Edgar Filing: BUCKEYE PARTNERS, L.P.

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2013

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

For the transition period from to

Commission file number 1-9356

Buckeye Partners, L.P.

(Exact name of registrant as specified in its charter)

Delaware		23-2432497
(State or other jurisdiction of		(IRS Employer
incorporation or organization)		Identification number)

One Greenway Plaza
Suite 600
Houston, TX		77046
(Address of principal executive offices)		(Zip Code)

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

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

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

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

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

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

Limited partner units and Class B units outstanding as of July 29, 2013: 97,796,054 and 8,323,992, respectively.

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TABLE OF CONTENTS

				Page
PART I. FINANCIAL INFORMATION

Item 1.	*Financial Statements*
	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2013 and 2012 (Unaudited) June 30, 2013 and 2012 (Unaudited)			2
	Condensed Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2013 and 2012 (Unaudited)			3
	Condensed Consolidated Balance Sheets as of June 30, 2013 and December 31, 2012 (Unaudited)			4
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2013 and 2012 (Unaudited)			5
	Condensed Consolidated Statements of Partners’ Capital for the Six Months Ended June 30, 2013 and 2012 (Unaudited)			6
	Notes to Unaudited Condensed Consolidated Financial Statements:
		1.	Organization and Basis of Presentation	7
		2.	Acquisitions	8
		3.	Commitments and Contingencies	8
		4.	Inventories	11
		5.	Equity Investments	11
		6	Long-term Debt	12
		7.	Derivative Instruments and Hedging Activities	12
		8.	Fair Value Measurements	16
		9.	Pensions and Other Postretirement Benefits	18
		10.	Unit-Based Compensation Plans	18
		11.	Partners’ Capital and Distributions	20
		12.	Earnings Per Unit	22
		13.	Business Segments	22
		14.	Supplemental Cash Flow Information	25
		15.	Subsequent Events	26

Item 2.	*Management’s Discussion and Analysis of Financial Condition and Results of Operations*			27

Item 3.	*Quantitative and Qualitative Disclosures About Market Risk*			40

Item 4.	*Controls and Procedures*			42

PART II. OTHER INFORMATION

Item 1.	*Legal Proceedings*			42

Item 1A.	*Risk Factors*			43

Item 6.	*Exhibits*			43

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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						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Revenue:
Product sales	$	734,396		$	745,863		$	1,803,613		$	1,773,751
Transportation, storage and other services	270,983			236,777			546,727			468,328
Total revenue	1,005,379			982,640			2,350,340			2,242,079

Costs and expenses:
Cost of product sales and natural gas storage services	737,217			747,155			1,810,910			1,778,640
Operating expenses	104,793			101,137			202,150			198,355
Depreciation and amortization	39,452			34,325			77,043			67,352
General and administrative	18,266			17,877			35,437			34,852
Total costs and expenses	899,728			900,494			2,125,540			2,079,199
Operating income	105,651			82,146			224,800			162,880

Other income (expense):
Earnings from equity investments	1,953			1,786			3,582			3,734
Interest and debt expense	(30,237		)	(27,612		)	(60,486		)	(56,422		)
Other income (expense)	198			35			299			(33		)
Total other expense, net	(28,086		)	(25,791		)	(56,605		)	(52,721		)

Income before taxes	77,565			56,355			168,195			110,159

Income tax expense	(195		)	(329		)	(326		)	(666		)
Net income	77,370			56,026			167,869			109,493
Less: Net income attributable to noncontrolling interests	(940		)	(1,647		)	(2,098		)	(3,155		)
Net income attributable to Buckeye Partners, L.P.	$	76,430		$	54,379		$	165,771		$	106,338

Earnings per unit:
Basic	$	0.72		$	0.56		$	1.59		$	1.10
Diluted	$	0.72		$	0.55		$	1.58		$	1.10

Weighted average units outstanding:
Basic	105,701			97,818			104,481			96,524
Diluted	106,171			98,109			104,878			96,834

See Notes to Unaudited Condensed Consolidated Financial Statements.

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BUCKEYE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012

Net income	$	77,370		$	56,026		$	167,869		$	109,493
Other comprehensive income (loss):
Unrealized gains (losses) on derivative instruments	25,000			(39,907		)	33,847			(22,616		)
Adjustment to funded status of benefit plans	427			(25		)	403			(2		)
Total other comprehensive income (loss)	25,427			(39,932		)	34,250			(22,618		)
Comprehensive income	102,797			16,094			202,119			86,875
Less: Comprehensive income attributable to noncontrolling interests	(940		)	(1,647		)	(2,098		)	(3,155		)
Comprehensive income attributable to Buckeye Partners, L.P.	$	101,857		$	14,447		$	200,021		$	83,720

See Notes to Unaudited Condensed Consolidated Financial Statements.

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BUCKEYE PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except unit amounts)

(Unaudited)

	June 30,			December 31,
	2013			2012
Assets:
Current assets:
Cash and cash equivalents	$	4,889		$	6,776
Trade receivables, net	213,091			262,023
Construction and pipeline relocation receivables	14,924			13,078
Inventories	194,876			259,163
Derivative assets	6,466			1,719
Prepaid and other current assets	73,852			91,563
Total current assets	508,098			634,322

Property, plant and equipment, net	4,274,660			4,188,648

Equity investments	72,023			68,713
Goodwill	812,297			818,121
Intangible assets, net	205,493			219,247
Other non-current assets	51,567			51,958
Total assets	$	5,924,138		$	5,981,009

Liabilities and partners’ capital:
Current liabilities:
Line of credit	$	76,000		$	206,200
Accounts payable	94,519			112,792
Derivative liabilities	2,531			82,989
Accrued and other current liabilities	195,536			192,385
Total current liabilities	368,586			594,366

Long-term debt	2,569,630			2,735,244
Long-term derivative liabilities	35,237			57,805
Other non-current liabilities	199,138			204,754
Total liabilities	3,172,591			3,592,169

Commitments and contingencies (Note 3)

Partners’ capital:
Buckeye Partners, L.P. capital:
Limited Partners (97,794,703 and 90,371,061 units outstanding as of June 30, 2013 and December 31, 2012, respectively)	2,434,991			2,117,788
Class B Units (8,323,992 and 7,974,750 units outstanding as of June 30, 2013 and December 31, 2012, respectively)	426,202			413,304
Accumulated other comprehensive loss	(124,529		)	(158,779		)
Total Buckeye Partners, L.P. capital	2,736,664			2,372,313
Noncontrolling interests	14,883			16,527
Total partners’ capital	2,751,547			2,388,840
Total liabilities and partners’ capital	$	5,924,138		$	5,981,009

See Notes to Unaudited Condensed Consolidated Financial Statements.

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BUCKEYE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Six Months Ended
	June 30,
	2013			2012
Cash flows from operating activities:
Net income	$	167,869		$	109,493
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Settlement of terminated interest rate swap agreement	(62,009		)	—
Depreciation and amortization	77,043			67,352
Net changes in fair value of derivatives	(12,374		)	4,480
Non-cash deferred lease expense	1,884			1,950
Amortization of unfavorable storage contracts	(5,497		)	(5,497		)
Earnings from equity investments	(3,582		)	(3,734		)
Distributions from equity investments	125			3,225
Other non-cash items	9,805			10,471
Change in assets and liabilities, net of amounts related to acquisitions:
Trade receivables	48,932			13,978
Construction and pipeline relocation receivables	(1,846		)	(2,600		)
Inventories	64,287			168,398
Prepaid and other current assets	11,743			11,719
Accounts payable	(19,277		)	(7,760		)
Accrued and other current liabilities	15,508			(10,656		)
Other non-current assets	2,221			(3,842		)
Other non-current liabilities	(3,927		)	(9,833		)
Net cash provided by operating activities	290,905			347,144
Cash flows from investing activities:
Capital expenditures	(147,867		)	(148,000		)
Contribution to equity investment	—			(350		)
Deposit in anticipation of acquisition	—			(14,000		)
Proceeds from disposal of property, plant and equipment	578			622
Net cash used in investing activities	(147,289		)	(161,728		)
Cash flows from financing activities:
Net proceeds from issuance of units	372,824			246,648
Net proceeds from exercise of unit options	980			999
Payment of tax withholding on issuance of LTIP awards	(3,728		)	(1,576		)
Issuance of long-term debt	499,050			—
Debt issuance costs	(3,250		)	—
Borrowings under BPL Credit Facility	601,000			336,500
Repayments under BPL Credit Facility	(1,266,000		)	(450,500		)
Net borrowings (repayments) under BES Credit Facility	(130,200		)	(138,200		)
Acquisition of additional interest in WesPac Memphis	(9,727		)	—
Credits associated with agreement and plan of merger	—			422
Distributions paid to noncontrolling interests	(5,210		)	(6,688		)
Distributions paid to unitholders	(201,242		)	(185,449		)
Net cash used in financing activities	(145,503		)	(197,844		)
Net decrease in cash and cash equivalents	(1,887		)	(12,428		)
Cash and cash equivalents — Beginning of period	6,776			12,986
Cash and cash equivalents — End of period	$	4,889		$	558

See Notes to Unaudited Condensed Consolidated Financial Statements.

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BUCKEYE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(In thousands)

(Unaudited)

						Accumulated
						Other
	Limited			Class B		Comprehensive			Noncontrolling
	Partners			Units		Income (Loss)			Interests			Total
Partners’ capital - January 1, 2013	$	2,117,788		$	413,304	$	(158,779	)	$	16,527		$	2,388,840
Net income	152,873			12,898		—			2,098			167,869
Acquisition of additional interest in WesPac Memphis	(8,232		)	—		—			(1,495		)	(9,727		)
Distributions paid to unitholders	(204,164		)	—		—			2,922			(201,242		)
Net proceeds from issuance of units	372,824			—		—			—			372,824
Amortization of unit-based compensation awards	7,327			—		—			—			7,327
Proceeds from exercise of unit options	980			—		—			—			980
Payment of tax withholding on issuance of LTIP awards	(3,728		)	—		—			—			(3,728		)
Distributions paid to noncontrolling interests	—			—		—			(5,210		)	(5,210		)
Other comprehensive income	—			—		34,250			—			34,250
Noncash accrual for distribution equivalent rights	(667		)	—		—			—			(667		)
Other	(10		)	—		—			41			31
Partners’ capital - June 30, 2013	$	2,434,991		$	426,202	$	(124,529	)	$	14,883		$	2,751,547

Partners’ capital - January 1, 2012	$	2,035,271		$	395,639	$	(127,741	)	$	20,788		$	2,323,957
Net income	98,155			8,183		—			3,155			109,493
Credits associated with agreement and plan of merger	422			—		—			—			422
Distributions paid to unitholders	(188,058		)	—		—			2,609			(185,449		)
Net proceeds from issuance of units	246,648			—		—			—			246,648
Amortization of unit-based compensation awards	7,688			—		—			—			7,688
Net proceeds from exercise of unit options	999			—		—			—			999
Payment of tax withholding on issuance of LTIP awards	(1,576		)	—		—			—			(1,576		)
Distributions paid to noncontrolling interests	—			—		—			(6,688		)	(6,688		)
Other comprehensive loss	—			—		(22,618		)	—			(22,618		)
Noncash accrual for distribution equivalent rights	(433		)	—		—			—			(433		)
Other	657			—		—			—			657
Partners’ capital - June 30, 2012	$	2,199,773		$	403,822	$	(150,359	)	$	19,864		$	2,473,100

See Notes to Unaudited Condensed Consolidated Financial Statements.

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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 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, miles of pipeline and active product terminals. 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. Beginning in late 2012, we began to provide fuel oil supply and distribution services to third parties in the Caribbean. 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 global logistics hub.

Basis of Presentation and Principles of Consolidation

The unaudited 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 unaudited 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, 2012.

Recent Accounting Developments

Reclassification Adjustments Out of Accumulated Other Comprehensive Income (“AOCI”). In February 2013, the Financial Accounting Standards Board (“FASB”) issued guidance requiring entities to disclose additional information about reclassification adjustments, including changes in AOCI balances by component and significant items reclassified out of AOCI. Under the new guidance, an entity would (i) disaggregate the total change of each component of other comprehensive income (“OCI”) and separately present reclassification adjustments and current-period OCI, and (ii) present information about significant items reclassified out of AOCI by component either on the face of the statement where net income is presented or as a separate disclosure in the notes to the financial statements. This guidance is effective for interim and annual periods beginning after December 15, 2012. We adopted this guidance on January 1, 2013, which did not have an impact on our unaudited condensed consolidated financial statements, or a material impact on our disclosures, as there were no significant reclassification adjustments during the three and six months ended June 30, 2013.

Balance Sheet: Disclosures about Offsetting Assets and Liabilities. In December 2011, the FASB issued guidance requiring an entity to provide enhanced disclosures that will enable users of its financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. In January 2013, the FASB issued an update to this guidance clarifying that the scope of disclosures applied to derivatives accounted for in accordance with FASB Accounting Standards Codification (“ASC”) Topic

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

815, Derivative and Hedging, including bifurcated embedded derivatives, repurchase agreements and reverse purchase agreements and securities lending transactions that are either offset in accordance with FASB ASC Section 210-20-45 or Section 815-10-45 or subject to an enforceable master netting arrangement or similar agreement. This guidance is effective for interim and annual reporting periods beginning on or after January 1, 2013 and should be applied retrospectively. We adopted this guidance on January 1, 2013, which did not have an impact on our unaudited condensed consolidated financial statements, or a material impact on our disclosures. See Note 7 for information about our netting policy for derivatives.

2. ACQUISITIONS

Business Combination

In July 2012, we acquired a marine terminal facility for liquid petroleum products in New York Harbor from Chevron U.S.A Inc. for $260.3 million in cash. The purchase price has been allocated to tangible and intangible assets acquired and liabilities assumed as follows (in thousands):

Current assets	$	547
Property, plant and equipment	198,091
Intangible assets	13,350
Goodwill	59,197
Environmental liabilities	(10,873		)
Allocated purchase price	$	260,312

Acquisition of Additional Interest in WesPac Pipelines — Memphis LLC

In April 2013, our operating subsidiary, Buckeye Pipe Line Holdings, L.P. (“BPH”), purchased an additional 10% ownership interest in WesPac Pipelines — Memphis LLC (“WesPac Memphis”) from Kealine LLC for $9.7 million and, as a result of the acquisition, our ownership interest in WesPac Memphis increased from 70% to 80%. 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.

BORCO Jetty. 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 presently estimated to be approximately $25.0 million. Buckeye has 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. 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. The vessel owner has claimed that it is entitled to limit its liability to approximately $17.0 million, but we are contesting the right of the vessel owner to such limitation. A hearing in the Bahamas court on the vessel

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

owner’s right to limit its liability was held on July 23, 2013, and we are awaiting a ruling on the issue. At this time, we have not experienced any material interruption of service at the BORCO facility as a result of the incident, and the repairs of the damaged sections are substantially complete. We recorded a loss on disposal due to the assets destroyed in the incident and other related costs incurred; however, since we believe recovery of our losses is probable, we recorded a corresponding receivable. As of June 30, 2013, we have a $5.0 million receivable included in “Other non-current assets” in our unaudited condensed consolidated balance sheet, representing reimbursement of the deductible. 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 June 30, 2013, no gain had been recognized; however, we recorded a $2.4 million deferred gain in “Accrued and other current liabilities” in our unaudited condensed consolidated balance sheet, representing excess proceeds received over the loss on disposal and other costs incurred.

Federal Energy Regulatory Commission (“FERC”) Proceedings

FERC Docket No. IS12-185 — Buckeye Pipe Line Show Cause Proceeding. On March 30, 2012, FERC issued an order (the “Show Cause 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 Show Cause Order, among other things, stated that FERC would review the continued efficacy of BPLC’s unique program and directed 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 Show Cause Order also disallowed proposed rate increases on the Buckeye System that would have become effective April 1, 2012. The Show Cause Order did 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. On February 22, 2013, FERC issued an order in Dkt. No. IS12-185-000 et al. discontinuing the BPLC program, and affirming on rehearing its rejection of all rate increases filed in March 2012 (“Ratemaking Methodology Order”). The Ratemaking Methodology Order permitted Buckeye to retain its currently-filed rates in place, to make future rate changes in under market-based ratemaking authority in markets previously found to be competitive by FERC, and to make future changes in rates in other markets pursuant to the generic FERC ratemaking methods, which would include indexing. No requests for rehearing or petitions for judicial review were filed with respect to the Ratemaking Methodology Order. Subsequently, on March 28, 2013, BPLC filed rate increases for services in the markets previously found to be competitive, and on May 30, 2013, BPLC filed rate increases for most transportation services in the markets not previously found to be competitive; both sets of tariff filings became effective and are not subject to any FERC proceedings.

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. On November 9, 2012, BPLC filed a response addressing newly raised arguments in the complainants’ October 25th answer. On February 22, 2013, FERC issued an order setting the airline complaint in Dkt. No. OR12-28-000 for hearing, but holding the

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

hearing in abeyance and setting the dispute for settlement procedures before a settlement judge. 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. On March 8, 2013, an order was issued consolidating this complaint proceeding with the proceeding regarding BPLC’s application for market-based rates in the New York City market in Dkt. No. OR13-3-00 (discussed below), for settlement purposes, and settlement discussions under the supervision of the FERC settlement judge are ongoing. 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. On December 14, 2012, Delta Air Lines, JetBlue Airways, United/Continental Air Lines, and US Airways filed a joint intervention and protest challenging the Application and requesting its rejection. On January 14, 2013, BPLC filed its answer to the protest and requested summary disposition as to those non-jet-fuel rates that were not challenged in the protest. On January 29, 2013, the protestants responded to BPLC’s answer, and on February 13, 2013, BPLC filed a further answer to the protestants’ January 29, 2013 pleading. On February 28, 2013, FERC issued an order setting the Application for hearing, holding the hearing in abeyance and setting the dispute for settlement procedures before a settlement judge. As discussed above, the Application has been consolidated with the complaint proceeding in Dkt. No. OR12-28-000 for settlement purposes and settlement discussions under the supervision of the FERC settlement judge are ongoing. 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 the Application cannot reasonably be determined at this time.

Environmental Contingencies

We recorded operating expenses, net of insurance recoveries, of $1.5 million and $1.4 million during the three months ended June 30, 2013 and 2012, respectively, related to environmental remediation expenditures unrelated to claims and legal proceedings. For the six months ended June 30, 2013 and 2012, we recorded operating expenses, net of recoveries, of $3.0 million and $2.6 million, respectively, related to environmental remediation expenditures unrelated to claims and legal proceedings. 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. As of June 30, 2013 and December 31, 2012, we recorded environmental liabilities of $62.4 million and $61.8 million, respectively. At June 30, 2013 and December 31, 2012, we had $11.9 million and $17.7 million, respectively, of receivables related to these environmental remediation expenditures covered by insurance.

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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):

	June 30,		December 31,
	2013		2012

Refined petroleum products (1)	$	180,634	$	246,918
Materials and supplies	14,242		12,245
Total inventories	$	194,876	$	259,163

(1) Ending inventory was 62.4 million and 80.9 million gallons of refined petroleum products at June 30, 2013 and December 31, 2012, respectively.

At June 30, 2013 and December 31, 2012, approximately 74% and 88% 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 unaudited 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				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012

West Shore Pipe Line Company	$	1,323	$	1,419	$	2,573	$	3,104
Muskegon Pipeline LLC	390		156		631		419
Transport4, LLC	140		78		196		78
South Portland Terminal LLC	100		133		182		133
Total earnings from equity investments	$	1,953	$	1,786	$	3,582	$	3,734

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						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012

Revenue	$	18,940		$	17,683		$	36,316		$	33,982
Costs and expenses	(9,278		)	(9,348		)	(19,213		)	(17,612		)
Non-operating expense	(3,498		)	(2,984		)	(6,120		)	(6,121		)
Net income	$	6,164		$	5,351		$	10,983		$	10,249

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

6. LONG-TERM DEBT

Notes Offering

In June 2013, we issued $500.0 million of 4.150% Notes due July 1, 2023 (the “4.150% Notes”) in an underwritten public offering at 99.81% of their principal amount. Total proceeds from this offering, after underwriters’ fees, expenses and debt issuance costs of $3.3 million, were approximately $495.8 million. We used the net proceeds from this offering for general partnership purposes and to repay amounts due under our $1.25 billion revolving credit facility dated September 26, 2011 (the “Credit Facility”) with SunTrust Bank, a portion of which was subsequently reborrowed in July 2013 in order to repay in full the $300.0 million principal amount outstanding under the 4.625% Notes maturing on July 15, 2013 (the “4.625% Notes”), including approximately $6.9 million of related accrued interest. We also settled all interest rate swaps relating to the 4.150% Notes for approximately $62.0 million during June 2013.

Current Maturities Expected to be Refinanced

At June 30, 2013, the 4.625% Notes were classified as long-term debt in the unaudited condensed consolidated balance sheet because we had determined that our Credit Facility would be used to refinance this debt. At June 30, 2013, we had $612.7 million of additional borrowing capacity available under our Credit Facility. In July 2013, we repaid in full the $300.0 million principal amount outstanding under the 4.625% Notes using funds available under our Credit Facility.

7. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

We are exposed to financial market risks, including changes in interest rates and commodity prices, in the course of our normal business operations. We use derivative instruments to manage risks.

Interest Rate Derivatives

We utilize forward-starting interest rate swaps to hedge the variability of the forecasted interest payments on anticipated debt issuances that may result from changes in the benchmark interest rate until the expected debt is issued. 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.

We entered into six forward-starting interest rate swaps with a total aggregate notional amount of $300.0 million, which we entered into in anticipation of the 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, which we entered into in anticipation of the issuance of debt on or before October 15, 2014. We designated the swap agreements as cash flow hedges at inception and expect the changes in values to be highly correlated with the changes in value of the underlying borrowings. In June 2013, we issued $500 million of the 4.150% Notes (see Note 6 for further discussion) and also settled the related six forward-starting interest rate swaps for approximately $62.0 million. As a result of the interest rate swap settlement, we recognized $0.9 million hedge ineffectiveness in interest and debt expense attributable to the timing difference between when the swaps were settled and when they were forecasted to settle. We expect to issue new fixed-rate debt on or before October 15, 2014 to repay the $275.0 million of 5.300% Notes that are due on October 15, 2014, although no assurances can be given that the issuance of fixed-rate debt will be possible on acceptable terms.

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

During the three months ended June 30, 2013 and 2012, unrealized gains of $23.9 million and unrealized losses of $40.1 million, respectively, were recorded in accumulated other comprehensive loss to reflect the change in the fair values of the forward-starting interest rate swaps. For the six months ended June 30, 2013 and 2012, unrealized gains of $32.5 million and unrealized losses of $23.1 million, respectively, were recorded in accumulated other comprehensive loss to that effect. Additionally, over the next twelve months, we expect to reclassify $7.1 million of net losses from accumulated other comprehensive loss to interest and debt expense. The loss consists of the following: i) the forward-starting interest rate swaps that were settled in 2008 and ii) the forward-starting interest rate swaps settled in June 2013 (as discussed above). These losses were partially offset by a gain attributable to the settlement of a treasury lock agreement settled in 2011.

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 derivative contracts. The futures contracts used to hedge refined petroleum product inventories are designated as fair value hedges with changes in fair value of both the futures contracts and physical inventory reflected in earnings. Physical contracts and futures contracts that have not been designated in a hedge relationship are marked-to-market.

The following table summarizes our commodity derivative instruments outstanding at June 30, 2013 (amounts in thousands of gallons):

	Volume (1)		Accounting
Derivative Purpose	Current	Long-Term (2)	Treatment

Derivatives NOT designated as hedging instruments:

Physical fixed price derivative contracts	46,926	—	Mark-to-market
Physical index derivative contracts	40,337	—	Mark-to-market
Futures contracts for refined petroleum products	27,423	—	Mark-to-market

Derivatives designated as hedging instruments:

Futures contracts for refined petroleum products	46,284	—	Fair Value Hedge

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

(2) There were no derivative contracts that extended beyond June 30, 2014.

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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):

	June 30, 2013
	Derivatives			Derivatives			Gross			Netting
	NOT Designated			Designated			Derivative			Balance
	as Hedging			as Hedging			Carrying			Sheet
	Instruments			Instruments			Value			Adjustment (1)			Net Total

Physical fixed price derivative contracts	$	4,396		$	—		$	4,396		$	(1,330	)	$	3,066
Physical index derivative contracts	594			—			594			(30		)	564
Futures contracts for refined products	60,898			386			61,284			(58,448		)	2,836
Total current derivative assets	65,888			386			66,274			(59,808		)	6,466

Physical fixed price derivative contracts	(3,687		)	—			(3,687		)	1,330			(2,357		)
Physical index derivative contracts	(204		)	—			(204		)	30			(174		)
Futures contracts for refined products	(57,003		)	(1,445		)	(58,448		)	58,448			—
Total current derivative liabilities	(60,894		)	(1,445		)	(62,339		)	59,808			(2,531		)

Interest rate derivatives	—			(35,237		)	(35,237		)	—			(35,237		)
Total non-current derivative liabilities	—			(35,237		)	(35,237		)	—			(35,237		)
Net derivative assets (liabilities)	$	4,994		$	(36,296	)	$	(31,302	)	$	—		$	(31,302	)

(1) Amounts represent the netting of physical fixed and index contracts’ assets and liabilities when a legal right of offset exists. Futures contracts are subject to settlement through margin requirements and are additionally presented on a net basis.

	December 31, 2012
	Derivatives			Derivatives			Gross			Netting
	NOT Designated			Designated			Derivative			Balance
	as Hedging			as Hedging			Carrying			Sheet
	Instruments			Instruments			Value			Adjustment (1)			Net Total

Physical fixed price derivative contracts	$	1,489		$	—		$	1,489		$	(335	)	$	1,154
Physical index derivative contracts	724			—			724			(159		)	565
Futures contracts for refined products	10,359			435			10,794			(10,794		)	—
Total current derivative assets	12,572			435			13,007			(11,288		)	1,719

Physical fixed price derivative contracts	(2,377		)	—			(2,377		)	335			(2,042		)
Physical index derivative contracts	(705		)	—			(705		)	159			(546		)
Futures contracts for refined products	(15,268		)	(3,096		)	(18,364		)	10,794			(7,570		)
Interest rate derivatives	—			(72,831		)	(72,831		)	—			(72,831		)
Total current derivative liabilities	(18,350		)	(75,927		)	(94,277		)	11,288			(82,989		)

Interest rate derivatives	—			(57,805		)	(57,805		)	—			(57,805		)
Total non-current derivative liabilities	—			(57,805		)	(57,805		)	—			(57,805		)
Net derivative assets (liabilities)	$	(5,778	)	$	(133,297	)	$	(139,075	)	$	—		$	(139,075	)

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Our hedged inventory portfolio extends to the fourth quarter of 2013. The majority of the unrealized loss at June 30, 2013 for inventory hedges represented by futures contracts of $1.1 million will be realized by the fourth quarter of 2013 as the related inventory is sold. At June 30, 2013, 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 May 2014. In addition, at June 30, 2013, 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						Six Months Ended
		June 30,						June 30,
	Location	2013			2012			2013			2012

Derivatives NOT designated as hedging instruments:
Physical fixed price derivative contracts	Product sales	$	2,795		$	3,791		$	3,376		$	2,898
Physical index derivative contracts	Product sales	700			258			1,109			360
Physical fixed price derivative contracts	Cost of product sales and natural gas storage services	(359		)	784			(445		)	(603		)
Physical index derivative contracts	Cost of product sales and natural gas storage services	(541		)	4			(544		)	(39		)
Futures contracts for refined products	Cost of product sales and natural gas storage services	1,457			1,960			5,797			5,331

Derivatives designated as fair value hedging instruments:
Futures contracts for refined products	Cost of product sales and natural gas storage services	8,159			14,536			8,935			(14,635		)
Physical inventory - hedged items	Cost of product sales and natural gas storage services	(8,959		)	(17,301		)	(9,440		)	11,157

Ineffectiveness excluding 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	(5,212		)	172			(3,627		)	(560		)
Time value excluded from hedge assessment	Cost of product sales and natural gas storage services	4,412			(2,937		)	3,122			(2,917		)
Net loss in income		$	(800	)	$	(2,765	)	$	(505	)	$	(3,477	)

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

		Loss Reclassified from AOCI to Income for the
		Three Months Ended						Six Months Ended
		June 30,						June 30,
	Location	2013			2012			2013			2012

Derivatives designated as cash flow hedging instruments:
Interest rate contracts	Interest and debt expense	$	(1,093	)	$	(229	)	$	(1,321	)	$	(459	)

		Gain (Loss) Recognized in OCI on Derivatives for the
		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2013			2012			2013			2012

Derivatives designated as cash flow hedging instruments:
Interest rate contracts		$	23,907		$	(40,136	)	$	32,526		$	(23,075	)

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 indicated, and the basis for that measurement, by level within the fair value hierarchy (in thousands):

	June 30, 2013					December 31, 2012
	Level 1		Level 2			Level 1			Level 2

Financial assets:
Physical fixed price derivative contracts	$	—	$	3,066		$	—		$	1,154
Physical index derivative contracts	—		564			—			565
Futures contracts for refined products	2,836		—			—			—

Financial liabilities:
Physical fixed price derivative contracts	—		(2,357		)	—			(2,042		)
Physical index derivative contracts	—		(174		)	—			(546		)
Futures contracts for refined products	—		—			(7,570		)	—
Interest rate derivatives	—		(35,237		)	—			(130,636		)
Fair value	$	2,836	$	(34,138	)	$	(7,570	)	$	(131,505	)

The values of the Level 1 derivative assets and liabilities were based on quoted market prices obtained from the New York Mercantile Exchange.

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 derivative contracts were calculated using market approaches based on observable market data inputs, including published commodity pricing data, which is verified against other available market data, and market interest rate and volatility data. Level 2 fixed price derivative assets are net of credit value adjustments (“CVAs”) determined using an expected cash flow model, which incorporates assumptions about the credit risk of the 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 derivative contracts are large organizations with nationally-recognized credit ratings. The Level 2 fixed price derivative assets of $3.1 million and $1.2 million as of June 30, 2013 and December 31, 2012, respectively, are net of CVAs of ($0.1) million for both periods, respectively. As of June 30, 2013, the Energy Services segment did not hold any net liability derivative position containing credit contingent features.

Financial instruments included in current assets and current liabilities are reported in the unaudited 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 the publicly-issued debt of other master limited partnerships 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. The carrying value and fair value, using Level 2 input values, of our debt were as follows at the dates indicated (in thousands):

	June 30, 2013				December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value

Fixed-rate debt	$	2,569,630	$	2,684,646	$	2,070,244	$	2,203,662
Variable-rate debt	76,000		76,000		871,200		871,200
Total debt	$	2,645,630	$	2,760,646	$	2,941,444	$	3,074,862

We 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 six months ended June 30, 2013 and 2012, 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 impairment. For the three and six months ended June 30, 2013 and 2012, there were no fair value adjustments related to such assets or liabilities reflected in our unaudited condensed consolidated financial statements.

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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 June 30, 2013 and 2012 (in thousands):

	RIGP						Retiree Medical Plan
	Three Months Ended						Three Months Ended
	June 30,						June 30,
	2013			2012			2013			2012

Service cost	$	55		$	61		$	71		$	78
Interest cost	187			207			404			448
Expected return on plan assets	(103		)	(113		)	—			—
Amortization of prior service cost	—			—			(615		)	(683		)
Amortization of unrecognized losses	308			343			284			315
Actuarial loss due to settlements	112			—			—			—
Net periodic benefit cost	$	559		$	498		$	144		$	158

The components of the net periodic benefit cost for the RIGP and the Retiree Medical Plan were as follows for the six months ended June 30, 2013 and 2012 (in thousands):

	RIGP						Retiree Medical Plan
	Six Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012

Service cost	$	122		$	132		$	157		$	154
Interest cost	414			414			897			930
Expected return on plan assets	(227		)	(200		)	—			—
Amortization of prior service cost	—			—			(1,365		)	(1,424		)
Amortization of unrecognized losses	685			797			630			626
Actuarial loss due to settlements	453			—			—			—
Net periodic benefit cost	$	1,447		$	1,143		$	319		$	286

During the three months ended June 30, 2013 and 2012, we contributed approximately $0.4 million and $0.2 million, respectively, in aggregate to the RIGP and Retiree Medical Plans. For the six months ended June 30, 2013 and 2012, we contributed approximately $0.7 million and $2.5 million, respectively, in aggregate to the RIGP and Retiree Medical Plans.

10. UNIT-BASED COMPENSATION PLANS

We award unit-based compensation to employees and directors primarily under the Buckeye Partners, L.P. 2013 Long-Term Incentive Plan (the “LTIP”), which was approved by the Partnership’s unitholders in June 2013. The LTIP replaced the 2009 Long-Term Incentive Plan (the “2009 Plan”), which was merged with and into the LTIP, and no further grants will be made under the 2009 Plan. 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”).

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

We recognized compensation expense related to the LTIP, which includes awards under the 2009 Plan, and the Option Plan of $4.0 million and $5.1 million for the three months ended June 30, 2013 and 2012, respectively. For the six months ended June 30, 2013 and 2012, we recognized compensation expense of $7.3 million and $7.7 million, respectively. These compensation plans are discussed below.

LTIP

The LTIP is the successor long-term incentive compensation plan to the 2009 Plan. Following the approval by unitholders of the LTIP, (i) the 2009 Plan was merged with and into the LTIP, (ii) no further grants will be made under the 2009 Plan, and (iii) LP Units with respect to all grants outstanding under the 2009 Plan will be issued under the LTIP. As a result of the merger of the 2009 Plan into the LTIP on June 4, 2013, the LTIP provides for the issuance of up to 3,000,000 LP Units, plus 889,491 LP Units subject to outstanding grants under the 2009 Plan and 193,913 LP Units that remained available for issuance under the 2009 Plan. Therefore, as of June 30, 2013, there were 3,207,094 LP Units available for issuance under the LTIP.

Deferral Plan under the LTIP

We also maintain the Buckeye Partners, L.P. Unit Deferral and Incentive Plan (the “Deferral Plan”), pursuant to which we issue phantom and matching units under the LTIP to certain employees in lieu of a portion of the cash payments such employees would be entitled to receive under our Annual Incentive Compensation Plan. At December 31, 2012 and 2011, actual compensation awards deferred under the Deferral Plan were $1.4 million and $0.7 million, for which 51,668 and 23,426 phantom units (including matching units) were granted during the six months ended June 30, 2013, and the year ended 2012, respectively. These grants are included as granted in the LTIP activity table below.

Awards under the LTIP

During the six months ended June 30, 2013, the Compensation Committee granted 185,497 phantom units to employees (including the 51,668 phantom units granted as discussed above), 14,000 phantom units to independent directors of Buckeye GP and 169,735 performance units to employees.

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
Unvested at January 1, 2013	745		$	62.08
Granted	406		53.62
Vested	(222	)	56.90
Forfeited	(58	)	59.15
Unvested at June 30, 2013	871		$	59.66

At June 30, 2013, approximately $27.0 million of compensation expense related to the LTIP is expected to be recognized over a weighted average period of approximately 2.0 years.

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unit Option and Distribution Equivalent Plan

The following is a summary of the changes in the 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, 2013	74		$	47.19	3.3	$	35
Exercised	(22	)	47.56
Outstanding at June 30, 2013	52		47.04		2.8	$	1,207

Exercisable at June 30, 2013	52		$	47.04	2.8	$	1,207

(1) Aggregate intrinsic value reflects fully vested LP Unit options at the date indicated. Intrinsic value is determined by calculating the difference between our closing LP Unit price on the last trading day in June 2013 and the exercise price, multiplied by the number of exercisable, in-the-money options.

The total intrinsic value of options exercised was $0.4 million and $0.3 million during the six months ended June 30, 2013 and 2012, respectively.

11. PARTNERS’ CAPITAL AND DISTRIBUTIONS

In May 2013, we entered into four separate equity distribution agreements (each an “Equity Distribution Agreement” and collectively the “Equity Distribution Agreements”) with each of Wells Fargo Securities, LLC, Barclays Capital Inc., SunTrust Robinson Humphrey, Inc. and UBS Securities LLC. Under the terms of the Equity Distribution Agreements, we may offer and sell up to $300.0 million in aggregate gross sales proceeds of LP Units from time to time through such firms, acting as agents of the Partnership or as principals, subject in each case to the terms and conditions set forth in the applicable Equity Distribution Agreement. Sales of LP Units, if any, may be made by means of ordinary brokers’ transactions on the New York Stock Exchange or otherwise at market prices prevailing at the time of sale, at prices related to prevailing market prices or at negotiated prices or as otherwise agreed with any of such firms. During the three months ended June 30, 2013, we sold 0.4 million LP Units in aggregate under the Equity Distribution Agreements and received approximately $23.6 million in net proceeds after deducting commissions and other related expenses. During the three months ended June 30, 2013, we paid approximately $0.3 million of compensation in aggregate to the agents under the Equity Distribution Agreements.

In January 2013, we completed a public offering of 6.0 million LP Units pursuant to an effective shelf registration statement, which priced at $52.54 per unit. The underwriters also exercised an option to purchase 0.9 million additional LP Units, resulting in total gross proceeds of approximately $362.5 million before deducting underwriting fees and estimated offering expenses. We used the net proceeds from this offering to reduce the indebtedness outstanding under our Credit Facility.

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Summary of Changes in Outstanding Units

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

	Limited	Class B
	Partners	Units	Total

Units outstanding at January 1, 2013	90,371	7,975	98,346
LP Units issued pursuant to the Option Plan (1)	21	—	21
LP Units issued pursuant to the LTIP (1)	152	—	152
Issuance of units to institutional investors	6,900	—	6,900
Issuance of units through Equity Distribution Agreements	351	—	351
Issuance of Class B Units in lieu of quarterly cash distributions	—	349	349
Units outstanding at June 30, 2013	97,795	8,324	106,119

(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 appropriate. Actual cash distributions on our LP Units totaled $204.2 million and $188.1 million during the six months ended June 30, 2013 and 2012, respectively. We also paid distributions in-kind to our Class B unitholders by issuing 349,242 Class B Units during the six months ended June 30, 2013.

On August 2, 2013, we announced a quarterly distribution of $1.0625 per LP Unit that will be paid on August 20, 2013, to LP unitholders of record on August 12, 2013. Based on the LP Units outstanding as of June 30, 2013, cash distributed to LP unitholders on August 20, 2013 will total approximately $104.3 million. Based on Class B Units outstanding as of June 30, 2013, we also expect to issue approximately 146,000 Class B Units in lieu of cash distributions on August 20, 2013, to Class B unitholders of record on August 12, 2013. The Class B Units will convert into LP Units on a one-for-one basis on the date on which at least 4 million barrels of incremental storage capacity are placed in service at our BORCO facility, which is expected to occur in the third quarter of 2013.

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

12. EARNINGS PER UNIT

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012

Net income attributable to Buckeye Partners, L.P.	$	76,430	$	54,379	$	165,771	$	106,338

Basic:
Weighted average units outstanding - basic	105,701		97,818		104,481		96,524

Earnings per unit - basic	$	0.72	$	0.56	$	1.59	$	1.10

Diluted:
Weighted average units outstanding - basic	105,701		97,818		104,481		96,524
Dilutive effect of LP Unit options and LTIP awards granted	470		291		397		310
Weighted average units outstanding - diluted	106,171		98,109		104,878		96,834

Earnings per unit - diluted	$	0.72	$	0.55	$	1.58	$	1.10

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, transports those products to other locations for a fee and provides bulk storage and terminal throughput services in the continental United States for refined petroleum products and other hydrocarbons. This segment owns and operates pipeline systems and refined petroleum products terminals in the continental United States. In addition, the segment provides crude oil services, including train off-loading, storage and throughput.

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. Beginning in late 2012, the segment began to provide fuel oil supply and distribution services to third parties in the Caribbean.

Natural Gas Storage

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

Energy Services

The Energy Services segment is a wholesale distributor of refined petroleum products in the Northeastern and Midwestern United States. This segment recognizes revenues 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’s customers consist principally of product wholesalers as well as major commercial users of these refined petroleum products.

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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. Additionally, the Development & Logistics segment 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 audited condensed consolidated financial statements. All inter-segment revenues, operating income and assets have been eliminated. All periods are presented on a consistent basis. All of our operations and assets are conducted and located in the continental United States, except for our terminals located in Puerto Rico and The Bahamas.

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following tables summarize our financial information by each segment for the periods indicated (in thousands):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012

Revenue:
Pipelines & Terminals	$	190,632		$	167,312		$	384,832		$	333,240
International Operations (1)	144,369			50,428			315,219			100,663
Natural Gas Storage	11,791			16,469			25,674			26,680
Energy Services	650,326			746,821			1,612,145			1,777,247
Development & Logistics	13,697			13,152			25,609			25,617
Intersegment	(5,436		)	(11,542		)	(13,139		)	(21,368		)
Total revenue	$	1,005,379		$	982,640		$	2,350,340		$	2,242,079

(1) The International Operations segment’s revenue generated in The Bahamas was $54.1 million and $47.2 million for the three months ended June 30, 2013 and 2012, respectively. For the six months ended June 30, 2013 and 2012, the International Operations segment’s revenue generated in The Bahamas was $106.8 million and $93.3 million, respectively. The remainder relates primarily to the fuel oil supply and distribution services in the Caribbean.

For the three and six months ended June 30, 2013 and 2012, no customer contributed 10% or more of consolidated revenue.

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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 to Adjusted EBITDA for the periods indicated (in thousands):

		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2013			2012			2013			2012

Adjusted EBITDA:
Pipelines & Terminals		$	109,085		$	89,598		$	224,629		$	177,830
International Operations		37,203			30,591			72,446			62,257
Natural Gas Storage		(5,757		)	(388		)	(7,584		)	(1,656		)
Energy Services		4,773			(3,206		)	11,964			(9,378		)
Development & Logistics		3,187			3,337			5,885			5,866
Total Adjusted EBITDA		$	148,491		$	119,932		$	307,340		$	234,919

Reconciliation of Net Income to Adjusted EBITDA:
Net income		$	77,370		$	56,026		$	167,869		$	109,493
Less:	Net income attributable to noncontrolling interests	(940		)	(1,647		)	(2,098		)	(3,155		)
Net income attributable to Buckeye Partners, L.P.		76,430			54,379			165,771			106,338
Add:	Interest and debt expense	30,237			27,612			60,486			56,422
	Income tax expense	195			329			326			666
	Depreciation and amortization	39,452			34,325			77,043			67,352
	Non-cash deferred lease expense	942			975			1,884			1,950
	Non-cash unit-based compensation expense	3,984			5,061			7,327			7,688
Less:	Amortization of unfavorable storage contracts (1)	(2,749		)	(2,749		)	(5,497		)	(5,497		)
Adjusted EBITDA		$	148,491		$	119,932		$	307,340		$	234,919

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

14. SUPPLEMENTAL CASH FLOW INFORMATION

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

	Six Months Ended
	June 30,
	2013			2012

Cash paid for interest (net of capitalized interest)	$	57,813		$	57,646
Cash paid for income taxes	542			1,093
Capitalized interest	3,178			4,524

Non-cash investing activities:
Decrease in accounts payable and accrued and other current liabilities related to capital expenditures	$	(6,020	)	$	(636	)

Non-cash financing activities:
Issuance of Class B Units in lieu of quarterly cash distribution	$	16,843		$	15,304

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15. SUBSEQUENT EVENT

Extinguishment of Debt

In July 2013, we repaid in full the $300.0 million principal amount outstanding under the 4.625% Notes due on July 15, 2013 and approximately $6.9 million of related accrued interest using funds available under our Credit Facility.

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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, 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 approximately 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. Beginning in late 2012, we began to provide fuel oil supply and distribution services to third parties in the Caribbean. 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 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.

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Recent Developments

Notes Offering

At-the-Market Offering Program

Acquisition of Additional Interest in WesPac Pipelines — Memphis LLC

Equity Offering

Overview of Operating Results

Net income attributable to our unitholders was $165.8 million for the six months ended June 30, 2013, which was an increase of $59.5 million, or 56.0% from $106.3 million for the corresponding period in 2012. Operating income was $224.8 million for the six months ended June 30, 2013, which is an increase of $61.9 million, or 38.0% from $162.9 million for the corresponding period in 2012. Our results for the six months ended June 30, 2013 includes year-over-year improvement in our Pipelines & Terminals, International Operations and Energy Services segments, while our Natural Gas Storage segment experienced challenges associated with a decline in storage rates compared to the corresponding period in 2012. Continued excess supply of natural gas, minimal volatility in natural gas prices and compressed seasonal spreads could cause further reduction in Adjusted EBITDA and a reduction of

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our estimates of future cash flows related to our Natural Gas Storage segment. Accordingly, we continue to monitor the effect of any adverse economic conditions on the carrying value of the long-lived assets related to this segment.

The increase in net income attributable to our unitholders was primarily the result of increased revenue in our Pipelines & Terminals segment, as well as increased contributions from our International Operations and Energy Services segments. Terminalling volumes for the first six months of 2013 increased over the prior year period in our Pipelines & Terminals segment as recent growth capital projects became operational in the latter half of 2012, including our propylene and storage project at our Chicago complex and transformation of our Albany terminal to add the ability to provide crude-handling services. This represents further product diversification for Buckeye as we were able to leverage our existing assets to provide a broader array of services to our customers. Our International Operations segment benefited from incremental storage capacity brought online at our BORCO facility in the second half of 2012 and early 2013. In addition to the storage revenue contribution from the expansion capacity, higher ancillary revenues, including berthing and heating revenue, were generated due to increased customer utilization of our facilities. Additionally, our Energy Services segment benefited from improved rack margins, largely the result of renewable identification number (“RIN”) sales. Our Energy Services segment generates RINs through its ethanol blending and bio-blended diesel activities. The market for RINs, which are legislatively required to be purchased by refiners, experienced a substantial increase in value during the year. Furthermore, our Energy Services segment continued to benefit from the execution of our risk mitigation strategy, which included focusing on fewer, more strategic locations in which to transact business, better managing our inventories and reducing the cost structure of the business. Sales volumes declined as a result of our continued execution of this risk mitigation strategy.

Results of Operations

Consolidated Summary

Our summary operating results were as follows for the periods indicated (in thousands, except per unit amounts):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012

Revenue	$	1,005,379		$	982,640		$	2,350,340		$	2,242,079
Costs and expenses	899,728			900,494			2,125,540			2,079,199
Operating income	105,651			82,146			224,800			162,880
Other expense, net	(28,086		)	(25,791		)	(56,605		)	(52,721		)
Income before taxes	77,565			56,355			168,195			110,159
Income tax expense	(195		)	(329		)	(326		)	(666		)
Net income	77,370			56,026			167,869			109,493
Less: Net income attributable to noncontrolling interests	(940		)	(1,647		)	(2,098		)	(3,155		)
Net income attributable to Buckeye Partners, L.P.	$	76,430		$	54,379		$	165,771		$	106,338
Earnings per unit - diluted	$	0.72		$	0.55		$	1.58		$	1.10

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.

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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.

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

		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2013			2012			2013			2012

Adjusted EBITDA:
Pipelines & Terminals		$	109,085		$	89,598		$	224,629		$	177,830
International Operations		37,203			30,591			72,446			62,257
Natural Gas Storage		(5,757		)	(388		)	(7,584		)	(1,656		)
Energy Services		4,773			(3,206		)	11,964			(9,378		)
Development & Logistics		3,187			3,337			5,885			5,866
Total Adjusted EBITDA		$	148,491		$	119,932		$	307,340		$	234,919

Reconciliation of Net Income to Adjusted EBITDA and Distributable Cash Flow:
Net income		$	77,370		$	56,026		$	167,869		$	109,493
Less: Net income attributable to noncontrolling interests		(940		)	(1,647		)	(2,098		)	(3,155		)
Net income attributable to Buckeye Partners, L.P.		76,430			54,379			165,771			106,338
Add:	Interest and debt expense	30,237			27,612			60,486			56,422
	Income tax expense	195			329			326			666
	Depreciation and amortization	39,452			34,325			77,043			67,352
	Non-cash deferred lease expense	942			975			1,884			1,950
	Non-cash unit-based compensation expense	3,984			5,061			7,327			7,688
Less:	Amortization of unfavorable storage contracts (1)	(2,749		)	(2,749		)	(5,497		)	(5,497		)
Adjusted EBITDA		$	148,491		$	119,932		$	307,340		$	234,919
Less:	Interest and debt expense, excluding amortization of deferred financing costs, debt discounts and other	(28,505		)	(26,767		)	(57,887		)	(54,684		)
	Income tax expense	(195		)	(329		)	(326		)	(666		)
	Maintenance capital expenditures	(13,069		)	(10,765		)	(18,202		)	(23,875		)
Distributable cash flow		$	106,722		$	82,071		$	230,925		$	155,694

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

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The following table presents product volumes and average tariff rates 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		Six Months Ended
	June 30,		June 30,
	2013	2012	2013	2012

Pipelines & Terminals (average bpd in thousands):
Pipelines:
Gasoline	756.3	724.9	708.7	693.8
Jet fuel	337.8	342.9	335.7	337.7
Middle distillates (1)	320.5	294.1	333.1	315.7
Other products (2)	28.9	35.1	32.9	29.0
Total pipelines throughput	1,443.5	1,397.0	1,410.4	1,376.2

Terminals:
Products throughput	1,015.0	919.6	986.4	898.4

Pipeline Average Tariff (cents/bbl)	82.3	82.7	79.7	80.7

Energy Services (in millions of gallons):
Sales volumes	225.3	258.5	537.3	603.3

(1) Includes diesel fuel and heating oil.

(2) Includes liquefied petroleum gas (“LPG”), intermediate petroleum products and crude oil.

Three Months Ended June 30, 2013 Compared to Three Months Ended June 30, 2012

Consolidated

Adjusted EBITDA was $148.5 million for the three months ended June 30, 2013, which is an increase of $28.6 million, or 23.8%, from $119.9 million for the corresponding period in 2012. The increase in Adjusted EBITDA was primarily related to positive contributions from growth capital spending and higher transportation volumes in the Pipelines & Terminals segment, as well as increased earnings as a result of higher margins and lower operating costs in the Energy Services segment. Higher margins in the Energy Services segment were primarily the result of managing product costs through risk management activities and RIN generation. In addition, our International Operations segment benefited from increased storage capacity and customer utilization of our BORCO facility. These increases in Adjusted EBITDA were offset by compressed seasonal spreads and minimal volatility in natural gas prices in our Natural Gas Storage segment.

Revenue was $1,005.4 million for the three months ended June 30, 2013, which is an increase of $22.8 million, or 2.3%, from $982.6 million for the corresponding period in 2012. The increase in revenue was primarily related to incremental storage capacity brought online at our BORCO facility in the second half of 2012 and early 2013, as well as new fuel oil supply and distribution services in the International Operations segment. In addition, revenue in our Pipelines & Terminals segment increased as a result of increased pipeline and terminalling volumes and contribution from growth capital initiatives that were placed into service in the second half of 2012. These increases in revenue were offset by lower product sales volume in our Energy Services segment.

Operating income was $105.7 million for the three months ended June 30, 2013, which is an increase of $23.5 million, or 28.6%, from $82.1 million for the corresponding period in 2012. The increase in operating income was primarily related to increased pipeline and terminalling volumes and contributions from growth capital spending initiatives in the Pipelines & Terminals segment and increased contribution from our Energy Services segment as a result of higher margins and lower operating costs. In addition, our International Operations segment benefited from incremental storage capacity brought online at our BORCO facility in the second half of 2012 and early 2013. These increases were offset by decreased seasonal spreads in our Natural Gas Storage segment.

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Distributable cash flow was $106.7 million for the three months ended June 30, 2013, which is an increase of $24.7 million, or 30.0%, from $82.1 million for the corresponding period in 2012. The increase in distributable cash flow was primarily related to an increase of $28.6 million in Adjusted EBITDA as described above.

Adjusted EBITDA by Segment

Pipelines & Terminals. Adjusted EBITDA from the Pipelines & Terminals segment was $109.1 million for the three months ended June 30, 2013, which is an increase of $19.5 million, or 21.7%, from $89.6 million for the corresponding period in 2012. The positive factors impacting Adjusted EBITDA were primarily related to $8.8 million of incremental revenue from capital investments in internal growth and diversification initiatives, including expanded butane blending capabilities, crude-handling services, as well as storage and throughput of other hydrocarbons, an $8.7 million increase in revenue resulting from an increase in terminalling storage contracts, including those associated with the facility in Perth Amboy, New Jersey that we acquired in July 2012 (the “Perth Amboy Facility”), an $8.5 million increase in revenue due to higher pipeline and terminalling volumes, a $0.9 million increase in earnings due to the purchase of an additional 30% ownership interest in WesPac Pipelines — Memphis LLC in the second half of 2012 and the beginning of the second quarter of 2013, which increased our ownership interest from 50% to 80% and a $0.2 million increase in earnings from equity investments.

The negative factors impacting Adjusted EBITDA were a $5.0 million increase in operating expenses, primarily related to outside services for asset-maintenance, higher operating costs due to increased volumes, and incremental costs associated with the Perth Amboy Facility acquired in July 2012, as well as a $2.6 million decrease in revenue due to lower average pipeline tariff rates resulting from shorter-haul shipments.

Pipeline volumes increased by 3.3% due to stronger demand for gasoline and middle distillates resulting from changes in regional production and supply, as well as higher heating oil shipments due to cooler temperatures when compared to the corresponding period in 2012. Terminalling volumes increased by 10.4% due to higher demand for gasoline, distillates, and other hydrocarbons 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 in a period of favorable market conditions.

International Operations. Adjusted EBITDA from the International Operations segment was $37.2 million for the three months ended June 30, 2013, which is an increase of $6.6 million, or 21.6%, from $30.6 million for the corresponding period in 2012. The positive factors impacting Adjusted EBITDA were due to a $6.7 million increase in storage revenue primarily as a result of incremental storage capacity brought online at our BORCO facility and a $1.0 million increase in ancillary revenues, including berthing of ships at our jetties, and heating services due to increased customer utilization of our facilities.

The increase in revenue was offset by a $1.0 million increase in operating expenses primarily due to increased costs necessary to operate the expanded capabilities of the BORCO facility and one-time costs related to certain organizational changes. Contribution related to new service offerings providing fuel oil supply and distribution services in the Caribbean remained relatively flat for the quarter ($86.1 million in revenue and $86.2 million in cost of product sales and related overhead expenses).

Natural Gas Storage. Adjusted EBITDA from the Natural Gas Storage segment was a loss of $5.8 million for the three months ended June 30, 2013, which is $5.4 million less favorable than a loss of $0.4 million for the corresponding period in 2012. The decrease in Adjusted EBITDA was primarily the result of a $2.7 million decrease in revenue for hub service activities related to decreased seasonal spreads, a $2.1 million increase in costs of natural gas storage services, which includes increased costs for hub services activities and a $2.0 million decrease in storage revenue due to lower rates and capacity utilization when compared to the corresponding period in 2012, partially offset by a $1.4 million decrease in operating expenses which primarily related to a decline in the number of well workovers performed during 2013 as compared to the 2012 period. Storage 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 $4.8 million for the three months ended June 30, 2013, which is an improvement of $8.0 million, or 248.9%, from a loss of $3.2 million for the corresponding period in 2012. The positive factors impacting Adjusted EBITDA were primarily related to cooler weather conditions in the Northeast when compared to the corresponding period in 2012, driving distillate demand and higher rack margins due to lower product costs from risk management activities and the generation of RINs, which are tradable “credits” generated by blending biofuels into finished gasoline or diesel products.

Adjusted EBITDA was positively impacted by a $104.0 million decrease in cost of product sales, which included a $96.0 million decrease due to 12.8% less volumes sold and a $8.0 million decrease in refined petroleum product cost due to a price decrease of approximately $0.04 per gallon (average cost prices per gallon were $2.85 and $2.89 for the 2013 and 2012 periods, respectively) and a $0.5 million decrease in operating expenses, which primarily related to overhead costs.

Adjusted EBITDA was negatively impacted by a $96.5 million decrease in revenue, which included a $96.0 million decrease due to 12.8% less volumes sold and a $0.5 million decrease in refined petroleum product sales due to no change in price per gallon (average sales price per gallon was $2.89 for both the 2013 and 2012 periods, respectively).

Development & Logistics. Adjusted EBITDA from the Development & Logistics segment was $3.2 million for the three months ended June 30, 2013, which is a decrease of $0.1 million, or 4.5%, from $3.3 million for the corresponding period in 2012. The decrease in Adjusted EBITDA was primarily due to a $0.6 million increase in engineering and operations expenses, partially offset by a $0.5 million increase in third-party engineering and operations revenue.

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

Consolidated

Adjusted EBITDA was $307.3 million for the six months ended June 30, 2013, which is an increase of $72.4 million, or 30.8%, from $234.9 million for the corresponding period in 2012. The increase in Adjusted EBITDA was primarily related to positive contributions from increased pipeline and terminalling volumes, growth capital spending and higher blending capabilities, particularly butane blending, in the Pipelines & Terminals segment, as well as increased earnings as a result of higher margins and lower operating costs in the Energy Services segment. Higher margins in the Energy Services segment were primarily due to lower product costs resulting from risk management activities and the generation of RINs. In addition, our International Operations segment benefited from increased storage capacity and customer utilization of our BORCO facility. These increases in Adjusted EBITDA were offset by compressed seasonal spreads and minimal volatility in natural gas prices in our Natural Gas Storage segment.

Revenue was $2,350.3 million for the six months ended June 30, 2013, which is an increase of $108.2 million, or 4.8%, from $2,242.1 million for the corresponding period in 2012. The increase in revenue was primarily related to incremental storage capacity brought online at our BORCO facility in the second half of 2012 and early 2013, as well as new service offerings providing fuel oil supply and distribution services in the International Operations segment. In addition, revenue in our Pipelines & Terminals segment increased as a result of increased pipeline and terminalling volumes directly attributable to our growth capital spending and higher blending capabilities. These increases in revenue were offset by lower product sales volume in our Energy Services segment.

Operating income was $224.8 million for the six months ended June 30, 2013, which is an increase of $61.9 million, or 38.0%, from $162.9 million for the corresponding period in 2012. The increase in operating income was primarily related to increased pipeline and terminalling volumes directly attributable to our growth capital spending and diversification initiatives in the Pipelines & Terminals segment and increased contribution from our Energy Services segment as a result of higher margins and lower operating costs. In addition, our International Operations segment benefited from incremental storage capacity brought online at our BORCO facility in the second half of 2012 and early 2013. These increases were offset by decreased seasonal spreads in our Natural Gas Storage segment.

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Distributable cash flow was $230.9 million for the six months ended June 30, 2013, which is an increase of $75.2 million, or 48.3%, from $155.7 million as compared to the corresponding period in 2012. The increase in distributable cash flow was primarily related to an increase of $72.4 million in Adjusted EBITDA as described above.

Adjusted EBITDA by Segment

Pipelines & Terminals. Adjusted EBITDA from the Pipelines & Terminals segment was $224.6 million for the six months ended June 30, 2013, which is an increase of $46.8 million, or 26.3%, from $177.8 million for the corresponding period in 2012. The positive factors impacting Adjusted EBITDA were related to $18.7 million of incremental revenue from capital investments in internal growth and diversification initiatives, including expanded butane blending capabilities, crude-handling services, as well as storage and throughput of other hydrocarbons, a $15.2 million increase in revenue due to higher pipeline and terminalling volumes on our legacy assets, a $13.7 million increase in revenue resulting from an increase in terminalling storage contracts, including those associated with the Perth Amboy Facility acquired in July 2012, $8.4 million of favorable settlement experience and a $1.3 million increase in earnings due to the purchase of an additional 30% ownership interest in WesPac Pipelines — Memphis LLC in the second half of 2012 and the beginning of the second quarter of 2013, which increased our ownership interest from 50% to 80%.

The negative factors impacting Adjusted EBITDA were a $5.9 million increase in operating expenses, primarily related to higher operating costs due to increased volumes, incremental costs associated with the Perth Amboy Facility acquired in July 2012, and an increase in fees related to the legal proceedings before the Federal Energy Regulatory Commission (“FERC”), a $4.4 million decrease in revenue due to lower average pipeline tariff rates resulting from shorter-haul shipments and a $0.2 million decrease in earnings from equity investments.

Pipeline volumes increased by 2.5% due to stronger demand for gasoline and middle distillates resulting from changes in regional production and supply, as well as higher heating oil shipments due to cooler temperatures when compared to the corresponding period in 2012. Terminalling volumes increased by 9.8% due to higher demand for gasoline, distillates and other hydrocarbons, 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 in a period of favorable market conditions.

International Operations. Adjusted EBITDA from the International Operations segment was $72.4 million for the six months ended June 30, 2013, which is an increase of $10.1 million, or 16.4%, from $62.3 million for the corresponding period in 2012. The positive factors impacting Adjusted EBITDA were due to an $11.3 million increase in storage revenue primarily as a result of incremental storage capacity brought online at our BORCO facility and a $2.6 million increase in ancillary revenues, including berthing of ships at our jetties, and heating services due to increased customer utilization of our facilities.

The increase in revenue was offset by a $2.7 million increase in operating expenses primarily due to increased costs necessary to operate the expanded capabilities of the BORCO facility and one-time costs related to certain organizational changes, and a loss of $1.1 million ($200.5 million in revenue and $201.6 million in cost of product sales and related overhead expenses) related to new fuel oil supply and distribution services in the Caribbean.

Natural Gas Storage. Adjusted EBITDA from the Natural Gas Storage segment was a loss of $7.6 million for the six months ended June 30, 2013, which is $5.9 million less favorable than a loss of $1.7 million for the corresponding period in 2012. The decrease in Adjusted EBITDA was primarily the result of a $6.4 million increase in costs of natural gas storage services, which includes increased costs for hub services activities related to opportunities to optimize the asset in future periods, a $0.6 million decrease in revenue for hub service activities related to decreased seasonal spreads and a $0.5 million decrease in storage revenue due to lower rates and capacity utilization when compared to the corresponding period in 2012, partially offset by a $1.6 million decrease in operating expenses which primarily related to a decline in the number of well workovers performed during 2013 as

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compared to the 2012 period. Storage 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).

Energy Services. Adjusted EBITDA from the Energy Services segment was $12.0 million for the six months ended June 30, 2013, which is an increase of $21.4 million, or 227.6%, from a loss of $9.4 million for the corresponding period in 2012. In 2012, we developed and executed a strategy to mitigate the basis risk that included the reduction of refined petroleum product inventories in the Midwest. In 2013, we continue to benefit from the execution of our risk mitigation strategy, which included focusing on fewer, more strategic locations in which to transact business, better managing our inventories and reducing the cost structure of the business. Furthermore, we benefited from improved rack margins, largely the result of risk management activities to lower product costs and the generation of RINs, which are tradable “credits” generated by blending biofuels into finished gasoline or diesel products.

Adjusted EBITDA was positively impacted by a $184.3 million decrease in cost of product sales, which included a $194.6 million decrease due to 10.9% of lower volumes sold, offset by a $10.3 million increase as a result of approximately $0.02 per gallon increase in refined petroleum product cost price (average cost prices per gallon were $2.97 and $2.95 for the 2013 and 2012 periods, respectively) and a $2.2 million decrease in operating expenses, which primarily related to overhead costs.

Adjusted EBITDA was negatively impacted by a $165.1 million decrease in revenue, which included a $194.5 million decrease due to 10.9% of lower sales volumes, offset by a $29.4 million increase as a result of approximately $0.05 per gallon increase in refined petroleum product sales price (average sales prices per gallon were $3.00 and $2.95 for the 2013 and 2012 periods, respectively).

Development & Logistics. Adjusted EBITDA from the Development & Logistics segment was $5.9 million for each of the six months ended June 30, 2013 and 2012. The offsetting changes in Adjusted EBITDA were primarily due to a $0.2 million increase in storage and throughput revenue in the 2013 period related to the LPG storage caverns, partially offset by a $0.2 million net increase in operating expenses, which primarily related to outside services.

Liquidity and Capital Resources

General

Our primary cash requirements, in addition to normal operating expenses and debt service, are for working capital, capital expenditures, business acquisitions and distributions to partners. Our principal sources of liquidity are cash from operations, borrowings under our Credit Facility and proceeds from the issuance of our LP 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.

Current Liquidity

As of June 30, 2013, we had $139.5 million of working capital and $612.7 million of additional borrowing capacity under our Credit Facility. In July 2013, we repaid in full the $300.0 million principal amount outstanding under the 4.625% Notes set to mature on July 15, 2013 and approximately $6.9 million of related accrued interest using funds available under our Credit Facility. See Note 6 in the Notes to Unaudited Condensed Consolidated Financial Statements for more information.

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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 on file with the SEC that, as of June 30, 2013, had approximately $726.2 million of unsold equity securities that we may issue thereunder. 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, 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; and merger and acquisition activities.

Debt

In June 2013, we issued $500.0 million of 4.150% Notes due July 1, 2023 in an underwritten public offering at 99.81% of their principal amount. Total proceeds from this offering, after underwriters’ fees, expenses and debt issuance costs of $3.3 million, were approximately $495.8 million. We used the net proceeds from this offering for general partnership purposes and to repay amounts due under our Credit Facility, a portion of which was subsequently reborrowed in July 2013 in order to repay in full the $300.0 million principal amount outstanding under the 4.625% Notes, including approximately $6.9 million of related accrued interest. We also settled all interest rate swaps relating to the 4.150% Notes for approximately $62.0 million during June 2013.

At June 30, 2013, the 4.625% Notes were classified as long-term debt because we had determined that our Credit Facility would be used to refinance this debt. At June 30, 2013, we had $612.7 million of additional borrowing capacity available under our Credit Facility. In July 2013, we repaid in full the $300.0 million principal amount outstanding under the 4.625% Notes using funds available under our Credit Facility.

At June 30, 2013, we had total fixed-rate and variable-rate debt obligations of $2,569.6 million and $76.0 million, respectively, with an aggregate fair value of $2,760.6 million. At June 30, 2013, we were in compliance with the covenants under our Credit Facility.

Equity

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otherwise agreed with any of such firms. During the three months ended June 30, 2013, we sold 0.4 million LP Units in aggregate under the Equity Distribution Agreements and received approximately $23.6 million in net proceeds after deducting commissions and other related expenses. During the three months ended June 30, 2013, we paid approximately $0.3 million of compensation in aggregate to the agents under the Equity Distribution Agreements.

Cash Flows from Operating, Investing and Financing Activities

The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated (in thousands):

	Six Months Ended
	June 30,
	2013			2012

Cash provided by (used in):
Operating activities	$	290,905		$	347,144
Investing activities	(147,289		)	(161,728		)
Financing activities	(145,503		)	(197,844		)
Net decrease in cash and cash equivalents	$	(1,887	)	$	(12,428	)

Operating Activities

Net cash provided by operating activities of $290.9 million for the six months ended June 30, 2013 primarily related to $167.9 million of net income, $77.0 million of depreciation and amortization and $64.3 million associated with a reduction in inventory, partially offset by a $62.0 million settlement to terminate the interest swap agreements related to the 4.150% Notes.

Net cash provided by operating activities of $347.1 million for the six months ended June 30, 2012 primarily related to $109.5 million of net income, $67.4 million of depreciation and amortization and $168.4 million associated with a reduction in inventory. During 2012, we developed and executed a strategy to mitigate our basis risk that included the reduction of refined petroleum product inventories in the Midwest. In 2013, we continue to effectively manage our exposure to basis risk through better management of our inventory levels.

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 of $147.3 million for the six months ended June 30, 2013 primarily related to $147.9 million of capital expenditures. Net cash used in investing activities of $161.7 million for the six months ended June 30, 2012 primarily related to $148.0 million of capital expenditures and a $14.0 million deposit for the Perth Amboy Facility acquired in 2012. See below for a discussion of capital spending.

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Financing Activities

Net cash used in financing activities of $145.5 million for the six months ended June 30, 2013 primarily related to $795.2 million of net repayments under the Credit Facility and $201.2 million of cash distributions paid to our unitholders ($2.0875 per LP Unit), partially offset by $499.1 million of proceeds from the issuance of the 4.150% Notes due on July 1, 2023, $349.2 million of net proceeds from the issuance of 6.9 million LP Units and $23.6 million of net proceeds from the issuance of 0.4 million LP Units under the Equity Distribution Agreements.

Net cash used in used in financing activities of $197.8 million for the six months ended June 30, 2012 primarily related to $252.2 million of net repayments under the Credit Facility and $185.4 million ($2.075 per LP Unit) of cash distributions paid to our unitholders, partially offset by $246.6 million of net proceeds from the issuance of 4.3 million LP Units to institutional investors in a registered direct offering.

Capital Expenditures

We have capital expenditures, which we define as “maintenance capital expenditures,” in order to maintain and enhance the safety and integrity of our pipelines, terminals, storage facilities and related assets, and “expansion and cost reduction capital expenditures” to expand the reach or capacity of those assets, to improve the efficiency of our operations, reduce costs and to pursue new business opportunities. Capital expenditures, excluding non-cash changes in accruals for capital expenditures, were as follows for the periods indicated (in thousands):

	Six Months Ended
	June 30,
	2013		2012

Maintenance capital expenditures	$	18,202	$	23,875
Expansion and cost reduction	129,665		124,125
Total capital expenditures, net	$	147,867	$	148,000

In the six months ended June 30, 2013, maintenance capital expenditures included pump replacements and truck rack infrastructure upgrades, as well as pipeline and tank integrity work. Expansion and cost reduction capital expenditures included significant investments in storage tank expansion at BORCO and Perth Amboy, butane blending, rail offloading facilities, crude storage/ transportation and various other cost reduction and revenue generating projects. In the six months ended June 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 continued progress on a new pipeline and terminal billing system as well as various other operating infrastructure projects.

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We have estimated our capital expenditures as follows for the year ending December 31, 2013 (in thousands):

	2013
	Low		High
Pipelines & Terminals:
Maintenance capital expenditures	$	45,000	$	50,000
Expansion and cost reduction	230,000		255,000
Total capital expenditures	$	275,000	$	305,000

International Operations:
Maintenance capital expenditures	$	10,000	$	20,000
Expansion and cost reduction	70,000		85,000
Total capital expenditures	$	80,000	$	105,000

Overall:
Maintenance capital expenditures	$	55,000	$	70,000
Expansion and cost reduction	300,000		340,000
Total capital expenditures	$	355,000	$	410,000

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 BORCO; completion of additional storage tanks and truck loading rack upgrades; rail offloading facilities and the refurbishment of storage tanks across our system; continued installation of vapor recovery units throughout our system of terminals; and various upgrades and expansions of our butane blending business. In connection with our 2012 Perth Amboy Facility acquisition, our estimated expansion and cost reduction expenditures include: development of a new crude rail offloading system; completion of a bi-directional pipeline; conversion of tanks for distillate and gasoline storage; a new gasoline and diesel truck loading rack installation; construction of a multi-product blend and transfer piping manifold; and construction of a new 16-inch pipeline allowing direct access to our existing pipeline infrastructure. Also, estimated expansion and cost reduction expenditures include costs to repair the damaged jetty at our BORCO facility as a result of the allision of a vessel with our jetty in May 2012. We believe the recovery of the costs to repair the damaged jetty is probable. See Note 3 in the Notes to Unaudited Condensed Consolidated Financial Statements for a more detailed discussion of this incident.

Off-Balance Sheet Arrangements

There have been no material changes with regard to our off-balance sheet arrangements since our Annual Report on Form 10-K for the year ended December 31, 2012.

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.

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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, 2012. 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

We are exposed to financial market risks, including changes in commodity prices and interest rates. 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. We are also susceptible to basis risk created when we enter into financial hedges that are priced at a certain location, but the sales or exchanges of the underlying commodity are at another location where prices and price changes might differ from the prices and price changes at the location upon which the hedging instrument is based. 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.

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

	Commodity			Interest
	Instruments			Rate Swaps			Total
Fair value of contracts outstanding at January 1, 2013	$	(8,439	)	$	(130,636	)	$	(139,075	)
Items recognized or settled during the period	(5,800		)	62,873			57,073
Fair value attributable to new deals	(2,142		)	—			(2,142		)
Change in fair value attributable to price movements	20,318			32,526			52,844
Change in fair value attributable to non-performance risk	(2		)	—			(2		)
Fair value of contracts outstanding at June 30, 2013	$	3,935		$	(35,237	)	$	(31,302	)

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.

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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, 2013	$	12,047
Net expenses recognized in period (1)	(8,610		)
Net cash paid—prepaid expense (2)	1,448
Net Asset at June 30, 2013	$	4,885

(1) Expenses were amortized into earnings based on the net fee paid over the injection and withdrawal period.

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

Energy Services

Our Energy Services segment primarily uses exchange-traded refined petroleum product futures contracts to manage the risk of market price volatility on its refined petroleum product inventories and its physical derivative contracts. Based on a hypothetical 10% movement in the underlying quoted market prices of the futures contracts and observable market data from third-party pricing publications for physical derivative contracts related to designated hedged refined petroleum products inventories outstanding and physical derivative contracts at June 30, 2013, the estimated fair value would be as follows (in thousands):

	Resulting
Scenario	Classification	Fair Value

Fair value assuming no change in underlying commodity prices (as is)	Asset	$	153,945
Fair value assuming 10% increase in underlying commodity prices	Asset	$	151,721
Fair value assuming 10% decrease in underlying commodity prices	Asset	$	156,169

Interest Rate Risk

We utilize forward-starting interest rate swaps to hedge the variability of the forecasted interest payments on anticipated debt issuances that may result from changes in the benchmark interest rate until the expected debt is issued. When entering into interest rate swap transactions, we are exposed to both credit risk and market risk. We manage our credit risk by entering into swap transactions only with major financial institutions with investment-grade credit ratings. We are subject to credit risk when the change in fair value of the swap instruments 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 impact the fair value of swaps. 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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Based on a hypothetical 10% movement in the underlying interest rates at June 30, 2013, the estimated fair value of the interest rate derivative contracts would be as follows (in thousands):

	Resulting
Scenario	Classification	Fair Value

Fair value assuming no change in underlying interest rates (as is)	Liability	$	(35,237	)
Fair value assuming 10% increase in underlying interest rates	Liability	$	(27,201	)
Fair value assuming 10% decrease in underlying interest rates	Liability	$	(43,872	)

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

Item 4. Controls and Procedures

(a) Evaluation of Disclosure Controls and Procedures.

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

(b) Change in Internal Control Over Financial Reporting.

There have been no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) or in other factors during the second quarter of 2013 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 May 2013, the Pennsylvania Department of Environmental Protection (“PADEP”) issued a proposed Consent Assessment of Civil Penalty related to a March 2011 release of diesel fuel that occurred in Shippingport Borough, Pennsylvania, which included a $0.2 million proposed penalty. We are in discussions with PADEP regarding the circumstances of the release and the appropriate amount of the penalty. The timing or outcome of this matter cannot reasonably be determined at this time.

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In May 2013, the Pipeline Hazardous Materials Safety Administration issued a proposed penalty totaling $0.4 million in connection with a product release that occurred in Linden, NJ in May 2010. We have contested portions of the proposed penalty. The timing or outcome of this matter cannot reasonably be determined at this time.

On December 3, 2012, a complaint was filed in the Circuit Court for Washington County, Wisconsin by Chad Altschafl, et al., as plaintiffs, naming Buckeye, Buckeye Pipe Line Services Company (“Services Company”), Buckeye Pipe Line Holdings, L.P. (“BPH”), Buckeye Pipe Line Company, L.P. (“BPLC”), West Shore Pipe Line Company (“West Shore”) and Zurich American Insurance Co. as defendants, which complaint was amended by the plaintiffs on April 18, 2013 and again on August 1, 2013. The plaintiffs are owners of 213 properties located in and around Jackson, Wisconsin. The complaint attempts to allege various emotional distress and property damage claims under Wisconsin law arising out of a release of gasoline from a pipeline owned by West Shore in the Town of Jackson, Wisconsin on July 17, 2012. On January 21, 2013, we filed an answer to the complaint, denying plaintiffs’ claims and asserting affirmative defenses. No dollar amount of damages is stated in the complaint, but the plaintiffs seek damages to reimburse them for, among other things, alleged costs of restoring their properties, of installing a permanent supply of potable water, and the alleged diminution in value of their properties. The plaintiffs also seek punitive damages. Pursuant to the proposed scheduling order jointly submitted by the parties, a trial is scheduled to begin in August 2015, but the timing or outcome of final resolution of this matter cannot reasonably be determined at this time. Buckeye, Services Company, BPH and BPLC are entitled to certain indemnifications by West Shore pursuant to an agreement between Buckeye Pipe Line and West Shore, which we believe would result in West Shore indemnifying us for any losses stemming from this litigation. In addition, West Shore has insurance that we believe should cover such losses, subject to a $3.0 million deductible. West Shore is pursuing that insurance coverage.

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, 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.

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).

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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).

3.	7	Amendment No. 2 to Amended and Restated Agreement of Limited Partnership of Buckeye Partners, L.P., dated as of February 21, 2013 (Incorporated by reference to Exhibit 3.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on February 25, 2013).

10.	1	Buckeye Partners, L.P. 2013 Long-Term Incentive Plan (Incorporated by reference to Exhibit A of Buckeye Partners, L.P.’s definitive Proxy Statement filed on April 19, 2013).

*10.	2	Form of Phantom Unit Grant Agreement for Directors.

*10.	3	Form of Phantom Unit Grant Agreement for Employees.

*10.	4	Form of Phantom Unit Grant Agreement for Unit Deferral Incentive Plan awards.

*10.	5	Form of Performance Unit Grant Agreement for Employees.

*31.	1	Certification of Chief Executive Officer pursuant to Rule 13a-14 (a) under the Securities Exchange Act of 1934.

*31.	2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

*32.	1	Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350.

*32.	2	Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350.

*101.	INS	XBRL Instance Document.

*101.	SCH	XBRL Taxonomy Extension Schema Document.

*101.	CAL	XBRL Taxonomy Extension Calculation Linkbase Document.

*101.	LAB	XBRL Taxonomy Extension Label Linkbase Document.

*101.	PRE	XBRL Taxonomy Extension Presentation Linkbase Document.

*101.	DEF	XBRL Taxonomy Extension Definition Linkbase Document.

* Filed herewith.

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SIGNATURES

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

	By:	BUCKEYE PARTNERS, L.P.
		(Registrant)

	By:	Buckeye GP LLC,
		as General Partner


Date: August 7, 2013	By:	/s/ Keith E. St.Clair
		Keith E. St.Clair
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)