $650.0 million aggregate principal amount of 4.875% Notes due 2021 (the “4.875% Notes”) in an underwritten public offering. The notes were issued at 99.62% of their principal amount. Total proceeds from this offering, after underwriters’ fees, expenses and debt issuance costs of $4.9 million, were approximately $642.6 million, and were used to fund a portion of the purchase price of the BORCO acquisition.

On January 18 and 19, 2011, we issued 5,794,725 LP Units and 1,314,870 Class B Units to institutional investors for aggregate consideration of approximately $425.0 million to fund a portion of the BORCO acquisition. On January 18, 2011, we issued 2,483,444 LP Units and 4,382,889 Class B Units to First Reserve as $400.0 million of consideration to fund a portion of the BORCO acquisition. On February 16, 2011, we issued 620,861 LP Units and 1,095,722 Class B Units to Vopak as $100.0 million of consideration to fund a portion of the BORCO acquisition. Equity issuance costs incurred on these transactions were approximately $4.6 million. The remaining purchase price was funded with cash on hand at closing and borrowings under our unsecured revolving credit agreement (“Credit Facility”).

On January 18, 2011, in connection with the BORCO acquisition, we repaid all of BORCO’s outstanding indebtedness and settled BORCO’s interest rate derivative instruments, consisting of approximately $318.2 million.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The results of operations of the BORCO acquisition are included in our consolidated financial statements from the date of acquisition and are included in our International Operations segment. The acquisition cost has been allocated to assets acquired and liabilities assumed based on estimated fair values at the acquisition date, with amounts exceeding the fair value recorded as goodwill, which represents both expected synergies from combining the BORCO acquisition with our existing operations and the economic value attributable to future expansion projects resulting from this acquisition. Fair values have been developed using recognized business valuation techniques and are subject to change pending final valuation analysis. The purchase price has been allocated to tangible and intangible assets acquired, on a preliminary basis, as follows (in thousands):

Current assets	$	41,540
Inventory		1,645
Property, plant and equipment		1,105,278
Intangible assets		206,000
Other assets		415
Goodwill		497,454
Current liabilities		(55,270	)
Debt, including interest rate derivative instruments		(318,167	)
Other non-current liabilities		(54,708	)
Allocated purchase price	$	1,424,187

Pipeline and Terminals Acquisition

On June 1, 2011, we acquired 33 refined petroleum products terminals with total storage capacity of over 10 million barrels and approximately 650 miles of refined petroleum products pipelines from BP for $166.0 million. The terminal and pipeline assets are located in the Midwestern, Southeastern and Western United States. BP entered into a commercial contract with us concurrent with the acquisition relating to the continued usage of these terminals. We believe the acquisition of these assets further extends our operations into new, key geographic markets. The operations of these acquired assets are reported in the Pipelines & Terminals segment. We funded this acquisition with borrowings under our Credit Facility. We continue to evaluate and may revise the preliminary purchase price allocation, primarily the value of property, plant and equipment, in future periods as estimated fair values are finalized. The purchase price has been allocated to tangible assets acquired, on a preliminary basis, as follows (in thousands):

Inventory	$	1,161
Property, plant and equipment		183,537
Environmental and other liabilities		(18,722	)
Allocated purchase price	$	165,976

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Pro forma Financial Results

Our condensed consolidated statements of operations do not include earnings from BORCO prior to January 18, 2011, the effective date of the BORCO acquisition. The following table presents selected unaudited pro forma earnings information for the three months ended June 30, 2010 and the six months ended June 30, 2011 and 2010, as if the BORCO acquisition had occurred on January 1, 2010. This pro forma information does not give effect to any of the other acquisitions we have made since January 1, 2010, as pro forma results including those acquisitions would not be materially different from the information presented in our accompanying condensed consolidated statements of operations. The pro forma information presented below was prepared using BORCO’s historical financial data and reflects certain estimates and assumptions made by our management. Our unaudited pro forma financial information was prepared for comparative purposes only and is not necessarily indicative of what our consolidated financial results would have been had we actually acquired BORCO on January 1, 2010 or the results that may be attained in the future (in thousands):

	Three Months Ended June 30,				Six Months Ended June  30,
	2011		2010		2011		2010
Revenues:
As reported	$	1,077,092	$	667,276	$	2,329,628	$	1,398,450
Pro forma adjustments		—		49,904		8,358		96,414
Pro forma revenues	$	1,077,092	$	717,180	$	2,337,986	$	1,494,864
Net income:
As reported	$	92,021	$	11,507	$	158,514	$	22,777
Pro forma adjustments		—		17,000		4,057		33,782
Pro forma net income	$	92,021	$	28,507	$	162,571	$	56,559
Pro forma earnings per unit:
Basic	$	1.00	$	0.80	$	1.85	$	1.58
Diluted	$	1.00	$	0.80	$	1.85	$	1.58
Pro forma weighted average number of units outstanding:
Basic		91,743		35,829		87,728		35,760
Diluted		92,088		35,829		88,042		35,760

Dispositions

On May 11, 2011, we sold our 20% interest in West Texas LPG Pipeline Limited Partnership (“WT LPG”) to affiliates of Atlas Pipeline Partners L.P. for $85.0 million. WT LPG owns a 2,295-mile common-carrier pipeline system that transports natural gas liquids from points in New Mexico and Texas to Mont Belvieu, Texas for fractionation. Chevron Pipeline Company, which owns the remaining 80% interest, is the operator of WT LPG. The proceeds from the sale will be used to fund a portion of our internal growth capital projects in 2011. We recognized a gain of $34.1 million on the sale of our interest in WT LPG.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

3. COMMITMENTS AND CONTINGENCIES

Claims and Proceedings

In the ordinary course of business, we are involved in various claims and legal proceedings, some of which are covered by insurance. We are generally unable to predict the timing or outcome of these claims and proceedings. Based upon our evaluation of existing claims and proceedings and the probability of losses relating to such contingencies, we have accrued certain amounts relating to such claims and proceedings, none of which are considered material.

In June 2009, the Pipeline Hazardous Materials Safety Administration (“PHMSA”) proposed penalties totaling approximately $0.6 million as a result of alleged violations of various pipeline safety requirements raised as a result of PHMSA’s 2008 integrated inspection of our procedures and records for operations and maintenance, operator qualification, and integrity management as well as field inspections of locations in Pennsylvania, Ohio, Illinois, Michigan and Colorado. We are contesting portions of the proposed penalty. The timing or outcome of final resolution of this matter cannot reasonably be determined at this time.

In April 2010, PHMSA proposed penalties totaling approximately $0.5 million in connection with a tank overfill incident that occurred at our facility in East Chicago, Indiana in May 2005 and other related personnel qualification issues raised as a result of PHMSA’s 2008 Integrity Inspection. We are contesting the proposed penalty. The timing or outcome of this appeal cannot reasonably be determined at this time.

On July 30, 2010, a putative class action was filed by a unitholder against BGH, MainLine Management LLC (“MainLine Management”), BGH GP Holdings, LLC (“BGH GP”) and each of MainLine Management’s directors in the District Court of Harris County, Texas under the captionBroadbased Equities v. Forrest E. Wylie, et. al. In the Petition, the plaintiff alleged that MainLine Management and its directors breached their fiduciary duties to BGH’s public unitholders by, among other things, acting to facilitate the sale of BGH to Buckeye in order to facilitate the gradual sale by BGH GP of its interest in BGH and failing to disclose all material facts in order that the BGH unitholders could cast an informed vote on the Merger Agreement. Among other things, the Petition sought an order certifying a class consisting of all BGH unitholders, a determination that the action was a proper derivative action, damages in an unspecified amount, and an award of attorneys’ fees and costs.

On August 2, 2010, a putative class action was filed by a unitholder against BGH, MainLine Management, Merger Sub, Buckeye, Buckeye GP and each of MainLine Management’s directors in the District Court of Harris County, Texas under the captionHenry James Steward v. Forrest E. Wylie, et. al. In the Petition, the plaintiff alleged that MainLine Management and its directors breached their fiduciary duties to BGH’s public unitholders by, among other things, failing to disclose all material facts in order that the BGH unitholders could cast an informed vote on the Merger Agreement. The Petition also alleged that Buckeye, Buckeye GP and Merger Sub aided and abetted the breaches of fiduciary duty. Among other things, the Petition sought an order certifying a plaintiff class consisting of all of BGH unitholders, an order enjoining the Merger, rescission of the Merger, damages in an unspecified amount, and an award of attorneys’ fees and costs.

On August 2, 2010, a putative class action was filed by a unitholder against BGH, MainLine Management, BGH GP, ArcLight Capital Partners (“ArcLight”), Kelso & Company (“Kelso”), Buckeye, Buckeye GP and each of MainLine Management’s directors in the District Court of Harris County, Texas under the captionJR Garrett Trust v. Buckeye GP Holdings L.P. et al.In the Petition, the plaintiff alleged that MainLine Management and its directors breached their fiduciary duties to BGH’s public unitholders by, among other things, accepting insufficient consideration, failing to condition the Merger on a majority vote of public unitholders of BGH, and failing to disclose all material facts in order that the BGH unitholders could cast an informed vote on the Merger Agreement. The Petition also alleged that Buckeye, Buckeye GP, BGH GP, ArcLight and Kelso aided and abetted the breaches of fiduciary duty. Among other things, the Petition sought an order certifying a class consisting of all of BGH’s unitholders, an order enjoining the Merger, damages in an unspecified amount, and an award of attorneys’ fees and costs.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

On August 24, 2010, the District Court of Harris County, Texas entered an order consolidating the three previously filed putative class actions (Broadbased Equities v. Forrest E. Wylie, et. al.,Henry James Steward v. Forrest E. Wylie, et. al., andJR Garrett Trust v. Buckeye GP Holdings L.P., et al.,) under the caption ofBroadbased Equities v. Forrest E. Wylie, et al. and appointing interim co-lead class counsel and interim co-liaison counsel. The plaintiffs subsequently filed a consolidated amended class action and derivative complaint on September 1, 2010 (the “Complaint”). The Complaint purported to be a putative class and derivative action alleging that MainLine Management and its directors breached their fiduciary duties to BGH’s public unitholders in connection with the Merger by, among other things, accepting insufficient consideration and failing to disclose all material facts in order that BGH’s unitholders could cast an informed vote on the Merger Agreement, and that we, Buckeye GP, MainLine Management, Merger Sub, BGH GP, ArcLight and Kelso aided and abetted the breaches of fiduciary duty.

On October 29, 2010, the parties to the litigation entered into a Memorandum of Understanding (“MOU”) in connection with a proposed settlement of the class action and the Complaint. The MOU provides for dismissal with prejudice of the litigation and a release of the defendants from all present and future claims asserted in the litigation in exchange for, among other things, the agreement of the defendants to amend the Merger Agreement to reduce the termination fees payable by BGH upon termination of the Merger Agreement and to provide BGH’s unitholders with supplemental disclosure to BGH’s and our joint proxy statement/prospectus, dated September 24, 2010. The supplemental disclosure is set forth in a joint proxy statement/prospectus supplement, dated October 29, 2010, which was filed with the SEC on November 1, 2010.

In addition, the MOU provides that, in settlement of the plaintiffs’ claims (including any claim against the defendants by the plaintiffs’ counsel for attorneys’ fees or expenses related to the litigation), the defendants (or their insurers) will make a cash payment of $900,000 to plaintiff’s counsel for attorneys’ fees, subject to final court approval of the settlement. On January 25, 2011, pursuant to the MOU, the parties signed a Stipulation of Settlement. The Stipulation of Settlement was filed with the court, and the court preliminarily approved the settlement on March 21, 2011. The court held a hearing on May 23, 2011 to consider the fairness of the settlement and whether to finally approve the settlement. On May 23, 2011, after the hearing, the court issued an order that, among other things, finally approved all terms of the settlement and dismissed the action.

We and the other defendants vigorously deny all liability with respect to the facts and claims alleged in the Complaint, and specifically deny that any modifications to the Merger Agreement or any supplemental disclosure was required or advisable under any applicable rule, statute, regulation or law. However, to avoid the substantial burden, expense, risk, inconvenience and distraction of continuing the litigation, and to fully resolve the claims alleged, we and the other defendants agreed to the proposed settlement described above.

Environmental Contingencies

In accordance with our accounting policy, we recorded operating expenses, net of insurance recoveries, of $2.4 million and $2.5 million during the three months ended June 30, 2011 and 2010, respectively, related to environmental expenditures unrelated to claims and proceedings. For the six months ended June 30, 2011 and 2010, we recorded operating expenses, net of insurance recoveries, of $4.8 million and $5.4 million, respectively, related to environmental expenditures unrelated to claims and proceedings.

Ammonia Contract Contingencies

On November 30, 2005, Buckeye Development & Logistics I LLC (“BDL”) (formerly Buckeye Gulf Coast Pipe Lines, L.P.) purchased an ammonia pipeline and other assets from El Paso Merchant Energy-Petroleum Company (“EPME”), a subsidiary of El Paso Corporation (“El Paso”). As part of the transaction, BDL assumed the obligations of EPME under several contracts involving monthly purchases and sales of ammonia. EPME and BDL agreed, however, that EPME would retain the economic risks and benefits associated with those contracts until their expiration at the end of 2012. To effectuate this agreement, BDL passes through to EPME both the cost of purchasing ammonia under a supply contract and the proceeds from selling ammonia under three sales contracts. For the vast majority of monthly periods since the closing of the pipeline acquisition, the pricing terms of the ammonia contracts have resulted in ammonia supply costs exceeding ammonia sales proceeds. The amount of the shortfall generally increases as the market price of ammonia increases.

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BUCKEYE PARTNERS, L.P.

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EPME has informed BDL that, notwithstanding the parties’ agreement, it will not continue to pay BDL for shortfalls created by the pass-through of ammonia costs in excess of ammonia revenues. EPME encouraged BDL to seek payment by invoking a $40.0 million guaranty made by El Paso, which guaranteed EPME’s obligations to BDL. If EPME fails to reimburse BDL for these shortfalls, then such unreimbursed shortfalls could exceed the $40.0 million cap on El Paso’s guaranty. To the extent the unreimbursed shortfalls significantly exceed the $40.0 million cap, the resulting costs incurred by BDL could adversely affect our financial position, results of operations and cash flows. To date, BDL has continued to receive payment for ammonia costs under the contracts at issue. BDL has not called on El Paso’s guaranty and believes only BDL may invoke the guaranty. EPME, however, contends that El Paso’s guaranty is the source of payment for the shortfalls, but has not clarified the extent to which it believes the guaranty has been exhausted. We, in cooperation with EPME, have terminated one of the ammonia sales contracts. Given the uncertainty of future ammonia prices and EPME’s future actions, we continue to believe we may have risk of loss in connection with the two remaining ammonia sales contracts and an ammonia supply contract and, at this time, are unable to estimate the amount of any such losses we might incur in the future. We are assessing our options in the event that we are unable to mitigate our risk with respect to the remaining contracts through termination of such contracts by other means, including commencing litigation or pursuing other recourse against EPME and El Paso, with respect to this matter.

Leases –Where We are Lessee

We lease certain property, plant and equipment under noncancelable and cancelable operating leases. Lease expense is charged to operating expenses on a straight-line basis over the period of expected benefit. Contingent rental payments are expensed as incurred. Total rental expense for the three months ended June 30, 2011 and 2010 was $8.5 million and $5.5 million, respectively. For the six months ended June 30, 2011 and 2010, total rental expense was $16.1 million and $10.5 million, respectively. The following table presents minimum lease payment obligations under our operating leases with terms in excess of one year for the years ending December 31 (in thousands):

	Office space and other  (1)		Equipment (2)		Land Leases (3)		Total (4)
2011 (remainder)	$	1,011	$	1,753	$	2,334	$	5,098
2012		2,270		3,487		4,890		10,647
2013		2,439		3,608		5,016		11,063
2014		2,535		2,093		5,100		9,728
2015		2,634		—		5,224		7,858
Thereafter		16,380		—		358,591		374,971
Total	$	27,269	$	10,941	$	381,155	$	419,365

(1) Includes leases of space in office buildings and related land leases with respect to our Albany terminal.

(2) Includes BORCO facility leases for tugboats and a barge in our International Operations segment.

(3) Includes leases for inland dock and seabed in connection with our operations in the International Operations segment and leases for subsurface underground gas storage rights and surface rights in connection with our operations in the Natural Gas Storage segment. We may cancel the Natural Gas Storage segment leases if the storage reservoir is not used for underground storage of natural gas or the removal or injection thereof for a continuous period of two consecutive years. Lease expense associated with the Natural Gas Storage segment leases, which is being recognized on a straight-line basis over 44 years, was approximately $1.8 million for each of the three months ended June 30, 2011 and 2010 and $3.6 million for each of the six months ended June 30, 2011 and 2010. At June 30, 2011 and December 31, 2010, the balance of our Natural Gas Storage segment deferred lease liability was $15.4 million and $13.3 million, respectively. We estimate that this deferred lease liability will continue to increase through 2032, at which time our deferred lease liability is estimated to be approximately $64.7 million. Our

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deferred lease liability will then be reduced over the remaining 19 years of the lease, since the expected annual lease payments will exceed the amount of lease expense.

(4) Total minimum lease payment obligations for 2011 is the remaining portion from July 1 through December 31, 2011. All other years consist of the total minimum lease payment obligations for the full year.

Leases – Where We are Lessor

We have entered into capacity and other leases with remaining terms from 1 to 12 years that are accounted for as operating leases. All of the agreements provide for negotiated extensions. Future minimum lease payments to be received under such operating leasing arrangements as of December 31, 2011 are as follows, with the amount for 2011 consisting of the remainder of 2011 (July 1 through December 31) and all other years consisting of the total amount for the full year (in thousands):

	Years Ending December 31,
2011 (remainder)	$	59,695
2012		80,212
2013		43,624
2014		11,526
2015		11,152
Thereafter		50,891
Total	$	257,100

4. INVENTORIES

Our inventory amounts were as follows at the dates indicated (in thousands):

	June 30, 2011		December 31, 2010
Refined petroleum products (1)	$	331,529	$	340,659
Materials and supplies		14,183		10,946
Total inventories	$	345,712	$	351,605

(1) Ending inventory was 111.0 million and 134.9 million gallons of refined petroleum products at June 30, 2011 and December 31, 2010, respectively.

At both June 30, 2011 and December 31, 2010, approximately 94% of our refined petroleum products inventory was hedged. Hedged inventory is valued at current market prices with the change in value of the inventory reflected in our condensed consolidated statements of operations. Inventory not accounted for as a fair value hedge is accounted for at weighted average cost.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

5. PREPAID AND OTHER CURRENT ASSETS

Prepaid and other current assets consist of the following at the dates indicated (in thousands):

	June 30, 2011		December 31, 2010
Prepaid insurance	$	14,528	$	8,865
Insurance receivables		8,736		8,886
Ammonia receivable		1,510		1,295
Margin deposits		13,499		18,833
Prepaid services		17,592		24,359
Unbilled revenue		6,842		3,263
Tax receivable		3,640		120
Prepaid taxes		7,752		5,417
Customer deposits		1,913		2,657
Other		12,458		11,994
Total prepaid and other current assets	$	88,470	$	85,689

6. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consist of the following at the dates indicated (in thousands):

	June 30, 2011			December 31, 2010
Land	$	226,211		$	64,905
Rights-of-way		108,533			97,529
Pad gas		29,346			29,346
Buildings and leasehold improvements		122,392			109,585
Jetties and subsea pipelines		158,281			—
Gas storage facility		195,087			196,077
Pipeline and terminals		2,718,128			1,982,049
Vehicles, equipment and office furnishings		215,728			72,901
Construction in progress		255,233			66,642
Total property, plant and equipment		4,028,939			2,619,034
Less: Accumulated depreciation		(363,651	)		(313,150	)
Total property, plant and equipment, net	$	3,665,288		$	2,305,884

Depreciation expense was $26.1 million and $13.4 million for the three months ended June 30, 2011 and 2010, respectively. For the six months ended June 30, 2011 and 2010, depreciation expense was $49.3 million and $26.7 million, respectively.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

7. EQUITY INVESTMENTS

We own interests in related businesses that are accounted for using the equity method of accounting. The following table presents our equity investments, all included within the Pipelines & Terminals segment, at the dates indicated (in thousands):

	Ownership			June 30, 2011		December 31, 2010
Muskegon Pipeline LLC		40.0	%	$	14,129	$	14,552
Transport4, LLC		25.0	%		441		341
West Shore Pipe Line Company		34.6	%		44,933		43,563
West Texas LPG Pipeline Limited Partnership (1)		—			—		48,591
Total equity investments				$	59,503	$	107,047

(1) In May 2011, we sold our 20% interest in this investment. See Note 2 for further information.

The following table presents earnings from equity investments for the periods indicated (in thousands):

	Three Months Ended June 30,					Six Months Ended June 30,
	2011			2010		2011		2010
Muskegon Pipeline LLC	$	(85	)	$	227	$	98	$	571
Transport4, LLC		42			30		100		69
West Shore Pipe Line Company		1,338			1,294		2,886		2,501
West Texas LPG Pipeline Limited Partnership (1)		739			1,213		2,297		2,275
Total earnings from equity investments	$	2,034		$	2,764	$	5,381	$	5,416

(1) In May 2011, we sold our 20% interest in WT LPG. Amounts for WT LPG are included through the date of the sale of our interest.

Combined income statement data for the periods indicated for our equity investments are summarized below (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Revenues	$	28,201		$	35,754		$	61,504		$	67,299
Costs and expenses		(17,958	)		(20,343	)		(34,966	)		(36,244	)
Non-operating expense		(3,267	)		(3,461	)		(6,820	)		(7,038	)
Net income (1)	$	6,976		$	11,950		$	19,718		$	24,017

(1) In May 2011, we sold our 20% interest in WT LPG. Amounts for WT LPG are included through the date of the sale of our interest.

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

8. GOODWILL AND INTANGIBLE ASSETS

Goodwill

Goodwill represents the excess of the purchase price of an acquired business over the amounts assigned to assets acquired and liabilities assumed in the transaction. Goodwill is not amortized; it is subject to annual impairment testing. The following table summarizes our goodwill amounts by segment at the dates indicated (in thousands):

	June 30, 2011		December 31, 2010
Pipelines & Terminals:
Purchase of general partner interests in 2004	$	210,066	$	210,066
Acquisition of six terminals in June 2000		11,355		11,355
Acquisition of Albany Terminal in 2008		26,829		26,829
Subtotal		248,250		248,250
International Operations:
Acquisition of BORCO in 2011		497,454		—
Natural Gas Storage:
Acquisition of Lodi Gas in 2008		169,560		169,560
Energy Services:
Acquisition of Farm & Home in 2008		1,132		1,132
Development & Logistics:
Purchase of general partner interests in 2004		13,182		13,182
Total goodwill	$	929,578	$	432,124

Intangible Assets

Intangible assets include customer relationships and contracts. These intangible assets have definite lives and are being amortized on a straight-line basis over their estimated useful lives ranging from 5 to 25 years. Our amortizable customer contracts are contracts that were acquired in connection with the acquisition of BDL in March 1999, the acquisition of the Taylor, Michigan terminal in December 2005, the acquisition of certain pipeline and terminal assets in November 2009, the acquisition of the Yabucoa, Puerto Rico terminal in 2010 and the acquisition of BORCO in 2011 (see Note 2 for further discussion). The customer contracts are being amortized over their contractual life, 5 years in the case of the acquisition of certain pipeline and terminal assets in November 2009 and 5 years in the case of the terminal acquisition in 2010.

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The customer relationships resulted from the acquisition of Farm & Home Oil Company LLC (“Farm & Home”) in 2008 and BORCO in 2011. We determined, through an analysis of historical customer attrition rates at Farm & Home, that an appropriate recovery period for customer relationships is approximately 12 years. For BORCO, due to the high customer demand at the facility, the level of customer service being provided, the expansion capabilities of the facility, the potential of customer recontracting rates and the location of the facility in relation to international shipping routes, we anticipate the customer relationships to extend well beyond the existing contract terms with a recovery period of approximately 25 years. Intangible assets consist of the following at the dates indicated (in thousands):

	June 30, 2011			December 31, 2010
Customer relationships	$	247,663		$	41,663
Accumulated amortization		(14,142	)		(8,600	)
Net carrying amount		233,521			33,063
Customer contracts		16,380			16,380
Accumulated amortization		(6,118	)		(5,376	)
Net carrying amount		10,262			11,004
Total intangible assets	$	243,783		$	44,067

For the three months ended June 30, 2011 and 2010, amortization expense related to intangible assets was $3.5 million and $1.1 million, respectively. For the six months ended June 30, 2011 and 2010, amortization expense related to intangible assets was $6.3 million and $2.2 million, respectively. Amortization expense related to intangible assets is expected to be approximately $6.7 million for the remainder of 2011 (July 1 through December 31), $13.4 million for 2012, $13.4 million for 2013, $13.2 million for 2014 and $12.2 million for 2015.

9. OTHER NON-CURRENT ASSETS

Other non-current assets consist of the following at the dates indicated (in thousands):

	June 30, 2011		December 31, 2010
Prepaid services	$	2,064	$	5,836
Unbilled revenue		—		2,163
Derivative assets		—		3,892
Debt issuance costs		14,285		11,184
Insurance receivables		7,900		8,826
Indemnification asset (see Note 2)		17,720		17,720
Other		9,470		8,842
Total other non-current assets	$	51,439	$	58,463

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

10. ACCRUED AND OTHER CURRENT LIABILITIES

Accrued and other current liabilities consist of the following at the dates indicated (in thousands):

	June 30, 2011		December 31, 2010
Taxes - other than income	$	24,026	$	20,698
Accrued employee benefit liability		3,817		3,817
Environmental liabilities		15,586		10,471
Interest payable		45,429		30,700
Payable for ammonia purchase		2,701		2,354
Unearned revenue		18,733		18,776
Compensation and vacation		16,125		13,134
Accrued capital expenditures		20,197		2,032
Deferred consideration		1,000		2,010
Customer deposits		8,555		5,389
Unfavorable storage contracts (1)		9,583		—
Other		36,910		35,499
Total accrued and other current liabilities	$	202,662	$	144,880

(1) See Note 12 for a discussion of the unfavorable storage contracts acquired in connection with the BORCO acquisition.

11. DEBT OBLIGATIONS

Long-term debt consists of the following at the dates indicated (in thousands):

	June 30, 2011			December 31, 2010
4.625% Notes due July 15, 2013 (1)	$	300,000		$	300,000
5.300% Notes due October 15, 2014 (1)		275,000			275,000
5.125% Notes due July 1, 2017 (1)		125,000			125,000
6.050% Notes due January 15, 2018 (1)		300,000			300,000
5.500% Notes due August 15, 2019 (1)		275,000			275,000
4.875% Notes due February 1, 2021 (1)		650,000			—
6.750% Notes due August 15, 2033 (1)		150,000			150,000
Credit Facility		120,000			98,000
BES Credit Agreement		267,200			284,300
Services Company 3.60% ESOP Notes due March 28, 2011		—			1,531
Retirement premium		—			(6	)
Total debt		2,462,200			1,808,825
Other, including unamortized discounts and fair value hedges		(5,762	)		(3,607	)
Subtotal debt		2,456,438			1,805,218
Less: Current portion of long-term debt		(267,200	)		(285,825	)
Total long-term debt	$	2,189,238		$	1,519,393

(1) We make semi-annual interest payments on these notes based on the rates noted above with the principal balances outstanding to be paid on or before the due dates as shown above.

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The fair values of our aggregate debt and credit facilities were estimated to be $2,586.2 million and $1,897.5 million at June 30, 2011 and December 31, 2010, respectively. The fair values of the fixed-rate debt were estimated by observing market trading prices and by comparing the historic market prices of our publicly-issued debt with the market prices of other MLPs’ publicly-issued debt with similar credit ratings and terms. The fair values of the variable-rate debt are their carrying amounts, as the carrying amount reasonably approximates fair value due to the variability of the interest rates.

Notes Offering

On January 13, 2011, we sold the 4.875% Notes in an underwritten public offering. The notes were issued at 99.62% of their principal amount. Total proceeds from this offering, after underwriters’ fees, expenses and debt issuance costs of $4.9 million, were approximately $642.6 million, and were used to fund a portion of the purchase price for our acquisition of BORCO (see Note 2). In connection with this offering, we settled a treasury lock agreement, which resulted in the receipt of a settlement of $0.5 million, which is being amortized as a reduction to interest expense over the ten-year term of the 4.875% Notes (see Note 14).

Bridge Loans

In December 2010, in connection with the proposed BORCO acquisition, we obtained a commitment from commercial banks for senior unsecured bridge loans in an aggregate amount up to $595 million (or up to $775 million in the event we purchased both First Reserve’s 80% interest and Vopak’s 20% interest in FRBCH) (the “Bridge Loans”). The commitment was to expire upon the earliest to occur of the termination date as defined in the BORCO sale and purchase agreement, the consummation of the BORCO acquisition, the termination of the BORCO sale and purchase agreement or 120 days after December 18, 2010. We paid $2.0 million of fees in December 2010 associated with these Bridge Loans. In January 2011, we terminated the Bridge Loans upon issuance of the 4.875% Notes.

Services Company ESOP Notes

At December 31, 2010, Services Company had total debt outstanding of $1.5 million consisting of 3.60% Senior Secured Notes due March 28, 2011 payable by the ESOP to a third-party lender, which were repaid on March 28, 2011.

Credit Facility

We have a borrowing capacity of $580.0 million under the Credit Facility with SunTrust Bank, as administrative agent, which may be expanded up to $780.0 million subject to certain conditions and upon the further approval of the lenders. The Credit Facility’s maturity date is August 24, 2012, which we may extend for up to two additional one-year periods. Borrowings under the Credit Facility bear interest under one of two rate options, selected by us, equal to either (i) the greater of (a) the federal funds rate plus 0.5% and (b) SunTrust Bank’s prime rate plus an applicable margin, or (ii) the London Interbank Offered Rate (“LIBOR”) plus an applicable margin. The applicable margin is determined based on the current utilization level of the Credit Facility and ratings assigned by Standard & Poor’s Rating Services and Moody’s Investor Service for our senior unsecured non-credit enhanced long-term debt. At June 30, 2011 and December 31, 2010, $120.0 million and $98.0 million, respectively, were outstanding under the Credit Facility. The weighted average interest rate for borrowings under the Credit Facility was 0.5% at June 30, 2011.

The Credit Facility requires us to maintain a specified ratio (the “Funded Debt Ratio”) of no greater than 5.00 to 1.00 subject to a provision that allows for increases to 5.50 to 1.00 in connection with certain acquisitions. The Funded Debt Ratio is calculated by dividing consolidated debt by annualized EBITDA, which is defined in the Credit Facility as earnings before interest, taxes, depreciation, depletion and amortization, in each case excluding the income of certain of our majority-owned subsidiaries and equity investments (but including distributions from those majority-owned subsidiaries and equity investments). At June 30, 2011, our Funded Debt Ratio was approximately 4.2 to 1.00. As permitted by the Credit Facility, the $267.2 million of borrowings by Buckeye Energy Services LLC (“BES”) under its separate credit agreement (discussed below) was excluded from the calculation of the Funded Debt Ratio.

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

In addition, the Credit Facility contains other covenants including, but not limited to, covenants limiting our ability to incur additional indebtedness, to create or incur liens on our property, to dispose of property material to our operations, and to consolidate, merge or transfer assets. At June 30, 2011, we were not aware of any instances of noncompliance with the covenants under our Credit Facility.

At June 30, 2011 and December 31, 2010, we had committed $1.5 million and $1.4 million, respectively, in support of letters of credit. The obligations for letters of credit are not reflected as debt on our condensed consolidated balance sheets.

BES Credit Agreement

BES has a credit agreement (the “BES Credit Agreement”) that provides for borrowings of up to $500.0 million with a maturity date of June 25, 2013. The maximum amount available to be borrowed under the BES Credit Agreement is initially limited to $350.0 million. An accordion feature provides BES the ability to increase the commitments under the BES Credit Agreement to $500.0 million, subject to obtaining the requisite commitments and satisfying other customary conditions. In addition to the accordion, subject to BES’s satisfaction of certain financial covenants as set forth in the financial covenants table below, BES may, from time to time, elect to increase or decrease the maximum amount available for borrowing under the BES Credit Agreement in $5.0 million increments, but in no event below $150.0 million or above $500.0 million.

Under the BES Credit Agreement, borrowings accrue interest under one of three rate options, at BES’s election, equal to (i) the Administrative Agent’s Cost of Funds (as defined in the BES Credit Agreement) plus 2.25%, (ii) the Eurodollar Rate (as defined in the BES Credit Agreement) plus 2.25% or (iii) the Prime Rate (as defined in the BES Credit Agreement) plus 1.25%. The BES Credit Agreement also permits Daylight Overdraft Loans (as defined in the BES Credit Agreement), Swingline Loans (as defined in the BES Credit Agreement) and letters of credit. Such alternative extensions of credit are subject to certain conditions as specified in the BES Credit Agreement. The BES Credit Agreement is secured by liens on certain assets of BES, including its inventory, cash deposits (other than certain accounts), investments and hedging accounts, receivables and intangibles.

The balances outstanding under the BES Credit Agreement were approximately $267.2 million and $284.3 million at June 30, 2011 and December 31, 2010, respectively, both of which were classified as current liabilities in our condensed consolidated balance sheets. The BES Credit Agreement requires BES to meet certain financial covenants, which are defined in the BES Credit Agreement and summarized below (in millions, except for the leverage ratio):

Borrowings outstanding on BES Credit Agreement	Minimum Consolidated Tangible Net Worth		Minimum Consolidated Net Working Capital		Maximum Consolidated Leverage Ratio
$150	$	40	$	30	7.0 to 1.0
Above $150 up to $200	$	50	$	40	7.0 to 1.0
Above $200 up to $250	$	60	$	50	7.0 to 1.0
Above $250 up to $300	$	72	$	60	7.0 to 1.0
Above $300 up to $350	$	84	$	70	7.0 to 1.0
Above $350 up to $400	$	96	$	80	7.0 to 1.0
Above $400 up to $450	$	108	$	90	7.0 to 1.0
Above $450 up to $500	$	120	$	100	7.0 to 1.0

At June 30, 2011, BES’s Consolidated Tangible Net Worth and Consolidated Net Working Capital were $122.2 million and $82.7 million, respectively, and the Consolidated Leverage Ratio was 3.1 to 1.0. The weighted average interest rate for borrowings outstanding under the BES Credit Agreement was 2.5% at June 30, 2011.

24

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

In addition, the BES Credit Agreement contains other covenants, including, but not limited to, covenants limiting BES’s ability to incur additional indebtedness, to create or incur certain liens on its property, to consolidate, merge or transfer its assets, to make dividends or distributions, to dispose of its property, to make investments, to modify its risk management policy, or to engage in business activities materially different from those presently conducted. At June 30, 2011, we were not aware of any instances of noncompliance with the covenants under the BES Credit Agreement.

12. OTHER NON-CURRENT LIABILITIES

Other non-current liabilities consist of the following at the dates indicated (in thousands):

	June 30, 2011		December 31, 2010
Accrued employee benefit liabilities (see Note 15)	$	48,596	$	49,170
Accrued environmental liabilities		39,924		20,346
Deferred consideration		17,764		16,415
Deferred rent		15,454		13,393
Uncertain tax position liability (see Note 2)		17,720		17,720
Unfavorable storage contracts (1)		43,589		—
Derivative liabilities		5,918		—
Other		9,136		10,999
Total other non-current liabilities	$	198,101	$	128,043

(1) In determining fair value of assets and liabilities acquired in the BORCO acquisition (see Note 2), we allocated negative fair values to certain unfavorable storage contracts at the date of acquisition and recorded them as current and long-term liabilities in the condensed consolidated balance sheet. The unfavorable storage contracts are being recognized in revenues based on the estimated realization of the fair value established on the acquisition date over the contractual life. At June 30, 2011, amount is net of $4.3 million of recognized revenue. Revenue to be recognized related to these unfavorable storage contracts is expected to be approximately $4.8 million for the remainder of 2011 (July 1 through December 31) and $9.6 million for each of the years 2012 through 2015. See Note 10 for the current portion of unfavorable storage contracts.

25

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

13. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The following table presents the components of accumulated other comprehensive income (loss) (“AOCI”) on the condensed consolidated balance sheets at the dates indicated (in thousands):

	June 30, 2011			December 31, 2010
Adjustments to funded status of retirement income guarantee plan and retiree medical plan	$	(10,323	)	$	(10,323	)
Amortization of interest rate swap		(6,307	)		(6,789	)
Derivative instruments		(5,950	)		3,144
Gain on settlement of treasury lock, net of amortization		476			—
Accumulated amortization of retirement income guarantee plan and retiree medical plan		(7,531	)		(7,291	)
Total accumulated other comprehensive loss	$	(29,635	)	$	(21,259	)

14. DERIVATIVE INSTRUMENTS, HEDGING ACTIVITIES AND FAIR VALUE MEASUREMENTS

We are exposed to certain risks, including changes in interest rates and commodity prices, in the course of our normal business operations. We use derivative instruments to manage risks associated with certain identifiable and anticipated transactions. Derivatives are financial instruments whose fair value is determined by changes in a specified benchmark such as interest rates or commodity prices. Typical derivative instruments include futures, forward contracts, swaps and other instruments with similar characteristics. We have no trading derivative instruments.

Our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategies for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives used in a transaction are highly effective in offsetting changes in cash flows or the fair value of hedged items. A discussion of our derivative activities by risk category follows.

Interest Rate Derivatives

We utilize 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 our cost of capital associated with such borrowings. When entering into interest rate swap transactions, we become exposed to both credit risk and market risk. We are 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. We are subject to market risk with respect to changes in the underlying benchmark interest rate that impacts the fair value of the swaps. We manage our credit risk by only entering into swap transactions with major financial institutions with investment-grade credit ratings. We manage our 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.

Our 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 us to enter into certain short-term interest rate swap agreements to manage our interest rate and cash flow risks associated with the Credit Facility. In addition, in July 2009 and May 2010, Buckeye GP’s board of directors authorized us to enter into certain transactions, such as forward-starting interest rate swaps, to manage our interest rate and cash flow risks related to certain expected debt issuances associated with the maturity of existing debt obligations.

26

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

We expect 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. We have entered into six forward-starting interest rate swaps with a total aggregate notional amount of $300.0 million related to the anticipated issuance of debt on or before July 15, 2013 and six forward-starting interest rate swaps with a total aggregate notional amount of $275.0 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. During the three months ended June 30, 2011 and 2010, unrealized losses of $13.8 million and unrealized losses of $34.9 million, respectively, were recorded in accumulated other comprehensive income (loss) to reflect the change in the fair values of the forward-starting interest rate swaps. During the six months ended June 30, 2011 and 2010, unrealized losses of $9.3 million and unrealized losses of $36.2 million, respectively, were recorded in accumulated other comprehensive income (loss). We designated the swap agreements as cash flow hedges at inception and expect the changes in values to be highly correlated with the changes in value of the underlying borrowings.

On January 13, 2011, we issued the 4.875% Notes in an underwritten public offering. In December 2010, in connection with the proposed offering, we entered into a treasury lock agreement to fix the 10-year treasury rate at 3.3375% per annum on a notional amount of $650.0 million. In January 2011, we subsequently cash-settled the treasury lock agreement upon the issuance of the 4.875% Notes and received approximately $0.5 million, which is being recognized as a reduction to interest expense over the term of the 4.875% Notes.

Over the next twelve months, we expect to reclassify $0.9 million of net losses, consisting of loss attributable to forward-starting interest rate swaps terminated in 2008 associated with our 6.050% Notes, partially offset by a gain attributable to the settlement of the treasury lock agreement associated with the 4.875% Notes in January 2011, from accumulated other comprehensive loss to earnings as an increase to interest and debt expense.

Commodity Derivatives

Our Energy Services segment primarily uses exchange-traded refined petroleum product futures contracts to manage the risk of market price volatility on its refined petroleum product inventories and its physical commodity forward fixed-price purchase and sales contracts. The derivative contracts used to hedge refined petroleum product inventories are designated as fair value hedges. Accordingly, our method of measuring ineffectiveness compares the change in the fair value of New York Mercantile Exchange (“NYMEX”) futures contracts to the change in fair value of our hedged fuel inventory. Hedge accounting is discontinued when the hedged fuel inventory is sold or when the related derivative contracts expire. In addition, we periodically enter into offsetting exchange-traded futures contracts to economically close-out an existing futures contract based on a near-term expectation to sell a portion of our fuel inventory. These offsetting derivative contracts are not designated as hedging instruments and any resulting gains or losses are recognized in earnings during the period. The fair values of futures contracts for inventory designated as hedging instruments in the following tables have been presented net of these offsetting futures contracts.

Our Energy Services segment has not used hedge accounting with respect to its fixed-price contracts. Therefore, our fixed-price contracts and the related futures contracts used to offset the changes in fair value of the fixed-price sales contracts are all marked-to-market on the condensed consolidated balance sheets with gains and losses being recognized in earnings during the period.

In order to hedge the cost of natural gas used to operate our turbine engines at our Linden, New Jersey location, our Pipelines & Terminals segment bought natural gas futures contracts in March 2009 with terms that coincide with the remaining term of an ongoing natural gas supply contract (through August 2011). We designated the futures contracts as cash flow hedges at inception.

27

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes our commodity derivative instruments outstanding at June 30, 2011 (amounts in thousands of gallons, except as noted):

	Volume (1)				Accounting Treatment
Derivative Purpose	Current		Long-Term (2)
Derivatives NOT designated as hedging instruments:
Physical derivative contracts for refined products		2,885		—		Mark-to-market
Futures contracts for refined products		12,180		—		Mark-to-market
Derivatives designated as hedging instruments:
Futures contracts for refined products		104,202		—		Fair Value Hedge
Futures contracts for natural gas (BBtu) (3)		30		—		Cash Flow Hedge

(1) Volume represents absolute value of net notional volume position.

(2) The maximum term for derivatives included in the long-term column is June 2012.

(3) BBtu represents one billion British thermal units.

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table sets forth the fair value of each classification of derivative instruments at the dates indicated (in thousands):

	June 30, 2011
	Derivatives NOT Designated as Hedging Instruments			Derivatives Designated as Hedging Instruments			Derivative Carrying Value			Netting Balance Sheet Adjustment			Total
Physical derivative contracts for refined products	$	2,012		$	—		$	2,012		$	(1,368	)	$	644
Futures contracts for refined products		5,288			3,859			9,147			(9,042	)		105
Futures contracts for natural gas		4			—			4			(4	)		—
Total current derivative assets		7,304			3,859			11,163			(10,414	)		749
Interest rate derivatives		—			1,193			1,193			(1,193	)		—
Total non-current derivative assets		—			1,193			1,193			(1,193	)		—
Physical derivative contracts for refined products		(2,546	)		—			(2,546	)		1,368			(1,178	)
Futures contracts for refined products		(6,159	)		(4,173	)		(10,332	)		9,042			(1,290	)
Futures contracts for natural gas		(36	)		—			(36	)		4			(32	)
Total current derivative liabilities		(8,741	)		(4,173	)		(12,914	)		10,414			(2,500	)
Interest rate derivatives		—			(7,111	)		(7,111	)		1,193			(5,918	)
Total non-current derivative liabilities		—			(7,111	)		(7,111	)		1,193			(5,918	)
Net derivative assets/(liabilities)	$	(1,437	)	$	(6,232	)	$	(7,669	)	$	—		$	(7,669	)
	December 31, 2010
	Derivatives NOT Designated as Hedging Instruments			Derivatives Designated as Hedging Instruments			Derivative Carrying Value			Netting Balance Sheet Adjustment			Total
Physical derivative contracts for refined products	$	1,552		$	—		$	1,552		$	(30	)	$	1,522
Futures contracts for refined products		36,916			—			36,916			(36,804	)		112
Total current derivative assets		38,468			—			38,468			(36,834	)		1,634
Interest rate derivatives		—			5,351			5,351			(1,459	)		3,892
Total non-current derivative assets		—			5,351			5,351			(1,459	)		3,892
Physical derivative contracts for refined products		(3,930	)		—			(3,930	)		30			(3,900	)
Futures contracts for refined products		(21,368	)		(28,071	)		(49,439	)		36,804			(12,635	)
Futures contracts for natural gas		—			(206	)		(206	)		—			(206	)
Interest rate derivatives		—			(2,003	)		(2,003	)		1,459			(544	)
Total current derivative liabilities		(25,298	)		(30,280	)		(55,578	)		38,293			(17,285	)
Net derivative assets/(liabilities)	$	13,170		$	(24,929	)	$	(11,759	)	$	—		$	(11,759	)

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table sets forth the location of derivative instruments on our condensed consolidated balance sheets at the dates indicated (in thousands):

	June 30, 2011			December 31, 2010
Derivative assets	$	749		$	1,634
Other non-current assets		—			3,892
Derivative liabilities		(2,500	)		(17,285	)
Other non-current liabilities		(5,918	)		—
Total	$	(7,669	)	$	(11,759	)

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The gains and losses on our derivative instruments recognized in income were as follows for the periods indicated (in thousands):

		Gain (Loss) Recognized in Income on Derivatives
		Three Months Ended June  30,						Six Months Ended June  30,
	Location	2011			2010			2011			2010
Derivatives NOT designated as hedging instruments:
Physical derivative contracts for refined products	Product sales	$	2,204		$	6,268		$	(1,587	)	$	8,678
Physical derivative contracts for refined products	Cost of product sales and natural gas storage services		732			(2,972	)		1,767			(3,466	)
Futures contracts for refined products	Cost of product sales and natural gas storage services		3,330			20			1,181			266
Derivatives designated as fair value hedging instruments:
Futures contracts for refined products	Cost of product sales and natural gas storage services		8,069			18,123			(48,831	)		13,213
Physical Inventory - Hedge items	Cost of product sales and natural gas storage services		(10,136	)		(17,360	)		40,283			(23,795	)
Ineffectiveness and the time value component on fair value hedging instruments:
Fair value hedge ineffectiveness (excluding time value)	Cost of product sales and natural gas storage services	$	(4,253	)	$	5,769		$	(204	)	$	10,580
Time value excluded from hedge assessment	Cost of product sales and natural gas storage services		2,186			(5,006	)		(8,344	)		(21,162	)
Net impact on income		$	(2,067	)	$	763		$	(8,548	)	$	(10,582	)

Our hedged inventory portfolio extends to the fourth quarter of 2011. The majority of the unrealized gain of $0.1 million at June 30, 2011 for futures contracts designated as inventory hedging instruments and unrealized gains in the fair values of the underlying hedged refined petroleum product inventories will be realized by the fourth quarter of 2011 as the inventory is sold. At June 30, 2011, open refined petroleum product derivative contracts (represented by the fixed-price contracts and futures contracts for fixed-price sales contracts noted above) varied in duration, but did not extend beyond June 2012. In addition, at June 30, 2011, we had refined petroleum product inventories that we intend to use to satisfy a portion of the physical derivative contracts.

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The gains and losses reclassified from AOCI to income and the change in value recognized in other comprehensive income (“OCI”) on our derivatives were as follows for the periods indicated (in thousands):

		Gain (Loss) Reclassified from AOCI to Income
		Three Months Ended June  30,						Six Months Ended June  30,
	Location	2011			2010			2011			2010
Derivatives designated as cash flow hedging instruments:
Futures contracts for natural gas	Cost of product sales and natural gas storage services	$	(99	)	$	(96	)	$	(219	)	$	(168	)
Futures contracts for refined petroleum products	Cost of product sales and natural gas storage services		—			—			—			—
Interest rate contracts	Interest and debt expense		(229	)		(242	)		(462	)		(482	)
		Change in Value Recognized in OCI on Derivatives
		Three Months Ended June 30,						Six Months Ended June 30,
		2011			2010			2011			2010
Derivatives designated as cash flow hedging instruments:
Futures contracts for natural gas		$	(17	)	$	85		$	(46	)	$	(611	)
Interest rate contracts			(13,783	)		(34,853	)		(8,770	)		(36,157	)

Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Our fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. Recognized valuation techniques employ inputs such as product prices, operating costs, discount factors and business growth rates. These inputs may be readily observable, corroborated by market data or generally unobservable. In developing our estimates of fair value, we endeavor to utilize the best information available and apply market-based data to the extent possible. Accordingly, we utilize valuation techniques (such as the income or market approach) that maximize the use of observable inputs and minimize the use of unobservable inputs.

A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements based on the observability of inputs used to estimate such fair values. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). At each balance sheet reporting date, we categorize our financial assets and liabilities using this hierarchy. The characteristics of fair value amounts classified within each level of the hierarchy are described as follows:

• Level 1 inputs are based on quoted prices, which are available in active markets for identical assets or liabilities as of the reporting date. Active markets are defined as those in which transactions for identical assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

• Level 2 inputs are based on pricing inputs other than quoted prices in active markets and are either directly or indirectly observable as of the measurement date. Level 2 fair values include instruments that are valued using financial models or other appropriate valuation methodologies and include the following:

• Quoted prices in active markets for similar assets or liabilities.

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

• Quoted prices in markets that are not active for identical or similar assets or liabilities.

• Inputs other than quoted prices that are observable for the asset or liability.

• Inputs that are derived primarily from or corroborated by observable market data by correlation or other means.

• Level 3 inputs are based on unobservable inputs for the asset or liability. Unobservable inputs are used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. Unobservable inputs reflect the reporting entity’s own ideas about the assumptions that market participants would use in pricing an asset or liability (including assumptions about risk). Unobservable inputs are based on the best information available in the circumstances, which might include the reporting entity’s internally developed data. The reporting entity must not ignore information about market participant assumptions that is reasonably available without undue cost and effort. Level 3 inputs are typically used in connection with internally developed valuation methodologies where management makes its best estimate of an instrument’s fair value.

Recurring

The following table sets forth financial assets and liabilities, measured at fair value on a recurring basis, as of the measurement dates, June 30, 2011 and December 31, 2010, and the basis for that measurement, by level within the fair value hierarchy (in thousands):

	June 30, 2011						December 31, 2010
	Quoted Prices in  Active Markets			Significant Other Observable Inputs			Quoted Prices in Active Markets			Significant Other Observable Inputs
	(Level 1)			(Level 2)			(Level 1)			(Level 2)
Financial assets:
Physical derivative contracts for refined products	$	—		$	644		$	—		$	1,522
Futures contracts for refined products		105			—			112			—
Interest rate derivatives		—			—			—			3,892
Financial liabilities:
Physical derivative contracts for refined products		—			(1,178	)		—			(3,900	)
Futures contracts for refined products		(1,290	)		—			(12,635	)		—
Futures contracts for natural gas		(32	)		—			(206	)		—
Interest rate derivatives		—			(5,918	)		—			(544	)
Fair value	$	(1,217	)	$	(6,452	)	$	(12,729	)	$	970

The values of the Level 1 derivative assets and liabilities were based on quoted market prices obtained from the NYMEX.

The values of the Level 2 interest rate derivatives were determined using expected cash flow models, which incorporated market inputs including the implied forward LIBOR yield curve for the same period as the future interest swap settlements.

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The values of the Level 2 fixed-price contracts assets and liabilities were calculated using market approaches based on observable market data inputs, including published commodity pricing data, which is verified against other available market data, and market interest rate and volatility data. Level 2 fixed-price contracts assets are net of credit value adjustments (“CVA”) determined using an expected cash flow model, which incorporates assumptions about the credit risk of the fixed-price contracts based on the historical and expected payment history of each customer, the amount of product contracted for under the agreement and the customer’s historical and expected purchase performance under each contract. The Energy Services segment determined CVA is appropriate because few of the Energy Services segment’s customers entering into these fixed-price contracts are large organizations with nationally-recognized credit ratings. The Level 2 fixed-price contracts assets of $0.6 million and $1.5 million as of June 30, 2011 and December 31, 2010, respectively, are net of CVA of ($0.1) million and ($0.2) million, respectively. As of June 30, 2011, the Energy Services segment did not hold any net liability derivative position containing credit contingent features.

Non-Recurring

Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments in certain circumstances, such as when there is evidence of possible impairment. There were no fair value adjustments for such assets or liabilities reflected in our condensed consolidated financial statements for the three and six months ended June 30, 2011 and 2010.

15. PENSIONS AND OTHER POSTRETIREMENT BENEFITS

Services Company, which employs the majority of our workforce, sponsors a retirement income guarantee plan (“RIGP”), which is a defined benefit plan that generally guarantees employees hired before January 1, 1986 a retirement benefit based on years of service and the employee’s highest compensation for any consecutive 5-year period during the last 10 years of service or other compensation measures as defined under the respective plan provisions. The retirement benefit is subject to reduction at varying percentages for certain offsetting amounts, including benefits payable under a retirement and savings plan discussed further below. Services Company funds the plan through contributions to pension trust assets, generally subject to minimum funding requirements as provided by applicable law.

Services Company also sponsors an unfunded post-retirement benefit plan (the “Retiree Medical Plan”), which provides health care and life insurance benefits to certain of its retirees. To be eligible for these benefits, an employee must have been hired prior to January 1, 1991 and meet certain service requirements.

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The components of the net periodic benefit cost for the RIGP and Retiree Medical Plan were as follows for the three months ended June 30, 2011 and 2010 (in thousands):

	RIGP						Retiree Medical Plan
	Three Months Ended June  30,						Three Months Ended June  30,
	2011			2010			2011			2010
Service cost	$	73		$	65		$	75		$	117
Interest cost		199			227			481			786
Expected return on plan assets		(82	)		(86	)		—			—
Amortization of prior service benefit		—			(11	)		(741	)		(1,175	)
Amortization of unrecognized losses		299			242			312			354
Settlement charge		203			—			—			—
Net periodic benefit costs	$	692		$	437		$	127		$	82

The components of the net periodic benefit cost for the RIGP and Retiree Medical Plan were as follows for the six months ended June 30, 2011 and 2010 (in thousands):

	RIGP						Retiree Medical Plan
	Six Months Ended June  30,						Six Months Ended June  30,
	2011			2010			2011			2010
Service cost	$	136		$	133		$	161		$	147
Interest cost		399			459			938			991
Expected return on plan assets		(188	)		(174	)		—			—
Amortization of prior service benefit		—			(23	)		(1,482	)		(1,482	)
Amortization of unrecognized losses		636			490			606			447
Settlement charge		203			—			—			—
Net periodic benefit costs	$	1,186		$	885		$	223		$	103

During the six months ended June 30, 2011, we contributed $2.0 million to the RIGP.

16. UNIT-BASED COMPENSATION PLANS

BGH GP has an equity compensation plan (“BGH GP Equity Compensation Plan”) for certain members of our senior management. Compensation expense recorded with respect to the BGH GP Equity Compensation Plan was $0 and $0.3 million for the three months ended June 30, 2011 and 2010, respectively. For the six months ended June 30, 2011 and 2010, compensation expense recorded with respect to the BGH GP Equity Compensation Plan was $0 and $0.6 million, respectively.

We award unit-based compensation to employees and directors primarily under the Buckeye Partners, L.P. 2009 Long-Term Incentive Plan (the “LTIP”). We formerly awarded options to acquire LP Units to employees pursuant to the Buckeye Partners, L.P. Unit Option and Distribution Equivalent Plan (the “Option Plan”). We recognized compensation expense related to the LTIP and the Option Plan of $2.8 million and $1.3 million for the three months ended June 30, 2011 and 2010, respectively. For the six months ended June 30, 2011 and 2010, we recognized compensation expense related to the LTIP and the Option Plan of $4.9 million and $2.5 million, respectively. These compensation plans are discussed below.

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

BGH GP’s Override Units

Effective on June 25, 2007, BGH GP instituted the BGH GP Equity Compensation Plan. The BGH GP Equity Compensation Plan included both time-based and performance-based participation in the equity of BGH GP (but not ours) referred to as override units. These override units consisted of three equal tranches of units consisting of Value A, Value B and Operating Units. We are required to record, as compensation expense and a corresponding contribution to unitholders’ equity, the fair value of the compensation. We are not the sponsor of this plan and have no obligations with respect to it. Compensation expense related this plan was $0 and $0.3 million for the three months ended June 30, 2011 and 2010, respectively. For the six months ended June 30, 2011 and 2010, compensation expense related to this plan was $0 and $0.6 million, respectively.

On December 31, 2010, the override unit plan was modified. All outstanding Value A and Operating Units were exchanged for LP Units owned by BGH GP. The terms of the Value B Units remained unchanged. The Value B Units will participate in distributions by BGH GP based on the occurrence of an exit event and an investment return of 3.5 times the original investment and an internal rate of return of at least 10% or on a pro-rata basis on an investment return ranging from 2.0 to 3.5 times the original investment and an internal rate of return of at least 10%.

On January 27, 2011, BGH GP established and granted new override units in BGH GP to a member of senior management, which consisted of Value N-1 and Value N-2 Units. The Value N-1 Units will participate in distributions by BGH GP based on the occurrence of an exit event and an investment return of 2.0 times the original investment up to aggregate distributions of $3.0 million. The Value N-2 Units will participate in distributions by BGH GP based on the occurrence of an exit event and an investment return of 2.5 times the original investment or on a pro-rata basis on an investment return ranging from 2.0 to 2.5 times the original investment up to aggregate distributions of $5.0 million.

The exit event with respect to the Value B, Value N-1 and Value N-2 Units is generally defined as the sale by ArcLight, Kelso and their affiliates of their interests in BGH GP, the sale of substantially all the assets of BGH GP and its subsidiaries, or any other “extraordinary” transaction that the Board of Directors of BGH GP determines is an exit event.

The investment return is calculated generally as the sum of all the distributions that ArcLight and Kelso have received from BGH GP prior to and through the exit event, divided by the total amount of capital contributions to BGH GP that ArcLight and Kelso have made prior to the exit event.

The cumulative grant date fair values of the Value B, Value N-1 and Value N-2 Units that remained unvested as of June 30, 2011 are $2.2 million, $0.9 million and $1.1 million, respectively. The vesting of the override units is contingent on a performance condition, namely the completion of the exit event, and a market condition, primarily relating to the receipt of an investment return at a specified multiple and internal rate of return, where applicable. Accordingly, no compensation expense for these override units will be recorded until, and if, an exit event and other requirements occur.

At grant date, the override units were valued using the Monte Carlo simulation method that incorporated the market-based vesting condition into the grant date fair value of the unit awards. The following assumptions were used for grants of the Value N-1 and N-2 Units during the period:

	Three Months Ended March 31, 2011
Equity value in BGH GP (in millions)	$	410.7
Expected life in years		1
Risk-free interest rate		0.25	%
Volatility		25	%

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

LTIP

The LTIP provides for the issuance of up to 1,500,000 LP Units, subject to certain adjustments. After giving effect to the issuance or forfeiture of phantom unit and performance unit awards through June 30, 2011, awards representing a total of 874,528 additional LP Units could be issued under the LTIP.

Under the terms of the Buckeye Partners, L.P. Unit Deferral and Incentive Plan (“Deferral Plan”), eligible employees were allowed to defer up to 50% of their 2011 and 2010 compensation award under our Annual Incentive Compensation Plan or other discretionary bonus program 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. Approximately $1.6 million of 2010 compensation awards had been deferred at December 31, 2010, for which 50,660 phantom units (including matching units) were granted during the six months ended June 30, 2011. These grants are included as granted in the LTIP activity table below.

Awards under the LTIP

During the six months ended June 30, 2011, the Compensation Committee granted 110,165 phantom units to employees (including the 50,660 phantom units granted pursuant to the Deferral Plan discussed above), 14,000 phantom units to independent directors of Buckeye GP, and 120,740 performance units to employees. The amount paid with respect to phantom unit distribution equivalents under the LTIP was $0.5 million and $0.3 million for the six months ended June 30, 2011 and 2010, respectively.

The following table sets forth the LTIP activity for the periods indicated (dollars in thousands):

	Number of LP Units			Weighted Average Grant Date Fair Value per LP Unit  (1)		Total Value
Unvested at January 1, 2011		364,913		$	51.11	$	18,650
Granted		244,905			64.91		15,896
Vested		(15,246	)		55.35		(844	)
Forfeited		(3,507	)		57.46		(202	)
Unvested at June 30, 2011		591,065		$	56.69	$	33,500

(1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. The weighted-average grant date fair value per LP Unit for forfeited and vested awards is determined before an allowance for forfeitures.

At June 30, 2011, approximately $19.2 million of compensation expense related to the LTIP is expected to be recognized over a weighted average period of approximately 1.7 years.

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unit Option and Distribution Equivalent Plan

The following is a summary of the changes in the LP Unit options outstanding (all of which are vested or are expected to vest) under the Option Plan for the periods indicated (dollars in thousands):

	Number of LP Units			Weighted- Average Strike Price ($/LP Unit)		Weighted- Average Remaining Contractual Term (in years)		Aggregate Intrinsic Value (1)
Outstanding at January 1, 2011		241,800		$	47.04
Exercised		(17,500	)		48.78
Outstanding at June 30, 2011		224,300			46.84		5.2	$	4,215
Exercisable at June 30, 2011		220,800		$	47.20		5.2	$	4,043

(1) Aggregate intrinsic value reflects fully vested LP Unit options at the date indicated. Intrinsic value is determined by calculating the difference between our closing LP Unit price on the last trading day in June 2011 and the exercise price, multiplied by the number of exercisable, in-the-money options.

The total intrinsic value of options exercised was $0.3 million and $1.0 million during the six months ended June 30, 2011 and 2010, respectively. At June 30, 2011, total unrecognized compensation cost related to unvested LP Unit options was minimal. We expect to recognize this remaining cost over a weighted average period of 0.4 years. At June 30, 2011, 333,000 LP Units were available for grant in connection with the Option Plan. However, with the adoption of the LTIP, we do not expect to make any future grants pursuant to the Option Plan. The fair value of options vested was $0.2 million and $0.4 million during the six months ended June 30, 2011 and 2010, respectively.

38

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

17. RELATED PARTY TRANSACTIONS

We are managed by Buckeye GP, our general partner. Services Company is considered a related party with respect to us. As discussed in Note 1, our consolidated financial statements include the financial results of Services Company on a consolidated basis, and all intercompany transactions have been eliminated.

Services Company, which is beneficially owned by the ESOP, owned 1.4 million of our LP Units (approximately 1.6% of our LP Units outstanding) as of June 30, 2011. Distributions received by Services Company from us on such LP Units are used to fund obligations of the ESOP. Distributions paid to Services Company totaled $2.9 million and $3.0 million for the six months ended June 30, 2011 and 2010, respectively. Total distributions paid to Services Company decrease over time because Services Company sells LP Units to fund benefits payable to ESOP participants who exit the ESOP.

Prior to the Merger, Buckeye GP received incentive distributions from us pursuant to our partnership agreement and incentive compensation agreement. Incentive distributions were based on the level of quarterly cash distributions paid per LP Unit and the total number of LP Units outstanding. Incentive distribution payments totaled $24.9 million during the six months ended June 30, 2010.

18. PARTNERS’ CAPITAL AND DISTRIBUTIONS

Our LP Units represent limited partner interests, which give the holders thereof the right to participate in distributions and to exercise the other rights and privileges available to them under our partnership agreement. Our partnership agreement provides that, without prior approval of our limited partners holding an aggregate of at least two-thirds of the outstanding LP Units, we cannot issue any LP Units of a class or series having preferences or other special or senior rights over the LP Units. In accordance with our partnership agreement, capital accounts are maintained for our general partner and limited partners. In conjunction with the Merger, our partnership agreement was amended.

Class B Units represent a separate class of our limited partnership interests. The Class B Units share equally with the LP Units (i) with respect to the payment of distributions and (ii) in the event of our liquidation. We have the option to pay distributions on the Class B Units with cash or by issuing additional Class B Units, with the number of Class B Units issued based upon the volume-weighted average price of the LP Units for the 10 trading days immediately preceding the date the distributions are declared, less a discount of 15%. The Class B Units have the same voting rights as if they were outstanding LP Units and are entitled to vote as a separate class on any matters that materially adversely affect the rights or preferences of the Class B Units in relation to other classes of partnership interests or as required by law. The Class B Units will convert into LP Units on a one-for-one basis on the earlier of (a) the date on which at least 4 million barrels of incremental storage capacity are placed in service by BORCO or (b) the third anniversary of the closing of the BORCO acquisition.

In April 2011, we issued 5,520,000 LP Units, which included 720,000 LP Units issued as part of the overallotment option, in an underwritten public offering at a public offering price of $59.41 per LP Unit. Total proceeds from the offering, including the overallotment option and after the underwriters’ discount of $1.99 per LP Unit and offering expenses, were approximately $316.6 million, and were used to reduce amounts outstanding under our Credit Facility.

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Summary of Changes in Outstanding Units

The following is a reconciliation of units outstanding for the periods indicated:

	Limited Partners		Class B Units		Total
Units outstanding at December 31, 2010		71,436,099		—		71,436,099
LP Units issued pursuant to the Option Plan		9,098		—		9,098
LP Units issued pursuant to the LTIP		15,053		—		15,053
Issuance of units to First Reserve and Vopak as consideration for BORCO acquisition		3,104,305		5,478,611		8,582,916
Issuance of units to institutional investors (1)		5,794,725		1,314,870		7,109,595
Issuance of units in underwritten public offering		5,520,000		—		5,520,000
Issuance of Class B Units in lieu of quarterly cash distributions		—		249,290		249,290
Units outstanding at June 30, 2011		85,879,280		7,042,771		92,922,051

(1) Proceeds were used to fund a portion of the BORCO acquisition.

Distributions

We generally make quarterly cash distributions to unitholders of substantially all of our available cash, generally defined in our partnership agreement as consolidated cash receipts less consolidated cash expenditures and such retentions for working capital, anticipated cash expenditures and contingencies as our general partner deems appropriate. Cash distributions on our LP Units totaled $165.8 million and $122.9 million during the six months ended June 30, 2011 and 2010, respectively. We also paid distributions in kind to our Class B unitholders by issuing 249,290 Class B Units during the six months ended June 30, 2011.

On August 5, 2011, we announced a quarterly distribution of $1.0125 per LP Unit that will be paid on August 31, 2011, to LP unitholders of record on August 15, 2011. Total cash distributed to LP unitholders on August 31, 2011 will total approximately $87.2 million. We also expect to issue approximately 130,000 Class B Units in lieu of cash distributions on August 31, 2011, to Class B unitholders of record on August 15, 2011.

19. EARNINGS PER UNIT

Basic and diluted earnings per unit (including earnings per unit for LP Units and Class B Units) is calculated by dividing net income, after deducting the amount allocated to noncontrolling interests, by the weighted-average number of LP Units and Class B Units outstanding during the period.

Pursuant to the Merger Agreement, BGH’s unitholders received a total of approximately 20.0 million of Buckeye’s LP Units in the aggregate in exchange for all outstanding BGH common units and management units. As a result, the number of Buckeye’s LP Units outstanding increased from 51.6 million to 71.4 million on the date of the Merger. However, for historical reporting purposes, the impact of this change was accounted for as a reverse split of BGH’s units of 0.705 to 1.0, together with the addition of Buckeye’s existing LP Units. Therefore, since BGH was the surviving accounting entity, the weighted average number of units outstanding used for basic and diluted earnings per unit calculations are BGH’s historical weighted average common units outstanding adjusted for the reverse unit split and the addition of Buckeye’s existing LP Units. Amounts reflecting historical BGH unit and per unit amounts included in this report have been restated for the reverse unit split.

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table is a reconciliation of the weighted average number of units used in the basic and diluted earnings per unit calculations for the periods indicated (in thousands, except per unit amounts):

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Net income attributable to Buckeye Partners, L.P.	$	92,021	$	11,507	$	158,514	$	22,777
Basic:
Weighted average units outstanding		91,743		19,581		87,728		19,581
Weighted average management units outstanding		—		371		—		371
Units for basic		91,743		19,952		87,728		19,952
Earnings per unit - basic	$	1.00	$	0.58	$	1.81	$	1.14
Diluted:
Units used for basic calculation		91,743		19,952		87,728		19,952
Dilutive effect of LP Unit options and LITP awards granted		345		—		314		—
Units for diluted		92,088		19,952		88,042		19,952
Earnings per unit - diluted	$	1.00	$	0.58	$	1.80	$	1.14

20. BUSINESS SEGMENTS

We operate and report in five business segments: Pipelines & Terminals; International Operations; Natural Gas Storage; Energy Services; and Development & Logistics. Effective January 1, 2011, we realigned our five business segments. We combined the Pipeline Operations and Terminalling & Storage segments into one segment, the Pipelines & Terminals segment, and moved our terminal in Yabucoa, Puerto Rico, previously included as part of the Terminalling & Storage segment, to a new International Operations segment with the BORCO facility. We have adjusted our period-to-period comparisons to conform to the current presentation.

Pipelines & Terminals

The Pipelines & Terminals segment receives refined petroleum products from refineries, connecting pipelines, and bulk and marine terminals and transports those products to other locations for a fee and provides bulk storage and terminal throughput services in the continental United States. This segment owns and operates approximately 6,100 miles of pipeline systems in 17 states. The segment has 95 liquid petroleum products terminals in 21 states with aggregate storage capacity of approximately 37.1 million barrels.

International Operations

The International Operations segment provides marine bulk storage and marine terminal throughput services. The segment has two liquid petroleum product terminals, one in Puerto Rico and one on The Grand Bahama Island in the Bahamas, with an aggregate storage capacity of 26.2 million barrels.

Natural Gas Storage

The Natural Gas Storage segment provides natural gas storage services at a natural gas storage facility in northern California. The facility has approximately 29 Bcf of working natural gas storage capacity and is connected to Pacific Gas and Electric’s intrastate gas pipelines that service natural gas demand in the San Francisco and Sacramento, California areas. The Natural Gas Storage segment does not trade or market natural gas.

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Energy Services

The Energy Services segment is a wholesale distributor of refined petroleum products in areas also served by our pipelines and terminals assets. This segment recognizes revenues when products are delivered. The segment’s products include gasoline, propane and petroleum distillates such as heating oil, diesel fuel and kerosene. The segment also has five terminals with aggregate storage capacity of approximately 1.0 million barrels. The segment’s customers consist principally of product wholesalers as well as major commercial users of these refined petroleum products.

Development & Logistics

The Development & Logistics segment provides contract operations, engineering and construction management services as well as asset development services to energy companies throughout the U.S. and internationally. This segment operates approximately 2,700 miles of third-party pipeline and terminals, which are owned principally by major oil and gas, petrochemical and chemical companies, and also acts as a business development arm for many of these same customers. The Development & Logistics segment also includes our ownership and operation of an ammonia pipeline and our majority ownership of Sabina Pipelines, each located in Texas.

Adjusted EBITDA

Adjusted EBITDA is the primary measure used by senior management, including our Chief Executive Officer, to evaluate our operating results and to allocate our resources. We define EBITDA, a measure not defined under GAAP, as net income attributable to our unitholders before interest and debt expense, income taxes and depreciation and amortization. EBITDA should not be considered an alternative to net income, operating income, cash flow from operations or any other measure of financial performance or liquidity presented in accordance with GAAP. The EBITDA measure eliminates the significant level of non-cash depreciation and amortization expense that results from the capital-intensive nature of our businesses and from intangible assets recognized in business combinations. In addition, EBITDA is unaffected by our capital structure due to the elimination of interest and debt expense and income taxes. We define Adjusted EBITDA, which is also a non-GAAP measure, as EBITDA plus: (i) non-cash deferred lease expense, which is the difference between the estimated annual land lease expense for our natural gas storage facility in the Natural Gas Storage segment to be recorded under GAAP and the actual cash to be paid for such annual land lease; (ii) non-cash unit-based compensation expense; and (iii) income attributable to noncontrolling interests related to Buckeye for periods prior to the Merger in order to provide comparability between periods before and after the Merger; less (i) amortization of unfavorable storage contracts acquired in connection with the BORCO acquisition; and (ii) gain on the sale of our equity investment in WT LPG.

The EBITDA and Adjusted EBITDA data presented may not be comparable to similarly titled measures at other companies because EBITDA and Adjusted EBITDA exclude some items that affect net income attributable to our unitholders, and these items may be defined differently by other companies. Our senior management uses Adjusted EBITDA to evaluate consolidated operating performance and the operating performance of our business segments and to allocate resources and capital to the business segments. In addition, our senior management uses Adjusted EBITDA as a performance measure to evaluate the viability of proposed projects and to determine overall rates of return on alternative investment opportunities.

We believe that investors benefit from having access to the same financial measures that we use. Further, we believe that these measures are useful to investors because they are one of the bases for comparing our operating performance with that of other companies with similar operations, although our measures may not be directly comparable to similar measures used by other companies.

Each segment uses the same accounting policies as those used in the preparation of our consolidated financial statements. All inter-segment revenues, operating income and assets have been eliminated. All periods are presented on a consistent basis. All of our operations and assets are conducted and located in the United States, including Puerto Rico, or the Bahamas.

42

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Financial information about each segment, EBITDA and Adjusted EBITDA are presented below for the periods or at the dates indicated (in thousands):

	Three Months Ended June  30,						Six Months Ended June  30,
	2011			2010			2011			2010
Revenue:
Pipelines & Terminals	$	149,110		$	140,107		$	293,316		$	279,015
International Operations (1)		52,990			—			98,065			—
Natural Gas Storage		14,085			21,249			33,689			46,655
Energy Services		864,125			501,949			1,915,437			1,070,151
Development & Logistics		10,580			10,785			20,171			18,300
Intersegment		(13,798	)		(6,814	)		(31,050	)		(15,671	)
Total revenue	$	1,077,092		$	667,276		$	2,329,628		$	1,398,450
Depreciation and amortization:
Pipelines & Terminals	$	13,214		$	11,428		$	25,775		$	22,697
International Operations		13,036			—			23,431			—
Natural Gas Storage		1,803			1,640			3,519			3,281
Energy Services		1,280			1,176			2,515			2,371
Development & Logistics		423			425			757			848
Total depreciation and amortization	$	29,756		$	14,669		$	55,997		$	29,197
Operating income (loss):
Pipelines & Terminals	$	67,792		$	68,449		$	139,119		$	136,939
International Operations		19,972			—			38,701			—
Natural Gas Storage		(5,618	)		3,302			(6,018	)		6,753
Energy Services		2,258			(471	)		3,525			(3,868	)
Development & Logistics		1,531			659			3,171			1,606
Total operating income	$	85,935		$	71,939		$	178,498		$	141,430

(1) The International Operations segment’s revenue generated in the Bahamas was $48.8 million and $90.2 million for the three and six months ended June 30, 2011, respectively, which represents 92.0% of the International Operations segment’s total revenue for both periods.

43

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Three Months Ended June  30,						Six Months Ended June  30,
	2011			2010			2011			2010
Adjusted EBITDA:
Pipelines & Terminals	$	84,113		$	83,919		$	174,233		$	167,407
International Operations		30,646			—			56,153			—
Natural Gas Storage		(2,612	)		6,174			(160	)		12,558
Energy Services		3,841			1,306			6,600			(246	)
Development & Logistics		1,643			348			3,044			1,487
Total Adjusted EBITDA	$	117,631		$	91,747		$	239,870		$	181,206
GAAP Reconciliation:
Net income	$	93,592		$	53,438		$	161,405		$	104,080
Less: net income attributable to noncontrolling interests		(1,571	)		(41,931	)		(2,891	)		(81,303	)
Net income attributable to Buckeye Partners, L.P.		92,021			11,507			158,514			22,777
Interest and debt expense		28,596			21,350			57,093			43,006
Income tax benefit		(17	)		(646	)		(193	)		(664	)
Depreciation and amortization		29,756			14,669			55,997			29,197
EBITDA		150,356			46,880			271,411			94,316
Net income attributable to noncontrolling interests affected by Merger (for periods prior to Merger) (1)		—			41,921			—			81,055
Gain on sale of equity investment		(34,112	)		—			(34,112	)		—
Amortization of unfavorable storage contracts (2)		(2,396	)		—			(4,328	)		—
Non-cash deferred lease expense		1,031			1,058			2,061			2,117
Non-cash unit-based compensation expense		2,752			1,888			4,838			3,718
Adjusted EBITDA	$	117,631		$	91,747		$	239,870		$	181,206

(1) Amounts represent portions of BGH’s noncontrolling interests related to Buckeye that were eliminated as a result of the Merger. Amounts are added back for the 2010 periods to provide comparability with the 2011 periods.

(2) Represents amortization of unfavorable storage contracts acquired in connection with the BORCO acquisition.

	Six Months Ended June  30,
	2011		2010
Capital additions, net: (1)
Pipelines & Terminals	$	34,512	$	21,873
International Operations		60,395		—
Natural Gas Storage		4,821		3,292
Energy Services		690		2,064
Development & Logistics		43		343
Total capital additions, net	$	100,461	$	27,572

(1) Amount excludes $18.2 million and ($1.2) million of non-cash changes in accruals for capital expenditures for the six months ended June 30, 2011 and 2010, respectively (see Note 21).

44

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	June 30, 2011		December 31, 2010
Total Assets:
Pipelines & Terminals (1)	$	2,469,449	$	2,328,702
International Operations (2)		1,952,500		60,313
Natural Gas Storage		541,034		549,876
Energy Services		531,183		561,382
Development & Logistics		72,455		73,943
Total assets	$	5,566,621	$	3,574,216
Goodwill:
Pipelines & Terminals	$	248,250	$	248,250
International Operations		497,454		—
Natural Gas Storage		169,560		169,560
Energy Services		1,132		1,132
Development & Logistics		13,182		13,182
Total goodwill	$	929,578	$	432,124

(1) All equity investments are included in the assets of the Pipelines & Terminals segment.

(2) The International Operations segment’s long-lived assets consist of property, plant and equipment, goodwill, intangible assets and other non-current assets. Total long-lived assets located in or attributable to the Bahamas was $1,864.8 million at June 30, 2011, which was 97.3% of the International Operations segment’s total long-lived assets.

21. SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flows and non-cash transactions were as follows for the periods indicated (in thousands):

	Six Months Ended June  30,
	2011		2010
Cash paid for interest (net of capitalized interest)	$	41,958	$	40,165
Cash paid for income taxes		452		419
Capitalized interest		3,501		1,117
Non-cash changes in assets and liabilities:
Change in accrued and other current liabilities related to capital expenditures	$	18,165	$	(1,186	)
Non-cash financing activities:
Issuance of units to First Reserve for BORCO acquisition	$	407,391	$	—
Issuance of units to Vopak for BORCO acquisition		96,110		—
Issuance of Class B Units in lieu of quarterly cash distribution		13,625		—

45

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

22. SUBSEQUENT EVENTS

Acquisition of Refined Petroleum Products Terminals and Pipeline in Maine

On July 19, 2011, we acquired interests in two petroleum products terminals in Maine and a 124-mile pipeline that connects the two terminals from an affiliate of ExxonMobil for $23.5 million in cash. We purchased a pipeline and terminal in Bangor, Maine. We also purchased a terminal in Portland, Maine through a 50/50 joint venture with Irving Oil Terminals Inc. that will be operated by the Development & Logistics segment. We will operate both terminals and the pipeline. The Portland terminal is a marine terminal with approximately 725,000 barrels of storage capacity, and the Bangor terminal has approximately 140,000 barrels of storage capacity. We financed this acquisition with borrowings under our Credit Facility.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following information should be read in conjunction with our unaudited condensed consolidated financial statements and accompanying notes included in this report. The following information and such unaudited condensed consolidated financial statements should also be read in conjunction with the consolidated financial statements and related notes, together with our discussion and analysis of financial condition and results of operations, included in our Annual Report on Form 10-K/A for the year ended December 31, 2010.

Our consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”).

Cautionary Note Regarding Forward-Looking Statements

This discussion contains various forward-looking statements and information that are based on our beliefs, as well as assumptions made by us and information currently available to us. When used in this document, words such as “proposed,” “anticipate,” “project,” “potential,” “could,” “should,” “continue,” “estimate,” “expect,” “may,” “believe,” “will,” “plan,” “seek,” “outlook” and similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements. Although we believe that such expectations reflected in such forward-looking statements are reasonable, we cannot give any assurances that such expectations will prove to be correct. Such statements are subject to a variety of risks, uncertainties and assumptions as described in more detail in Item 1A “Risk Factors” included in our Annual Report on Form 10-K/A for the year ended December 31, 2010. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Although the expectations in the forward-looking statements are based on our current beliefs and expectations, caution should be taken not to place undue reliance on any such forward-looking statements because such statements speak only as of the date hereof. 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.

Overview of Critical Accounting Policies and Estimates

A summary of the significant accounting policies we have adopted and followed in the preparation of our condensed consolidated financial statements is included in our Annual Report on Form 10-K/A for the year ended December 31, 2010. Certain of these accounting policies require the use of estimates. As more fully described therein, the following estimates, in our opinion, are subjective in nature, require the exercise of judgment and involve complex analysis: depreciation methods, estimated useful lives and disposals of property, plant and equipment; reserves for environmental matters; fair value of derivatives; measuring the fair value of goodwill; and measuring recoverability of long-lived assets and equity method investments. These estimates are based on our knowledge and understanding of current conditions and actions we may take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our financial position, results of operations and cash flows.

As our business strategy involves expanding and diversifying our portfolio of energy assets, certain acquisitions have resulted in goodwill, which represents $929.6 million of total assets on our balance sheet at June 30, 2011. As a continued decline in natural gas prices, volatility in those prices and compressed seasonal spreads related to the Natural Gas Storage segment could cause further reduction in Adjusted EBITDA and a reduction of our estimates of future cash flows, we will continue to monitor the effect of the current economic conditions on the carrying value of goodwill of $169.6 million related to this segment, which could result in the recording of a non-cash impairment charge, possibly in the third quarter of 2011.

Overview of Business

Buckeye Partners, L.P. is a publicly traded Delaware master limited partnership (“MLP”), and its limited partnership units representing limited partner interests (“LP Units”) are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “BPL.” Buckeye GP LLC (“Buckeye GP”) is our general partner. Buckeye GP

47

is a wholly owned subsidiary of Buckeye GP Holdings L.P. (“BGH”), a Delaware limited partnership that was previously publicly traded on the NYSE prior to BGH’s merger with a wholly owned subsidiary of Buckeye. As used in these Notes to Unaudited Condensed Consolidated Financial Statements, “we,” “us,” “our” and “Buckeye” mean Buckeye Partners, L.P. and, where the context requires, includes our subsidiaries.

We were formed in 1986 and own and operate one of the largest independent refined petroleum products pipeline systems in the United States in terms of volumes delivered with approximately 6,100 miles of pipeline and over 100 active products terminals that provide aggregate storage capacity of over 64 million barrels. In 2011, we acquired (i) the Bahamas Oil Refining Company International Limited (“BORCO”) terminal facility in Freeport, Grand Bahama, The Bahamas, with a total installed capacity of approximately 21.6 million barrels, (ii) 33 refined petroleum products terminals with a total storage capacity of over 10 million barrels and approximately 650 miles of refined petroleum products pipelines (see Note 2 in the Notes to Unaudited Condensed Consolidated Financial Statements) and (iii) interests in two petroleum products terminals in Maine with a total storage capacity of approximately 0.9 million barrels and a 124-mile pipeline that connects the two terminals (see Note 22 in the Notes to Unaudited Condensed Consolidated Financial Statements). In addition, we operate and maintain approximately 3,400 miles of other pipelines under agreements with major oil and gas, petrochemical and chemical companies, and perform certain engineering and construction management services for third parties. We also own and operate a high performance natural gas storage facility in northern California, and are a wholesale distributor of refined petroleum products in the United States in areas also served by our pipelines and terminals.

We operate and report in five business segments: Pipelines & Terminals; International Operations; Natural Gas Storage; Energy Services; and Development & Logistics. Effective January 1, 2011, we realigned our five business segments. We combined the Pipeline Operations and Terminalling & Storage segments into one segment, the Pipelines & Terminals segment, and moved our terminal in Yabucoa, Puerto Rico, previously included as part of the Terminalling & Storage segment, to a new International Operations segment with the BORCO facility. We have adjusted our quarter-to-quarter comparisons to conform to the current presentation. See Note 20 in the Notes to Unaudited Condensed Consolidated Financial Statements for a discussion of our business segments.

Our primary business objective is to provide stable and sustainable cash distributions to our unitholders, while maintaining a relatively low investment risk profile. The key elements of our strategy are to maximize utilization of our assets at the lowest cost per unit, maintain stable long-term customer relationships, operate in a safe and environmentally responsible manner, optimize, expand and diversify our portfolio of energy assets, and maintain a solid, conservative financial position and our investment-grade credit rating.

Merger

On November 19, 2010, we consummated a transaction pursuant to a plan and agreement of merger (the “Merger Agreement”) with our general partner, BGH, BGH’s general partner and Grand Ohio, LLC (“Merger Sub”), our subsidiary. Pursuant to the Merger Agreement, Merger Sub was merged into BGH, with BGH as the surviving entity (the “Merger”). In the transaction, the incentive compensation agreement (also referred to as the incentive distribution rights) held by our general partner was cancelled, the general partner units held by our general partner (representing an approximate 0.5% general partner interest in us) were converted to a non-economic general partner interest, all of the economic interest in BGH was acquired by us and BGH unitholders received aggregate consideration of approximately 20.0 million of our LP Units.

Although titled Buckeye Partners, L.P., the accompanying 2010 financial statements in this Quarterly Report on Form 10-Q were originally the financial statements of BGH prior to the completion of the Merger. BGH is considered the surviving consolidated entity for accounting purposes, although Buckeye is the surviving consolidated entity for legal and reporting purposes. The Merger was accounted for as an equity transaction. Therefore, changes in BGH’s ownership interest as a result of the Merger did not result in gain or loss recognition.

Our general partner, Buckeye GP, continues to manage us following the Merger.

48

Recent Developments

Acquisition of BORCO

On December 18, 2010, we, through a wholly owned subsidiary, entered into a sale and purchase agreement with affiliates of FRC Founders Corporation (“First Reserve”), pursuant to which we agreed to acquire First Reserve’s indirect 80% interest in FR Borco Coop Holdings, L.P. (“FRBCH”), the indirect owner of BORCO, for $1.15 billion, financed through a combination of debt and equity, including the issuance of Class B units representing limited partner interests (“Class B Units”) and LP Units to First Reserve. BORCO is the fourth largest oil and petroleum products storage terminal in the world and the largest petroleum products facility in the Caribbean with current storage capacity of approximately 21.6 million barrels. On January 18, 2011, we completed the purchase of First Reserve’s interest in BORCO through the acquisition by us of all of the partnership interests in FR Borco Topco, L.P., which indirectly owned First Reserve’s interest.

Vopak Bahamas B.V. (“Vopak”), which is based in The Netherlands, owned the remaining 20% interest in FRBCH. On February 16, 2001, Vopak sold its 20% interest in FRBCH to us for approximately $276.5 million of cash and equity, which is a proportionate price and on the same terms and conditions as those in the sale and purchase agreement with First Reserve.

On January 13, 2011, we issued $650.0 million aggregate principal amount of 4.875% Notes due 2021 (the “4.875% Notes”) in an underwritten public offering. The notes were issued at 99.62% of their principal amount. Total proceeds from this offering, after underwriters’ fees, expenses and debt issuance costs of $4.9 million, were approximately $642.6 million, and were used to fund a portion of the purchase price of the BORCO acquisition.

On January 18 and 19, 2011, we issued 5,794,725 LP Units and 1,314,870 Class B Units to institutional investors for aggregate consideration of approximately $425.0 million to fund a portion of the BORCO acquisition. On January 18, 2011, we issued 2,483,444 LP Units and 4,382,889 Class B Units to First Reserve as $400.0 million of consideration to fund a portion of the BORCO acquisition. On February 16, 2011, we issued 620,861 LP Units and 1,095,722 Class B Units to Vopak as $100.0 million of consideration to fund a portion of the BORCO acquisition. Equity issuance costs incurred on these transactions were approximately $4.6 million. The remaining purchase price was funded with cash on hand at closing and borrowings under our unsecured revolving credit agreement (“Credit Facility”).

On January 18, 2011, in connection with the BORCO acquisition, we repaid all of BORCO’s outstanding indebtedness and settled BORCO’s interest rate derivative instruments, consisting of approximately $318.2 million.

For additional information, see Note 2 in the Notes to Unaudited Condensed Consolidated Financial Statements.

Acquisition of Pipeline & Terminal Assets

On June 1, 2011, we acquired 33 refined petroleum products terminals with total storage capacity of over 10 million barrels and approximately 650 miles of refined petroleum products pipelines from BP Products North America Inc. and its affiliates (“BP”) for $166.0 million. The terminal and pipeline assets are located in the Midwestern, Southeastern and Western United States, and the acquisition of these assets further extend our operations into new, key geographic markets. The operations of these acquired assets are reported in the Pipelines & Terminals segment. We funded this acquisition with borrowings under our Credit Facility.

Equity Offering

In April 2011, we issued 5,520,000 LP Units, which included 720,000 LP Units issued as part of the overallotment option, in an underwritten public offering at a public offering price of $59.41 per LP Unit. Total proceeds from the offering, including the overallotment option and after the underwriters’ discount of $1.99 per LP Unit and offering expenses, were approximately $316.6 million, and were used to reduce amounts outstanding under our Credit Facility.

49

Sale of Interest in West Texas LPG Pipeline Limited Partnership

On May 11, 2011, we sold our 20% interest in West Texas LPG Pipeline Limited Partnership (“WT LPG”) to affiliates of Atlas Pipeline Partners L.P. for $85.0 million. WT LPG owns a 2,295-mile common-carrier pipeline system that transports natural gas liquids from points in New Mexico and Texas to Mont Belvieu, Texas for fractionation. Chevron Pipeline Company, which owns the remaining 80% interest, is the operator of WT LPG. The proceeds from the sale will be used to fund a portion of our internal growth capital projects planned for 2011. We recognized a gain of $34.1 million on the sale of our interest in WT LPG.

Acquisition of Refined Petroleum Products Terminals and Pipeline in Maine

On July 19, 2011, we acquired interests in two petroleum products terminals in Maine and a 124-mile pipeline that connects the two terminals from an affiliate of ExxonMobil for $23.5 million in cash. We purchased a pipeline and terminal in Bangor, Maine. We also purchased a terminal in Portland, Maine through a 50/50 joint venture with Irving Oil Terminals Inc. that will be operated by the Development & Logistics segment. The Portland terminal is a marine terminal with approximately 725,000 barrels of storage capacity, and the Bangor terminal has approximately 140,000 barrels of storage capacity. We financed this acquisition with borrowings under our Credit Facility.

Results of Operations

Adjusted EBITDA

Adjusted EBITDA is the primary measure used by senior management, including our Chief Executive Officer, to evaluate our operating results and to allocate our resources. We define EBITDA, a measure not defined under GAAP, as net income attributable to our unitholders before interest and debt expense, income taxes and depreciation and amortization. EBITDA should not be considered an alternative to net income, operating income, cash flow from operations or any other measure of financial performance or liquidity presented in accordance with GAAP. The EBITDA measure eliminates the significant level of non-cash depreciation and amortization expense that results from the capital-intensive nature of our businesses and from intangible assets recognized in business combinations. In addition, EBITDA is unaffected by our capital structure due to the elimination of interest and debt expense and income taxes. We define Adjusted EBITDA, which is also a non-GAAP measure, as EBITDA plus: (i) non-cash deferred lease expense, which is the difference between the estimated annual land lease expense for our natural gas storage facility in the Natural Gas Storage segment to be recorded under GAAP and the actual cash to be paid for such annual land lease; (ii) non-cash unit-based compensation expense; and (iii) income attributable to noncontrolling interests related to Buckeye for periods prior to the Merger in order to provide comparability between periods before and after the Merger; less (i) amortization of unfavorable storage contracts acquired in connection with the BORCO acquisition; and (ii) gain on the sale of our equity investment in WT LPG.

The EBITDA and Adjusted EBITDA data presented may not be comparable to similarly titled measures at other companies because EBITDA and Adjusted EBITDA exclude some items that affect net income attributable to our unitholders, and these items may be defined differently by other companies. Our senior management uses Adjusted EBITDA to evaluate consolidated operating performance and the operating performance of our business segments and to allocate resources and capital to the business segments. In addition, our senior management uses Adjusted EBITDA as a performance measure to evaluate the viability of proposed projects and to determine overall rates of return on alternative investment opportunities.

We believe that investors benefit from having access to the same financial measures that we use. Further, we believe that these measures are useful to investors because they are one of the bases for comparing our operating performance with that of other companies with similar operations, although our measures may not be directly comparable to similar measures used by other companies.

50

The following table presents Adjusted EBITDA by segment and on a consolidated basis for the periods indicated, and a reconciliation of EBITDA and Adjusted EBITDA to net income attributable to our unitholders, which is the most comparable GAAP financial measure (in thousands):

	Three Months Ended June  30,						Six Months Ended June  30,
	2011			2010			2011			2010
Adjusted EBITDA:
Pipelines & Terminals	$	84,113		$	83,919		$	174,233		$	167,407
International Operations		30,646			—			56,153			—
Natural Gas Storage		(2,612	)		6,174			(160	)		12,558
Energy Services		3,841			1,306			6,600			(246	)
Development & Logistics		1,643			348			3,044			1,487
Total Adjusted EBITDA	$	117,631		$	91,747		$	239,870		$	181,206
GAAP Reconciliation:
Net income	$	93,592		$	53,438		$	161,405		$	104,080
Less: net income attributable to noncontrolling interests		(1,571	)		(41,931	)		(2,891	)		(81,303	)
Net income attributable to Buckeye Partners, L.P.		92,021			11,507			158,514			22,777
Interest and debt expense		28,596			21,350			57,093			43,006
Income tax benefit		(17	)		(646	)		(193	)		(664	)
Depreciation and amortization		29,756			14,669			55,997			29,197
EBITDA		150,356			46,880			271,411			94,316
Net income attributable to noncontrolling interests affected by Merger (for periods prior to Merger) (1)		—			41,921			—			81,055
Gain on sale of equity investment		(34,112	)		—			(34,112	)		—
Amortization of unfavorable storage contracts (2)		(2,396	)		—			(4,328	)		—
Non-cash deferred lease expense		1,031			1,058			2,061			2,117
Non-cash unit-based compensation expense		2,752			1,888			4,838			3,718
Adjusted EBITDA	$	117,631		$	91,747		$	239,870		$	181,206

(1) Amounts represent portions of BGH’s noncontrolling interests related to Buckeye that were eliminated as a result of the Merger. Amounts are added back for the 2010 periods to provide comparability with the 2011 periods.

(2) Represents amortization of unfavorable storage contracts acquired in connection with the BORCO acquisition.

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Segment Results

A summary of financial information by business segment follows for the periods indicated (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Revenues:
Pipelines & Terminals	$	149,110		$	140,107		$	293,316		$	279,015
International Operations		52,990			—			98,065			—
Natural Gas Storage		14,085			21,249			33,689			46,655
Energy Services		864,125			501,949			1,915,437			1,070,151
Development & Logistics		10,580			10,785			20,171			18,300
Intersegment		(13,798	)		(6,814	)		(31,050	)		(15,671	)
Total revenues	$	1,077,092		$	667,276		$	2,329,628		$	1,398,450
Total costs and expenses:(1)
Pipelines & Terminals	$	81,318		$	71,658		$	154,197		$	142,076
International Operations		33,018			—			59,364			—
Natural Gas Storage		19,703			17,947			39,707			39,902
Energy Services		861,867			502,420			1,911,912			1,074,019
Development & Logistics		9,049			10,126			17,000			16,694
Intersegment		(13,798	)		(6,814	)		(31,050	)		(15,671	)
Total costs and expenses	$	991,157		$	595,337		$	2,151,130		$	1,257,020
Depreciation and amortization:
Pipelines & Terminals	$	13,214		$	11,428		$	25,775		$	22,697
International Operations		13,036			—			23,431			—
Natural Gas Storage		1,803			1,640			3,519			3,281
Energy Services		1,280			1,176			2,515			2,371
Development & Logistics		423			425			757			848
Total depreciation and amortization	$	29,756		$	14,669		$	55,997		$	29,197
Operating income (loss):
Pipelines & Terminals	$	67,792		$	68,449		$	139,119		$	136,939
International Operations		19,972			—			38,701			—
Natural Gas Storage		(5,618	)		3,302			(6,018	)		6,753
Energy Services		2,258			(471	)		3,525			(3,868	)
Development & Logistics		1,531			659			3,171			1,606
Total operating income	$	85,935		$	71,939		$	178,498		$	141,430

(1) Total costs and expenses includes depreciation and amortization.

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The following table presents product volumes transported and average daily throughput for the Pipelines & Terminals segment in barrels per day (“bpd”), average daily throughput for the International Operations segment and total volumes sold in gallons for the Energy Services segment for the periods indicated:

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Pipelines & Terminals (average bpd):
Pipelines:
Gasoline		660,800		668,900		632,000		639,100
Jet fuel		348,100		339,300		337,300		330,900
Diesel fuel		244,300		223,100		242,400		225,300
Heating oil		31,300		36,100		70,700		74,800
LPGs		20,400		21,300		18,800		20,900
Other products		11,500		3,700		8,600		2,100
Total pipelines throughput		1,316,400		1,292,400		1,309,800		1,293,100
Terminals: (1)
Products throughput		625,600		570,000		581,000		563,200
International Operations (average bpd):(2)
Products throughput		516,400		—		521,200		—
Energy Services (in thousands of gallons):
Sales volumes		281,900		235,100		663,400		502,100

(1) 2011 amounts include throughput volumes on terminals acquired from BP on June 1, 2011.

(2) The BORCO facility was acquired on January 18, 2011, and the Yabucoa, Puerto Rico terminal was acquired on December 10, 2010.

Three Months Ended June 30, 2011 Compared to Three Months Ended June 30, 2010

Consolidated

Adjusted EBITDA. Adjusted EBITDA increased by $25.9 million, or 28.2%, to $117.6 million for the three months ended June 30, 2011 from $91.7 million for the corresponding period in 2010. The International Operations segment, the Energy Services segment, the Development & Logistics segment and the Pipelines & Terminals segment were primarily responsible for the increase in Adjusted EBITDA. The International Operations segment increased Adjusted EBITDA by $30.6 million, as a result of the acquisitions of BORCO and the Yabucoa, Puerto Rico terminal in January 2011 and December 2010, respectively, offset by acquisition and integration expenses. The Energy Services segment’s Adjusted EBITDA increased by $2.5 million for the three months ended June 30, 2011 as compared to the corresponding period in 2010, as a result of increased volumes of product sold and higher margins, which includes recognition of a biodiesel tax credit recorded as a reduction to cost of sales, partially offset by increased expenses. The Development & Logistics segment’s Adjusted EBITDA increased by $1.3 million for the three months ended June 30, 2011 as compared to the corresponding period in 2010, primarily due to the recognition of expenses in the 2010 period associated with a customer bankruptcy, partially offset by the recognition of $1.1 million of revenue in the 2010 period related to the sale of ammonia linefill. The Pipelines & Terminals segment’s Adjusted EBITDA increased by $0.2 million for the three months ended June 30, 2011 as compared to the corresponding period in 2010, as a result of the benefit of higher tariff rates and terminalling fees and the acquisition of pipeline and terminal assets in 2011 and 2010, partially offset by acquisition and integration expenses and lower transportation volumes on assets existing prior to acquisitions after second quarter 2010 (“legacy assets”).

These increases in Adjusted EBITDA were partially offset by a decrease in Adjusted EBITDA in the Natural Gas Storage segment. The Natural Gas Storage segment’s Adjusted EBITDA decreased by $8.8 million for the three months ended June 30, 2011 as compared to the corresponding period in 2010, as a result of low natural gas

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prices, low volatility in those prices and compressed seasonal spreads, which led to a decrease in the net contribution from hub services activities and a decrease in net lease revenue. Adjusted EBITDA was also unfavorably impacted by a decrease of $0.8 million in income from equity investments for the three months ended June 30, 2011 as compared to the corresponding period in 2010, primarily due to the sale of our interest in one of our investments. The revenue and expense factors affecting the variance in consolidated Adjusted EBITDA are more fully discussed below.

Revenue. Revenue was $1,077.1 million for the three months ended June 30, 2011, which is an increase of $409.8 million, or 61.4%, from the three months ended June 30, 2010. The increase in revenue for the three months ended June 30, 2011 as compared to the corresponding period in 2010 was caused primarily by the following:

• an increase of $362.2 million in revenue from the Energy Services segment, resulting from an overall increase in refined petroleum product prices and volumes of product sold during the three months ended June 30, 2011 as compared to the corresponding period in 2010. The 46.8 million gallon increase in sales volume resulted in an increase in revenue of approximately $99.9 million, and the increase in the average sales price per gallon from $2.13 in the 2010 period to $3.07 in the 2011 period, or approximately $0.94 per gallon, contributed to an increase in revenue of approximately $262.3 million;

• revenue of $53.0 million from the International Operations segment, as the result of the BORCO acquisition in 2011 and the Puerto Rico terminal acquisition in December 2010; and

• an increase of $9.0 million in revenue from the Pipelines & Terminals segment, resulting from the benefit of higher tariff rates and terminalling fees and the acquisition of pipeline and terminal assets in 2011 and 2010, partially offset by lower transportation volumes on legacy assets and unfavorable settlement experience.

The increase in revenue was partially offset by:

• a decrease of $7.1 million in revenue from the Natural Gas Storage segment, resulting primarily from lower fees from lease and hub services transactions as a result of general market conditions, including low natural gas prices, low volatility in those prices and compressed seasonal spreads; and

• a decrease of $0.2 million in revenue from the Development & Logistics segment, resulting primarily from the recognition of $1.1 million of revenue in the 2010 period related to the sale of ammonia linefill, partially offset by increased operating service revenue and project management revenue in the 2011 period.

Total Costs and Expenses. Total costs and expenses were $991.2 million for the three months ended June 30, 2011, which is an increase of $395.9 million, or 66.5%, from the corresponding period in 2010. Total costs and expenses reflect:

• an increase of $360.5 million in the Energy Services segment’s cost of product sales in the 2011 period as compared to the 2010 period, primarily as a result of increased refined petroleum product prices and increased volumes sold. The average cost of products sold, which includes recognition of a biodiesel tax credit, increased from approximately $2.11 per gallon in the 2010 period to approximately $3.04 per gallon in the 2011 period, or approximately $0.93 per gallon, resulting in an increase in cost of products sold of approximately $261.7 million, and sales volumes increased by 46.8 million gallons between the 2010 and 2011 periods, contributing $98.8 million to the increase in cost of products sold;

• $33.0 million of costs and expenses of the International Operations segment, as a result of operating the BORCO facility and the Puerto Rico terminal acquired in 2011 and December 2010, respectively, and acquisition and integration expenses.

• an increase of $9.6 million in costs and expenses of the Pipelines & Terminals segment, primarily resulting from acquisition and integration expenses, operating costs relating to the pipeline and terminal assets acquired in June 2011 and November 2010 and higher integrity program expenditures;

• an increase of $1.8 million in costs and expenses of the Natural Gas Storage segment, resulting from higher costs associated with hub services transactions recognized as an expense and increased outside service costs due to well workover costs; and

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• an increase of $15.1 million in depreciation and amortization, primarily on assets acquired in the BORCO acquisition and in the pipeline and terminal assets acquisitions in June 2011 and November 2010. Depreciation and amortization expense are not components of Adjusted EBITDA as presented in the reconciliation above.

Total costs and expenses also reflect the following decrease:

• a decrease of $1.1 million in costs and expenses of the Development & Logistics segment, primarily due to the recognition of $2.4 million of expenses in the 2010 period related to the write-off of a portion of an outstanding receivable balance and other costs associated with a customer bankruptcy, partially offset by increased project management activities and a lower income tax benefit in the 2011 period, which is not a component of Adjusted EBITDA as presented in the reconciliation above.

Gain on sale of equity method investment. On May 11, 2011, we sold our 20% interest in WT LPG for $85.0 million and recognized a gain of $34.1 million on the sale (see Note 2 in the Notes to Unaudited Condensed Consolidated Financial Statements).

Net income attributable to noncontrolling interests. Net income attributable to noncontrolling interests was $1.6 million for the three months ended June 30, 2011 as compared to $41.9 million in the corresponding period in 2010. Noncontrolling interests represents Buckeye Pipe Line Services Company’s (“Services Company”) equity and portions of Sabina Pipelines (“Sabina”) and WesPac Pipelines – Memphis LLC (“WesPac Memphis”) that are not owned by Buckeye. For the 2010 period through November 19, 2010, the date of the Merger, noncontrolling interests also included equity interests in Buckeye that were not owned by BGH. These interests were eliminated in connection with the Merger.

Consolidated net income attributable to unitholders. Consolidated net income attributable to our unitholders was $92.0 million for the three months ended June 30, 2011 compared to $11.5 million for the three months ended June 30, 2010. Interest and debt expense increased by $7.2 million for the three months ended June 30, 2011 as compared to the corresponding period in 2010, which increase was largely attributable to the issuance in January 2011 of the 4.875% Notes and higher outstanding borrowings under BES’s credit agreement (“BES Credit Agreement”) and under our Credit Facility, partially offset by an increase of $1.4 million in capitalized interest, primarily as a result of the BORCO acquisition. Other revenue and expense items impacting operating income are discussed above.

For a more detailed discussion of the above factors affecting our results, see the following discussion by segment.

Pipelines & Terminals

Adjusted EBITDA. Adjusted EBITDA from the Pipelines & Terminals segment of $84.1 million for the three months ended June 30, 2011 increased by $0.2 million, or 0.2%, from $83.9 million for the corresponding period in 2010. The increase in Adjusted EBITDA was driven primarily by a $5.0 million benefit of higher tariff rates and terminalling fees, a $3.0 million increase as a result of the pipeline and terminal acquisitions in 2011 and 2010 and a $1.3 million increase in other revenues. These increases in Adjusted EBITDA were partially offset by a $3.9 million increase in acquisition and integration expenses, a $3.2 million decrease in revenue resulting primarily from lower pipeline and terminal volumes on legacy assets, a $0.8 million decrease in income from equity investments, unfavorable settlement experience of $0.4 million and a $0.8 million increase in cash operating expenses (amount excludes non-cash expenses, including depreciation and amortization and unit-based compensation expense, both of which are not components of Adjusted EBITDA as presented in the reconciliation above). The revenue and expense factors affecting the variance in Adjusted EBITDA are more fully discussed below.

Revenue. Revenue from the Pipelines & Terminals segment was $149.1 million for the three months ended June 30, 2011, which is an increase of $9.0 million, or 6.4%, from the corresponding period in 2010. Revenues increased $6.3 million due to the acquisition of pipelines and terminal assets in 2011 and 2010, a $5.0 million benefit of higher tariff rates and terminal fees resulting from overall average tariff rate increases of approximately

55

2.8% and 2.6% implemented in April 2011 and May 2010, respectively, and a $1.3 million increase in other revenues. These increases in revenue were partially offset by unfavorable settlement experience of $0.4 million. Overall terminalling volumes increased by 9.8% and overall pipeline transportation volumes increased by 1.9% primarily as a result of the acquisition of pipelines and terminal assets in June 2011 and November 2010. Excluding the impact of the acquisitions, pipeline and terminalling volumes decreased by 0.4% and 11.4%, respectively, due to decreased diesel, ethanol and jet fuel throughput volumes, collectively impacting revenues by $3.2 million.

Total Costs and Expenses. Total costs and expenses from the Pipelines & Terminals segment were $81.3 million for the three months ended June 30, 2011, which is an increase of $9.6 million, or 13.5%, from the corresponding period in 2010. The increase in total costs and expenses was primarily due to a $3.9 million increase in acquisition and integration expenses, a $3.3 million increase in costs and expenses related primarily to operating the pipeline and terminal assets acquired in June 2011 and November 2010, a $1.8 million increase in depreciation and amortization as a result of assets placed into service, a $1.6 million increase in integrity program expenditures, a $0.5 million increase in environmental remediation expenses and a $0.3 million increase in bad debt expense. Depreciation and amortization expense are not components of Adjusted EBITDA as presented in the reconciliation above. These increases in total costs and expenses were partially offset by a decrease of $1.3 million in professional and other fees and a $0.3 million decrease in operating power costs and property and other taxes.

Operating Income. Operating income from the Pipelines & Terminals segment was $67.8 million for the three months ended June 30, 2011 compared to operating income of $68.4 million for the three months ended June 30, 2010. Revenue and expense items impacting operating income are discussed above.

International Operations

Adjusted EBITDA. Adjusted EBITDA from the International Operations segment was $30.6 million for the three months ended June 30, 2011. The revenue and expense factors affecting Adjusted EBITDA are more fully discussed below.

Revenue. Revenue from the International Operations segment was $53.0 million for the three months ended June 30, 2011 as the result of the BORCO acquisition in 2011 and the Puerto Rico terminal acquisition in December 2010. Revenues included storage fees of $40.9 million, which represent fees charged for storage of various products, berthing fees of $5.4 million, which represent amounts charged to ships that utilize the facility’s jetties, and other ancillary service revenues of $4.3 million. Also included in revenue is the recognition of $2.4 million of revenue from unfavorable storage contracts acquired in connection with the BORCO acquisition, which is not a component of Adjusted EBITDA as presented in the reconciliation above.

Total Costs and Expenses. Total costs and expenses from the International Operations segment were $33.0 million for the three months ended June 30, 2011, and included $15.9 million of costs and expenses related to operating the BORCO facility and the Yabucoa terminal, including payroll and benefits related costs, repairs and maintenance costs and lease expenses and $4.1 million in acquisition and integration expenses. Total costs and expenses also included $13.0 million of depreciation and amortization, primarily related to the depreciation of property, plant and equipment and the amortization of intangible assets (see Note 2 in the Notes to Unaudited Condensed Consolidated Financial Statements for further discussion). Depreciation and amortization is not a component of Adjusted EBITDA as presented in the reconciliation above.

Operating Income. Operating income from the International Operations segment was $20.0 million for the three months ended June 30, 2011. Revenue and expense items impacting operating income are discussed above.

Natural Gas Storage

Adjusted EBITDA. Adjusted EBITDA from the Natural Gas Storage segment was a loss of $2.6 million for the three months ended June 30, 2011 decreased by $8.8 million, or 142.3%, from earnings of $6.2 million for the corresponding period in 2010. The decrease in Adjusted EBITDA was primarily the result of a decrease of $4.7 million in the net contribution from hub service activities, a decrease of $3.3 million in net lease revenue and an increase of $0.8 million in other operating expenses during the three months ended June 30, 2011. The revenue and expense factors affecting the variance in Adjusted EBITDA are more fully discussed below.

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Revenue. Revenue from the Natural Gas Storage segment was $14.1 million for the three months ended June 30, 2011, which is a decrease of $7.1 million, or 33.7%, from the corresponding period in 2010. Lease revenue and hub service fees are primarily determined by the difference in natural gas commodity prices for the periods in which natural gas is injected and withdrawn from the storage facility (i.e., time spread). Lease revenue decreased $4.8 million for the three months ended June 30, 2011, primarily due to a decrease in the fee charged for each volumetric unit of storage capacity leased. Market conditions resulted in a decrease of $2.3 million in fees for hub service agreements recognized as revenue during the three months ended June 30, 2011 as compared to the corresponding period in 2010.

Total Costs and Expenses. Total costs and expenses from the Natural Gas Storage segment were $19.7 million for the three months ended June 30, 2011, which is an increase of $1.8 million, or 9.8%, from the corresponding period in 2010. Costs of natural gas storage services, which includes hub services fees paid to customers for hub service activities, increased $0.8 million, which is the primary driver of the increase in expenses. Total costs and expenses also include an increase of $1.3 million in outside service costs, primarily due to well workover costs in the current period, and a $0.2 million increase in depreciation and amortization. Depreciation and amortization are not components of Adjusted EBITDA as presented in the reconciliation above. These increases in total costs and expenses were partially offset by a decrease of $0.3 million in payroll related costs.

Operating Income (Loss). Operating loss from the Natural Gas Storage segment was $5.6 million for the three months ended June 30, 2011 compared to operating income of $3.3 million for the three months ended June 30, 2010. Revenue and expense items impacting operating income (loss) are discussed above.

Energy Services

Adjusted EBITDA. Adjusted EBITDA from the Energy Services segment of $3.8 million for the three months ended June 30, 2011 increased by $2.5 million, or 194.1%, from $1.3 million for the corresponding period in 2010. The increase in Adjusted EBITDA was primarily driven by higher volumes, higher rack margins, which includes recognition of a biodiesel tax credit of $3.6 million recorded as a reduction to cost of sales and more opportunities to optimize our storage as compared to the 2010 period. At the rack, sales volumes were 19.9% higher than in the 2010 period. The revenue and expense factors affecting the variance in Adjusted EBITDA are more fully discussed below.

Revenue. Revenue from the Energy Services segment was $864.1 million for the three months ended June 30, 2011, which is an increase of $362.2 million, or 72.2%, from the corresponding period in 2010. This increase in revenue was primarily due to an increase in refined petroleum product average sales prices of approximately $0.94 per gallon (average sales price per gallon was $3.07 and $2.13 for the 2011 and 2010 periods, respectively) resulting in an increase of $262.3 million in the 2011 period, and an increase of 19.9% in sales volumes that contributed an additional $99.9 million in revenue.

Total Costs and Expenses. Total costs and expenses from the Energy Services segment were $861.9 million for the three months ended June 30, 2011, which is an increase of $359.5 million, or 71.5%, from the corresponding period in 2010. The increase in total costs and expenses was primarily due to a $360.5 million increase in cost of product sales as a result of increased volumes sold and an increase in refined petroleum product prices (average cost of product sold per gallon, which includes recognition of a biodiesel tax credit of $3.6 million, was $3.04 and $2.11 for the 2011 and 2010 periods, respectively). The increase in the cost of product sold between the 2010 and 2011 periods was due to the 19.9% increase in sales volumes, and the $0.93 per gallon increase in product sales price was $98.8 million and $261.7 million, respectively. These increases in total costs and expenses were partially offset by a decrease of $0.6 million in bad debt expense.

Operating Income (Loss). Operating income from the Energy Services segment was $2.3 million for the three months ended June 30, 2011 compared to operating loss of $0.5 million for the three months ended June 30, 2010. Revenue and expense items impacting operating income (loss) are discussed above.

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Development & Logistics

Adjusted EBITDA. Adjusted EBITDA from the Development & Logistics segment of $1.6 million for the three months ended June 30, 2011 increased by $1.3 million, or 372.1%, from $0.3 million for the corresponding period in 2010, primarily due to the recognition of $2.4 million of expenses in the 2010 period related to the write-off of a portion of an outstanding receivable balance and other costs associated with a customer bankruptcy, partially offset by the recognition of $1.1 million of revenue in the 2010 period related to the sale of ammonia linefill. The revenue and expense factors affecting the variance in Adjusted EBITDA are more fully discussed below.

Revenue. Revenue from the Development & Logistics segment was $10.6 million for the three months ended June 30, 2011, which is a decrease of $0.2 million, or 1.9%, from the corresponding period in 2010. The decrease in revenue was primarily due to a decrease of $1.5 million in other revenue, primarily from the recognition of $1.1 million of revenue in the 2010 period related to the sale of ammonia linefill, partially offset by an increase of $0.6 million in operating service revenues as a result of higher fees and increased reimbursable costs and an increase of $0.6 million in project management revenues as a result of an increase in the number of projects in the 2011 period.

Total Costs and Expenses. Total costs and expenses from the Development & Logistics segment were $9.0 million for the three months ended June 30, 2011, which is a decrease of $1.1 million, or 10.6%, from the corresponding period in 2010. The decrease in total costs and expenses was the result of the recognition of $2.4 million of expenses in the 2010 period related to the write-off of a portion of an outstanding receivable balance and other costs associated with a customer bankruptcy, partially offset by an increase in costs of $0.5 million related to project management activities discussed above and lower income tax benefit of $0.6 million in the 2011 period, which is not a component of Adjusted EBITDA as presented in the reconciliation above.

Operating Income. Operating income from the Development & Logistics segment was $1.5 million for the three months ended June 30, 2011 compared to operating income of $0.7 million for the three months ended June 30, 2010. Revenue and expense items impacting operating income are discussed above.

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

Consolidated

Adjusted EBITDA. Adjusted EBITDA increased by $58.7 million, or 32.4%, to $239.9 million for the six months ended June 30, 2011 from $181.2 million for the corresponding period in 2010. The International Operations segment, the Pipelines & Terminals segment, the Energy Services segment and the Development & Logistics segment were responsible for the increase in Adjusted EBITDA. The International Operations segment increased Adjusted EBITDA by $56.2 million, as a result of the acquisitions of BORCO and the Yabucoa, Puerto Rico terminal in January 2011 and December 2010, respectively, offset by acquisition and integration expenses. The Pipelines & Terminals segment’s Adjusted EBITDA increased by $6.8 million for the six months ended June 30, 2011 as compared to the corresponding period in 2010, driven by the benefit of higher tariff rates and terminalling fees, pipeline and terminal acquisitions in 2011 and 2010, favorable settlement experience and other revenues, partially offset by acquisition and integration expenses and a decrease in revenues resulting from lower terminalling volumes on legacy assets. The Energy Services segment’s Adjusted EBITDA increased by $6.8 million for the six months ended June 30, 2011 as compared to the corresponding period in 2010, as a result of increased volumes of product sold and higher margins, partially offset by increased expenses. The Development & Logistics segment’s Adjusted EBITDA increased by $1.5 million for the six months ended June 30, 2011 as compared to the corresponding period in 2010, primarily due to the recognition of expenses in the, 2010 period associated with a customer bankruptcy, higher operating contract services and higher project management margins which includes recognition of a biodiesel tax credit tax credit recorded as a reduction to cost of sales, partially offset by the recognition of $1.1 million of revenue in the 2010 period related to the sale of ammonia linefill and higher operating expenses.

These increases in Adjusted EBITDA were partially offset by a decrease in Adjusted EBITDA in the Natural Gas Storage segment. The Natural Gas Storage segment’s Adjusted EBITDA decreased by $12.8 million for the six months ended June 30, 2011 as compared to the corresponding period in 2010, as a result of low natural gas prices, low volatility in those prices and compressed seasonal spreads, which led to a decrease in the net contribution from hub services activities and a decrease in net lease revenue. The revenue and expense factors affecting the variance in consolidated Adjusted EBITDA are more fully discussed below.

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Revenue. Revenue was $2,329.6 million for the six months ended June 30, 2011, which is an increase of $931.1 million, or 66.6%, from the six months ended June 30, 2010. The increase in revenue for the six months ended June 30, 2011 as compared to the corresponding period in 2010 was caused primarily by the following:

• an increase of $845.2 million in revenue from the Energy Services segment, resulting from an overall increase in refined petroleum product prices and volumes of product sold during the six months ended June 30, 2011 as compared to the corresponding period in 2010. The 161.3 million gallon increase in sales volume resulted in an increase in revenue of approximately $343.9 million, and the increase in the average sales price per gallon from $2.13 in the 2010 period to $2.89 in the 2011 period, or approximately $0.76 per gallon, contributed to an increase in revenue of approximately $501.5 million;

• revenue of $98.1 million from the International Operations segment, as the result of the BORCO acquisition in 2011 and the Puerto Rico terminal acquisition in December 2010;

• an increase of $14.3 million in revenue from the Pipelines & Terminals segment, resulting from the benefit of higher tariff rates and terminalling fees, the acquisition of pipeline and terminal assets in 2011 and 2010, favorable settlement experience and increased other revenues; and

• an increase of $1.9 million in revenue from the Development & Logistics segment, resulting primarily from increased operating service revenues and increased revenues from the assignment of certain service contracts from the Pipelines & Terminals segment to the Development & Logistics segment in April 2010.

The increase in revenue was partially offset by:

• a decrease of $13.0 million in revenue from the Natural Gas Storage segment, resulting primarily from lower fees from lease and hub services transactions as a result of general market conditions, including low natural gas prices, low volatility in those prices and compressed seasonal spreads.

Total Costs and Expenses. Total costs and expenses were $2,151.1 million for the six months ended June 30, 2011, which is an increase of $894.1 million, or 71.1%, from the corresponding period in 2010. Total costs and expenses reflect:

• an increase of $839.2 million in the Energy Services segment’s cost of product sales in the 2011 period as compared to the 2010 period, primarily as a result of increased refined petroleum product prices and increased volumes sold. The average cost of products sold, which includes recognition of a biodiesel tax credit, increased from approximately $2.11 per gallon in the 2010 period to approximately $2.87 per gallon in the 2011 period, or approximately $0.76 per gallon, resulting in an increase in cost of products sold of approximately $498.0 million, and sales volumes increased by 161.3 million gallons between the 2010 and 2011 periods, contributing $341.2 million to the increase in cost of products sold;

• $59.4 million of costs and expenses of the International Operations segment, as a result of operating the BORCO facility and the Puerto Rico terminal acquired in 2011 and December 2010, respectively, and acquisition and integration expenses;

• an increase of $12.1 million in costs and expenses of the Pipelines & Terminals segment, primarily resulting from acquisition and integration expenses, higher payroll related costs, environmental remediation expenses, integrity program expenditures and operating costs relating to the pipeline and terminal assets acquired in June 2011 and November 2010, partially offset by lower expenses related to contract service activities from the assignment of certain service contracts from the Pipelines & Terminals segment to the Development & Logistics segment, bad debt expense, operating power costs and professional and other fees;

• an increase of $0.3 million in costs and expenses of the Development & Logistics segment, primarily due to increased operating service activities, including increased costs from the assignment of certain service contracts from the Pipelines & Terminals segment to the Development & Logistics segment and lower income tax benefit, partially offset by the recognition of expenses in the 2010 period associated with a customer bankruptcy. The income tax benefit is not a component of Adjusted EBITDA as presented in the reconciliation above; and

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• an increase of $26.8 million in depreciation and amortization, primarily on assets acquired in the BORCO acquisition and the pipelines and terminals assets acquired in June 2011. Depreciation and amortization expense are not components of Adjusted EBITDA as presented in the reconciliation above.

Total costs and expenses also reflect the following decrease:

• a decrease of $0.2 million in costs and expenses of the Natural Gas Storage segment, primarily due to lower costs associated with hub services transactions recognized as an expense, resulting from lower hub services activities, partially offset by increased outside services and other costs, primarily due to well workover costs.

Gain on sale of equity method investment. On May 11, 2011, we sold our 20% interest in WT LPG and recognized a gain of $34.1 million on the sale.

Net income attributable to noncontrolling interests. Net income attributable to noncontrolling interests was $2.9 million for the six months ended June 30, 2011 as compared to $81.3 million in the corresponding period in 2010. Noncontrolling interests represents Services Company equity and portions of Sabina and WesPac Memphis that are not owned by Buckeye. The 2011 amount includes $1.7 million of noncontrolling interests expense related to the 20% of BORCO not acquired by us until February 16, 2011. For the 2010 period through November 19, 2010, the date of the Merger, noncontrolling interests also included equity interests in Buckeye that were not owned by BGH. These interests were eliminated in connection with the Merger.

Consolidated net income attributable to unitholders. Consolidated net income attributable to our unitholders was $158.5 million for the six months ended June 30, 2011 compared to $22.8 million for the six months ended June 30, 2010. Interest and debt expense increased by $14.1 million for the six months ended June 30, 2011 as compared to the corresponding period in 2010, which increase was largely attributable to the issuance in January 2011 of the 4.875% Notes and higher outstanding borrowings under the BES Credit Agreement and under our Credit Facility, partially offset by an increase of $2.4 million in capitalized interest, primarily as a result of the BORCO acquisition. Other revenue and expense items impacting operating income are discussed above.

For a more detailed discussion of the above factors affecting our results, see the following discussion by segment.

Pipelines & Terminals

Adjusted EBITDA. Adjusted EBITDA from the Pipelines & Terminals segment of $174.2 million for the six months ended June 30, 2011 increased by $6.8 million, or 4.1%, from $167.4 million for the corresponding period in 2010. The increase in Adjusted EBITDA was driven primarily by an $8.1 million benefit of higher tariff rates and terminalling fees, a $3.3 million increase as a result of the pipeline and terminal acquisitions in 2011 and 2010, favorable settlement experience of $2.0 million and a $2.6 million increase in other revenues. These increases in Adjusted EBITDA were partially offset by a $4.6 million increase in acquisition and integration expenses, a $3.9 million decrease in revenues resulting primarily from lower terminalling volumes on legacy assets and a $0.6 million increase in cash operating expenses. The revenue and expense factors affecting the variance in Adjusted EBITDA are more fully discussed below.

Revenue. Revenue from the Pipelines & Terminals segment was $293.3 million for the six months ended June 30, 2011, which is an increase of $14.3 million, or 5.1%, from the corresponding period in 2010. Revenues increased due to an $8.1 million benefit of higher tariff rates and terminal fees resulting from overall average tariff rate increases of approximately 2.80% and 2.6% implemented in April 2011 and May 2010, respectively, a $6.8 million increase due to the acquisition of pipelines and terminal assets in 2011 and 2010, favorable settlement experience of $2.0 million reflecting the favorable impact of higher refined petroleum product prices and a $2.6 million increase in other revenues. These increases in revenue were partially offset by a $1.3 million decrease in revenue from contract service activities at customer facilities connected to our refined petroleum products pipelines pursuant to the assignment of such service contract to the Development & Logistics segment. Overall terminalling volumes increased by 3.2%, and overall pipeline transportation volumes increased by 1.3%, primarily as a result of

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the acquisition of pipeline and terminal assets in June 2011 and November 2010. Excluding the impact of the acquisitions, pipeline volumes were relatively consistent with prior year, while terminalling volumes decreased by 8.5%, due to decreased diesel, ethanol and jet fuel throughput volumes, collectively impacting revenues by $3.9 million.

Total Costs and Expenses. Total costs and expenses from the Pipelines & Terminals segment were $154.2 million for the six months ended June 30, 2011, which is an increase of $12.1 million, or 8.5%, from the corresponding period in 2010. The increase in total costs and expenses was primarily due to a $4.6 million increase in acquisition and integration expenses, a $3.5 million increase in costs and expenses related primarily to operating the pipeline and terminal assets acquired in June 2011 and November 2010, a $3.1 million increase in depreciation and amortization as a result of the acquisition of pipeline and terminal assets and assets placed into service, a $3.0 million increase in payroll related costs, a $2.1 million increase in integrity program expenditures and a $0.9 million increase in environmental remediation expenses. Depreciation and amortization expense are not components of Adjusted EBITDA as presented in the reconciliation above.

These increases in total costs and expenses were partially offset by a $1.3 million decrease in contract service activities due to the assignment of certain operating service contracts from the Pipelines & Terminals segment to the Development & Logistics segment, a $1.2 million decrease in bad debt expense, a decrease of $1.1 million in professional and other fees, a $1.1 million decrease in operating power costs due to contract renegotiations and a $0.4 million decrease in property and other taxes.

Operating Income. Operating income from the Pipelines & Terminals segment was $139.1 million for the six months ended June 30, 2011 compared to operating income of $136.9 million for the six months ended June 30, 2010. Revenue and expense items impacting operating income are discussed above.

International Operations

Adjusted EBITDA. Adjusted EBITDA from the International Operations segment was $56.2 million for the six months ended June 30, 2011. The revenue and expense factors affecting Adjusted EBITDA are more fully discussed below.

Revenue. Revenue from the International Operations segment was $98.1 million for the six months ended June 30, 2011, as the result of the BORCO acquisition in 2011 and the Puerto Rico terminal acquisition in December 2010. Revenues included storage fees of $74.7 million, which represent fees charged for storage of various products, berthing fees of $9.7 million, which represent amounts charged to ships that utilize the facility’s jetties, and other ancillary service revenues of $9.3 million. Also included in revenue is the recognition of $4.3 million of revenue from unfavorable storage contracts acquired in connection with the BORCO acquisition, which is not a component of Adjusted EBITDA as presented in the reconciliation above.

Total Costs and Expenses. Total costs and expenses from the International Operations segment were $59.4 million for the six months ended June 30, 2011, and included $30.8 million of costs and expenses related to operating the BORCO facility and the Yabucoa terminal, including payroll and benefits related costs, repairs and maintenance costs and lease expenses and $5.2 million in acquisition and integration expenses. Total costs and expenses also included $23.4 million of depreciation and amortization, primarily related to the depreciation of property, plant and equipment and the amortization of intangible assets (see Note 2 in the Notes to Unaudited Condensed Consolidated Financial Statements for further discussion). Depreciation and amortization is not a component of Adjusted EBITDA as presented in the reconciliation above.

Operating Income. Operating income from the International Operations segment was $38.7 million for the six months ended June 30, 2011. Revenue and expense items impacting operating income are discussed above.

Natural Gas Storage

Adjusted EBITDA. Adjusted EBITDA from the Natural Gas Storage segment was a loss of $0.2 million for the six months ended June 30, 2011 decreased by $12.8 million, or 101.3%, from earnings of $12.6 million for the

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corresponding period in 2010. The decrease in Adjusted EBITDA was primarily the result of a decrease of $6.6 million in the net contribution from hub service activities, a decrease of $3.9 million in net lease revenue and an increase of $2.3 million in other operating expenses during the six months ended June 30, 2011. The revenue and expense factors affecting the variance in Adjusted EBITDA are more fully discussed below.

Revenue. Revenue from the Natural Gas Storage segment was $33.7 million for the six months ended June 30, 2011, which is a decrease of $13.0 million, or 27.8%, from the corresponding period in 2010. Lease revenue and hub service fees are primarily determined by the difference in natural gas commodity prices for the periods in which natural gas is injected and withdrawn from the storage facility (i.e., time spread). Market conditions resulted in a decrease of $7.5 million in fees for hub service agreements recognized as revenue during the six months ended June 30, 2011 as compared to the corresponding period in 2010. Lease revenue decreased $5.5 million for the six months ended June 30, 2011, primarily due to a decrease in the fee charged for each volumetric unit of storage capacity leased.

Total Costs and Expenses. Total costs and expenses from the Natural Gas Storage segment were $39.7 million for the six months ended June 30, 2011, which is a decrease of $0.2 million, or 0.5%, from the corresponding period in 2010. Costs of natural gas storage services, which includes hub services fees paid to customers for hub service activities, decreased $2.5 million. Total costs and expenses also include a decrease of $0.4 million in payroll related costs. These decreases in total costs and expenses were offset by an increase of $2.5 million in outside services and other costs, primarily due to well workover costs in the current period, and a $0.2 million increase in depreciation and amortization. Depreciation and amortization are not components of Adjusted EBITDA as presented in the reconciliation above.

Operating Income (Loss). Operating loss from the Natural Gas Storage segment was $6.0 million for the six months ended June 30, 2011 compared to operating income of $6.8 million for the six months ended June 30, 2010. Revenue and expense items impacting operating income (loss) are discussed above.

Energy Services

Adjusted EBITDA. Adjusted EBITDA from the Energy Services segment of $6.6 million for the six months ended June 30, 2011 increased by $6.8 million, or 2782.9%, from a loss of $0.2 million for the corresponding period in 2010. The increase in Adjusted EBITDA was primarily driven by higher volumes, higher rack margins, which includes recognition of a biodiesel tax credit of $3.6 million recorded as a reduction to cost of sales and more opportunities to optimize our storage as compared to the 2010 period. At the rack, sales volumes were 32.1% higher than in the 2010 period. The revenue and expense factors affecting the variance in Adjusted EBITDA are more fully discussed below.

Revenue. Revenue from the Energy Services segment was $1,915.4 million for the six months ended June 30, 2011, which is an increase of $845.2 million, or 79.0%, from the corresponding period in 2010. This increase in revenue was primarily due to an increase in refined petroleum product average sales prices of approximately $0.76 per gallon (average sales price per gallon was $2.89 and $2.13 for the 2011 and 2010 periods, respectively) resulting in an increase of $501.5 million in the 2011 period, and an increase of 32.1% in sales volumes that contributed an additional $343.9 million in revenue.

Total Costs and Expenses. Total costs and expenses from the Energy Services segment were $1,911.9 million for the six months ended June 30, 2011, which is an increase of $837.9 million, or 78.0%, from the corresponding period in 2010. The increase in total costs and expenses was primarily due to an $839.2 million increase in cost of product sales as a result of increased volumes sold and an increase in refined petroleum product prices (average cost of product sold per gallon, which includes recognition of a biodiesel tax credit of $3.6 million, was $2.87 and $2.11 for the 2011 and 2010 periods, respectively). The increase in the cost of product sold between the 2010 and 2011 periods was due to the 32.1% increase in sales volumes, and the $0.76 per gallon increase in product sales price was $341.2 million and $498.0 million, respectively. These increases in total costs and expenses were partially offset by a decrease of $1.3 million in bad debt expense.

Operating Income (Loss). Operating income from the Energy Services segment was $3.5 million for the six months ended June 30, 2011 compared to operating loss of $3.9 million for the six months ended June 30, 2010. Revenue and expense items impacting operating income (loss) are discussed above.

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Development & Logistics

Adjusted EBITDA. Adjusted EBITDA from the Development & Logistics segment of $3.0 million for the six months ended June 30, 2011 increased by $1.5 million, or 104.7%, from $1.5 million for the corresponding period in 2010, primarily due to the recognition of $2.4 million of expenses in the 2010 period related to the write-off of a portion of an outstanding receivable balance and other costs associated with a customer bankruptcy, higher operating contract margins of $0.8 million and higher project management margins of $0.3 million, partially offset by the recognition of $1.1 million of revenue in the 2010 period related to the sale of ammonia linefill, and higher operating expenses of $0.9 million. The revenue and expense factors affecting the variance in Adjusted EBITDA are more fully discussed below.

Revenue. Revenue from the Development & Logistics segment was $20.2 million for the six months ended June 30, 2011, which is an increase of $1.9 million, or 10.2%, from the corresponding period in 2010. The increase in revenue was primarily due to an increase of $3.0 million in operating service revenues as a result of higher fees and increased reimbursable costs, an increase of $0.3 million in project management revenues and an increase of $0.2 million in rental revenues, primarily due to the assignment of certain service contracts from the Pipelines & Terminals segment to the Development & Logistics segment in the 2010 period. These increases in revenues were partially offset by the recognition of $1.2 million of revenue in 2010 related to the sale of ammonia linefill.

Total Costs and Expenses. Total costs and expenses from the Development & Logistics segment were $17.0 million for the six months ended June 30, 2011, which is an increase of $0.3 million, or 1.8%, from the corresponding period in 2010. The increase in total costs and expenses was the result of an increase of $2.0 million relating to operating services activities discussed above, including increased costs from the assignment of certain service contracts from the Pipelines & Terminals segment to the Development & Logistics segment and lower income tax benefit of $0.5 million in the 2011 period, partially offset by the recognition of $2.4 million of expenses in the 2010 period related to the write-off of a portion of an outstanding receivable balance and other costs associated with a customer bankruptcy. Income tax benefit is not a component of Adjusted EBITDA as presented in the reconciliation above.

Operating Income. Operating income from the Development & Logistics segment was $3.2 million for the six months ended June 30, 2011 compared to operating income of $1.6 million for the six months ended June 30, 2010. Revenue and expense items impacting operating income are discussed above.

Liquidity and Capital Resources

General

Our primary cash requirements, in addition to normal operating expenses and debt service, are for working capital, capital expenditures, business acquisitions and distributions to partners. Our principal sources of liquidity are cash from operations, borrowings under our Credit Facility and proceeds from the issuance of our units. We will, from time to time, issue debt securities to permanently finance amounts borrowed under the Credit Facility. Buckeye Energy Services LLC (“BES”) funds its working capital needs principally from its operations and the BES Credit Agreement. Our 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. Our goal has been to fund at least half of these expenditures with proceeds from equity offerings in order to maintain our investment-grade credit rating.

In 2011, we completed the purchase of First Reserve’s and Vopak’s interests in FRBCH, the indirect owner of BORCO, for approximately $1.4 billion in cash and equity. We also assumed BORCO’s outstanding indebtedness and settled BORCO’s interest rate derivative instruments, consisting of approximately $318.2 million. In order to fund a portion of the combined purchase price and the repayment of the assumption of BORCO’s indebtedness, in January 2011, we accessed the capital markets through a $650.0 million note issuance due 2021. The notes were issued at 99.62% of their principal amount. In addition, in January 2011, we issued 5,794,725 LP Units and 1,314,870 Class B Units to institutional investors for aggregate consideration of approximately $425.0 million. The

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proceeds from the debt offering and these equity issuances were used to fund a portion of the BORCO acquisition. The remaining purchase price for the BORCO acquisition and the repayment of the assumed debt was funded through the issuance of LP Units and Class B Units to both First Reserve and Vopak, cash on hand and borrowings under our Credit Facility.

In April 2011, we issued 5,520,000 LP Units, which included 720,000 LP Units issued as part of the overallotment option, in an underwritten public offering at a public offering price of $59.41 per LP Unit. Total proceeds from the offering, including the overallotment option and after the underwriters’ discount of $1.99 per LP Unit and offering expenses, were approximately $316.6 million, and were used to reduce amounts outstanding under our Credit Facility.

In June 2011, we acquired pipelines and terminal assets from BP for $166.0 million, and in July 2011, we acquired pipelines and terminal assets from ExxonMobil for $23.5 million. As a result of our actions in 2011 and the fact that no debt facilities mature prior to 2012, we believe that availabilities under our Credit Facility and the BES Credit Agreement, coupled with ongoing cash flows from operations, will be sufficient to fund our operations for the remainder of 2011, including any expansion plans for the BORCO terminal facility. In addition, we expect to use the proceeds from the sale of WT LPG to fund a portion of our internal growth capital projects planned for 2011. We will continue to evaluate a variety of financing sources, including the debt and equity markets described above, throughout 2011.

Debt

At June 30, 2011, we had $18.1 million of cash and cash equivalents on hand and approximately $460.0 million of available credit under the Credit Facility, after application of the facility’s funded debt ratio covenant. In addition, at June 30, 2011, BES had $53.1 million of available credit under the BES Credit Agreement, pursuant to certain borrowing base calculations under that agreement.

At June 30, 2011, we had an aggregate face amount of $2,462.2 million of debt, which consisted of the following:

• $300.0 million of 4.625% Notes due 2013 (the “4.625% Notes”);

• $275.0 million of 5.300% Notes due 2014 (the “5.300% Notes”);

• $125.0 million of 5.125% Notes due 2017 (the “5.125% Notes”);

• $300.0 million of 6.050% Notes due 2018 (the “6.050% Notes”);

• $275.0 million of 5.500% Notes due 2019 (the “5.500% Notes”);

• $650.0 million of 4.875% Notes due 2021;

• $150.0 million of 6.750% Notes due 2033 (the “6.750% Notes”);

• $120.0 million outstanding under the Credit Agreement; and

• $267.2 million outstanding under the BES Credit Agreement.

See Note 11 in the Notes to Unaudited Condensed Consolidated Financial Statements for more information about the terms of the debt discussed above.

On January 13, 2011, we sold the 4.875% Notes in an underwritten public offering. The notes were issued at 99.62% of their principal amount. Total proceeds from this offering, after underwriters’ fees, expenses and debt issuance costs of $4.9 million, were approximately $642.6 million, and were used to fund a portion of the purchase price for our acquisition of BORCO. See Note 2 in the Notes to Unaudited Condensed Consolidated Financial Statements for further discussion of the BORCO acquisition.

On January 18, 2011, in connection with the BORCO acquisition, we repaid all of BORCO’s outstanding indebtedness and settled BORCO’s interest rate derivative instruments, consisting of approximately $318.2 million.

The fair values of our aggregate debt and credit facilities were estimated to be $2,586.2 million and $1,897.5 million at June 30, 2011 and December 31, 2010, respectively. The fair values of the fixed-rate debt were estimated

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by observing market trading prices and by comparing the historic market prices of our publicly-issued debt with the market prices of other MLPs’ publicly-issued debt with similar credit ratings and terms. The fair values of our variable-rate debt are their carrying amounts, as the carrying amount reasonably approximates fair value due to the variability of the interest rates.

Equity

On January 18 and 19, 2011, we issued 5,794,725 LP Units and 1,314,870 Class B Units to institutional investors for aggregate consideration of approximately $425.0 million to fund a portion of the BORCO acquisition. On January 18, 2011, we issued 2,483,444 LP Units and 4,382,889 Class B Units to First Reserve as $400.0 million of consideration to fund a portion of the acquisition of First Reserve’s 80% interest in BORCO. On February 16, 2011, we issued 620,861 LP Units and 1,095,722 Class B Units to Vopak as $100.0 million of consideration to fund a portion of the acquisition of Vopak’s 20% interest in BORCO. Equity issuance costs incurred on these transactions were approximately $4.6 million.

As discussed above, in April 2011, we issued 5,520,000 LP Units, which included 720,000 LP Units issued as part of the overallotment option, in an underwritten public offering at a public offering price of $59.41 per LP Unit. Total proceeds from the offering, including the overallotment option and after the underwriters’ discount of $1.99 per LP Unit and offering expenses, were approximately $316.6 million, and were used to reduce amounts outstanding under our Credit Facility.

Registration Statement

We may issue equity or debt securities to assist us in meeting our liquidity and capital spending requirements. We have a universal shelf registration statement on file with the U.S. Securities and Exchange Commission (“SEC”) that does not place any dollar limits on the amount of debt and equity securities that we may issue thereunder.

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):

	Six Months Ended June 30,
	2011			2010
Cash provided by (used in):
Operating activities	$	184,855		$	231,951
Investing activities		(1,078,071	)		(5,298	)
Financing activities		897,723			(248,730	)

Operating Activities

Net cash flows provided by operating activities was $184.9 million for the six months ended June 30, 2011 compared to $232.0 million for the six months ended June 30, 2010. The following were the principal factors impacting net cash flows provided by operating activities for the six months ended June 30, 2011:

• The net change in fair values of derivatives was a decrease of $68.5 million to cash flows from operating activities for the six months ended June 30, 2011, resulting from the decrease in value related to futures contracts executed to hedge physical inventory. The offsetting adjustment is made to the value of inventory by adjusting inventory to current market prices.

• The net impact of working capital changes was an increase of $57.6 million to cash flows from operating activities for the six months ended June 30, 2011. The principal factors affecting the working capital changes were:

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• Inventories decreased by $58.1 million due to a decrease in volume of hedged inventory stored by the Energy Services segment. From time to time, the Energy Services segment stores hedged inventory to attempt to capture value when market conditions are economically favorable.

• Trade receivables decreased by $18.8 million, due to the timing of collections from customers, primarily as a result of the timing of the BORCO acquisition, which occurred on January 18, 2011.

• Accounts payable decreased by $23.7 million, due to lower payable balances at June 30, 2011 as a result of the timing of invoice payments.

• Construction and pipeline relocation receivables decreased by $1.8 million primarily due to a decrease in construction activity in the 2011 period.

• Prepaid and other current assets decreased by $0.3 million primarily due to a decrease in margin deposits on futures contracts in our Energy Services segment as a result of increased commodity prices during the six months ended June 30, 2011 (increased commodity prices result in an increase in our broker equity account and therefore less margin deposit is required), partially offset by an increase in prepaid insurance due to the timing of policy renewals and an increase in unbilled revenue within our Natural Gas Storage segment reflecting billings to counterparties in accordance with terms of their storage agreements.

• Accrued and other current liabilities increased by $2.2 million primarily due to an increase in customer deposits, partially offset by a decrease in accrued interest as a result of interest payments made during the period and a decrease in accrued compensation and benefits.

Investing Activities

Net cash flows used in investing activities was $1,078.1 million for the six months ended June 30, 2011 compared to $5.3 million for the six months ended June 30, 2010. The following were the principal factors resulting in the $1,072.8 million increase in net cash flows used in investing activities:

• Capital expenditures increased by $72.9 million for the six months ended June 30, 2011 compared with the six months ended June 30, 2010. See below for a discussion of capital spending.

• We completed the acquisition of BORCO by purchasing interests from First Reserve and Vopak on January 18, 2011 and February 16, 2011, respectively, for approximately $1.4 billion of total consideration, consisting of $893.7 million in cash, which is net of cash acquired of $27.0 million. The remaining consideration of $503.5 million consisted of the issuance of LP Units and Class B Units. See “– Financing Activities” below for a discussion of the repayment of BORCO’s outstanding indebtedness, which occurred in connection with the BORCO acquisition. See Note 2 in the Notes to Unaudited Condensed Consolidated Financial Statements for further discussion regarding the BORCO acquisition.

• We completed the acquisition of pipeline and terminal assets from BP for approximately $166.0 million. See Note 2 in the Notes to Unaudited Condensed Consolidated Financial Statements for further discussion.

• We received cash proceeds from the sale of our 20% interest in WT LTP of $85.0 million during the six months ended June 30, 2011. Cash proceeds from the sale of the Buckeye NGL Pipeline were $22.0 million during the six months ended June 30, 2010.

• We paid $1.8 million as a deposit for the pending acquisition of pipeline and terminal assets from an affiliate of ExxonMobil, which closed in July 2011 (see Note 22 in the Notes to Unaudited Condensed Consolidated Financial Statements for further discussion).

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Capital expenditures, net of non-cash changes in accruals for capital expenditures, were as follows for the periods indicated (in thousands):

	Six Months Ended June 30,
	2011		2010
Sustaining capital expenditures	$	19,766	$	9,195
Expansion and cost reduction		80,695		18,377
Total capital expenditures, net	$	100,461	$	27,572

Expansion and cost reduction projects in the first six months of 2011 included upgrades and expansions of the jetty structure at BORCO, terminal ethanol and butane blending, new pipeline connections, continued progress on a new pipeline and terminal billing system as well as various other operating infrastructure projects. In the first six months of 2010, expansion and cost reduction projects included terminal ethanol and butane blending, new pipeline connections, natural gas storage well recompletions, continued progress on a new pipeline and terminal billing system as well as various other pipeline and terminal operating infrastructure projects.

We expect to spend approximately $315.0 million to $385.0 million for capital expenditures in 2011, of which approximately $55.0 million to $65.0 million is expected to relate to sustaining capital expenditures and $260.0 million to $320.0 million is expected to relate to expansion and cost reduction projects. Approximately $210.0 million to $255.0 million of these amounts are related to capital expenditures in 2011 for the BORCO facility, of which $190.0 million to $230.0 million is expected to relate to expansion projects and $20.0 million to $25.0 million is expected to relate to sustaining capital expenditures. Approximately $105.0 million to $130.0 million of these amounts are related to capital expenditures in 2011 for our other assets, excluding the BORCO facility, of which $70.0 million to $90.0 million is expected to relate to expansion projects and $35.0 million to $40.0 million is expected to relate to sustaining capital expenditures. 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 2011 will include upgrades and expansions of the jetty structure, the inland dock and berth developments and terminal storage tank expansion projects at the BORCO facility, completion of additional storage tanks in the Midwest, the refurbishment of storage tanks and facilities in the Northeast, installation of vapor recovery units throughout our system of terminals, new injection and withdrawal wells at our natural gas storage facilities and various upgrades and expansions of our ethanol business. Cost reduction expenditures improve operational efficiencies or reduce costs.

Financing Activities

Net cash flows provided by financing activities was $897.7 million for the six months ended June 30, 2011 compared to net cash flows used in financing activities of $248.7 million for the six months ended June 30, 2010. The following were the principal factors resulting in the $1,146.4 million increase in net cash flows provided by financing activities:

• We borrowed $683.5 million and $95.0 million and repaid $661.5 million and $173.0 million under the Credit Facility during the six months ended June 30, 2011 and 2010, respectively.

• We repaid $318.2 million of debt assumed in the BORCO acquisition, which includes settlement of BORCO’s interest rate derivative instruments (see Note 2 in the Notes to Unaudited Condensed Consolidated Financial Statements).

• We repaid $1.5 million and $3.1 million under the Services Company 3.60% Senior Secured Notes (the “3.60% ESOP Notes”) during the six months ended June 30, 2011 and 2010, respectively. We repaid the 3.60% ESOP Notes in full in March 2011.

• We made net repayments under the BES Credit Agreement of $17.1 million and $45.6 million during the six months ended June 30, 2011 and 2010, respectively. We incurred $3.2 million of debt issuance costs during the six months ended June 30, 2010 related to an amendment to the BES Credit Agreement in June 2010.

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• We received $647.5 million from the issuance in January 2011 of $650.0 million in aggregate principal amount of the 4.875% Notes in an underwritten public offering. Debt issuance costs incurred were $4.9 million. Proceeds from this offering were used to fund a portion of the BORCO acquisition. In connection with this debt offering, we settled a treasury lock agreement, which resulted in the receipt of $0.5 million that is being amortized into interest expense over the ten-year term of the 4.875% Notes.

• We received total proceeds of $425.0 million from the issuance of 5,794,725 LP Units and 1,314,870 Class B Units to institutional investors in January 2011 to fund a portion of the BORCO acquisition. Equity issuance costs incurred in these equity transactions were approximately $4.6 million. We received $316.6 million in net proceeds from an underwritten equity offering in April 2011 for the public issuance of 5,520,000 LP Units.

• We received $0.4 million and $3.0 million in net proceeds from the exercise of LP Unit options during the six months ended June 30, 2011 and 2010, respectively.

• We paid $1.4 million and $1.5 million of costs associated with the Merger during the six months ended June 30, 2011 and 2010, respectively. The 2011 amount includes a payment for the settlement of litigation associated with the Merger (see Note 3 in the Notes to Unaudited Condensed Consolidated Financial Statements).

• Cash distributions paid to our partners were $162.9 million ($1.9875 per LP Unit) for the six months ended June 30, 2011. Cash distributions paid to partners of BGH were $23.8 million ($0.84 per unit) for the six months ended June 30, 2010. In connection with the Merger, BGH’s units were converted into Buckeye LP Units.

• Distributions to noncontrolling partners of Buckeye, consisting primarily of distributions paid by Sabina and WesPac Memphis, were $3.8 million for the six months ended June 30, 2011. Distributions to noncontrolling partners of Buckeye, consisting primarily of distributions to holders of LP Units, were $96.4 million for the six months ended June 30, 2010. Included in this amount was approximately $2.4 million of distributions paid primarily by Sabina and WesPac Memphis. Buckeye paid cash distributions of $1.8875 per LP Unit in the 2010 period. In connection with the Merger, the majority of noncontrolling interests were eliminated.

Derivatives

See “Item 3. Quantitative and Qualitative Disclosures About Market Risk – Market Risk – Non Trading Instruments” for a discussion of commodity derivatives used by our Energy Services segment.

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Other Considerations

Contractual Obligations

The following table summarizes our contractual obligations as of June 30, 2011 (in thousands):

	Payments Due by Period (1)
	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Long-term debt (2)	$	2,195,000	$	—	$	420,000	$	275,000	$	1,500,000
Interest payments (3)		925,787		62,709		213,901		185,988		463,189
Operating leases: (4)
Office space and other (5)		27,269		1,011		4,709		5,169		16,380
Equipment (6)		10,941		1,753		7,095		2,093		—
Land leases (7)		381,155		2,334		9,906		10,324		358,591
Purchase obligations (8)		97,575		97,575		—		—		—
Capital expenditure obligations (9)		20,197		20,197		—		—		—
Total contractual cash obligations	$	3,657,924	$	185,579	$	655,611	$	478,574	$	2,338,160

(1) Less than 1 year represents amounts for the remainder of 2011 (July 1 through December 31), 1-3 years represents amounts for 2012 and 2013, 3-5 years represents amounts for 2014 and 2015, and more than 5 years represents amounts after 2015.

(2) We have long-term payment obligations under our Credit Facility and our underwritten publicly issued notes. Amounts shown in the table represent our scheduled future maturities of long-term debt principal for the periods indicated. We have assumed that the borrowings under our Credit Facility as of June 30, 2011 will not be repaid until the maturity date of the facility. See Note 11 in the Notes to Unaudited Condensed Consolidated Financial Statements for additional information regarding our debt obligations.

(3) Interest payments include amounts due on our notes and interest payments and commitment fees due on our Credit Facility. The interest amount calculated on the Credit Facility is based on the assumption that the amount outstanding and the interest rate charged both remain at their current levels.

(4) We lease certain property, plant and equipment under noncancelable and cancelable operating leases. Amounts shown in the table represent minimum lease payment obligations under our operating leases with terms in excess of one year for the periods indicated. Lease expense is charged to operating expenses on a straight line basis over the period of expected benefit. Contingent rental payments are expensed as incurred. Total rental expense for the three months ended June 30, 2011 and 2010 was $8.5 million and $5.5 million, respectively. For the six months ended June 30, 2011 and 2010, total rental expense was $16.1 million and $10.5 million, respectively.

(5) Includes leases of space in office buildings and related land leases with respect to our Albany terminal.

(6) Includes BORCO facility leases for tugboats and a barge in our International Operations segment.

(7) Includes leases for inland dock and seabed in connection with our International Operations segment and leases for subsurface underground gas storage rights and surface rights in connection with our operations in the Natural Gas Storage segment. We may cancel the Natural Gas Storage segment leases if the storage reservoir is not used for underground storage of natural gas or the removal or injection thereof for a continuous period of two consecutive years. Lease expense associated with the Natural Gas Storage segment leases, which is being recognized on a straight-line basis over 44 years, was approximately $1.8 million for each of the three months ended June 30, 2011 and 2010 and $3.6 million for each of the six months ended June 30, 2011 and 2010. At June 30, 2011 and December 31, 2010, the balance of our Natural Gas Storage segment deferred lease liability was $15.4 million and $13.3 million, respectively. We estimate that this deferred lease liability will continue to increase through 2032, at which time our deferred lease liability is estimated to be approximately $64.7 million. Our deferred lease liability will then be reduced over the remaining 19 years of the lease, since the expected annual lease payments will exceed the amount of lease expense.

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(8) We have long and short-term purchase obligations for products and services with third-party suppliers. The prices that we are obligated to pay under these contracts approximate current market prices. The table shows our commitments and estimated payment obligations under these contracts for the periods indicated. Our estimated future payment obligations are based on the contractual price under each contract for products and services at June 30, 2011.

(9) We have short-term payment obligations relating to capital projects we have initiated. These commitments represent unconditional payment obligations that we have agreed to pay vendors for services rendered or products purchased.

In addition, our obligations related to our pension and postretirement benefit plans are discussed in Note 15 in the Notes to Unaudited Condensed Consolidated Financial Statements.

Off-Balance Sheet Arrangements

There have been no material changes with regard to our off-balance sheet arrangements since those reported in our Annual Report on Form 10-K/A for the year ended December 31, 2010.

Related Party Transactions

With respect to related party transactions, see Note 17 in the Notes to Unaudited Condensed Consolidated Financial Statements.

Recent Accounting Pronouncements

See Note 1 in the Notes to Unaudited Condensed Consolidated Financial Statements for a description of certain new accounting pronouncements that will or may affect our consolidated financial statements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Market Risk – Trading Instruments

We have no trading derivative instruments.

Market Risk – Non-Trading Instruments

We are exposed to financial market risk resulting from changes in commodity prices and interest rates. BORCO’s functional currency is the U.S. dollar and it is equivalent in value with the Bahamian dollar. Foreign exchange gains and losses arising from transactions denominated in a currency other than the functional currency are included in net income in the condensed consolidated statements of operations. The effects of foreign currency transactions were not considered to be material for the three and six months ended June 30, 2011.

Commodity Risk

Natural Gas Storage

The Natural Gas Storage segment enters into interruptible natural gas storage hub service agreements 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. Although the Natural Gas Storage segment does not purchase or sell natural gas, the Natural Gas Storage segment is subject to commodity risk because the value of natural gas storage hub services generally fluctuates based on changes in the relative market prices of natural gas over different delivery periods.

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As of June 30, 2011, the Natural Gas Storage segment has recorded the following assets and liabilities related to its hub services agreements (in thousands):

	June 30,
	2011
Assets:
Hub service agreements	$	24,774
Liabilities:
Hub service agreements		(18,497	)
Total	$	6,277

Energy Services

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 physical commodity forward fixed-price purchase and 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 the New York Mercantile Exchange (“NYMEX”) futures contracts to the change in fair value of our hedged fuel inventory.

Our Energy Services segment has not used hedge accounting with respect to its physical derivative contracts. Therefore, our physical derivative contracts and the related futures contracts used to offset the changes in fair value of the physical derivative contracts are all marked-to-market on the consolidated balance sheet with gains and losses being recognized in earnings during the period. In addition, hedge accounting has not been elected for futures contracts that have been executed to economically hedge a portion of the Energy Services segments’ refined petroleum products held in inventory; therefore, the changes in fair value of the futures contracts are marked-to-market on the consolidated balance sheet with gains and losses being recognized in earnings during the period.

As of June 30, 2011, the Energy Services segment had derivative assets and liabilities as follows (in thousands):

	June 30,
	2011
Assets:
Physical derivative contracts for refined products	$	644
Futures contracts for refined products		105
Liabilities:
Physical derivative contracts for refined products		(1,178	)
Futures contracts for refined products		(1,290	)
Futures contracts for natural gas		(32	)
Total	$	(1,751	)

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The gains and losses recognized in income for ineffectiveness and the time value component on our derivative instruments that are designated as fair value hedging instruments were as follows for the periods indicated (in thousands):

		Three Months Ended June 30,			Six Months Ended June 30,
	Location	2011			2011
Fair value hedge ineffectiveness (excluding time value)	Cost of product sales and natural gas storage services	$	(4,253	)	$	(204	)
Time value excluded from hedge assessment	Cost of product sales and natural gas storage services		2,186			(8,344	)
Net impact on income		$	(2,067	)	$	(8,548	)

Our hedged inventory portfolio extends to the fourth quarter of 2011. The majority of the unrealized gain at June 30, 2011 for inventory hedges represented by future contracts will be realized by the fourth quarter of 2011 as the inventory is sold. At June 30, 2011, open refined petroleum product derivative contracts varied in duration in the overall portfolio, but did not extend beyond June 2012. In addition, at June 30, 2011, we had refined petroleum product inventories that we intend to use to satisfy a portion of the physical derivative contracts.

Based on a hypothetical 10% movement in the underlying quoted market prices of the commodity financial instruments outstanding at June 30, 2011, the estimated fair value of the portfolio of commodity financial instruments would be as follows (in thousands):

Scenario	Resulting Classification	Commodity Financial Instrument Portfolio Fair Value
Fair value assuming no change in underlying commodity prices (as is)	Liability	$	(1,751	)
Fair value assuming 10% increase in underlying commodity prices	Liability	$	(30,373	)
Fair value assuming 10% decrease in underlying commodity prices	Asset	$	26,872

The value of the open futures contract positions noted above were based upon quoted market prices obtained from NYMEX. The value of the physical derivative contracts was based on observable market data related to the obligation to provide refined petroleum products to customers.

As discussed above, these commodity financial instruments are used primarily to manage the risk of market price volatility on the Energy Services segment’s refined petroleum product inventories and its physical derivative contracts. The derivative contracts used to hedge refined petroleum product inventories are classified as fair value hedges and are, therefore, expected to be highly effective in offsetting changes in the fair value of the refined petroleum product inventories.

Interest Rate Risk

We utilize 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 our cost of capital associated with such borrowings. When entering into interest rate swap transactions, we become exposed to both credit risk

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and market risk. We are 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. We are subject to market risk with respect to changes in the underlying benchmark interest rate that impact the fair value of the swaps. We manage our credit risk by only entering into swap transactions with major financial institutions with investment-grade credit ratings. We manage our 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.

Our 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 us to enter into certain short-term interest rate hedge agreements to manage our interest rate and cash flow risks associated with the Credit Facility. In addition, in July 2009 and May 2010, Buckeye GP’s board of directors authorized us to enter into certain transactions, such as forward starting interest rate swaps, to manage our interest rate and cash flow risks related to certain expected debt issuances associated with the maturity of existing debt obligations.

At June 30, 2011, we had total fixed-rate debt obligations at face value of $2,075.0 million, consisting of $300.0 million of the 4.625% Notes, $275.0 million of the 5.300% Notes, $125.0 million of the 5.125% Notes, $300.0 million of the 6.050% Notes, $275.0 million of the 5.500% Notes, $650.0 million of the 4.875% Notes and $150.0 million of the 6.750% Notes. The fair value of these fixed-rate debt obligations at June 30, 2011 was approximately $2,199.0 million. We estimate that a 1% decrease in rates for obligations of similar maturities would increase the fair value of our fixed-rate debt obligations by approximately $132.3 million.

At June 30, 2011, our variable-rate obligations were $120.0 million under the Credit Facility and $267.2 million under the BES Credit Agreement. Based on the balances outstanding at June 30, 2011, we estimate that a 1% increase or decrease in interest rates would increase or decrease annual interest expense by approximately $3.9 million.

We expect 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. We have entered into six forward-starting interest rate swaps with a total aggregate notional amount of $300.0 million related to the anticipated issuance of debt on or before July 15, 2013 and six forward-starting interest rate swaps with a total aggregate notional amount of $275.0 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. During the three months ended June 30, 2011, unrealized losses of $13.8 million were recorded in accumulated other comprehensive income (loss) to reflect the change in the fair values of the forward-starting interest rate swaps. During the six months ended June 30, 2011, unrealized losses of $9.3 million were recorded in accumulated other comprehensive income (loss) to reflect the change in the fair values of the forward-starting interest rate swaps. We designated the swap agreements as cash flow hedges at inception and expect the changes in values to be highly correlated with the changes in value of the underlying borrowings.

On January 13, 2011, we issued the 4.875% Notes in an underwritten public offering. In December 2010, in connection with the proposed offering, we entered into a treasury lock agreement to fix the ten-year treasury rate at 3.3375% per annum on a notional amount of $650.0 million. In January 2011, we subsequently cash-settled the treasury lock agreement upon the issuance of the 4.875% Notes and received approximately $0.5 million, which is being recognized as a reduction to interest and debt expense over the ten-year term of the 4.875% Notes.

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The following table presents the effect of hypothetical price movements on the estimated fair value of our interest rate swap portfolio and the related change in fair value of the underlying debt at June 30, 2011 (in thousands):

Scenario	Resulting Classification	Financial Instrument Portfolio Fair Value
Fair value assuming no change in underlying interest rates (as is)	Liability	$	(5,918	)
Fair value assuming 10% increase in underlying interest rates	Asset	$	14,629
Fair value assuming 10% decrease in underlying interest rates	Liability	$	(27,788	)

Item 4. Controls and Procedures

(a) Evaluation of Disclosure Controls and Procedures.

Our management, with the participation of our Chief Executive Officer (the “CEO”) and Chief Financial Officer (the “CFO”), evaluated the design and effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the CEO and CFO concluded that our disclosure controls and procedures as of the end of the period covered by this report are designed and operating effectively to provide reasonable assurance that the information required to be disclosed by us in reports filed under the Securities Exchange Act of 1934, as amended, is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (ii) accumulated and communicated to management, including the CEO and CFO, as appropriate to allow timely decisions regarding disclosure. A controls system cannot provide absolute assurance, however, that the objectives of the controls system are met, and no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a company have been detected.

(b) Change in Internal Control Over Financial Reporting.

There have been no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) or in other factors during the second quarter of 2011 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

We closed the BORCO acquisitions on January 18, 2011 and February 16, 2011, and have begun the evaluation of the internal control structure of BORCO. We expect that evaluation to continue during the remainder of 2011. In recording the BORCO acquisitions, we followed our normal accounting procedures and internal controls. Our management also reviewed the operations of BORCO that are included in our earnings for the three and six months ended June 30, 2011.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For information on legal proceedings, see Part 1, Item 1, Financial Statements, Note 3, “Commitments and Contingencies” in the Notes to Unaudited Condensed Consolidated Financial Statements included in this quarterly report, which is incorporated into this item by reference.

Item 1A. Risk Factors

Security holders and potential investors in our securities should carefully consider the risk factors set forth in Part 1, “Item 1A. Risk Factors” of our Annual Report on Form 10-K/A for the year ended December 31, 2010 in

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addition to other information in such report and in this quarterly report. We have identified these risk factors as important 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.

Item 6. Exhibits

(a) Exhibits

3.1	Amended and Restated Certificate of Limited Partnership of Buckeye Partners, L.P., dated as of February 4, 1998 (Incorporated by reference to Exhibit 3.2 of Buckeye Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 1997).
3.2	Certificate of Amendment to Amended and Restated Certificate of Limited Partnership of Buckeye Partners, L.P., dated as of April 26, 2002 (Incorporated by reference to Exhibit 3.2 of Buckeye Partners, L.P.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2002).
3.3	Certificate of Amendment to Amended and Restated Certificate of Limited Partnership of Buckeye Partners, L.P., dated as of June 1, 2004, effective as of June 3, 2004 (Incorporated by reference to Exhibit 3.3 of the Buckeye Partners, L.P.’s Registration Statement on Form S-3 filed June 16, 2004).
3.4	Certificate of Amendment to Amended and Restated Certificate of Limited Partnership of Buckeye Partners, L.P., dated as of December 15, 2004 (Incorporated by reference to Exhibit 3.5 of Buckeye Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2004).
3.5	Amended and Restated Agreement of Limited Partnership of Buckeye Partners, L.P., dated as of November 19, 2010 (Incorporated by reference to Exhibit 3.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed November 22, 2010).
3.6	Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Buckeye Partners, L.P., dated as of January 18, 2011 (Incorporated by reference to Exhibit 3.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on January 20, 2011).
4.1	Indenture dated as of July 10, 2003, between Buckeye Partners, L.P. and SunTrust Bank, as Trustee (Incorporated by reference to Exhibit 4.1 of Buckeye Partners, L.P.’s Registration Statement on Form S-4 filed September 19, 2003).
4.2	First Supplemental Indenture dated as of July 10, 2003, between Buckeye Partners, L.P. and SunTrust Bank, as Trustee (Incorporated by reference to Exhibit 4.2 of Buckeye Partners, L.P.’s Registration Statement on Form S-4 filed September 19, 2003).
4.3	Second Supplemental Indenture dated as of August 19, 2003, between Buckeye Partners, L.P. and SunTrust Bank, as Trustee (Incorporated by reference to Exhibit 4.3 of Buckeye Partners, L.P.’s Registration Statement on Form S-4 filed September 19, 2003).
4.4	Third Supplemental Indenture dated as of October 12, 2004, between Buckeye Partners, L.P. and SunTrust Bank, as Trustee (Incorporated by reference to Exhibit 4.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on October 14, 2004).
4.5	Fourth Supplemental Indenture dated as of June 30, 2005, between Buckeye Partners, L.P. and SunTrust Bank, as Trustee (Incorporated by reference to Exhibit 4.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on June 30, 2005).
4.6	Fifth Supplemental Indenture dated as of January 11, 2008, between Buckeye Partners, L.P. and U.S. Bank National Association (successor to SunTrust Bank), as Trustee (Incorporated by reference to Exhibit 4.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on January 11, 2008).
4.7	Sixth Supplemental Indenture dated as of August 18, 2009, between Buckeye Partners, L.P. and U.S. Bank National Association (successor-in-interest to SunTrust Bank), as Trustee (Incorporated by reference to Exhibit 4.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on August 24, 2009).

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4.8	Seventh Supplemental Indenture dated as of January 13, 2011, between Buckeye Partners, L.P. and U.S. Bank National Association (successor-in-interest to SunTrust Bank), as Trustee (Incorporated by reference to Exhibit 4.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on January 20, 2011).
4.9	Registration Rights Agreement, by and among Buckeye Partners, L.P., BGH GP Holdings, LLC, ArcLight Energy Partners Fund III, L.P., ArcLight Energy Partners Fund IV, L.P., Kelso Investment Associates VIII, L.P. and KEP VI, LLC (Incorporated by reference to Exhibit 10.2 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on June 11, 2010).
4.10	Registration Rights Agreement by and among Buckeye Partners, L.P., FR XI Offshore AIV, L.P. and the other investors named therein, dated as of December 18, 2010 (Incorporated by reference to Exhibit 10.4 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on December 21, 2010).
4.11	Registration Rights Agreement by and among Buckeye Partners, L.P. and the investors named therein, dated as of December 18, 2010 (Incorporated by reference to Exhibit 10.5 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on December 21, 2010).
4.12	Registration Rights Agreement by and between Buckeye Partners, L.P. and Vopak Bahamas B.V. dated as of February 15, 2011 (Incorporated by reference to Exhibit 10.2 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on February 22, 2011).
*31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14 (a) under the Securities Exchange Act of 1934.
*31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
*32.1	Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350.
*32.2	Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350.
*101.INS	XBRL Instance Document.
*101.SCH	XBRL Taxonomy Extension Schema Document.
*101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.
*101.LAB	XBRL Taxonomy Extension Label Linkbase Document.
*101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.
*101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.

* Filed herewith.

† Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. Buckeye agrees to furnish supplementally a copy of the omitted schedules to the SEC upon request.

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SIGNATURES

Pursuant to the requirements of Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	By:	BUCKEYE PARTNERS, L.P.
		(Registrant)
	By:	Buckeye GP LLC,
		as General Partner
Date: August 8, 2011	By:	/s/ Keith E. St.Clair
		Keith E. St.Clair
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer)

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