Buckeye Partners (BPL) 10-Q 2012 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2012

OR

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

For the transition period from                    to                    

Commission file number 1-9356

Buckeye Partners, L.P.

(Exact name of registrant as specified in its charter)

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

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

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

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

Limited partner units and Class B units outstanding as of October 31, 2012: 90,331,395 and 7,777,811, respectively.

TABLE OF CONTENTS

	Page
PART I. FINANCIAL INFORMATION
Item 1.Financial Statements
Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September  30, 2012 and 2011 (Unaudited) September 30, 2012 and 2011 (Unaudited)		2
Condensed Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2012 and 2011 (Unaudited)		3
Condensed Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011 (Unaudited)		4
Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September  30, 2012 and 2011 (Unaudited)		5
Condensed Consolidated Statements of Partners’ Capital for the Nine Months Ended September  30, 2012 and 2011 (Unaudited)		6
Notes to Unaudited Condensed Consolidated Financial Statements:
1. Organization and Basis of Presentation		7
2. Acquisitions		8
3. Commitments and Contingencies		9
4. Inventories		12
5. Equity Investments		12
6 Long-term Debt		13
7. Derivative Instruments and Hedging Activities		13
8. Fair Value Measurements		18
9. Pensions and Other Postretirement Benefits		20
10. Unit-Based Compensation Plans		20
11. Partners’ Capital and Distributions		22
12. Earnings (Loss) Per Unit		23
13. Business Segments		23
14. Supplemental Cash Flow Information		27
Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations		28
Item 3.Quantitative and Qualitative Disclosures About Market Risk		39
Item 4.Controls and Procedures		42
PART II. OTHER INFORMATION
Item 1.Legal Proceedings		42
Item 1A.Risk Factors		42
Item 6.Exhibits		43

1

PART I. FINANCIAL INFORMATION

Item 1.Financial Statements

BUCKEYE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit amounts)

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
Revenue:
Product sales	$	688,948		$	884,436		$	2,462,699		$	2,775,698
Transportation and other services		277,022			232,475			745,350			670,841
Total revenue		965,970			1,116,911			3,208,049			3,446,539
Costs and expenses:
Cost of product sales and natural gas storage services		698,019			881,596			2,476,659			2,773,899
Operating expenses		101,242			96,776			300,263			266,909
Depreciation and amortization		37,134			31,230			104,486			87,227
General and administrative		16,222			15,054			51,074			47,751
Goodwill impairment expense		—			169,560			—			169,560
Total costs and expenses		852,617			1,194,216			2,932,482			3,345,346
Operating income (loss)		113,353			(77,305	)		275,567			101,193
Other income (expense):
Earnings from equity investments		553			2,379			4,287			7,760
Gain on sale of equity investment		—			—			—			34,112
Interest and debt expense		(28,737	)		(33,199	)		(85,159	)		(90,292	)
Other income (expense)		90			(75	)		57			432
Total other expense, net		(28,094	)		(30,895	)		(80,815	)		(47,988	)
Net income (loss)		85,259			(108,200	)		194,752			53,205
Less: Net income attributable to noncontrolling interests		(143	)		(1,500	)		(3,298	)		(4,391	)
Net income (loss) attributable to Buckeye Partners, L.P.	$	85,116		$	(109,700	)	$	191,454		$	48,814
Earnings (loss) per unit:
Basic	$	0.87		$	(1.18	)	$	1.97		$	0.55
Diluted	$	0.87		$	(1.18	)	$	1.97		$	0.54
Weighted average units outstanding:
Basic		97,993			92,982			97,017			89,499
Diluted		98,342			92,982			97,340			89,831

See Notes to Unaudited Condensed Consolidated Financial Statements.

2

BUCKEYE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
Net income (loss)	$	85,259		$	(108,200	)	$	194,752		$	53,205
Other comprehensive income (loss):
Change in value of derivatives		(6,154	)		(83,323	)		(28,746	)		(91,935	)
Gain on settlement of treasury lock, net of amortization		(13	)		(12	)		(37	)		464
Adjustment to funded status of benefit plans		(73	)		(154	)		(75	)		(394	)
Total other comprehensive loss		(6,240	)		(83,489	)		(28,858	)		(91,865	)
Comprehensive income (loss)		79,019			(191,689	)		165,894			(38,660	)
Less: Comprehensive income attributable to noncontrolling interests		(143	)		(1,500	)		(3,298	)		(4,391	)
Comprehensive income (loss) attributable to Buckeye Partners, L.P.	$	78,876		$	(193,189	)	$	162,596		$	(43,051	)

See Notes to Unaudited Condensed Consolidated Financial Statements.

3

BUCKEYE PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except unit amounts)

(Unaudited)

	September 30,			December 31,
	2012			2011
Assets:
Current assets:
Cash and cash equivalents	$	2,951		$	12,986
Trade receivables, net		238,591			206,601
Construction and pipeline relocation receivables		11,672			8,662
Inventories		197,030			298,304
Derivative assets		1,555			6,756
Prepaid and other current assets		89,461			92,727
Total current assets		541,260			626,036
Property, plant and equipment, net		4,150,488			3,847,573
Equity investments		66,974			65,882
Goodwill		838,345			753,100
Intangible assets, net		229,628			230,568
Other non-current assets		48,502			47,217
Total assets	$	5,875,197		$	5,570,376
Liabilities and partners’ capital:
Current liabilities:
Line of credit	$	166,000		$	251,200
Accounts payable		98,636			102,445
Derivative liabilities		86,846			1,859
Accrued and other current liabilities		159,019			199,475
Total current liabilities		510,501			554,979
Long-term debt		2,672,677			2,393,574
Long-term derivative liabilities		58,460			101,911
Other non-current liabilities		190,886			195,955
Total liabilities		3,432,524			3,246,419
Commitments and contingencies (Note 3)
Partners’ capital:
Buckeye Partners, L.P. capital:
Limited Partners (90,331,395 and 85,968,423 units outstanding as of September 30, 2012 and December 31, 2011, respectively)		2,172,617			2,035,271
Class B Units (7,777,811 and 7,304,880 units outstanding as of September 30, 2012 and December 31, 2011, respectively)		410,453			395,639
Accumulated other comprehensive loss		(156,599	)		(127,741	)
Total Buckeye Partners, L.P. capital		2,426,471			2,303,169
Noncontrolling interests		16,202			20,788
Total partners’ capital		2,442,673			2,323,957
Total liabilities and partners’ capital	$	5,875,197		$	5,570,376

See Notes to Unaudited Condensed Consolidated Financial Statements.

4

BUCKEYE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Nine Months Ended
	September 30,
	2012			2011
Cash flows from operating activities:
Net income	$	194,752		$	53,205
Adjustments to reconcile net income to net cash provided by operating activities:
Gain on sale of equity investment		—			(34,112	)
Value of ESOP shares released		—			1,183
Depreciation and amortization		104,486			87,227
Goodwill impairment expense		—			169,560
Net changes in fair value of derivatives		17,055			(150,433	)
Non-cash deferred lease expense		2,925			3,091
Amortization of unfavorable storage contracts		(8,245	)		(4,813	)
Earnings from equity investments		(4,287	)		(7,760	)
Distributions from equity investments		3,324			1,922
Amortization of other non-cash items		14,282			10,074
Change in assets and liabilities, net of amounts related to acquisitions:
Trade receivables		(31,990	)		922
Construction and pipeline relocation receivables		(3,010	)		647
Inventories		101,274			(9,590	)
Prepaid and other current assets		3,214			8,121
Accounts payable		970			(3,691	)
Accrued and other current liabilities		(46,882	)		(36,724	)
Other non-current assets		985			11,669
Other non-current liabilities		(857	)		81,564
Net cash provided by operating activities		347,996			182,062
Cash flows from investing activities:
Capital expenditures		(233,005	)		(191,368	)
Acquisition of interest in equity investment		—			(5,723	)
Contribution to equity investment		(350	)		—
Deposit in anticipation of acquisition		—			(500	)
Acquisitions, net of cash acquired		(260,312	)		(1,079,411	)
Proceeds from sale of equity investment		—			85,000
Net proceeds from disposal of property, plant and equipment		52			573
Net cash used in investing activities		(493,615	)		(1,191,429	)
Cash flows from financing activities:
Net proceeds from issuance of units		246,805			736,977
Proceeds from exercise of unit options		1,067			2,226
Payment of tax withholding on issuance of LTIP awards		(1,608	)		—
Issuance of long-term debt		—			647,530
Repayment of long term-debt		—			(1,525	)
Borrowings under BPL Credit Facilities		856,000			1,100,232
Repayments under BPL Credit Facilities		(577,400	)		(952,532	)
Net borrowings (repayments) under BES Credit Facility		(85,200	)		62,500
Debt issuance costs		—			(9,968	)
Acquisition of additional interest in WesPac Memphis		(17,328	)		—
Repayment of debt assumed in BORCO acquisition		—			(318,167	)
Credits (costs) associated with agreement and plan of merger		422			(1,415	)
Distributions paid to noncontrolling interests		(8,900	)		(4,260	)
Proceeds from settlement of treasury lock		—			497
Distributions paid to unitholders		(278,274	)		(250,158	)
Net cash provided by financing activities		135,584			1,011,937
Net increase (decrease) in cash and cash equivalents		(10,035	)		2,570
Cash and cash equivalents — Beginning of period		12,986			13,626
Cash and cash equivalents — End of period	$	2,951		$	16,196

See Notes to Unaudited Condensed Consolidated Financial Statements.

5

BUCKEYE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(In thousands)

(Unaudited)

						Accumulated
						Other
	Limited			Class B		Comprehensive			Noncontrolling
	Partners			Units		Loss			Interests			Total
Partners’ capital—January 1, 2012	$	2,035,271		$	395,639	$	(127,741	)	$	20,788		$	2,323,957
Net income		176,640			14,814		—			3,298			194,752
Acquisition of additional interest in WesPac Memphis		(14,536	)		—		—			(2,792	)		(17,328	)
Credits associated with agreement and plan of merger		422			—		—			—			422
Distributions paid to unitholders		(282,111	)		—		—			3,837			(278,274	)
Net proceeds from issuance of units		246,805			—		—			—			246,805
Amortization of unit-based compensation awards		10,534			—		—			—			10,534
Proceeds from exercise of unit options		1,067			—		—			—			1,067
Payment of tax withholding on issuance of LTIP awards		(1,608	)		—		—			—			(1,608	)
Distributions paid to noncontrolling interests		—			—		—			(5,063	)		(5,063	)
Other comprehensive loss		—			—		(28,858	)		—			(28,858	)
Noncash accrual for distribution equivalent rights		(555	)		—		—			—			(555	)
Other		688			—		—			(3,866	)		(3,178	)
Partners’ capital—September 30, 2012	$	2,172,617		$	410,453	$	(156,599	)	$	16,202		$	2,442,673
Partners’ capital—January 1, 2011	$	1,413,664		$	—	$	(21,259	)	$	17,855		$	1,410,260
Net income		45,311			3,503		—			4,391			53,205
Acquisition of 80% interest in BORCO		—			—		��			276,508			276,508
Acquisition of remaining interest in BORCO		—			—		—			(278,211	)		(278,211	)
Costs associated with agreement and plan of merger		(1,415	)		—		—			—			(1,415	)
Distributions paid to unitholders		(250,158	)		—		—			—			(250,158	)
Issuance of units to First Reserve for BORCO acquisition		152,772			254,619		—			—			407,391
Issuance of units to Vopak for BORCO acquisition		36,041			60,069		—			—			96,110
Net proceeds from issuance of units		663,930			73,047		—			—			736,977
Amortization of unit-based compensation awards		6,588			—		—			—			6,588
Proceeds from exercise of unit options		2,226			—		—			—			2,226
Services Company’s non-cash ESOP distributions		—			—		—			(1,410	)		(1,410	)
Distributions paid to noncontrolling interests		—			—		—			(4,260	)		(4,260	)
Other comprehensive loss		—			—		(91,865	)		—			(91,865	)
Noncash accrual for distribution equivalent rights		(892	)		—		—			—			(892	)
Other		(460	)		—		—			3,119			2,659
Partners’ capital—September 30, 2011	$	2,067,607		$	391,238	$	(113,124	)	$	17,992		$	2,363,713

See Notes to Unaudited Condensed Consolidated Financial Statements.

6

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND BASIS OF PRESENTATION

Organization

Buckeye Partners, L.P. is a publicly traded Delaware master limited partnership (“MLP”), and its limited partnership units representing limited partner interests (“LP Units”) are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “BPL.” Buckeye GP LLC (“Buckeye GP”) is our general partner. As used in these Notes to Unaudited Condensed Consolidated Financial Statements, “we,” “us,” “our” and “Buckeye” mean Buckeye Partners, L.P. and, where the context requires, includes our subsidiaries.

We were formed in 1986 and own and operate one of the largest independent refined petroleum products pipeline systems in the United States in terms of volumes delivered with over 6,000 miles of pipeline and over 100 active products terminals that provide aggregate storage capacity of approximately 70 million barrels. In addition, we operate and/or maintain third-party pipelines under agreements with major oil and gas, petrochemical and chemical companies, and perform certain engineering and construction management services for third parties. We also own and operate a natural gas storage facility in Northern California, and are a wholesale distributor of refined petroleum products in the United States in areas also served by our pipelines and terminals. Our flagship marine terminal in The Bahamas, which is owned by our subsidiary, Bahamas Oil Refining Company International Limited (“BORCO”), is one of the largest marine crude oil and petroleum products storage facilities in the world, serving the international markets as a premier global logistics hub.

Basis of Presentation and Principles of Consolidation

The condensed consolidated financial statements and the accompanying notes are prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) and the rules of the U.S. Securities and Exchange Commission (“SEC”). Accordingly, our financial statements reflect all normal and recurring adjustments that are, in the opinion of management, necessary for a fair presentation of our results of operations for the interim periods. The consolidated financial statements include the accounts of our subsidiaries controlled by us and variable interest entities of which we are the primary beneficiary. We have eliminated all intercompany transactions in consolidation.

We believe that the disclosures in these condensed consolidated financial statements are adequate to make the information presented not misleading. These interim financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto contained in our Annual Report on Form 10-K for the year ended December 31, 2011.

Recent Accounting Developments

Intangibles, Goodwill and Other. In September 2011, the Financial Accounting Standards Board (“FASB”) issued guidance that amended testing goodwill for impairment. Under the revised guidance, entities testing goodwill for impairment have the option of performing a qualitative assessment before calculating the fair value of the reporting unit (i.e., step 1 of the goodwill impairment test). If entities determine, on the basis of qualitative factors, that the fair value of the reporting unit is more likely than not less than the carrying amount, the two-step impairment test would be required. The amended guidance does not change how goodwill is calculated or assigned to reporting units nor revise the requirement to test goodwill for impairment annually or between annual tests if events or circumstances warrant. However, it does revise the examples of events and circumstances that an entity should consider. The amendments are effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. We applied the amended guidance for our annual goodwill impairment test as of January 1, 2012 based on the facts and circumstances within each reporting unit. The adoption of this guidance did not have an impact on our condensed consolidated financial statements.

Presentation of Comprehensive Income.In June 2011, the FASB issued new guidance regarding the presentation of comprehensive income. This guidance requires entities to present reclassification adjustments for items that are reclassified from other comprehensive income to net income in the statement in which the components of net income and components of other comprehensive income are presented. It also eliminates the current option

7

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

under U.S. GAAP to present components of other comprehensive income within the statement of changes in stockholders’ equity. The components of comprehensive income are required to be presented within either (i) a single continuous statement of comprehensive income or (ii) two separate but consecutive statements. This guidance is effective for interim and annual periods beginning after December 15, 2011. Since this issuance only impacts the presentation of such financial information, adoption of this guidance did not have an impact on our condensed consolidated financial statements. On December 23, 2011, the FASB issued guidance to defer the new requirement to present the effect of reclassification adjustments on net income and other comprehensive income in the statement in which components of net income and the components of other comprehensive income are presented. The FASB issued an exposure draft on August 16, 2012 proposing new disclosures for reclassifications. The FASB has not determined an effective date for the exposure draft. We are still evaluating the impacts of this exposure draft, however, since this exposure draft only impacts the presentation of such financial information, adoption of this guidance is not expected to have an impact on our condensed consolidated financial statements.

2. ACQUISITIONS

Business Combinations

The following acquisitions were accounted for as business combinations:

2012 Transaction

In July 2012, we acquired a marine terminal facility for liquid petroleum products in New York Harbor (the “Perth Amboy Facility”) from Chevron U.S.A Inc. (“Chevron”) for $260.3 million in cash. The facility, which sits on approximately 250 acres on the Arthur Kill tidal strait in Perth Amboy, New Jersey, has over 4.0 million barrels of tankage, four docks, and significant undeveloped land available for potential expansion. The Perth Amboy Facility has water, pipeline, rail, and truck access, and is located six miles from our Linden, New Jersey complex. The facility provides a link between our inland pipelines and terminals and our BORCO facility in The Bahamas and opportunities for improved service offerings to our customers. Concurrent with the acquisition, we entered into multi-year storage, blending, and throughput commitments with Chevron. The operations of the Perth Amboy Facility are reported in our Pipelines & Terminals segment. The acquisition cost has been allocated to assets acquired and liabilities assumed based on estimated fair values at the acquisition date, with amounts exceeding the fair value recorded as goodwill, which represents both expected synergies from combining the Perth Amboy Facility with our existing operations and the economic value attributable to future expansion projects resulting from this acquisition. Fair values have been developed using recognized business valuation techniques and are subject to change pending final valuation analysis. The purchase price has been allocated to tangible and intangible assets acquired and liabilities assumed, on a preliminary basis, as follows (in thousands):

Current assets	$	547
Property, plant and equipment		169,537
Intangible assets		13,350
Goodwill		85,245
Environmental liabilities		(8,367	)
Allocated purchase price	$	260,312

8

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

2011 Transaction

On June 1, 2011, we acquired 33 refined petroleum products terminals with total storage capacity of over 10 million barrels and approximately 650 miles of refined petroleum products pipelines from BP Products North America Inc. and its affiliates for $166.0 million. The purchase price has been allocated to tangible and intangible assets acquired and liabilities assumed as follows (in thousands):

Inventory	$	1,161
Property, plant and equipment		175,577
Intangible assets		8,940
Environmental and other liabilities		(19,702	)
Allocated purchase price	$	165,976

Acquisition of Additional Interest in WesPac Pipelines – Memphis LLC

In September 2012, our operating subsidiary, Buckeye Pipe Line Holdings, L.P. (“BPH”), purchased an additional 20% ownership interest in WesPac Pipelines – Memphis LLC (“WesPac Memphis”) from Kealine LLC for $17.3 million and, as a result of the acquisition, our ownership interest in WesPac Memphis increased from 50% to 70%. Since BPH retains controlling interest in WesPac Memphis, this acquisition was accounted for as an equity transaction.

3. COMMITMENTS AND CONTINGENCIES

Claims and Legal Proceedings

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

On May 25, 2012, a ship allided with a jetty at our BORCO facility while berthing, causing damage to portions of the jetty. The extent of the damage is being assessed and presently is estimated to range between $25.0 million and $50.0 million. We have insurance to cover this loss, subject to a $5.0 million deductible. On May 26, 2012, we commenced legal proceedings in the Bahamas against the vessel’s owner and the vessel to obtain security for the cost of repairs and other losses incurred as a result of the incident. Full security for our claim has been provided by the vessel owner’s insurers, reserving all of their defenses, but the vessel owner is claiming it is entitled to limit its liability to approximately $17.0 million. We also have notified the customer on whose behalf the vessel was at the BORCO facility that we intend to hold them responsible for all damages and losses resulting from the incident pursuant to the terms of an agreement between the parties. Any disputes between us and our customer on this matter are subject to arbitration in Houston, Texas. At this time, we have not experienced any material interruption of service at the BORCO facility as a result of the incident and have commenced the process of repairing the jetty. We recorded a $4.2 million loss on disposal due to the assets destroyed in the incident; however, since we believe the recovery of our losses is probable, we recorded a corresponding receivable for the loss on disposal. To the extent the proceeds from the recovery of our losses is in excess of the carrying value of the destroyed assets or other costs incurred, we will recognize a gain when such proceeds are received and are not refundable. As of September 30, 2012, no gain had been recognized.

9

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Federal Energy Regulatory Commission (“FERC”) Proceedings

FERC Docket No. IS12-185 – Buckeye Pipe Line Show Cause Proceeding. On March 30, 2012, the FERC issued an order (the “Order”) regarding the market-based methodology used by Buckeye Pipe Line Company, L.P. (“BPLC”) to set tariff rates on its pipeline system (the “Buckeye System”). In 1991, BPLC sought and received FERC permission to determine rate changes on the Buckeye System using a unique methodology that constrains rates in markets not found to be competitive based on rate changes in markets that FERC found to be competitive, as well as certain other limits on rate increases. FERC ordered the continuation of this methodology for the Buckeye System in 1994, subject to FERC’s authority to cause BPLC to terminate the program in the future. The Order, among other things, states that FERC will review the continued efficacy of BPLC’s unique program and directs BPLC to show cause why it should not be required to discontinue the program on the Buckeye System and avail itself of the generic ratemaking methodologies used by other oil pipelines. The Order also disallowed proposed rate increases on the Buckeye System that would have become effective April 1, 2012. The Order does not impact any of the pipeline systems or terminals owned by Buckeye’s other operating subsidiaries. On April 23, 2012, BPLC requested rehearing as to the disallowance of certain rates, and filed its response to FERC’s show cause requirement, in which it defended the program, on May 15, 2012. Subsequently, parties interested in rates for transportation of jet fuel to the New York City airports filed pleadings seeking to change the program, three other shippers filed to intervene in the proceeding without taking a position on the program, and BPLC and the principal commenting party on jet fuel rates each filed replies to the other party’s filings. On October 9, 2012, one of the three shippers that intervened in the proceeding without taking a position on the program withdrew its intervention. The timing or outcome of final resolution of this matter cannot reasonably be determined at this time.

FERC Docket No. OR12-28 – Airlines Complaint against BPLC New York City Jet Fuel Rates. On September 20, 2012, a complaint was filed with FERC by Delta Air Lines, JetBlue Airways, United/Continental Air Lines, and US Airways challenging BPLC’s rates for transportation of jet fuel from New Jersey to three New York City airports. The complaint was not directed at BPLC’s rates for service to other destinations, and does not involve pipeline systems and terminals owned by Buckeye’s other operating subsidiaries. The complaint challenges these jet fuel transportation rates as generating revenues in excess of costs and thus being “unjust and unreasonable” under the Interstate Commerce Act. On October 10, 2012, BPLC filed its answer to the complaint, contending that the airlines’ allegations are based on inappropriate adjustments to the pipeline’s costs and revenues, and that, in any event, any revenue recovery by BPLC in excess of costs would be irrelevant because BPLC’s rates are set under a FERC-approved program that ties rates to competitive levels. BPLC also sought dismissal of the complaint to the extent it seeks to challenge the portion of BPLC’s rates that were deemed just and reasonable, or “grandfathered,” under Section 1803 of the Energy Policy Act of 1992. BPLC further contested the airlines’ ability to seek relief as to past charges where the rates are lawful under BPLC’s FERC-approved rate program. On October 25, 2012, the complainants filed their answer to BPLC’s motion to dismiss and answer. If FERC were to find these challenged rates to be in excess of costs and not otherwise protected by law, it could order BPLC to reduce these rates prospectively and could order repayment to the complaining airlines of any past charges found to be in excess of just and reasonable levels for up to two years prior to the filing date of the complaint. BPLC intends to vigorously defend its rates and its existing rate program. The timing or outcome of final resolution of this matter cannot reasonably be determined at this time.

FERC Docket No. OR13-3 – Buckeye Pipe Line’s Market-Based Rate Application. On October 15, 2012, BPLC filed an application with FERC seeking authority to charge market-based rates for deliveries of refined petroleum products to the New York City-area market (the “Application”). In the Application, BPLC seeks to charge market-based rates from its three origin points in northeastern New Jersey to its five destinations on its Long Island System, including deliveries of jet fuel to the Newark, LaGuardia, and JFK airports. The jet fuel rates were also the subject of the airlines’ OR12-28 complaint discussed above. Protests and comments on the Application are due by December 14, 2012, after which FERC will determine whether to approve the Application, deny it, or set it for further proceedings, including potentially an evidentiary hearing. If FERC were to approve the Application, BPLC would be permitted prospectively to set these rates in response to competitive forces, and the basis for the airlines’ claim for relief in their OR12-28 complaint as to BPLC’s future rates would be irrelevant prospectively. The timing or outcome of FERC’s review of this application cannot reasonably be determined at this time.

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Environmental Contingencies

We recorded operating expenses, net of recoveries, of $1.2 million and $3.1 million during the three months ended September 30, 2012 and 2011, respectively, related to environmental remediation expenditures unrelated to claims and legal proceedings. For the nine months ended September 30, 2012 and 2011, we recorded operating expenses, net of recoveries, of $3.9 million and $5.6 million, respectively, related to environmental remediation expenditures unrelated to claims and legal proceedings. As of September 30, 2012 and December 31, 2011, we recorded environmental liabilities of $61.5 million and $58.4 million, respectively. Costs incurred may be in excess of our estimate, which may have a material impact on our financial condition, results of operations or cash flows.

Ammonia Contract Contingencies

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

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

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BUCKEYE PARTNERS, 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, 2012		December 31, 2011
Refined petroleum products (1)	$	183,895		$	285,509
Materials and supplies		13,135			12,795
Total inventories	$	197,030		$	298,304

(1) Ending inventory was 57.0 million and 99.6 million gallons of refined petroleum products at September 30, 2012 and December 31, 2011, respectively.

At September 30, 2012 and December 31, 2011, approximately 94% and 96% of our refined petroleum products inventory volumes were hedged, respectively. Because we generally designate inventory as a hedged item upon purchase, hedged inventory is valued at current market prices with the change in value of the inventory reflected in our condensed consolidated statements of operations. Inventory not accounted for as a fair value hedge is accounted for at the lower of cost or market using the weighted average cost method.

5. EQUITY INVESTMENTS

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2012			2011		2012		2011
Muskegon Pipeline LLC	$	303		$	454	$	722	$	552
Transport4, LLC		113			43		191		143
West Shore Pipe Line Company		(220	)		1,638		2,884		4,524
West Texas LPG Pipeline Limited Partnership (1)		—			—		—		2,297
South Portland Terminal LLC (2)		357			244		490		244
Total earnings from equity investments	$	553		$	2,379	$	4,287	$	7,760

(1) In May 2011, we sold our 20% interest in West Texas LPG Pipeline Limited Partnership (“WT LPG”). Amounts for WT LPG are included through the date of the sale of our interest.

(2) In July 2011, we acquired a 50% interest.

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Summarized combined income statement data for our equity method investments are as follows for the periods indicated (amounts represent 100% of investee income statement data in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011 (1)			2012			2011 (1)
Revenue	$	21,233		$	19,485		$	55,215		$	80,989
Costs and expenses		(16,549	)		(8,140	)		(34,161	)		(43,106	)
Non-operating expense		(1,061	)		(2,812	)		(7,182	)		(9,632	)
Net income	$	3,623		$	8,533		$	13,872		$	28,251

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

6. LONG-TERM DEBT

Current Maturities Expected to be Refinanced

The $300.0 million of 4.625% Notes maturing on July 15, 2013 has been classified as long-term debt under the assumption that our Revolving Credit Facility dated September 26, 2011 (the “Credit Facility”) with SunTrust Bank could be used to refinance this debt, if required. At September 30, 2012, we had $481.4 million of availability under our Credit Facility but, except for borrowings that are used to refinance other debt, we are limited to $230.9 million of additional borrowings by the financial covenants under our Credit Facility. It is our intent to refinance the 4.625% Notes in 2013.

7. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

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 forecasted transactions. Derivatives are financial and physical 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 physical contracts, swaps and other instruments with similar characteristics. We do not engage in speculative trading activities.

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

Interest Rate Derivatives

We utilize forward-starting interest rate swaps to manage interest rate risk related to forecasted interest payments on anticipated debt issuances. This strategy is a component in controlling our cost of capital associated with such borrowings by mitigating the adverse effect of a change in the capital markets. When entering into interest rate swap transactions, we become exposed to both credit risk and market risk. We are subject to credit risk when the change in fair value of the swap instrument is positive and the counterparty may fail to perform under the terms of the contract. We are subject to market risk with respect to changes in the underlying benchmark interest rate that impacts the fair value of the swaps. We manage our credit risk by entering into swap transactions only with major financial institutions with investment-grade credit ratings. We manage our market risk by aligning the swap instrument with the existing underlying debt obligation or a specified expected debt issuance generally associated with the maturity of an existing debt obligation.

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

We expect to issue new fixed-rate debt (i) on or before July 15, 2013 to repay the $300.0 million of 4.625% Notes and (ii) on or before October 15, 2014 to repay the $275.0 million of 5.300% Notes, although no assurances can be given that the issuance of fixed-rate debt will be possible on acceptable terms. We have entered into six forward-starting interest rate swaps with a total aggregate notional amount of $300.0 million related to the anticipated issuance of debt on or before July 15, 2013 and six forward-starting interest rate swaps with a total aggregate notional amount of $275.0 million related to the anticipated issuance of debt on or before October 15, 2014. The purpose of these swaps is to hedge the variability of the forecasted interest payments on these expected debt issuances that may result from changes in the benchmark interest rate until the expected debt is issued. During the three months ended September 30, 2012 and 2011, unrealized losses of $6.4 million and $83.6 million, respectively, were recorded in accumulated other comprehensive loss to reflect the change in the fair values of the forward-starting interest rate swaps. During the nine months ended September 30, 2012 and 2011, unrealized losses of $29.5 million and $92.4 million, respectively, were recorded in accumulated other comprehensive loss. We designated the swap agreements as cash flow hedges at inception and expect the changes in value to be highly correlated with the changes in value of the underlying borrowings.

Over the next twelve months, we expect to reclassify $0.9 million of net losses from accumulated other comprehensive loss to interest and debt expense. The loss consists of the change in fair value on forward-starting interest rate swaps that were terminated in 2008 and served as a designated cash flow hedge of our 6.050% Notes, partially offset by a gain attributable to the settlement in January 2011 of the treasury lock agreement associated with the 4.875% 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. The time value component is excluded from our hedge assessment and reported directly in earnings. Hedge accounting is discontinued when the hedged fuel inventory is sold or when the related derivative contracts expire. In addition, we periodically enter into offsetting exchange-traded futures contracts to economically close-out an existing futures contract based on a near-term expectation to sell a portion of our fuel inventory. These offsetting derivative contracts are not designated as hedging instruments and any resulting gains or losses are recognized in earnings during the period. The fair values of futures contracts for inventory designated as hedging instruments in the following tables have been presented net of these offsetting futures contracts.

Our Energy Services segment has not used hedge accounting with respect to its fixed-price contracts. Therefore, our fixed-price contracts and the related futures contracts used to offset the changes in fair value of the fixed-price sales contracts are all marked-to-market on the condensed consolidated balance sheets with gains and losses being recognized in earnings during the period. In addition, futures contracts were executed to economically hedge a portion of the Energy Services segment’s refined petroleum products held in inventory. The mark-to-market is recorded on the condensed consolidated balance sheets with gains and losses being recognized in earnings during the period.

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes our commodity derivative instruments outstanding at September 30, 2012 (amounts in thousands of gallons):

	Volume (1)				Accounting
Derivative Purpose	Current		Long-Term		Treatment
Derivatives NOT designated as hedging instruments:
Physical fixed price derivative contracts for refined products		23,199		498		Mark-to-market
Physical index derivative contracts		183,229		1,054		Mark-to-market
Futures contracts for refined products		66,612		504		Mark-to-market
Derivatives designated as hedging instruments:
Futures contracts for refined products		53,550		—		Fair Value Hedge

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

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table sets forth the fair value of each classification of derivative instruments and the locations of the derivative instruments on our condensed consolidated balance sheets at the dates indicated (in thousands):

	September 30, 2012
	Derivatives NOT Designated as Hedging Instruments			Derivatives Designated as Hedging Instruments			Derivative Carrying Value			Netting Balance Sheet Adjustment			Total
Physical fixed price derivative contracts	$	1,206		$	—		$	1,206		$	(280	)	$	926
Physical index derivative contracts		631			—			631			(2	)		629
Futures contracts for refined products		30,701			304			31,005			(31,005	)		—
Total current derivative assets		32,538			304			32,842			(31,287	)		1,555
Physical index derivative contracts		43			—			43			—			43
Futures contracts for refined products		169			—			169			—			169
Total non-current derivative assets		212			—			212			—			212
Physical fixed price derivative contracts		(5,669	)		—			(5,669	)		280			(5,389	)
Physical index derivative contracts		(728	)		—			(728	)		2			(726	)
Futures contracts for refined products		(33,027	)		(5,661	)		(38,688	)		31,005			(7,683	)
Interest rate derivatives		—			(73,048	)		(73,048	)		—			(73,048	)
Total current derivative liabilities		(39,424	)		(78,709	)		(118,133	)		31,287			(86,846	)
Physical fixed price derivative contracts		(127	)		—			(127	)		—			(127	)
Interest rate derivatives		—			(58,333	)		(58,333	)		—			(58,333	)
Total non-current derivative liabilities		(127	)		(58,333	)		(58,460	)		—			(58,460	)
Net derivative assets (liabilities)	$	(6,801	)	$	(136,738	)	$	(143,539	)	$	—		$	(143,539	)
	December 31, 2011
	Derivatives NOT Designated as Hedging Instruments			Derivatives Designated as Hedging Instruments			Derivative Carrying Value			Netting Balance Sheet Adjustment			Total
Physical fixed price derivative contracts	$	5,351		$	—		$	5,351		$	(59	)	$	5,292
Physical index derivative contracts		853			—			853			(19	)		834
Futures contracts for refined products		3,594			2,664			6,258			(5,628	)		630
Total current derivative assets		9,798			2,664			12,462			(5,706	)		6,756
Physical fixed price derivative contracts		(1,304	)		—			(1,304	)		59			(1,245	)
Physical index derivative contracts		(633	)		—			(633	)		19			(614	)
Futures contracts for refined products		(3,154	)		(2,474	)		(5,628	)		5,628			—
Total current derivative liabilities		(5,091	)		(2,474	)		(7,565	)		5,706			(1,859	)
Interest rate derivatives		—			(101,911	)		(101,911	)		—			(101,911	)
Total non-current derivative liabilities		—			(101,911	)		(101,911	)		—			(101,911	)
Net derivative assets (liabilities)	$	4,707		$	(101,721	)	$	(97,014	)	$	—		$	(97,014	)

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Our hedged inventory portfolio extends to the third quarter of 2013. The majority of the unrealized loss of $5.4 million at September 30, 2012 for inventory hedges represented by futures contracts will be realized by the first quarter of 2013 as the inventory is sold. At September 30, 2012, open refined petroleum product derivative contracts (represented by the physical fixed-price contracts, physical index contracts, and futures contracts for fixed-price sales contracts noted above) varied in duration in the overall portfolio, but did not extend beyond December 2013. In addition, at September 30, 2012, we had refined petroleum product inventories that we intend to use to satisfy a portion of the physical derivative contracts.

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

		Three Months Ended September 30,						Nine Months Ended September 30,
	Location	2012			2011			2012			2011
Derivatives NOT designated as hedging instruments:
Physical fixed price derivative contracts	Product sales	$	(9,153	)	$	7,507		$	(6,255	)	$	5,920
Physical index derivative contracts	Product sales		678			—			1,038			—
Physical fixed price derivative contracts	Cost of product sales and natural gas storage services		813			4,277			210			6,044
Physical index derivative contracts	Cost of product sales and natural gas storage services		(1,014	)		—			(1,053	)		—
Futures contracts for refined products	Cost of product sales and natural gas storage services		1,304			(1,016	)		6,635			165
Derivatives designated as fair value hedging instruments:
Futures contracts for refined products	Cost of product sales and natural gas storage services		(19,062	)		30,240			(33,697	)		(18,591	)
Physical inventory—hedge items	Cost of product sales and natural gas storage services		21,307			(27,768	)		32,464			12,515
Ineffectiveness and the time value component on fair value hedging instruments:
Fair value hedge ineffectiveness (excluding time value)	Cost of product sales and natural gas storage services		(249	)		3,825			(809	)		3,621
Time value excluded from hedge assessment	Cost of product sales and natural gas storage services		2,494			(1,353	)		(423	)		(9,697	)
Net gain (loss) in income		$	2,245		$	2,472		$	(1,232	)	$	(6,076	)

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 (in thousands):

		Loss Reclassified from AOCI to Income
		Three Months Ended						Nine Months Ended
		September 30,						September 30,
	Location	2012			2011			2012			2011
Derivatives designated as cash flow hedging instruments:
Futures contracts for natural gas	Cost of product sales and natural gas storage services	$	—		$	(32	)	$	—		$	(251	)
Interest rate contracts	Interest and debt expense		(229	)		(229	)		(688	)		(691	)

	Change in Value Recognized in OCI on Derivatives
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
Derivatives designated as cash flow hedging instruments:
Futures contracts for natural gas	$	—		$	—		$	—		$	(46	)
Interest rate contracts		(6,396	)		(83,596	)		(29,471	)		(92,366	)

8. FAIR VALUE MEASUREMENTS

We categorize our financial assets and liabilities using the three-tier hierarchy as follows.

Recurring

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

	September 30, 2012						December 31, 2011
	Level 1			Level 2			Level 1		Level 2
Financial assets:
Physical fixed price derivative contracts	$	—		$	926		$	—	$	5,292
Physical index derivative contracts		—			672			—		834
Futures contracts for refined products		169			—			630		—
Financial liabilities:
Physical fixed price derivative contracts		—			(5,516	)		—		(1,245	)
Physical index derivative contracts		—			(726	)		—		(614	)
Futures contracts for refined products		(7,683	)		—			—		—
Interest rate derivatives		—			(131,381	)		—		(101,911	)
Fair value	$	(7,514	)	$	(136,025	)	$	630	$	(97,644	)

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

The values of the Level 2 physical derivative 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 physical derivative contracts assets are net of credit value adjustments (“CVAs”) determined using an expected cash flow model, which incorporates assumptions about the credit risk of the physical derivative 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 CVAs are appropriate because few of the Energy Services segment’s customers entering into these physical derivative contracts are large organizations with nationally-recognized credit ratings. The Level 2 physical derivative contracts assets of $1.6 million and $6.1 million as of September 30, 2012 and December 31, 2011, respectively, are net of CVAs of ($0.1) million for both periods, respectively. As of September 30, 2012, the Energy Services segment did not hold any net liability derivative position containing credit contingent features.

Cash and cash equivalents, prepaid and other current assets and accrued and other current liabilities are reported in the condensed consolidated balance sheets at amounts which approximate fair value due to the relatively short period to maturity of these financial instruments. The fair values of our fixed-rate debt were estimated by observing market trading prices and by comparing the historic market prices of our publicly-issued debt with the market prices of other MLPs’ publicly-issued debt with similar credit ratings and terms. The fair values of our variable-rate debt are their carrying amounts, as the carrying amount reasonably approximates fair value due to the variability of the interest rates. Using Level 2 input values, the fair values of our aggregate debt and credit facility were estimated to be $2,924.0 million and $2,811.7 million at September 30, 2012 and December 31, 2011, respectively.

Our policy is to recognize transfers between levels within the fair value hierarchy as of the beginning of the reporting period. We did not have any transfers between Level 1 and Level 2 during the nine months ended September 30, 2012 and 2011, respectively.

Non-Recurring

Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments in certain circumstances, such as when there is evidence of possible impairment. For the nine months ended September 30, 2012, there were not any fair value adjustments related to such assets or liabilities reflected in our condensed consolidated financial statements. During the nine months ended September 30, 2011, we recorded a non-cash goodwill impairment charge of $169.6 million based on Level 3 inputs. For a discussion of our valuation methodology relating to the goodwill impairment test, see Note 9 in our Annual Report on Form 10-K for the year ended December 31, 2011.

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

9. PENSIONS AND OTHER POSTRETIREMENT BENEFITS

Buckeye Pipe Line Services Company (“Services Company”), which employs the majority of our workforce, sponsors a defined benefit plan, the Retirement Income Guarantee Plan (the “RIGP”), and an unfunded post-retirement benefit plan (the “Retiree Medical Plan”). The components of the net periodic benefit cost for the RIGP and Retiree Medical Plan were as follows for the three months ended September 30, 2012 and 2011 (in thousands):

	RIGP						Retiree Medical Plan
	Three Months Ended						Three Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
Service cost	$	51		$	86		$	82		$	66
Interest cost		206			199			415			508
Expected return on plan assets		(140	)		(59	)		—			—
Amortization of prior service benefit		—			—			(623	)		(740	)
Amortization of unrecognized losses		231			260			319			327
Settlement charge		930			406			—			—
Net periodic benefit costs	$	1,278		$	892		$	193		$	161

The components of the net periodic benefit cost for the RIGP and the Retiree Medical Plan were as follows for the nine months ended September 30, 2012 and 2011 (in thousands):

	RIGP						Retiree Medical Plan
	Nine Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
Service cost	$	183		$	222		$	236		$	227
Interest cost		620			598			1,345			1,446
Expected return on plan assets		(340	)		(247	)		—			—
Amortization of prior service benefit		—			—			(2,047	)		(2,222	)
Amortization of unrecognized losses		1,028			896			945			933
Settlement charge		930			609			—			—
Net periodic benefit costs	$	2,421		$	2,078		$	479		$	384

During the nine months ended September 30, 2012, we contributed $2.7 million to the RIGP.

10. UNIT-BASED COMPENSATION PLANS

We award unit-based compensation to employees and directors primarily under the Buckeye Partners, L.P. 2009 Long-Term Incentive Plan (the “LTIP”). We formerly awarded options to acquire LP Units to employees pursuant to the Buckeye Partners, L.P. Unit Option and Distribution Equivalent Plan (the “Option Plan”). We recognized compensation expense related to the LTIP and the Option Plan of $2.8 million and $1.7 million for the three months ended September 30, 2012 and 2011, respectively. For the nine months ended September 30, 2012 and 2011, we recognized compensation expense related to the LTIP and the Option Plan of $10.5 million and $6.6 million, respectively. These compensation plans are discussed below.

20

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

LTIP

The LTIP provides for the issuance of up to 1,500,000 LP Units, subject to certain adjustments. After giving effect to the issuance or forfeiture of phantom unit and performance unit awards through September 30, 2012, awards representing a total of 552,332 additional LP Units could be issued under the LTIP.

Approximately $0.7 million of 2011 compensation awards were deferred at December 31, 2011, for which 23,426 phantom units (including matching units) were granted during the nine months ended September 30, 2012. These grants are included as granted in the LTIP activity table below.

Awards under the LTIP

During the nine months ended September 30, 2012, the Compensation Committee granted 228,230 phantom units to employees (including the 23,426 phantom units granted as discussed above), 14,000 phantom units to independent directors of Buckeye GP and 133,386 performance units to employees. The amount paid with respect to phantom unit distribution equivalents under the LTIP was $1.0 million and $0.8 million for the nine month periods ended September 30, 2012 and 2011, respectively.

The following table sets forth the LTIP activity for the periods indicated (in thousands, except per unit amounts):

				Weighted
				Average
				Grant Date
	Number of			Fair Value
	LP Units			per LP Unit (1)
Unvested at January 1, 2012		585		$	56.75
Granted		376			63.04
Vested		(105	)		46.68
Forfeited		(50	)		45.40
Unvested at September 30, 2012		806		$	61.70

(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 September 30, 2012, approximately $23.8 million of compensation expense related to the LTIP is expected to be recognized over a weighted average period of approximately 1.9 years.

21

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unit Option and Distribution Equivalent Plan

The following is a summary of the changes in the LP Unit options outstanding (all of which are vested) under the Option Plan for the periods indicated (in thousands, except per unit amounts):

						Weighted
				Weighted		Average
				Average		Remaining		Aggregate
	Number of			Strike Price		Contractual		Intrinsic
	LP Units			per LP Unit		Term (in years)		Value (1)
Outstanding at January 1, 2012		97		$	46.81
Exercised		(23	)		45.62
Outstanding at September 30, 2012		74			47.19		3.5	$	58
Exercisable at September 30, 2012		74		$	47.19		3.5	$	58

(1) Aggregate intrinsic value reflects fully vested LP Unit options at the date indicated. Intrinsic value is determined by calculating the difference between our closing LP Unit price on the last trading day in September 2012 and the exercise price, multiplied by the number of exercisable, in-the-money options.

The total intrinsic value of options exercised was $0.3 million and $1.3 million during the nine months ended September 30, 2012 and 2011, respectively.

11. PARTNERS’ CAPITAL AND DISTRIBUTIONS

In February 2012, we issued 4,262,575 LP Units to institutional investors in a registered direct offering for aggregate consideration of approximately $250.0 million at a price of $58.65 per LP Unit, before deducting placement agents’ fees and estimated offering expenses. We have used the majority of the net proceeds from this offering to reduce the indebtedness outstanding under our Credit Facility and have also funded a portion of the Perth Amboy Facility acquisition as well as certain other growth capital expenditures.

Summary of Changes in Outstanding Units

The following is a summary of changes in units outstanding for the periods indicated (in thousands):

	Limited		Class B
	Partners		Units		Total
Units outstanding at January 1, 2012		85,968		7,305		93,273
LP Units issued pursuant to the Option Plan (1)		23		—		23
LP Units issued pursuant to the LTIP (1)		77		—		77
Issuance of units to institutional investors		4,263		—		4,263
Issuance of Class B Units in lieu of quarterly cash distributions		—		473		473
Units outstanding at September 30, 2012		90,331		7,778		98,109

(1) The number of units issued represents issuance net of tax withholding.

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

22

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

appropriate. Actual cash distributions on our LP Units totaled $282.1 million and $252.2 million during the nine months ended September 30, 2012 and 2011, respectively. We also paid distributions in-kind to our Class B unitholders by issuing 472,931 Class B Units during the nine months ended September 30, 2012.

On November 2, 2012, we announced a quarterly distribution of $1.0375 per LP Unit that will be paid on November 30, 2012, to LP unitholders of record on November 12, 2012. Based on the LP Units outstanding as of September 30, 2012, cash distributed to LP unitholders on November 30, 2012 will total approximately $94.1 million. Based on Class B Units outstanding as of September 30, 2012, we also expect to issue approximately 198,000 Class B Units in lieu of cash distributions on November 30, 2012, to Class B unitholders of record on November 12, 2012.

12. EARNINGS (LOSS) PER UNIT

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2012		2011			2012		2011
Net income (loss) attributable to Buckeye Partners, L.P.	$	85,116	$	(109,700	)	$	191,454	$	48,814
Basic:
Weighted average units outstanding		97,993		92,982			97,017		89,499
Earnings (loss) per unit—basic	$	0.87	$	(1.18	)	$	1.97	$	0.55
Diluted:
Units used for basic calculation		97,993		92,982			97,017		89,499
Dilutive effect of LP Unit options and LTIP awards granted		349		—			323		332
Units for diluted		98,342		92,982			97,340		89,831
Earnings (loss) per unit—diluted	$	0.87	$	(1.18	)	$	1.97	$	0.54

13. BUSINESS SEGMENTS

We operate and report in five business segments: (i) Pipelines & Terminals; (ii) International Operations; (iii) Natural Gas Storage; (iv) Energy Services; and (v) Development & Logistics.

Pipelines & Terminals

The Pipelines & Terminals segment receives refined petroleum products from refineries, connecting pipelines, and bulk and marine terminals and transports those products to other locations for a fee and provides bulk storage and terminal throughput services in the continental United States. This segment owns and operates over 6,000 miles of pipeline systems in 17 states and also owns approximately 100 refined petroleum products terminals in 21 states, including five terminals owned by the Energy Services segment but operated by the Pipelines & Terminals segment. The segment has an aggregate storage capacity of over 40.0 million barrels, which includes our recent acquisition of the Perth Amboy Facility. See Note 2 for information regarding the Perth Amboy Facility acquisition.

23

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

International Operations

The International Operations segment provides marine bulk storage and marine terminal throughput services. The segment has two liquid petroleum product terminals, one in Puerto Rico and one on Grand Bahama Island in The Bahamas. The segment has an aggregate storage capacity of approximately 28.0 million barrels, which includes 1.9 million barrels of storage capacity completed in the second half of 2012 in connection with BORCO’s publicly announced expansion plans.

Natural Gas Storage

The Natural Gas Storage segment provides natural gas storage services at a natural gas storage facility in Northern California. The facility has approximately 30.0 Bcf of working natural gas storage capacity and is connected to Pacific Gas and Electric’s intrastate natural gas pipelines that services natural gas demand in the San Francisco and Sacramento, California areas. The Natural Gas Storage segment does not trade or market natural gas.

Energy Services

The Energy Services segment is a wholesale distributor of refined petroleum products in the Northeastern and Midwestern United States. This segment recognizes revenue when products are delivered. The segment’s products include gasoline, propane, ethanol, biodiesel and petroleum distillates such as heating oil, diesel fuel and kerosene. The segment owns five terminals with aggregate storage capacity of approximately 1.0 million barrels, which are operated by the Pipelines & Terminals segment. The segment’s customers consist principally of product wholesalers as well as major commercial users of these refined petroleum products.

Development & Logistics

The Development & Logistics segment consists primarily of our contract operations of third-party pipelines, which are owned principally by major oil and gas, petrochemical and chemical companies and are located primarily in Texas and Louisiana. This segment also performs pipeline construction management services, typically for cost plus a fixed fee, for these same customers. The Development & Logistics segment also includes our ownership and operation of two underground propane storage caverns in Indiana and Illinois and an ammonia pipeline, as well as our majority ownership of the Sabina Pipeline, located in Texas.

Adjusted EBITDA

Adjusted EBITDA is the primary measure used by our senior management, including our Chief Executive Officer, to: (i) evaluate our consolidated operating performance and the operating performance of our business segments; (ii) allocate resources and capital to business segments; (iii) evaluate the viability of proposed projects; and (iv) determine overall rates of return on alternative investment opportunities. Adjusted EBITDA eliminates: (i) non-cash expenses, including but not limited to depreciation and amortization expense resulting from the significant capital investments we make in our businesses and from intangible assets recognized in business combinations; (ii) charges for obligations expected to be settled with the issuance of equity instruments; and (iii) items that are not indicative of our core operating performance results and business outlook.

We believe that investors benefit from having access to the same financial measures that we use and that these measures are useful to investors because they aid in comparing our operating performance with that of other companies with similar operations. The Adjusted EBITDA data presented by us may not be comparable to similarly titled measures at other companies because these items may be defined differently by other companies.

Each segment uses the same accounting policies as those used in the preparation of our condensed consolidated financial statements. All inter-segment revenue has been eliminated. All periods are presented on a consistent basis. All of our operations and assets are conducted and located in the continental United States, except for our terminals located in Puerto Rico and The Bahamas.

24

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes our revenue by each segment for the periods indicated (in thousands):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
Revenue:
Pipelines & Terminals	$	194,609		$	162,740		$	527,849		$	456,056
International Operations (1)		51,686			47,986			152,349			146,051
Natural Gas Storage		20,229			15,742			46,909			49,431
Energy Services		691,875			894,618			2,469,122			2,810,055
Development & Logistics		11,798			10,766			37,415			30,937
Intersegment		(4,227	)		(14,941	)		(25,595	)		(45,991	)
Total revenue	$	965,970		$	1,116,911		$	3,208,049		$	3,446,539

(1) The International Operations segment’s revenue generated in The Bahamas was $48.2 million and $43.9 million for the three months ended September 30, 2012 and 2011, which represented 93.2% and 91.5%, respectively, of the International Operations segment’s total revenue for the periods. For the nine months ended September 30, 2012 and 2011, the International Operations segment’s revenue generated in The Bahamas was $141.4 million and $134.1 million, which represented 92.8% and 91.8%, respectively, of the International Operations segment’s total revenue for the periods.

For the nine months ended September 30, 2012 and 2011, no customer contributed 10% or more of consolidated revenue.

25

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following tables present Adjusted EBITDA by segment and on a consolidated basis and a reconciliation of net income (loss) to Adjusted EBITDA for the periods indicated (in thousands):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
Adjusted EBITDA:
Pipelines & Terminals	$	112,879		$	86,510		$	290,709		$	260,743
International Operations		33,548			30,095			95,805			86,248
Natural Gas Storage		1,357			426			(299	)		266
Energy Services		1,619			6,978			(7,759	)		13,578
Development & Logistics		3,168			2,519			9,034			5,563
Total Adjusted EBITDA	$	152,571		$	126,528		$	387,490		$	366,398
Reconciliation of Net Income (Loss) to Adjusted EBITDA:
Net income (loss)	$	85,259		$	(108,200	)	$	194,752		$	53,205
Less: Net income attributable to noncontrolling interests		(143	)		(1,500	)		(3,298	)		(4,391	)
Net income (loss) attributable to Buckeye Partners, L.P.		85,116			(109,700	)		191,454			48,814
Add: Interest and debt expense		28,737			33,199			85,159			90,292
Income tax expense (benefit)		511			—			1,177			(193	)
Depreciation and amortization		37,134			31,230			104,486			87,227
Non-cash deferred lease expense		975			1,030			2,925			3,091
Non-cash unit-based compensation expense		2,846			1,694			10,534			6,532
Goodwill impairment expense		—			169,560			—			169,560
Less: Amortization of unfavorable storage contracts (1)		(2,748	)		(485	)		(8,245	)		(4,813	)
Gain on sale of equity investment		—			—			—			(34,112	)
Adjusted EBITDA	$	152,571		$	126,528		$	387,490		$	366,398

(1) Represents amortization of negative fair values allocated to certain unfavorable storage contracts acquired in connection with the BORCO acquisition.

26

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

14. SUPPLEMENTAL CASH FLOW INFORMATION

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

	Nine Months Ended
	September 30,
	2012			2011
Cash paid for interest (net of capitalized interest)	$	101,815		$	101,998
Cash paid for income taxes		1,413			1,104
Capitalized interest		7,061			5,388
Non-cash changes in assets and liabilities:
Change in accounts payable and accrued and other current liabilities related to capital expenditures	$	(3,676	)	$	20,084
Non-cash financing activities:
Issuance of units to First Reserve for BORCO acquisition	$	—		$	407,391
Issuance of units to Vopak for BORCO acquisition		—			96,110
Issuance of Class B Units in lieu of quarterly cash distribution		23,195			20,756

27

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

Cautionary Note Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q (this “Report”) 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 Report, 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 Part I “Item 1A, Risk Factors” included in our Annual Report on Form 10-K for the year ended December 31, 2011 and Part II “Item 1A. Risk Factors” of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2012. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Although the expectations in the forward-looking statements are based on our current beliefs and expectations, caution should be taken not to place undue reliance on any such forward-looking statements because such statements speak only as of the date hereof. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason.

The following information should be read in conjunction with our unaudited condensed consolidated financial statements and accompanying notes included in this Report.

Overview of Business

Buckeye Partners, L.P. is a publicly traded Delaware master limited partnership and its limited partnership units representing limited partner interests (“LP Units”) are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “BPL.” Buckeye GP LLC (“Buckeye GP”) is our general partner. As used in this Report, unless otherwise indicated, “we,” “us,” “our” and “Buckeye” mean Buckeye Partners, L.P. and, where the context requires, includes our subsidiaries.

We were formed in 1986 and own and operate one of the largest independent refined petroleum products pipeline systems in the United States in terms of volumes delivered, with over 6,000 miles of pipeline and over 100 active products terminals that provide aggregate storage capacity of approximately 70 million barrels. We also operate and/or maintain third-party pipelines under agreements with major oil and gas, petrochemical and chemical companies, and perform certain engineering and construction management services for third parties. We also own and operate a natural gas storage facility in Northern California, and are a wholesale distributor of refined petroleum products in the United States in areas also served by our pipelines and terminals. Our flagship marine terminal in The Bahamas, Bahamas Oil Refining Company International Limited (“BORCO”), is one of the largest marine crude oil and petroleum products storage facilities in the world, serving the international markets as a premier global logistics hub.

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

28

Recent Developments

Acquisitions

In September 2012, our operating subsidiary, Buckeye Pipe Line Holdings, L.P. (“BPH”), purchased an additional 20% ownership interest in WesPac Pipelines – Memphis LLC (“WesPac Memphis”) from Kealine LLC for $17.3 million and, as a result of the acquisition, our ownership interest in WesPac Memphis increased from 50% to 70%. Since BPH retains controlling interest in WesPac Memphis, this acquisition was accounted for as an equity transaction.

In July 2012, we acquired a marine terminal facility for liquid petroleum products in New York Harbor (the “Perth Amboy Facility”) from Chevron U.S.A. Inc. (“Chevron”) for $260.3 million in cash. The facility, which sits on approximately 250 acres on the Arthur Kill tidal strait in Perth Amboy, New Jersey, has over 4.0 million barrels of tankage, four docks, and significant undeveloped land available for potential expansion. The Perth Amboy Facility has water, pipeline, rail, and truck access, and is located six miles from our Linden, New Jersey complex. The facility provides a link between our inland pipelines and terminals and our BORCO facility in The Bahamas and opportunities for improved service offerings to our customers. Concurrent with the acquisition, we entered into multi-year storage, blending, and throughput commitments with Chevron.

Equity Offering

In February 2012, we issued 4,262,575 LP Units to institutional investors in a registered direct offering for aggregate consideration of approximately $250.0 million at a price of $58.65 per LP Unit, before deducting placement agents’ fees and estimated offering expenses. We have used the majority of the net proceeds from this offering to reduce the indebtedness outstanding under our Revolving Credit Agreement dated September 26, 2011 (the “Credit Facility”) with SunTrust Bank and to fund a portion of the Perth Amboy Facility acquisition as well as certain other growth capital expenditures.

Results of Operations

Non-GAAP Financial Measures

Adjusted EBITDA is the primary measure used by our senior management, including our Chief Executive Officer, to: (i) evaluate our consolidated operating performance and the operating performance of our business segments; (ii) allocate resources and capital to business segments; (iii) evaluate the viability of proposed projects; and (iv) determine overall rates of return on alternative investment opportunities. Distributable cash flow is another measure used by our senior management to provide a clearer picture of cash available for distribution to its unitholders. Adjusted EBITDA and distributable cash flow eliminate: (i) non-cash expenses, including but not limited to, depreciation and amortization expense resulting from the significant capital investments we make in our businesses and from intangible assets recognized in business combinations; (ii) charges for obligations expected to be settled with the issuance of equity instruments; and (iii) items that are not indicative of our core operating performance results and business outlook.

We believe that investors benefit from having access to the same financial measures that we use and that these measures are useful to investors because they aid in comparing our operating performance with that of other companies with similar operations. The Adjusted EBITDA and distributable cash flow data presented by us may not be comparable to similarly titled measures at other companies because these items may be defined differently by other companies.

29

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
Adjusted EBITDA:
Pipelines & Terminals	$	112,879		$	86,510		$	290,709		$	260,743
International Operations		33,548			30,095			95,805			86,248
Natural Gas Storage		1,357			426			(299	)		266
Energy Services		1,619			6,978			(7,759	)		13,578
Development & Logistics		3,168			2,519			9,034			5,563
Total Adjusted EBITDA	$	152,571		$	126,528		$	387,490		$	366,398
Reconciliation of Net Income (Loss) to Adjusted EBITDA and Distributable Cash Flow:
Net income (loss)	$	85,259		$	(108,200	)	$	194,752		$	53,205
Less: Net income attributable to noncontrolling interests		(143	)		(1,500	)		(3,298	)		(4,391	)
Net income (loss) attributable to Buckeye Partners, L.P.		85,116			(109,700	)		191,454			48,814
Add: Interest and debt expense		28,737			33,199			85,159			90,292
Income tax expense (benefit)		511			—			1,177			(193	)
Depreciation and amortization		37,134			31,230			104,486			87,227
Non-cash deferred lease expense		975			1,030			2,925			3,091
Non-cash unit-based compensation expense		2,846			1,694			10,534			6,532
Goodwill impairment expense		—			169,560			—			169,560
Less: Amortization of unfavorable storage contracts (1)		(2,748	)		(485	)		(8,245	)		(4,813	)
Gain on sale of equity investment		—			—			—			(34,112	)
Adjusted EBITDA	$	152,571		$	126,528		$	387,490		$	366,398
Less: Interest and debt expense, excluding amortization of deferred financing costs and debt discounts		(27,868	)		(28,709	)		(82,552	)		(83,541	)
Income tax (expense) benefit		(511	)		—			(1,177	)		193
Maintenance capital expenditures		(11,889	)		(16,803	)		(35,764	)		(36,569	)
Distributable cash flow	$	112,303		$	81,016		$	267,997		$	246,481

(1) Represents amortization of negative fair values allocated to certain unfavorable storage contracts acquired in connection with the BORCO acquisition.

30

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2012		2011		2012		2011
Pipelines & Terminals (average bpd in thousands):
Pipelines:
Gasoline		729.7		693.4		705.9		658.3
Jet fuel		352.7		344.8		342.7		339.8
Middle distillates (1)		306.0		298.7		314.6		309.4
Other products (2)		18.8		19.6		23.5		24.7
Total pipelines throughput		1,407.2		1,356.5		1,386.7		1,332.2
Terminals:
Products throughput (3)		910.9		879.1		888.3		681.5
Energy Services (in millions of gallons):
Sales volumes		233.4		297.4		836.7		960.8

(1) Includes diesel fuel, heating oil and kerosene.

(2) Includes liquefied petroleum gas (“LPG”).

(3) Amounts include throughput volumes at terminals acquired from BP Products North America Inc. and its affiliates (“BP”) and ExxonMobil Corporation on June 1, 2011 and July 19, 2011, respectively.

Three Months Ended September 30, 2012 Compared to Three Months Ended September 30, 2011

Consolidated

Adjusted EBITDA was $152.6 million for the three months ended September 30, 2012, which is an increase of $26.1 million, or 20.6%, from $126.5 million for the corresponding period in 2011. The increase in Adjusted EBITDA was primarily related to additional revenue due to higher pipeline tariff rates and terminalling contract rate escalations, increased pipeline and terminalling volumes and favorable settlement experience in the Pipelines & Terminals segment, as well as an increase in revenue and reduced operating expenses in the International Operations segment. These increases in Adjusted EBITDA were partially offset by reduced earnings in the Energy Services segment as a result of continued market backwardation and declining basis in the Northeast refined petroleum commodity markets that adversely affected our profitability. Backwardation is a market condition in which commodity futures contracts with a delivery month further away in time have lower settlement prices than commodity futures contracts with a delivery month closer in time. Basis is the difference between the physical spot price for a commodity and the prompt contract price for the respective physical commodity.

Revenue was $966.0 million for the three months ended September 30, 2012, which is a decrease of $150.9 million, or 13.5%, from $1,116.9 million for the corresponding period in 2011. The decrease in revenue was primarily related to a decrease in refined petroleum product sales prices and lower product sales volume in the Energy Services segment, which was partially offset by an increase in revenue related to higher pipeline tariff rates and terminalling contract rate escalations, increased pipeline and terminalling volumes and a favorable settlement experience in the Pipelines & Terminals segment.

Operating income was $113.4 million for the three months ended September 30, 2012, which is an increase of $190.7 million, or 246.6%, from a loss of $77.3 million for the corresponding period in 2011. The increase in operating income was primarily related to additional revenue due to higher pipeline tariff rates and terminalling contract rate escalations, increased pipeline and terminalling volumes and a favorable settlement experience in the Pipelines & Terminals segment, as well as a non-cash goodwill impairment charge in the Natural Gas Storage segment in 2011. These increases were partially offset by decreased earnings in the Energy Services segment due to adverse market conditions.

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Distributable cash flow was $112.3 million for the three months ended September 30, 2012, which is an increase of $31.3 million, or 38.6%, from $81.0 million as compared to the corresponding period in 2011. The increase in distributable cash flow was primarily related to an increase of $26.1 million in Adjusted EBITDA as described above and a $4.9 million decrease in maintenance capital expenditures relating to the timing of pipeline and tank integrity work performed in the Pipelines & Terminals segment.

Adjusted EBITDA by Segment

Pipelines & Terminals. Adjusted EBITDA from the Pipelines & Terminals segment was $112.9 million for the three months ended September 30, 2012, which is an increase of $26.4 million, or 30.5%, from $86.5 million for the corresponding period in 2011. The positive factors impacting Adjusted EBITDA were primarily related to $13.0 million of favorable settlement experience, $8.0 million in additional revenue due to higher pipeline tariff rates, long-haul shipments and terminalling contract rate escalations, a $5.5 million increase in revenue due to higher pipeline and terminalling volumes, a $4.0 million increase in revenue resulting from the Perth Amboy Facility acquired in 2012, a $1.6 million increase in earnings due to the purchase of an additional 20% ownership interest in WesPac Memphis and a $1.3 million increase in other revenue resulting primarily from higher butane blending capabilities in the Northeast. The favorable settlement experience primarily related to the successful resolution of a $10.6 million product settlement allocation matter related to certain pipeline transportation-related services provided by Buckeye over a period of several years, of which $7.8 million related to services rendered in prior years but, for accounting purposes, was not recognized in revenue until the current period.

The negative factors impacting Adjusted EBITDA were a $1.9 million increase in operating expenses from the Perth Amboy Facility acquired in 2012, a $1.8 million decrease in earnings from equity investments primarily due to higher environmental remediation cost estimates, $1.5 million of fees related to temporary suspension of ethanol offloading capabilities at our Albany facility, a $1.1 million increase in operating expenses primarily related to payroll costs and $0.7 million in fees related to the legal proceedings before the Federal Energy Regulatory Commission (“FERC”).

Pipeline volumes increased by 3.7% as a result of higher demand for gasoline and middle distillates, as well as changes in supply patterns resulting from the refinery closures affecting the Philadelphia market in 2012 and extreme weather conditions and related refinery issues in 2011. Terminalling volumes increased by 3.6% due to higher demand for gasoline and distillates resulting from new customer contracts and service offerings at select locations, effective commercialization of acquired assets and continued positive contribution from our recently completed internal growth projects.

International Operations. Adjusted EBITDA from the International Operations segment was $33.5 million for the three months ended September 30, 2012, which is an increase of $3.4 million, or 11.5%, from $30.1 million for the corresponding period in 2011. The positive factors impacting Adjusted EBITDA were primarily related to a $2.1 million decrease in expenses, which included fuel and utilities expenses and professional fees and a $1.3 million increase in revenue as a result of the initial 1.1 million barrels of our BORCO expansion becoming operational as of the beginning of the quarter and the overall lease rate for the period remaining relatively flat.

Natural Gas Storage. Adjusted EBITDA from the Natural Gas Storage segment was $1.4 million for the three months ended September 30, 2012, which is an increase of $1.0 million, or 218.5%, from $0.4 million for the corresponding period in 2011. The increase in Adjusted EBITDA was primarily the result of a $7.0 million increase in fees for hub services activities, partially offset by a $2.5 million increase in costs of natural gas storage services which includes hub services fees paid to customers for hub service activities, a $2.5 million decrease in lease revenue due to lower firm storage rates and a $1.0 million net increase in operating expenses, which included lease expenses and payroll costs. Lease revenue and hub service fees are primarily determined by the difference in natural gas commodity prices for the periods in which natural gas is injected and withdrawn from the storage facility (i.e., time spread).

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Energy Services. Adjusted EBITDA from the Energy Services segment was $1.6 million for the three months ended September 30, 2012, which is a decrease of $5.4 million, or 76.8%, from $7.0 million for the corresponding period in 2011. Despite aggressive management of our inventory levels and reduction of our exposure to market backwardation, adverse market conditions continued to negatively impact the value of our inventory portfolio, which contributed to the unfavorable impact on our overall sales margin. In addition, during 2011, we recognized $1.6 million in biodiesel tax credits as a reduction to cost of sales, but due to legislative changes enacted during 2012, the biodiesel tax credits were disallowed in the current period.

The decrease in Adjusted EBITDA was primarily related to a $202.7 million decrease in revenue, which included a $10.2 million decrease as a result of approximately $0.05 per gallon decrease in refined petroleum product sales price (average sales prices per gallon were $2.96 and $3.01 for the 2012 and 2011 periods, respectively) and a $192.5 million decrease due to 21.5% lower sales volumes.

The decrease in revenue was partially offset by a $196.3 million decrease in cost of product sales, which included a $6.0 million decrease as a result of approximately $0.02 per gallon decrease in refined petroleum product cost price (average cost prices per gallon were $2.95 and $2.97 for the 2012 and 2011 periods, respectively) and a $190.3 million decrease due to 21.5% of lower volumes sold, and a $1.0 million decrease in operating expenses, which primarily related to overhead costs.

Development & Logistics. Adjusted EBITDA from the Development & Logistics segment was $3.2 million for the three months ended September 30, 2012, which is an increase of $0.7 million, or 25.8%, from $2.5 million for the corresponding period in 2011. The increase in Adjusted EBITDA was primarily due to $1.4 million in revenue related to the LPG storage caverns acquired in November 2011 and a $0.2 million decrease in third-party engineering and operations expenses, partially offset by a $0.4 million decrease in third-party engineering and operations revenue, both as a result of reduced construction contract services, and a $0.3 million increase in operating expenses, which primarily related to overhead costs and $0.2 million in operating expenses for the LPG storage caverns.

Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011

Consolidated

Adjusted EBITDA was $387.5 million for the nine months ended September 30, 2012, which is an increase of $21.1 million, or 5.8%, from $366.4 million for the corresponding period in 2011. The increase in Adjusted EBITDA was primarily related to positive contribution as a result of a full period of operating activities for 2011 acquisitions in the Pipelines & Terminals segment and International Operations segment, as well as a decrease in expenses in the International Operations segment. These increases were partially offset by losses incurred in the Energy Services segment as a result of declining basis in the Midwest and Northeast refined petroleum commodity markets that adversely affected the value of our inventory portfolio.

Revenue was $3,208.0 million for the nine months ended September 30, 2012, which is a decrease of $238.5 million, or 6.9%, from $3,446.5 million for the corresponding period in 2011. The decrease in revenue was primarily related to a net decrease in revenue in the Energy Services segment, which was partially offset by the revenue generated due to a full period of operations for the 2011 acquisitions in the Pipelines & Terminals segment.

Operating income was $275.6 million for the nine months ended September 30, 2012, which is an increase of $174.4 million, or 172.3%, from $101.2 million for the corresponding period in 2011. The increase in operating income was primarily related to a non-cash goodwill impairment charge in the Natural Gas Storage segment in 2011 and positive contribution as a result of a full period of operating activities for 2011 acquisitions in the Pipelines & Terminals segment and International Operations segment. These increases were partially offset by losses incurred in the Energy Services segment due to adverse market conditions and an increase in depreciation due to the assets acquired in 2011 in the Pipelines & Terminals segment and the upgrades and expansions of the jetty structure in the International Operations segment.

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Distributable cash flow was $268.0 million for the nine months ended September 30, 2012, which is an increase of $21.5 million, or 8.7%, from $246.5 million as compared to the corresponding period in 2011. The increase in distributable cash flow was primarily related to an increase of $21.1 million in Adjusted EBITDA as described above.

Adjusted EBITDA by Segment

Pipelines & Terminals. Adjusted EBITDA from the Pipelines & Terminals segment was $290.7 million for the nine months ended September 30, 2012, which is an increase of $30.0 million, or 11.5%, from $260.7 million for the corresponding period in 2011. The positive factors impacting Adjusted EBITDA were related to a $37.3 million increase in revenue due to a full period of operations for the assets acquired in 2011 and the Perth Amboy Facility acquired in 2012, a $27.1 million increase in revenue due to higher pipeline tariff rates and terminalling contract rate escalations on assets owned prior to the 2011 and 2012 acquisitions (which we refer to as our “legacy assets”), $4.9 million of favorable net settlement experience and a $1.4 million increase in other revenue resulting primarily from higher butane blending capabilities in the Northeast. The favorable net settlement experience included the successful resolution of a $10.6 million product settlement allocation matter related to certain pipeline transportation-related services provided by Buckeye over a period of several years, of which $7.8 million related to services rendered in prior years but, for accounting purposes, was not recognized in revenue until the current period.

The negative factors impacting Adjusted EBITDA were a $15.6 million increase in operating expenses related to the full period of operations of the assets acquired in 2011 and the Perth Amboy Facility acquired in 2012, which included acquisition and transition expenses, a $12.1 million increase in operating expenses, which included integrity program expenditures, payroll costs, insurance and environmental remediation expenses, a $5.4 million increase in expenses related to the relocation of certain operations and administrative support functions to our Houston, TX headquarters, a $3.5 million decrease in earnings from equity investments primarily due to higher environmental remediation costs and the sale of our interest in West Texas LPG Pipeline Limited Partnership in 2011, a $1.7 million increase in fees related to the legal proceedings before the FERC, $1.5 million of fees related to the temporary suspension of ethanol offloading capabilities at our Albany facility and a $0.9 million increase in other costs.

Overall pipeline and terminalling volumes increased by 4.1% and 30.3%, respectively, primarily as a result of the assets acquired in 2011. Legacy pipeline and terminalling volumes remained relatively flat between the periods.

International Operations. Adjusted EBITDA from the International Operations segment was $95.8 million for the nine months ended September 30, 2012, which is an increase of $9.6 million, or 11.1%, from $86.2 million for the corresponding period in 2011. The positive factors impacting Adjusted EBITDA were primarily related to a $5.1 million decrease in expenses, which included professional fees and payroll costs, a $2.8 million increase in revenue as a result of the initial 1.1 million barrels of our BORCO expansion becoming operational as of the beginning of the quarter and an overall lease rate increase of 4.3%, and $1.7 million decrease in income allocated to noncontrolling interests related to the remaining 20% ownership interest in BORCO not acquired by us until February 16, 2011.

Natural Gas Storage. Adjusted EBITDA from the Natural Gas Storage segment was a loss of $0.3 million for the nine months ended September 30, 2012, which is a decrease of $0.6 million, or 212.4%, from earnings of $0.3 million for the corresponding period in 2011. The decrease in Adjusted EBITDA was primarily the result of a $10.3 million decrease in lease revenue due to lower firm storage rates, partially offset by a $7.8 million increase in fees for hub services activities, a $1.0 million decrease in costs of natural gas storage services, which includes hub services fees paid to customers for hub service activities and a $0.9 million decrease in operating expenses, which primarily related to a decline in the number of well workovers performed during 2012 as compared to the 2011 period. Lease revenue and hub services revenue are affected by the difference in natural gas commodity prices for the periods in which natural gas is injected and withdrawn from the storage facility (i.e., time spread).

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Energy Services. Adjusted EBITDA from the Energy Services segment was a loss of $7.8 million for the nine months ended September 30, 2012, which is a decrease of $21.4 million, or 157.1%, from earnings of $13.6 million for the corresponding period in 2011. In the first quarter of 2012, we developed and executed a strategy to mitigate the basis risk that included the reduction of refined petroleum product inventories in the Midwest. As a result, losses generated from the execution of our strategy contributed to the decrease in Adjusted EBITDA. During the period, because adverse market conditions continued, we incurred losses, despite aggressive management of our inventory levels and reduction of our exposure to market backwardation. In addition, during 2011, we recognized $5.3 million in biodiesel tax credits as a reduction to cost of sales, but due to legislative changes enacted during 2012, the biodiesel tax credits were disallowed in the current period.

The decrease in Adjusted EBITDA was primarily related to a $341.1 million net decrease in revenue, which included a $363.0 million decrease due to 12.9% of lower sales volumes, offset by a $21.9 million increase as a result of approximately $0.03 per gallon increase in refined petroleum product sales price (average sales prices per gallon were $2.95 and $2.92 for the 2012 and 2011 periods, respectively).

This decrease in revenue was partially offset by a $318.6 million net decrease in cost of product sales, which included a $359.8 million decrease due to 12.9% of lower volumes sold, offset by a $41.2 million increase as a result of approximately $0.05 per gallon increase in refined petroleum product cost price (average cost prices per gallon were $2.95 and $2.90 for the 2012 and 2011 periods, respectively) and a $1.1 million decrease in operating expenses, which primarily related to overhead costs.

Development & Logistics. Adjusted EBITDA from the Development & Logistics segment was $9.0 million for the nine months ended September 30, 2012, which is an increase of $3.4 million, or 62.4%, from $5.6 million for the corresponding period in 2011. The increase in Adjusted EBITDA was primarily due to a $4.0 million increase in revenue related to the LPG storage caverns acquired in November 2011, a $2.5 million increase in third-party engineering and operations revenue as a result of new contracts and higher fees, partially offset by a $1.4 million increase in operating expenses, which primarily related to overhead costs, a $0.9 million increase in third-party engineering and operations expenses and a $0.8 million increase in operating expenses for the LPG storage caverns.

Liquidity and Capital Resources

General

The following section describes our liquidity and capital requirements, including sources and uses of liquidity and capital resources. Our primary cash requirements, in addition to normal operating expenses and debt service, are for working capital, capital expenditures, business acquisitions and distributions to partners. Our principal sources of liquidity are cash from operations, borrowings under our Credit Facility and proceeds from the issuance of our units. We will, from time to time, issue debt securities to permanently finance amounts borrowed under our Credit Facility. Buckeye Energy Services LLC (“BES”) funds its working capital needs principally from its operations and its portion of our Credit Facility. Our financial policy has been to fund maintenance capital expenditures with cash from operations. Expansion and cost reduction capital expenditures, along with acquisitions, have typically been funded from external sources including our Credit Facility as well as debt and equity offerings. Our goal has been to fund at least half of these expenditures with proceeds from equity offerings in order to maintain our investment-grade credit rating.

Based on current market conditions, we believe our borrowing capacity under our Credit Facility, cash flows from operations and access to debt and equity markets, if necessary, will be sufficient to fund our primary cash requirements, including our expansion plans over the next 12 months.

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Current Liquidity

We had the following liquidity available to meet our working capital needs, capital expenditures, business acquisitions and distributions to partners as of the period indicated (in thousands):

	September 30,
	2012
Cash and cash equivalents	$	2,951
Availability under our Credit Facility (1)		481,400
Total available liquidity	$	484,351

(1) At September 30, 2012, we had $481.4 million of availability under our Credit Facility but, except for borrowings that are used to refinance other debt, we are limited to $230.9 million of additional borrowings by the financial covenants under our Credit Facility.

At September 30, 2012, we had total fixed-rate and variable-rate debt obligations of $2,075.0 million and $768.6 million, respectively, with an aggregate fair value of $2,924.0 million. At September 30, 2012, we were not aware of any instances of noncompliance with the covenants under our Credit Facility.

Capital Structuring Transactions

As part of our ongoing efforts to maintain a capital structure that is closely aligned with the cash-generating potential of our asset-based business, we may explore additional sources of external liquidity, including public or private debt or equity issuances. Matters to be considered will include cash interest expense and maturity profile, all to be balanced with maintaining adequate liquidity. We have a universal shelf registration statement that does not place any dollar limits on the amount of debt and equity securities that we may issue thereunder and a traditional shelf registration statement that currently has a $750.0 million limit on the amount of equity securities that we may issue thereunder on file with the SEC. The timing of any transaction may be impacted by events, such as strategic growth opportunities, legal judgments or regulatory or environmental requirements. The receptiveness of the capital markets to an offering of debt or equity securities cannot be assured and may be negatively impacted by, among other things, our long-term business prospects and other factors beyond our control, including market conditions.

In addition, consistent with industry practice, we periodically evaluate engaging in strategic transactions as a source of capital or may consider divesting non-core assets where such evaluation suggests such a transaction is in the best interest of Buckeye.

Capital Allocation

We continually review our investment options with respect to our capital resources that are not distributed to our unitholders or used to pay down our debt and seek to invest these capital resources in various projects and activities based on their return to Buckeye. Potential investments could include, among others: add-on or other enhancement projects associated with our current assets; greenfield or brownfield development projects at BORCO; and merger and acquisition activities.

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Current Maturities Expected to be Refinanced

The $300.0 million of 4.625% Notes maturing on July 15, 2013 has been classified as long-term debt under the assumption that our Credit Facility could be used to refinance this debt, if required. At September 30, 2012, we had $481.4 million of availability under our Credit Facility but, except for borrowings that are used to refinance other debt, we are limited to $230.9 million of additional borrowings by the financial covenants under our Credit Facility. It is our intent to refinance the 4.625% Notes in 2013.

Equity

In February 2012, we issued 4,262,575 LP units to institutional investors in a registered direct offering for aggregate consideration of approximately $250.0 million at a price of $58.65 per LP Unit, before deducting placement agents’ fees and estimated offering expenses. We have used the majority of the net proceeds from this offering to reduce the indebtedness outstanding under our Credit Facility and have also funded indirectly a portion of the Perth Amboy Facility acquisition as well as certain other growth capital expenditures.

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):

	Nine Months Ended
	September 30,
	2012			2011
Cash provided by (used in):
Operating activities	$	347,996		$	182,062
Investing activities		(493,615	)		(1,191,429	)
Financing activities		135,584			1,011,937

Operating Activities

Net cash provided by operating activities was $348.0 million for the nine months ended September 30, 2012, which is an increase of $165.9 million, from $182.1 million for the corresponding period in 2011. The increase in net cash provided by operating activities primarily related to an increase in net income and a decrease in refined petroleum products inventory in the Energy Services segment. In the first quarter of 2012, we developed and executed a strategy to mitigate our basis risk that included the reduction of refined petroleum product inventories in the Midwest. This strategy reduced refined petroleum products inventory in the Energy Services segment and mitigated basis risk following the volatility experienced in late 2011 and into early 2012.

Future Operating Cash Flows. Our future operating cash flows will vary based on a number of factors, many of which are beyond our control, including demand for our services, the cost of commodities, the effectiveness of our strategy, legal environmental and regulatory requirements and our ability to capture value associated with commodity price volatility.

Investing Activities

Net cash used in investing activities was $493.6 million for the nine months ended September 30, 2012, which is a decrease of $697.8 million, from $1,191.4 million for the corresponding period in 2011. During 2012, we paid $260.3 million for the acquisition of the Perth Amboy Facility and $233.0 million for capital expenditures. See below for a discussion of capital spending. During 2011, we paid net cash consideration of $893.7 million for the BORCO acquisition, $166.0 million to acquire the pipeline and terminal assets from BP and $191.4 million for capital expenditures, which were partially offset by $85.0 million in cash proceeds from the sale of our 20% interest in West Texas LPG Pipeline Limited Partnership.

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

	Nine Months Ended
	September 30,
	2012		2011
Maintenance capital expenditures	$	35,764	$	36,569
Expansion and cost reduction		197,241		154,799
Total capital expenditures, net	$	233,005	$	191,368

In the nine months ended September 30, 2012, maintenance capital expenditures included terminal pump replacements and truck rack infrastructure upgrades, as well as pipeline and tank integrity work, and expansion and cost reduction projects included significant investments in storage tank expansion at BORCO, biodiesel and butane blending, rail off-loading facilities, and various other operating infrastructure projects. In the nine months ended September 30, 2011, maintenance capital expenditures included pipeline and tank integrity work, and expansion and cost reduction projects included upgrades and expansions of the jetty structure at BORCO, terminal ethanol and butane blending, new pipeline connections, new natural gas storage well recompletions, continued progress on a new pipeline and terminal billing system, as well as various other operating infrastructure projects.

We estimated our capital expenditures as follows for the period indicated (in thousands):

	2012
	Low		High
Pipelines & Terminals:
Maintenance capital expenditures	$	36,000	$	42,000
Expansion and cost reduction		115,000		125,000
Total capital expenditures	$	151,000	$	167,000
International Operations:
Maintenance capital expenditures	$	14,000	$	18,000
Expansion and cost reduction		145,000		155,000
Total capital expenditures	$	159,000	$	173,000
Overall:
Maintenance capital expenditures	$	50,000	$	60,000
Expansion and cost reduction		260,000		280,000
Total capital expenditures	$	310,000	$	340,000

Estimated maintenance 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. Estimated major expansion and cost reduction expenditures include storage tank expansion projects at the BORCO facility, completion of additional storage tanks and rail loading facilities in the Midwest, the refurbishment of storage tanks and facilities in the Northeast, installation of a major crude oil offloading system in Albany, continued development of our Perth Amboy infrastructure, additive system installation throughout our terminal infrastructure and various upgrades and expansions of our ethanol business. Furthermore, cost reduction expenditures improve operational efficiencies or reduce costs.

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Financing Activities

Net cash provided by financing activities was $135.6 million for the nine months ended September 30, 2012, which is a decrease of $876.3 million, from $1,011.9 million in net cash provided by financing activities for the corresponding period in 2011. During 2012, we borrowed $856.0 million under our Credit Facility and received $246.8 million in net proceeds from the issuance of 4.3 million LP Units to institutional investors in a registered direct offering primarily to reduce the indebtedness outstanding under our Credit Facility and also fund a portion of the Perth Amboy Facility acquisition. These amounts were partially offset by the repayment of $577.4 million of outstanding borrowings under our Credit Facility and $278.3 million of distributions paid to unitholders. During 2011, we borrowed $1,100.2 million under our prior revolving credit agreement, received $737.0 million in net proceeds from the issuance of 5.8 million LP Units and 1.3 million Class B Units to institutional investors to fund a portion of the BORCO acquisition and received $647.5 million from the issuance of 4.875% Notes in an underwritten public offering. These amounts were partially offset by the repayment of $952.5 million of outstanding borrowings under our prior revolving credit agreement, repayment of $318.2 million of debt assumed in the BORCO acquisition and $250.2 million of distributions paid to unitholders.

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, 2011.

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

The following should be read in conjunction with Quantitative and Qualitative Disclosures About Market Risk included under Item 7A in our Annual Report on Form 10-K for the year ended December 31, 2011. There have been no material changes in that information other than as discussed below. Also see Note 7 in the Notes to Unaudited Condensed Consolidated Financial Statements for additional discussion related to derivative instruments and hedging activities.

Market Risk – Non-Trading Instruments

The primary factors affecting our market risk and the fair value of our derivative portfolio at any point in time are the volume of open derivative positions, changing refined petroleum commodity prices, and prevailing interest rates for our interest rate swaps. Since prices for refined petroleum products and interest rates are volatile, there may be material changes in the fair value of our derivatives over time, driven both by price volatility and the changes in volume of open derivative transactions. Our net derivative liability has increased to approximately $143.5 million at September 30, 2012, compared to $97.0 million at December 31, 2011.

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The following is a summary of changes in fair value of our outstanding commodity and interest rate derivative instruments for the periods indicated (in thousands):

	Commodity			Interest
	Instruments			Rate Swaps			Total
Fair value of contracts outstanding at January 1, 2012	$	4,897		$	(101,911	)	$	(97,014	)
Items recognized or settled during the period		20,529			—			20,529
Fair value attributable to new deals		(4,815	)		—			(4,815	)
Change in fair value attributable to price movements		(32,801	)		(29,470	)		(62,271	)
Change in fair value attributable to non-performance risk		32			—			32
Fair value of contracts outstanding at September 30, 2012	$	(12,158	)	$	(131,381	)	$	(143,539	)

Commodity Risk

Natural Gas Storage

The Natural Gas Storage segment enters into interruptible natural gas storage hub service agreements in order to manage the operational integrity 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. The hub service agreements do not qualify as derivatives and therefore are not accounted for at fair value. The fee to be received or paid is based on the time spread at the time of execution. The hub service agreements are accrued as fees are paid or received and recognized ratably in earnings over the entire term of the transactions.

The following is a summary of changes in the net balance sheet of our outstanding hub service agreements (in thousands):

Net Asset at January 1, 2012	$	11,390
Net revenues recognized in period (1)		62
Net cash paid—prepaid expense (2)		6,007
Net Asset at September 30, 2012	$	17,459

(1) Net revenue was amortized into earnings based on the net fee received for injection and withdrawal services performed during the period.

(2) Fees were paid and a net asset was recorded for injection and withdrawal services to be rendered in future periods.

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Energy Services

Based on a hypothetical 10% movement in the underlying quoted market prices of the futures contracts, physical fixed price and index derivative contracts, and designated hedged refined petroleum products inventories outstanding at September 30, 2012, 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)		Asset	$	160,427
Fair value assuming 10% increase in underlying commodity prices		Asset	$	160,995
Fair value assuming 10% decrease in underlying commodity prices		Asset	$	159,859

Interest Rate Risk

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

The following table presents the effect of hypothetical price movements on the estimated fair value of our interest rate swap portfolio and the related change in fair value of the underlying debt at September 30, 2012 (in thousands):

			Financial
			Instrument
	Resulting		Portfolio
Scenario	Classification		Fair Value
Fair value assuming no change in underlying interest rates (as is)		Liability	$	(131,381	)
Fair value assuming 10% increase in underlying interest rates		Liability	$	(120,143	)
Fair value assuming 10% decrease in underlying interest rates		Liability	$	(144,844	)

See Note 7 in the Notes to Unaudited Condensed Consolidated Financial Statements for additional discussion related to derivative instruments and hedging activities.

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Item 4. Controls and Procedures

(a) Evaluation of Disclosure Controls and Procedures.

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

(b) Change in Internal Control Over Financial Reporting.

There have been no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) or in other factors during the third quarter of 2012 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal 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. For information on unresolved legal proceedings not otherwise described below, see Part I, 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.

In 2010, the Attorney General of Illinois and the State’s Attorney for Will County, Illinois, filed a complaint under caption the People of the State of Illinois et al v. Buckeye Pipe Line Company, L.P. et al. in connection with an alleged release of oil on December 14, 2010, from a pipeline owned by West Shore Pipe Line Company (“West Shore”) and operated by BPLC in Lockport, Illinois. In September 2012, the settlement order was entered by the Circuit Court of Will County, Illinois with the aggregate penalty amount for both West Shore and BPLC marginally exceeding $0.1 million.

Item 1A. Risk Factors

Security holders and potential investors in our securities should carefully consider the risk factors set forth in Part I, “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2011 and Part II “Item 1A. Risk Factors” of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2012. 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.

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Item 6. Exhibits

(a) Exhibits

3.1	Amended and Restated Certificate of Limited Partnership of Buckeye Partners, L.P., dated as of February 4, 1998 (Incorporated by reference to Exhibit 3.2 of Buckeye Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 1997).
3.2	Certificate of Amendment to Amended and Restated Certificate of Limited Partnership of Buckeye Partners, L.P., dated as of April 26, 2002 (Incorporated by reference to Exhibit 3.2 of Buckeye Partners, L.P.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2002).
3.3	Certificate of Amendment to Amended and Restated Certificate of Limited Partnership of Buckeye Partners, L.P., dated as of June 1, 2004, effective as of June 3, 2004 (Incorporated by reference to Exhibit 3.3 of the Buckeye Partners, L.P.’s Registration Statement on Form S-3 filed June 16, 2004).
3.4	Certificate of Amendment to Amended and Restated Certificate of Limited Partnership of Buckeye Partners, L.P., dated as of December 15, 2004 (Incorporated by reference to Exhibit 3.5 of Buckeye Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2004).
3.5	Amended and Restated Agreement of Limited Partnership of Buckeye Partners, L.P., dated as of November 19, 2010 (Incorporated by reference to Exhibit 3.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed November 22, 2010).
3.6	Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Buckeye Partners, L.P., dated as of January 18, 2011 (Incorporated by reference to Exhibit 3.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on January 20, 2011).
*31.1         *31.2 *32.1 *32.2	Certification of Chief Executive Officer pursuant to Rule 13a-14 (a) under the Securities Exchange Act of 1934. Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934. Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350. Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350.
*101.INS	XBRL Instance Document.
*101.SCH	XBRL Taxonomy Extension Schema Document.
*101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.
*101.LAB	XBRL Taxonomy Extension Label Linkbase Document.
*101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.
*101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.

* Filed herewith.

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SIGNATURES

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

	By:	BUCKEYE PARTNERS, L.P. (Registrant)
	By:	Buckeye GP LLC, as General Partner
Date: November 6, 2012	By:	/s/ Keith E. St.Clair
		Keith E. St.Clair
		Executive Vice President and Chief Financial Officer (Principal Financial Officer)

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