UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended ~~June~~September 30, 2010


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

For the transition period from to

Commission file number 1-32963

Buckeye GP Holdings L.P.

(Exact name of registrant as specified in its charter)


Delaware		11-3776228

(State or other jurisdiction of		(IRS Employer
incorporation or organization)		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 þ No o

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 o No o

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


Large accelerated filer o	Accelerated filer þ	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

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

As of ~~August~~November 35, 2010, there were 27,774,016 Common Units and 525,984 Management Units outstanding.

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, 2010 and 2009 (Unaudited)		2
Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2010 and 2009 (Unaudited)		2
Condensed Consolidated Balance Sheets as of June 30, 2010 and December 31, 2009 (Unaudited)		3
Condensed Consolidated Balance Sheets as of September 30, 2010 and December 31, 2009 (Unaudited)		3
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2010 and 2009 (Unaudited)		4
Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2010 and 2009 (Unaudited)		4
Condensed Consolidated Statements of Partners’ Capital for the Six Months Ended June 30, 2010 and 2009 (Unaudited)		5
Condensed Consolidated Statements of Partners’ Capital for the Nine Months Ended September 30, 2010 and 2009 (Unaudited)		5
Notes to Unaudited Condensed Consolidated Financial Statements:
1. Organization and Basis of Presentation		6
2. Acquisition and Disposition		8
2. Acquisitions and Disposition		8
3. Commitments and Contingencies		9
4. Inventories		1011
5. Prepaid and Other Current Assets		11
6. Equity Investments		1112
7. Intangible Assets		1213
8. Other Non-Current Assets		1213
9. Accrued and Other Current Liabilities		1314
10. Debt Obligations		1314
11. Other Non-Current Liabilities		1617
12. Derivative Instruments, Hedging Activities and Fair Value Measurements		1718
13. Pensions and Other Postretirement Benefits		2324
14. Unit-Based Compensation Plans		2425
15. Related Party Transactions		2627
16. Cash Distributions		2728
17. Earnings Per Partnership Unit		2728
18. Business Segments		2729
19. Supplemental Cash Flow Information		2930
20. Subsequent Event		29
20. Subsequent Events		30
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		3031
Item 3. Quantitative and Qualitative Disclosures About Market Risk		4950
Item 4. Controls and Procedures		5253
PART II. OTHER INFORMATION
Item 1. Legal Proceedings		53
Item 1A. Risk Factors		53
Item 6. Exhibits		5754
EX-31.1
EX-31.2
EX-32.1
EX-32.2

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

BUCKEYE GP HOLDINGS L.P.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
(Unaudited)

	Three Months Ended						~~Six~~Nine Months Ended
	June 30,						June 30,
	September 30,						September 30,
	2010			2009			2010			2009
Revenues:
Product sales	$	~~501~~564,~~744~~044		$	~~201~~258,~~777~~188		$	1,~~069~~633,~~914~~958		$	~~470~~728,~~556~~744
Transportation and other services		~~165~~170,~~532~~813			~~149~~165,~~443~~256			~~328~~499,~~536~~349			~~297~~462,~~504~~760
Total revenue		~~667~~734,~~276~~857			~~351~~423,~~220~~444			12,~~398~~133,~~450~~307			~~768~~1,~~060~~191,504
Costs and expenses:
Cost of product sales and natural gas storage services		~~498~~560,~~645~~248			~~193~~258,~~440~~507			1,~~068~~628,~~382~~630			~~444~~702,~~116~~623
Operating expenses		68,~~769~~685			6866,~~842~~100			~~135~~204,~~352~~037			~~142~~208,~~742~~842
Depreciation and amortization		1415,~~669~~062			13,~~559~~138			2944,~~197~~259			2640,~~923~~061
Asset impairment expense		—			~~72,540~~—			—			72,540
General and administrative		1311,~~254~~349			109,~~158~~814			2435,~~089~~438			2030,~~193~~007
Reorganization expense		—			~~28,113~~996			—			2829,~~113~~109
Total costs and expenses		~~595~~655,~~337~~344			~~386~~348,~~652~~555			1,~~257~~912,~~020~~364			~~734~~1,~~627~~083,182
Operating income (loss)		71,939			(35,432	)		141,430			33,433
Operating income		79,513			74,889			220,943			108,322
Other income (expense):
Investment income		85140			~~142~~65			~~240~~380			~~294~~359
Interest and debt expense		(2122,~~350~~082	)		(1620,~~236~~391	)		(4365,~~006~~088	)		(3354,~~639~~030	)
Total other expense		(21,~~265~~942	)		(1620,~~094~~326	)		(4264,~~766~~708	)		(3353,~~345~~671	)
Income (loss) before earnings from equity investments		50,674			(51,526	)		98,664			88
Income before earnings from equity investments		57,571			54,563			156,235			54,651
Earnings from equity investments		23,~~764~~391			3,~~142~~807			58,~~416~~807			59,~~224~~031
Net income (loss)		53,438			(48,384	)		104,080			5,312
Net income		60,962			58,370			165,042			63,682
Less: net income (loss) attributable to noncontrolling interests		(41,931	)		58,156			(81,303	)		14,609
Less: net income attributable to noncontrolling interests		(49,021	)		(47,275	)		(130,324	)		(32,666	)
Net income attributable to Buckeye GP Holdings L.P.	$	11,~~507~~941		$	911,~~772~~095		$	2234,~~777~~718		$	1931,~~921~~016
Earnings per partnership unit:
Basic	$	0.4142		$	0.3539		$	01.8023		$	01.7010
Diluted	$	0.4142		$	0.3539		$	01.8023		$	01.7010
Weighted average number of common units outstanding:
Basic		28,300			28,300			28,300			28,300
Diluted		28,300			28,300			28,300			28,300

See Notes to Unaudited Condensed Consolidated Financial Statements.

BUCKEYE GP HOLDINGS L.P. CONDENSED CONSOLIDATED BALANCE SHEETS (In thousands, except unit amounts) (Unaudited)

CONDENSED CONSOLIDATED BALANCE SHEETS


	September 30,		December 31,
	2010		2009
Assets:
Current assets:
Cash and cash equivalents	$	15,922	$	37,574
Trade receivables, net		133,695		124,165
Construction and pipeline relocation receivables		8,844		14,095
Inventories		267,724		310,214
Derivative assets		2,600		4,959
Assets held for sale		—		22,000
Prepaid and other current assets		74,484		104,251

Total current assets		503,269		617,258

Property, plant and equipment, net		2,248,866		2,238,321
Equity investments		108,143		96,851
Goodwill		432,124		432,124
Intangible assets, net		41,817		45,157
Other non-current assets		37,732		56,860

Total assets	$	3,371,951	$	3,486,571


Liabilities and partners’ capital:
Current liabilities:
Line of credit	$	211,800	$	239,800
Current portion of long-term debt		3,059		6,178
Accounts payable		56,346		56,723
Derivative liabilities		10,978		14,665
Accrued and other current liabilities		115,489		113,474

Total current liabilities		397,672		430,840

Long-term debt		1,441,287		1,500,495
Long-term derivative liabilities		40,910		—
Other non-current liabilities		109,521		102,942

Total liabilities		1,989,390		2,034,277


Commitments and contingent liabilities		—		—

Partners’ capital:
Buckeye GP Holdings L.P. capital:
General Partner (2,830 common units outstanding as of September 30, 2010 and December 31, 2009)		7		7
Limited Partners (27,771,186 common units outstanding as of September 30, 2010 and December 31, 2009)		232,985		236,545
Management (525,984 units outstanding as of September 30, 2010 and December 31, 2009)		3,157		3,225
Equity gains on issuance of Buckeye Partners, L.P. limited partner units		2,557		2,557

Total Buckeye GP Holdings L.P. capital		238,706		242,334
Noncontrolling interests		1,143,855		1,209,960

Total partners’ capital		1,382,561		1,452,294

Total liabilities and partners’ capital	$	3,371,951	$	3,486,571

(In thousands, except unit amounts)

(Unaudited)

	June 30,		December 31,
	2010		2009
Assets:
Current assets:
Cash and cash equivalents	$	15,497	$	37,574
Trade receivables, net		113,576		124,165
Construction and pipeline relocation receivables		11,626		14,095
Inventories		275,174		310,214
Derivative assets		10,093		4,959
Assets held for sale		—		22,000
Prepaid and other current assets		68,574		104,251
Total current assets		494,540		617,258
Property, plant and equipment, net		2,237,598		2,238,321
Equity investments		98,568		96,851
Goodwill		432,124		432,124
Intangible assets, net		42,931		45,157
Other non-current assets		38,118		56,860
Total assets	$	3,343,879	$	3,486,571
Liabilities and partners’ capital:
Current liabilities:
Line of credit	$	194,179	$	239,800
Current portion of long-term debt		4,599		6,178
Accounts payable		64,352		56,723
Derivative liabilities		367		14,665
Accrued and other current liabilities		127,091		113,474
Total current liabilities		390,588		430,840
Long-term debt		1,421,181		1,500,495
Other non-current liabilities		128,280		102,942
Total liabilities		1,940,049		2,034,277
Commitments and contingent liabilities		—		—
Partners’ capital:
Buckeye GP Holdings L.P. capital:
General Partner (2,830 common units outstanding as of June 30, 2010 and December 31, 2009)		7		7
Limited Partners (27,771,186 common units outstanding as of June 30, 2010 and December 31, 2009)		234,257		236,545
Management (525,984 units outstanding as of June 30, 2010 and December 31, 2009)		3,182		3,225
Equity gains on issuance of Buckeye Partners, L.P. limited partner units		2,557		2,557
Total Buckeye GP Holdings L.P. capital		240,003		242,334
Noncontrolling interests		1,163,827		1,209,960
Total partners’ capital		1,403,830		1,452,294
Total liabilities and partners’ capital	$	3,343,879	$	3,486,571

See Notes to Unaudited Condensed Consolidated Financial Statements.

BUCKEYE GP HOLDINGS L.P. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands) (Unaudited)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Nine Months Ended
	September 30,
	2010			2009
Cash flows from operating activities:
Net income	$	165,042		$	63,682

Adjustments to reconcile net income to cash provided by operating activities:
Value of ESOP shares released		3,480			768
Depreciation and amortization		44,259			40,061
Asset impairment expense		—			72,540
Net changes in fair value of derivatives		(16,152	)		(5,632	)
Non-cash deferred lease expense		3,176			3,375
Earnings from equity investments of Buckeye Partners, L.P.		(8,807	)		(9,031	)
Distributions from equity investments of Buckeye Partners, L.P.		11,027			4,281
Amortization of other non-cash items		7,552			4,765
Change in assets and liabilities:
Trade receivables		(9,530	)		(8,428	)
Construction and pipeline relocation receivables		5,251			9,394
Inventories		56,657			(90,579	)
Prepaid and other current assets		31,289			(19,804	)
Accounts payable		(377	)		(2,308	)
Accrued and other current liabilities		(2,367	)		8,196
Other non-current assets		3,059			(21,069	)
Other non-current liabilities		2,548			14,469

Total adjustments from operating activities		131,065			998

Net cash provided by operating activities		296,107			64,680


Cash flows from investing activities:
Capital expenditures		(49,275	)		(58,803	)
Acquisition of additional interest in equity investment		(13,512	)		—
Contributions to equity investments		—			(3,870	)
Acquisitions		(1,269	)		(10	)
Net proceeds from disposal of property, plant and equipment		22,448			1,248

Net cash used in investing activities		(41,608	)		(61,435	)


Cash flows from financing activities:
Net proceeds from issuance of Buckeye Partners, L.P. limited partner units		—			104,633
Proceeds from exercise of Buckeye Partners, L.P. unit options		4,275			1,901
Issuance of long-term debt		—			273,210
Repayment of long-term debt		(4,644	)		(4,730	)
Borrowings under credit facility		175,900			160,720
Repayments under credit facility		(233,900	)		(458,987	)
Net (repayments) borrowings under BES credit agreement		(28,000	)		53,600
Debt issuance costs		(3,245	)		(2,138	)
Costs associated with agreement and plan of merger		(4,514	)		—
Distributions paid to noncontrolling partners of Buckeye Partners, L.P.		(145,516	)		(133,104	)
Distributions paid to partners		(36,507	)		(29,716	)

Net cash used in financing activities		(276,151	)		(34,611	)

Net decrease in cash and cash equivalents		(21,652	)		(31,366	)
Cash and cash equivalents — Beginning of period		37,574			61,281

Cash and cash equivalents — End of period	$	15,922		$	29,915

(In thousands)

(Unaudited)

	Six Months Ended
	June 30,
	2010			2009
Cash flows from operating activities:
Net income	$	104,080		$	5,312
Adjustments to reconcile net income to cash provided by operating activities:
Value of ESOP shares released		2,271			380
Depreciation and amortization		29,197			26,923
Asset impairment expense		—			72,540
Net changes in fair value of derivatives		(12,901	)		4,672
Non-cash deferred lease expense		2,117			2,250
Reorganization expense		—			28,113
Earnings from equity investments of Buckeye Partners, L.P.		(5,416	)		(5,224	)
Distributions from equity investments of Buckeye Partners, L.P.		3,700			2,827
Amortization of other non-cash items		5,060			3,170
Change in assets and liabilities:
Trade receivables		10,589			(2,832	)
Construction and pipeline relocation receivables		2,469			4,855
Inventories		28,065			(27,742	)
Prepaid and other current assets		36,962			(17,692	)
Accounts payable		7,629			5,236
Accrued and other current liabilities		11,058			(5,506	)
Other non-current assets		3,370			(7,069	)
Other non-current liabilities		3,701			9,424
Total adjustments from operating activities		127,871			94,325
Net cash provided by operating activities		231,951			99,637
Cash flows from investing activities:
Capital expenditures		(27,572	)		(39,819	)
Contributions to equity investments		—			(3,880	)
Net proceeds from disposal of property, plant and equipment		22,274			21
Net cash used in investing activities		(5,298	)		(43,678	)
Cash flows from financing activities:
Net proceeds from issuance of Buckeye Partners, L.P. limited partner units		—			104,779
Proceeds from exercise of Buckeye Partners, L.P. unit options		2,976			38
Repayment of long-term debt		(3,104	)		(3,162	)
Borrowings under credit facility		95,000			77,333
Repayments under credit facility		(173,000	)		(166,600	)
Net (repayments) borrowings under BES credit agreement		(45,621	)		3,000
Debt issuance costs		(3,227	)		(18	)
Costs associated with agreement and plan of merger		(1,547	)		—
Distributions paid to noncontrolling partners of Buckeye Partners, L.P.		(96,435	)		(87,064	)
Distributions paid to partners		(23,772	)		(19,244	)
Net cash used in financing activities		(248,730	)		(90,938	)
Net decrease in cash and cash equivalents		(22,077	)		(34,979	)
Cash and cash equivalents — Beginning of period		37,574			61,281
Cash and cash equivalents — End of period	$	15,497		$	26,302

See Notes to Unaudited Condensed Consolidated Financial Statements.

BUCKEYE GP HOLDINGS L.P. CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL (In thousands) (Unaudited)

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL


	Buckeye GP Holdings L.P. Unitholders
									Equity Gains
	General		Limited						on Issuance
	Partner		Partner						of Buckeye’s
	Common		Common			Management			Limited		Noncontrolling
	Units		Units			Units			Partner Units		Interests			Total
Balance – January 1, 2009	$	7	$	226,565		$	3,037		$	2,451	$	1,166,774		$	1,398,834
Net income*		—		30,434			582			—		32,666			63,682
Distributions paid to partners		—		(29,159	)		(557	)		—		—			(29,716	)
Recognition of unit-based compensation charges		—		972			18			—		—			990
Equity gains on issuance of Buckeye’s limited partner units		—		—			—			106		(106	)		—
Net proceeds from issuance of 3.0 million of Buckeye’s limited partner units		—		—			—			—		104,633			104,633
Amortization of Buckeye’s unit-based compensation awards		—		—			—			—		1,210			1,210
Exercise of limited partner unit options		—		—			—			—		1,901			1,901
Services Company’s non-cash ESOP distributions		—		—			—			—		(4,740	)		(4,740	)
Distributions paid to noncontrolling interests		—		—			—			—		(133,104	)		(133,104	)
Adjustment to funded status of benefit plans		—		—			—			—		6,400			6,400
Other		—		—			—			—		3,261			3,261

Balance – September 30, 2009	$	7	$	228,812		$	3,080		$	2,557	$	1,178,895		$	1,413,351


Balance – January 1, 2010	$	7	$	236,545		$	3,225		$	2,557	$	1,209,960		$	1,452,294
Net income*		—		34,068			650			—		130,324			165,042
Costs associated with agreement and plan of merger				(2,746	)		(52	)				(4,129	)		(6,927	)
Distributions paid to partners		—		(35,823	)		(684	)		—		—			(36,507	)
Recognition of unit-based compensation charges		—		941			18			—		—			959
Amortization of Buckeye’s unit-based compensation awards		—		—			—			—		5,159			5,159
Exercise of limited partner unit options		—		—			—			—		4,275			4,275
Services Company’s non-cash ESOP distributions		—		—			—			—		(2,639	)		(2,639	)
Distributions paid to noncontrolling interests		—		—			—			—		(145,516	)		(145,516	)
Change in value of derivatives		—		—			—			—		(58,772	)		(58,772	)
Investment in Buckeye’s limited partner units		—		—			—			—		4,503			4,503
Other		—		—			—			—		690			690

Balance — September 30, 2010	$	7	$	232,985		$	3,157		$	2,557	$	1,143,855		$	1,382,561

(In thousands)

(Unaudited)

	Buckeye GP Holdings L.P. Unitholders
									Equity Gains
	General		Limited						on Issuance
	Partner		Partner						of Buckeye’s
	Common		Common			Management			Limited		Noncontrolling
	Units		Units			Units			Partner Units		Interests			Total
Balance – January 1, 2009	$	7	$	226,565		$	3,037		$	2,451	$	1,166,774		$	1,398,834
Net income*		—		19,547			374			—		(14,609	)		5,312
Distributions paid to partners		—		(18,883	)		(361	)		—		—			(19,244	)
Recognition of unit-based compensation charges		—		718			16			—		—			734
Equity gains on issuance of Buckeye’s limited partner units		—		—			—			106		(106	)		—
Net proceeds from issuance of 3.0 million of Buckeye’s limited partner units		—		—			—			—		104,779			104,779
Amortization of Buckeye’s limited partner unit options		—		—			—			—		477			477
Exercise of limited partner unit options		—		—			—			—		38			38
Services Company’s non-cash ESOP distributions		—		—			—			—		(3,122	)		(3,122	)
Distributions paid to noncontrolling interests		—		—			—			—		(87,064	)		(87,064	)
Adjustment to funded status of benefit plans		—		—			—			—		7,971			7,971
Other		—		—			—			—		4,166			4,166
Balance – June 30, 2009	$	7	$	227,947		$	3,066		$	2,557	$	1,179,304		$	1,412,881
Balance – 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		—		(23,327	)		(445	)		—		—			(23,772	)
Recognition of unit-based compensation charges		—		630			12			—		—			642
Amortization of Buckeye’s limited partner unit options		—		—			—			—		3,596			3,596
Exercise of limited partner 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	)
Investment in Buckeye’s limited partner units		—		—			—			—		4,503			4,503
Other		—		—			—			—		(991	)		(991	)
Balance – June 30, 2010	$	7	$	234,257		$	3,182		$	2,557	$	1,163,827		$	1,403,830


*		Comprehensive income equals net income.

See Notes to Unaudited Condensed Consolidated Financial Statements.

BUCKEYE GP HOLDINGS L.P. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Except for per unit amounts, or as otherwise noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands.

1. ORGANIZATION AND BASIS OF PRESENTATION

Partnership Organization

Buckeye GP Holdings L.P. is a publicly traded Delaware master limited partnership (“MLP”), the common units (“Common Units”) of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “BGH.” We were organized on June 15, 2006 and own 100% of Buckeye GP LLC (“Buckeye GP”), which is the general partner of Buckeye Partners, L.P. (“Buckeye”). Buckeye is also a publicly traded Delaware MLP which was organized in 1986, and its limited partner units (“LP Units”) are separately traded on the NYSE under the ticker symbol “BPL.” Approximately 62% of our outstanding equity, which includes Common Units and management units (“Management Units”), are owned by BGH GP Holdings, LLC (“BGH GP”) and approximately 38% by the public. BGH GP is owned by affiliates of ArcLight Capital Partners, LLC (“ArcLight”), Kelso & Company (“Kelso”), and certain investment funds along with certain members of senior management of Buckeye GP. MainLine Management LLC, a Delaware limited liability company (“MainLine Management”), is our general partner and is wholly owned by BGH GP. As used in these Notes to Unaudited Condensed Consolidated Financial Statements, unless the context requires otherwise, references to “we,” “us,” “our” or "BGH” are intended to mean the business and operations of Buckeye GP Holdings L.P. on a consolidated basis, including those of Buckeye. References to “Buckeye” mean Buckeye Partners, L.P. and its consolidated subsidiaries.

Our only business is the ownership of Buckeye GP. Buckeye GP’s only business is the management of Buckeye and its subsidiaries. At ~~June~~September 30, 2010, Buckeye GP owned an approximate 0.5% general partner interest in Buckeye.

Buckeye was formed in 1986 and owns and operates one of the largest independent refined petroleum products pipeline systems in the United States in terms of volumes delivered with approximately 5,400 miles of pipeline and 6768 active products terminals that provide aggregate storage capacity of approximately 27.23 million barrels. In addition, Buckeye operates and maintains approximately 2,400 miles of other pipelines under agreements with major oil and gas, petrochemical and chemical companies, and performs certain engineering and construction management services for third parties. Buckeye also owns and operates a major natural gas storage facility in northern California, and is a wholesale distributor of refined petroleum products in the United States in areas also served by its pipelines and terminals. We, through Buckeye, operate and report in five business segments: Pipeline Operations; Terminalling & Storage; Natural Gas Storage; Energy Services; and Development & Logistics.

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~~September 30, 2010, Services Company owned approximately 32.09% of Buckeye’s LP Units. Services Company employees provide services to Buckeye’s operating subsidiaries. Pursuant to a services agreement entered into in December 2004 (the “Services Agreement”), Buckeye’s operating subsidiaries reimburse Services Company for the costs of the services provided by Services Company.

Agreement and Plan of Merger

On ~~June~~August 1018, 2010, we and our general partner entered into ana First Amended and Restated Agreement and Plan of Merger (the “Merger Agreement”) with Buckeye, its general partner and Grand Ohio, LLC (“Merger Sub”), Buckeye’s subsidiary,. ~~pursuant~~Pursuant to ~~which~~the Merger Agreement, Merger Sub will be 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 Buckeye’s general partner will be cancelled, the general partner units held by Buckeye’s general partner (representing an approximate 0.5% general partner interest in Buckeye) will be converted to a non-economic general partner interest, all of the economic interest in us will be acquired by BPL and our unitholders will receive aggregate consideration of approximately 20.0 million of Buckeye’s LP Units.

BUCKEYE GP HOLDINGS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The ~~terms of the~~ Merger Agreement ~~were~~is ~~unanimously~~subject ~~approved~~to, byamong ~~the~~other ~~audit~~things, ~~committee~~approval ofby the ~~board~~ ofaffirmative ~~directors~~vote of ~~our general partner (“Audit Committee”), and by~~ the ~~board~~holders of ~~directors~~a majority of Buckeye’s ~~general~~LP ~~partner.~~Units ~~Additionally,~~outstanding ~~our majority unitholder, BGH GP Holdings, LLC,~~ and ~~ArcLight~~ ~~Energy~~entitled ~~Partners~~to ~~Fund~~vote ~~III,~~at ~~L.P.,~~a ~~ArcLight~~meeting ~~Energy Partners Fund IV, L.P., Kelso Investment~~of ~~Associates~~the ~~VII,~~holders ~~L.P.,~~of ~~and~~Buckeye’s ~~KEP~~LP VIUnits, ~~LLC~~approval ~~have~~by ~~executed~~the ~~a Support Agreement~~ (~~“Support Agreement”~~a) ~~agreeing~~ affirmative to vote inof ~~favor~~holders of ~~the~~a ~~Merger~~majority ~~and against any alternative transaction. The Support~~of ~~Agreement~~our ~~will~~Common ~~automatically~~Units ~~terminate~~and if(b) affirmative ~~the~~vote ~~board~~ of ~~directors~~holders of ~~our~~a ~~general~~majority ~~partner~~of ~~changes its recommendation to~~ our ~~unitholders~~Common ~~with~~Units ~~respect~~and management tounits, ~~the~~voting ~~Merger~~together oras ~~the~~a ~~Merger~~single ~~Agreement is terminated~~class.

After the Merger, the board of directors of Buckeye’s general partner is expected to consist of nine members, three of whom are expected to be the existing independent members of Buckeye’s Audit Committee, one of whom is expected to be the existing chief executive officer of Buckeye’s general partner and three of whom are expected to be the three existing independent members of the audit committee of the board of directors of our general partner. In addition, our general partner, which will own a non-economic general partner interest in us and will continue to be owned by BGH GP Holdings, LLC, will have the right and authority to designate two additional members of the board of directors, subject to reduction if BGH GP Holdings, LLC’s ownership of Buckeye’s LP Units drops below certain thresholds. The remaining seven members of Buckeye’s general partner’s board of directors will be elected by holders of its LP Units.

The Merger Agreement is subject to, among other things, approval by the affirmative vote of the holders of a majority of Buckeye’s LP Units outstanding and entitled to vote at a meeting of the holders of Buckeye’s LP Units, approval by the (a) affirmative vote of holders of a majority of our Common Units and (b) affirmative vote of holders of a majority of our Common Units and management units, voting together as a single class, and the effectiveness of a registration statement on Form S-4 with respect to the issuance of Buckeye’s LP Units in connection with the Merger.

The Merger will be accounted for as an equity transaction. Therefore, changes in our ownership interest as a result of the Merger will not result in gain or loss recognition. We will be considered the surviving consolidated entity for accounting purposes, while Buckeye will be the surviving consolidated entity for legal and reporting purposes.

We ~~and Buckeye~~ incurred a total of $32.8 million of costs associated with the Merger during the nine months ~~three~~ended ~~and~~September 30, ~~six~~2010, of which $1.3 million has been paid. Together with Buckeye, the aggregate costs associated with the Merger incurred during the nine months ended ~~June~~September 30, 2010 were $6.9 million, of which $14.5 million has been paid. We charged these costs directly to partners’ capital.

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements reflect all adjustments that are, in the opinion of our management, of a normal and recurring nature and necessary for a fair statement of our financial position as of ~~June~~September 30, 2010, and the results of our operations and cash flows for the periods presented. The results of operations for the three and nine ~~six~~ months ended ~~June~~ September 30, 2010 are not necessarily indicative of results of our operations for the 2010 fiscal year. The unaudited condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). We have eliminated all intercompany transactions in consolidation. The consolidated financial statements also include the accounts of wholly-owned subsidiaries, as well as the accounts of Buckeye and Services Company, on a consolidated basis. Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted pursuant to those rules and regulations. These interim financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our Annual Report on Form 10-K for the year ended December 31, 2009, as filed with the SEC on March 2, 2010.

BUCKEYE GP HOLDINGS L.P. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Reclassifications

Certain prior year amounts have been reclassified in the condensed consolidated statements of cash flows to conform to the current-year presentation. The reclassification in the condensed consolidated statements of cash flows is as follows:

• We have separately disclosed cash flows from the issuance of long-term debt and borrowings under our credit facilities for the ~~six~~nine months ended ~~June~~September 30, 2009. These amounts had been included within the same line item in the 2009 period.

This reclassification had no impact on net income ~~(loss)~~ or cash flows from operating, investing or financing activities.

Recent Accounting Developments

Consolidation of Variable Interest Entities (“VIEs”). In June 2009, the Financial Accounting Standards Board (“FASB”) amended consolidation guidance for VIEs. The objective of this new guidance is to improve financial reporting by companies involved with VIEs. This guidance requires each reporting company to perform an analysis to determine whether the company’s variable interest or interests give it a controlling financial interest in a VIE. The new guidance was effective for us on January 1, 2010. The adoption of this guidance did not have an impact on our consolidated financial statements.

BUCKEYE GP HOLDINGS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Fair Value Measurements. In January 2010, the FASB issued guidance that requires new disclosures related to fair value measurements. The new guidance requires expanded disclosures related to transfers between Level 1 and 2 activities and a gross presentation for Level 3 activity. The new accounting guidance is effective for fiscal years and interim periods beginning after December 15, 2009, except for the new disclosures related to Level 3 activities, which are 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, 2010, except for the new disclosures related to Level 3 activities, which will be effective for us on January 1, 2011. We have included the enhanced disclosure requirements regarding fair value measurements in Note 12.

2. ~~ACQUISITION~~ACQUISITIONS AND DISPOSITION

Refined Petroleum Products Terminals and Pipeline Assets Acquisition

On November 18, 2009, we acquired from ConocoPhillips certain refined petroleum product terminals and pipeline assets for approximately $47.1 million in cash. In addition, we acquired certain inventory on hand upon completion of the transaction for additional consideration of $7.3 million. The assets include over 300 miles of active pipeline that provide connectivity between the East St. Louis, Illinois and East Chicago, Indiana markets and three terminals providing 2.3 million barrels of storage tankage. ConocoPhillips entered into certain commercial contracts with us concurrent with our acquisition regarding usage of the acquired facilities. We believe the acquisition of these assets has given us greater access to markets and refinery operations in the Midwest and increased the commercial value of these assets and certain of our existing assets to our customers by offering enhanced distribution connectivity and flexible storage capabilities. The operations of these acquired assets are reported in the Pipeline Operations and Terminalling & Storage segments. The purchase price has been allocated to the tangible and intangible assets acquired, as follows (in thousands):


Inventory	$	7,287
Property, plant and equipment		44,400
Intangible assets		4,580
Environmental and other liabilities		(1,834	)

Allocated purchase price	$	54,433

Acquisition of Additional Interest in West Shore Pipe Line Company

On August 2, 2010, in connection with our exercise of a right of first refusal, we completed the acquisition of additional shares of West Shore Pipe Line Company (“West Shore”) common stock from an affiliate of BP plc, resulting in an increase in our ownership interest in West Shore from 24.9% to 34.6%. We paid approximately $13.5 million for this additional interest. We exercised our right of first refusal to purchase the additional shares because of the favorable economics associated with the investment opportunity and our desire to increase our ownership in a successful joint venture pipeline that we currently operate.

Acquisition of Other Pipeline Assets

In August 2010, we acquired pipeline assets in western Pennsylvania for $1.3 million. These assets have been included in the Pipeline Operations segment.

Sale of Buckeye NGL Pipeline

Effective January 1, 2010, we sold our ownership interest in an approximately 350-mile natural gas liquids pipeline (the “Buckeye NGL Pipeline”) that runs from Wattenberg, Colorado to Bushton, Kansas for $22.0 million. The assets had been classified as “Assets held for sale” in our consolidated balance sheet at December 31, 2009 with a carrying amount equal to the proceeds received. Revenues for Buckeye NGL Pipeline for the three and nine months ended September 30, 2009 were $1.7 million and $8.2 million, respectively.

BUCKEYE GP HOLDINGS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Sale of Buckeye NGL Pipeline

Effective January 1, 2010, we sold our ownership interest in an approximately 350-mile natural gas liquids pipeline (the “Buckeye NGL Pipeline”) that runs from Wattenberg, Colorado to Bushton, Kansas for $22.0 million. The assets had been classified as “Assets held for sale” in our consolidated balance sheet at December 31, 2009 with a carrying amount equal to the proceeds received. Revenues for Buckeye NGL Pipeline for the three and six months ended June 30, 2009 were $3.2 million and $6.5 million, respectively.

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 April 2010, the Pipeline Hazardous Materials Safety Administration (“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~~August 3024, 2010, athe ~~putative~~District ~~class~~Court ~~action~~of ~~was~~Harris County, Texas, entered an order consolidating three previously filed byputative aclass ~~unitholder~~actions ~~against~~(Broadbased ~~BGH~~Equities v. Forrest E. Wylie, ~~MainLine~~et. al., ~~Management~~Henry James Steward v. Forrest E. Wylie, ~~BGH~~et. GPal., and JR Garrett Trust v. Buckeye GP Holdings L.P., et al., each of ~~MainLine~~which ~~Management’s~~were ~~directors~~previously described in ~~the~~our ~~District~~Quarterly ~~Court~~Report ofon ~~Harris~~Form 10-Q for the ~~County~~quarter ended June 30, ~~Texas~~2010) under the caption of Broadbased Equities v. Forrest E. Wylie, et. al. and Inappointing ~~the~~interim ~~Petition,~~co-lead class counsel and interim co-liaison counsel. The plaintiffs ~~the~~subsequently ~~plaintiff~~filed ~~alleges~~a ~~that~~consolidated ~~MainLine~~amended ~~Management~~class action and ~~its~~derivative ~~directors~~complaint ~~breached~~on ~~their~~September 1, 2010 ~~fiduciary~~(the ~~duties~~“Complaint”). The Complaint purports to ~~BGH’s~~ ~~public~~be ~~unitholders~~a ~~by,~~putative ~~among~~class ~~other~~and ~~things,~~derivative ~~acting~~action alleging tothat ~~facilitate~~MainLine ~~the~~Management ~~sale~~and ofits ~~BGH~~directors tobreached ~~Buckeye~~their ~~in order~~fiduciary duties to ~~facilitate~~our ~~the~~public unitholders ~~gradual~~in ~~sale~~connection bywith ~~BGH~~the GPMerger ofby, ~~its~~among ~~interest~~other inthings, ~~BGH~~accepting insufficient consideration and failing to disclose all material facts in order that ~~the~~our ~~BGH~~ unitholders ~~can~~may cast an informed vote on the Merger Agreement~~. Among other things~~, ~~the~~and ~~Petition~~that ~~seeks~~Buckeye, anBuckeye ~~order~~GP, ~~certifying~~MainLine aManagement, ~~class consisting of all BGH~~Merger ~~unitholders~~Sub, aBGH ~~determination that the action is a proper derivative action~~GP, ~~damages~~ArcLight ~~in an unspecified amount,~~ and anKelso ~~award~~aided ~~of attorneys’ fees~~ and ~~costs.~~abetted ~~The~~the ~~defendants~~breaches ~~have~~of ~~not~~fiduciary ~~yet answered or otherwise responded to the Petition~~duty.

On ~~August~~October 229, 2010, athe ~~putative~~parties ~~class~~to ~~action~~the ~~was~~litigation ~~filed~~entered byinto a ~~unitholder~~Memorandum ~~against~~of ~~BGH, MainLine~~Understanding ~~Management,~~(“MOU”) ~~Grand~~in ~~Ohio,~~connection ~~LLC,~~with ~~Buckeye,~~a ~~Buckeye~~proposed ~~GP,~~settlement ~~and each~~ of ~~MainLine Management’s directors in~~ the ~~District~~class ~~Court~~action ofand ~~Harris County, Texas under~~ the ~~caption Henry James Steward v~~Complaint. ~~Forrest~~The E.MOU ~~Wylie,~~provides ~~et.~~for ~~al.~~dismissal Inwith ~~the~~prejudice ~~Petition,~~of the ~~plaintiff~~litigation ~~alleges~~and ~~that~~a ~~MainLine~~release ~~Management~~of ~~and~~the ~~its~~defendants ~~directors~~from all ~~breached~~present ~~their~~and ~~fiduciary~~future ~~duties~~claims toasserted ~~BGH’s~~in ~~public~~the ~~unitholders~~litigation byin exchange for, among other things, ~~failing to~~the ~~disclose~~agreement ~~all~~of ~~material~~the ~~facts~~defendants into ~~order~~amend ~~that~~ the ~~BGH~~Merger ~~unitholders~~Agreement ~~can~~to ~~cast~~reduce anthe ~~informed~~termination ~~vote~~fees onpayable ~~the~~by ~~Merger~~us ~~Agreement.~~upon ~~The~~termination ~~Petition~~of ~~also~~the ~~alleges~~Merger ~~that~~Agreement ~~Buckeye, Buckeye GP~~ and ~~Grand~~to ~~Ohio,~~provide ~~LLC~~our ~~aided~~unitholders ~~and~~with supplemental ~~abetted~~disclosure ~~the~~to ~~breaches~~Buckeye’s ofand ~~fiduciary~~our ~~duty.~~joint ~~Among~~proxy ~~other things~~statement/prospectus, ~~the~~dated ~~Petition~~September 24, ~~seeks~~2010. ~~an order certifying~~The asupplemental ~~plaintiff~~disclosure ~~class~~is ~~consisting~~set offorth ~~all~~in ofa ~~BGH~~joint ~~unitholders,~~proxy anstatement/prospectus ~~order enjoining the Merger~~supplement, ~~rescission~~dated ~~of the Merger~~October 29, ~~damages in an unspecified amount~~2010, ~~and~~that anwas ~~award~~filed ofwith ~~attorneys’ fees and costs. Neither we nor~~ the ~~other~~SEC ~~defendants~~on ~~have~~November 1, ~~yet answered or otherwise responded to the Petition~~2010.

OnIn ~~August 2~~addition, ~~2010,~~the aMOU ~~putative~~provides ~~class action was filed by a unitholder against BGH~~that, ~~MainLine Management,~~in ~~BGH~~settlement ~~GP,~~of ~~ArcLight,~~the ~~Kelso,~~plaintiffs’ ~~Buckeye,~~claims ~~Buckeye~~(including ~~GP and each of MainLine Management’s~~any ~~directors,~~claim inagainst the ~~District~~defendants ~~Court~~by ~~of Harris County, Texas under~~ the ~~caption~~plaintiffs’ ~~Henry~~counsel ~~James~~for ~~Steward~~attorneys’ ~~v. Forrest~~fees E.or ~~Wylie,~~expenses ~~et.~~related ~~al. In~~ to the ~~Petition~~litigation), the ~~plaintiff~~defendants ~~alleges~~(or ~~that MainLine Management and its directors breached~~ their ~~fiduciary~~insurers) ~~duties~~will topay ~~BGH’s~~a ~~public~~cash ~~unitholders~~payment ~~by,~~of ~~among other things~~$900, ~~accepting insufficient consideration~~000, ~~failing~~subject to final ~~condition~~court ~~the~~approval ~~Merger~~of onthe asettlement. ~~majority~~The ~~vote~~proposed ofsettlement ~~public unitholders~~is ofsubject ~~BGH, and failing~~ to ~~disclose~~further ~~all material facts in order that the BGH unitholders~~definitive ~~can~~documentation ~~cast~~and anto ~~informed~~a ~~vote~~number onof ~~the Merger Agreement. The Petition also alleges that Buckeye~~conditions, ~~Buckeye GP~~including, ~~BGH~~without GPlimitation, ~~ArcLight~~completion ~~and~~of ~~Kelso~~certain confirmatory ~~aided~~discovery ~~and~~by ~~abetted~~ the ~~breaches of fiduciary duty. Among other things~~plaintiffs, the ~~Petition~~drafting ~~seeks~~and anexecution ~~order~~of ~~certifying~~ a ~~class~~formal ~~consisting~~Stipulation of ~~all of BGH’s unitholders~~ Settlement, ~~an order~~the ~~enjoining~~consummation of the Merger, ~~damages in an unspecified amount,~~ and ancourt ~~award~~approval of ~~attorneys’~~the ~~fees~~proposed ~~and costs~~settlement. ~~Neither~~There weis no ~~nor~~assurance ~~the~~that ~~other~~these ~~defendants~~conditions ~~have~~will ~~yet~~be ~~answered or otherwise responded to the Petition~~satisfied.

~~Environmental~~ We ~~Contingencies~~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 and finally resolve the claims alleged, we and the other defendants agreed to the proposed settlement described above.

In accordance with our accounting policy, we recorded operating expenses, net of insurance recoveries, of $2.5 million and $1.2 million during the three months ended June 30, 2010 and 2009, respectively, and $5.4 million and $6.6 million during the six months ended June 30, 2010 and 2009, respectively, related to environmental expenditures unrelated to claims and proceedings.

Ammonia Contract Contingencies

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

BUCKEYE GP HOLDINGS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~source~~Environmental of payment for the shortfalls, but has not clarified the extent to which it believes the guaranty has been exhausted. We have been working with EPME to terminate the ammonia sales contracts and ammonia supply contracts and, at no out of pocket cost to us, have terminated one of the ammonia sales contracts. Given, however, the uncertainty of future ammonia prices and EPME’s future actions, we continue to believe we have risk of loss 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 and EPME are unable to terminate the remaining contracts or otherwise mitigate the remaining risk, including potential recourse against EPME and El Paso, with respect to this matter. Contingencies

In accordance with our accounting policy, we recorded operating expenses, net of insurance recoveries, of $2.2 million and $2.2 million during the three months ended September 30, 2010 and 2009, respectively, and $7.6 million and $8.8 million during the nine months ended September 30, 2010 and 2009, respectively, related to environmental expenditures unrelated to claims and proceedings.

Ammonia Contract Contingencies

EPME has informed BGC that, notwithstanding the parties’ agreement, it will not continue to pay BGC for shortfalls created by the pass-through of ammonia costs in excess of ammonia revenues. EPME encouraged BGC to seek payment by invoking a $40.0 million guaranty made by El Paso, which guaranteed EPME’s obligations to BGC. If EPME fails to reimburse BGC for these shortfalls for a significant period during the remainder of the term of the ammonia agreements, then such unreimbursed shortfalls could exceed the $40.0 million cap on El Paso’s guaranty. To the extent the unreimbursed shortfalls significantly exceed the $40.0 million cap, the resulting costs incurred by BGC could adversely affect our financial position, results of operations and cash flows. To date, BGC has continued to receive payment for ammonia costs under the contracts at issue. BGC has not called on El Paso’s guaranty and believes only BGC may invoke the guaranty. EPME, however, contends that El Paso’s guaranty is the source of payment for the shortfalls, but has not clarified the extent to which it believes the guaranty has been exhausted. We have been working with EPME to terminate the ammonia sales contracts and ammonia supply contracts and, at no out of pocket cost to us, have terminated one of the ammonia sales contracts. Given, however, the uncertainty of future ammonia prices and EPME’s future actions, we continue to believe we have risk of loss 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 and EPME are unable to terminate the remaining contracts or otherwise mitigate the remaining risk, including potential recourse against EPME and El Paso, with respect to this matter.

Customer Bankruptcy

One of our customers filed for bankruptcy in October 2009; and approximately $4.21 million ~~remained~~ remained payable to us from the customer pursuant to a pre-bankruptcy contract. with that customer. In June 2010, we entered into a court approved settlement with the bankrupt customer and its largest creditor pursuant to which we ~~expect~~ were to be paid at least $2.0 million ~~upon~~in ~~the sale of certain of the customer’s assets within the bankruptcy proceedings~~cash, and we were released from both asserted and unasserted claims. AtIn ~~this time~~August 2010, we ~~expect~~received ~~the~~a ~~sale of the assets to be completed, and the~~ settlement payment ~~to be made to us, in the third quarter~~ of ~~2010~~$2.0 million. As a result of ~~the~~this settlement, our Development & Logistics ~~segment~~ segment recognized approximately $2.1 million in expense related to the write-off of a portion of ~~the~~ the outstanding receivable balance during the ~~three~~nine ~~and six~~ months ended ~~June~~September 30, 2010.

4. INVENTORIES

Our inventory amounts were as follows at the dates indicated:

	June 30,		December 31,
	2010		2009
Refined petroleum products (1)	$	264,638	$	299,473
Materials and supplies		10,536		10,741
Total inventories	$	275,174	$	310,214

(1) Ending inventory was 130.4 million and 141.7 million gallons of refined petroleum products at June 30, 2010 and December 31, 2009, respectively.

At June 30, 2010 and December 31, 2009, approximately 95% and 99%, respectively, of our 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.

BUCKEYE GP HOLDINGS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

4. INVENTORIES

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


	September 30,		December 31,
	2010		2009
Refined petroleum products (1)	$	257,124	$	299,473
Materials and supplies		10,600		10,741

Total inventories	$	267,724	$	310,214


(1)		Ending inventory was 115.8 million and 141.7 million gallons of refined petroleum products at September 30, 2010 and December 31, 2009, respectively.

At September 30, 2010 and December 31, 2009, approximately 93% and 99%, respectively, of our 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.

5. PREPAID AND OTHER CURRENT ASSETS

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

	June 30,		December 31,
	September 30,		December 31,
	2010		2009
Prepaid insurance	$	24,~~435~~750	$	7,088
Insurance receivables		119,~~238~~942		13,544
Ammonia receivable		1,~~690~~902		7,429
Margin deposits		711,~~921~~807		21,037
Prepaid services		2124,~~742~~830		21,571
Unbilled revenue		23,~~469~~425		13,201
Tax receivable		~~7,162~~260		7,162
Prepaid taxes		47,~~001~~197		2,213
Other		910,~~916~~371		11,006
Total prepaid and other current assets	$	6874,~~574~~484	$	104,251

6. EQUITY INVESTMENTS

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

		June 30,		December 31,
	Ownership	2010		2009
Muskegon Pipeline LLC	40.0%	$	14,514	$	15,273
Transport4, LLC	25.0%		373		379
West Shore Pipe Line Company	24.9%		30,526		30,320
West Texas LPG Pipeline Limited Partnership	20.0%		53,155		50,879
Total equity investments		$	98,568	$	96,851

The following table presents earnings from equity investments for the periods indicated:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009
Muskegon Pipeline LLC	$	227	$	173	$	571	$	538
Transport4, LLC		30		40		69		70
West Shore Pipe Line Company		1,294		1,094		2,501		2,197
West Texas LPG Pipeline Limited Partnership		1,213		1,835		2,275		2,419
Total earnings from equity investments	$	2,764	$	3,142	$	5,416	$	5,224

BUCKEYE GP HOLDINGS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~Combined~~6. ~~income~~EQUITY ~~statement data for the periods indicated for our equity method investments is summarized below:~~ INVESTMENTS

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009
Revenues	$	35,754	$	32,846	$	67,299	$	64,414
Costs and expenses		20,343		16,543		36,244		32,613
Non-operating expense		3,461		2,961		7,038		5,869
Net income		11,950		13,342		24,017		25,932


				September 30,		December 31,
	Ownership (1)			2010		2009
Muskegon Pipeline LLC		40.0	%	$	14,536	$	15,273
Transport4, LLC		25.0	%		349		379
West Shore Pipe Line Company (2)		34.6	%		43,500		30,320
West Texas LPG Pipeline Limited Partnership		20.0	%		49,758		50,879

Total equity investments				$	108,143	$	96,851


(1)		Represents ownership interest in equity investment at September 30, 2010.

(2)		See Note 2 for a discussion of the acquisition of an additional interest in West Shore.

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
Muskegon Pipeline LLC	$	488	$	385	$	1,059	$	923
Transport4, LLC		51		31		120		101
West Shore Pipe Line Company		1,229		1,204		3,730		3,401
West Texas LPG Pipeline Limited Partnership		1,623		2,187		3,898		4,606

Total earnings from equity investments	$	3,391	$	3,807	$	8,807	$	9,031

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
Revenues	$	36,546	$	36,212	$	103,845	$	100,626
Costs and expenses		19,690		17,351		55,934		49,964
Non-operating expense		3,983		3,184		11,021		9,053
Net income		12,873		15,677		36,890		41,609

BUCKEYE GP HOLDINGS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

7. INTANGIBLE ASSETS

Intangible assets consist of the following at the dates indicated (in thousands):

	June 30,			December 31,
	September 30,			December 31,
	2010			2009
Customer relationships	$	38,300		$	38,300
Accumulated amortization		(7,~~115~~858	)		(5,631	)
Net carrying amount		3130,~~185~~442			32,669
Customer contracts		16,380			16,380
Accumulated amortization		(45,~~634~~005	)		(3,892	)
Net carrying amount		11,~~746~~375			12,488
Total intangible assets	$	4241,~~931~~817		$	45,157

For the three months ended ~~June~~September 30, 2010 and 2009, amortization expense related to ~~intangible~~ intangible assets was $1.1 million and $0.9 million, respectively. For the ~~six~~nine months ended ~~June~~ September 30, 2010 and 2009, amortization expense related to intangible assets was $23.23 million and $12.87 million, respectively. Amortization expense related to intangible assets is expected to be ~~approximately~~ approximately $4.5 million for each of the next five years.

8. OTHER NON-CURRENT ASSETS

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

	June 30,		December 31,
	September 30,		December 31,
	2010		2009
Prepaid services	$	8,~~065~~051	$	11,640
Derivative assets		—		17,204
Debt issuance costs		1211,~~459~~678		11,058
Insurance receivables		7,~~530~~109		7,265
Other		10,~~064~~894		9,693
Total other non-current assets	$	3837,~~118~~732	$	56,860

1213

BUCKEYE GP HOLDINGS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

9. ACCRUED AND OTHER CURRENT LIABILITIES

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

	June 30,		December 31,
	September 30,		December 31,
	2010		2009
Taxes – other than income	$	1617,~~278~~190	$	15,487
Accrued employee benefit liability		3,287		3,287
Environmental liabilities		1110,~~549~~387		10,799
Accrued interest		3018,~~699~~429		30,613
Payable for ammonia purchase		12,~~803~~215		7,015
Deferred revenue		2019,~~306~~395		6,829
Compensation and vacation		912,~~748~~910		11,385
Accrued capital expenditures		~~425~~2,639		1,611
Reorganization		—		2,133
Deferred consideration		2,010		1,675
Other		3027,~~986~~027		22,640
Total accrued and other current liabilities	$	~~127~~115,~~091~~489	$	113,474

10. DEBT OBLIGATIONS

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

	June 30,			December 31,
	September 30,			December 31,
	2010			2009
BGH:
BGH Credit Agreement	$	—		$	—
Services Company:
3.60% ESOP Notes due March 28, 2011		43,~~634~~076			7,790
Retirement premium		(3517	)		(87	)
Buckeye:
4.625% Notes due July 15, 2013 (1)		300,000			300,000
5.300% Notes due October 15, 2014 (1)		275,000			275,000
5.125% Notes due July 1, 2017 (1)		125,000			125,000
6.050% Notes due January 15, 2018 (1)		300,000			300,000
5.500% Notes due August 15, 2019 (1)		275,000			275,000
6.750% Notes due August 15, 2033 (1)		150,000			150,000
Credit Facility		—20,000			78,000
BES Credit Agreement		~~194~~211,~~179~~800			239,800
Total debt		1,~~623~~659,~~778~~859			1,750,503
Other, including unamortized discounts and fair value hedges		(3,~~819~~713	)		(4,030	)
Subtotal debt		1,~~619~~656,~~959~~146			1,746,473
Less: Current portion of long-term debt		(~~198~~214,~~778~~859	)		(245,978	)
Total long-term debt	$	1,~~421~~441,~~181~~287		$	1,500,495


(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.

1314

BUCKEYE GP HOLDINGS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The fair values of our aggregate debt and credit facilities were estimated to be $1,~~677~~799.28 million and $1,769.8 million at ~~June~~September 30, 2010 and December 31, 2009, respectively. The fair ~~values~~ values of the fixed-rate debt were estimated by observing market trading prices and by comparing ~~the~~ 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.

BGH

We have a five-year, $10.0 million unsecured revolving credit facility with SunTrust Bank, as both administrative agent and lender (the “BGH Credit Agreement”). The BGH Credit Agreement may be used for working capital and other partnership purposes. We have pledged all of the limited liability company interests in Buckeye GP as security for our obligations under the BGH Credit Agreement. Borrowings under the BGH Credit Agreement bear interest under one of two rate options, selected by us, equal to either (i) the greater of (a) the federal funds rate plus 0.5% and (b) SunTrust Bank’s prime commercial lending rate; or (ii) the London Interbank Offered Rate (“LIBOR”), plus a margin which can range from 0.40% to 1.40%, based on the ratings assigned by Standard & Poor’s Rating Services and Moody’s Investor Service to our senior unsecured non-credit enhanced long-term debt. At ~~June~~September 30, 2010 and December 31, 2009, there were no amounts outstanding ~~under~~ under the BGH Credit Agreement.

The BGH Credit Agreement requires us to maintain leverage and funded debt coverage ratios. The leverage ratio covenant requires us to maintain, as of the last day of each fiscal quarter, a ratio of the total funded indebtedness of us and our Restricted Subsidiaries (as defined below), measured as of the last day of each fiscal quarter, to the aggregate dividends and distributions received by us and the Restricted Subsidiaries from Buckeye, plus all other cash received by us and the Restricted Subsidiaries, measured for the preceding twelve months, less expenses, of not more than 2.50 to 1.00. The BGH Credit Agreement defines “Restricted Subsidiaries” as certain of our wholly owned subsidiaries. The funded debt coverage ratio covenant requires us to maintain, as of the last day of each fiscal quarter, a ratio of us and all of our consolidated subsidiaries total consolidated funded debt to the consolidated EBITDA, as defined in the BGH Credit Agreement, of us and all of our subsidiaries, measured for the preceding twelve months, of not more than 5.25 to 1.00, subject to a provision for increases to 5.75 to 1.00 in connection with future acquisitions. At ~~June~~September 30, 2010, our funded debt coverage ratio was 4.3132 to 1.00.

The BGH Credit Agreement contains other covenants that prohibit us from taking certain actions, including but not limited to, declaring dividends or distributions if any default or event of default has occurred or would result from such a declaration and limiting our ability to incur additional indebtedness, creating negative pledges and granting certain liens, making certain loans, acquisitions, and investments, making material changes to the nature of us and our Restricted Subsidiaries’ business, and entering into a merger, consolidation, or sale of assets. At ~~June~~September 30, 2010, we were not aware of any instances of noncompliance with the covenants under ~~the~~ the BGH Credit Agreement.

Services Company ESOP Notes

Services Company had total debt outstanding of $43.61 million and $7.7 million at ~~June~~September 30, ~~2010~~ 2010 and December 31, 2009, respectively, consisting of 3.60% Senior Secured Notes (the “3.60% ESOP Notes”) due March 28, 2011 payable by the ESOP to a third-party lender. The 3.60% ESOP Notes were issued on May 4, 2004. The 3.60% ESOP Notes are collateralized by Services Company’s common stock and are guaranteed by Services Company. In addition, Buckeye has committed that, in the event that the value of Buckeye’s LP Units owned by Services Company falls below 125% of the balance payable under the 3.60% ESOP Notes, Buckeye will fund an escrow account with sufficient assets to bring the value of the total collateral (the value of Buckeye’s LP Units owned by Services Company and the escrow account) up to the 125% minimum. Amounts deposited in the escrow account are returned to Buckeye when the value of Buckeye’s LP Units owned by Services Company returns to an amount that exceeds the 125% minimum. At ~~June~~September 30, 2010, the value of Buckeye’s LP Units owned by Services Company exceeded the 125% requirement.

1415

BUCKEYE GP HOLDINGS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Credit Facility

Buckeye has a borrowing capacity of $580.0 million under an unsecured revolving credit agreement (the “Credit Facility”) with SunTrust Bank, as administrative agent, which may be expanded up to $780.0 million subject to certain conditions and upon the further approval of the lenders. The Credit Facility’s maturity date is August 24, 2012, which Buckeye 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 Buckeye, equal to either (i) the greater of (a) the federal funds rate plus 0.5% and (b) SunTrust Bank’s prime rate plus an applicable margin, or (ii) LIBOR plus an applicable margin. The applicable margin is determined based on the current utilization level of the Credit Facility and ratings assigned by Standard & Poor’s Rating Services and Moody’s Investor Service for Buckeye’s senior unsecured non-credit enhanced long-term debt. At ~~June~~September 30, 2010 and December 31, ~~no amounts~~2009, $20.0 million and $78.0 million, respectively, were outstanding under the Credit Facility,. ~~while~~The atweighted ~~December 31,~~average ~~2009,~~interest ~~$78.0 million~~rate ~~was outstanding~~for borrowings under the Credit Facility was 0.5% at September 30, 2010.

The Credit Facility requires Buckeye to maintain a specified ratio (the “Funded Debt Ratio”) of no greater than 5.00 to 1.00 subject to a provision that allows for increases to 5.50 to 1.00 in connection with certain future acquisitions. The Funded Debt Ratio is calculated by dividing consolidated debt by annualized EBITDA, which is defined in the Credit Facility as earnings before interest, taxes, depreciation, depletion and amortization, in each case excluding the income of certain of Buckeye’s majority-owned subsidiaries and equity investments (but including distributions from those majority-owned subsidiaries and equity investments). At ~~June~~September 30, 2010, Buckeye’s Funded Debt Ratio was approximately 3.8677 to 1.00. As permitted by the Credit Facility, the $~~194~~211.28 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.

In addition, the Credit Facility contains other covenants including, but not limited to, covenants limiting Buckeye’s ability to incur additional indebtedness, to create or incur liens on its property, to dispose of property material to its operations, and to consolidate, merge or transfer assets. At ~~June~~September 30, 2010, we were not aware of any instances of noncompliance with ~~the~~ the covenants under Buckeye’s Credit Facility.

At ~~June~~September 30, 2010 and December 31, 2009, Buckeye had committed $1.45 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 had a credit agreement (the “BES Credit Agreement”) that provided for borrowings of up to $250.0 million with a maturity date of May 20, 2011. On June 25, 2010, BES amended and restated the BES Credit Agreement to increase the total commitments for borrowings available to BES up to $500.0 million. However, the maximum amount available to be borrowed under the amended and restated 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. The maturity date of the BES Credit Agreement is June 25, 2013. BES incurred $3.2 million of debt issuance costs related to the amendment, which will be amortized into interest expense over the term of the BES Credit Agreement.

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.

1516

BUCKEYE GP HOLDINGS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~The~~alternative ~~balances outstanding under the BES Credit Agreement were approximately $194.2 million and~~extensions ~~$239.8 million~~of atcredit ~~June 30,~~are ~~2010~~subject ~~and~~to ~~December 31,~~certain ~~2009,~~conditions ~~respectively, both of which were classified~~ as ~~current~~specified ~~liabilities~~ in ~~our~~the ~~condensed~~BES ~~consolidated~~Credit ~~balance sheets~~Agreement. The BES Credit Agreement ~~requires~~ ~~BES~~is tosecured ~~meet~~by ~~certain~~liens ~~financial~~on ~~covenants,~~certain ~~which~~assets ~~are~~of ~~defined in the~~ BES, ~~Credit~~including ~~Agreement~~its ~~and~~inventory, cash ~~summarized~~deposits ~~below~~ (inother ~~millions~~than certain accounts), ~~except~~investments ~~for~~and ~~the~~hedging ~~leverage~~accounts, ~~ratio):~~receivables and intangibles.

The balances outstanding under the BES Credit Agreement were approximately $211.8 million and $239.8 million at September 30, 2010 and December 31, 2009, 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	Minimum		Minimum		Maximum
outstanding on	Consolidated Tangible		Consolidated Net		Consolidated
BES Credit Agreement	Net Worth		Working Capital		Leverage Ratio
$150	$	40	$	30		7.0 to 1.0
Above $150 up to $200	$	50	$	40		7.0 to 1.0
Above $200 up to $250	$	60	$	50		7.0 to 1.0
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~~September 30, 2010, BES’s Consolidated Tangible Net Worth and Consolidated Net Working ~~Capital~~ Capital were $~~121~~122.38 million and $7172.58 million, respectively, and the Consolidated Leverage Ratio was 2.35 to 1.0. The weighted average interest rate for borrowings outstanding under the BES Credit ~~Agreement~~ Agreement was 2.5% at ~~June~~September 30, 2010.

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~~September 30, 2010, we were not aware of any instances of noncompliance with the covenants under the BES Credit Agreement.

11. OTHER NON-CURRENT LIABILITIES

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

	June 30,		December 31,
	September 30,		December 31,
	2010		2009
Accrued employee benefit liabilities (see Note 13)	$	45,~~799~~274	$	45,837
Accrued environmental liabilities		18,~~891~~447		19,053
Derivative liabilities		18,953		—
Deferred consideration		16,918		18,425
Deferred consideration		17,420		18,425
Deferred rent		12,334		9,158
Deferred rent		11,275		9,158
Deferred revenue		7,269		1,532
Deferred revenue		7,082		1,532
Other		9,279		8,937
Other		8,860		8,937
Total other non-current liabilities	$	109,521	$	102,942
Total other non-current liabilities	$	128,280	$	102,942

1617

BUCKEYE GP HOLDINGS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

12. DERIVATIVE INSTRUMENTS, HEDGING ACTIVITIES AND FAIR VALUE MEASUREMENTS

We are exposed to certain risks, including changes in interest rates and commodity prices, in the course of our normal business operations. We use derivative instruments to manage risks associated with certain identifiable and anticipated transactions. Derivatives are financial instruments whose fair value is determined by changes in a specified benchmark such as interest rates or commodity prices. Typical derivative instruments include futures, forward contracts, swaps and other instruments with similar characteristics. We have no trading derivative instruments ~~and do not engage in hedging activity with respect to trading instruments~~.

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

Interest Rate Derivatives

Buckeye utilizes forward-starting interest rate swaps to manage interest rate risk related to forecasted interest payments on anticipated debt issuances. This strategy is a component in controlling its cost of capital associated with such borrowings. When entering into interest rate swap transactions, Buckeye becomes exposed to both credit risk and market risk. Buckeye is subject to credit risk when the value of the swap transaction is positive and the risk exists that the counterparty will fail to perform under the terms of the contract. Buckeye is subject to market risk with respect to changes in the underlying benchmark interest rate that impacts the fair value of the swaps. Buckeye manages its credit risk by only entering into swap transactions with major financial institutions with investment-grade credit ratings. Buckeye manages its market risk by associating each swap transaction with an existing debt obligation or a specified expected debt issuance generally associated with the maturity of an existing debt obligation.

Buckeye’s practice with respect to derivative transactions related to interest rate risk has been to have each transaction in connection with non-routine borrowings authorized by the board of directors of Buckeye GP. In January 2009, Buckeye GP’s board of directors adopted an interest rate hedging policy which permits Buckeye to enter into certain short-term interest rate swap agreements to manage its interest rate and cash flow risks associated with its Credit Facility. In addition, in July 2009 and May 2010, Buckeye GP’s board of directors authorized Buckeye to enter into certain transactions, such as forward-starting interest rate swaps, to manage its interest rate and cash flow risks related to certain expected debt issuances associated with the maturity of existing debt obligations.

Buckeye expects to issue new fixed-rate debt (i) on or before July 15, 2013, to repay the $300.0 million of 4.625% Notes that are due on July 15, 2013, and (ii) on or before October 15, 2014, to repay the $275.0 million of 5.300% Notes that are due on October 15, 2014, although no assurances can be given that the issuance of fixed-rate debt will be possible on acceptable terms. During 2009, Buckeye entered into four forward-starting interest rate swaps with a total aggregate notional amount of $200.0 million related to the anticipated issuance of debt on or before July 15, 2013 and three forward-starting interest rate swaps with a total aggregate notional amount of $150.0 million related to the anticipated issuance of debt on or before October 15, 2014. During the ~~three~~nine months ended ~~June~~September 30, 2010, Buckeye entered into two forward-starting interest rate ~~swaps~~ swaps with a total aggregate notional amount of $100.0 million related to the anticipated issuance of of debt on or before July 15, 2013 and three forward-starting interest rate swaps with a total aggregate notional amount of $125.0 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 and ~~six~~nine months ended ~~June~~ September 30, 2010, unrealized losses of $3422.90 million and $3658.21 million, respectively, were recorded in Buckeye’s accumulated other comprehensive income (loss) to reflect the change in the fair values of the forward-starting interest rate swaps. Buckeye designated the swap agreements as cash flow hedges at inception and expects the changes in values to be highly correlated with the changes in value of the underlying borrowings.

1718

BUCKEYE GP HOLDINGS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Over the next twelve months, Buckeye expects to reclassify $1.0 million of accumulated other comprehensive loss as an increase to interest expense that was generated by forward-starting interest rate swaps terminated in 2008 associated with its 6.050% Notes.

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. ~~Presentations~~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 ~~sales~~ contracts. Therefore, our fixed-price ~~sales~~ contracts and the related futures contracts used to offset the ~~those~~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 Pipeline Operations segment bought natural gas futures contracts in March 2009 with terms that coincide with the remaining term of an ongoing natural gas supply contract (through July 2011). We designated the futures contract as a cash flow hedge at inception.

The following table summarizes our commodity derivative instruments outstanding at ~~June~~ September 30, 2010 (amounts in thousands of gallons, except as noted):

Volume (1)

Accounting

Derivative Purpose

Current

Long-Term (2)

Treatment

Derivatives NOT designated as hedging instruments:

Fixed-price sales contracts

29,050

168

Mark-to-market

Fixed-price contracts

45,380

Mark-to-market

Futures contracts for fixed-price sales contracts

2421,~~612~~672

~~168~~—

Mark-to-market

Futures contracts for inventory

214,~~777~~448

—

Mark-to-market

Derivatives designated as hedging instruments:

Futures contracts for inventory

~~123~~107,~~522~~730

—

Fair Value Hedge

Futures contracts for natural gas (BBtu) (3)

~~360~~300

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 October 2011.
(3)		BBtu represents one billion British thermal units.

BUCKEYE GP HOLDINGS 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:

	June 30, 2010								December 31, 2009
						Derivative								Derivative
	Assets		(Liabilities)			Net Carrying			Assets		(Liabilities)			Net Carrying
	Fair value		Fair value			Value			Fair value		Fair value			Value
Derivatives NOT designated as hedging instruments:
Fixed-price sales contracts	$	5,213	$	(258	)	$	4,955		$	4,959	$	(3,662	)	$	1,297
Futures contracts for fixed-price sales contracts		1,492		(1,806	)		(314	)		7,594		(384	)		7,210
Futures contracts for inventory		3,336		(3,457	)		(121	)		—		—			—
Derivatives designated as hedging instruments:
Futures contracts for inventory		8,094		(2,748	)		5,346			1,992		(20,517	)		(18,525	)
Futures contracts for natural gas		—		(140	)		(140	)		312		—			312
Interest rate contracts		—		(18,953	)		(18,953	)		17,204		—			17,204
Total						$	(9,227	)						$	7,498

	June 30,			December 31,
Balance Sheet Locations:	2010			2009
Derivative assets	$	10,093		$	4,959
Other non-current assets		—			17,204
Derivative liabilities		(367	)		(14,665	)
Other non-current liabilities		(18,953	)		—
Total	$	(9,227	)	$	7,498

Our hedged inventory portfolio extends to the first quarter of 2011. The majority of the unrealized income of $5.2 million at June 30, 2010 for inventory hedges represented by futures contracts will be realized by the third quarter of 2010 as the related inventory is sold. Gains recorded on inventory hedges that were ineffective were approximately $1.0 million and $3.3 million for the three months ended June 30, 2010 and 2009, respectively. For the six months ended June 30, 2010 and 2009, gains recorded on inventory hedges that were ineffective were approximately $5.8 million and $7.6 million, respectively. At June 30, 2010, open refined petroleum product derivative contracts (represented by the fixed-price sales contracts and futures contracts for fixed-price sales contracts noted above) varied in duration, but did not extend beyond October 2011. In addition, at June 30, 2010, we had refined petroleum product inventories which we intend to use to satisfy a portion of the fixed-price sales contracts.

BUCKEYE GP HOLDINGS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The ~~gains~~following ~~and~~table ~~losses~~sets onforth ~~our~~the ~~derivative~~fair ~~instruments~~value ~~recognized~~of ineach ~~income~~classification ~~were~~of asderivative ~~follows for~~instruments at the ~~periods~~dates indicated (in thousands):

			Gain (Loss) Recognized in Income on Derivatives
	September 30, 2010												December 31, 2009
			Three Months Ended								Six Months Ended
									Derivative											Derivative
			June 30,								June 30,
	Assets				(Liabilities)				Net Carrying				Assets				(Liabilities)			Net Carrying
	Location		2010				2009				2010				2009
	Fair Value				Fair Value				Value				Fair Value				Fair Value			Value
Derivatives NOT designated as hedging instruments:
Derivatives NOT designated as hedginginstruments:
Fixed-price sales contracts	Product sales		$	6,268			$	(13,866	)		$	8,678			$	(571	)
Fixed-price contracts	$	2,747			$	(2,130	)		$	617			$	4,959			$	(3,662	)	$	1,297
Futures contracts for fixed-price sales contracts	~~Cost of product sales and natural gas storage services~~	2,808		~~(2,972~~	)	(398	)	~~19,007~~		2,410		~~(3,466~~	)	7,594		~~11,461~~		(384	)		7,210
Futures contracts for inventory	~~Cost of product sales and natural gas storage services~~	25,241		20		(24,550	)	—		691		~~266~~		—		—		—			—
Derivatives designated as fair value hedging instruments:
Derivatives designated as hedging instruments:
Futures contracts for inventory	~~Cost of product sales and natural gas storage services~~	795	$	~~18,123~~		(12,530	$)	~~(31,251~~	)	(11,735	$)	~~13,213~~		1,992	$	~~(3,603~~	)	(20,517	)		(18,525	)
Futures contracts for natural gas		—				(361	)			(361	)			312				—			312
Interest rate contracts		—				(40,910	)			(40,910	)			17,204				—			17,204
Total									$	(49,288	)									$	7,498

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


	September 30,			December 31,
Balance Sheet Locations:	2010			2009
Derivative assets	$	2,600		$	4,959
Other non-current assets		—			17,204
Derivative liabilities		(10,978	)		(14,665	)
Long-term derivative liabilities		(40,910	)		—


Total	$	(49,288	)	$	7,498

		Gain (Loss) Reclassified from AOCI to Income
		Three Months Ended						Six Months Ended
		June 30,						June 30,
	Location	2010			2009			2010			2009
Derivatives designated as cash flow hedging instruments:
Futures contracts for natural gas	Cost of product sales and natural gas storage services	$	(96	)	$	(162	)	$	(168	)	$	(215	)
Futures contracts for refined petroleum products	Cost of product sales and natural gas storage services		—			(379	)		—			(146	)
Interest rate contracts	Interest and debt expense		(242	)		(164	)		(482	)		(656	)

Our hedged inventory portfolio extends to the first quarter of 2011. The majority of the unrealized loss of $11.7 million at September 30, 2010 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 2010 as the inventory is sold. A loss of $1.5 million and a gain of $10.0 million were recorded on inventory hedges that were ineffective for the three months ended September 30, 2010 and 2009, respectively. For the nine months ended September 30, 2010 and 2009, gains recorded on inventory hedges that were ineffective were approximately $1.2 million and $17.7 million, respectively. At September 30, 2010, 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 October 2011. In addition, at September 30, 2010, we had refined petroleum product inventories which we intend to use to satisfy a portion of the fixed-price contracts.

	Change in Value Recognized in OCI on Derivatives
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Derivatives designated as cash flow hedging instruments:
Futures contracts for natural gas	$	85		$	46		$	(611	)	$	163
Interest rate contracts		(34,853	)		(158	)		(36,157	)		(157	)

BUCKEYE GP HOLDINGS 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						Nine Months Ended
		September 30,						September 30,
	Location	2010			2009			2010			2009
Derivatives NOT designated as hedging instruments:
Fixed-price contracts	Product sales	$	(1,974	)	$	3,937		$	6,704		$	3,366
Futures contracts for fixed-price sales contracts	Cost of product sales and natural gas storage services		3,363			(3,972	)		(103	)		7,489
Futures contracts for inventory	Cost of product sales and natural gas storage services		65			—			331			—

Derivatives designated as fair value hedging instruments:

Futures contracts for inventory	Cost of product sales and natural gas storage services	$	(18,509	)	$	4,273		$	(5,296	)	$	670


		Gain (Loss) Reclassified from AOCI to Income
		Three Months Ended						Nine Months Ended
		September 30,						September 30,
	Location	2010			2009			2010			2009
Derivatives designated as cash flow hedging instruments:

Futures contracts for natural gas	Cost of product sales and natural gas storage services	$	(122	)	$	(192	)	$	(291	)	$	(407	)
Futures contracts for refined petroleum products	Cost of product sales and natural gas storage services		—			—			—			(146	)
Interest rate contracts	Interest and debt expense		(241	)		(1,393	)		(723	)		(2,049	)


	Change in Value Recognized in OCI on Derivatives
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Derivatives designated as cash flow hedging instruments:

Futures contracts for natural gas	$	(337	)	$	(1	)	$	(949	)	$	162
Interest rate contracts		(21,957	)		(3,849	)		(58,114	)		(4,006	)

BUCKEYE GP HOLDINGS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Fair Value Measurements

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

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

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

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

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

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

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

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

•

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

2122

BUCKEYE GP HOLDINGS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Recurring

The following table sets forth financial assets and liabilities, measured at fair value on a recurring basis, as of the measurement dates, ~~June~~September 30, 2010 and December 31, 2009, and the ~~basis~~ basis for that measurement, by level within the fair value hierarchy (in thousands):

	June 30, 2010						December 31, 2009
	September 30, 2010						December 31, 2009
				Significant						Significant
	Quoted Prices			Other			Quoted Prices			Other
	in Active			Observable			in Active			Observable
	Markets			Inputs			Markets			Inputs
	(Level 1)			(Level 2)			(Level 1)			(Level 2)
Financial assets:
Fixed-price sales contracts	$	—		$	5,121		$	—		$	4,959
Fixed-price contracts	$	—		$	2,497		$	—		$	4,959
Futures contracts for inventory and fixed-price sales contracts		~~4,973~~103			—			—			—
Asset held in trust		—			—			1,793			—
Interest rate derivatives		—			—			—			17,204
Financial liabilities:
Fixed-price sales contracts		—			(166	)		—			(3,662	)
Fixed-price contracts		—			(1,880	)		—			(3,662	)
Futures contracts for inventory and fixed-price sales contracts		(~~202~~8,737	)		—			(11,003	)		—
Interest rate derivatives		—			(18,953	)		—			—
Futures contracts for natural gas		(361	)		—			—			—
Total	$	4,771		$	(13,998	)	$	(9,210	)	$	18,501
Interest rate derivatives		—			(40,910	)		—			—
Total	$	(8,995	)	$	(40,293	)	$	(9,210	)	$	18,501

The ~~value~~values of the Level 1 derivative assets and liabilities were based on quoted market prices obtained from the NYMEX. The value of the Level 1 asset held in trust was obtained from quoted market prices. ~~The value of the Level 2 derivative assets and liabilities were based on observable~~ ~~market data related to the obligations to provide petroleum products. The value of the Level 2 interest rate derivatives was based on observable market data related to similar obligations.~~

The ~~Level~~values ~~2 derivative assets~~ of $5.1 million and $5.0 million as of June 30, 2010 and December 31, 2009, respectively, are net of a credit valuation adjustment (“CVA”) of ($0.6) million and ($0.9) million, respectively. Because few of the ~~Energy~~Level ~~Services~~2 ~~segment’s~~interest ~~customers~~rate ~~entering into~~derivatives ~~these~~were ~~fixed-price~~determined ~~sales~~using ~~contracts~~expected ~~are~~cash ~~large organizations with nationally-recognized credit~~flow ~~ratings~~models, ~~the Energy Services segment determined that a CVA,~~ which isincorporated ~~based~~market oninputs ~~the~~including ~~credit risk of such contracts, is appropriate. The CVA is based on~~ the ~~historical~~implied ~~and~~forward ~~expected~~LIBOR ~~payment~~yield ~~history~~curve ~~of each customer, the amount of product contracted~~ for ~~under~~ the same ~~agreement~~period ~~and~~as the ~~customer’s historical~~future ~~and~~interest ~~expected~~swap ~~purchase performance under each contract~~settlements.

22 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 $2.5 million and $5.0 million as of September 30, 2010 and December 31, 2009, respectively, are net of CVA of ($0.3) million and ($0.9) million, respectively.

BUCKEYE GP HOLDINGS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 impairment. The following table presents the fair value of an asset carried on the condensed consolidated balance sheet by asset classification and by level within the valuation hierarchy (as described above) at the date indicated for which a nonrecurring change in fair value has been recorded during the ~~three~~nine ~~and six~~ months ended ~~June~~September 30, 2009 (in thousands):

	June 30,								Total
	September 30,								Total
	2009		Level 1		Level 2		Level 3		Losses
Assets held for sale (1)	$	5,760	$	—	$	—	$	5,760	$	72,540
Prepaid and other current assets (1)	$	8,639	$	—	$	—	$	8,639	$	72,540

(1) Represents the property, plant and equipment of net assets held for sale that ~~were~~was included in prepaid and other current assets at ~~June~~September 30, 2009 (see Note 2).

As a result of a loss in the customer base utilizing the Buckeye NGL Pipeline, we recorded a non-cash impairment charge of $72.5 million during the ~~three~~nine ~~and six~~ months ended ~~June~~September 30, 2009. ~~The~~ The estimated fair value was based on a probability-weighted combination of income and market approaches.

13. 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.

The components of the net periodic benefit cost for the RIGP and Retiree Medical Plan were as follows for the three months ended ~~June~~September 30, 2010 and 2009 (in thousands):

	RIGP						Retiree Medical Plan
	Three Months Ended						Three Months Ended
	June 30,						June 30,
	September 30,						September 30,
	2010			2009			2010			2009
Service cost	$	6566		$	~~207~~(44	)	$	~~117~~74		$	~~105~~37
Interest cost		~~227~~226			~~369~~146			~~786~~495			~~491~~419
Expected return on plan assets		(86	)		(~~189~~47	)		—			—
Amortization of prior service benefit		(11	)		(~~118~~47	)		(~~1,175~~741	)		(~~859~~679	)
Amortization of unrecognized losses		~~242~~241			~~355~~90			~~354~~223			~~261~~220
Settlement/curtailment charge (1)		—			~~7,171~~—			—			~~800~~(1,571	)
Net periodic benefit costs	$	~~437~~436		$	~~7,795~~98		$	8251		$	~~798~~(1,574	)

(1) In connection with Buckeye’s reorganization in 2009, $86.04 million of the aggregate amount of $2829.1 million of expenses incurred through ~~June~~September 30, 2009 was recorded as an adjustment to the funded status of the RIGP and the Retiree Medical Plan, which represent settlement and curtailment adjustments.

2324

BUCKEYE GP HOLDINGS 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 ~~six~~nine months ended ~~June~~September 30, 2010 and 2009 (in thousands):

	RIGP						Retiree Medical Plan
	Six Months Ended						Six Months Ended
	Nine Months Ended						Nine Months Ended
	June 30,						June 30,
	September 30,						September 30,
	2010			2009			2010			2009
Service cost	$	~~133~~199		$	~~415~~371		$	~~147~~221		$	~~210~~247
Interest cost		~~459~~685			~~740~~886			~~991~~1,486			~~983~~1,402
Expected return on plan assets		(~~174~~260	)		(~~380~~427	)		—			—
Amortization of prior service benefit		(2334	)		(~~235~~282	)		(12,~~482~~223	)		(12,~~719~~397	)
Amortization of unrecognized losses		~~490~~731			~~712~~802			~~447~~670			~~522~~743
Settlement/curtailment charge (1)		—			7,171			—			~~800~~(771	)
Net periodic benefit costs	$	~~885~~1,321		$	8,~~423~~521		$	~~103~~154		$	~~796~~(776	)

During the ~~six~~nine months ended ~~June~~September 30, 2010, we contributed $12.57 million to the RIGP.

14. UNIT-BASED COMPENSATION PLANS

We have Management Units (see Note 1) and an equity compensation plan (“GP Equity Compensation Plan”) for certain members of our and BGH GP’s senior management. The GP Equity Compensation Plan includes both time-based and performance-based participation in the equity of BGH GP (but not ours) referred to as override units. Compensation expense recorded with respect to the override units was $0.3 million and $0.43 million for the three months ended ~~June~~September 30, 2010 and 2009, respectively, and $0.69 million and $01.70 million for the ~~six~~nine months ended ~~June~~September 30, 2010 and 2009, respectively.

Buckeye awards unit-based compensation to employees and directors primarily under the 2009 Long-Term Incentive Plan of Buckeye Partners, L.P. (the “LTIP”), which became effective in March 2009. Buckeye 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 total unit-based compensation expense related to the LTIP and the Option Plan of $1.3 million and $0.45 million for the three months ended ~~June~~September 30, 2010 and 2009, respectively, and $23.58 million ~~and~~ and $01.50 million for the ~~six~~nine months ended ~~June~~September 30, 2010 and 2009, respectively.

2425

BUCKEYE GP HOLDINGS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

BGH GP’s Override Units

No override units were granted or forfeited during the ~~six~~nine months ended ~~June~~September 30, 2010. ~~The~~ The following is a summary of the activity of the override units as of ~~June~~September 30, 2010 (~~units~~ in thousands):

	Number of Override Units							Total Number
					Operating			of Units
	Value A Units		Value B Units		Units			Awarded
Unvested at December 31, 2009		1,699		1,699		812			4,210
Vested		—		—		(~~165~~266	)		(~~165~~266	)
Unvested at June 30, 2010		1,699		1,699		647			4,045
Unvested at September 30, 2010		1,699		1,699		546			3,944

	Compensation Costs for Override Units
					Operating
	Value A Units		Value B Units		Units			Totals
Total fair value of all outstanding override units	$	3,587	$	2,179	$	5,808		$	11,574
Less: Expense recorded from plan inception to June 30, 2010		—		—		(3,984	)		(3,984	)
Less: Expense recorded from plan inception to September 30, 2010		—		—		(4,301	)		(4,301	)
Estimated future compensation costs at June 30, 2010	$	3,587	$	2,179	$	1,824		$	7,590
Estimated future compensation costs at September 30, 2010	$	3,587	$	2,179	$	1,507		$	7,273

Buckeye’s Long-Term Incentive Plan

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~~September 30, 2010, awards representing a total of 1,~~113~~116,~~451~~268 additional LP ~~Units~~ Units could be issued under the LTIP.

On December 16, 2009, the Compensation Committee approved the terms of the Buckeye Partners, L.P. Unit Deferral and Incentive Plan (“Deferral Plan”). The Compensation Committee is expressly authorized to adopt the Deferral Plan under the terms of the LTIP, which grants the Compensation Committee the authority to establish a program pursuant to which Buckeye’s phantom units may be awarded in lieu of cash compensation at the election of the employee. At December 31, 2009, eligible employees were allowed to defer up to 50% of their 2009 compensation award under Buckeye’s 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 $1.8 million of 2009 compensation awards had been deferred at December 31, 2009, for which 62,332 phantom units (including matching units) were granted during the three months ended March 31, 2010. These grants are included as granted in the LTIP activity table below.

Awards under the LTIP

During the ~~six~~nine months ended ~~June~~September 30, 2010, the Compensation Committee granted 123,~~290 phantom~~669 phantom units to employees (including the 62,332 phantom units granted pursuant to the Deferral ~~Plan~~ Plan discussed above), 12,000 phantom units to independent directors of Buckeye GP and MainLine Management, and ~~121~~122,~~926~~683 performance units to employees. The amount paid with respect to phantom unit distribution equivalents under the LTIP was $0.34 million for the ~~six~~nine months ended ~~June~~ September 30, 2010.

2526

BUCKEYE GP HOLDINGS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

				Weighted
				Average
				Grant Date
	Number of			Fair Value
	LP Units			per LP Unit (1)		Total Value
Unvested at January 1, 2010		140,095		$	39.81	$	5,577
Granted		~~257~~258,~~216~~352			56.2022		14,~~455~~525
Vested		(18,~~454~~518	)		39.1718		(~~723~~725	)
Forfeited		(1115,~~281~~234	)		4849.2844		(~~545~~753	)
Unvested at June 30, 2010		367,576		$	51.05	$	18,764
Unvested at September 30, 2010		364,695		$	51.07	$	18,624


(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~~September 30, 2010, approximately $1310.18 million of compensation expense related to the LTIP is is expected to be recognized over a weighted average period of approximately 21.29 years.

Buckeye’s Unit Option and Distribution Equivalent Plan

Buckeye also sponsors the Option Plan, pursuant to which it historically granted options to employees to purchase LP Units at the market price of its LP Units on the date of grant. Generally, the options vest three years from the date of grant and expire ten years from the date of grant. As unit options are exercised, Buckeye issues new LP Units to the holder. Buckeye has not historically repurchased, and does not expect to repurchase in 2010, any of its LP Units.

The impact of Buckeye’s Option Plan is immaterial to our condensed consolidated financial statements.

15. RELATED PARTY TRANSACTIONS

Approximately 62% of our outstanding equity, which includes Common Units and Management Units, ~~are~~is owned by BGH GP and approximately 38% by the public. BGH GP is owned by affiliates of ArcLight, Kelso and certain investment funds along with certain members of senior management of Buckeye GP. MainLine Management is our general partner and is wholly owned by BGH GP.

Services Company and Buckeye are considered related parties with respect to us. As discussed in Note 1, our condensed consolidated financial statements include the accounts of Services Company and Buckeye on a consolidated basis, and all intercompany transactions have been eliminated.

We incurred a senior administrative charge for certain management services performed by affiliates of Buckeye GP of $0.5 million for the three months ended March 31, 2009. The senior administrative charge was waived indefinitely on April 1, 2009 as these affiliates are currently not providing services to us that were contemplated as being covered by the senior administrative charge. As a result, there were no related charges recorded in the last nine months of 2009 or during the ~~six~~nine months ended ~~June~~September 30, 2010.

26 On August 18, 2010, we and our general partner entered into the Merger Agreement with Buckeye, its general partner and Merger Sub, Buckeye’s subsidiary, pursuant to which Merger Sub will be merged into BGH, with BGH as the surviving entity. The Merger Agreement amends and restates an original Agreement and Plan of Merger, dated as of June 10, 2010, by and among the parties to the Merger Agreement. See Note 1 for further information regarding the Merger.

BUCKEYE GP HOLDINGS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

16. CASH 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 totaled $2336.85 million and $1929.27 million during the ~~six~~nine months ended ~~June~~September 30, 2010 and 2009, respectively.

On ~~August~~November 68, 2010, we announced a quarterly distribution of $0.4547 per Common Unit that will be be paid on ~~August~~November 3130, 2010, to unitholders of record on November ~~August 16~~15, 2010. Total cash distributed to unitholders on ~~August~~November 3130, 2010 will total approximately $1213.73 million.

17. EARNINGS PER PARTNERSHIP UNIT

Basic and diluted earnings per partnership unit is calculated by dividing net income, after deducting the amount allocated to Buckeye, by the weighted-average number of partnership units outstanding during the period.

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

	Three Months Ended				~~Six~~Nine Months Ended
	June 30,				June 30,
	September 30,				September 30,
	2010		2009		2010		2009
Basic:
Weighted average common units outstanding		27,774		27,770		27,774		27,770
Weighted average management units outstanding		526		530		526		530
Units for basic		28,300		28,300		28,300		28,300
Diluted:
Units used for basic calculation		28,300		28,300		28,300		28,300
Dilutive effect of additional management units		—		—		—		—
Units for diluted		28,300		28,300		28,300		28,300

BUCKEYE GP HOLDINGS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

18. BUSINESS SEGMENTS

We operate and report in five business segments: Pipeline Operations; Terminalling & Storage; Natural Gas Storage; Energy Services; and Development & Logistics.

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.

27 Financial information about each segment is presented below for the periods or at the dates indicated (in thousands):


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Revenue:
Pipeline Operations	$	103,621		$	96,714		$	299,497		$	294,084
Terminalling & Storage		41,900			34,036			125,039			94,108
Natural Gas Storage		21,663			28,576			68,318			60,325
Energy Services		566,804			258,407			1,636,955			728,563
Development & Logistics		9,082			7,516			27,382			25,446
Intersegment		(8,213	)		(1,805	)		(23,884	)		(11,022	)

Total revenue	$	734,857		$	423,444		$	2,133,307		$	1,191,504


Operating income (loss):
Pipeline Operations	$	48,991		$	41,846		$	138,891		$	35,208
Terminalling & Storage		23,656			17,323			70,695			39,095
Natural Gas Storage		2,795			7,591			9,548			19,572
Energy Services		2,581			5,620			(1,287	)		10,404
Development & Logistics		1,490			2,509			3,096			4,043

Total operating income	$	79,513		$	74,889		$	220,943		$	108,322


Depreciation and amortization:
Pipeline Operations	$	9,263		$	8,659		$	27,295		$	26,482
Terminalling & Storage		2,386			1,813			7,051			5,401
Natural Gas Storage		1,643			1,241			4,924			3,943
Energy Services		1,331			986			3,702			2,946
Development & Logistics		439			439			1,287			1,289

Total depreciation and amortization	$	15,062		$	13,138		$	44,259		$	40,061


Capital additions, net: (1)
Pipeline Operations							$	22,013		$	20,813
Terminalling & Storage								16,116			15,186
Natural Gas Storage								7,466			18,884
Energy Services								2,835			2,973
Development & Logistics								845			947

Total capital additions, net							$	49,275		$	58,803


(1)		Amount excludes $1.0 million and ($2.6) million of non-cash changes in accruals for capital expenditures for the nine months ended September 30, 2010 and 2009, respectively (see Note 19).

BUCKEYE GP HOLDINGS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Financial information about each segment is presented below for the periods or at the dates indicated:


	September 30,		December 31,
	2010		2009
Total Assets:
Pipeline Operations (1)	$	1,543,935	$	1,592,916
Terminalling & Storage		522,941		532,971
Natural Gas Storage		549,243		573,261
Energy Services		461,146		482,025
Development & Logistics		60,386		74,476
Consolidating level		234,300		230,922

Total assets	$	3,371,951	$	3,486,571


Goodwill:
Pipeline Operations	$	198,632	$	198,632
Terminalling & Storage		49,618		49,618
Natural Gas Storage		169,560		169,560
Energy Services		1,132		1,132
Development & Logistics		13,182		13,182

Total goodwill	$	432,124	$	432,124

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Revenue:
Pipeline Operations	$	99,339		$	98,175		$	195,876		$	197,370
Terminalling & Storage		40,768			29,429			83,139			60,072
Natural Gas Storage		21,249			16,672			46,655			31,749
Energy Services		501,949			201,676			1,070,151			470,156
Development & Logistics		10,785			8,805			18,300			17,930
Intersegment		(6,814	)		(3,537	)		(15,671	)		(9,217	)
Total revenue	$	667,276		$	351,220		$	1,398,450		$	768,060
Operating income (loss):
Pipeline Operations		44,535		$	(51,085	)	$	89,900		$	(6,638	)
Terminalling & Storage		23,914			11,115			47,039			21,772
Natural Gas Storage		3,302			5,817			6,753			11,981
Energy Services		(471	)		(1,432	)		(3,868	)		4,784
Development & Logistics		659			153			1,606			1,534
Total operating income (loss)	$	71,939		$	(35,432	)	$	141,430		$	33,433
Depreciation and amortization:
Pipeline Operations		9,079		$	8,984		$	18,032		$	17,823
Terminalling & Storage		2,349			1,866			4,665			3,588
Natural Gas Storage		1,640			1,243			3,281			2,702
Energy Services		1,176			983			2,371			1,960
Development & Logistics		425			483			848			850
Total depreciation and amortization	$	14,669		$	13,559		$	29,197		$	26,923
Capital additions, net: (1)
Pipeline Operations							$	14,252		$	12,561
Terminalling & Storage								7,621			12,021
Natural Gas Storage								3,292			12,906
Energy Services								2,064			1,802
Development & Logistics								343			529
Total capital additions, net							$	27,572		$	39,819
Contributions to equity investments:
Pipeline Operations							$	—		$	3,880
Total contributions to equity investments							$	—		$	3,880

(1) Amount excludes ($1.2) million and ($0.9) million of non-cash changes in accruals for capital expenditures for the six months ended June 30, 2010 and 2009, respectively (see Note 19).

BUCKEYE GP HOLDINGS L.P. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	June 30,		December 31,
	2010		2009
Total Assets:
Pipeline Operations (1)	$	1,536,124	$	1,592,916
Terminalling & Storage		526,720		532,971
Natural Gas Storage		548,061		573,261
Energy Services		436,271		482,025
Development & Logistics		63,159		74,476
Consolidating level		233,544		230,922
Total assets	$	3,343,879	$	3,486,571
Goodwill:
Pipeline Operations	$	198,632	$	198,632
Terminalling & Storage		49,618		49,618
Natural Gas Storage		169,560		169,560
Energy Services		1,132		1,132
Development & Logistics		13,182		13,182
Total goodwill	$	432,124	$	432,124


(1)		All equity investments are included in the assets of the Pipeline Operations segment.

19. SUPPLEMENTAL CASH FLOW INFORMATION

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

	Six Months Ended
	Nine Months Ended
	June 30,
	September 30,
	2010			2009
Cash paid for interest (net of capitalized interest)	$	4073,~~165~~230		$	3359,~~349~~101
Cash paid for income taxes		~~419~~801			1,~~298~~650
Capitalized interest		1,~~117~~710			2,~~684~~906
Non-cash changes in assets and liabilities:
Change in capital expenditures in accounts payable	$	(1,~~186~~028	)	$	(~~865~~2,606	)

20. SUBSEQUENT ~~EVENT~~EVENTS

OnTerminal ~~August 2, 2010, we completed the acquisition of additional shares of West Shore Pipe Line~~Acquisitions Company (“West Shore”) common stock from an affiliate of BP plc, resulting in an increase in our ownership interest in West Shore from 24.9% to 34.6%. We paid approximately $13.4 million for this additional interest.

29 On October 28, 2010, we entered into an agreement to acquire a refined petroleum products terminal on the southeast coast of Puerto Rico from an affiliate of Royal Dutch Shell plc (“Shell”). The terminal, located in Yabucoa, Puerto Rico, includes 44 storage tanks with approximately 4.6 million barrels of gasoline, jet fuel, diesel, fuel oil and crude oil storage capacity. Our investment will provide us with long-term fee-based revenues supported by multi-year commitments from Shell. The acquisition, which is subject to customary closing conditions, is expected to close in December 2010.

On November 5, 2010, we completed the purchase of a refined petroleum products terminal in Opelousas, Louisiana from Chevron U.S.A Inc. (“Chevron”) for $13.0 million in cash. The terminal includes seven storage tanks with approximately 135,000 barrels of total storage capacity and a truck rack. In addition, Chevron has agreed to enter into a commercial contract with us that is associated with the acquired facility.


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 for the year ended December 31, 2009.

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 for the year ended December 31, 2009 and in ~~this~~our ~~quarterly~~Quarterly ~~report~~Report on Form 10-Q for the quarter ended June 30, 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. You should not put undue reliance on any forward-looking statements. The forward-looking statements in this Quarterly Report 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 for the year ended December 31, 2009. 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.

Overview of BGH

Buckeye GP Holdings L.P. is a publicly traded Delaware master limited partnership (“MLP”), the common units (“Common Units”) of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “BGH.” We own 100% of Buckeye GP LLC (“Buckeye GP”), which is the general partner of Buckeye Partners, L.P. (“Buckeye”). Buckeye is also a publicly traded Delaware MLP which was organized in 1986, and its limited partner units (“LP Units”) are separately traded on the NYSE under the ticker symbol “BPL.” Approximately 62% of our outstanding equity, which includes Common Units and management units (“Management Units”) are owned by BGH GP Holdings, LLC (“BGH GP”) and approximately 38% by the public. BGH GP is owned by affiliates of ArcLight Capital Partners, LLC (“ArcLight”), Kelso & Company (“Kelso”), and certain investment funds along with certain members of senior management of Buckeye GP. MainLine Management LLC, a Delaware limited liability company (“MainLine Management”), is our general partner and is wholly owned by BGH GP. Unless the context requires otherwise, references to “we,” “us,” “our” or “BGH” are intended to mean the business and operations of Buckeye GP Holdings L.P. on a consolidated basis, including those of Buckeye. References to “Buckeye” mean Buckeye Partners, L.P. and its consolidated subsidiaries.

3031

Our only cash-generating assets are our partnership interests in Buckeye, comprised primarily of the following:

	•		the incentive distribution rights in Buckeye;

	•		the indirect ownership of the general partner interests in certain of Buckeye’s operating subsidiaries (representing an approximate 1% interest in each of such operating subsidiaries);

	•		the general partner interests in Buckeye (representing 243,914 general partner units (the “GP Units”), or an approximate 0.5% interest in Buckeye); and

	•		80,000 of Buckeye’s LP Units.

The incentive distribution rights noted above entitle us to receive amounts equal to specified percentages of the incremental amount of cash distributed by Buckeye to the holders of LP Units when target distribution levels for each quarter are exceeded. The 2,573,146 LP Units originally issued to the Buckeye Pipe Line Services Company Employee Stock Ownership Plan (the “ESOP”) are excluded for the purpose of calculating incentive distributions. The target distribution levels begin at $0.325 and increase in steps to the highest target distribution level of $0.525 per eligible LP Unit. When Buckeye makes quarterly distributions above this level, the incentive distributions include an amount equal to 45% of the incremental cash distributed to each eligible unitholder for the quarter, or approximately 29.5% of total incremental cash distributed by Buckeye above $0.525 per LP Unit.

Our earnings and cash flows are, therefore, directly dependent upon the ability of Buckeye and its operating subsidiaries to make cash distributions to its unitholders. The actual amount of cash that Buckeye will have available for distribution will depend primarily on its ability to generate earnings and cash flows beyond its working capital requirements.

The following table summarizes the cash we received for the three and ~~six~~nine months ended ~~June~~ September 30, 2010 and 2009 as a result of our partnership interests in Buckeye (in thousands, except unit amounts):

Three Months Ended

~~Six~~Nine Months Ended

June 30,

September 30,

2010

2009

2010

2009

Incentive payments from Buckeye

12,~~604~~886

11,~~466~~742

2437,~~918~~804

2133,~~971~~713

Distributions from the indirect 1% ownership in certain of Buckeye’s operating subsidiaries

—534

~~534~~519

~~403~~937

~~896~~1,415

Distributions from the ownership of 243,914 of Buckeye’s GP Units

~~231~~235

~~220~~223

~~460~~695

~~436~~659

Distributions from the ownership of 80,000 of Buckeye’s LP Units

7677

7273

~~151~~228

~~143~~216

Cash received

1213,~~911~~732

12,~~292~~557

2539,~~932~~664

2336,~~446~~003

Overview of Buckeye Partners, L.P.

Buckeye’s primary business strategies are to generate stable cash flows, increase pipeline and terminal throughput and pursue strategic cash-flow accretive acquisitions that complement its existing asset base, improve operating efficiencies and allow increased cash distributions to its unitholders.

We, through Buckeye, operate and report in five business segments: Pipeline Operations; Terminalling & Storage; Natural Gas Storage; Energy Services; and Development & Logistics. Buckeye owns and operates one of the largest independent refined petroleum products pipeline systems in the United States in terms of volumes delivered with approximately 5,400 miles of pipeline and 6768 active products terminals that provide aggregate storage capacity of approximately 27.23 million barrels. In addition, Buckeye operates and maintains approximately 2,400 miles of other pipelines under agreements with major oil and gas, petrochemical and chemical companies, and performs certain engineering and construction management services for third parties. Buckeye also owns and operates a major natural gas storage facility in northern California, and is a wholesale distributor of refined petroleum products in the United States in areas also served by its pipelines and terminals.

3132

Recent Developments

Agreement and Plan of Merger

On ~~June~~August 1018, 2010, we and our general partner entered into ana First Amended and Restated Agreement and Plan of Merger (the “Merger Agreement”) with Buckeye, its general partner, and Grand Ohio, LLC (“Merger Sub”), Buckeye’s subsidiary,. ~~pursuant~~Pursuant to ~~which~~the Merger Agreement, Merger Sub will be 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 Buckeye’s general partner will be cancelled, the general partner units held by Buckeye’s general partner (representing an approximate 0.5% general partner interest in Buckeye) will be converted to a non-economic general partner interest, all of the economic interest in us will be acquired by BPL and our unitholders will receive aggregate consideration of approximately 20.0 million of Buckeye’s LP Units.

Amendment to BES Credit Agreement

On June 25, 2010, Buckeye Energy Services LLC (“BES”) amended and restated its credit agreement (the “BES Credit Agreement”) to increase the total commitments for borrowings available to BES up to $500.0 million. However, the maximum amount available to be borrowed under the amended and restated 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, 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. The maturity date of the BES Credit Agreement is June 25, 2013. BES incurred $3.2 million of debt issuance costs related to the amendment, which will be amortized into interest expense over the term of the BES Credit Agreement. See Note 10 in the Notes to Unaudited Condensed Consolidated Financial Statements for further discussion.

under the BES Credit Agreement in $5.0 million increments, but in no event below $150.0 million or above $500.0 million. The maturity date of the BES Credit Agreement is June 25, 2013. BES incurred $3.2 million of debt issuance costs related to the amendment, which will be amortized into interest expense over the term of the BES Credit Agreement. See Note 10 in the Notes to Unaudited Condensed Consolidated Financial Statements for further discussion.

Purchase of Additional Interest in West Shore Pipe Line Company

On August 2, 2010, in connection with our exercise of a right of first refusal, we completed the acquisition of additional shares of West Shore Pipe Line Company (“West Shore”) common stock from an affiliate of BP plc, resulting in an increase in our ownership interest in West Shore from 24.9% to 34.6%. We paid approximately $13.45 million for this additional interest. We exercised our right of first refusal to purchase the additional shares because of the favorable economics associated with the investment opportunity and our desire to increase our ownership in a successful joint venture pipeline that we currently operate.

Sale of Buckeye NGL Pipeline

Results of Operations

The results of operations discussed below principally reflect the activities of Buckeye. Since our condensed consolidated financial statements include the consolidated results of Buckeye, our condensed consolidated financial statements are substantially similar to Buckeye’s except as noted below:

	•		Interest of noncontrolling partners in Buckeye — Our condensed consolidated balance sheets include a noncontrolling interests capital account that reflects the proportion of Buckeye owned by its partners other than us. Similarly, the ownership interests in Buckeye held by its partners other than us are reflected in our condensed consolidated statements of operations as income attributable to noncontrolling interests. These noncontrolling interest accounts are not reflected in Buckeye’s condensed consolidated financial statements.

	•		Our capital structure — In addition to incorporating the assets and liabilities of Buckeye, our condensed consolidated balance sheets include our own indebtedness and related debt placement costs, and the partners’ capital on our condensed consolidated balance sheets represent our partners’ capital as opposed to the capital reflected in Buckeye’s condensed consolidated balance sheets, which reflects the ownership interest of all its partners, including its owners other than us or Services Company. Consequently, our condensed consolidated statements of operations reflect additional interest expense, interest income and debt amortization expense that is not reflected in Buckeye’s condensed consolidated financial statements.

	•		Inclusion of Services Company — The financial statements of Services Company, which employs the employees who manage and operate our assets, are consolidated into our financial statements. The condensed consolidated financial statements of Buckeye do not include the financial statements of Services Company.

	•		Our general and administrative expenses — We incur general and administrative expenses that are independent from Buckeye’s operations and are not reflected in Buckeye’s condensed consolidated financial statements.

	•		Elimination of intercompany transactions — Intercompany obligations and payments among Buckeye and its consolidated subsidiaries, us and Services Company are reflected in Buckeye’s condensed consolidated financial statements but are eliminated in our condensed consolidated financial statements.

3334

Segment Results

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

Three Months Ended

~~Six~~Nine Months Ended

June 30,

September 30,

2010

2009

2010

2009

Revenues:

Pipeline Operations

99103,~~339~~621

9896,~~175~~714

~~195~~299,~~876~~497

~~197~~294,~~370~~084

Terminalling & Storage

4041,~~768~~900

2934,~~429~~036

83125,~~139~~039

6094,~~072~~108

Natural Gas Storage

21,~~249~~663

1628,~~672~~576

4668,~~655~~318

3160,~~749~~325

Energy Services

~~501~~566,~~949~~804

~~201~~258,~~676~~407

1,~~070~~636,~~151~~955

~~470~~728,~~156~~563

Development & Logistics

109,~~785~~082

87,~~805~~516

1827,~~300~~382

1725,~~930~~446

Intersegment

(68,~~814~~213

)

(31,~~537~~805

)

(1523,~~671~~884

)

(911,~~217~~022

)

Total revenues

~~667~~734,~~276~~857

~~351~~423,~~220~~444

12,~~398~~133,~~450~~307

~~768~~1,~~060~~191,504

Total costs and expenses: (1)

Pipeline Operations

54,~~804~~630

~~149~~54,~~260~~868

~~105~~160,~~976~~606

~~204~~258,~~008~~876

Terminalling & Storage

1618,~~854~~244

1816,~~314~~713

3654,~~100~~344

3855,~~300~~013

Natural Gas Storage

1718,~~947~~868

1020,~~855~~985

3958,~~902~~770

1940,~~768~~753

Energy Services

~~502~~564,~~420~~223

~~203~~252,~~108~~787

1,~~074~~638,~~019~~242

~~465~~718,~~372~~159

Development & Logistics

107,~~126~~592

85,~~652~~007

1624,~~694~~286

1621,~~396~~403

Intersegment

(68,~~814~~213

)

(31,~~537~~805

)

(1523,~~671~~884

)

(911,~~217~~022

)

Total costs and expenses

~~595~~655,~~337~~344

~~386~~348,~~652~~555

1,~~257~~912,~~020~~364

~~734~~1,~~627~~083,182

Depreciation and amortization:

Pipeline Operations

9,~~079~~263

8,~~984~~659

1827,~~032~~295

1726,~~823~~482

Terminalling & Storage

2,~~349~~386

1,~~866~~813

47,~~665~~051

35,~~588~~401

Natural Gas Storage

1,~~640~~643

1,~~243~~241

34,~~281~~924

23,~~702~~943

Energy Services

1,~~176~~331

~~983~~986

23,~~371~~702

12,~~960~~946

Development & Logistics

~~425~~439

~~483~~439

~~848~~1,287

~~850~~1,289

Total depreciation and amortization

1415,~~669~~062

13,~~559~~138

2944,~~197~~259

2640,~~923~~061

Asset impairment expense:

Pipeline Operations

—

~~72,540~~—

—

72,540

Reorganization expense:

Pipeline Operations

—

~~23,054~~518

—

23,~~054~~572

Terminalling and Storage

—

~~2,402~~163

—

2,~~402~~565

Natural Gas Storage

—

~~291~~91

—

~~291~~382

Energy Services

—

~~944~~206

—

~~944~~1,150

Development and Logistics

—

1,422

—

1,422

Development & Logistics

—

1,440

Total reorganization expense

—

~~28,113~~996

—

2829,~~113~~109

Operating income (loss):

Pipeline Operations

4448,~~535~~991

~~(51~~41,~~085~~846

)

89138,~~900~~891

(635,~~638~~208

)

Terminalling & Storage

23,~~914~~656

1117,~~115~~323

4770,~~039~~695

2139,~~772~~095

Natural Gas Storage

32,~~302~~795

57,~~817~~591

69,~~753~~548

1119,~~981~~572

Energy Services

~~(471~~2,581

)

(15,~~432~~620

)

(31,~~868~~287

)

410,~~784~~404

Development & Logistics

~~659~~1,490

~~153~~2,509

13,~~606~~096

14,~~534~~043

Total operating income (loss)

71,939

(35,432

)

141,430

33,433

Total operating income

79,513

74,889

220,943

108,322


(1)		Total costs and expenses includes depreciation and amortization, asset impairment expense and reorganization expense.

3435

Costs and expenses attributable to Buckeye, Services Company and us were as follows (in thousands):

Three Months Ended

~~Six~~Nine Months Ended

June 30,

September 30,

2010

2009

2010

2009

Attributable to Buckeye

~~593~~653,~~437~~261

~~385~~347,~~728~~479

1,~~253~~906,~~591~~852

~~732~~1,~~465~~079,944

Elimination of Buckeye deferred charge

(1,~~175~~174

)

(1,~~175~~174

)

(23,~~349~~523

)

(23,~~349~~523

)

Net effect of ESOP charges

1,~~211~~400

~~246~~564

23,~~086~~486

~~645~~1,209

Attributable to BGH

1,~~864~~857

1,~~853~~686

35,~~692~~549

35,~~866~~552

Total costs and expenses

~~595~~655,~~337~~344

~~386~~348,~~652~~555

1,~~257~~912,~~020~~364

~~734~~1,~~627~~083,182

Amounts attributable to us were as follows (in thousands):

Three Months Ended

~~Six~~Nine Months Ended

June 30,

September 30,

2010

2009

2010

2009

Payroll and payroll benefits

1,109

1,~~182~~086

23,~~225~~334

23,~~369~~455

Professional fees

~~311~~272

~~359~~103

~~432~~704

~~656~~759

Other

~~444~~476

~~312~~497

1,~~035~~511

~~841~~1,338

Total

1,~~864~~857

1,~~853~~686

35,~~692~~549

35,~~866~~552

Payroll and benefits costs include salaries and benefits for the four highest paid executives performing services on behalf of Buckeye based on a negotiated fee, as well as allocations of the cost of Buckeye personnel performing administrative services directly for us.

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

Three Months Ended

~~Six~~Nine Months Ended

June 30,

September 30,

2010

2009

2010

2009

Pipeline Operations (average bpd):

Gasoline

~~668~~663,900

~~685~~666,~~700~~900

~~639~~647,~~100~~400

~~659~~661,~~200~~700

Jet fuel

~~339~~350,~~300~~700

~~345~~350,~~100~~000

~~330~~337,~~900~~500

~~339~~342,~~200~~900

Diesel fuel

~~223~~237,~~100~~000

~~193~~199,~~200~~900

~~225~~229,~~300~~200

~~207~~205,~~500~~000

Heating oil

3635,~~100~~000

5233,~~200~~600

7461,~~800~~400

9172,~~500~~000

LPGs

2116,~~300~~700

1817,~~800~~700

2019,~~900~~500

1617,~~600~~000

NGLs

—

209,~~500~~600

—

2017,~~900~~100

Other products

3,~~700~~300

105,000

2,~~100~~600

119,~~700~~400

Total Pipeline Operations

1,~~292~~306,~~400~~600

1,~~325~~282,~~500~~700

1,~~293~~297,~~100~~600

1,~~346~~325,~~600~~100

Terminalling & Storage (average bpd):

Products throughput (1)

~~570~~566,~~000~~200

~~459~~472,~~800~~000

~~563~~564,200

470,~~200~~800

Energy Services (in thousands of gallons):

Sales volumes

~~235~~278,~~100~~000

~~134~~138,~~000~~500

~~502~~780,~~100~~000

~~317~~455,~~000~~500

(1) Reported quantities exclude transfer volumes, which are non-revenue generating transfers among our various terminals, and include volumes from the Albany terminal, which had not been previously reported in the 2009 periods. For the three and ~~six~~nine months ended ~~June~~September 30, 2009, we previously reported ~~489~~total products throughput of 486.45 thousand and ~~505~~491.19 thousand, respectively, which included transfer volumes and excluded volumes from the Albany terminal.

3536

Three Months Ended ~~June~~September 30, 2010 Compared to Three Months Ended ~~June~~September 30, 2009

Consolidated

Consolidated income attributable to unitholders. Consolidated income attributable to our unitholders was $11.59 million for the three months ended ~~June~~September 30, 2010 compared to $911.~~8 million~~1 million for the three months ended ~~June~~September 30, 2009. The increase in income attributable to our ~~unitholders~~ unitholders was due to increases in Buckeye’s quarterly cash distribution. As mentioned above, the ~~incentive~~ incentive distribution rights entitle us to receive amounts equal to specified percentages of the ~~incremental~~ incremental amount of cash distributed by Buckeye to the holders of Buckeye’s LP Units when target ~~distribution~~ distribution levels for a quarter are exceeded. As a result, increases in Buckeye’s distributions ~~cause~~ cause increases in income attributable to our unitholders. During the three months ended ~~June~~ September 30, 2010, Buckeye paid a $0.959625 per LP Unit distribution as compared to a $0.909125 per LP Unit distribution in the three months ended ~~June~~September 30, 2009, which resulted in an increase of $1.1 million in incentive distributions in the 2010 period as compared to the corresponding period in 2009.

Revenue. Revenue was $~~667~~734.39 million for the three months ended ~~June~~September 30, 2010, ~~which~~ which is an increase of $~~316~~311.15 million, or 9073.05%, from the three months ended ~~June~~September 30, 2009. ~~This~~ ~~overall~~The increase ~~was caused by increases~~ in ~~revenues~~revenue ~~in all segments~~ for the three months ended ~~June~~ September 30, 2010 as compared to the corresponding period in 2009 aswas ~~follows~~caused primarily by the following:

• an increase of $~~300~~308.24 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~~September 30, 2010 as compared to the corresponding period in 2009; • an increase of $117.49 million in revenue from the Terminalling & Storage segment, resulting from increased ~~throughput~~revenue ~~volumes,~~from ~~increased~~terminals ~~fees~~acquired in November 2009, ~~storage~~internal growth projects and ~~rental~~increased ~~revenue~~throughput volumes, including $1.54 million in storage fees from previously underutilized tankage identified in connection with our best practices initiative and other marketing opportunities~~, increased revenue from the contribution of terminals acquired in November 2009 and favorable settlement experience~~; • an increase of $46.59 million in revenue from the ~~Natural~~Pipeline ~~Gas~~Operations ~~Storage~~ segment, resulting ~~primarily~~ from ~~higher~~the ~~fees~~benefit ~~from~~of ~~hub~~higher ~~services~~tariff ~~transactions recognized as revenue~~rates, ~~partially~~increased ~~offset by reduced lease~~ revenues asfrom athe ~~result~~contribution of ~~general~~pipeline ~~market~~assets ~~conditions,~~acquired ~~including reduced market-based fees charged for storage services as a result of high storage inventory levels~~ in ~~the~~November ~~western region~~2009, ~~above~~increased ~~normal~~other ~~temperatures~~revenues and ~~general~~more ~~uncertainty~~favorable ~~regarding~~settlement ~~the economic recovery~~experience; and • an increase of $21.06 million in revenue from the Development & Logistics segment, resulting primarily from the ~~sale~~assignment of ~~ammonia~~certain ~~linefill;~~service ~~and~~contracts ~~• an increase of $1.1 million in revenue~~ from the Pipeline Operations segment, ~~resulting~~to ~~from~~ the ~~benefit~~Development of& ~~higher~~Logistics ~~tariffs,~~segment ~~favorable settlement experience, increased revenues from the contribution of pipeline assets acquired~~ in ~~November~~April ~~2009 and increased other revenues~~2010.

~~Total~~The ~~Costs and Expenses. Total costs and expenses were $595.3 million for the three months ended June 30, 2010, which is an~~ increase ~~of $208.6 million, or 54.0%, from the corresponding period~~ in ~~2009.~~revenue ~~Total~~was ~~costs~~partially ~~and~~offset ~~expenses reflect~~by:

• ana ~~increase~~decrease inof ~~refined petroleum product prices, which, coupled with an increase in volumes sold, resulted in a~~ $~~299~~6.79 million ~~increase~~ in ~~the~~revenue ~~Energy~~from ~~Services segment’s cost of product sales in~~ the ~~2010 period as compared to the 2009 period; • an increase of $7.1 million in the~~ Natural Gas Storage segment’s, ~~costs and expenses~~ resulting primarily from ~~higher~~lower ~~costs~~fees ~~associated~~from ~~with~~ hub services transactions ~~recognized~~ as ~~expense~~a ~~caused~~result ~~primarily~~of by general market conditions, asincluding ~~discussed~~reduced ~~above;~~market-based •fees ancharged ~~increase~~for instorage ~~the~~services ~~Development~~as &a ~~Logistics~~result ~~segment’s costs and expenses due to $2.4 million~~ of ~~expenses~~low ~~related~~natural togas ~~the~~prices, ~~write-off~~compressed inseasonal ~~the~~spreads, ~~2010~~lower ~~period~~recontracting ofrates, aabove ~~portion~~normal oftemperatures ~~an outstanding receivable balance~~ and ~~other~~general ~~costs~~uncertainty ~~associated~~regarding ~~with a customer bankruptcy (see Note 3 in~~ the ~~Notes~~economic ~~to Unaudited Condensed Consolidated Financial Statements for further discussion); and~~recovery.

36 Total Costs and Expenses. Total costs and expenses were $655.3 million for the three months ended September 30, 2010, which is an increase of $306.7 million, or 88.0%, from the corresponding period in 2009. Total costs and expenses reflect:

	•		an increase of $310.4 million in the Energy Services segment’s cost of product sales in the 2010 period as compared to the 2009 period, primarily as a result of increased refined petroleum product prices and increased volumes sold;

	•		an increase of $2.6 million in costs and expenses of the Development & Logistics segment, primarily due to the assignment of certain service contracts from the Pipeline Operations segment to the Development & Logistics segment and higher income tax expense, partially offset by reduced construction contract activity;

	•		an increase of $1.5 million in costs and expenses of the Terminalling & Storage segment, resulting primarily from higher operating expenses for terminals acquired in November 2009 and certain environmental remediation expenses; and

• an increase of $12.0 million in depreciation and amortization, primarily ~~due to expense~~ on assets placed in service in the second half of 2009 in connection with the Kirby Hills Phase II expansion project, ~~and~~ certain internal-use software, ~~which was~~ placed in service in the fourth quarter of 2009 and on assets acquired in November 2009, and an increase of $10.17 million in non-cash unit-based compensation expense.

Total costs and expenses in the 2009 period ~~include~~includes the recognition of ~~a non-cash~~ $~~72.5 million asset impairment expense in the Pipeline Operations segment related to the Buckeye NGL Pipeline and $28.~~1.0 million of expenses across all segments associated with organizational restructuring. ~~These two charges were the primary cause of a partially offsetting decrease in total costs and expenses for the 2010 period as compared to the 2009 period.~~ Total costs and expenses for the three months ended ~~June~~September 30, 2010 reflect the effectiveness of cost management efforts we implemented in 2009. ~~Largely~~As as a result of these efforts, costs ~~decreased~~and byexpenses reflected a savings of approximately $42.63 million during the three months ended ~~June~~September 30, 2010 as compared to the corresponding period in 2009.

Total costs and expenses also reflect the following decreases:

	•		a decrease of $2.1 million in costs and expenses of the ~~Pipeline~~Natural ~~Operations~~Gas Storage segment, resulting ~~substantially~~ from alower ~~decrease~~costs ~~related~~associated towith ~~the~~hub ~~asset~~services ~~impairment~~transactions ~~expense and the organizational restructuring charges~~ recognized ~~in the 2009 period~~ as ~~discussed~~an above and lower payroll and benefits costs, which was primarily attributable to the organizational restructuring that occurred in 2009 and resulted in reduced headcount, partially offset by increased integrity program expenses and increased professional feesexpense; and
	•		a decrease of $0.3 million in costs and expenses of the ~~Terminalling~~Pipeline &Operations ~~Storage~~ segment, resulting ~~primarily~~substantially from a decrease related to ~~expenses~~the ~~for~~ organizational restructuring charges recognized in the 2009 period ~~and~~as ~~decreased~~discussed ~~payroll and benefits costs~~above, ~~partially~~lower ~~offset by higher~~ environmental ~~remediation~~ expenses and ~~higher~~lower operating ~~expenses~~power ~~for~~costs, ~~terminals~~partially ~~acquired~~offset inby ~~November~~increased ~~2009~~project costs.

Operating Income. Operating income was $7179.95 million for the three months ended ~~June~~ September 30, 2010 compared to operating ~~loss~~income of $3574.49 million for the three months ended ~~June~~ September 30, 2009. Interest and debt expense increased by $51.27 million for the three months ended ~~June~~ September 30, 2010 as compared to the corresponding period in 2009, which increase was largely attributable to the issuance in August 2009 of $275.0 million aggregate principal amount of 5.500% Notes due 2019 and higher outstanding borrowings under the BES Credit Agreement, partially offset by lower outstanding borrowings under Buckeye’s unsecured revolving credit agreement (the “Credit Facility”). In addition, depreciation and amortization increased by $1.0 million, primarily due to expense on assets placed in service in the second half of 2009 in connection with the Kirby Hills Phase II expansion project, and certain internal-use software, which was placed in service in the fourth quarter of 2009. Income from equity investments decreased by $0.34 million for the three months ~~ended~~ ~~June~~ended September 30, 2010 as compared to the corresponding period in 2009. Other revenue and expense items impacting operating income are discussed above.

Income attributable to noncontrolling interests. Income attributable to noncontrolling interests, which represents the allocation of Buckeye’s income to its limited partner ~~interest~~interests not owned by us or Services Company, was $4149.90 million for the three months ended ~~June~~September 30, 2010 as compared to ~~a loss of~~ $5847.23 million in the corresponding period in 2009~~, primarily due to the recognition of the asset impairment expense and the organizational restructuring charges in the 2009 period~~.

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

Pipeline Operations

Revenue. Revenue from the Pipeline Operations segment was $99103.36 million for the ~~three~~ three months ended ~~June~~September 30, 2010, which is an increase of $16.19 million, or 17.21%, from the ~~corresponding~~ corresponding period in 2009. Revenues increased due to ~~the~~favorable ~~benefit~~settlement experience of ~~higher~~$2.8 million, ~~tariffs~~a of $12.96 million, ~~the result~~benefit offrom higher tariff rates resulting from overall average tariff rate increases of approximately ~~3.8% implemented on July 1, 2009 and~~ 2.616% implemented on May 1, 2010~~. In addition~~, ~~favorable~~an ~~settlement~~increase ~~experience~~ of $1.09 million, in other ~~increased~~pipeline revenues, increased revenue of $0.86 million from pipeline assets acquired in November 2009 and ~~increased~~a 1.9% increase in transportation volumes, resulting in an increase of $0.3 million in ~~other~~transportation revenues. These increases in revenue ofwere partially offset by reduced revenues of $21.43 million ~~contributed~~from contract service activities at customer facilities connected to our refined petroleum products pipelines pursuant to the assignment of such service contracts to the Development & Logistics segment. In addition, the increase in ~~revenues.~~transportation ~~These~~volumes ~~increases~~were partially offset by a decrease in ~~revenue~~transportation volumes related to the sale of the Buckeye NGL ~~were~~Pipeline on January 1, 2010 (see Note 2 in the Notes to Unaudited Condensed Consolidated Financial Statements).

partially offset by a $3.2 million decrease related to a 2.5% decrease in transportation volumes due in part to the sale of the Buckeye NGL Pipeline on January 1, 2010 and reduced revenues of $1.3 million from a product supply arrangement with a wholesale distributor and 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.

Total Costs and Expenses. Total costs and expenses from the Pipeline Operations segment were $54.8 million for the three months ended June 30, 2010, which is a decrease of $94.5 million, or 63.3%, from the corresponding period in 2009. Total costs and expenses for the 2009 period include a $72.5 million non-cash asset impairment expense and $23.1 million of expense related to an organizational restructuring. These charges in the 2009 period were the primary reason that costs and expenses in the 2009 period were 63.3% higher than in the 2010 period. Total costs and expenses for the three months ended June 30, 2010 also reflect an increase of $2.1 million in integrity program expenses, primarily due to increased levels of pipeline maintenance activities, and an increase of $0.7 million in professional fees, partially offset by a decrease of $1.3 million in payroll and benefits costs primarily related to our best practices initiative in 2009, and a decrease of $1.2 million in operating power costs due to lower transportation volumes and power contract renegotiations as part of our best practices initiative.

Operating Income. Operating income from the Pipeline Operations segment was $44.5 million for the three months ended June 30, 2010 compared to an operating loss of $51.1 million for the three months ended June 30, 2009. Income from equity investments decreased by $0.3 million for the three months ended June 30, 2010 as compared to the corresponding period in 2009. Other revenue and expense items impacting operating income are discussed above.

Terminalling & Storage

Revenue. Revenue from the Terminalling & Storage segment was $40.8 million for the three months ended June 30, 2010, which is an increase of $11.4 million, or 38.5%, from the corresponding period in 2009. Approximately $8.7 million of the increase resulted primarily from terminals acquired in November 2009, internal growth projects, increased throughput volumes, higher fees, higher storage and rental revenue, including $1.5 million in storage fees from previously underutilized tankage identified in connection with our best practices initiative and other marketing opportunities, and increased butane-blending revenue. Also contributing to the improved revenue was an increase of $2.6 million in settlement experience reflecting the favorable impact of higher refined petroleum product prices during the three months ended June 30, 2010 as compared to the corresponding period in 2009. In addition to the 13.8% increase in volumes resulting from the acquisition of terminals in November 2009, terminalling volumes increased 10.2% for the three months ended June 30, 2010 as compared to the corresponding period in 2009, largely due to increased ethanol throughput volumes.

Total Costs and Expenses. Total costs and expenses from the Terminalling & Storage segment were $16.9 million for the three months ended June 30, 2010, which is a decrease of $1.4 million, or 8.0%, from the corresponding period in 2009. The decrease in total costs and expenses in the 2010 period as compared to the 2009 period is due to a $2.4 million decrease related to expenses for organizational restructuring recognized in the 2009 period and a $1.1 million decrease in payroll and benefits costs primarily related to our best practices initiative in 2009. These decreases were partially offset by a $0.8 million increase in environmental remediation expenses, a $0.6 million increase in operating expenses for terminals acquired in November 2009 and a $0.4 million increase in depreciation and amortization.

Operating Income. Operating income from the Terminalling & Storage segment was $23.9 million for the three months ended June 30, 2010 compared to operating income of $11.1 million for the three months ended June 30, 2009. Depreciation and amortization increased by $0.4 million for the three months ended June 30, 2010 as a result of the terminals acquired in November 2009. Other revenue and expense items impacting operating income are discussed above.

Total Costs and Expenses. Total costs and expenses from the Pipeline Operations segment were $54.6 million for the three months ended September 30, 2010, which is a decrease of $0.3 million, or 0.4%, from the corresponding period in 2009. Total costs and expenses for the 2009 period include $0.5 million of expense related to an organizational restructuring. This charge in the 2009 period was the primary reason that costs and expenses in the 2009 period were 0.4% higher than in the 2010 period. Total costs and expenses for the three months ended September 30, 2010 also reflect a decrease of $1.3 million in contract service activities due to the assignment of certain service contracts from the Pipeline Operations segment to the Development & Logistics segment, a decrease of $0.6 million in environmental expenses, a decrease of $0.3 million in pipeline integrity program expenses, a decrease of $0.2 million in operating power costs, primarily due to power contract renegotiations as part of our best practices initiative and a decrease of $0.2 million in property taxes. These decreases were offset by an increase of $1.6 million in professional fees, outside service costs and other project costs and an increase of $0.7 million in depreciation and amortization expense as a result of pipeline assets acquired in November 2009.

Operating Income. Operating income from the Pipeline Operations segment was $49.0 million for the three months ended September 30, 2010 compared to operating income of $41.8 million for the three months ended September 30, 2009. Income from equity investments decreased by $0.4 million for the three months ended September 30, 2010 as compared to the corresponding period in 2009. Other revenue and expense items impacting operating income are discussed above.

Terminalling & Storage

Revenue. Revenue from the Terminalling & Storage segment was $41.9 million for the three months ended September 30, 2010, which is an increase of $7.9 million, or 23.1%, from the corresponding period in 2009. The increase resulted primarily from terminals acquired in November 2009, internal growth projects, increased throughput volumes, higher fees, higher storage and rental revenue, including $1.4 million in storage fees from previously underutilized tankage identified in connection with our best practices initiative and other marketing opportunities. In addition to the 15.6% increase in volumes resulting from the acquisition of terminals in November 2009, terminalling volumes increased 4.4% for the three months ended September 30, 2010 as compared to the corresponding period in 2009, primarily due to increased jet fuel, diesel and ethanol throughput volumes.

Total Costs and Expenses. Total costs and expenses from the Terminalling & Storage segment were $18.2 million for the three months ended September 30, 2010, which is an increase of $1.5 million, or 9.2%, from the corresponding period in 2009. The increase in total costs and expenses in the 2010 period as compared to the 2009 period is due to a $0.9 million increase in operating expenses and a $0.6 million increase in depreciation and amortization, both as a result of the terminals acquired in November 2009, and a $0.4 million increase in environmental remediation expenses. These increases in total costs and expenses were partially offset by a $0.5 million decrease in payroll and benefits costs primarily related to our best practices initiative in 2009.

Operating Income. Operating income from the Terminalling & Storage segment was $23.7 million for the three months ended September 30, 2010 compared to operating income of $17.3 million for the three months ended September 30, 2009. Other revenue and expense items impacting operating income are discussed above.

Natural Gas Storage

Revenue. Revenue from the Natural Gas Storage segment was $21.27 million for the three months ended ~~June~~September 30, 2010, which is ana ~~increase~~decrease of $46.59 million, or 2724.52%, from the ~~corresponding~~ corresponding period in 2009. This overall ~~increase~~decrease is attributable to ~~greater~~lower underlying volume and lower ~~higher~~ fees recognized as revenue for hub services provided during the three months ended ~~June~~ September 30, 2010. The fees for hub services agreements are based on the relative market prices of natural gas over different delivery periods. A positive market price spread results in receipt of a fee from the customer that is reflected as transportation and other services revenue. A negative market price spread results in payment of a fee to the customer that is reflected as cost of natural gas storage services. These fees are recognized as revenue or cost of natural gas storage services ratably as the underlying services are provided or utilized. Such agreements allow us to maximize the daily utilization of the natural gas storage facility and to attempt to capture value from seasonal price differences in the natural gas markets. During the three months ended ~~June~~ September 30, 2010 and 2009, there were ~~165~~174 and ~~150~~119 outstanding hub service contracts, respectively, for which revenue was being recognized ratably. Market conditions ~~contributed~~resulted toin ~~higher~~ lower fees of $56.23 million for hub service agreements recognized as revenue during the three months ended June 30, 2010 compared to the same period in 2009, partially offset by reduced market-based fees charged for storage services as a result of high storage inventory levels in the western region, above normal temperatures and general uncertainty regarding the economic recovery. Additionally, lease revenue decreased $0.6 million for the three months ended June 30, 2010, as a decrease in the fee charged for each volumetric unit of storage capacity leased was partially offset by increased storage capacity from the commissioning of the Kirby Hills Phase II expansion project, which was placed in service in June 2009.

Total Costs and Expenses. Total costs and expenses from the Natural Gas Storage segment were $17.9 million for the three months ended June 30, 2010, which is an increase of $7.1 million, or 65.3%, from the corresponding period in 2009. The primary driver of the increase in expenses is an increase in hub services fees paid to customers for hub service activities. As stated above, hub service fees are based on the relative market prices of natural gas over different delivery periods; a negative market price spread results in payment of a fee to the customer that is reflected as cost of natural gas storage services ratably as those services are provided. Other operating expenses increased $0.7 million, primarily due to increased fuel costs, professional fees, maintenance materials expense and rental expense. Total costs and expenses also include an increase of $0.4 million in depreciation and amortization, partially offset by a decrease of $0.3 million related to an organizational restructuring recognized in the 2009 period.

Operating Income. Operating income from the Natural Gas Storage segment was $3.3 million for the three months ended June 30, 2010 compared to operating income of $5.8 million for the three months ended June 30, 2009. Depreciation and amortization increased by $0.4 million for the three months ended June 30, 2010 from the corresponding period in 2009 due to expense on assets placed in service in the second half of 2009 in connection with the Kirby Hills Phase II expansion project. Other revenue and expense items impacting operating income are discussed above.

Energy Services

Revenue. Revenue from the Energy Services segment was $501.9 million for the three months ended June 30, 2010, which is an increase of $300.2 million, or 148.9%, from the corresponding period in 2009. This increase was primarily due to an increase in refined petroleum product prices, which correspondingly increased the cost of product sales, and an increase of 75.4% in sales volumes.

Total Costs and Expenses. Total costs and expenses from the Energy Services segment were $502.4 million for the three months ended June 30, 2010, which is an increase of $299.3 million, or 147.4%, from the corresponding period in 2009. The increase in total costs and expenses was primarily due to an increase of $299.7 million in cost of product sales as a result of increased volumes sold and an increase in refined petroleum product prices, an increase of $0.4 million in payroll related costs and an increase of $0.4 million in bad debt expense, partially offset by a decrease of $0.7 million in maintenance materials expense and professional fees and a decrease of $0.9 million related to an organizational restructuring recognized in the 2009 period.

~~Operating~~agreements ~~Income~~recognized ~~(loss).~~as ~~Operating~~revenue ~~loss~~during ~~from~~ the ~~Energy Services segment was $0.5 million for the~~ three months ended ~~June~~September 30, 2010 compared to the ansame ~~operating~~period ~~loss~~in of2009, ~~$1.4 million~~including reduced market-based fees charged for storage services as a ~~the~~result ~~three~~of ~~months~~low ~~ended~~natural ~~June 30~~gas prices, ~~2009.~~compressed ~~Depreciation~~seasonal spreads, lower recontracting rates, above normal temperatures and ~~amortization~~general ~~increased~~uncertainty byregarding the economic recovery. Additionally, lease revenue decreased $0.26 million for the three months ended ~~June~~September 30, 2010, ~~from~~as ~~the~~a ~~corresponding~~decrease ~~period~~ in ~~2009~~the fee ~~due~~charged tofor ~~amortization~~each volumetric unit of ~~certain~~ ~~internal-use~~storage ~~software~~capacity ~~that~~leased was ~~placed~~partially inoffset ~~service~~by inincreased storage ~~the~~capacity ~~fourth~~from ~~quarter~~the commissioning of ~~2009.~~the ~~Other revenue~~Kirby ~~and~~Hills ~~expense~~Phase ~~items~~II ~~impacting~~expansion ~~operating~~project, ~~income~~which ~~(loss) are~~was placed ~~discussed~~in ~~above~~service in June 2009.

Total Costs and Expenses. Total costs and expenses from the Natural Gas Storage segment were $18.9 million for the three months ended September 30, 2010, which is a decrease of $2.1 million, or 10.1%, from the corresponding period in 2009. The primary driver of the decrease in expenses is a decrease in hub services fees paid to customers for hub service activities. As stated above, hub service fees are based on the relative market prices of natural gas over different delivery periods; a negative market price spread results in payment of a fee to the customer that is reflected as cost of natural gas storage services ratably as those services are provided. Other operating expenses decreased $3.2 million, primarily due to lower fuel costs and professional fees. Total costs and expenses also include an increase of $0.4 million in depreciation and amortization, primarily related to assets placed in service in the second half of 2009 in connection with the Kirby Hills Phase II expansion project.

Operating Income. Operating income from the Natural Gas Storage segment was $2.8 million for the three months ended September 30, 2010 compared to operating income of $7.6 million for the three months ended September 30, 2009. Other revenue and expense items impacting operating income are discussed above.

Energy Services

Revenue. Revenue from the Energy Services segment was $566.8 million for the three months ended September 30, 2010, which is an increase of $308.4 million, or 119.3%, from the corresponding period in 2009. This increase was primarily due to an increase in refined petroleum product prices, which correspondingly increased the cost of product sales, and an increase of 100.7% in sales volumes.

Total Costs and Expenses. Total costs and expenses from the Energy Services segment were $564.2 million for the three months ended September 30, 2010, which is an increase of $311.4 million, or 123.2%, from the corresponding period in 2009. The increase in total costs and expenses was primarily due to an increase of $310.4 million in cost of product sales as a result of increases in volumes sold, refined petroleum product prices and payroll related costs. Depreciation and amortization increased by $0.3 million for the three months ended September 30, 2010 from the corresponding period in 2009 due to amortization of certain internal-use software placed in service in the fourth quarter of 2009.

Operating Income. Operating income from the Energy Services segment was $2.6 million for the three months ended September 30, 2010 compared to operating income of $5.6 million for the three months ended September 30, 2009. Other revenue and expense items impacting operating income are discussed above.

Development & Logistics

Revenue. Revenue from the Development & Logistics segment, ~~which consists principally of our contract operations and engineering services for third-party pipelines,~~ was $109.81 million for the three months ended ~~June~~September 30, 2010, which is an increase of $21.06 million, or 2220.58%, from the corresponding period in 2009. The increase in revenue was ~~partially~~primarily due to aan increase of $1.5 million ~~increase~~ in ~~other~~operating ~~revenue,~~service ~~primarily~~revenues ~~from~~and ~~the~~an ~~recognition~~increase of $10.14 million ofin ~~revenue~~construction ~~related~~contract ~~to the sale of~~and ~~ammonia~~other ~~linefill. In addition, operating service~~ revenues ~~increased $2.2 million~~ from the 2009 period,. Both increases were primarily due to the assignment of certain service contracts from the Pipeline Operations segment to the Development & Logistics segment, and an increase of $0.5 million in rental and other revenues. These increases in revenue were partially offset by the completion and non-replacement of certain construction projects in 2009, resulting in a $20.18 million reduction in ~~certain~~ construction contract revenues.

Total Costs and Expenses. Total costs and expenses from the Development & Logistics segment were $10.1 million for the three months ended June 30, 2010, which is an increase of $1.4 million, or 17.0%, from the corresponding period in 2009. The increase in total costs and expenses was the result of the recognition of $2.4 million of expenses related to the write-off in the 2010 period of a portion of an outstanding receivable balance and other costs associated with a customer bankruptcy, and increased operating services activities discussed above, partially offset by reduced construction contract activity and lower income tax expense. Total costs and expenses also include a decrease of $1.4 million related to an organizational restructuring recognized in the 2009 period.

Operating Income. Operating income from the Development & Logistics segment was $0.7 million for the three months ended June 30, 2010 compared to operating income of $0.2 million for the three months ended June 30, 2009. Income tax expense decreased by $0.7 million for the three months ended June 30, 2010 due to the recognition of a tax benefit of $0.6 million primarily related to the write-off of a portion of an outstanding receivable balance and other costs associated with a customer bankruptcy as discussed above. Other revenue and expense items impacting operating income are discussed above.

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

Consolidated

Consolidated income attributable to our unitholders was $22.8 million for the six months ended June 30, 2010 compared to $19.9 million for the six months ended June 30, 2009. The increase in income attributable to our unitholders was due to increases in Buckeye’s quarterly cash distribution. As mentioned above, the incentive distribution rights entitle us to receive amounts equal to specified percentages of the incremental amount of cash distributed by Buckeye to the holders of Buckeye’s LP Units when target distribution levels for a quarter are exceeded. As a result, increases in Buckeye’s distributions cause increases in income attributable to our unitholders. During the six months ended June 30, 2010, Buckeye paid aggregate distributions of $1.8875 per LP Unit as compared to $1.7875 per LP Unit in the six months ended June 30, 2009, which resulted in an increase of $2.9 million in incentive distributions in the first six months of 2010 as compared to the corresponding period in 2009.

Revenue. Revenue was $1,398.5 million for the six months ended June 30, 2010, which is an increase of $630.4 million, or 82.1%, from the six months ended June 30, 2009. The increase in revenue for the six months ended June 30, 2010 as compared to the corresponding period in 2009 was caused primarily by the following:

• an increase of $600.0 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, 2010 as compared to the corresponding period in 2009;

• Total anCosts ~~increase~~and ~~of $23~~Expenses.0 ~~million~~Total incosts ~~revenue~~and expenses from the ~~Terminalling~~Development & ~~Storage~~ Logistics segment, ~~resulting~~were ~~from~~$7.6 million ~~increased~~for ~~throughput~~the ~~volumes,~~three ~~increased~~months ~~fees~~ended September 30, ~~storage~~2010, ~~and~~which ~~rental~~is ~~revenue,~~an ~~including~~increase of $3.2 .6 million, inor ~~storage fees from previously underutilized tankage identified in connection with our best practices initiative and other marketing opportunities~~51.6%, ~~increased revenue~~ from the ~~contribution~~corresponding ofperiod ~~terminals acquired~~ in ~~November~~ 2009. ~~and~~The ~~favorable settlement experience; • an~~ increase ofin ~~$15.0~~total ~~million~~costs inand expenses ~~revenue~~was ~~from~~ the ~~Natural~~result ~~Gas~~of ~~Storage~~the ~~segment,~~increased ~~resulting~~operating ~~primarily from higher fees from hub~~ services ~~transactions~~activities ~~recognized~~discussed asabove ~~revenue;~~ and •higher income antax ~~increase~~expense of $0.4 6 million indue ~~revenue~~to ~~from~~higher ~~the~~earnings ~~Development~~in &the ~~Logistics~~current ~~segment~~period, ~~resulting~~partially ~~primarily~~offset by ~~from~~reduced ~~the~~construction ~~sale~~contract ~~of ammonia linefill~~activity.

~~The~~Operating ~~increase~~Income. inOperating ~~revenue~~income from the Development & Logistics segment was ~~partially~~$1.5 million ~~offset~~for ~~by:~~the three months ended September 30, 2010 compared to operating income of $2.5 million for the three months ended September 30, 2009. Other revenue and expense items impacting operating income are discussed above.

•Nine aMonths ~~decrease~~Ended ~~of $1.5 million in revenue from the Pipeline Operations segment~~September 30, ~~resulting~~2010 ~~primarily~~Compared ~~from~~to ~~lower~~Nine ~~transportation~~Months ~~volumes~~Ended ~~and lower other revenue~~September 30, ~~partially offset by increased tariffs, favorable settlement experience and increased revenues from the contribution of pipeline assets acquired in November~~ 2009.

Total Costs and Expenses. Total costs and expenses were $1,257.0 million for the six months ended June 30, 2010, which is an increase of $522.4 million, or 71.1%, from the corresponding period in 2009. Total costs and expenses reflect: Consolidated

• Consolidated anincome ~~increase~~attributable into ~~refined~~our ~~petroleum~~unitholders ~~product~~was ~~prices,~~$34.7 million ~~which,~~for ~~coupled~~the ~~with~~nine anmonths ended ~~increase in volume sold~~September 30, ~~resulted~~2010 incompared ato $~~609~~31.6 0 million ~~increase~~for in the ~~Energy~~nine ~~Services~~months ~~segment’s~~ended ~~cost~~September 30, of2009. The ~~product~~increase ~~sales~~ in ~~the~~income ~~2010~~attributable ~~period as compared~~ to ~~the~~our ~~2009~~unitholders ~~period;~~was •due anto ~~increase~~increases ~~of $20.2 million~~ in ~~the Natural Gas Storage segment~~Buckeye’s ~~costs~~quarterly cash ~~and~~distribution. ~~expenses~~As ~~resulting~~mentioned ~~from~~above, ~~higher~~the ~~costs~~incentive ~~associated~~distribution ~~with~~rights ~~hub~~entitle ~~services~~us ~~transactions~~to ~~recognized~~receive amounts asequal ~~expense~~to ~~caused~~specified ~~primarily~~percentages byof ~~general~~the ~~market~~incremental ~~conditions;~~amount ~~• an increase~~ of ~~$2.3~~cash ~~million~~distributed inby ~~depreciation~~Buckeye ~~and amortization, primarily due~~ to ~~expense on assets placed in service in~~ the ~~second~~holders ~~half~~ of ~~2009~~Buckeye’s inLP ~~connection~~Units ~~with~~when ~~the~~target ~~Kirby~~distribution ~~Hills~~levels ~~Phase~~for IIa ~~expansion~~quarter ~~project,~~are ~~and~~exceeded. ~~certain~~As ~~internal-use software~~a result, ~~which~~increases ~~was placed~~ in ~~service~~Buckeye’s indistributions ~~the~~cause ~~fourth~~increases ~~quarter~~in ofincome ~~2009,~~attributable ~~and~~to ~~an increase of $2~~our unitholders.3 ~~million~~During inthe ~~non-cash~~nine ~~unit-based~~months ~~compensation~~ended ~~expense;~~September 30, ~~and~~2010, •Buckeye anpaid ~~increase~~aggregate distributions of $02.385 ~~million~~per inLP ~~the~~Unit ~~Development~~as &compared ~~Logistics~~to ~~segment’s costs and expense reflecting~~ $2.470 ~~million~~per ofLP ~~expenses~~Unit ~~related to the write-off~~ in the ~~2010~~nine ~~period~~months ofended aSeptember 30, ~~portion~~2009, which ofresulted ~~an outstanding receivable balance and other costs associated with a customer bankruptcy and increased operating services activities~~ in ~~the~~an ~~2010~~increase ~~period, partially offset by a decrease~~ of $1.4 .1 million ~~related~~in toincentive andistributions ~~organizational restructuring recognized~~ in the ~~2009~~first ~~period~~nine ~~and~~months of ~~reduced~~2010 ~~construction~~as ~~contract~~compared ~~activity~~to in the ~~2010~~corresponding period in 2009.

~~Total~~Revenue. ~~costs~~Revenue ~~and~~was ~~expenses in the 2009 period include the recognition of a non-cash~~ $722,133.5 3 million ~~asset~~for ~~impairment~~the ~~expense~~nine inmonths ~~the~~ended ~~Pipeline~~September 30, ~~Operations segment~~2010, which ~~related~~is toan ~~the~~increase ~~Buckeye~~of ~~NGL Pipeline and~~ $28941.18 million, ofor ~~expenses across all segments associated with organizational restructuring~~79.0%, ~~These~~from ~~two charges were~~ the ~~primary~~nine ~~cause of a partially offsetting decrease in total costs and expenses for the 2010 period as compared to the 2009 period. Total costs and expenses for the six~~ months ended ~~June~~September 30, ~~2010 reflect the effectiveness of cost management~~2009. ~~efforts~~The weincrease ~~implemented~~ in ~~2009.~~revenue ~~Largely~~for ~~as result of these efforts, costs decreased by approximately $9.4 million during~~ the ~~six~~nine months ended ~~June~~September 30, 2010 as compared to the corresponding period in 2009. was caused primarily by the following:

~~Total~~• ~~costs~~an increase of $908.4 million in revenue from the Energy Services segment, resulting from an overall increase in refined petroleum product prices and ~~expenses~~volumes ~~also~~of ~~reflect~~product sold during the ~~following~~nine ~~decreases:~~ months ended September 30, 2010 as compared to the corresponding period in 2009; • an increase of $30.9 million in revenue from the Terminalling & Storage segment, resulting from increased revenue from terminals acquired in November 2009, increased throughput volumes, increased fees, storage and rental revenue, including $4.6 million in storage fees from previously underutilized tankage identified in connection with our best practices initiative and other marketing opportunities and favorable settlement experience; • an increase of $8.0 million in revenue from the Natural Gas Storage segment, resulting primarily from higher fees from hub services transactions recognized as revenue; • an increase of $5.4 million in revenue from the Pipeline Operations segment, resulting primarily from the benefit of higher tariff rates, favorable settlement experience and increased revenues from pipeline assets acquired in November 2009, partially offset by the impact of lower transportation volumes; and • an increase of $2.0 million in revenue from the Development & Logistics segment, resulting primarily from the sale of ammonia linefill and from the assignment of certain service contracts from the Pipeline Operations segment to the Development & Logistics segment in April 2010.

• Total aCosts ~~decrease~~and inExpenses. Total costs and expenses ofwere ~~the Pipeline Operations segment~~$1,912.3 million ~~resulting~~for ~~substantially from a decrease related to~~ the ~~asset~~nine months ~~impairment~~ended ~~expense~~September 30, ~~and~~2010, ~~the~~which ~~organizational~~is ~~restructuring~~an ~~charges~~increase ~~recognized~~of in$829.0 million, ~~the~~or ~~2009 period as discussed above and lower payroll and benefits costs~~76.6%, ~~which~~from ~~was primarily attributable to~~ the corresponding ~~organizational~~period ~~restructuring that occurred~~ in 2009. ~~and~~Total ~~resulted in reduced headcount, as well as from lower contract service activities, lower environmental remediation expenses, lower contract service activities and lower operating power~~ costs ~~due to lower transportation volumes~~ and ~~power~~expenses ~~contract renegotiations as part of our best practices initiative; and~~reflect:

•

an increase in refined petroleum product prices, which, coupled with an increase in volume sold, resulted in a $920.0 million increase in the Energy Services segment’s cost of product sales in the 2010 period as compared to the 2009 period;

• aan ~~decrease~~increase of $18.0 million in costs and expenses of the ~~Terminalling~~Natural &Gas Storage segment, resulting ~~primarily~~ from ahigher ~~decrease~~costs ~~related~~associated towith ~~expenses~~hub ~~for~~services ~~organizational~~transactions ~~restructuring~~ recognized inas ~~the~~expense ~~2009~~caused ~~period,~~primarily ~~lower environmental remediation expenses and lower payroll and benefits costs, partially offset~~ by ~~higher~~general ~~operating~~market ~~expense for terminals acquired in November 2009 and higher bad debt expense.~~conditions;

Operating Income. Operating income was $141.4 million for the six months ended June 30, 2010 compared to operating income of $33.5 million for the six months ended June 30, 2009. Interest and debt expense increased by $9.4 million for the six months ended June 30, 2010 as compared to the corresponding period in 2009, which increase was largely attributable to the issuance in August 2009 of $275.0 million aggregate principal amount of 5.500% Notes due 2019, higher outstanding borrowings under the BES Credit Agreement and lower interest capitalized on construction projects, partially offset by lower outstanding borrowings under Buckeye’s Credit Facility. In addition, depreciation and amortization increased by $2.3 million, primarily due to expense on assets placed in service in the second half of 2009 in connection with the Kirby Hills Phase II expansion project and certain internal-use software, which was placed in service in the fourth quarter of 2009. Income from equity investments increased by $0.2 million for the six months ended June 30, 2010 as compared to the corresponding period in 2009. Other revenue and expense items impacting operating income are discussed above.

	•		an increase of $4.2 million in depreciation and amortization, primarily on assets placed in service in the second half of 2009 in connection with the Kirby Hills Phase II expansion project, certain internal-use software placed in service in the fourth quarter of 2009 and on assets acquired in November 2009, and an increase of $3.0 million in non-cash unit-based compensation expense; and

	•		an increase of $2.9 million in costs and expenses of the Development & Logistics segment, primarily resulting from $2.4 million of expenses related to the write-off in the 2010 period of a portion of an outstanding receivable balance and other costs associated with a customer bankruptcy and due to the assignment of certain service contracts from the Pipeline Operations segment to the Development & Logistics segment in April 2010.

~~Income~~Total ~~attributable~~costs toand ~~noncontrolling~~expenses ~~interests~~in the 2009 period include the recognition of a non-cash $72.5 million ~~Income~~asset ~~attributable~~impairment expense in the Pipeline Operations segment, related to the Buckeye NGL ~~noncontrolling~~Pipeline ~~interests,~~and ~~which~~$29.1 million ~~represents~~of expenses across all segments associated with organizational restructuring. These two charges were the ~~allocation~~primary cause of ~~Buckeye’s~~a ~~income~~partially tooffsetting ~~its~~decrease ~~limited~~in ~~partner~~total ~~interest~~costs ~~not~~and ~~owned~~expenses byfor usthe or2010 ~~Services~~period ~~Company,~~as ~~was~~compared ~~$81~~to the 2009 period.~~3 million~~ Total costs and expenses for the ~~six~~nine months ended ~~June~~ September 30, 2010 asalso ~~compared~~reflect tothe aeffectiveness ~~loss~~ of ~~$14.6 million~~cost management inefforts ~~the~~we ~~corresponding~~implemented ~~period~~ in 2009. Largely as result of these efforts, ~~primarily due~~costs todecreased ~~the~~by approximately ~~recognition~~$11.7 million ofduring the ~~asset~~nine ~~impairment~~months ~~expense~~ended ~~and~~September 30, ~~the~~2010 ~~organizational~~as ~~restructuring~~compared ~~charges in~~to the corresponding ~~2009~~ period in 2009.

Total costs and expenses also reflect the following decreases:

	•		a decrease in costs and expenses of the Pipeline Operations segment, resulting substantially from a decrease related to the asset impairment expense and the organizational restructuring charges recognized in the 2009 period as discussed above and lower payroll and benefits costs, which were primarily attributable to the organizational restructuring that occurred in 2009 and resulted in reduced headcount, as well as from lower environmental remediation expenses, lower operating power costs due to lower transportation volumes and power contract renegotiations as part of our best practices initiative and lower contract service activities, partially offset by higher pipeline integrity program expenses and higher project costs; and

	•		a decrease in costs and expenses of the Terminalling & Storage segment, resulting primarily from a decrease related to expenses for organizational restructuring recognized in the 2009 period, lower environmental remediation expenses and lower payroll and benefits costs, partially offset by higher operating expense for terminals acquired in November 2009 and higher bad debt expense.

Operating Income. Operating income was $220.9 million for the nine months ended September 30, 2010 compared to operating income of $108.3 million for the nine months ended September 30, 2009. Interest and debt expense increased by $11.1 million for the nine months ended September 30, 2010 as compared to the corresponding period in 2009, which increase was largely attributable to the issuance in August 2009 of $275.0 million aggregate principal amount of 5.500% Notes due 2019, higher outstanding borrowings under the BES Credit Agreement and lower interest capitalized on construction projects, partially offset by lower outstanding borrowings under Buckeye’s Credit Facility. Income from equity investments decreased by $0.2 million for the nine months ended September 30, 2010 as compared to the corresponding period in 2009. Other revenue and expense items impacting operating income are discussed above.

Income attributable to noncontrolling interests. Income attributable to noncontrolling interests, which represents the allocation of Buckeye’s income to its limited partner interests not owned by us or Services Company, was $130.3 million for the nine months ended September 30, 2010 as compared to $32.7 million in the corresponding period in 2009. The increase is primarily due to the recognition of the asset impairment expense and the organizational restructuring charges in the 2009 period.

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

Pipeline Operations

Revenue. Revenue from the Pipeline Operations segment was $195.9 million for the six months ended June 30, 2010, which is a decrease of $1.5 million, or 0.8%, from the corresponding period in 2009. Revenues decreased by $8.9 million, resulting from a 4.0% decrease in transportation volumes, due in part to the sale of the Buckeye NGL Pipeline on January 1, 2010, and a $2.2 million decrease from a product supply arrangement with a wholesale distributor and 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. These decreases in revenue were partially offset by higher tariffs of $4.6 million, the result of overall average tariff increases of approximately 3.8% implemented on July 1, 2009 and 2.61% implemented on May 1, 2010, favorable settlement experience of $3.0 million and increased revenues of $1.4 million from pipeline assets acquired in November 2009.

Total Costs and Expenses. Total costs and expenses from the Pipeline Operations segment were $106.0 million for the six months ended June 30, 2010, which is a decrease of $98.0 million, or 48.1%, from the corresponding period in 2009. Total costs and expenses for the 2009 period include a $72.5 million non-cash asset impairment expense and $23.1 million of expense related to organizational restructuring. These charges in the six months ended June 30, 2009 were the primary reason that total costs and expenses in the 2009 period were 48.1% higher than in the 2010 period. In addition, total costs and expenses in the 2010 period were lower than in the 2009 period as a result of a $3.3 million decrease in payroll and benefits costs, resulting primarily from our best practices initiative, a $1.5 million reduction in environmental remediation expenses, a $1.3 million decrease in operating power costs due to lower transportation volumes and power contract renegotiations as part of our best practices initiative, a $1.2 million decrease in contract service activities at customer facilities connected to our refined petroleum products pipelines, and a $0.8 million decrease in product costs, resulting from reduced volumes of product sold to a wholesale distributor. These decreases in total costs and expenses were partially offset by an increase of $4.7 million in professional fees and other expenses, including an increase of $2.2 million in integrity program expenses and an increase of $0.6 million in bad debt expense.

~~Operating Income. Operating income from the~~ Pipeline Operations segment was $89.9 million for the six months ended June 30, 2010 compared to an operating loss of $6.6 million for the six months ended June 30, 2009. Depreciation and amortization increased by $0.2 million for the six months ended June 30, 2010 from the corresponding period in 2009. Income from equity investments increased by $0.2 million for the six months ended June 30, 2010 as compared to the corresponding period in 2009. Other revenue and expense items impacting operating income are discussed above.

Revenue. Revenue from the Pipeline Operations segment was $299.5 million for the nine months ended September 30, 2010, which is an increase of $5.4 million, or 1.8%, from the corresponding period in 2009. Revenues increased due to a $7.3 million benefit of higher tariff rates resulting from overall average tariff rate increases of approximately 3.8% implemented on July 1, 2009 and 2.6% implemented on May 1, 2010, favorable settlement experience of $5.8 million, increased revenues of $2.0 million from pipeline assets acquired in November 2009 and an increase of $3.4 million in other pipeline revenues. These increases were partially offset by a 2.1% decrease in transportation volumes, which resulted in an $8.7 million decrease in transportation revenues, due in part to the sale of the Buckeye NGL Pipeline on January 1, 2010, and a $4.5 million decrease in revenue from a product supply arrangement with a wholesale distributor and 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.

Total Costs and Expenses. Total costs and expenses from the Pipeline Operations segment were $160.6 million for the nine months ended September 30, 2010, which is a decrease of $98.3 million, or 38.0%, from the corresponding period in 2009. Total costs and expenses for the 2009 period include a $72.5 million non-cash asset impairment expense and $23.6 million of expense related to organizational restructuring. These charges in the nine months ended September 30, 2009 were the primary reason that total costs and expenses in the 2009 period were 38.0% higher than in the 2010 period. In addition, total costs and expenses in the 2010 period were lower than in the 2009 period as a result of a $3.5 million decrease in contract service activities due to the assignment of certain service contracts from the Pipeline Operations segment to the Development & Logistics segment, a $2.0 million reduction in environmental remediation expenses, a $1.7 million decrease in payroll and benefits costs, resulting primarily from our best practices initiative, a $1.2 million decrease in operating power costs due to lower transportation volumes and power contract renegotiations as part of our best practices initiative, a $0.8 million decrease in product costs, resulting from reduced volumes of product sold to a wholesale distributor and a decrease of $0.6 million in property taxes. These decreases in total costs and expenses were partially offset by an increase of an increase of $3.7 million in professional fees, outside services and other project expenses, an increase of $2.4 million in pipeline integrity program expenses, an increase of $0.6 million in bad debt expense and an increase of $0.8 million in depreciation and amortization as a result of pipeline assets acquired in November 2009.

Operating Income. Operating income from the Pipeline Operations segment was $138.9 million for the nine months ended September 30, 2010 compared to operating income of $35.2 million for the nine months ended September 30, 2009. Income from equity investments decreased by $0.2 million for the nine months ended September 30, 2010 as compared to the corresponding period in 2009. Other revenue and expense items impacting operating income are discussed above.

Terminalling & Storage

Revenue. Revenue from the Terminalling & Storage segment was $83125.10 million for the ~~six~~nine months ended ~~June~~September 30, 2010, which is an increase of $2330.09 million, or 3832.49%, from the corresponding period in 2009. Approximately $1927.56 million of the increase resulted primarily from terminals acquired in November 2009, internal growth projects, increased throughput volumes, higher fees, higher storage and rental revenue, including $34.26 million in storage fees from previously underutilized tankage identified in connection with our best practices initiative and other marketing opportunities, and increased butane-blending revenue. Also contributing to the improved revenue was an increase of $3.53 million in settlement experience, reflecting the favorable impact of higher refined petroleum product prices during the ~~six~~nine months ended ~~June~~September 30, 2010 as compared to the corresponding period in 2009. In addition to the 1213.13% increase in volumes resulting from the acquisition of terminals in November 2009, terminalling volumes increased 7.6.5% for the ~~six~~nine months ended ~~June~~September 30, 2010 as compared to the corresponding period in 2009, primarily ~~largely~~ due to increased diesel, ethanol and jet fuel throughput volumes.

Total Costs and Expenses. Total costs and expenses from the Terminalling & Storage segment were $3654.13 million for the ~~six~~nine months ended ~~June~~September 30, 2010, which is a decrease of $20.2 7 million, or 51.72%, from the corresponding period in 2009. The decrease in total costs and ~~expenses~~ expenses in the 2010 period as compared to the 2009 period is due to a $2.46 million decrease related to expenses for organizational restructuring recognized in the 2009 ~~period, a $1.5 million decrease in~~ environmental remediation expenses and a $1.5 million decrease in payroll and benefits costs primarily related to our best practices initiative in 2009, partially offset by a $1.3 million increase in operating expenses for terminals acquired in November 2009, a $0.6 million increase in bad debt expense and a $1.1 million increase in depreciation and amortization, primarily due to expense on assets acquired in November 2009.

Operating Income. Operating income from the Terminalling & Storage segment was $47.0 million for the six months ended June 30, 2010 compared to operating income of $21.8 million for the six months ended June 30, 2009. Depreciation and amortization increased by $1.1 million for the six months ended June 30, 2010 as a result of the terminals acquired in November 2009. Other revenue and expense items impacting operating income are discussed above.

Natural Gas Storage

Revenue. Revenue from the Natural Gas Storage segment was $46.7 million for the six months ended June 30, 2010, which is an increase of $15.0 million, or 46.9%, from the corresponding period in 2009. This overall increase is attributable to greater underlying volume and higher fees recognized as revenue for hub services provided during the six months ended June 30, 2010. During the six months ended June 30, 2010 and 2009, there were 232 and 205 outstanding hub service contracts, respectively, for which revenue was being recognized ratably. Market conditions contributed to higher fees of $14.1 million for hub service agreements recognized as revenue during the six months ended June 30, 2010 as compared to the corresponding period in 2009. Lease revenue also increased $0.8 million for the six months ended June 30, 2010, as increased storage capacity from the commissioning of the Kirby Hills Phase II expansion project, which was placed in service in June 2009, was partially offset by 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 $39.9 million for the six months ended June 30, 2010, which is an increase of $20.2 million, or 101.9%, from the corresponding period in 2009. The primary driver of the increase in expenses is an increase in hub services fees paid to customers for hub service activities. Other operating expenses increased by $0.6 million, primarily due to increased fuel costs, professional fees, maintenance materials expense and supplies and rental expenses, partially offset by decreased outside service costs. Total costs and expenses also include an increase of $0.6 million in depreciation and

~~amortization~~period, a $1.6 million decrease in payroll and benefits costs primarily related to our best practices initiative in 2009 and a $1.2 million decrease in environmental remediation expenses, partially offset by a ~~decrease~~$2.2 million ofincrease in operating expenses for terminals acquired in November 2009, a $0.36 million ~~related~~increase toin ~~organizational restructuring~~bad ~~charges~~debt ~~recognized~~expense and a $1.7 million increase in depreciation ~~the~~and ~~2009~~amortization, ~~period~~primarily on terminals acquired in November 2009.

Operating Income. Operating income from the ~~Natural~~Terminalling ~~Gas~~& Storage segment was $670.87 million for the ~~six~~nine months ended ~~June~~September 30, 2010 compared to operating income of $1239.01 million ~~for~~ ~~the six months ended June 30, 2009. Depreciation and amortization increased by $0.6 million~~ for the ~~six~~nine months ended ~~June~~September 30, ~~2010 from the corresponding period in~~ 2009 ~~due to expense on assets placed in service in the second half of 2009 in connection with the Kirby Hills Phase II expansion project~~. Other revenue and expense items impacting operating income are discussed above.

Natural Gas Storage

Revenue. Revenue from the Natural Gas Storage segment was $68.3 million for the nine months ended September 30, 2010, which is an increase of $8.0 million, or 13.2%, from the corresponding period in 2009. This overall increase is attributable to greater underlying volume and higher fees recognized as revenue for hub services provided during the nine months ended September 30, 2010. During the nine months ended September 30, 2010 and 2009, there were 310 and 283 outstanding hub service contracts, respectively, for which revenue was being recognized ratably. Market conditions resulted in lower fees of $7.8 million for hub service agreements recognized as revenue during the nine months ended September 30, 2010 as compared to the corresponding period in 2009. Lease revenue increased $0.2 million for the nine months ended September 30, 2010, as increased storage capacity from the commissioning of the Kirby Hills Phase II expansion project, which was placed in service in June 2009, was partially offset by 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 $58.8 million for the nine months ended September 30, 2010, which is an increase of $18.0 million, or 44.2%, from the corresponding period in 2009. The primary driver of the increase in expenses is an increase in hub services fees paid to customers for hub service activities. Total costs and expenses also include an increase of $1.0 million in depreciation and amortization primarily due to assets placed in service in the second half of 2009 in connection with the Kirby Hills Phase II expansion project, partially offset by a decrease of $0.4 million related to organizational restructuring charges recognized in the 2009 period. Other operating expenses decreased by $2.5 million, primarily due to decreased outside service costs and other expenses, partially offset by increased fuel costs, maintenance materials expense and supplies and rental expenses.

Operating Income. Operating income from the Natural Gas Storage segment was $9.5 million for the nine months ended September 30, 2010 compared to operating income of $19.6 million for the nine months ended September 30, 2009. Other revenue and expense items impacting operating income are discussed above.

Energy Services

Revenue. Revenue from the Energy Services segment was $1,~~070~~637.20 million for the ~~six~~nine months ended ~~June~~September 30, 2010, which is an increase of $~~600~~908.04 million, or ~~127~~124.67%, from the corresponding period in 2009. This increase was primarily due to an increase in refined petroleum product prices in the 2010 period, which correspondingly increased the cost of product sales, and an increase of 5871.42% in sales volumes.

Total Costs and Expenses. Total costs and expenses from the Energy Services segment were $1,~~074~~638.02 million for the ~~six~~nine months ended ~~June~~September 30, 2010, which is an increase of $~~608~~920.60 million, or ~~130~~128.81%, from the corresponding period in 2009. The increase in total costs and expenses was primarily due to an increase of $~~609~~920.60 million in cost of product sales as a result of increased volumes sold and an increase in refined petroleum product prices. The increase in expenses was a result of ~~the~~lower ~~withdrawal~~rack ofmargins ~~product~~driven ~~from~~by ~~inventory~~competitive aspricing ~~market~~at ~~conditions~~the ~~changed~~rack ~~and~~as inventory ~~commodity~~levels ~~prices~~have ~~were~~remained noat ~~longer~~higher inthan ~~contango.~~normal ~~The~~levels ~~increase~~while in product ~~supply~~demand inhas declined. Additionally, the ~~market~~contango ~~place from~~opportunities ~~inventory~~that ~~liquidation,~~existed ~~coupled~~during ~~with~~2009 ~~lower~~have ~~overall~~not ~~product~~existed ~~demand,~~through ~~created~~the ~~additional~~first ~~pressure~~nine months onin ~~margins,~~2010. ~~which~~These ~~was~~negative factors were partially offset by a 5871.42% increase in Energy Services’ sales volume. Total costs and expenses also increased due to an increase of $0.7 million in bad debt expense and an increase of $1.2 million in payroll related costs, ~~partially~~including an increase of $0.6 million in non-cash unit-based compensation expense, partially offset by a decrease of $1.4 2 million in ~~maintenance~~repairs ~~materials~~and maintenance expense and professional fees. Total costs and expenses also include an increase of $0.47 million in depreciation and amortization, related primarily to certain internal-use software placed in service in the fourth quarter of 2009, partially offset by a decrease of $01.92 million related to an organizational restructuring recognized in the 2009 period.

Operating Income (loss). Operating loss from the Energy Services segment was $3.9 million for the six months ended June 30, 2010 compared to operating income of $4.8 million for the six months ended June 30, 2009. Depreciation and amortization increased by $0.4 million for the six months ended June 30, 2010 from the corresponding period in 2009 due to amortization of certain internal-use software that was placed in service in the fourth quarter of 2009. Other revenue and expense items impacting operating income (loss) are discussed above.

Development & Logistics

Revenue. Revenue from the Development & Logistics segment was $18.3 million for the six months ended June 30, 2010, which is an increase of $0.4 million, or 2.1%, from the corresponding period in 2009. The increase in revenue was partially due to the recognition of $1.2 million of revenue related to the sale of ammonia linefill. In addition, operating service revenues increased by $2.0 million from the 2009 period, primarily due to the assignment of certain service contracts from the Pipeline Operations segment to the Development & Logistics segment. These increases in revenue were partially offset by reduced construction contract activity following completion of certain construction projects in 2009, resulting in a $3.6 million reduction in certain construction contract revenues.

Total Costs and Expenses. Total costs and expenses from the Development & Logistics segment were $16.7 million for the six months ended June 30, 2010, which is an increase of $0.3 million, or 1.8%, from the corresponding period in 2009. Total costs and expenses increased as a result of the recognition of $2.4 million of expenses related to the write-off in the 2010 period of a portion of an outstanding receivable balance and other costs associated with a customer bankruptcy, and increased operating services activities discussed above, partially offset by reduced contract construction activity discussed above and lower income tax expense. Total costs and expenses in the 2009 period include $1.4 million of expense related to an organizational restructuring.

Operating Income (Loss). Operating ~~income~~loss from the ~~Development~~Energy &Services ~~Logistics~~ segment was $1.63 million for the ~~six~~nine months ended ~~June~~September 30, 2010 compared to operating income of $110.54 million for the ~~six~~ nine months ended ~~June~~September 30, 2009. Income tax expense decreased by $0.8 million for the six months ended June 30, 2010, primarily due to the recognition of a tax benefit of $0.6 million primarily related to the write-off of a portion of an outstanding receivable balance and other costs associated with a customer bankruptcy as discussed above. Other revenue and expense items impacting operating income (loss) are discussed above.

Development & Logistics

Revenue. Revenue from the Development & Logistics segment was $27.4 million for the nine months ended September 30, 2010, which is an increase of $2.0 million, or 7.6%, from the corresponding period in 2009. The increase in revenue was partially due to the recognition of $1.2 million of revenue related to the sale of ammonia linefill. In addition, the increase in revenue was due to an increase of $3.8 million in operating service revenues and other revenues from the 2009 period, primarily due to the assignment of certain service contracts from the Pipeline Operations segment to the Development & Logistics segment, an increase of $0.9 million in rental and transportation revenues and an increase of $0.6 million in operating service revenues as a result of higher fees and increased reimbursable costs. These increases in revenue were partially offset by reduced construction contract activity following completion of certain construction projects in 2009, resulting in a $4.5 million reduction in construction contract revenues.

Total Costs and Expenses. Total costs and expenses from the Development & Logistics segment were $24.3 million for the nine months ended September 30, 2010, which is an increase of $2.9 million, or 13.5%, from the corresponding period in 2009. Total costs and expenses include $1.4 million of expense related to an organizational restructuring recognized in the 2009 period. Total costs and expenses increased as a result of the recognition of $2.4 million of expenses related to the write-off in the 2010 period of a portion of an outstanding receivable balance and other costs associated with a customer bankruptcy, and increased operating services activities discussed above, partially offset by reduced contract construction activity discussed above and lower income tax expense.

Operating Income. Operating income from the Development & Logistics segment was $3.1 million for the nine months ended September 30, 2010 compared to operating income of $4.0 million for the nine months ended September 30, 2009. Income tax expense decreased by $0.1 million for the nine months ended September 30, 2010, primarily due to the recognition of a tax benefit of $0.6 million primarily related to the write-off of a portion of an outstanding receivable balance and other costs associated with a customer bankruptcy as discussed above, partially offset by higher earnings. Other revenue and expense items impacting operating income are discussed above.

Liquidity and Capital Resources

BGH

We currently have no capital requirements apart from Buckeye’s capital requirements. Buckeye’s capital requirements consist of maintenance and capital expenditures, expenditures for acquisitions and debt service requirements.

Our only cash-generating asset is our ownership interest in Buckeye GP. Our cash flow is, therefore, directly dependent upon the ability of Buckeye and its operating subsidiaries to make cash distributions to Buckeye’s partners. The actual amount of cash that Buckeye will have available for distribution depends primarily on Buckeye’s ability to generate cash beyond its working capital requirements.

Our principal uses of cash are the payment of our operating expenses and distributions to our unitholders. We generally make quarterly cash distributions of substantially all of our available cash, generally defined as consolidated cash receipts less consolidated cash expenditures and such retentions for working capital, anticipated cash expenditures and contingencies as MainLine Management deems appropriate. In the ~~six~~nine months ended ~~June~~September 30, 2010 and 2009, we paid cash distributions of $01.8429 and $01.6805 per Common Unit, respectively. Total cash distributed to our unitholders for the ~~six~~nine months ended ~~June~~September 30, 2010 and 2009 was approximately $2336.85 million and $1929.27 million, respectively.

At ~~June~~September 30, 2010 and December 31, 2009, we had no amounts outstanding under our unsecured revolving credit facility (the “BGH Credit Agreement”). See Note 10 in the Notes to Unaudited Condensed Consolidated Financial Statements for a description of the terms of the BGH Credit Agreement.

Services Company

At June 30, 2010 and December 31, 2009, Services Company had total debt outstanding of $4.6 million and $7.7 million, respectively, consisting of 3.60% Senior Secured Notes (the “3.60% ESOP Notes”) due March 28, 2011 payable by the ESOP to a third-party lender. The 3.60% ESOP Notes were issued on May 4, 2004. The 3.60% ESOP Notes are collateralized by Services Company’s common stock and are guaranteed by Services Company. In addition, Buckeye has committed that, in the event that the value of Buckeye’s LP Units owned by Services Company falls below 125% of the balance payable under the 3.60% ESOP Notes, Buckeye will fund an escrow account with sufficient assets to bring the value of the total collateral (the value of Buckeye’s LP Units owned by Services Company and the escrow account) up to the 125% minimum. Amounts deposited in the escrow account are returned to Buckeye when the value of Buckeye’s LP Units owned by Services Company returns to an amount that exceeds the 125% minimum. At June 30, 2010, the value of Buckeye’s LP Units owned by Services Company exceeded the 125% requirement.

Buckeye

Buckeye’s primary cash requirements, in addition to normal operating expenses and debt service, are for working capital, capital expenditures, business acquisitions and distributions to its partners. Buckeye’s principal sources of liquidity are cash from operations, borrowings under its Credit Facility and proceeds from the issuance of its LP Units. Buckeye will, from time to time, issue debt securities to permanently finance amounts borrowed under its Credit Facility. BES funds its working capital needs principally from its operations and the BES Credit Agreement. Buckeye’s financial policy has been to fund sustaining capital expenditures with cash from operations. Expansion and cost improvement capital expenditures, along with acquisitions, have typically been funded from external sources including Buckeye’s Credit Facility as well as debt and equity offerings. Buckeye’s goal has been

toServices ~~fund at least half of these expenditures with proceeds from equity offerings in order to maintain its investment-grade credit rating.~~ Company

At September 30, 2010 and December 31, 2009, Services Company had total debt outstanding of $3.1 million and $7.7 million, respectively, consisting of 3.60% Senior Secured Notes (the “3.60% ESOP Notes”) due March 28, 2011 payable by the ESOP to a third-party lender. The 3.60% ESOP Notes were issued on May 4, 2004. The 3.60% ESOP Notes are collateralized by Services Company’s common stock and are guaranteed by Services Company. In addition, Buckeye has committed that, in the event that the value of Buckeye’s LP Units owned by Services Company falls below 125% of the balance payable under the 3.60% ESOP Notes, Buckeye will fund an escrow account with sufficient assets to bring the value of the total collateral (the value of Buckeye’s LP Units owned by Services Company and the escrow account) up to the 125% minimum. Amounts deposited in the escrow account are returned to Buckeye when the value of Buckeye’s LP Units owned by Services Company returns to an amount that exceeds the 125% minimum. At September 30, 2010, the value of Buckeye’s LP Units owned by Services Company exceeded the 125% requirement.

Buckeye

As a result of Buckeye’s actions to minimize external financing requirements and the fact that no debt facilities mature prior to 2011, Buckeye believes that availabilities under its credit facilities, coupled with ongoing cash flows from operations, will be sufficient to fund its operations for the remainder of 2010. Buckeye will continue to evaluate a variety of financing sources, including the debt and equity markets described above, throughout 2010. However, continuing volatility in the debt and equity markets will make the timing and cost of any such potential financing uncertain.

At ~~June~~September 30, 2010, Buckeye had $1213.53 million of cash and cash equivalents on hand and approximately $580.0 million of available credit under its Credit Facility, after application of the facility’s funded debt ratio covenant. In addition, at ~~June~~September 30, 2010, BES had $2053.6 5 million of available credit under the BES Credit Agreement, pursuant to certain borrowing base ~~calculations~~ calculations under that agreement.

At ~~June~~September 30, 2010, Buckeye had an aggregate face amount of $1,~~619~~656.28 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”); • $150.0 million of 6.750% Notes due 2033 (the “6.750% Notes”); • $20.0 million outstanding under the Credit Facility; and • $~~194~~211.28 million outstanding under the BES Credit Agreement.

See Note 10 in the Notes to Unaudited Condensed Consolidated Financial Statements for more information about the terms of the debt discussed above.

~~The fair values of Buckeye’s aggregate debt and credit facilities were estimated to be~~46 $1,672.6 million and $1,762.1 million at June 30, 2010 and December 31, 2009, respectively. The fair values of the fixed-rate debt were estimated by observing market trading prices and by comparing the historic market prices of its publicly-issued debt with the market prices of other MLPs’ publicly-issued debt with similar credit ratings and terms. The fair values of Buckeye’s variable-rate debt are their carrying amounts, as the carrying amount reasonably approximates fair value due to the variability of the interest rates.

The fair values of Buckeye’s aggregate debt and credit facilities were estimated to be $1,796.7 million and $1,762.1 million at September 30, 2010 and December 31, 2009, respectively. The fair values of the fixed-rate debt were estimated by observing market trading prices and by comparing the historic market prices of its publicly-issued debt with the market prices of other MLPs’ publicly-issued debt with similar credit ratings and terms. The fair values of Buckeye’s variable-rate debt are their carrying amounts, as the carrying amount reasonably approximates fair value due to the variability of the interest rates.

Registration Statement

Buckeye may issue equity or debt securities to assist it in meeting its liquidity and capital spending requirements. Buckeye has a universal shelf registration statement on file with the U.S. Securities and Exchange Commission (“SEC”) that would allow it to issue an unlimited amount of debt and equity securities for general partnership purposes.

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
	Nine Months Ended
	June 30,
	September 30,
	2010			2009
Cash provided by (used in):
Operating activities	$	~~231~~296,~~951~~107		$	9964,~~637~~680
Investing activities		(541,~~298~~608	)		(4361,~~678~~435	)
Financing activities		(~~248~~276,~~730~~151	)		(9034,~~938~~611	)

Operating Activities

Net cash flow provided by operating activities was $~~232~~296.01 million for the ~~six~~nine months ended ~~June~~September 30, 2010 compared to $9964.67 million for the ~~six~~nine months ended ~~June~~September 30, 2009. The following were the principal factors resulting in the $~~132~~231.4 million increase in net cash flows provided by operating activities:

	•		The net change in fair values of derivatives was a decrease of $1216.92 million to cash flows from operating activities for the ~~six~~nine months ended ~~June~~September 30, 2010, resulting from the increase in value related to fixed-price ~~sales~~ contracts compared to a lower level of opposite fluctuations in futures contracts purchased to hedge such fluctuations.
	•		The net impact of working capital changes was an increase of $9680.89 million to cash flows from operating activities for the ~~six~~nine months ended ~~June~~September 30, 2010. The principal factors affecting the working capital changes were:

o Prepaid and other current assets decreased by $37.0 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, 2010 (increased commodity prices result in an increase in our broker equity account and therefore less margin deposit is required), a decrease in unbilled revenue within our Natural Gas Storage segment reflecting billings to counterparties in accordance with terms of their storage agreements, a decrease in receivables related to ammonia contracts and a decrease in prepaid insurance due to continued amortization of the balance over the policy period. o Inventories decreased by $28.1 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. o Trade receivables decreased by $10.6 million primarily due to the timing of collections from customers, partially offset by increased activity from our Energy Services segment due to higher volumes and higher commodity prices in the 2010 period. o Accrued and other current liabilities increased by $11.1 million primarily due to increases in unearned revenue primarily in the Natural Gas Storage segment as a result of increased hub services contracts during the six months ended June 30, 2010 for which the customer is billed up front for services provided over the entire term of the contract, partially offset by the payment of accrued ammonia purchases during the period and a reduction in the reorganization accrual. o Accounts payable increased by $7.6 million primarily due to higher payable balances at June 30, 2010 as a result of increased trading activity at BES resulting from increased volumes and increased commodity prices during the period. o Construction and pipeline relocation receivables decreased by $2.5 million primarily due to a decrease in construction activity in the 2010 period.

	o		Inventories decreased by $56.7 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.

	o		Prepaid and other current assets decreased by $31.3 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 nine months ended September 30, 2010 (increased commodity prices result in an increase in our broker equity account and therefore less margin deposit is required), a decrease in unbilled revenue within our Natural Gas Storage segment reflecting billings to counterparties in accordance with terms of their storage agreements, a decrease in receivables related to ammonia contracts, a decrease in tax receivables due to the collection of an amount outstanding from a regulatory agency and a decrease in prepaid insurance due to continued amortization of the balance over the policy period, partially offset by an increase in prepaid fuel taxes in our Energy Services segment.

Investing Activities

Net cash flow used in investing activities was $5.3 million for the six months ended June 30, 2010 compared to $43.7 million for the six months ended June 30, 2009. The following were the principal factors resulting in the $38.4 million decrease in net cash flows used in investing activities:

• Capital expenditures decreased by $12.2 million for the six months ended June 30, 2010 compared with the six months ended June 30, 2009. See below for a discussion of capital spending. • We contributed $3.9 million to West Texas LPG Pipeline Limited Partnership in the six months ended June 30, 2009 for our pro-rata share of an expansion project required to meet increased pipeline demand caused by increased product production in the Fort Worth basin and East Texas regions. • Cash proceeds from the sale of the Buckeye NGL Pipeline were $22.0 million during the six months ended June 30, 2010.

	o		Construction and pipeline relocation receivables decreased by $5.3 million primarily due to a decrease in construction activity in the 2010 period.

	o		Accounts payable decreased by $0.4 million primarily due to higher payable balances at September 30, 2010 as a result of increased trading activity at BES resulting from increased volumes and increased commodity prices during the period.

	o		Trade receivables increased by $9.5 million primarily due to the timing of collections from customers, including increased activity from our Energy Services segment due to higher volumes and higher commodity prices in the 2010 period.

	o		Accrued and other current liabilities decreased by $2.4 million primarily due to a decrease in accrued interest as a result of interest payments made during the period, a decrease due to the payment of accrued ammonia purchases during the period and a reduction in the reorganization accrual, partially offset by increases in unearned revenue primarily in the Natural Gas Storage segment as a result of increased hub services contracts during the nine months ended September 30, 2010 for which the customer is billed up front for services provided over the entire term of the contract.

Investing Activities

Net cash flow used in investing activities was $41.6 million for the nine months ended September 30, 2010 compared to $61.4 million for the nine months ended September 30, 2009. The following were the principal factors resulting in the $19.8 million decrease in net cash flows used in investing activities:

	•		Capital expenditures decreased by $9.5 million for the nine months ended September 30, 2010 compared with the nine months ended September 30, 2009. See below for a discussion of capital spending.

	•		We acquired additional shares of West Shore common stock from an affiliate of BP plc for $13.5 million, resulting in an increase in our ownership interest in West Shore from 24.9% to 34.6%.

	•		We contributed $3.9 million to West Texas LPG Pipeline Limited Partnership in the nine months ended September 30, 2009 for our pro-rata share of an expansion project required to meet increased pipeline demand caused by increased product production in the Fort Worth basin and East Texas regions.

	•		We acquired pipeline assets for $1.3 million during the nine months ended September 30, 2010.

	•		Cash proceeds from the sale of the Buckeye NGL Pipeline were $22.0 million during the nine months ended September 30, 2010.

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

	Six Months Ended
	Nine Months Ended
	June 30,
	September 30,
	2010		2009
Sustaining capital expenditures	$	918,~~195~~513	$	711,~~773~~869
Expansion and cost reduction		1830,~~377~~762		3246,~~046~~934
Total capital expenditures, net	$	2749,~~572~~275	$	3958,~~819~~803

Expansion and cost reduction projects in the first ~~six~~nine months of 2010 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 operating infrastructure projects. In the first ~~six~~nine months of 2009, expansion and cost reduction projects included the Kirby Hills Phase II expansion project, terminal ethanol and butane blending, the construction of three additional tanks with capacity of 0.4 million barrels in Linden, New Jersey and various other pipeline and terminal operating infrastructure projects.

We expect to spend approximately $75.0 million to $95.0 million for capital expenditures in 2010, of which approximately $25.0 million to $35.0 million is expected to relate to sustaining capital expenditures and $50.0 million to $60.0 million is expected to relate to expansion and cost reduction projects. Sustaining capital expenditures include renewals and replacement of pipeline sections, tank floors and tank roofs and upgrades to station and terminalling equipment, field instrumentation and cathodic protection systems. Major expansion and cost reduction expenditures in 2010 will include the completion of additional product storage tanks in the Midwest, various terminal expansions and upgrades and pipeline and terminal automation projects.

Financing Activities

Net cash flow used in financing activities was $248.7 million for the six months ended June 30, 2010 compared to $90.9 million for the six months ended June 30, 2009. The following were the principal factors resulting in the $157.8 million increase in net cash flows used in financing activities:

• Buckeye borrowed $95.0 million and $77.3 million and repaid $173.0 million and $166.6 million under its Credit Facility during the six months ended June 30, 2010 and 2009, respectively. • Net repayments under the BES Credit Agreement were $45.6 million during the six months ended June 30, 2010, while net borrowings under the BES Credit Agreement were $3.0 million during the six months ended June 30, 2009. • We incurred $3.2 million of debt issuance costs during the six months ended June 30, 2010 related to the amendment to the BES Credit Agreement in June 2010 (see Note 10 in the Notes to Unaudited Condensed Consolidated Financial Statements). • We received $3.0 million in net proceeds from the exercise of Buckeye’s LP Unit options during the six months ended June 30, 2010. We received $104.8 million in net proceeds from an underwritten equity offering in March and April of 2009 for Buckeye’s public issuance of 3.0 million LP Units. • Cash distributions paid to our partners increased by $4.6 million period-to-period due to an increase in our quarterly cash distribution rate per Common Unit. We paid cash distributions of $23.8 million ($0.84 per Common Unit) and $19.2 million ($0.68 per Common Unit) during the six months ended June 30, 2010 and 2009, respectively. • We paid $1.5 million of costs associated with the Merger during the six months ended June 30, 2010.

We expect to spend approximately $70.0 million to $90.0 million for capital expenditures in 2010, of which approximately $25.0 million to $35.0 million is expected to relate to sustaining capital expenditures and $45.0 million to $55.0 million is expected to relate to expansion and cost reduction projects. Sustaining capital expenditures include renewals and replacement of pipeline sections, tank floors and tank roofs and upgrades to station and terminalling equipment, field instrumentation and cathodic protection systems. Major expansion and cost reduction expenditures in 2010 will include the completion of additional product storage tanks in the Midwest, various terminal expansions and upgrades and pipeline and terminal automation projects.

Financing Activities

Net cash flow used in financing activities was $276.2 million for the nine months ended September 30, 2010 compared to $34.6 million for the nine months ended September 30, 2009. The following were the principal factors resulting in the $241.6 million increase in net cash flows used in financing activities:

	•		Buckeye borrowed $175.9 million and $160.7 million and repaid $233.9 million and $459.0 million under its Credit Facility during the nine months ended September 30, 2010 and 2009, respectively.

	•		Net repayments under the BES Credit Agreement were $28.0 million during the nine months ended September 30, 2010, while net borrowings under the BES Credit Agreement were $53.6 million during the nine months ended September 30, 2009.

	•		We incurred $3.2 million of debt issuance costs during the nine months ended September 30, 2010 related to the amendment to the BES Credit Agreement in June 2010 (see Note 10 in the Notes to Unaudited Condensed Consolidated Financial Statements).

	•		Buckeye received $273.2 million (net of debt issuance costs of $2.1 million) from the issuance in August 2009 of $275.0 million in aggregate principal amount of the 5.500% Notes in an underwritten public offering. Proceeds from this offering were used to reduce amounts outstanding under the Credit Facility.

	•		Buckeye received $4.3 million and $1.9 million in net proceeds from the exercise of its LP Unit options during the nine months ended September 30, 2010 and 2009, respectively. Buckeye received $104.6 million in net proceeds from an underwritten equity offering in March and April of 2009 for its public issuance of 3.0 million LP Units.

	•		Cash distributions paid to our partners increased by $6.8 million period-to-period due to an increase in our quarterly cash distribution rate per Common Unit. We paid cash distributions of $36.5 million ($1.29 per Common Unit) and $29.7 million ($1.05 per Common Unit) during the nine months ended September 30, 2010 and 2009, respectively.

	•		We paid $4.5 million of costs associated with the Merger during the nine months ended September 30, 2010.

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.

Other Considerations

Contractual Obligations

With the exception of routine fluctuations in the balance of Buckeye’s Credit Facility and the BES Credit Agreement, there have been no material changes in our scheduled maturities of our debt obligations since those reported in our Annual Report on Form 10-K for the year ended December 31, 2009.

Total rental expense for the three months ended ~~June~~September 30, 2010 and 2009 was $5.57 million ~~and~~ and $5.13 million, respectively. For the ~~six~~nine months ended ~~June~~September 30, 2010 and 2009, total rental expense was $1016.52 million and $1015.37 million, respectively. There have been no material changes in our operating lease commitments since those reported in our Annual Report on Form 10-K for the year ended December 31, 2009.

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 for the year ended December 31, 2009.

Related Party Transactions

With respect to related party transactions, see Note 15 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 ~~and do not engage in hedging activity with respect to trading instruments~~.

Market Risk — Non-Trading Instruments

We are exposed to financial market risk resulting from changes in commodity prices and interest rates. We do not currently have foreign exchange risk.

Commodity Risk

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.

49 As of September 30, 2010, the Natural Gas Storage segment has recorded the following assets and liabilities related to its hub services agreements (in thousands):


	September 30,
	2010
Assets:
Hub service agreements	$	37,100

Liabilities:
Hub service agreements		(25,510	)

Total	$	11,590

As of June 30, 2010, the Natural Gas Storage segment has recorded the following assets and liabilities related to its hub services agreements (in thousands):

	June 30,
	2010
Assets:
Hub service agreements	$	32,394
Liabilities:
Hub service agreements		(26,750	)
Total	$	5,644

Energy Services

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

As of June 30, 2010, the Energy Services segment had derivative assets and liabilities as follows (in thousands):

	June 30,
	2010
Assets:
Fixed-price sales contracts	$	5,121
Futures contracts for inventory and fixed-price sales contracts		4,973
Liabilities:
Fixed-price sales contracts		(166	)
Futures contracts for inventory and fixed-price sales contracts		(202	)
Total	$	9,726

Our hedged inventory portfolio extends to the first quarter of 2011. The majority of the unrealized income at June 30, 2010 for inventory hedges represented by futures contracts will be realized by the third quarter of 2010 as the related inventory is sold. Gains recorded on inventory hedges that were ineffective were approximately $1.0 million and $5.8 million for the three and six months ended June 30, 2010, respectively. At June 30, 2010, open refined petroleum product derivative contracts (represented by the fixed-price sales contracts and futures contracts for fixed-price sales contracts and inventory noted above) varied in duration, but did not extend beyond October 2011. In addition, at June 30, 2010, we had refined petroleum product inventories which we intend to use to satisfy a portion of the fixed-price sales contracts.

~~Based~~changes ~~on a hypothetical 10% movement~~ in the fair ~~underlying~~value ~~quoted market prices~~ of the ~~commodity financial~~New ~~instruments~~York ~~outstanding~~Mercantile atExchange ~~June 30,~~(“NYMEX”) ~~2010,~~futures contracts to the ~~estimated~~change ~~fair~~in fair value of ~~the~~our ~~portfolio~~hedged ~~of commodity~~fuel ~~financial instruments would be as follows (in thousands):~~inventory.

		Commodity
		Financial
		Instrument
	Resulting	Portfolio
Scenario	Classification	Fair Value
Fair value assuming no change in underlying commodity prices (as is)	Asset	$	9,726
Fair value assuming 10% increase in underlying commodity prices	Liability	$	(3,589	)
Fair value assuming 10% decrease in underlying commodity prices	Asset	$	23,044

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.

~~The~~As ~~value~~ of ~~the~~September 30, ~~open~~2010, ~~futures~~the ~~contract~~Energy ~~positions~~Services ~~noted~~segment ~~above~~had ~~were~~derivative ~~based~~assets ~~upon~~and ~~quoted~~liabilities ~~market~~as ~~prices~~follows ~~obtained~~(in ~~from NYMEX. The value of the fixed-price sales contracts was based on observable~~thousands): ~~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 refined petroleum product inventories and its fixed-price sales contracts. The derivative contracts used to hedge refined petroleum product inventories are classified as fair value hedges and are, therefore, expected to be highly effective in offsetting changes in the fair value of the refined petroleum product inventories.


	September 30,
	2010
Assets:
Fixed-price contracts	$	2,497
Futures contracts for inventory and fixed-price sales contracts		103

Liabilities:
Fixed-price sales contracts		(1,880	)
Futures contracts for inventory and fixed-price sales contracts		(8,737	)
Futures contracts for natural gas		(361	)

Total	$	(8,378	)

Our hedged inventory portfolio extends to the first quarter of 2011. The majority of the unrealized loss at September 30, 2010 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 2010 as the inventory is sold. A loss of $1.5 million and a gain of $1.2 million were recorded on inventory hedges that were ineffective for the three and nine months ended September 30, 2010, respectively. At September 30, 2010, open refined petroleum product derivative contracts (represented by the fixed-price contracts and futures contracts for fixed-price sales contracts and inventory noted above) varied in duration, but did not extend beyond October 2011. In addition, at September 30, 2010, we had refined petroleum product inventories which we intend to use to satisfy a portion of the fixed-price contracts.

Based on a hypothetical 10% movement in the underlying quoted market prices of the commodity financial instruments outstanding at September 30, 2010, the estimated fair value of the portfolio of commodity financial instruments would be as follows (in thousands):


		Commodity Financial Instrument
	Resulting	Portfolio
Scenario	Classification	Fair Value
Fair value assuming no change in underlying commodity prices (as is)	Liability	$	(8,378	)
Fair value assuming 10% increase in underlying commodity prices	Liability	$	(32,115	)
Fair value assuming 10% decrease in underlying commodity prices	Asset	$	15,359

The value of the open futures contract positions noted above were based upon quoted market prices obtained from NYMEX. The value of the fixed-price 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 refined petroleum product inventories and its fixed-price 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

Buckeye utilizes forward-starting interest rate swaps to manage interest rate risk related to forecasted interest payments on anticipated debt issuances. This strategy is a component in controlling its cost of capital associated with such borrowings. When entering into interest rate swap transactions, Buckeye becomes exposed to both credit risk and market risk. Buckeye is subject to credit risk when the value of the swap transaction is positive and the risk exists that the counterparty will fail to perform under the terms of the contract. Buckeye is subject to market risk with respect to changes in the underlying benchmark interest rate that impact the fair value of the swaps. Buckeye manages its credit risk by only entering into swap transactions with major financial institutions with investment-grade credit ratings. Buckeye manages its market risk by associating each swap transaction with an existing debt obligation or a specified expected debt issuance generally associated with the maturity of an existing debt obligation.

Buckeye’s practice with respect to derivative transactions related to interest rate risk has been to have each transaction in connection with non-routine borrowings authorized by the board of directors of Buckeye GP. In January 2009, Buckeye GP’s board of directors adopted an interest rate hedging policy which permits Buckeye to enter into certain short-term interest rate hedge agreements to manage its interest rate and cash flow risks associated with its Credit Facility. In addition, in July 2009 and May 2010, Buckeye GP’s board of directors authorized Buckeye to enter into certain transactions, such as forward starting interest rate swaps, to manage its interest rate and cash flow risks related to certain expected debt issuances associated with the maturity of existing debt obligations.

At ~~June~~September 30, 2010, Buckeye had total fixed-rate debt obligations at face value of $1,425.0 million, consisting of $125.0 million of the 5.125% Notes, $275.0 million of the 5.300% Notes, $300.0 million of the 4.625% Notes, $150.0 million of the 6.750% Notes, $300.0 million of the 6.050% Notes and $275.0 million of the 5.500% Notes. The fair value of these fixed-rate debt obligations at ~~June~~September 30, 2010 was approximately $1,~~478~~564.49 million. Buckeye estimates that a 1% decrease in rates for obligations of similar maturities would increase the fair value of its fixed-rate debt obligations by approximately $8791.3 million.

51 At September 30, 2010, Buckeye’s variable-rate obligations were $20.0 million under its Credit Facility and $211.8 million under the BES Credit Agreement. Based on the balances outstanding at September 30, 2010, we estimate that a 1% increase or decrease in interest rates would increase or decrease annual interest expense by approximately $2.3 million.

Buckeye expects to issue new fixed-rate debt (i) on or before July 15, 2013, to repay the $300.0 million of 4.625% Notes that are due on July 15, 2013, and (ii) on or before October 15, 2014, to repay the $275.0 million of 5.300% Notes that are due on October 15, 2014, although no assurances can be given that the issuance of fixed-rate debt will be possible on acceptable terms. During 2009, Buckeye entered into four forward-starting interest rate swaps with a total aggregate notional amount of $200.0 million related to the anticipated issuance of debt on or before July 15, 2013 and three forward-starting interest rate swaps with a total aggregate notional amount of $150.0 million related to the anticipated issuance of debt on or before October 15, 2014. During the nine months ended September 30, 2010, Buckeye entered into two forward-starting interest rate swaps with a total aggregate notional amount of $100.0 million related to the anticipated issuance of debt on or before July 15, 2013 and three forward-starting interest rate swaps with a total aggregate notional amount of $125.0 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 and nine months ended September 30, 2010, unrealized losses of $22.0 million and $58.1 million, respectively, were recorded in Buckeye’s accumulated other comprehensive income (loss) to reflect the change in the fair values of the forward-starting interest rate swaps. Buckeye designated the swap agreements as cash flow hedges at inception and expects the changes in values to be highly correlated with the changes in value of the underlying borrowings.

AtThe ~~June 30,~~following ~~2010,~~table ~~Buckeye’s~~presents ~~variable-rate~~the ~~obligation~~effect ~~was~~of ~~$194.2 million~~hypothetical ~~under~~price ~~the~~movements ~~BES Credit Agreement. Based~~ on the ~~balance~~estimated ~~outstanding~~fair value atof ~~June 30,~~Buckeye’s ~~2010,~~interest werate ~~estimate~~swap ~~that~~portfolio aand 1%the ~~increase~~related ~~or decrease~~change in ~~interest~~fair ~~rates~~value ~~would~~of ~~increase~~the underlying ordebt ~~decrease~~at ~~annual~~September 30, ~~interest~~2010 ~~expense~~(in ~~by approximately $1.9~~thousands): ~~million.~~

Buckeye expects to issue new fixed-rate debt (i) on or before July 15, 2013, to repay the $300.0 million of 4.625% Notes that are due on July 15, 2013, and (ii) on or before October 15, 2014, to repay the $275.0 million of 5.300% Notes that are due on October 15, 2014, although no assurances can be given that the issuance of fixed-rate debt will be possible on acceptable terms. During 2009, Buckeye entered into four forward-starting interest rate swaps with a total aggregate notional amount of $200.0 million related to the anticipated issuance of debt on or before July 15, 2013 and three forward-starting interest rate swaps with a total aggregate notional amount of $150.0 million related to the anticipated issuance of debt on or before October 15, 2014. During the three months ended June 30, 2010, Buckeye entered into two forward-starting interest rate swaps with a total aggregate notional amount of $100.0 million related to the anticipated issuance of debt on or before July 15, 2013 and three forward-starting interest rate swaps with a total aggregate notional amount of $125.0 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 and six months ended June 30, 2010, unrealized losses of $34.9 million and $36.2 million, respectively, were recorded in Buckeye’s accumulated other comprehensive income (loss) to reflect the change in the fair values of the forward-starting interest rate swaps. Buckeye designated the swap agreements as cash flow hedges at inception and expects the changes in values to be highly correlated with the changes in value of the underlying borrowings.


		Financial
		Instrument
	Resulting	Portfolio
Scenario	Classification	Fair Value
Fair value assuming no change in underlying interest rates (as is)	Liability	$	(40,910	)
Fair value assuming 10% increase in underlying interest rates	Liability	$	(22,382	)
Fair value assuming 10% decrease in underlying interest rates	Liability	$	(60,046	)

The following table presents the effect of hypothetical price movements on the estimated fair value of Buckeye’s interest rate swap portfolio and the related change in fair value of the underlying debt at June 30, 2010 (in thousands):

		Financial
		Instrument
	Resulting	Portfolio
Scenario	Classification	Fair Value
Fair value assuming no change in underlying interest rates (as is)	Liability	$	(18,953	)
Fair value assuming 10% increase in underlying interest rates	Asset	$	414
Fair value assuming 10% decrease in underlying interest rates	Liability	$	(39,148	)

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~~During ~~have been no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under~~ the ~~Securities~~third ~~Exchange Act of 1934) or in other factors during the second~~ quarter of 2010, ~~that~~we ~~have~~implemented ~~materially~~a ~~affected,~~new orrevenue ~~are~~accounting ~~reasonably likely to materially affect, our internal controls over financial reporting~~system.

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 ~~below and~~ in Part 1, “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2009 and in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 in addition to other information in such ~~report~~reports 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.

The market value of the stated consideration to our unitholders in the Merger will be determined by the price of Buckeye’s LP Units, the value of which will decrease if the market value of Buckeye’s LP Units decreases, and our unitholders cannot be sure of the market value of Buckeye’s LP Units that will be issued.

Pursuant to the Merger Agreement, our unitholders will receive approximately 20.0 million of Buckeye’s LP Units as a result of the Merger. The aggregate market value of Buckeye’s LP Units that our unitholders will receive in the Merger will fluctuate with any changes in the trading price of Buckeye’s LP Units. This means there is no “price protection” mechanism contained in the Merger Agreement that would adjust the number of Buckeye’s LP Units that our unitholders will receive based on any decreases in the trading price of the LP Units. If Buckeye’s LP Unit price decreases, the market value of the stated consideration received by our unitholders will also decrease. Consider the following example:

Example: Pursuant to the Merger Agreement, our unitholders will receive 0.705 of Buckeye’s LP Units for each Common Unit, subject to receipt of cash in lieu of any fractional LP Units. Based on the closing sales price of Buckeye’s LP Units on June 10, 2010 of $58.17 per LP Unit, the market value of all LP Units to be received by our unitholders would be approximately $1,161.0 million. If the trading price for Buckeye’s LP Units decreased 10% from $58.17 to $52.35, then the market value of all LP Units to be received by our unitholders would be approximately $1,045.0 million.

Accordingly, there is a risk that the 32% premium estimated by our board of directors to exist at the date the Merger Agreement was executed will not be realized by our unitholders at the time the Merger is completed. Buckeye’s LP Unit price changes may result from a variety of factors, including general market and economic conditions, changes in its business, operations and prospects, and regulatory considerations. Many of these factors are beyond Buckeye’s control.

The right of our unitholders to distributions will be changed following the Merger.

Under Buckeye’s current partnership agreement, we are entitled to receive approximately 0.5% of all distributions made by Buckeye and increasing percentages, up to a maximum of 45%, of the amount of incremental cash distributed by Buckeye in respect of the LP Units (other than 2,573,146 LP Units) as certain target distribution levels are reached in excess of $0.325 per LP Unit in any quarter. This results in our being entitled to receive incentive distributions of up to approximately 31% of the aggregate amount of distributions to Buckeye’s partners. After the Merger, the former holders of Common Units as a group will be entitled to receive approximately 28% of

all distributions made by Buckeye. As a result of this change, the distributions received by the former holders of Common Units could be significantly different. If distributions from Buckeye were to increase significantly, the distributions to the former holders of Common Units would be significantly less than they would be if the current structure was not changed.

While the Merger Agreement is in effect, our opportunities to enter into different business combination transactions with other parties on more favorable terms may be limited, and both we and Buckeye may be limited in our ability to pursue other attractive business opportunities.

While the Merger Agreement is in effect, we are prohibited from knowingly initiating, soliciting or encouraging the submission of any acquisition proposal or from participating in any discussions or negotiations regarding any acquisition proposal, subject to certain exceptions. As a result of these provisions in the Merger Agreement, our opportunities to enter into more favorable transactions may be limited. Likewise, if we were to sell directly to a third party, we might have received more value with respect to the general partner interest in Buckeye and the incentive distribution rights in Buckeye based on the value of Buckeye’s business at such time.

Moreover, the Merger Agreement provides for the payment of up to $29.0 million in termination fees under specified circumstances, which may discourage other parties from proposing alternative transactions that could be more favorable to our unitholders.

Both we and Buckeye have also agreed to refrain from taking certain actions with respect to our businesses and financial affairs pending completion of the Merger or termination of the Merger Agreement. These restrictions could be in effect for an extended period of time if completion of the Merger is delayed. These limitations do not preclude us from conducting our business in the ordinary or usual course or from acquiring assets or businesses so long as such activity does not have a “material adverse effect” as such term is defined in the Merger Agreement or materially affect our or Buckeye’s ability to complete the transactions contemplated by the Merger Agreement.

In addition to the economic costs associated with pursuing the Merger, the management of our general partner and Buckeye’s general partner will continue to devote substantial time and other human resources to the proposed Merger, which could limit our and Buckeye’s ability to pursue other attractive business opportunities, including potential joint ventures, stand-alone projects and other transactions. If either we or Buckeye are unable to pursue such other attractive business opportunities, then our growth prospects and the long-term strategic position of our businesses following the Merger could be adversely affected.

The number of outstanding Buckeye LP Units will increase as a result of the Merger, which could make it more difficult for Buckeye to pay the current level of quarterly distributions.

As of August 3, 2010, there were approximately 51.5 million of Buckeye’s LP Units outstanding. Buckeye will issue approximately 20.0 million LP Units in connection with the Merger. Accordingly, the dollar amount required to pay the current per LP Unit quarterly distributions will increase, which will increase the likelihood that Buckeye will not have sufficient funds to pay the current level of quarterly distributions to all holders of LP Units. Using the amount of $0.9625 per LP Unit declared with respect to the second quarter of 2010, the aggregate cash distribution to be paid to holders of Buckeye’s LP Units will total approximately $49.6 million, resulting in a distribution of $13.1 million to us for our general partner units and incentive distribution rights. Therefore, the combined total distribution to be paid by Buckeye with respect to the second quarter of 2010 will be $62.7 million. Pursuant to the Merger Agreement, our unitholders will receive approximately 20.0 million of Buckeye’s LP Units as a result of the Merger. Buckeye’s combined pro forma distribution with respect to the second quarter 2010, had the Merger been completed prior to such distribution, would result in $0.9625 per LP Unit being distributed on approximately 71.5 million LP Units, or a total of $68.8 million, with BGH no longer receiving any distributions. As a result, Buckeye would be required to distribute an additional $6.1 million per quarter in order to maintain the distribution level of $0.9625 per LP Unit paid with respect to the second quarter of 2010.

Although the elimination of the incentive distribution rights may increase the cash available for distribution to holders of LP Units in the future, this source of funds may not be sufficient to meet the overall increase in cash required to maintain the current level of quarterly distributions to holders of LP Units.

Failure to complete the Merger or delays in completing the Merger could negatively impact the price of Buckeye’s LP Units and our Common Units.

If the Merger is not completed for any reason, we and Buckeye may be subject to a number of material risks, including the following:

• Buckeye will not realize the benefits expected from the Merger, including a potentially enhanced financial and competitive position; • the price of Buckeye’s LP Units or our Common Units may decline to the extent that the current market price of these securities reflects a market assumption that the Merger will be completed; and • some costs relating to the Merger, such as certain investment banking fees and legal and accounting fees, must be paid even if the Merger is not completed.

The costs of the Merger could adversely affect Buckeye’s operations and cash flows available for distribution to its unitholders.

We and Buckeye estimate the total costs of the Merger to be approximately $12.0 million, primarily consisting of investment banking and legal advisors’ fees, accounting fees, financial printing and other related costs. These costs could adversely affect Buckeye’s operations and cash flows available for distributions to its unitholders. The foregoing estimate is preliminary and is subject to change.

If the Merger Agreement were terminated, we may be obligated to pay Buckeye for costs incurred related to the Merger. These costs could require us to seek loans or use our available cash that would have otherwise been available for distributions.

Upon termination of the Merger Agreement, and depending upon the circumstances leading to that termination, we could be responsible for reimbursing Buckeye for Merger related expenses that Buckeye has paid.

If the Merger Agreement is terminated, the expense reimbursements required by us under the Merger Agreement may require us to seek loans, borrow amounts under our revolving credit facility or use cash received from distributions we receive from Buckeye to reimburse these expenses. In either case, reimbursement of these costs could reduce the cash we have available to make quarterly distributions.

Tax Risks Related to the Merger

No ruling has been obtained with respect to the tax consequences of the Merger.

No ruling has been or will be requested from the Internal Revenue Service (“IRS”) with respect to the tax consequences of the Merger. Instead, we and Buckeye are relying on the opinions of our respective counsel as to the tax consequences of the Merger, and counsel’s conclusions may not be sustained if challenged by the IRS.

The intended tax consequences of the Merger are dependent upon our and Buckeye being treated as partnerships for tax purposes.

The treatment of the Merger as nontaxable to our and Buckeye’s unitholders is dependent upon each of us and Buckeye being treated as a partnership for federal income tax purposes. If either we or Buckeye were treated as a corporation for federal income tax purposes, the consequences of the Merger would be materially different and the Merger would likely be a fully taxable transaction to our unitholders.

The tax treatment of the Merger could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The federal income tax consequences of the Merger depend in some instances on determinations of fact and interpretations of complex provisions of federal income tax law. The federal income tax rules are constantly under review by persons involved in the legislative process, the IRS and the U.S. Treasury Department, frequently resulting in revised interpretations of established concepts, statutory changes, revisions to Treasury regulations and other modifications and interpretations. The IRS pays close attention to the proper application of tax laws to partnerships. The present federal income tax consequences of the merger to our unitholders may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively and could change the tax treatment of the Merger as nontaxable to our unitholders. For example, in response to recent public offerings of interests in the management operations of private equity funds and hedge funds, the U.S. House of Representatives has passed legislation that may cause the Merger to be treated as a taxable exchange to our unitholders. The U.S. Senate is considering similar legislation, although the most current version of the legislation under consideration by the U.S. Senate would not cause the Merger to be treated as a taxable exchange if a holder of Common Units agreed to make an affirmative election that, as currently interpreted, could change the tax treatment of future sales of LP Units received in the Merger. The most current version of the legislation under consideration in the U.S. Senate would apply to transactions, such as the Merger, that occur after December 31, 2010. We are unable to predict whether this proposed legislation or any other proposals will ultimately be enacted, and if so, whether any such proposed legislation would be applied retroactively.

Existing BGH unitholders may recognize taxable income as a result of receiving cash in lieu of fractional LP Units.

Although it is anticipated that for U.S. federal income tax purposes no gain or loss should be recognized by our unitholders solely as a result of the Merger, the receipt of cash in lieu of any fractional LP Units will result in a BGH unitholder recognizing gain or loss equal to the difference between the amount of cash received and the unitholder’s adjusted tax basis allocable to such fractional LP Units.

Item 6. Exhibits

(a) Exhibits

2.1		First Amended and Restated Agreement and Plan of Merger, dated ~~June~~August 1018, 2010, by and among Buckeye Partners, L.P., Buckeye GP LLC, Buckeye GP Holdings L.P., MainLine Management LLC and Grand Ohio, LLC, ~~a subsidiary of Buckeye Partners, L.P.~~ (Incorporated by reference to ~~Exhibit~~Annex ~~2.1~~A ofto Buckeye Partners, L.P.’s ~~Current~~Registration ~~Report~~Statement on Form 8S-K4/A filed on ~~June~~August 1119, 2010).†
*10.1		Buckeye Partners, L.P. Annual Incentive Compensation Plan, as Amended and Restated, effective as of May 6, 2010 (Incorporated by reference to Exhibit 10.15 of Buckeye Partners, L.P.’s Registration Statement on Form S-4 filed on July 14, 2010).
2.2		First Amendment to First Amended and Restated Agreement and Plan of Merger, dated October 29, 2010, by and among Buckeye Partners, L.P., Buckeye GP LLC, Buckeye GP Holdings L.P., MainLine Management LLC and Grand Ohio, LLC (Incorporated by reference to Exhibit 2.1 of Buckeye GP Holdings L.P.’s Current Report on Form 8-K filed on November 3, 2010).
10.2		Amended and Restated Credit Agreement, dated as of June 25, 2010, among Buckeye Energy Services LLC, BNP Paribas and other lenders party thereto (Incorporated by reference to Exhibit 10.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on July 1, 2010).
3.1		Certificate of Limited Partnership of Buckeye GP Holdings L.P., dated as of March 7, 2006 (Incorporated by reference to Exhibit 3.1 of Buckeye GP Holdings L.P.’s Registration Statement on Form S-1 filed on April 20, 2006).
10.3		Support 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 10.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on June 11, 2010).
3.2		First Amended and Restated Agreement of Limited Partnership of Buckeye GP Holdings L.P., dated as of August 9, 2006 (Incorporated by reference to Exhibit 3.1 of Buckeye GP Holdings L.P.’s Current Report on Form 8-K filed on August 14, 2006).
10.4		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).
10.1		Amendment No. 1 to the Amended and Restated Agreement of Limited Partnership of Buckeye Partners, L.P. (Incorporated by reference to Exhibit 3.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on August 11, 2010).
10.2		Form of Amended and Restated Agreement of Limited Partnership of Buckeye Partners, L.P. (Incorporated by reference to Annex B to the Joint Proxy Statement/Prospectus in Part I of Buckeye Partners, L.P.’s Registration Statement on Form S-4 filed on September 14, 2010).
10.3		Sixth Amendment to Credit Agreement, dated September 29, 2010, among Buckeye Partners, L.P., SunTrust Bank, as administrative agent, and the lenders signatory thereto (Incorporated by reference to Exhibit 10.1 of Buckeye Partners, L.P.’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010).
**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.

*		Represents management contract or compensatory plan or arrangement.
**		Filed herewith.
†		Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. BGH agrees to furnish supplementally a copy of the omitted schedules to the SEC upon request.

5754

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:	~~By:~~BUCKEYE GP HOLDINGS L.P.	~~BUCKEYE GP HOLDINGS L.P.~~
		(Registrant)	~~(Registrant)~~
	By:	~~By:~~MainLine Management LLC,	~~MainLine Management LLC,~~
		as General Partner	~~as General Partner~~
Date: August 6, 2010		By:	/s/ Keith E. St.Clair
Date: November 8, 2010	By:	/s/ Keith E. St.Clair
		Keith E. St.Clair	~~Keith E. St.Clair~~
			Senior Vice President and Chief Financial Officer
		Senior Vice President and Chief Financial Officer (Principal Accounting Officer and Principal Financial Officer)
			(Principal Accounting Officer and Principal Financial Officer)

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Filing Compare · Buckeye GP Holdings L.P.