Buckeye Partners (BPL) 10-Q 3 Nov 16 2016 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2016	Oct. 28, 2016
Document and Entity Information
Entity Registrant Name	BUCKEYE PARTNERS, L.P.
Entity Central Index Key	805,022
Document Type	10-Q
Document Period End Date	Sep. 30, 2016
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		140,222,340
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q3

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Revenue:
Product sales	$ 337,092	$ 382,624	$ 1,086,180	$ 1,581,455
Transportation, storage and other services	429,513	345,760	1,238,141	1,031,812
Total revenue	766,605	728,384	2,324,321	2,613,267
Costs and expenses:
Cost of product sales	326,718	366,319	1,049,315	1,532,392
Operating expenses	149,867	141,790	446,671	425,494
Depreciation and amortization	63,472	54,830	188,220	164,204
General and administrative	20,321	21,885	63,737	64,796
Total costs and expenses	560,378	584,824	1,747,943	2,186,886
Operating income	206,227	143,560	576,378	426,381
Other income (expense):
Earnings (loss) from equity investments	2,901	(30)	8,459	4,550
Interest and debt expense	(48,476)	(43,413)	(144,093)	(127,097)
Other (expense) income	(74)	70	(102)	180
Total other expense, net	(45,649)	(43,373)	(135,736)	(122,367)
Income from continuing operations before taxes	160,578	100,187	440,642	304,014
Income tax expense	(308)	(240)	(896)	(720)
Income from continuing operations	160,270	99,947	439,746	303,294
Loss from discontinued operations	0	0	0	(857)
Net income	160,270	99,947	439,746	302,437
Less: Net (income) loss attributable to noncontrolling interests	(3,896)	93	(11,803)	794
Net income attributable to Buckeye Partners, L.P.	$ 156,374	$ 100,040	$ 427,943	$ 303,231
Basic earnings (loss) per unit attributable to Buckeye Partners, L.P.:
Continuing operations (in dollars per share)	$ 1.19	$ 0.78	$ 3.28	$ 2.38
Discontinued operations (in dollars per share)	0	0	0	(0.01)
Total (in dollars per share)	1.19	0.78	3.28	2.37
Diluted earnings (loss) per unit attributable to Buckeye Partners, L.P.:
Continuing operations (in dollars per share)	1.19	0.78	3.26	2.37
Discontinued operations (in dollars per share)	0	0	0	(0.01)
Total (in dollars per share)	$ 1.19	$ 0.78	$ 3.26	$ 2.36
Weighted average units outstanding:
Basic (in shares)	131,113	128,329	130,439	127,722
Diluted (in shares)	131,940	128,906	131,076	128,241

CONDENSED CONSOLIDATED STATEME3

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Statement of Comprehensive Income [Abstract]
Net income	$ 160,270	$ 99,947	$ 439,746	$ 302,437
Other comprehensive income:
Unrealized gains on derivative instruments	1,052	11,168	1,052	7,311
Reclassification of derivative losses to net income	3,037	3,037	7,846	9,113
Recognition of costs related to benefit plans to net income	252	712	756	1,232
Total other comprehensive income	4,341	14,917	9,654	17,656
Comprehensive income	164,611	114,864	449,400	320,093
Less: Comprehensive (income) loss attributable to noncontrolling interests	(3,896)	93	(11,803)	794
Comprehensive income attributable to Buckeye Partners, L.P.	$ 160,715	$ 114,957	$ 437,597	$ 320,887

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 2	$ 4,881
Accounts receivable, net	253,019	213,830
Construction and pipeline relocation receivables	17,825	13,491
Inventories	295,307	192,992
Derivative assets	3,674	78,285
Prepaid and other current assets	71,153	48,071
Total current assets	640,980	551,550
Property, plant and equipment	7,430,036	7,076,901
Less: Accumulated depreciation	(1,008,061)	(874,820)
Property, plant and equipment, net	6,421,975	6,202,081
Equity investments	89,948	84,128
Goodwill	1,001,190	998,748
Intangible assets	618,370	627,310
Less: Accumulated amortization	(178,091)	(135,938)
Intangible assets, net	440,279	491,372
Other non-current assets	42,660	41,402
Total assets	8,637,032	8,369,281
Current liabilities:
Line of credit	218,340	111,488
Accounts payable	91,884	82,691
Derivative liabilities	22,036	510
Accrued and other current liabilities	253,162	309,620
Total current liabilities	585,422	504,309
Long-term debt	3,826,860	3,732,824
Other non-current liabilities	111,816	115,407
Total liabilities	4,524,098	4,352,540
Commitments and contingencies (Note 3)	0	0
Buckeye Partners, L.P. capital:
Limited Partners (131,309,840 and 129,523,703 units outstanding as of September 30, 2016 and December 31, 2015, respectively)	3,913,401	3,833,230
Accumulated other comprehensive loss	(88,187)	(97,841)
Total Buckeye Partners, L.P. capital	3,825,214	3,735,389
Noncontrolling interests	287,720	281,352
Total partners’ capital	4,112,934	4,016,741
Total liabilities and partners’ capital	$ 8,637,032	$ 8,369,281

CONDENSED CONSOLIDATED BALANCE5

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - shares	Sep. 30, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Limited Partners, units outstanding	131,309,840	129,523,703

CONDENSED CONSOLIDATED STATEME6

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Cash flows from operating activities:
Net income	$ 439,746	$ 302,437
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization	188,220	164,204
Litigation contingency accrual	0	15,229
Gains on property damage recoveries	(5,700)	0
Net changes in fair value of derivatives	98,917	25,632
Amortization of unfavorable storage contracts	(5,979)	(8,303)
Earnings from equity investments	(8,459)	(4,550)
Distributions from equity investments	2,418	4,258
Other non-cash items	39,393	34,319
Change in assets and liabilities, net of amounts related to acquisitions:
Accounts receivable	(40,109)	39,435
Construction and pipeline relocation receivables	(4,334)	6,570
Inventories	(101,016)	9,599
Prepaid and other current assets	(45,841)	(11,513)
Accounts payable	9,332	(54,820)
Accrued and other current liabilities	(10,088)	(18,881)
Other non-current assets	138	3,820
Other non-current liabilities	(6,865)	(5,005)
Net cash provided by operating activities	549,773	502,431
Cash flows from investing activities:
Capital expenditures	(380,072)	(433,152)
Acquisitions, net of working capital settlement	(25,941)	(2,921)
Proceeds from sale and disposition of assets	2,235	10,074
Escrow deposits	19,850	0
Recoveries on property damages	5,700	0
Net cash used in investing activities	(378,228)	(425,999)
Cash flows from financing activities:
Net proceeds from issuance of LP Units	108,422	117,820
Net proceeds from exercise of LP Unit options	300	173
Payment of tax withholding on issuance of LTIP awards	(5,123)	(6,667)
Debt issuance costs	(1,240)	(365)
Borrowings under BPL Credit Facility	978,700	1,087,000
Repayments under BPL Credit Facility	(1,136,800)	(844,000)
Net borrowings (repayments) under BMSC Credit Facility	106,852	(17,550)
Acquisition of additional interest in Buckeye Memphis	0	(10,044)
Borrowings under $250M Term Loan	250,000	0
Contributions from noncontrolling interests	3,760	44,000
Distributions paid to noncontrolling interests	(11,531)	(8,348)
Distributions paid to unitholders	(469,764)	(439,578)
Net cash used in financing activities	(176,424)	(77,559)
Net decrease in cash and cash equivalents	(4,879)	(1,127)
Cash and cash equivalents — Beginning of period	4,881	8,208
Cash and cash equivalents — End of period	$ 2	$ 7,081

CONDENSED CONSOLIDATED STATEME7

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL (Unaudited) - USD ($) $ in Thousands	Total	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interests	Limited Partners
Beginning balance at Dec. 31, 2014	$ 3,940,596	$ (115,288)	$ 237,968	$ 3,817,916
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	302,437		(794)	303,231
Acquisition of additional interest in Buckeye Memphis	(10,044)		(1,768)	(8,276)
Adjusted value of noncontrolling interest in acquisition	(1,220)		(1,220)
Distributions paid to unitholders	(439,578)		2,379	(441,957)
Net proceeds from issuance of LP Units	117,820			117,820
Amortization of unit-based compensation awards	17,764			17,764
Net proceeds from exercise of LP Unit options	173			173
Payment of tax withholding on issuance of LTIP awards	(6,667)			(6,667)
Distributions paid to noncontrolling interests	(8,348)		(8,348)
Contributions from noncontrolling interests	44,000		44,000
Other comprehensive income	17,656	17,656
Noncash accrual for distribution equivalent rights	(1,944)			(1,944)
Other	56		(106)	162
Ending balance at Sep. 30, 2015	3,972,701	(97,632)	272,111	3,798,222
Beginning balance at Dec. 31, 2015	4,016,741	(97,841)	281,352	3,833,230
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	439,746		11,803	427,943
Distributions paid to unitholders	(469,764)		2,292	(472,056)
Net proceeds from issuance of LP Units	108,422			108,422
Amortization of unit-based compensation awards	22,977			22,977
Net proceeds from exercise of LP Unit options	300			300
Payment of tax withholding on issuance of LTIP awards	(5,123)			(5,123)
Distributions paid to noncontrolling interests	(11,531)		(11,531)
Contributions from noncontrolling interests	3,760		3,760
Other comprehensive income	9,654	9,654
Noncash accrual for distribution equivalent rights	(2,248)			(2,248)
Other	0		44	(44)
Ending balance at Sep. 30, 2016	$ 4,112,934	$ (88,187)	$ 287,720	$ 3,913,401

ORGANIZATION AND BASIS OF PRESE

ORGANIZATION AND BASIS OF PRESENTATION	9 Months Ended
	Sep. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
ORGANIZATION AND BASIS OF PRESENTATION	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 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 ” or “ Buckeye ” mean Buckeye Partners, L.P. and, where the context requires, includes our subsidiaries. Buckeye owns and operates a diversified network of integrated assets providing midstream logistic solutions, primarily consisting of the transportation, storage and marketing of liquid petroleum products. We are one of the largest independent liquid petroleum products pipeline operators in the United States in terms of volumes delivered and miles of pipeline. In addition, we own and operate one of the largest networks of active products terminals across our portfolio of pipelines, inland terminals and marine terminals located primarily in the East Coast and Gulf Coast regions of the United States and in the Caribbean. Our network of marine terminals enables us to facilitate global flows of crude oil and refined petroleum products, offering our customers connectivity between supply areas and market centers through some of the world’s most important bulk storage and blending hubs. Our flagship marine terminal in The Bahamas, Buckeye Bahamas Hub Limited (“BBH”), formerly known as Bahamas Oil Refining Company International Limited (“BORCO”), is one of the largest marine crude oil and refined petroleum products storage facilities in the world and provides an array of logistics and blending services for the global flow of petroleum products. Our expansion into the Gulf Coast has added another regional hub, Buckeye Texas Partners LLC (“Buckeye Texas”), with world-class marine terminalling, storage and processing capabilities. We are also a wholesale distributor of refined petroleum products in certain areas served by our pipelines and terminals. 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 and the rules of the U.S. Securities and Exchange Commission. 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 unaudited condensed 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, 2015 . Recent Accounting Developments Statement of Cash Flows . In August 2016, the Financial Accounting Standards Board (“FASB”) issued guidance to address how certain cash receipts and cash payments are presented and classified in the statement of cash flows, with the objective of reducing existing diversity in practice with respect to these items. The guidance must be applied retrospectively, and it is effective for annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods, with early adoption permitted. We are currently evaluating the impact the adoption of this guidance will have on our consolidated financial statements. Equity-Based Compensation . In March 2016, the FASB issued guidance to simplify several aspects of the accounting for employee equity-based payment transactions, including the accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as classification in the statement of cash flows and classification of awards as liabilities or equity. The guidance is effective for annual reporting periods beginning after December 15, 2016 and interim periods within those annual periods, with early adoption permitted. Amendments related to the timing of when excess tax benefits are recognized, statutory withholding requirements and forfeitures should be applied using a modified retrospective transition method by means of a cumulative-effect adjustment to equity as of the beginning of the period in which the guidance is adopted. Amendments related to the presentation of employee taxes paid on the statement of cash flows should be applied retrospectively. Amendments requiring recognition of excess tax benefits and tax deficiencies in the income statement should be applied prospectively. Amendments related to the presentation of excess tax benefits on the statement of cash flows may be applied using either a prospective transition method or a retrospective transition method. We are currently evaluating the impact the adoption of this guidance will have on our consolidated financial statements. Leases . In February 2016, the FASB issued guidance requiring lessees to recognize assets and liabilities for leases with lease terms greater than twelve months in the statement of financial position. This update also requires enhanced disclosures regarding the amount, timing and uncertainty of cash flows arising from leases. The guidance must be applied using a modified retrospective approach and is effective for annual reporting periods beginning after December 15, 2018 and interim periods within those annual periods, with early adoption permitted. We are currently evaluating the impact the adoption of this guidance will have on our consolidated financial statements.

ACQUISITIONS

ACQUISITIONS	9 Months Ended
	Sep. 30, 2016
Business Combinations [Abstract]
ACQUISITIONS	2. ACQUISITIONS Business Combinations 2016 Transaction Indianola terminalling facility acquisition In August 2016, we acquired a liquid petroleum products terminalling facility in Indianola, Pennsylvania from Kinder Morgan Transmix Company, LLC for $25.9 million . The operations of these assets are reported in our Domestic Pipelines & Terminals segment. The acquisition cost has been allocated on a preliminary basis to assets acquired based on estimated fair values at the acquisition date, with amounts exceeding the fair value recorded as goodwill, which represent expected synergies from combining the acquired assets with our existing operations. Fair values have been developed using recognized business valuation techniques. The estimates of fair value reflected as of September 30, 2016 are subject to change pending final valuation analysis. The purchase price has been allocated to tangible and intangible assets acquired and liabilities assumed as follows (in thousands): Inventories $ 1,299 Property, plant and equipment 20,239 Goodwill 4,403 Allocated purchase price $ 25,941 Unaudited Pro forma Financial Results for the Indianola terminalling facility acquisition Our consolidated statements of operations do not include earnings from the terminalling facility prior to August 4, 2016, the effective acquisition date of these assets. The preparation of unaudited pro forma financial information for the terminalling facility is impracticable due to the fact that meaningful historical revenue information is not available. The revenues and earnings impact of this acquisition was not significant to our financial results for the three and nine months ended September 30, 2016 . 2015 Transactions Pennsauken pipeline acquisition In December 2015, we acquired a pipeline and associated tanks and other infrastructure in Pennsauken, New Jersey for $5.3 million . The operations of these assets are reported in our Domestic Pipelines & Terminals segment. The acquisition cost has been allocated to assets acquired based on estimated fair values at the acquisition date, with amounts exceeding the fair value recorded as goodwill, which represent expected synergies from combining the acquired assets with our existing operations. Fair values have been developed using recognized business valuation techniques. The purchase price has been allocated to tangible and intangible assets acquired and liabilities assumed as follows (in thousands): Property, plant and equipment $ 7,159 Goodwill 500 Environmental liabilities (2,372 ) Allocated purchase price $ 5,287 We finalized the purchase price allocation during the third quarter of 2016. Adjustments to the preliminary purchase price allocation resulted in an increase to property, plant and equipment of $1.9 million , with a corresponding decrease to goodwill. The change to the preliminary amount resulted in a nominal increase to depreciation expense and accumulated depreciation. Unaudited Pro forma Financial Results for the Pennsauken pipeline acquisition Our consolidated statements of operations do not include earnings from the pipeline and associated tanks and other infrastructure prior to December 10, 2015, the effective acquisition date of these assets. The preparation of unaudited pro forma financial information for the pipeline and associated tanks and other infrastructure is impracticable due to the fact that meaningful historical revenue information is not available. The revenues and earnings impact of this acquisition was not significant to our financial results for the three and nine months ended September 30, 2016 . Springfield pipeline and terminal acquisitions In March and May 2015, we acquired a terminal and pipeline, respectively, in Springfield, Massachusetts from ExxonMobil Oil Corporation (“ExxonMobil”) for an aggregate $7.7 million . The operations of these assets are reported in our Domestic Pipelines & Terminals segment. The acquisition cost has been allocated to assets acquired and liabilities assumed based on estimated fair values at the acquisition date, with amounts exceeding the fair value recorded as goodwill, which represents both expected synergies from combining the acquired assets with our existing operations and the economic value attributable to optimizing, modernizing and commercializing the asset from this acquisition. Fair values have been developed using recognized business valuation techniques. We finalized the purchase price allocation during the first quarter of 2016. The purchase price has been allocated to tangible and intangible assets acquired and liabilities assumed as follows (in thousands): Property, plant and equipment $ 4,040 Goodwill 8,165 Asset retirement obligation (4,200 ) Environmental liabilities (293 ) Allocated purchase price $ 7,712 Unaudited Pro forma Financial Results for the Springfield pipeline and terminal acquisition Our consolidated statements of operations do not include earnings from the terminal acquired from ExxonMobil prior to March 31, 2015, nor earnings from the pipeline acquired from ExxonMobil prior to May 5, 2015, which were the respective acquisition dates of the assets. The preparation of unaudited pro forma financial information for the terminal and pipeline acquired from ExxonMobil is impracticable due to the fact that ExxonMobil historically operated the assets as part of its integrated distribution network and, therefore, meaningful historical revenue information is not available. The revenues and earnings impact of this acquisition was not significant to our financial results for the three and nine months ended September 30, 2016 or 2015 .

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	9 Months Ended
	Sep. 30, 2016
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	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. Environmental Contingencies We recorded operating expenses, net of insurance recoveries, of $1.8 million and $1.7 million during the three months ended September 30, 2016 and 2015 , respectively, related to environmental remediation liabilities unrelated to claims and legal proceedings. For the nine months ended September 30, 2016 and 2015 , we recorded operating expenses, net of insurance recoveries, of $6.0 million and $4.5 million , respectively, related to environmental remediation liabilities unrelated to claims and legal proceedings. As of September 30, 2016 and December 31, 2015 , we recorded environmental remediation liabilities of $46.3 million and $48.0 million , respectively. Costs incurred may be in excess of our estimate, which may have a material impact on our financial condition, results of operations or cash flows. At September 30, 2016 and December 31, 2015 , we had $7.0 million and $10.9 million , respectively, of receivables related to these environmental remediation liabilities covered by insurance or third-party claims.

INVENTORIES

INVENTORIES	9 Months Ended
	Sep. 30, 2016
Inventory Disclosure [Abstract]
INVENTORIES	4. INVENTORIES Our inventory amounts were as follows at the dates indicated (in thousands): September 30, December 31, Liquid petroleum products (1) $ 275,853 $ 174,232 Materials and supplies 19,454 18,760 Total inventories $ 295,307 $ 192,992 (1) Ending inventory was 178.8 million and 153.3 million gallons of liquid petroleum products as of September 30, 2016 and December 31, 2015 , respectively. At September 30, 2016 and December 31, 2015 , approximately 92% and 89% of our liquid petroleum products inventory volumes were designated in a fair value hedge relationship, 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. Our inventory volumes that are not designated as the hedged item in a fair value hedge relationship are economically hedged to reduce our commodity price exposure. Inventory not accounted for as a fair value hedge is accounted for at the lower of weighted average cost method or net realizable value.

PREPAID AND OTHER CURRENT ASSET

PREPAID AND OTHER CURRENT ASSETS	9 Months Ended
	Sep. 30, 2016
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
PREPAID AND OTHER CURRENT ASSETS	5. PREPAID AND OTHER CURRENT ASSETS Prepaid and other current assets consist of the following at the dates indicated (in thousands): September 30, December 31, Prepaid insurance $ 13,050 $ 12,779 Margin deposits 35,950 — Unbilled revenue 2,383 4,047 Prepaid taxes 9,396 4,842 Escrow deposits 10 21,360 Other 10,364 5,043 Total prepaid and other current assets $ 71,153 $ 48,071

EQUITY INVESTMENTS

EQUITY INVESTMENTS	9 Months Ended
	Sep. 30, 2016
Equity Method Investments and Joint Ventures [Abstract]
EQUITY INVESTMENTS	6. EQUITY INVESTMENTS The following table presents earnings (losses) from equity investments for the periods indicated (in thousands): Three Months Ended Nine Months Ended 2016 2015 2016 2015 West Shore Pipe Line Company $ 1,784 $ 2,033 $ 5,680 $ 6,209 Muskegon Pipeline LLC 544 (2,761 ) 1,340 (3,345 ) Transport4, LLC 204 183 577 456 South Portland Terminal LLC 369 515 862 1,230 Total earnings (loss) from equity investments $ 2,901 $ (30 ) $ 8,459 $ 4,550 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 Nine Months Ended 2016 2015 2016 2015 Revenue $ 22,831 $ 24,440 $ 65,877 $ 68,786 Costs and expenses (10,026 ) (16,642 ) (30,466 ) (43,256 ) Non-operating expenses (4,142 ) (4,033 ) (11,425 ) (11,690 ) Net income $ 8,663 $ 3,765 $ 23,986 $ 13,840

LONG-TERM DEBT

LONG-TERM DEBT	9 Months Ended
	Sep. 30, 2016
Debt Disclosure [Abstract]
LONG-TERM DEBT	7. LONG-TERM DEBT Credit Facility In September 2016, Buckeye and its indirect wholly-owned subsidiaries, Buckeye Energy Services LLC, Buckeye West Indies Holdings LP and Buckeye Caribbean Terminals LLC, collectively the Buckeye Merchant Service Companies (“BMSC”), as borrowers, exercised their remaining option with consenting lenders to extend $1.4 billion of our existing $1.5 billion revolving credit facility with SunTrust Bank, as administrative agent, and other lenders (the “Credit Facility”) by one year to September 30, 2021. At the time of the transaction, we had $3.4 million of remaining unamortized deferred financing costs, and we incurred additional debt issuance costs of $0.7 million in connection with the extension of the Credit Facility. Term Loan In September 2016, we entered into a credit agreement with SunTrust Bank, as administrative agent, and other lenders for a $250.0 million variable-rate term loan due September 30, 2019 (the “Term Loan”), with an option to extend the term for up to two one -year periods. We incurred debt issuance costs of $0.5 million related to the Term Loan. Under the Term Loan, interest accrues at the London Interbank Offered Rate (“LIBOR”) rate or a base rate plus an applicable margin based on the election of the borrower. The applicable margin used in connection with interest rates and fees is based on the credit ratings assigned to our senior unsecured long-term debt securities. The applicable margin for LIBOR rate loans ranges from 1.0% to 1.6% and the applicable margin for base rate loans ranges from 0% to 0.6% . The Term Loan includes covenants limiting, as of the last day of each fiscal quarter, the ratio of consolidated funded debt (“Funded Debt Ratio”) to consolidated EBITDA, as defined in the Term Loan, measured for the preceding twelve months, to not more than 5.0 to 1.0. This requirement is subject to a provision for increases to 5.5 to 1.0 in connection with certain future acquisitions. The Funded Debt Ratio is calculated by dividing consolidated debt by annualized EBITDA, which is defined in the Term Loan as earnings before interest, taxes, depreciation, depletion and amortization determined on a consolidated basis. At September 30, 2016 , we were in compliance with the covenants under the Term Loan. At September 30, 2016 , we had $250.0 million outstanding under the Term Loan. We used the proceeds from the Term Loan to reduce the indebtedness outstanding under our Credit Facility. Current Maturities Expected to be Refinanced It is our intent to refinance the $125.0 million of 5.125% Notes maturing on July 1, 2017 using our Credit Facility. At September 30, 2016, we had $1,078.8 million of additional borrowing capacity under our Credit Facility. Therefore, we have classified these notes as long-term debt in the unaudited condensed consolidated balance sheet at September 30, 2016 .

DERIVATIVE INSTRUMENTS AND HEDG

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES	9 Months Ended
	Sep. 30, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES	8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES We are exposed to financial market risks, including changes in commodity prices, in the course of our normal business operations. We use derivative instruments to manage risks. Interest Rate Derivatives From time to time, 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 designate 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. During the third quarter of 2016, we entered into four forward-starting interest rate swaps with a total aggregate notional amount of $200.0 million , which we entered into in anticipation of the issuance of debt on or before January 15, 2018, and 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 November 15, 2018. We expect to issue new fixed-rate debt on or before January 15, 2018 to repay the $300.0 million of 6.050% Notes that are due on January 15, 2018, and on or before November 15, 2018 to repay the $400.0 million of 2.650% Notes that are due on November 15, 2018, although no assurances can be given that the issuance of fixed-rate debt will be possible on acceptable terms. During the three and nine months ended September 30, 2016 , unrealized gains of $1.1 million were recorded in accumulated other comprehensive income (“AOCI”) to reflect the change in the fair values of the forward-starting interest rate swaps. Commodity Derivatives Our Merchant 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 which we designated as fair value hedges with changes in fair value of both the futures contracts and physical inventory reflected in earnings. Physical forward 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 September 30, 2016 (amounts in thousands of gallons): Volume (1) Accounting Derivative Purpose Current Long-Term Treatment Derivatives NOT designated as hedging instruments: Physical fixed price derivative contracts 8,504 1,073 Mark-to-market Physical index derivative contracts 31,274 — Mark-to-market Futures contracts for refined petroleum products 24,819 16,926 Mark-to-market Derivatives designated as hedging instruments: Physical fixed price derivative contracts 1,176 — Fair Value Hedge Futures contracts for refined petroleum products 163,800 — Fair Value Hedge (1) Volume represents absolute value of net notional volume position. The following table sets forth the fair value of each classification of derivative instruments and the locations of the derivative instruments on our unaudited condensed consolidated balance sheets at the dates indicated (in thousands): September 30, 2016 Derivatives NOT Designated as Hedging Instruments Derivatives Designated as Hedging Instruments Derivative Carrying Value Netting Balance Sheet Adjustment (1) Net Total Physical fixed price derivative contracts $ 4,046 $ 67 $ 4,113 $ (505 ) $ 3,608 Physical index derivative contracts 67 — 67 (1 ) 66 Futures contracts for refined products 20,655 1,005 21,660 (21,660 ) — Total current derivative assets 24,768 1,072 25,840 (22,166 ) 3,674 Physical fixed price derivative contracts 293 — 293 (8 ) 285 Futures contracts for refined products 84 — 84 (84 ) — Interest rates derivatives — 1,052 1,052 — 1,052 Total non-current derivative assets 377 1,052 1,429 (92 ) 1,337 Physical fixed price derivative contracts (2,673 ) — (2,673 ) 505 (2,168 ) Physical index derivative contracts (41 ) — (41 ) 1 (40 ) Futures contracts for refined products (29,231 ) (12,257 ) (41,488 ) 21,660 (19,828 ) Total current derivative liabilities (31,945 ) (12,257 ) (44,202 ) 22,166 (22,036 ) Physical fixed price derivative contracts (27 ) — (27 ) 8 (19 ) Futures contracts for refined products (4,042 ) — (4,042 ) 84 (3,958 ) Total non-current derivative liabilities (4,069 ) — (4,069 ) 92 (3,977 ) Net derivative liabilities $ (10,869 ) $ (10,133 ) $ (21,002 ) $ — $ (21,002 ) (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, 2015 Derivatives NOT Designated as Hedging Instruments Derivatives Designated as Hedging Instruments Derivative Carrying Value Netting Balance Sheet Adjustment (1) Net Total Physical fixed price derivative contracts $ 26,698 $ — $ 26,698 $ (79 ) $ 26,619 Physical index derivative contracts 87 — 87 (62 ) 25 Futures contracts for refined products 136,131 36,834 172,965 (121,324 ) 51,641 Total current derivative assets 162,916 36,834 199,750 (121,465 ) 78,285 Physical fixed price derivative contracts 1,057 — 1,057 — 1,057 Total non-current derivative assets 1,057 — 1,057 — 1,057 Physical fixed price derivative contracts (535 ) — (535 ) 79 (456 ) Physical index derivative contracts (116 ) — (116 ) 62 (54 ) Futures contracts for refined products (119,506 ) (1,818 ) (121,324 ) 121,324 — Total current derivative liabilities (120,157 ) (1,818 ) (121,975 ) 121,465 (510 ) Futures contracts for refined products (703 ) — (703 ) — (703 ) Total non-current derivative liabilities (703 ) — (703 ) — (703 ) Net derivative assets $ 43,113 $ 35,016 $ 78,129 $ — $ 78,129 (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. Our futures contracts designated as fair value hedges related to our inventory portfolio extend to the second quarter of 2017 . The unrealized loss at September 30, 2016 for fair value hedges of inventory represented by future contracts of $11.3 million will be realized by the second quarter of 2017 . At September 30, 2016 , open refined petroleum product derivative contracts (represented by the physical fixed-price contracts, physical index contracts, and futures contracts for refined products contracts noted above) varied in duration in the overall portfolio, but did not extend beyond December 2018 . In addition, at September 30, 2016 , 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 Nine Months Ended Location 2016 2015 2016 2015 Derivatives NOT designated as hedging instruments: Physical fixed price derivative contracts Product sales $ 301 $ 15,731 $ (7,263 ) $ 19,660 Physical index derivative contracts Product sales 142 (299 ) 130 (309 ) Physical fixed price derivative contracts Cost of product sales 479 3,600 7,965 10,191 Physical index derivative contracts Cost of product sales 30 (288 ) 193 (224 ) Futures contracts for refined products Cost of product sales (307 ) (10,992 ) 4,326 2,591 Derivatives designated as fair value hedging instruments: Futures contracts for refined products Cost of product sales $ (635 ) $ 54,514 $ (27,590 ) $ 21,959 Physical inventory - hedged items Cost of product sales 3,620 (55,424 ) 43,627 (34,848 ) Ineffectiveness excluding the time value component on fair value hedging instruments: Fair value hedge ineffectiveness (excluding time value) Cost of product sales $ (4,262 ) $ 2,626 $ (4,275 ) $ 2,476 Time value excluded from hedge assessment Cost of product sales 7,247 (3,536 ) 20,312 (15,365 ) Net gain (loss) in income $ 2,985 $ (910 ) $ 16,037 $ (12,889 ) The change in value recognized in other comprehensive income (“OCI”) and the losses reclassified from AOCI to income attributable to our derivative instruments designated as cash flow hedges were as follows for the periods indicated (in thousands): Gain Recognized in OCI on Derivatives for the Three Months Ended Nine Months Ended 2016 2015 2016 2015 Derivatives designated as cash flow hedging instruments: Interest rate contracts $ 1,052 $ — $ 1,052 $ — Commodity derivatives — 11,168 — 7,311 Total $ 1,052 $ 11,168 $ 1,052 $ 7,311 (Loss) Gain Reclassified from AOCI to Income (Effective Portion) for the Three Months Ended Nine Months Ended Location 2016 2015 2016 2015 Derivatives designated as cash flow hedging instruments: Interest rate contracts Interest and debt expense $ (3,037 ) $ (3,037 ) $ (9,112 ) $ (9,113 ) Commodity derivatives Product Sales — — 1,266 — Total $ (3,037 ) $ (3,037 ) $ (7,846 ) $ (9,113 ) Over the next twelve months, we expect to reclassify $12.2 million of net losses attributable to interest rate derivative instruments from AOCI to earnings as an increase to interest and debt expense. For additional information on the net losses attributable to interest rate derivative instruments, see our Annual Report on Form 10-K for the year ended December 31, 2015 .

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	9 Months Ended
	Sep. 30, 2016
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	9. 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): September 30, 2016 December 31, 2015 Level 1 Level 2 Level 1 Level 2 Financial assets: Physical fixed price derivative contracts $ — $ 3,893 $ — $ 27,676 Physical index derivative contracts — 66 — 25 Futures contracts for refined products — — 51,641 — Interest rate derivatives — 1,052 — — Financial liabilities: Physical fixed price derivative contracts — (2,187 ) — (456 ) Physical index derivative contracts — (40 ) — (54 ) Futures contracts for refined products (23,786 ) — (703 ) — Fair value $ (23,786 ) $ 2,784 $ 50,938 $ 27,191 The values of the Level 1 derivative assets and liabilities were based on quoted market prices obtained from the New York Mercantile Exchange. The values of the Level 2 commodity 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 physical 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 Merchant Services segment determined CVAs are appropriate because few of the Merchant Services segment’s customers entering into these derivative contracts are large organizations with nationally recognized credit ratings. The CVAs were nominal as of September 30, 2016 and December 31, 2015 . As of September 30, 2016 and December 31, 2015 , the Merchant 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): September 30, 2016 December 31, 2015 Carrying Amount Fair Value Carrying Amount Fair Value Fixed-rate debt $ 3,623,960 $ 3,795,826 $ 3,371,824 $ 3,057,945 Variable-rate debt 421,240 421,240 472,488 472,488 Total debt $ 4,045,200 $ 4,217,066 $ 3,844,312 $ 3,530,433 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 nine months ended September 30, 2016 and 2015 , 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 nine months ended September 30, 2016 and 2015 , there were no fair value adjustments related to such assets or liabilities reflected in our unaudited condensed consolidated financial statements.

PENSIONS AND OTHER POSTRETIREME

PENSIONS AND OTHER POSTRETIREMENT BENEFITS	9 Months Ended
	Sep. 30, 2016
Compensation and Retirement Disclosure [Abstract]
PENSIONS AND OTHER POSTRETIREMENT BENEFITS	10. PENSIONS AND OTHER POSTRETIREMENT BENEFITS Buckeye Pipe Line 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 RIGP and Retiree Medical Plan are closed and have limited participation. The components of the net periodic benefit cost for the RIGP and Retiree Medical Plan were as follows for the three and nine months ended September 30, 2016 and 2015 (in thousands): RIGP Retiree Medical Plan Three Months Ended Three Months Ended 2016 2015 2016 2015 Service cost $ (9 ) $ 3 $ 81 $ 92 Interest cost 106 137 327 333 Expected return on plan assets (64 ) (84 ) — — Amortization of unrecognized losses 130 211 — 50 Actuarial loss due to settlements 122 451 — — Net periodic benefit cost $ 285 $ 718 $ 408 $ 475 RIGP Retiree Medical Plan Nine Months Ended Nine Months Ended 2016 2015 2016 2015 Service cost $ (26 ) $ 9 $ 242 $ 274 Interest cost 316 413 982 1,000 Expected return on plan assets (192 ) (251 ) — — Amortization of unrecognized losses 391 632 — 149 Actuarial loss due to settlements 365 451 — — Net periodic benefit cost $ 854 $ 1,254 $ 1,224 $ 1,423 During the three months ended September 30, 2016 and 2015 , we contributed $0.3 million and $0.5 million , respectively, in aggregate to the RIGP and Retiree Medical Plans. For the nine months ended September 30, 2016 and 2015 , we contributed $1.3 million and $1.2 million , respectively, in aggregate to the RIGP and Retiree Medical Plans.

UNIT-BASED COMPENSATION PLANS

UNIT-BASED COMPENSATION PLANS	9 Months Ended
	Sep. 30, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
UNIT-BASED COMPENSATION PLANS	11. 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”). 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”). These compensation plans are further discussed below. We recognized compensation expense from continuing operations related to the LTIP and the Option Plan, of $8.9 million and $6.6 million for the three months ended September 30, 2016 and 2015 , respectively. For the nine months ended September 30, 2016 and 2015 , we recognized compensation expense of $23.0 million and $17.6 million , respectively. LTIP As of September 30, 2016 , there were 2,036,228 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, as amended and restated effective February 4, 2015 (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 the Buckeye Partners, L.P. Annual Incentive Compensation Plan, as amended and restated, effective January 1, 2012. At December 31, 2015 and 2014 , actual compensation awards deferred under the Deferral Plan were $3.1 million and $1.7 million , for which 139,526 and 54,592 phantom units (including matching units) were granted during the nine months ended September 30, 2016 and the year ended 2015 , respectively. These grants are included as granted in the LTIP activity table below. Awards under the LTIP During the nine months ended September 30, 2016 , the Compensation Committee of the Board granted 342,572 phantom units to employees (including the 139,526 phantom units granted pursuant to the Deferral Plan, as discussed above), 20,000 phantom units to independent directors of Buckeye GP and 274,896 performance units to employees. The following table sets forth the LTIP activity for the periods indicated (in thousands, except per unit amounts): Number of LP Units Weighted Average Grant Date Fair Value per LP Unit Unvested at January 1, 2016 1,011 $ 68.20 Granted 637 53.48 Vested (267 ) 55.28 Forfeited (8 ) 64.53 Unvested at September 30, 2016 1,373 $ 64.00 At September 30, 2016 , $39.1 million of compensation expense related to the LTIP is expected to be recognized over a weighted average period of 1.8 years . Unit Option 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): Number of LP Units Weighted Average Strike Price per LP Unit Weighted Average Remaining Contractual Term (in years) Aggregate Intrinsic Value (1) Outstanding at January 1, 2016 17 $ 48.71 0.9 $ 300 Exercised (6 ) 47.17 Forfeited, cancelled or expired (1 ) 44.73 Outstanding at September 30, 2016 10 50.36 0.4 $ 203 Exercisable at September 30, 2016 10 $ 50.36 0.4 $ 203 (1) Aggregate intrinsic value reflects fully vested LP Unit options at the date indicated. Intrinsic value is determined by calculating the difference between our closing LP Unit price on the last trading day in September 2016 and the exercise price, multiplied by the number of exercisable, in-the-money options. The total intrinsic value of options exercised during each of the nine months ended September 30, 2016 and 2015 was $0.1 million .

PARTNERS' CAPITAL AND DISTRIBUT

PARTNERS' CAPITAL AND DISTRIBUTIONS	9 Months Ended
	Sep. 30, 2016
Equity [Abstract]
PARTNERS' CAPITAL AND DISTRIBUTIONS	12. PARTNERS' CAPITAL AND DISTRIBUTIONS In March 2016, we entered into an equity distribution agreement (the “Equity Distribution Agreement”) with J.P. Morgan Securities LLC, BB&T Capital Markets, a division of BB&T Securities, LLC, BNP Paribas Securities Corp., Deutsche Bank Securities Inc., Jefferies LLC, Morgan Stanley & Co. LLC, RBC Capital Markets, LLC, and SMBC Nikko Securities America, Inc. Under the terms of the Equity Distribution Agreement, we may offer and sell up to $500.0 million in aggregate gross sales proceeds of LP Units from time to time through such firms, acting as agents of Buckeye or as principals, subject in each case to the terms and conditions set forth in the Equity Distribution Agreement. This agreement replaced our prior four separate equity distribution agreements with each of Wells Fargo Securities, LLC, Barclays Capital Inc., SunTrust Robinson Humphrey, Inc. and UBS Securities LLC, which we entered into in May 2013 and, under the terms of which, we could sell up to $300.0 million in aggregate gross sales proceeds of LP Units from time to time through such firms. During the nine months ended September 30, 2016 , we sold approximately 1.6 million LP Units under the Equity Distribution Agreement and received $108.4 million in net proceeds after deducting commissions and other related expenses, including $1.1 million of compensation paid in aggregate to the agents under the Equity Distribution Agreement. Summary of Changes in Outstanding LP Units The following is a summary of changes in Buckeye's outstanding LP Units for the periods indicated (in thousands): Limited Partners LP Units outstanding at January 1, 2016 129,524 LP Units issued pursuant to the Option Plan (1) 6 LP Units issued pursuant to the LTIP (1) 212 Issuance of LP Units through Equity Distribution Agreements 1,568 LP Units outstanding at September 30, 2016 131,310 (1) The number of LP 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 $472.1 million ( $3.60 per LP Unit) and $442.0 million ( $3.45 per LP Unit) during the nine months ended September 30, 2016 and 2015 , respectively. On October 24, 2016 , we announced a quarterly distribution of $1.2250 per LP Unit that will be paid on November 22, 2016 to unitholders of record on November 15, 2016 . Based on the LP Units outstanding as of September 30, 2016 , estimated cash distributed to unitholders on November 22, 2016 will total $161.8 million .

EARNINGS PER UNIT

EARNINGS PER UNIT	9 Months Ended
	Sep. 30, 2016
Earnings Per Share [Abstract]
EARNINGS PER UNIT	13. 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 Nine Months Ended 2016 2015 2016 2015 Net income attributable to Buckeye Partners, L.P. $ 156,374 $ 100,040 $ 427,943 $ 303,231 Basic: Weighted average units outstanding - basic 131,113 128,329 130,439 127,722 Earnings per unit - basic $ 1.19 $ 0.78 $ 3.28 $ 2.37 Diluted: Weighted average units outstanding - basic 131,113 128,329 130,439 127,722 Dilutive effect of LP Unit options and LTIP awards granted 827 577 637 519 Weighted average units outstanding - diluted 131,940 128,906 131,076 128,241 Earnings per unit - diluted $ 1.19 $ 0.78 $ 3.26 $ 2.36

BUSINESS SEGMENTS

BUSINESS SEGMENTS	9 Months Ended
	Sep. 30, 2016
Segment Reporting [Abstract]
BUSINESS SEGMENTS	14. BUSINESS SEGMENTS We operate and report in three business segments: (i) Domestic Pipelines & Terminals; (ii) Global Marine Terminals; and (iii) Merchant Services. Each segment uses the same accounting policies as those used in the preparation of our unaudited condensed consolidated financial statements. All inter-segment revenues, operating income and assets have been eliminated. Domestic Pipelines & Terminals The Domestic Pipelines & Terminals segment receives liquid petroleum products from refineries, connecting pipelines, vessels, and bulk and marine terminals, transports those products to other locations for a fee, and provides bulk storage and terminal throughput services. The segment also has butane blending capabilities and provides crude oil services, including train loading/unloading, storage and throughput. This segment owns and operates pipeline systems and liquid petroleum products terminals in the continental United States, including five terminals owned by the Merchant Services segment but operated by the Domestic Pipelines & Terminals segment, and two underground propane storage caverns. Additionally, this segment provides turn-key operations and maintenance of third-party pipelines and performs pipeline construction management services typically for cost plus a fixed fee. Global Marine Terminals The Global Marine Terminals segment provides marine accessible bulk storage and blending services, rail and truck rack loading/unloading along with petroleum processing services in the East Coast and Gulf Coast regions of the United States and in the Caribbean. The segment has seven liquid petroleum product terminals located in The Bahamas, Puerto Rico and St. Lucia in the Caribbean, as well as the New York Harbor and Corpus Christi, Texas in the United States. Merchant Services The Merchant Services segment is a wholesale distributor of refined petroleum products in the United States and in the Caribbean. This segment recognizes revenues when products are delivered. The segment’s products include gasoline, natural gas liquids, ethanol, biodiesel and petroleum distillates such as heating oil, diesel fuel, kerosene and fuel oil. The segment owns five terminals, which are operated by the Domestic Pipelines & Terminals segment. The segment’s customers consist principally of product wholesalers as well as major commercial users of these refined petroleum products. The following table summarizes revenue by each segment for the periods indicated (in thousands): Three Months Ended Nine Months Ended 2016 2015 2016 2015 Revenue: Domestic Pipelines & Terminals $ 265,036 $ 236,080 $ 752,968 $ 704,305 Global Marine Terminals 170,072 127,161 509,653 372,735 Merchant Services 344,041 386,105 1,103,186 1,586,421 Intersegment (12,544 ) (20,962 ) (41,486 ) (50,194 ) Total revenue $ 766,605 $ 728,384 $ 2,324,321 $ 2,613,267 For the three and nine months ended September 30, 2016 and 2015 , no customers contributed 10% or more of consolidated revenue. The following table summarizes revenue for our continuing operations, by major geographic area, for the periods indicated (in thousands): Three Months Ended Nine Months Ended 2016 2015 2016 2015 Revenue: United States $ 683,850 $ 644,445 $ 2,072,893 $ 2,358,622 International 82,755 83,939 251,428 254,645 Total revenue $ 766,605 $ 728,384 $ 2,324,321 $ 2,613,267 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. The following tables present Adjusted EBITDA from continuing operations by segment and on a consolidated basis and a reconciliation of income from continuing operations to Adjusted EBITDA for the periods indicated (in thousands): Three Months Ended Nine Months Ended 2016 2015 2016 2015 Adjusted EBITDA from continuing operations: Domestic Pipelines & Terminals $ 152,785 $ 120,979 $ 423,245 $ 376,042 Global Marine Terminals 110,705 80,593 325,710 233,716 Merchant Services 8,159 2,592 23,909 13,797 Adjusted EBITDA from continuing operations $ 271,649 $ 204,164 $ 772,864 $ 623,555 Reconciliation of Income from continuing operations to Adjusted EBITDA from continuing operations: Income from continuing operations $ 160,270 $ 99,947 $ 439,746 $ 303,294 Less: Net (income) loss attributable to noncontrolling interests (3,896 ) 93 (11,803 ) 794 Income from continuing operations attributable to Buckeye Partners, L.P. 156,374 100,040 427,943 304,088 Add: Interest and debt expense 48,476 43,413 144,093 127,097 Income tax expense 308 240 896 720 Depreciation and amortization (1) 63,472 54,830 188,220 164,204 Non-cash unit-based compensation expense 8,853 6,597 22,912 17,578 Acquisition and transition expense (2) 309 82 479 2,942 Litigation contingency accrual (3) — 1,729 — 15,229 Less: Amortization of unfavorable storage contracts (4) (443 ) (2,767 ) (5,979 ) (8,303 ) Gains on property damage recoveries (5) (5,700 ) — (5,700 ) — Adjusted EBITDA from continuing operations $ 271,649 $ 204,164 $ 772,864 $ 623,555 (1) Includes 100% of the depreciation and amortization expense of $18.5 million and $12.2 million for Buckeye Texas for the three months ended September 30, 2016 and 2015 , respectively, and $52.5 million and $34.7 million for the nine months ended September 30, 2016 and 2015 , respectively. (2) Represents transaction costs, costs for transitional employees, and other employee and third-party costs related to the integration of acquired assets. (3) Represents reductions in revenue related to settlement of a Federal Energy Regulatory Commission proceeding. (4) Represents amortization of negative fair value allocated to certain unfavorable storage contracts acquired in connection with the BBH acquisition. (5) Represents recoveries of property damages caused by third parties, primarily related to an allision with a ship dock at our terminal located in Pennsauken, New Jersey.

SUPPLEMENTAL CASH FLOW INFORMAT

SUPPLEMENTAL CASH FLOW INFORMATION	9 Months Ended
	Sep. 30, 2016
Supplemental Cash Flow Elements [Abstract]
SUPPLEMENTAL CASH FLOW INFORMATION	15. SUPPLEMENTAL CASH FLOW INFORMATION Supplemental cash flows and non-cash transactions were as follows for the periods indicated (in thousands): Nine Months Ended 2016 2015 Cash paid for interest (net of capitalized interest) $ 141,140 $ 126,203 Cash paid for income taxes 670 1,562 Capitalized interest 3,142 16,897 Liabilities related to capital projects outstanding at September 30, 2016 and 2015 of $45.2 million and $103.7 million , respectively, are not included under “Capital expenditures” within the unaudited condensed consolidated statements of cash flows.

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	9 Months Ended
	Sep. 30, 2016
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	16. SUBSEQUENT EVENTS VTTI Acquisition In October 2016, we signed a definitive agreement to acquire an indirect 50% equity interest in VTTI B.V. (“VTTI”) for cash consideration of $1.15 billion (the “VTTI Acquisition”). VTTI is one of the largest independent global marine terminal businesses that, through its subsidiaries and partnership interests, owns and operates approximately 54 million barrels of petroleum products storage across 13 terminals located on five continents. These marine terminals are predominately located in key global energy hubs, including Northwest Europe, the United Arab Emirates and Singapore, and offer world-class storage and marine terminalling services for refined petroleum products, liquid petroleum gas and crude oil. The VTTI Acquisition is expected to close in January 2017, subject to regulatory approvals and customary closing conditions. Equity Offering In October 2016, we completed a public offering of 7.75 million LP Units pursuant to an effective shelf registration statement, which priced at $66.05 per unit. The underwriters also exercised an option to purchase 1.16 million additional LP Units, resulting in total gross proceeds of $588.7 million before deducting estimated underwriting fees and offering expenses of $7.7 million . We intend to use the net proceeds from this offering to fund a portion of the purchase price for the VTTI Acquisition. Pending such use, the net proceeds of this offering will be used to reduce the indebtedness outstanding under our Credit Facility and for general partnership purposes. Notes Offering In October 2016, we priced an offering of $600.0 million of senior unsecured 3.950% notes maturing on December 1, 2026 in an underwritten public offering at 99.644% of their principal amount. We expect the offering to close on November 7, 2016, subject to customary closing conditions. Total gross proceeds from this offering will be $597.9 million before deducting estimated underwriting fees, expenses and debt issuance costs of $5.3 million . We intend to use the net proceeds from this offering to fund a portion of the purchase price for the VTTI Acquisition. Hurricane Matthew In October 2016, Hurricane Matthew made landfall in the Bahamas and the southeastern United States. Our domestic operations experienced no property damages or product releases as a result of the storm. We are currently evaluating the impact of the storm on our BBH terminalling facility, which is located along the Northwest Providence Channel of Grand Bahama Island. Based on information currently available, we estimate the range of costs expected to be incurred as a result of Hurricane Matthew to be between $20 million to $30 million , comprised of both operating and capital expenditures. We intend to seek recovery from our insurers for property damage incurred above our self-insured retentions; however, no assurances can be given relative to the timing or amount of such recoveries.

ORGANIZATION AND BASIS OF PRE24

ORGANIZATION AND BASIS OF PRESENTATION (Policies)	9 Months Ended
	Sep. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	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 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 ” or “ Buckeye ” mean Buckeye Partners, L.P. and, where the context requires, includes our subsidiaries. Buckeye owns and operates a diversified network of integrated assets providing midstream logistic solutions, primarily consisting of the transportation, storage and marketing of liquid petroleum products. We are one of the largest independent liquid petroleum products pipeline operators in the United States in terms of volumes delivered and miles of pipeline. In addition, we own and operate one of the largest networks of active products terminals across our portfolio of pipelines, inland terminals and marine terminals located primarily in the East Coast and Gulf Coast regions of the United States and in the Caribbean. Our network of marine terminals enables us to facilitate global flows of crude oil and refined petroleum products, offering our customers connectivity between supply areas and market centers through some of the world’s most important bulk storage and blending hubs. Our flagship marine terminal in The Bahamas, Buckeye Bahamas Hub Limited (“BBH”), formerly known as Bahamas Oil Refining Company International Limited (“BORCO”), is one of the largest marine crude oil and refined petroleum products storage facilities in the world and provides an array of logistics and blending services for the global flow of petroleum products. Our expansion into the Gulf Coast has added another regional hub, Buckeye Texas Partners LLC (“Buckeye Texas”), with world-class marine terminalling, storage and processing capabilities. We are also a wholesale distributor of refined petroleum products in certain areas served by our pipelines and terminals.
Basis of Presentation and Principles of Consolidation	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 and the rules of the U.S. Securities and Exchange Commission. 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 unaudited condensed 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, 2015 .
Recent Accounting Developments	Recent Accounting Developments Statement of Cash Flows . In August 2016, the Financial Accounting Standards Board (“FASB”) issued guidance to address how certain cash receipts and cash payments are presented and classified in the statement of cash flows, with the objective of reducing existing diversity in practice with respect to these items. The guidance must be applied retrospectively, and it is effective for annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods, with early adoption permitted. We are currently evaluating the impact the adoption of this guidance will have on our consolidated financial statements. Equity-Based Compensation . In March 2016, the FASB issued guidance to simplify several aspects of the accounting for employee equity-based payment transactions, including the accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as classification in the statement of cash flows and classification of awards as liabilities or equity. The guidance is effective for annual reporting periods beginning after December 15, 2016 and interim periods within those annual periods, with early adoption permitted. Amendments related to the timing of when excess tax benefits are recognized, statutory withholding requirements and forfeitures should be applied using a modified retrospective transition method by means of a cumulative-effect adjustment to equity as of the beginning of the period in which the guidance is adopted. Amendments related to the presentation of employee taxes paid on the statement of cash flows should be applied retrospectively. Amendments requiring recognition of excess tax benefits and tax deficiencies in the income statement should be applied prospectively. Amendments related to the presentation of excess tax benefits on the statement of cash flows may be applied using either a prospective transition method or a retrospective transition method. We are currently evaluating the impact the adoption of this guidance will have on our consolidated financial statements. Leases . In February 2016, the FASB issued guidance requiring lessees to recognize assets and liabilities for leases with lease terms greater than twelve months in the statement of financial position. This update also requires enhanced disclosures regarding the amount, timing and uncertainty of cash flows arising from leases. The guidance must be applied using a modified retrospective approach and is effective for annual reporting periods beginning after December 15, 2018 and interim periods within those annual periods, with early adoption permitted. We are currently evaluating the impact the adoption of this guidance will have on our consolidated financial statements.

ACQUISITIONS (Tables)

ACQUISITIONS (Tables)	9 Months Ended
	Sep. 30, 2016
Indianola Pipeline
Business Acquisition [Line Items]
Schedule of purchase price allocated to tangible and intangible assets acquired and liabilities assumed	The purchase price has been allocated to tangible and intangible assets acquired and liabilities assumed as follows (in thousands): Inventories $ 1,299 Property, plant and equipment 20,239 Goodwill 4,403 Allocated purchase price $ 25,941
Pennsauken Pipeline
Business Acquisition [Line Items]
Schedule of purchase price allocated to tangible and intangible assets acquired and liabilities assumed	The purchase price has been allocated to tangible and intangible assets acquired and liabilities assumed as follows (in thousands): Property, plant and equipment $ 7,159 Goodwill 500 Environmental liabilities (2,372 ) Allocated purchase price $ 5,287
ExxonMobil Pipeline
Business Acquisition [Line Items]
Schedule of purchase price allocated to tangible and intangible assets acquired and liabilities assumed	The purchase price has been allocated to tangible and intangible assets acquired and liabilities assumed as follows (in thousands): Property, plant and equipment $ 4,040 Goodwill 8,165 Asset retirement obligation (4,200 ) Environmental liabilities (293 ) Allocated purchase price $ 7,712

INVENTORIES (Tables)

INVENTORIES (Tables)	9 Months Ended
	Sep. 30, 2016
Inventory Disclosure [Abstract]
Schedule of inventory	Our inventory amounts were as follows at the dates indicated (in thousands): September 30, December 31, Liquid petroleum products (1) $ 275,853 $ 174,232 Materials and supplies 19,454 18,760 Total inventories $ 295,307 $ 192,992 (1) Ending inventory was 178.8 million and 153.3 million gallons of liquid petroleum products as of September 30, 2016 and December 31, 2015 , respectively.

PREPAID AND OTHER CURRENT ASS27

PREPAID AND OTHER CURRENT ASSETS (Tables)	9 Months Ended
	Sep. 30, 2016
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Schedule of prepaid and other current assets	Prepaid and other current assets consist of the following at the dates indicated (in thousands): September 30, December 31, Prepaid insurance $ 13,050 $ 12,779 Margin deposits 35,950 — Unbilled revenue 2,383 4,047 Prepaid taxes 9,396 4,842 Escrow deposits 10 21,360 Other 10,364 5,043 Total prepaid and other current assets $ 71,153 $ 48,071

EQUITY INVESTMENTS (Tables)

EQUITY INVESTMENTS (Tables)	9 Months Ended
	Sep. 30, 2016
Equity Method Investments and Joint Ventures [Abstract]
Earnings (losses) from equity investments	The following table presents earnings (losses) from equity investments for the periods indicated (in thousands): Three Months Ended Nine Months Ended 2016 2015 2016 2015 West Shore Pipe Line Company $ 1,784 $ 2,033 $ 5,680 $ 6,209 Muskegon Pipeline LLC 544 (2,761 ) 1,340 (3,345 ) Transport4, LLC 204 183 577 456 South Portland Terminal LLC 369 515 862 1,230 Total earnings (loss) from equity investments $ 2,901 $ (30 ) $ 8,459 $ 4,550
Summary of combined income statement data for equity method investments	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 Nine Months Ended 2016 2015 2016 2015 Revenue $ 22,831 $ 24,440 $ 65,877 $ 68,786 Costs and expenses (10,026 ) (16,642 ) (30,466 ) (43,256 ) Non-operating expenses (4,142 ) (4,033 ) (11,425 ) (11,690 ) Net income $ 8,663 $ 3,765 $ 23,986 $ 13,840

DERIVATIVE INSTRUMENTS AND HE29

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables)	9 Months Ended
	Sep. 30, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Summary of commodity derivative instruments outstanding	The following table summarizes our commodity derivative instruments outstanding at September 30, 2016 (amounts in thousands of gallons): Volume (1) Accounting Derivative Purpose Current Long-Term Treatment Derivatives NOT designated as hedging instruments: Physical fixed price derivative contracts 8,504 1,073 Mark-to-market Physical index derivative contracts 31,274 — Mark-to-market Futures contracts for refined petroleum products 24,819 16,926 Mark-to-market Derivatives designated as hedging instruments: Physical fixed price derivative contracts 1,176 — Fair Value Hedge Futures contracts for refined petroleum products 163,800 — Fair Value Hedge (1) Volume represents absolute value of net notional volume position.
Fair value of each classification of derivative instrument and their location in the unaudited consolidated balance sheet	The following table sets forth the fair value of each classification of derivative instruments and the locations of the derivative instruments on our unaudited condensed consolidated balance sheets at the dates indicated (in thousands): September 30, 2016 Derivatives NOT Designated as Hedging Instruments Derivatives Designated as Hedging Instruments Derivative Carrying Value Netting Balance Sheet Adjustment (1) Net Total Physical fixed price derivative contracts $ 4,046 $ 67 $ 4,113 $ (505 ) $ 3,608 Physical index derivative contracts 67 — 67 (1 ) 66 Futures contracts for refined products 20,655 1,005 21,660 (21,660 ) — Total current derivative assets 24,768 1,072 25,840 (22,166 ) 3,674 Physical fixed price derivative contracts 293 — 293 (8 ) 285 Futures contracts for refined products 84 — 84 (84 ) — Interest rates derivatives — 1,052 1,052 — 1,052 Total non-current derivative assets 377 1,052 1,429 (92 ) 1,337 Physical fixed price derivative contracts (2,673 ) — (2,673 ) 505 (2,168 ) Physical index derivative contracts (41 ) — (41 ) 1 (40 ) Futures contracts for refined products (29,231 ) (12,257 ) (41,488 ) 21,660 (19,828 ) Total current derivative liabilities (31,945 ) (12,257 ) (44,202 ) 22,166 (22,036 ) Physical fixed price derivative contracts (27 ) — (27 ) 8 (19 ) Futures contracts for refined products (4,042 ) — (4,042 ) 84 (3,958 ) Total non-current derivative liabilities (4,069 ) — (4,069 ) 92 (3,977 ) Net derivative liabilities $ (10,869 ) $ (10,133 ) $ (21,002 ) $ — $ (21,002 ) (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, 2015 Derivatives NOT Designated as Hedging Instruments Derivatives Designated as Hedging Instruments Derivative Carrying Value Netting Balance Sheet Adjustment (1) Net Total Physical fixed price derivative contracts $ 26,698 $ — $ 26,698 $ (79 ) $ 26,619 Physical index derivative contracts 87 — 87 (62 ) 25 Futures contracts for refined products 136,131 36,834 172,965 (121,324 ) 51,641 Total current derivative assets 162,916 36,834 199,750 (121,465 ) 78,285 Physical fixed price derivative contracts 1,057 — 1,057 — 1,057 Total non-current derivative assets 1,057 — 1,057 — 1,057 Physical fixed price derivative contracts (535 ) — (535 ) 79 (456 ) Physical index derivative contracts (116 ) — (116 ) 62 (54 ) Futures contracts for refined products (119,506 ) (1,818 ) (121,324 ) 121,324 — Total current derivative liabilities (120,157 ) (1,818 ) (121,975 ) 121,465 (510 ) Futures contracts for refined products (703 ) — (703 ) — (703 ) Total non-current derivative liabilities (703 ) — (703 ) — (703 ) Net derivative assets $ 43,113 $ 35,016 $ 78,129 $ — $ 78,129 (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.
Gains and losses on derivative instruments recognized in income	The gains and losses on our derivative instruments recognized in income were as follows for the periods indicated (in thousands): Three Months Ended Nine Months Ended Location 2016 2015 2016 2015 Derivatives NOT designated as hedging instruments: Physical fixed price derivative contracts Product sales $ 301 $ 15,731 $ (7,263 ) $ 19,660 Physical index derivative contracts Product sales 142 (299 ) 130 (309 ) Physical fixed price derivative contracts Cost of product sales 479 3,600 7,965 10,191 Physical index derivative contracts Cost of product sales 30 (288 ) 193 (224 ) Futures contracts for refined products Cost of product sales (307 ) (10,992 ) 4,326 2,591 Derivatives designated as fair value hedging instruments: Futures contracts for refined products Cost of product sales $ (635 ) $ 54,514 $ (27,590 ) $ 21,959 Physical inventory - hedged items Cost of product sales 3,620 (55,424 ) 43,627 (34,848 ) Ineffectiveness excluding the time value component on fair value hedging instruments: Fair value hedge ineffectiveness (excluding time value) Cost of product sales $ (4,262 ) $ 2,626 $ (4,275 ) $ 2,476 Time value excluded from hedge assessment Cost of product sales 7,247 (3,536 ) 20,312 (15,365 ) Net gain (loss) in income $ 2,985 $ (910 ) $ 16,037 $ (12,889 )
Losses reclassified from AOCI to income (effective portion)	The change in value recognized in other comprehensive income (“OCI”) and the losses reclassified from AOCI to income attributable to our derivative instruments designated as cash flow hedges were as follows for the periods indicated (in thousands): Gain Recognized in OCI on Derivatives for the Three Months Ended Nine Months Ended 2016 2015 2016 2015 Derivatives designated as cash flow hedging instruments: Interest rate contracts $ 1,052 $ — $ 1,052 $ — Commodity derivatives — 11,168 — 7,311 Total $ 1,052 $ 11,168 $ 1,052 $ 7,311 (Loss) Gain Reclassified from AOCI to Income (Effective Portion) for the Three Months Ended Nine Months Ended Location 2016 2015 2016 2015 Derivatives designated as cash flow hedging instruments: Interest rate contracts Interest and debt expense $ (3,037 ) $ (3,037 ) $ (9,112 ) $ (9,113 ) Commodity derivatives Product Sales — — 1,266 — Total $ (3,037 ) $ (3,037 ) $ (7,846 ) $ (9,113 )

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	9 Months Ended
	Sep. 30, 2016
Fair Value Disclosures [Abstract]
Financial assets and liabilities measured at fair value on a recurring basis	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): September 30, 2016 December 31, 2015 Level 1 Level 2 Level 1 Level 2 Financial assets: Physical fixed price derivative contracts $ — $ 3,893 $ — $ 27,676 Physical index derivative contracts — 66 — 25 Futures contracts for refined products — — 51,641 — Interest rate derivatives — 1,052 — — Financial liabilities: Physical fixed price derivative contracts — (2,187 ) — (456 ) Physical index derivative contracts — (40 ) — (54 ) Futures contracts for refined products (23,786 ) — (703 ) — Fair value $ (23,786 ) $ 2,784 $ 50,938 $ 27,191
Carrying value and fair value using level 2 inputs of debt	The carrying value and fair value, using Level 2 input values, of our debt were as follows at the dates indicated (in thousands): September 30, 2016 December 31, 2015 Carrying Amount Fair Value Carrying Amount Fair Value Fixed-rate debt $ 3,623,960 $ 3,795,826 $ 3,371,824 $ 3,057,945 Variable-rate debt 421,240 421,240 472,488 472,488 Total debt $ 4,045,200 $ 4,217,066 $ 3,844,312 $ 3,530,433

PENSIONS AND OTHER POSTRETIRE31

PENSIONS AND OTHER POSTRETIREMENT BENEFITS (Tables)	9 Months Ended
	Sep. 30, 2016
Compensation and Retirement Disclosure [Abstract]
Components of net periodic benefit cost for RIGP and Retiree Medical Plan	The components of the net periodic benefit cost for the RIGP and Retiree Medical Plan were as follows for the three and nine months ended September 30, 2016 and 2015 (in thousands): RIGP Retiree Medical Plan Three Months Ended Three Months Ended 2016 2015 2016 2015 Service cost $ (9 ) $ 3 $ 81 $ 92 Interest cost 106 137 327 333 Expected return on plan assets (64 ) (84 ) — — Amortization of unrecognized losses 130 211 — 50 Actuarial loss due to settlements 122 451 — — Net periodic benefit cost $ 285 $ 718 $ 408 $ 475 RIGP Retiree Medical Plan Nine Months Ended Nine Months Ended 2016 2015 2016 2015 Service cost $ (26 ) $ 9 $ 242 $ 274 Interest cost 316 413 982 1,000 Expected return on plan assets (192 ) (251 ) — — Amortization of unrecognized losses 391 632 — 149 Actuarial loss due to settlements 365 451 — — Net periodic benefit cost $ 854 $ 1,254 $ 1,224 $ 1,423

UNIT-BASED COMPENSATION PLANS (

UNIT-BASED COMPENSATION PLANS (Tables)	9 Months Ended
	Sep. 30, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Awards activity under the LTIP	The following table sets forth the LTIP activity for the periods indicated (in thousands, except per unit amounts): Number of LP Units Weighted Average Grant Date Fair Value per LP Unit Unvested at January 1, 2016 1,011 $ 68.20 Granted 637 53.48 Vested (267 ) 55.28 Forfeited (8 ) 64.53 Unvested at September 30, 2016 1,373 $ 64.00
Summary of changes in options outstanding	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): Number of LP Units Weighted Average Strike Price per LP Unit Weighted Average Remaining Contractual Term (in years) Aggregate Intrinsic Value (1) Outstanding at January 1, 2016 17 $ 48.71 0.9 $ 300 Exercised (6 ) 47.17 Forfeited, cancelled or expired (1 ) 44.73 Outstanding at September 30, 2016 10 50.36 0.4 $ 203 Exercisable at September 30, 2016 10 $ 50.36 0.4 $ 203 (1) Aggregate intrinsic value reflects fully vested LP Unit options at the date indicated. Intrinsic value is determined by calculating the difference between our closing LP Unit price on the last trading day in September 2016 and the exercise price, multiplied by the number of exercisable, in-the-money options.

PARTNERS' CAPITAL AND DISTRIB33

PARTNERS' CAPITAL AND DISTRIBUTIONS (Tables)	9 Months Ended
	Sep. 30, 2016
Equity [Abstract]
Summary of changes in LP units outstanding	The following is a summary of changes in Buckeye's outstanding LP Units for the periods indicated (in thousands): Limited Partners LP Units outstanding at January 1, 2016 129,524 LP Units issued pursuant to the Option Plan (1) 6 LP Units issued pursuant to the LTIP (1) 212 Issuance of LP Units through Equity Distribution Agreements 1,568 LP Units outstanding at September 30, 2016 131,310 (1) The number of LP Units issued represents issuance net of tax withholding.

EARNINGS PER UNIT (Tables)

EARNINGS PER UNIT (Tables)	9 Months Ended
	Sep. 30, 2016
Earnings Per Share [Abstract]
Reconciliation of weighted average units outstanding used in computing basic and diluted 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 Nine Months Ended 2016 2015 2016 2015 Net income attributable to Buckeye Partners, L.P. $ 156,374 $ 100,040 $ 427,943 $ 303,231 Basic: Weighted average units outstanding - basic 131,113 128,329 130,439 127,722 Earnings per unit - basic $ 1.19 $ 0.78 $ 3.28 $ 2.37 Diluted: Weighted average units outstanding - basic 131,113 128,329 130,439 127,722 Dilutive effect of LP Unit options and LTIP awards granted 827 577 637 519 Weighted average units outstanding - diluted 131,940 128,906 131,076 128,241 Earnings per unit - diluted $ 1.19 $ 0.78 $ 3.26 $ 2.36

BUSINESS SEGMENTS (Tables)

BUSINESS SEGMENTS (Tables)	9 Months Ended
	Sep. 30, 2016
Segment Reporting [Abstract]
Summary of revenue by each segment	The following table summarizes revenue by each segment for the periods indicated (in thousands): Three Months Ended Nine Months Ended 2016 2015 2016 2015 Revenue: Domestic Pipelines & Terminals $ 265,036 $ 236,080 $ 752,968 $ 704,305 Global Marine Terminals 170,072 127,161 509,653 372,735 Merchant Services 344,041 386,105 1,103,186 1,586,421 Intersegment (12,544 ) (20,962 ) (41,486 ) (50,194 ) Total revenue $ 766,605 $ 728,384 $ 2,324,321 $ 2,613,267
Summary of revenue for continuing operations by major geographic area	The following table summarizes revenue for our continuing operations, by major geographic area, for the periods indicated (in thousands): Three Months Ended Nine Months Ended 2016 2015 2016 2015 Revenue: United States $ 683,850 $ 644,445 $ 2,072,893 $ 2,358,622 International 82,755 83,939 251,428 254,645 Total revenue $ 766,605 $ 728,384 $ 2,324,321 $ 2,613,267
Adjusted EBITDA from continuing operations by segment and reconciliation of income from continuing operations to Adjusted EBITDA	The following tables present Adjusted EBITDA from continuing operations by segment and on a consolidated basis and a reconciliation of income from continuing operations to Adjusted EBITDA for the periods indicated (in thousands): Three Months Ended Nine Months Ended 2016 2015 2016 2015 Adjusted EBITDA from continuing operations: Domestic Pipelines & Terminals $ 152,785 $ 120,979 $ 423,245 $ 376,042 Global Marine Terminals 110,705 80,593 325,710 233,716 Merchant Services 8,159 2,592 23,909 13,797 Adjusted EBITDA from continuing operations $ 271,649 $ 204,164 $ 772,864 $ 623,555 Reconciliation of Income from continuing operations to Adjusted EBITDA from continuing operations: Income from continuing operations $ 160,270 $ 99,947 $ 439,746 $ 303,294 Less: Net (income) loss attributable to noncontrolling interests (3,896 ) 93 (11,803 ) 794 Income from continuing operations attributable to Buckeye Partners, L.P. 156,374 100,040 427,943 304,088 Add: Interest and debt expense 48,476 43,413 144,093 127,097 Income tax expense 308 240 896 720 Depreciation and amortization (1) 63,472 54,830 188,220 164,204 Non-cash unit-based compensation expense 8,853 6,597 22,912 17,578 Acquisition and transition expense (2) 309 82 479 2,942 Litigation contingency accrual (3) — 1,729 — 15,229 Less: Amortization of unfavorable storage contracts (4) (443 ) (2,767 ) (5,979 ) (8,303 ) Gains on property damage recoveries (5) (5,700 ) — (5,700 ) — Adjusted EBITDA from continuing operations $ 271,649 $ 204,164 $ 772,864 $ 623,555 (1) Includes 100% of the depreciation and amortization expense of $18.5 million and $12.2 million for Buckeye Texas for the three months ended September 30, 2016 and 2015 , respectively, and $52.5 million and $34.7 million for the nine months ended September 30, 2016 and 2015 , respectively. (2) Represents transaction costs, costs for transitional employees, and other employee and third-party costs related to the integration of acquired assets. (3) Represents reductions in revenue related to settlement of a Federal Energy Regulatory Commission proceeding. (4) Represents amortization of negative fair value allocated to certain unfavorable storage contracts acquired in connection with the BBH acquisition. (5) Represents recoveries of property damages caused by third parties, primarily related to an allision with a ship dock at our terminal located in Pennsauken, New Jersey.

SUPPLEMENTAL CASH FLOW INFORM36

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)	9 Months Ended
	Sep. 30, 2016
Supplemental Cash Flow Elements [Abstract]
Supplemental cash flows and non-cash transactions	Supplemental cash flows and non-cash transactions were as follows for the periods indicated (in thousands): Nine Months Ended 2016 2015 Cash paid for interest (net of capitalized interest) $ 141,140 $ 126,203 Cash paid for income taxes 670 1,562 Capitalized interest 3,142 16,897

ACQUISITIONS - Narrative (Detai

ACQUISITIONS - Narrative (Details) - USD ($) $ in Millions	1 Months Ended		3 Months Ended	9 Months Ended
	Aug. 31, 2016	Dec. 31, 2015	May 31, 2015	Sep. 30, 2016
Indianola Pipeline
Business Acquisition [Line Items]
Consideration for business acquisition	$ 25.9
Pennsauken Pipeline
Business Acquisition [Line Items]
Consideration for business acquisition		$ 5.3
Increase to property, plant and equipment				$ 1.9
Decrease to goodwill				$ 1.9
ExxonMobil Pipeline
Business Acquisition [Line Items]
Consideration for business acquisition			$ 7.7

ACQUISITIONS - Purchase Price A

ACQUISITIONS - Purchase Price Allocation to Tangible and Intangible Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Aug. 31, 2016	Dec. 31, 2015	May 31, 2015
Business Acquisition [Line Items]
Goodwill	$ 1,001,190		$ 998,748
Indianola Pipeline
Business Acquisition [Line Items]
Inventories		$ 1,299
Property, plant and equipment		20,239
Goodwill		4,403
Allocated purchase price		$ 25,941
Pennsauken Pipeline
Business Acquisition [Line Items]
Property, plant and equipment			7,159
Goodwill			500
Environmental liabilities			(2,372)
Allocated purchase price			$ 5,287
ExxonMobil Pipeline
Business Acquisition [Line Items]
Property, plant and equipment				$ 4,040
Goodwill				8,165
Asset retirement obligation				(4,200)
Environmental liabilities				(293)
Allocated purchase price				$ 7,712

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - Environmental Contingencies (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Commitments and Contingencies Disclosure
Operating expenses, net of insurance recoveries related to environmental liabilities	$ 0	$ 1,729	$ 0	$ 15,229
Environmental remediation unrelated to claims and legal proceedings
Commitments and Contingencies Disclosure
Operating expenses, net of insurance recoveries related to environmental liabilities	1,800	$ 1,700	6,000	$ 4,500
Environmental remediation liabilities	46,300		46,300		$ 48,000
Receivables related to environmental remediation expenditures covered by insurance or third party claims	$ 7,000		$ 7,000		$ 10,900

INVENTORIES (Details)

INVENTORIES (Details) $ in Thousands, gal in Millions	Sep. 30, 2016USD ($)gal	Dec. 31, 2015USD ($)gal
Inventory Disclosure [Abstract]
Liquid petroleum products	$ 275,853	$ 174,232
Materials and supplies	19,454	18,760
Total inventories	$ 295,307	$ 192,992
Refined petroleum products (in gallons) | gal	178.8	153.3
Percentage of hedged refined petroleum products inventory	92.00%	89.00%

PREPAID AND OTHER CURRENT ASS41

PREPAID AND OTHER CURRENT ASSETS (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Prepaid insurance	$ 13,050	$ 12,779
Margin deposits	35,950	0
Unbilled revenue	2,383	4,047
Prepaid taxes	9,396	4,842
Escrow deposits	10	21,360
Other	10,364	5,043
Total prepaid and other current assets	$ 71,153	$ 48,071

EQUITY INVESTMENTS - Equity Inv

EQUITY INVESTMENTS - Equity Investments (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Equity investments
Total earnings (loss) from equity investments	$ 2,901	$ (30)	$ 8,459	$ 4,550
West Shore Pipe Line Company
Equity investments
Total earnings (loss) from equity investments	1,784	2,033	5,680	6,209
Muskegon Pipeline LLC
Equity investments
Total earnings (loss) from equity investments	544	(2,761)	1,340	(3,345)
Transport4, LLC
Equity investments
Total earnings (loss) from equity investments	204	183	577	456
South Portland Terminal LLC
Equity investments
Total earnings (loss) from equity investments	$ 369	$ 515	$ 862	$ 1,230

EQUITY INVESTMENTS - Income Fro

EQUITY INVESTMENTS - Income From Equity Method Investments (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Equity Method Investments and Joint Ventures [Abstract]
Representation of investee financial information in the summarized equity method investments (as a percent)			100.00%
INCOME STATEMENT DATA:
Revenue	$ 22,831	$ 24,440	$ 65,877	$ 68,786
Costs and expenses	(10,026)	(16,642)	(30,466)	(43,256)
Non-operating expenses	(4,142)	(4,033)	(11,425)	(11,690)
Net income	$ 8,663	$ 3,765	$ 23,986	$ 13,840

LONG-TERM DEBT (Details)

LONG-TERM DEBT (Details)	1 Months Ended
	Sep. 30, 2016USD ($)extension	Sep. 29, 2016USD ($)
5.125% Due July 2017 | Notes Payable
Debt instrument
Face amount	$ 125,000,000
Interest rate percentage	5.125%
Revolving Credit Facility | Line of Credit
Debt instrument
Maximum borrowing capacity	$ 1,400,000,000
Extension term (in years)	1 year
Unamortized deferred financing costs	$ 3,400,000
Debt issuance costs	700,000
Additional borrowing capacity	1,078,800,000
Prior Revolving Credit Facility | Line of Credit
Debt instrument
Amount of maximum borrowing capacity extended		$ 1,500,000,000
Term Loan | Line of Credit
Debt instrument
Amount of maximum borrowing capacity extended	$ 250,000,000
Extension term (in years)	1 year
Debt issuance costs	$ 500,000
Number of extension periods | extension	2
Maximum funded debt ratio	5
Maximum funded debt ratio subject to future acquisitions	5.5
Debt outstanding	$ 250,000,000
Term Loan | Minimum | LIBOR | Line of Credit
Debt instrument
Basis spread of variable interest rate	1.00%
Term Loan | Minimum | Base Rate | Line of Credit
Debt instrument
Basis spread of variable interest rate	0.00%
Term Loan | Maximum | LIBOR | Line of Credit
Debt instrument
Basis spread of variable interest rate	1.60%
Term Loan | Maximum | Base Rate | Line of Credit
Debt instrument
Basis spread of variable interest rate	0.60%

DERIVATIVE INSTRUMENTS AND HE45

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Additional Information (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2016USD ($)instrument	Sep. 30, 2015USD ($)	Sep. 30, 2016USD ($)instrument	Sep. 30, 2015USD ($)
Derivative [Line Items]
Unrealized gains on derivative instruments	$ 1,052,000	$ 11,168,000	$ 1,052,000	$ 7,311,000
Interest Rate Swap Entered Into In Anticipation of Debt Due January 2018
Derivative [Line Items]
Number of instruments entered into | instrument	4		4
Notional amount	$ 200,000,000		$ 200,000,000
Interest Rate Swap Entered Into In Anticipation of Debt Due November 2018
Derivative [Line Items]
Number of instruments entered into | instrument	6		6
Notional amount	$ 300,000,000		$ 300,000,000
Interest rate contracts
Derivative [Line Items]
Cash flow hedge loss to be reclassified within twelve months			12,200,000
6.050% Notes Due January 2018 | Notes Payable
Derivative [Line Items]
Face amount	$ 300,000,000		$ 300,000,000
Interest rate percentage	6.05%		6.05%
2.650% Notes Due November 2018 | Notes Payable
Derivative [Line Items]
Face amount	$ 400,000,000		$ 400,000,000
Interest rate percentage	2.65%		2.65%

DERIVATIVE INSTRUMENTS AND HE46

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Commodity Derivative Instruments (Details) gal in Thousands	9 Months Ended
	Sep. 30, 2016gal
Derivatives NOT Designated as Hedging Instruments | Physical fixed price derivative contracts | Current
Derivative Instruments And Hedging Activities
Volume (in gallons)	8,504
Derivatives NOT Designated as Hedging Instruments | Physical fixed price derivative contracts | Long-Term
Derivative Instruments And Hedging Activities
Volume (in gallons)	1,073
Derivatives NOT Designated as Hedging Instruments | Physical index derivative contracts | Current
Derivative Instruments And Hedging Activities
Volume (in gallons)	31,274
Derivatives NOT Designated as Hedging Instruments | Physical index derivative contracts | Long-Term
Derivative Instruments And Hedging Activities
Volume (in gallons)	0
Derivatives NOT Designated as Hedging Instruments | Futures contracts for refined petroleum products | Current
Derivative Instruments And Hedging Activities
Volume (in gallons)	24,819
Derivatives NOT Designated as Hedging Instruments | Futures contracts for refined petroleum products | Long-Term
Derivative Instruments And Hedging Activities
Volume (in gallons)	16,926
Derivatives Designated as Hedging Instruments | Fair Value Hedge | Physical fixed price derivative contracts | Current
Derivative Instruments And Hedging Activities
Volume (in gallons)	1,176
Derivatives Designated as Hedging Instruments | Fair Value Hedge | Physical fixed price derivative contracts | Long-Term
Derivative Instruments And Hedging Activities
Volume (in gallons)	0
Derivatives Designated as Hedging Instruments | Fair Value Hedge | Futures contracts for refined petroleum products | Current
Derivative Instruments And Hedging Activities
Volume (in gallons)	163,800
Derivatives Designated as Hedging Instruments | Fair Value Hedge | Futures contracts for refined petroleum products | Long-Term
Derivative Instruments And Hedging Activities
Volume (in gallons)	0

DERIVATIVE INSTRUMENTS AND HE47

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Fair Value of Each Classification of Derivative Instrument (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Derivatives, Fair Value
Fair value	$ (21,002)	$ 78,129
Netting balance sheet adjustment	0	0
Net Total
Derivatives, Fair Value
Fair value	(21,002)	78,129
Derivatives NOT Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	(10,869)	43,113
Derivatives Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	(10,133)	35,016
Total current derivative assets
Derivatives, Fair Value
Fair value	25,840	199,750
Netting balance sheet adjustment	(22,166)	(121,465)
Total current derivative assets | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	4,113	26,698
Netting balance sheet adjustment	(505)	(79)
Total current derivative assets | Physical index derivative contracts
Derivatives, Fair Value
Fair value	67	87
Netting balance sheet adjustment	(1)	(62)
Total current derivative assets | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value	21,660	172,965
Netting balance sheet adjustment	(21,660)	(121,324)
Total current derivative assets | Net Total
Derivatives, Fair Value
Fair value	3,674	78,285
Total current derivative assets | Net Total | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	3,608	26,619
Total current derivative assets | Net Total | Physical index derivative contracts
Derivatives, Fair Value
Fair value	66	25
Total current derivative assets | Net Total | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value	0	51,641
Total current derivative assets | Derivatives NOT Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	24,768	162,916
Total current derivative assets | Derivatives NOT Designated as Hedging Instruments | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	4,046	26,698
Total current derivative assets | Derivatives NOT Designated as Hedging Instruments | Physical index derivative contracts
Derivatives, Fair Value
Fair value	67	87
Total current derivative assets | Derivatives NOT Designated as Hedging Instruments | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value	20,655	136,131
Total current derivative assets | Derivatives Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	1,072	36,834
Total current derivative assets | Derivatives Designated as Hedging Instruments | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	67	0
Total current derivative assets | Derivatives Designated as Hedging Instruments | Physical index derivative contracts
Derivatives, Fair Value
Fair value	0	0
Total current derivative assets | Derivatives Designated as Hedging Instruments | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value	1,005	36,834
Total non-current derivative assets
Derivatives, Fair Value
Fair value	1,429	1,057
Netting balance sheet adjustment	(92)	0
Total non-current derivative assets | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	293	1,057
Netting balance sheet adjustment	(8)	0
Total non-current derivative assets | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value	84
Netting balance sheet adjustment	(84)
Total non-current derivative assets | Interest rate derivatives
Derivatives, Fair Value
Fair value	1,052
Netting balance sheet adjustment	0
Total non-current derivative assets | Net Total
Derivatives, Fair Value
Fair value	1,337	1,057
Total non-current derivative assets | Net Total | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	285	1,057
Total non-current derivative assets | Net Total | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value	0
Total non-current derivative assets | Net Total | Interest rate derivatives
Derivatives, Fair Value
Fair value	1,052
Total non-current derivative assets | Derivatives NOT Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	377	1,057
Total non-current derivative assets | Derivatives NOT Designated as Hedging Instruments | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	293	1,057
Total non-current derivative assets | Derivatives NOT Designated as Hedging Instruments | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value	84
Total non-current derivative assets | Derivatives NOT Designated as Hedging Instruments | Interest rate derivatives
Derivatives, Fair Value
Fair value	0
Total non-current derivative assets | Derivatives Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	1,052	0
Total non-current derivative assets | Derivatives Designated as Hedging Instruments | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	0	0
Total non-current derivative assets | Derivatives Designated as Hedging Instruments | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value	0
Total non-current derivative assets | Derivatives Designated as Hedging Instruments | Interest rate derivatives
Derivatives, Fair Value
Fair value	1,052
Total current derivative liabilities
Derivatives, Fair Value
Fair value	(44,202)	(121,975)
Netting balance sheet adjustment	22,166	121,465
Total current derivative liabilities | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	(2,673)	(535)
Netting balance sheet adjustment	505	79
Total current derivative liabilities | Physical index derivative contracts
Derivatives, Fair Value
Fair value	(41)	(116)
Netting balance sheet adjustment	1	62
Total current derivative liabilities | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value	(41,488)	(121,324)
Netting balance sheet adjustment	21,660	121,324
Total current derivative liabilities | Net Total
Derivatives, Fair Value
Fair value	(22,036)	(510)
Total current derivative liabilities | Net Total | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	(2,168)	(456)
Total current derivative liabilities | Net Total | Physical index derivative contracts
Derivatives, Fair Value
Fair value	(40)	(54)
Total current derivative liabilities | Net Total | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value	(19,828)	0
Total current derivative liabilities | Derivatives NOT Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	(31,945)	(120,157)
Total current derivative liabilities | Derivatives NOT Designated as Hedging Instruments | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	(2,673)	(535)
Total current derivative liabilities | Derivatives NOT Designated as Hedging Instruments | Physical index derivative contracts
Derivatives, Fair Value
Fair value	(41)	(116)
Total current derivative liabilities | Derivatives NOT Designated as Hedging Instruments | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value	(29,231)	(119,506)
Total current derivative liabilities | Derivatives Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	(12,257)	(1,818)
Total current derivative liabilities | Derivatives Designated as Hedging Instruments | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	0	0
Total current derivative liabilities | Derivatives Designated as Hedging Instruments | Physical index derivative contracts
Derivatives, Fair Value
Fair value	0	0
Total current derivative liabilities | Derivatives Designated as Hedging Instruments | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value	(12,257)	(1,818)
Total non-current derivative liabilities
Derivatives, Fair Value
Fair value	(4,069)	(703)
Netting balance sheet adjustment	92	0
Total non-current derivative liabilities | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	(27)
Netting balance sheet adjustment	8
Total non-current derivative liabilities | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value	(4,042)	(703)
Netting balance sheet adjustment	84	0
Total non-current derivative liabilities | Net Total
Derivatives, Fair Value
Fair value	(3,977)	(703)
Total non-current derivative liabilities | Net Total | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	(19)
Total non-current derivative liabilities | Net Total | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value	(3,958)	(703)
Total non-current derivative liabilities | Derivatives NOT Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	(4,069)	(703)
Total non-current derivative liabilities | Derivatives NOT Designated as Hedging Instruments | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	(27)
Total non-current derivative liabilities | Derivatives NOT Designated as Hedging Instruments | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value	(4,042)	(703)
Total non-current derivative liabilities | Derivatives Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	0	0
Total non-current derivative liabilities | Derivatives Designated as Hedging Instruments | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	0
Total non-current derivative liabilities | Derivatives Designated as Hedging Instruments | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value	$ 0	$ 0

DERIVATIVE INSTRUMENTS AND HE48

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Gains and Losses on Derivative Instruments (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Hedge Ineffectiveness
Ineffectiveness excluding the time value component on fair value hedging instruments:
Net gain (loss) in income	$ 2,985	$ (910)	$ 16,037	$ (12,889)
Futures contracts for refined products
Derivatives designated as fair value hedging instruments:
Futures contracts for refined products			(11,300)
Derivatives NOT Designated as Hedging Instruments | Product sales | Physical fixed price derivative contracts
Derivatives NOT designated as hedging instruments:
Gains (losses) on derivative instruments recognized in income	301	15,731	(7,263)	19,660
Derivatives NOT Designated as Hedging Instruments | Product sales | Physical index derivative contracts
Derivatives NOT designated as hedging instruments:
Gains (losses) on derivative instruments recognized in income	142	(299)	130	(309)
Derivatives NOT Designated as Hedging Instruments | Cost of product sales | Physical fixed price derivative contracts
Derivatives NOT designated as hedging instruments:
Gains (losses) on derivative instruments recognized in income	479	3,600	7,965	10,191
Derivatives NOT Designated as Hedging Instruments | Cost of product sales | Physical index derivative contracts
Derivatives NOT designated as hedging instruments:
Gains (losses) on derivative instruments recognized in income	30	(288)	193	(224)
Derivatives NOT Designated as Hedging Instruments | Cost of product sales | Futures contracts for refined products
Derivatives NOT designated as hedging instruments:
Gains (losses) on derivative instruments recognized in income	(307)	(10,992)	4,326	2,591
Derivatives Designated as Hedging Instruments | Cost of product sales | Hedge Ineffectiveness
Ineffectiveness excluding the time value component on fair value hedging instruments:
Fair value hedge ineffectiveness (excluding time value)	(4,262)	2,626	(4,275)	2,476
Time value excluded from hedge assessment	7,247	(3,536)	20,312	(15,365)
Derivatives Designated as Hedging Instruments | Cost of product sales | Futures contracts for refined products
Derivatives designated as fair value hedging instruments:
Futures contracts for refined products	(635)	54,514	(27,590)	21,959
Derivatives Designated as Hedging Instruments | Cost of product sales | Physical inventory - hedged items
Derivatives designated as fair value hedging instruments:
Physical inventory - hedged items	$ 3,620	$ (55,424)	$ 43,627	$ (34,848)

DERIVATIVE INSTRUMENTS AND HE49

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Changes in Value Recognized in OCI (Details) - Cash Flow Hedge - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Losses reclassified from AOCI to income
Gain Recognized in OCI on Derivatives	$ 1,052	$ 11,168	$ 1,052	$ 7,311
(Loss) Gain Reclassified from AOCI to Income (Effective Portion)	(3,037)	(3,037)	(7,846)	(9,113)
Interest rate contracts
Losses reclassified from AOCI to income
Gain Recognized in OCI on Derivatives	1,052	0	1,052	0
Commodity derivatives
Losses reclassified from AOCI to income
Gain Recognized in OCI on Derivatives	0	11,168	0	7,311
Interest and debt expense | Interest rate contracts
Losses reclassified from AOCI to income
(Loss) Gain Reclassified from AOCI to Income (Effective Portion)	(3,037)	(3,037)	(9,112)	(9,113)
Product sales | Commodity derivatives
Losses reclassified from AOCI to income
(Loss) Gain Reclassified from AOCI to Income (Effective Portion)	$ 0	$ 0	$ 1,266	$ 0

FAIR VALUE MEASUREMENTS - Asset

FAIR VALUE MEASUREMENTS - Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Fair value measurements
Fair value	$ (21,002)	$ 78,129
Fair Value, Measurements, Recurring | Level 1
Fair value measurements
Fair value	(23,786)	50,938
Fair Value, Measurements, Recurring | Level 1 | Physical fixed price derivative contracts
Fair value measurements
Financial assets	0	0
Financial liabilities	0	0
Fair Value, Measurements, Recurring | Level 1 | Physical index derivative contracts
Fair value measurements
Financial assets	0	0
Financial liabilities	0	0
Fair Value, Measurements, Recurring | Level 1 | Futures contracts for refined petroleum products
Fair value measurements
Financial assets	0	51,641
Financial liabilities	(23,786)	(703)
Fair Value, Measurements, Recurring | Level 1 | Interest rate derivatives
Fair value measurements
Financial assets	0	0
Fair Value, Measurements, Recurring | Level 2
Fair value measurements
Fair value	2,784	27,191
Fair Value, Measurements, Recurring | Level 2 | Physical fixed price derivative contracts
Fair value measurements
Financial assets	3,893	27,676
Financial liabilities	(2,187)	(456)
Fair Value, Measurements, Recurring | Level 2 | Physical index derivative contracts
Fair value measurements
Financial assets	66	25
Financial liabilities	(40)	(54)
Fair Value, Measurements, Recurring | Level 2 | Futures contracts for refined petroleum products
Fair value measurements
Financial assets	0	0
Financial liabilities	0	0
Fair Value, Measurements, Recurring | Level 2 | Interest rate derivatives
Fair value measurements
Financial assets	$ 1,052	$ 0

FAIR VALUE MEASUREMENTS - Carry

FAIR VALUE MEASUREMENTS - Carrying Value and Fair Value of Debt (Details) - Level 2 - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Carrying Amount
Fair Value And Carrying Value By Balance Sheet Grouping
Total debt	$ 4,045,200	$ 3,844,312
Carrying Amount | Fixed-rate debt
Fair Value And Carrying Value By Balance Sheet Grouping
Total debt	3,623,960	3,371,824
Carrying Amount | Variable-rate debt
Fair Value And Carrying Value By Balance Sheet Grouping
Total debt	421,240	472,488
Fair Value
Fair Value And Carrying Value By Balance Sheet Grouping
Total debt	4,217,066	3,530,433
Fair Value | Fixed-rate debt
Fair Value And Carrying Value By Balance Sheet Grouping
Total debt	3,795,826	3,057,945
Fair Value | Variable-rate debt
Fair Value And Carrying Value By Balance Sheet Grouping
Total debt	$ 421,240	$ 472,488

PENSIONS AND OTHER POSTRETIRE52

PENSIONS AND OTHER POSTRETIREMENT BENEFITS (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Components of net periodic benefit cost:
Defined benefit plan contributions	$ 300	$ 500	$ 1,300	$ 1,200
RIGP
Components of net periodic benefit cost:
Service cost	(9)	3	(26)	9
Interest cost	106	137	316	413
Expected return on plan assets	(64)	(84)	(192)	(251)
Amortization of unrecognized losses	130	211	391	632
Actuarial loss due to settlements	122	451	365	451
Net periodic benefit cost	285	718	854	1,254
Retiree Medical Plan
Components of net periodic benefit cost:
Service cost	81	92	242	274
Interest cost	327	333	982	1,000
Expected return on plan assets	0	0	0	0
Amortization of unrecognized losses	0	50	0	149
Actuarial loss due to settlements	0	0	0	0
Net periodic benefit cost	$ 408	$ 475	$ 1,224	$ 1,423

UNIT-BASED COMPENSATION PLANS -

UNIT-BASED COMPENSATION PLANS - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015	Dec. 31, 2014
LTIP and Option Plan
Share-based Compensation Arrangement by Share-based Payment Award
Compensation expense	$ 8.9	$ 6.6	$ 23	$ 17.6
Long Term Incentive Plan 2013
Share-based Compensation Arrangement by Share-based Payment Award
LP Units, available for issuance	2,036,228		2,036,228
Awards granted (in shares)			637,000
Long Term Incentive Plan 2013 | Phantom Stock Units | Employee
Share-based Compensation Arrangement by Share-based Payment Award
Awards granted (in shares)			342,572
Long Term Incentive Plan 2013 | Phantom Stock Units | Independent directors
Share-based Compensation Arrangement by Share-based Payment Award
Awards granted (in shares)			20,000
Long Term Incentive Plan 2013 | Performance Shares | Employee
Share-based Compensation Arrangement by Share-based Payment Award
Awards granted (in shares)			274,896
Long Term Incentive Plan 2009, Deferral Plan
Share-based Compensation Arrangement by Share-based Payment Award
Compensation awards deferred					$ 3.1	$ 1.7
Long Term Incentive Plan 2009, Deferral Plan | Phantom Stock Units
Share-based Compensation Arrangement by Share-based Payment Award
Awards granted (in shares)			139,526		54,592

UNIT-BASED COMPENSATION PLANS54

UNIT-BASED COMPENSATION PLANS - LTIP Activity for the Period (Details) - Long Term Incentive Plan 2013 $ / shares in Units, shares in Thousands, $ in Millions	9 Months Ended
	Sep. 30, 2016USD ($)$ / sharesshares
Number of LP Units
Beginning Balance (in shares) | shares	1,011
Granted (in shares) | shares	637
Vested (in shares) | shares	(267)
Forfeited (in shares) | shares	(8)
Ending Balance (in shares) | shares	1,373
Weighted Average Grant Date Fair Value per LP Unit
Beginning Balance (in dollars per share) | $ / shares	$ 68.20
Granted (in dollars per share) | $ / shares	53.48
Vested (in dollars per share) | $ / shares	55.28
Forfeited (in dollars per share) | $ / shares	64.53
Ending Balance (in dollars per share) | $ / shares	$ 64
Additional disclosures
Compensation expense expected to be recognized | $	$ 39.1
Unrecognized compensation cost, weighted average period of recognition (in years)	1 year 9 months 18 days

UNIT-BASED COMPENSATION PLANS55

UNIT-BASED COMPENSATION PLANS - Summary of Changes in the Options Outstanding Under the Option Plan (Details) - Option Plan - Limited Partners - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	9 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Number of LP Units
Beginning Balance (in units)	17
Exercised (in units)	(6)
Forfeited, cancelled or expired (in units)	(1)
Ending Balance (in units)	10		17
Exercisable (in units)	10
Weighted Average Strike Price per LP Unit
Beginning Balance (in dollars per share)	$ 48.71
Exercised (in dollars per share)	47.17
Forfeited, cancelled or expired (in dollars per share)	44.73
Ending Balance (in dollars per share)	50.36		$ 48.71
Exercisable (in dollars per share)	$ 50.36
Weighted Average Remaining Contractual Term (in years)
Outstanding	4 months 24 days		10 months 24 days
Exercisable	4 months 24 days
Aggregate Intrinsic Value
Outstanding	$ 203		$ 300
Exercisable	203
Additional disclosures
Total intrinsic value of options exercised	$ 100	$ 100

PARTNERS' CAPITAL AND DISTRIB56

PARTNERS' CAPITAL AND DISTRIBUTIONS - Narrative (Details) - Limited Partners - Equity Distribution Agreements - USD ($) shares in Millions	1 Months Ended		9 Months Ended
	Mar. 31, 2016	May 31, 2013	Sep. 30, 2016
Partner's capital and distributions
LP Units authorized to sell (in shares)	$ 500,000,000	$ 300,000,000
Public offering, LP units issued (in shares)			1.6
Proceeds from issuance of units			$ 108,400,000
Aggregate compensation expense paid to the agents under the Equity Distribution Agreements			$ 1,100,000

PARTNERS' CAPITAL AND DISTRIB57

PARTNERS' CAPITAL AND DISTRIBUTIONS - Summary of Changes in Outstanding Units (Details) - Limited Partner shares in Thousands	9 Months Ended
	Sep. 30, 2016shares
Summary of Changes in Outstanding Units for the Period
Beginning Balance (in shares)	129,524
Ending Balance (in shares)	131,310
Equity Distribution Agreements
Summary of Changes in Outstanding Units for the Period
Issuance of units through Equity Distribution Agreements (in shares)	1,568
Option Plan
Summary of Changes in Outstanding Units for the Period
LP Units issued (in shares)	6
Long Term Incentive Plan 2009
Summary of Changes in Outstanding Units for the Period
LP Units issued (in shares)	212

PARTNERS' CAPITAL AND DISTRIB58

PARTNERS' CAPITAL AND DISTRIBUTIONS - Distributions (Details) - USD ($) $ / shares in Units, $ in Thousands	Nov. 22, 2016	Oct. 24, 2016	Sep. 30, 2016	Sep. 30, 2015
Distributions to unitholders
Actual cash distributions			$ 469,764	$ 439,578
Limited Partners
Distributions to unitholders
Actual cash distributions			$ 472,100	$ 442,000
Distribution per LP unit (in dollars per share)			$ 3.6	$ 3.45
Limited Partners | Forecast
Distributions to unitholders
Actual cash distributions	$ 161,800
Limited Partners | Subsequent event
Distributions to unitholders
Cash distributions declared (in dollars per share)		$ 1.225

EARNINGS PER UNIT (Details)

EARNINGS PER UNIT (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Earnings Per Share [Abstract]
Net income attributable to Buckeye Partners, L.P.	$ 156,374	$ 100,040	$ 427,943	$ 303,231
Basic:
Weighted average units outstanding - basic (in shares)	131,113	128,329	130,439	127,722
Earnings per unit - basic (in dollars per share)	$ 1.19	$ 0.78	$ 3.28	$ 2.37
Diluted:
Weighted average units outstanding - basic (in shares)	131,113	128,329	130,439	127,722
Dilutive effect of LP Unit options and LTIP awards granted (in shares)	827	577	637	519
Weighted average units outstanding - diluted (in shares)	131,940	128,906	131,076	128,241
Earnings per unit - diluted (in dollars per share)	$ 1.19	$ 0.78	$ 3.26	$ 2.36

BUSINESS SEGMENTS - Narrative (

BUSINESS SEGMENTS - Narrative (Details)	9 Months Ended
	Sep. 30, 2016terminalsegmentpropane_storage
Segment information
Number of business segments | segment	3
Domestic Pipelines & Terminals
Segment information
Number of Terminals Operated	5
Number of underground propane storage caverns | propane_storage	2
Global Marine Terminals
Segment information
Number of Terminals Owned	7
Merchant Services
Segment information
Number of Terminals Owned	5

BUSINESS SEGMENTS - Revenue by

BUSINESS SEGMENTS - Revenue by Segment (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Revenue:
Total revenue	$ 766,605	$ 728,384	$ 2,324,321	$ 2,613,267
United States
Revenue:
Total revenue	683,850	644,445	2,072,893	2,358,622
International
Revenue:
Total revenue	82,755	83,939	251,428	254,645
Operating Segments | Domestic Pipelines & Terminals
Revenue:
Total revenue	265,036	236,080	752,968	704,305
Operating Segments | Global Marine Terminals
Revenue:
Total revenue	170,072	127,161	509,653	372,735
Operating Segments | Merchant Services
Revenue:
Total revenue	344,041	386,105	1,103,186	1,586,421
Intersegment
Revenue:
Total revenue	$ (12,544)	$ (20,962)	$ (41,486)	$ (50,194)

BUSINESS SEGMENTS - Adjusted EB

BUSINESS SEGMENTS - Adjusted EBITDA from Continuing Operations (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Reconciliation of Income from continuing operations to Adjusted EBITDA from continuing operations:
Income from continuing operations	$ 160,270	$ 99,947	$ 439,746	$ 303,294
Less: Net (income) loss attributable to noncontrolling interests	(3,896)	93	(11,803)	794
Income from continuing operations attributable to Buckeye Partners, L.P.	156,374	100,040	427,943	304,088
Add: Interest and debt expense	48,476	43,413	144,093	127,097
Income tax expense	308	240	896	720
Depreciation and amortization	63,472	54,830	188,220	164,204
Non-cash unit-based compensation expense	8,853	6,597	22,912	17,578
Acquisition and transition expense	309	82	479	2,942
Litigation contingency accrual	0	1,729	0	15,229
Less: Amortization of unfavorable storage contracts	(443)	(2,767)	(5,979)	(8,303)
Gains on property damage recoveries	(5,700)	0	(5,700)	0
Adjusted EBITDA from continuing operations	271,649	204,164	772,864	623,555
Buckeye Texas
Reconciliation of Income from continuing operations to Adjusted EBITDA from continuing operations:
Depreciation and amortization	$ 18,500	12,200	$ 52,500	34,700
Ownership percentage	100.00%		100.00%
Domestic Pipelines & Terminals
Reconciliation of Income from continuing operations to Adjusted EBITDA from continuing operations:
Adjusted EBITDA from continuing operations	$ 152,785	120,979	$ 423,245	376,042
Global Marine Terminals
Reconciliation of Income from continuing operations to Adjusted EBITDA from continuing operations:
Adjusted EBITDA from continuing operations	110,705	80,593	325,710	233,716
Merchant Services
Reconciliation of Income from continuing operations to Adjusted EBITDA from continuing operations:
Adjusted EBITDA from continuing operations	$ 8,159	$ 2,592	$ 23,909	$ 13,797

SUPPLEMENTAL CASH FLOW INFORM63

SUPPLEMENTAL CASH FLOW INFORMATION (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Supplemental Cash Flow Elements [Abstract]
Cash paid for interest (net of capitalized interest)	$ 141,140	$ 126,203
Cash paid for income taxes	670	1,562
Capitalized interest	3,142	16,897
Capital expenditures incurred but not yet paid	$ 45,200	$ 103,700

SUBSEQUENT EVENTS (Details)

SUBSEQUENT EVENTS (Details) - Subsequent event $ / shares in Units, shares in Thousands, bbl in Millions	1 Months Ended
	Oct. 31, 2016USD ($)terminalcontinent$ / sharessharesbbl
3.950% Notes Due December 2026 | Unsecured Debt
Subsequent events.
Face amount	$ 600,000,000
Interest rate percentage	3.95%
Percentage of principal amount issued in underwritten public offering	99.644%
Proceeds from issuance of debt	$ 597,900,000
Underwriting fees, expenses and debt issuance costs	$ 5,300,000
VTTI Acquisition
Subsequent events.
Percentage of interest acquired	50.00%
Cash consideration	$ 1,150,000,000
Public Offering | Limited Partners
Subsequent events.
Number of units issued (in shares) | shares	7,750
Price per unit issued (in dollars per share) | $ / shares	$ 66.05
Over-Allotment Option | Limited Partners
Subsequent events.
Number of units issued (in shares) | shares	1,160
Proceeds from issuance of units	$ 588,700,000
Underwriting fees and offering expenses	$ 7,700,000
VTTI B.V.
Subsequent events.
Product storage capacity (in bbl) | bbl	54
Number of terminals | terminal	13
Number of continents | continent	5
Natural Disasters, Hurricane Matthew | Minimum
Subsequent events.
Estimate of costs expected to be incurred	$ 20,000,000
Natural Disasters, Hurricane Matthew | Maximum
Subsequent events.
Estimate of costs expected to be incurred	$ 30,000,000