Buckeye Partners (BPL) 10-Q 2 Nov 15 2015 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2015	Oct. 27, 2015
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, 2015
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		128,836,223
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q3

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Revenue:
Product sales	$ 382,624	$ 1,241,696	$ 1,581,455	$ 4,412,135
Transportation, storage and other services	345,760	331,777	1,031,812	962,118
Total revenue	728,384	1,573,473	2,613,267	5,374,253
Costs and expenses:
Cost of product sales	366,319	1,218,471	1,532,392	4,393,893
Operating expenses	141,790	138,906	425,494	396,753
Depreciation and amortization	54,830	45,406	164,204	131,791
General and administrative	21,885	21,749	64,796	59,436
Total costs and expenses	584,824	1,424,532	2,186,886	4,981,873
Operating income	143,560	148,941	426,381	392,380
Other income (expense):
(Loss) earnings from equity investments	(30)	2,523	4,550	5,959
Interest and debt expense	(43,413)	(43,838)	(127,097)	(127,063)
Other income (expense)	70	(375)	180	(471)
Total other expense, net	(43,373)	(41,690)	(122,367)	(121,575)
Income from continuing operations before taxes	100,187	107,251	304,014	270,805
Income tax expense	(240)	(243)	(720)	(319)
Income from continuing operations	99,947	107,008	303,294	270,486
Loss from discontinued operations	0	(3,280)	(857)	(51,508)
Net income	99,947	103,728	302,437	218,978
Less: Net loss (income) attributable to noncontrolling interests	93	(785)	794	(2,547)
Net income attributable to Buckeye Partners, L.P.	$ 100,040	$ 102,943	$ 303,231	$ 216,431
Basic earnings (loss) per unit attributable to Buckeye Partners, L.P.:
Continuing operations (in dollars per share)	$ 0.78	$ 0.90	$ 2.38	$ 2.29
Discontinued operations (in dollars per share)	0	(0.03)	(0.01)	(0.44)
Total (in dollars per share)	0.78	0.87	2.37	1.85
Diluted earnings (loss) per unit attributable to Buckeye Partners, L.P.:
Continuing operations (in dollars per share)	0.78	0.89	2.37	2.29
Discontinued operations (in dollars per share)	0	(0.03)	(0.01)	(0.44)
Total (in dollars per share)	$ 0.78	$ 0.86	$ 2.36	$ 1.85
Weighted average units outstanding:
Basic (in shares)	128,329	118,804	127,722	116,747
Diluted (in shares)	128,906	119,429	128,241	117,305

CONDENSED CONSOLIDATED STATEME3

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Statement of Comprehensive Income [Abstract]
Net income	$ 99,947	$ 103,728	$ 302,437	$ 218,978
Other comprehensive income (loss):
Unrealized gains (losses) on derivative instruments	11,168	(2,612)	7,311	(21,424)
Reclassification of derivative losses to net income	3,037	3,159	9,113	6,716
Recognition of costs related to benefit plans to net income	712	394	1,232	1,181
Total other comprehensive income (loss)	14,917	941	17,656	(13,527)
Comprehensive income	114,864	104,669	320,093	205,451
Less: Comprehensive loss (income) attributable to noncontrolling interests	93	(785)	794	(2,547)
Comprehensive income attributable to Buckeye Partners, L.P.	$ 114,957	$ 103,884	$ 320,887	$ 202,904

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 7,081	$ 8,208
Accounts receivable, net	223,480	265,830
Construction and pipeline relocation receivables	13,972	20,542
Inventories	236,170	243,475
Derivative assets	50,683	69,189
Prepaid and other current assets	33,834	25,055
Total current assets	565,220	632,299
Property, plant and equipment, net	6,096,346	5,735,787
Equity investments	82,921	82,849
Goodwill	995,236	993,375
Intangible assets, net	507,392	553,924
Other non-current assets	77,331	87,854
Total assets	8,324,446	8,086,088
Current liabilities:
Line of credit	148,450	166,000
Accounts payable	116,807	159,129
Derivative liabilities	1,452	1,802
Accrued and other current liabilities	322,994	295,024
Total current liabilities	589,703	621,955
Long-term debt	3,632,843	3,388,986
Other non-current liabilities	129,199	134,551
Total liabilities	4,351,745	4,145,492
Commitments and contingencies (Note 3)	0	0
Buckeye Partners, L.P. capital:
Limited Partners (128,836,099 and 127,043,317 units outstanding as of September 30, 2015 and December 31, 2014 respectively)	3,798,222	3,817,916
Accumulated other comprehensive loss	(97,632)	(115,288)
Total Buckeye Partners, L.P. capital	3,700,590	3,702,628
Noncontrolling interests	272,111	237,968
Total partners’ capital	3,972,701	3,940,596
Total liabilities and partners’ capital	$ 8,324,446	$ 8,086,088

CONDENSED CONSOLIDATED BALANCE5

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Sep. 30, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Limited Partners, units outstanding	128,836,099	127,043,317

CONDENSED CONSOLIDATED STATEME6

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Cash flows from operating activities:
Net income	$ 302,437	$ 218,978
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Settlement of terminated interest rate swap agreement	0	(51,469)
Depreciation and amortization	164,204	131,791
Asset impairment expense	0	20,875
Litigation contingency accrual	15,229	0
Net changes in fair value of derivatives	25,632	(32,017)
Non-cash deferred lease expense	0	2,728
Amortization of unfavorable storage contracts	(8,303)	(8,303)
Earnings from equity investments	(4,550)	(5,959)
Distributions from equity investments	4,258	220
Other non-cash items	34,319	22,114
Change in assets and liabilities, net of amounts related to acquisitions:
Accounts receivable	39,435	(89,248)
Construction and pipeline relocation receivables	6,570	(3,461)
Inventories	9,599	(114,620)
Prepaid and other current assets	(11,513)	24,914
Accounts payable	(54,820)	102,125
Accrued and other current liabilities	(18,881)	(18,254)
Other non-current assets	3,820	(12,454)
Other non-current liabilities	(5,005)	(5,609)
Net cash provided by operating activities	502,431	182,351
Cash flows from investing activities:
Capital expenditures	(433,152)	(300,831)
Deposit in anticipation of sale	0	5,250
Acquisitions, net of working capital settlement	(2,921)	(824,736)
Net proceeds from insurance settlement	0	737
Proceeds from sale and disposition of assets	10,074	1,203
Net cash used in investing activities	(425,999)	(1,118,377)
Cash flows from financing activities:
Net proceeds from issuance of LP Units	117,820	821,944
Net proceeds from exercise of Unit options	173	698
Payment of tax withholding on issuance of LTIP awards	(6,667)	(5,244)
Issuance of long-term debt	0	599,103
Debt issuance costs	(365)	(6,783)
Borrowings under BPL Credit Facility	1,087,000	1,476,000
Repayments under BPL Credit Facility	(844,000)	(1,505,000)
Net repayments under BMSC Credit Facility	(17,550)	(44,000)
Acquisition of additional interest in WesPac Memphis	(10,044)	(9,510)
Contributions from noncontrolling interests	44,000	0
Distributions paid to noncontrolling interests	(8,348)	(5,217)
Distributions paid to unitholders	(439,578)	(384,418)
Net cash (used in) provided by financing activities	(77,559)	937,573
Net (decrease) increase in cash and cash equivalents	(1,127)	1,547
Cash and cash equivalents — Beginning of period	8,208	4,950
Cash and cash equivalents — End of period	$ 7,081	$ 6,497

CONDENSED CONSOLIDATED STATEME7

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL - USD ($) $ in Thousands	Total	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interests	Limited Partners
Beginning balance at Dec. 31, 2013	$ 3,080,836	$ (103,552)	$ 15,171	$ 3,169,217
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	218,978		2,547	216,431
Acquisition of additional interest in WesPac Memphis	(9,510)		(1,577)	(7,933)
Noncontrolling equity in acquisition	208,998		208,998
Distributions paid to unitholders	(384,418)		2,572	(386,990)
Net proceeds from issuance of LP Units	821,944			821,944
Amortization of unit-based compensation awards	13,549			13,549
Net proceeds from exercise of Unit options	698			698
Payment of tax withholding on issuance of LTIP awards	(5,244)			(5,244)
Distributions paid to noncontrolling interests	(5,217)		(5,217)
Other comprehensive income (loss)	(13,527)	(13,527)
Noncash accrual for distribution equivalent rights	(1,136)			(1,136)
Other	336		276	60
Ending balance at Sep. 30, 2014	3,926,287	(117,079)	222,770	3,820,596
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 WesPac Memphis	(10,044)		(1,768)	(8,276)
Adjustment to value of noncontrolling equity 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 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 (loss)	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

ORGANIZATION AND BASIS OF PRESE

ORGANIZATION AND BASIS OF PRESENTATION	9 Months Ended
	Sep. 30, 2015
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 (“NYSE”) under the ticker symbol “BPL.” Buckeye GP LLC (“Buckeye GP”) is our general partner. As used in these Notes to Unaudited Condensed Consolidated Financial Statements, “ we ,” “ us ,” “ our ” and “ Buckeye ” mean Buckeye Partners, L.P. and, where the context requires, includes our subsidiaries. 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, miles of pipeline and 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 flagship marine terminal in The Bahamas, 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 petroleum products. Our network of marine terminals enables us to facilitate global flows of crude oil, refined petroleum products, and other commodities, and to offer our customers connectivity to some of the world’s most important bulk storage and blending hubs. In September 2014, we expanded our network of marine midstream assets by acquiring a controlling interest in a company with assets located in Corpus Christi and the Eagle Ford play in Texas. We are also a wholesale distributor of refined petroleum products in certain areas served by our pipelines and terminals. Finally, Buckeye operates and/or maintains third-party pipelines under agreements with major oil and gas, petrochemical and chemical companies, and performs certain engineering and construction management services for third parties. On December 31, 2014, we completed the sale of our Natural Gas Storage disposal group and have reported the final working capital adjustments as discontinued operations in the first quarter of 2015. For additional information, see our Annual Report on Form 10-K for the year ended December 31, 2014. 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 (“VIE”) 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, 2014 . Recent Accounting Developments Business Combinations . In September 2015, the Financial Accounting Standards Board (“FASB”) issued guidance to simplify the accounting for adjustments made to provisional amounts recognized in a business combination. The amendments require that an acquirer recognize adjustments to provisional amounts identified during the measurement period in the reporting period in which the adjustment amounts are determined. This eliminates the requirement to retrospectively account for such adjustments. The guidance is effective prospectively for annual reporting periods beginning after December 15, 2015, 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. Inventory . In August 2015, the FASB issued guidance to simplify the measurement of inventory. The amendments require inventory to be measured at the lower of cost or net realizable value. Net realizable value is defined as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The guidance is effective prospectively for annual reporting periods beginning after December 15, 2016, 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. Revenue from Contracts with Customers . In July 2015, the FASB deferred the effective date of guidance that was originally issued in May 2014 to clarify principles used to recognize revenue for all entities. The guidance is now effective for annual and interim periods beginning after December 15, 2017, with early adoption permitted for annual and interim periods beginning after December 15, 2016. The standard’s core principle is that an entity will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In doing so, entities will need to use more judgment and make more estimates than under current guidance. These may include identifying performance obligations in the contract, estimating the amount of variable consideration included in the transaction price and/or allocating the transaction price to each separate performance obligation. We are currently evaluating the impact the adoption of this guidance will have on our consolidated financial statements. Debt Issuance Costs . In April 2015, the FASB issued guidance to simplify the presentation of debt issuance costs. The amendments require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. In August 2015, the FASB issued clarifying guidance allowing entities to present debt issuance costs related to line-of-credit arrangements as an asset, which must be subsequently amortized ratably over the term of the arrangement. The guidance is effective for annual reporting periods beginning after December 15, 2015, 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. Consolidations . In February 2015, the FASB issued guidance changing the criteria for reporting entities that are required to evaluate whether they should consolidate certain legal entities. The amendments require additional testing to determine if a legal entity qualifies as a VIE and whether the entity should be consolidated. These provisions are effective prospectively for annual reporting periods beginning after December 15, 2015, 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, 2015
Business Combinations [Abstract]
ACQUISITIONS	2. ACQUISITIONS Business Combinations 2015 Transaction In May 2015, we acquired a pipeline in Springfield, Massachusetts from ExxonMobil Oil Corporation ("ExxonMobil") for $5.8 million . The operations of this asset are reported in the Pipelines & Terminals segment and complement the Springfield terminal also purchased from ExxonMobil for $2.0 million in the first quarter of 2015. We valued these acquisitions as a single portfolio of assets. 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 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. The estimates of fair value reflected as of September 30, 2015 are subject to change pending final valuation analysis. The purchase price has been allocated to tangible and intangible assets acquired as follows (in thousands): Property, plant and equipment $ 5,541 Goodwill 7,114 Asset retirement obligation (4,200 ) Environmental liabilities (653 ) Allocated purchase price $ 7,802 Unaudited Pro forma Financial Results for the Springfield pipeline and terminal acquisition Our consolidated statements of operations do not include earnings from the pipeline and terminal acquired from ExxonMobil prior to March 31, 2015 and May 5, 2015, the effective acquisition dates of the terminal and pipeline acquired from ExxonMobil, respectively. 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, 2015 . 2014 Transaction In September 2014, we acquired an 80% interest in Buckeye Texas Partners LLC (“Buckeye Texas”), a newly-formed entity, for $816.1 million , net of cash acquired of $15.0 million and settlement of working capital and capital expenditure adjustments of $4.9 million required by the contribution agreement with Trafigura Corpus Christi Holdings Inc. (the “Buckeye Texas Partners Transaction”). Buckeye Texas and its subsidiaries, which are owned jointly with Trafigura Trading LLC, formerly known as Trafigura AG (“Trafigura”), are constructing a vertically integrated system of midstream assets including a deep-water, high volume marine terminal located on the Corpus Christi Ship Channel, two condensate splitters and liquefied petroleum gas storage complex in Corpus Christi, Texas and three crude oil and condensate gathering facilities in the Eagle Ford play. The initial build-out of these facilities has been and continues to be funded through additional partnership contributions by us and Trafigura based on our respective ownership interests. Concurrent with this acquisition, we entered into multi-year storage and throughput commitments with Trafigura that support substantially all the capacity and cash flows expected from these assets. Buckeye Texas does not have sufficient resources to complete its initial build-out and activities without financial support of its joint owners. Accordingly, we concluded Buckeye Texas is a VIE of which we are the primary beneficiary. In making this conclusion, we evaluated the activities that significantly impact the economics of the VIE, including our role to perform all services reasonably required to construct, operate and maintain the assets. We consolidated Buckeye Texas due to our conclusion that Buckeye Texas is a VIE of which we are the primary beneficiary. The operations of these assets are reported in the Global Marine 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 Buckeye Texas operations with our existing operations and the economic value attributable to future expansion projects resulting from this acquisition. Fair values have been developed using recognized business valuation techniques. The purchase price has been allocated to tangible and intangible assets acquired and liabilities assumed as follows (in thousands): Current assets $ 23,061 Property, plant and equipment 527,390 Intangible assets 376,000 Goodwill 167,379 Current liabilities (54,943 ) Noncontrolling interests (207,778 ) Allocated purchase price $ 831,109 The pro forma impact of this acquisition was not significant to our consolidated financial results for the three and nine months ended September 30, 2015 or 2014 , as the construction of significant assets was recently completed and commissioning activities began in late September 2015. Acquisition of Remaining Interest in WesPac Pipelines — Memphis LLC In April 2015, our operating subsidiary, Buckeye Pipe Line Holdings, L.P. (“BPH”), purchased from Kealine LLC for $10.0 million the remaining 10% ownership interest in Buckeye Aviation (Memphis) LLC, formerly known as WesPac Pipelines — Memphis LLC (“Buckeye Memphis”), which was accounted for as an equity transaction. As a result of the acquisition, we now own 100% of Buckeye Memphis.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	9 Months Ended
	Sep. 30, 2015
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. Pennsauken Allisions . Our terminal located in Pennsauken, New Jersey suffered two allisions in the second half of 2014. The first occurred on August 5, 2014, when a vessel allided with our terminal’s ship dock. Reconstruction of the dock has been completed and service has commenced. The aggregate cost to reconstruct the dock was approximately $8.0 million . Security for our claim has been provided by the vessel owner’s insurers, in the amount of $19.0 million , reserving all of their defenses. We have commenced litigation against the vessel and its owner. They have stipulated to liability, so the only issue is the amount of Buckeye’s damages. The second incident occurred on October 5, 2014, when a tug and barge struck and damaged a second dock operated at the Pennsauken facility. The tug and barge owners have commenced proceedings to limit their liability to $1.0 million and $5.0 million , respectively. We have filed claims in the limitation proceedings for the reconstruction of the second dock and response costs totaling approximately $7.0 million . We also are suffering loss-of-use damages as a result of the above allisions as the two incidents together have impacted the ability of vessels to call at the terminal. In order to mitigate these business losses, we have made modifications to two other berths at a cost of $1.3 million . Recovery for both the mitigation costs and business losses is being sought jointly from all of the respective responsible parties. Investigation of the incidents as well as our rights to recover our losses is ongoing. We are insured for loss of use, subject to a 30 day deductible. Our insurers are involved in the recovery efforts. As of September 30, 2015 we had $1.3 million included in “Other non-current assets” in our unaudited condensed consolidated balance sheet, representing expected reimbursement from third parties for mitigation costs deemed probable for recovery. BORCO Jetty . On May 25, 2012, a ship, Cape Bari, allided with a jetty at our BORCO facility while berthing, causing damage to portions of the jetty. Buckeye has insurance to cover this loss, subject to a $5.0 million deductible. On May 26, 2012, we commenced legal proceedings in The Bahamas against the vessel’s owner and the vessel to obtain security for the cost of repairs and other losses incurred as a result of the incident. Full security for our claim has been provided by the vessel owner’s insurers, reserving all of their defenses. We also have notified the customer on whose behalf the vessel was at the BORCO facility that we intend to hold them responsible for all damages and losses resulting from the incident pursuant to the terms of an agreement between the parties. Any disputes between us and our customer on this matter are subject to arbitration in New York, New York, and arbitration has been commenced. The vessel owner has claimed that it is entitled to limit its liability to $17.0 million , but we are contesting the right of the vessel owner to such limitation. The Bahamas court of first instance denied the vessel owner the right to limit its liability for the incident, leaving the vessel owner responsible for all provable damages. The vessel owner appealed, and The Bahamas Court of Appeals reversed, holding that the vessel owner may limit its liability. Our application for leave to appeal the Court of Appeals’ decision to the Privy Council was granted, and the appeal has been filed. We can express no view on whether The Bahamas Court of Appeals decision ultimately will be affirmed or reversed. We experienced no material interruption of service at the BORCO facility as a result of the incident, and the repairs and reconstruction of the damaged sections are complete. The aggregate cost to repair and reconstruct the damaged portions of the jetty and pursue recovery in court has been $23.0 million . We recorded a loss on disposal due to the assets destroyed in the incident and other related costs incurred; however, since we believe recovery of our losses is probable, we recorded a corresponding receivable. As of September 30, 2015 , we had a $6.4 million receivable included in “Other non-current assets” in our unaudited condensed consolidated balance sheet, representing reimbursement of the deductible and other third party expenses. Additionally, we have received insurance reimbursements of $16.0 million , and to the extent the aggregate proceeds from the recovery of our losses is in excess of the carrying value of the destroyed assets or other costs incurred, we will recognize a gain when such proceeds are received and are not refundable. Our insurers have paid most of the claim and are now parties in The Bahamas litigation. As of September 30, 2015 , no gain had been recognized; however, we recorded a $14.1 million deferred gain in “Accrued and other current liabilities” in our unaudited condensed consolidated balance sheet, representing excess proceeds received over the loss on disposal and other costs incurred. On May 12, 2014, the vessel owner filed a third-party complaint against BORCO and a BORCO subsidiary, Borco Towing Company Limited, alleging negligence by the pilots and tugs that assisted the Cape Bari berth. We have investigated these allegations and believe that we have defenses and intend to defend ourselves and pursue our claims against the vessel owner. BORCO and Borco Towing Company Limited are insured for the alleged liability, subject to an applicable deductible, and the liability insurers are participating in the defense. Federal Energy Regulatory Commission (“FERC”) Proceedings FERC Docket No. OR12-28-000 — Airlines Complaint against Buckeye Pipe Line Company, L.P. (“BPLC”) New York City Jet Fuel Rates . On September 20, 2012, a complaint was filed with FERC by Delta Air Lines, JetBlue Airways, United/Continental Air Lines, and US Airways challenging BPLC’s rates for transportation of jet fuel from New Jersey to three New York City airports. The complaint was not directed at BPLC’s rates for service to other destinations and does not involve pipeline systems and terminals owned by Buckeye’s other operating subsidiaries. The complaint challenges these jet fuel transportation rates as generating revenues in excess of costs and thus being “unjust and unreasonable” under the Interstate Commerce Act. On October 10, 2012, BPLC filed its answer to the complaint, contending that the airlines’ allegations are based on inappropriate adjustments to the pipeline’s costs and revenues, and that, in any event, any revenue recovery by BPLC in excess of costs would be irrelevant because BPLC’s rates are set under a FERC-approved program that ties rates to competitive levels. BPLC also sought dismissal of the complaint to the extent it seeks to challenge the portion of BPLC’s rates that were deemed just and reasonable, or “grandfathered,” under Section 1803 of the Energy Policy Act of 1992. BPLC further contested the airlines’ ability to seek relief as to past charges where the rates are lawful under BPLC’s FERC-approved rate program. On October 25, 2012, the complainants filed their answer to BPLC’s motion to dismiss and answer. On November 9, 2012, BPLC filed a response addressing newly raised arguments in the complainants’ October 25 th answer. On February 22, 2013, FERC issued an order setting the airline complaint in Docket (“Dkt.”) No. OR12-28-000 for hearing, but holding the hearing in abeyance and setting the dispute for settlement procedures before a settlement judge. If FERC were to find these challenged rates to be in excess of costs and not otherwise protected by law, it could order BPLC to reduce these rates prospectively and could order repayment to the complaining airlines of any past charges found to be in excess of just and reasonable levels for up to two years prior to the filing date of the complaint. BPLC intends to vigorously defend its rates. On March 8, 2013, an order was issued consolidating, for settlement purposes, this complaint proceeding with the proceeding regarding BPLC’s application for market-based rates in the New York City market in Dkt. No. OR13-3-000 (discussed below), and settlement discussions under the supervision of the FERC settlement judge continued until April 2014. On April 1, 2014, the FERC settlement judge issued a status report stating that the parties had been unable to reach a settlement, and recommending that both Dkt. Nos. OR12-28-000 and OR13-3-000 be set for hearing. The settlement judge further recommended that settlement procedures under the supervision of the settlement judge continue concurrently because the parties hope to continue settlement talks after the commencement of litigation. On April 17, 2014, the FERC Chief Administrative Law Judge (the “Chief ALJ”) ruled in favor of separate proceedings and of continuing the existing settlement procedures concurrently with litigation. In May 2014, a procedural schedule was established for this matter, providing for a hearing in March 2015, which occurred, and an initial decision by August 2015. The hearing was concluded on April 1, 2015. As a result of developments in ongoing settlement talks regarding Dkt. Nos. OR12-28-000, OR13-3-000 (discussed below) and OR 14-41-000 (discussed below), we recorded an accrual and a corresponding reduction in revenue in the amount of $40.0 million in the quarter ended December 31, 2014 in our Pipelines & Terminals segment. On June 19, 2015, BPLC and the airlines submitted an Offer of Settlement at the FERC (the “Settlement”) to resolve the complaints set for hearing in Dkt. Nos. OR12-28-000, et al. and OR14-41-000, as well as BPLC’s application in Dkt. No. OR13-3-000. Under the terms of the Settlement, BPLC agreed to reduce its jet fuel rates prospectively, to make settlement payments to the airlines, to install facilities to increase the flexibility and capacity of its system in shipping jet fuel to John F. Kennedy International Airport, and to resolve its application in Dkt. No. OR13-3-000 as described further below. As a result of submission of the Settlement, we recorded an additional accrual and corresponding reduction in revenue in the amount of $13.5 million in the quarter ended June 30, 2015 in our Pipelines & Terminals segment, which, together with the previously recorded $40.0 million reduction in revenue, represents anticipated settlement payments and other expenses associated with the Settlement. In the third quarter of 2015, we recorded an additional litigation accrual adjustment of $1.7 million as a reduction of revenue. On September 29, 2015, the FERC approved the Settlement without modification. On October 1, 2015, BPLC filed a tariff to implement the terms of the Settlement, including the agreed-upon reductions in jet fuel rates effective November 1, 2015 (the “Settlement Tariff”). On October 16, 2015, a jet fuel marketer and three airlines not parties to the Settlement protested the tariff, alleging that certain provisions of an incentive rate program provided for in the Settlement are unduly discriminatory (the “Protest”). On October 29, 2015, the jet fuel marketer and three airlines sought late intervention and rehearing at the FERC (the “Rehearing Request”) to challenge FERC’s approval of the Settlement alleging, on a basis similar to the Protest, that certain provisions of the Settlement’s incentive rate program are unduly discriminatory. On October 30, 2015, the FERC issued an order rejecting the Protest on the merits and accepting the Settlement Tariff, permitting the reduced rates to go into effect on November 1, 2015. Buckeye Pipe Line believes that the incentive rate program established under the settlement is reasonable, a position reflected in the FERC’s October 30th order, and intends to vigorously contest the Rehearing Request. FERC Docket No. OR14-41-000 — American Airlines Complaint against BPLC New York City Jet Fuel Rates . On September 17, 2014, a complaint was filed with FERC by American Airlines. It is similar to the Dkt. No. OR12-28-000 complaint (see above) in that it challenges BPLC’s rates for transportation of jet fuel from New Jersey to the three New York City airports, is not directed at BPLC’s rates for service to other destinations, and does not involve pipeline systems and terminals owned by Buckeye’s other operating subsidiaries. On October 7, 2014, BPLC filed its answer to the complaint, contesting the airline’s allegations and presenting certain legal defenses to relief sought by the airline. On December 18, 2014, FERC issued an order setting the complaint for hearing, but holding the hearing in abeyance and setting the dispute for settlement procedures before a settlement judge. As noted above, the Settlement to resolve this complaint was approved by the FERC on September 29, 2015. FERC Docket No. OR13-3-000 — BPLC’s Market-Based Rate Application . On October 15, 2012, BPLC filed an application with FERC seeking authority to charge market-based rates for deliveries of liquid petroleum products to the New York City-area market (the “Application”). In the Application, BPLC seeks to charge market-based rates from its three origin points in northeastern New Jersey to its five destinations on its Long Island System, including deliveries of jet fuel to the Newark, LaGuardia, and JFK airports. The jet fuel rates were also the subject of the airlines’ Dkt. No. OR12-28-000 complaint discussed above. On December 14, 2012, Delta Air Lines, JetBlue Airways, United/Continental Air Lines, and US Airways filed a joint intervention and protest challenging the Application and requesting its rejection. On January 14, 2013, BPLC filed its answer to the protest and requested summary disposition as to those non-jet-fuel rates that were not challenged in the protest. On January 29, 2013, the protestants responded to BPLC’s answer, and on February 13, 2013, BPLC filed a further answer to the protestants’ January 29, 2013 pleading. On February 28, 2013, FERC issued an order setting the Application for hearing, holding the hearing in abeyance and setting the dispute for settlement procedures before a settlement judge. As discussed above, the Application was consolidated with the complaint proceeding in Dkt. No. OR12-28-000 for settlement purposes, and the settlement judge reported to the FERC and the Chief ALJ that the Application should be set for hearing. The settlement judge also recommended that settlement procedures under the supervision of the settlement judge continue concurrently because the parties hope to continue settlement talks after the commencement of litigation. As noted above, the FERC Chief ALJ ruled that Dkt. No. OR13-3-000 would proceed separately from the Dkt. No. OR12-28-000 proceeding and that the existing settlement procedures would continue concurrently with litigation. As noted above, BPLC and the airlines submitted an Offer of Settlement to the FERC to resolve the airlines’ objections to the Application. Under the terms of the Settlement, and in connection with the resolution of challenges to the jet fuel rates by the airlines in the complaint dockets discussed separately above, Buckeye agreed, inter alia , to withdraw the portions of the Application addressing transportation of jet fuel within the New York City market, including transportation of jet fuel to the three airports, while remaining free to pursue market-based rates for transportation of other refined petroleum products to other destinations within the New York City market. As noted above, the Settlement was approved by the FERC on September 29, 2015. On October 8, 2015, the Chief ALJ issued an order continuing suspension of the procedural schedule until December 8, 2015 to permit discussions between Buckeye and FERC Trial Staff regarding procedural steps to recommend regarding the proceeding. Environmental Contingencies We recorded operating expenses, net of insurance recoveries, of $1.7 million and $2.0 million during the three months ended September 30, 2015 and 2014 , respectively, related to environmental remediation liabilities unrelated to claims and legal proceedings. For the nine months ended September 30, 2015 and 2014 , we recorded operating expenses, net of recoveries, of $4.5 million and $4.2 million , respectively, related to environmental remediation liabilities unrelated to claims and legal proceedings. As of September 30, 2015 and December 31, 2014 , we recorded environmental remediation liabilities of $48.4 million and $52.3 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, 2015 and December 31, 2014 , we had $12.9 million and $13.6 million , respectively, of receivables related to these environmental remediation liabilities covered by insurance or third party claims.

INVENTORIES

INVENTORIES	9 Months Ended
	Sep. 30, 2015
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) $ 219,043 $ 226,898 Materials and supplies 17,127 16,577 Total inventories $ 236,170 $ 243,475 (1) Ending inventory was 142.8 million and 140.3 million gallons of liquid petroleum products as of September 30, 2015 and December 31, 2014 , respectively. At September 30, 2015 and December 31, 2014 , approximately 93% and 90% 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 cost or market using the weighted average cost method.

PREPAID OTHER CURRENT ASSETS

PREPAID OTHER CURRENT ASSETS	9 Months Ended
	Sep. 30, 2015
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 $ 12,790 $ 9,918 Unbilled revenue 3,403 3,556 Prepaid taxes 7,868 2,492 Other 9,773 9,089 Total prepaid and other current assets $ 33,834 $ 25,055

EQUITY INVESTMENTS

EQUITY INVESTMENTS	9 Months Ended
	Sep. 30, 2015
Equity Method Investments and Joint Ventures [Abstract]
EQUITY INVESTMENTS	6. EQUITY INVESTMENTS The following table presents earnings from equity investments for the periods indicated (in thousands): Three Months Ended Nine Months Ended 2015 2014 2015 2014 West Shore Pipe Line Company $ 2,033 $ 1,551 $ 6,209 $ 3,734 Muskegon Pipeline LLC (2,761 ) 470 (3,345 ) 1,041 Transport4, LLC 183 109 456 362 South Portland Terminal LLC 515 393 1,230 822 Total (loss) earnings from equity investments $ (30 ) $ 2,523 $ 4,550 $ 5,959 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 2015 2014 2015 2014 Revenue $ 24,440 $ 23,872 $ 68,786 $ 65,337 Costs and expenses (16,642 ) (14,168 ) (43,256 ) (38,813 ) Non-operating expenses (4,033 ) (3,261 ) (11,690 ) (8,841 ) Net income $ 3,765 $ 6,443 $ 13,840 $ 17,683

DERIVATIVE INSTRUMENTS AND HEDG

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES	9 Months Ended
	Sep. 30, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES	7. 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 such as forwards, futures and other contracts to manage the risk of market price volatility associated with physical commodity inventory and expected future transactions. The majority of our futures contracts are used to hedge refined petroleum product inventories and are designated as fair value hedges with changes in fair value of both the futures contracts and physical inventory reflected in earnings. Other futures contracts are used to hedge certain expected future transactions and are designated as cash flow hedges with the effective portion of the hedge reported in other comprehensive income ("OCI") and reclassified into earnings when the expected future transaction affects earnings. In both cases, any gains or losses incurred on the derivative instrument that are not effective in offsetting changes in fair value or cash flows of the hedged item are recognized immediately in earnings. Physical forward contracts and futures contracts that have not been designated in a hedge relationship are marked-to-market. 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 designate as fair value hedges. In the second quarter of 2015, our Pipelines & Terminals segment designated exchange-traded refined petroleum product futures contracts as cash flow hedges. These hedges were executed to manage the risk of market price volatility on the narrowing gasoline-to-butane pricing spreads associated with our butane blending activities managed by a third party. The following table summarizes our commodity derivative instruments outstanding at September 30, 2015 (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 22,976 2,321 Mark-to-market Physical index derivative contracts 55,751 — Mark-to-market Futures contracts for refined petroleum products 24,361 3,024 Mark-to-market Derivatives designated as hedging instruments: Futures contracts for refined petroleum products 132,132 — Fair Value Hedge Futures contracts for refined petroleum products 33,600 — Cash Flow 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, 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 $ 20,445 $ — $ 20,445 $ (18 ) $ 20,427 Physical index derivative contracts 49 — 49 (17 ) 32 Futures contracts for refined products 110,154 63,412 173,566 (143,342 ) 30,224 Total current derivative assets 130,648 63,412 194,060 (143,377 ) 50,683 Physical fixed price derivative contracts 377 — 377 (6 ) 371 Futures contracts for refined products 1 — 1 — 1 Total non-current derivative assets 378 — 378 (6 ) 372 Physical fixed price derivative contracts (1,178 ) — (1,178 ) 18 (1,160 ) Physical index derivative contracts (309 ) — (309 ) 17 (292 ) Futures contracts for refined products (139,173 ) (4,169 ) (143,342 ) 143,342 — Total current derivative liabilities (140,660 ) (4,169 ) (144,829 ) 143,377 (1,452 ) Physical fixed price derivative contracts (28 ) — (28 ) 6 (22 ) Futures contracts for refined products (216 ) — (216 ) — (216 ) Total non-current derivative liabilities (244 ) — (244 ) 6 (238 ) Net derivative (liabilities) assets $ (9,878 ) $ 59,243 $ 49,365 $ — $ 49,365 (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, 2014 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 $ 42,005 $ — $ 42,005 $ (12 ) $ 41,993 Physical index derivative contracts 112 — 112 (59 ) 53 Futures contracts for refined products 150,352 30,702 181,054 (153,911 ) 27,143 Total current derivative assets 192,469 30,702 223,171 (153,982 ) 69,189 Physical fixed price derivative contracts 2,919 — 2,919 — 2,919 Total non-current derivative assets 2,919 — 2,919 — 2,919 Physical fixed price derivative contracts (1,502 ) — (1,502 ) 12 (1,490 ) Physical index derivative contracts (371 ) — (371 ) 59 (312 ) Futures contracts for refined products (153,911 ) — (153,911 ) 153,911 — Total current derivative liabilities (155,784 ) — (155,784 ) 153,982 (1,802 ) Physical fixed price derivative contracts (5 ) — (5 ) — (5 ) Futures contracts for refined products (2,615 ) — (2,615 ) — (2,615 ) Total non-current derivative liabilities (2,620 ) — (2,620 ) — (2,620 ) Net derivative assets $ 36,984 $ 30,702 $ 67,686 $ — $ 67,686 (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 hedged inventory portfolio extends to the third quarter of 2016. The majority of the unrealized gain at September 30, 2015 for inventory hedges represented by futures contracts of $51.9 million will be realized by the first quarter of 2016 . At September 30, 2015 , open refined petroleum product derivative contracts (represented by the physical fixed-price contracts, physical index contracts, and futures contracts for fixed-price sales contracts noted above) varied in duration in the overall portfolio, but did not extend beyond March 2017 . In addition, at September 30, 2015 , 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 2015 2014 2015 2014 Derivatives NOT designated as hedging instruments: Physical fixed price derivative contracts Product sales $ 15,731 $ 16,065 $ 19,660 $ 5,413 Physical index derivative contracts Product sales (299 ) (37 ) (309 ) (110 ) Physical fixed price derivative contracts Cost of product sales 3,600 (1,442 ) 10,191 7,179 Physical index derivative contracts Cost of product sales (288 ) 207 (224 ) (506 ) Futures contracts for refined products Cost of product sales (10,992 ) (997 ) 2,591 (810 ) Derivatives designated as fair value hedging instruments: Futures contracts for refined products Cost of product sales $ 54,514 $ 35,717 $ 21,959 $ 23,264 Physical inventory - hedged items Cost of product sales (55,424 ) (34,041 ) (34,848 ) (32,312 ) Ineffectiveness excluding the time value component on fair value hedging instruments: Fair value hedge ineffectiveness (excluding time value) Cost of product sales $ 2,626 $ 2,914 $ 2,476 $ 6,524 Time value excluded from hedge assessment Cost of product sales (3,536 ) (1,238 ) (15,365 ) (15,572 ) Net (loss) gain in income $ (910 ) $ 1,676 $ (12,889 ) $ (9,048 ) The change in value recognized in OCI and the losses reclassified from accumulated other comprehensive income (“AOCI”) to income attributable to our derivative instruments designated as cash flow hedges were as follows for the periods indicated (in thousands): Gain (Loss) Recognized in OCI on Derivatives for the Three Months Ended Nine Months Ended 2015 2014 2015 2014 Derivatives designated as cash flow hedging instruments: Interest rate contracts $ — $ (2,612 ) $ — $ (21,424 ) Commodity derivatives 11,168 — 7,311 — Total $ 11,168 $ (2,612 ) $ 7,311 $ (21,424 ) Loss Reclassified from AOCI to Income (Effective Portion) for the Three Months Ended Nine Months Ended Location 2015 2014 2015 2014 Derivatives designated as cash flow hedging instruments: Interest rate contracts Interest and debt expense $ (3,037 ) $ (3,159 ) $ (9,113 ) $ (6,716 ) Total $ (3,037 ) $ (3,159 ) $ (9,113 ) $ (6,716 ) The unrealized gain at September 30, 2015 for refined petroleum products designated as cash flow hedges of $7.3 million will be realized and reclassified from AOCI to product sales by the first quarter of 2016, at the end of the butane blending season. The ineffective portion of the change in fair value of cash flow hedges was not material for the nine months ended September 30, 2015. 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, 2014.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	9 Months Ended
	Sep. 30, 2015
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	8. FAIR VALUE MEASUREMENTS We categorize our financial assets and liabilities using the three-tier hierarchy as follows: Recurring The following table sets forth financial assets and liabilities measured at fair value on a recurring basis, as of the measurement dates indicated, and the basis for that measurement, by level within the fair value hierarchy (in thousands): September 30, 2015 December 31, 2014 Level 1 Level 2 Level 1 Level 2 Financial assets: Physical fixed price derivative contracts $ — $ 20,798 $ — $ 44,912 Physical index derivative contracts — 32 — 53 Futures contracts for refined products 30,225 — 27,143 — Financial liabilities: Physical fixed price derivative contracts — (1,182 ) — (1,495 ) Physical index derivative contracts — (292 ) — (312 ) Futures contracts for refined products (216 ) — (2,615 ) — Fair value $ 30,009 $ 19,356 $ 24,528 $ 43,158 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 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 Level 2 fixed price derivative assets of $44.9 million as of December 31, 2014 are net of CVAs of ($0.1) million . As of September 30, 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, 2015 December 31, 2014 Carrying Amount Fair Value Carrying Amount Fair Value Fixed-rate debt $ 3,389,843 $ 3,284,534 $ 3,388,986 $ 3,465,973 Variable-rate debt 391,450 391,450 166,000 166,000 Total debt $ 3,781,293 $ 3,675,984 $ 3,554,986 $ 3,631,973 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, 2015 and 2014 , 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, 2015 , there were no fair value adjustments related to such assets or liabilities reflected in our unaudited condensed consolidated financial statements. During the nine months ended September 30, 2014, we recorded a net non-cash asset impairment charge of $20.9 million related to our Natural Gas Storage disposal group since the carrying amount of the disposal group exceeded the estimated fair value less costs to sell the disposal group. During the three months ended September 30, 2014 , we reduced the initial non-cash asset impairment charge by $5.4 million due to changes in the carrying value of the net assets of our Natural Gas Storage disposal group, primarily related to the net loss experienced during the three months ended September 30, 2014 . We estimated fair value based on a market approach supported by a binding purchase and sale agreement for the disposal group. The sale of our Natural Gas Storage disposal group was completed in December 2014. For additional information, see our Annual Report on Form 10-K for the year ended December 31, 2014.

PENSIONS AND OTHER POSTRETIREME

PENSIONS AND OTHER POSTRETIREMENT BENEFITS	9 Months Ended
	Sep. 30, 2015
Compensation and Retirement Disclosure [Abstract]
PENSIONS AND OTHER POSTRETIREMENT BENEFITS	9. 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 months ended September 30, 2015 and 2014 (in thousands): RIGP Retiree Medical Plan Three Months Ended Three Months Ended 2015 2014 2015 2014 Service cost $ 3 $ 54 $ 92 $ 108 Interest cost 137 134 333 352 Expected return on plan assets (84 ) (98 ) — — Amortization of prior service credit — — — (406 ) Amortization of unrecognized losses 211 308 50 299 Actuarial loss due to settlements 451 193 — — Net periodic benefit cost $ 718 $ 591 $ 475 $ 353 The components of the net periodic benefit cost for the RIGP and the Retiree Medical Plan were as follows for the nine months ended September 30, 2015 and 2014 (in thousands): RIGP Retiree Medical Plan Nine Months Ended Nine Months Ended 2015 2014 2015 2014 Service cost $ 9 $ 163 $ 274 $ 323 Interest cost 413 403 1,000 1,056 Expected return on plan assets (251 ) (294 ) — — Amortization of prior service credit — — — (1,218 ) Amortization of unrecognized losses 632 924 149 895 Actuarial loss due to settlements 451 580 — — Net periodic benefit cost $ 1,254 $ 1,776 $ 1,423 $ 1,056 During the three months ended September 30, 2015 and 2014 , we contributed $0.5 million and $0.7 million , respectively, in aggregate to the RIGP and Retiree Medical Plans. For the nine months ended September 30, 2015 and 2014 , we contributed $1.2 million and $2.1 million , respectively, in aggregate to the RIGP and Retiree Medical Plans.

UNIT-BASED COMPENSATION PLANS

UNIT-BASED COMPENSATION PLANS	9 Months Ended
	Sep. 30, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
UNIT-BASED COMPENSATION PLANS	10. UNIT-BASED COMPENSATION PLANS We award unit-based compensation to employees and directors primarily under the Buckeye Partners, L.P. 2013 Long-Term Incentive Plan (the “LTIP”). 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 $6.6 million and $5.2 million for the three months ended September 30, 2015 and 2014 , respectively. For the nine months ended September 30, 2015 and 2014 , we recognized compensation expense of $17.6 million and $13.1 million , respectively. LTIP As of September 30, 2015 , there were 2,591,003 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, 2014 and 2013 , actual compensation awards deferred under the Deferral Plan were $1.7 million and $2.7 million , for which 54,592 and 75,870 phantom units (including matching units) were granted during the nine months ended September 30, 2015 and the year ended 2014 , respectively. These grants are included as granted in the LTIP activity table below. Awards under the LTIP During the nine months ended September 30, 2015 , the Compensation Committee of the Board granted 202,176 phantom units to employees (including the 54,592 phantom units granted pursuant to the Deferral Plan, as discussed above), 22,001 phantom units to independent directors of Buckeye GP and 210,494 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, 2015 906 $ 63.56 Granted 435 73.45 Vested (262 ) 63.73 Forfeited (17 ) 67.08 Unvested at September 30, 2015 1,062 $ 67.50 At September 30, 2015 , $33.8 million of compensation expense related to the LTIP is expected to be recognized over a weighted average period of 1.9 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, 2015 26 $ 48.18 1.6 $ 703 Exercised (4 ) 48.12 Forfeited, cancelled or expired (2 ) 45.88 Outstanding at September 30, 2015 20 48.44 1.1 $ 216 Exercisable at September 30, 2015 20 $ 48.44 1.1 $ 216 (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 2015 and the exercise price, multiplied by the number of exercisable, in-the-money options. The total intrinsic value of options exercised during the nine months ended September 30, 2015 and 2014 was $0.1 million and $0.4 million , respectively.

PARTNERS' CAPITAL AND DISTRIBUT

PARTNERS' CAPITAL AND DISTRIBUTIONS	9 Months Ended
	Sep. 30, 2015
Equity [Abstract]
PARTNERS' CAPITAL AND DISTRIBUTIONS	11. PARTNERS' CAPITAL AND DISTRIBUTIONS During the nine months ended September 30, 2015 , we sold approximately 1.6 million LP Units in aggregate under the equity distribution agreements entered into in May 2013 with each of Wells Fargo Securities, LLC, Barclays Capital Inc., SunTrust Robinson Humphrey, Inc. and UBS Securities LLC (each an “Equity Distribution Agreement” and collectively the “Equity Distribution Agreements”). We received $117.8 million in net proceeds after deducting commissions and other related expenses and paid $1.2 million of compensation in aggregate to the agents under the Equity Distribution Agreements. Summary of Changes in Outstanding Units The following is a summary of changes in LP Units outstanding for the periods indicated (in thousands): Limited Partners Outstanding at January 1, 2015 127,043 LP Units issued pursuant to the Option Plan (1) 4 LP Units issued pursuant to the LTIP (1) 198 Issuance of LP Units through Equity Distribution Agreements 1,591 Outstanding at September 30, 2015 128,836 (1) The number of units issued represents issuance net of tax withholding. Distributions We generally make quarterly cash distributions to unitholders of substantially all of our available cash, generally defined in our partnership agreement as consolidated cash receipts less consolidated cash expenditures and such retentions for working capital, anticipated cash expenditures and contingencies as our general partner deems appropriate. Actual cash distributions on our LP Units totaled $442.0 million and $387.0 million during the nine months ended September 30, 2015 and 2014, respectively. On October 30, 2015 , we announced a quarterly distribution of $1.175 per LP Unit that will be paid on November 17, 2015 to unitholders of record on November 9, 2015 . Based on the LP Units outstanding as of September 30, 2015, cash distributed to unitholders on November 17, 2015 will total $152.0 million .

EARNINGS PER UNIT

EARNINGS PER UNIT	9 Months Ended
	Sep. 30, 2015
Earnings Per Share [Abstract]
EARNINGS PER UNIT	12. EARNINGS PER UNIT The following table is a reconciliation of the weighted average units outstanding used in computing the basic and diluted earnings per unit for the periods indicated (in thousands, except per unit amounts): Three Months Ended Nine Months Ended 2015 2014 2015 2014 Net income attributable to Buckeye Partners, L.P. $ 100,040 $ 102,943 $ 303,231 $ 216,431 Basic: Weighted average units outstanding - basic 128,329 118,804 127,722 116,747 Earnings per unit - basic $ 0.78 $ 0.87 $ 2.37 $ 1.85 Diluted: Weighted average units outstanding - basic 128,329 118,804 127,722 116,747 Dilutive effect of LP Unit options and LTIP awards granted 577 625 519 558 Weighted average units outstanding - diluted 128,906 119,429 128,241 117,305 Earnings per unit - diluted $ 0.78 $ 0.86 $ 2.36 $ 1.85

BUSINESS SEGMENTS

BUSINESS SEGMENTS	9 Months Ended
	Sep. 30, 2015
Segment Reporting [Abstract]
BUSINESS SEGMENTS	13. BUSINESS SEGMENTS We operate and report in four business segments: (i) Pipelines & Terminals; (ii) Global Marine Terminals; (iii) Merchant Services; and (iv) Development & Logistics. 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. Pipelines & Terminals The Pipelines & Terminals segment receives liquid petroleum products from refineries, connecting pipelines, vessels, and bulk and marine terminals and transports those products to other locations for a fee and provides bulk storage and terminal throughput services in the continental United States. This segment owns and operates 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 Pipelines & Terminals segment. In addition, the segment has butane blending capabilities and provides crude oil services, including train off-loading, storage and throughput. Global Marine Terminals The Global Marine Terminals segment provides marine bulk storage and marine terminal throughput services in the East Coast and Gulf Coast regions of the United States and in the Caribbean. The segment has liquid petroleum product terminals located in The Bahamas, Puerto Rico and St. Lucia in the Caribbean, Corpus Christi and the New York Harbor. 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, propane, 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 Pipelines & Terminals segment. The segment’s customers consist principally of product wholesalers as well as major commercial users of these refined petroleum products. Development & Logistics The Development & Logistics segment consists primarily of our contract operations of third-party pipelines, which are owned principally by major oil and gas, petrochemical and chemical companies and are located primarily in Texas and Louisiana. Additionally, this segment performs pipeline construction management services, typically for cost plus a fixed fee. This segment also owns and operates two underground propane storage caverns in Indiana and Illinois, as well as our majority ownership of the Sabina Pipeline located in Texas. The following table summarizes revenue by each segment for the periods indicated (in thousands): Three Months Ended Nine Months Ended 2015 2014 2015 2014 Revenue: Pipelines & Terminals $ 219,942 $ 228,466 $ 652,178 $ 665,629 Global Marine Terminals 127,161 104,522 372,735 284,082 Merchant Services 386,105 1,246,462 1,586,421 4,420,205 Development & Logistics 16,553 21,003 53,610 56,637 Intersegment (21,377 ) (26,980 ) (51,677 ) (52,300 ) Total revenue $ 728,384 $ 1,573,473 $ 2,613,267 $ 5,374,253 For the three months ended September 30, 2015 and 2014 , no customers contributed 10% or more of consolidated revenue. For the nine months ended September 30, 2015 and 2014 , 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 2015 2014 2015 2014 Revenue: United States $ 644,445 $ 1,482,363 $ 2,358,622 $ 5,116,151 International 83,939 91,110 254,645 258,102 Total revenue $ 728,384 $ 1,573,473 $ 2,613,267 $ 5,374,253 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 2015 2014 2015 2014 Adjusted EBITDA from continuing operations: Pipelines & Terminals $ 116,711 $ 128,171 $ 362,503 $ 370,570 Global Marine Terminals 80,593 57,270 233,716 166,532 Merchant Services 2,592 10,468 13,797 (12,568 ) Development & Logistics 4,268 4,713 13,539 15,500 Adjusted EBITDA from continuing operations $ 204,164 $ 200,622 $ 623,555 $ 540,034 Reconciliation of Income from continuing operations to Adjusted EBITDA from continuing operations: Income from continuing operations $ 99,947 $ 107,008 $ 303,294 $ 270,486 Less: Net loss (income) attributable to noncontrolling interests 93 (785 ) 794 (2,547 ) Income from continuing operations attributable to Buckeye Partners, L.P. 100,040 106,223 304,088 267,939 Add: Interest and debt expense 43,413 43,838 127,097 127,063 Income tax expense 240 243 720 319 Depreciation and amortization (1) 54,830 45,406 164,204 131,791 Non-cash unit-based compensation expense 6,597 5,228 17,578 13,149 Acquisition and transition expense (2) 82 2,451 2,942 8,076 Litigation contingency accrual (3) 1,729 — 15,229 — Less: Amortization of unfavorable storage contracts (4) (2,767 ) (2,767 ) (8,303 ) (8,303 ) Adjusted EBITDA from continuing operations $ 204,164 $ 200,622 $ 623,555 $ 540,034 (1) Includes 100% of the depreciation and amortization expense of $12.2 million and $34.7 million for Buckeye Texas for the three and nine months ended September 30, 2015 . (2) Acquisition and transition expense consists of transaction costs, costs for transitional employees, and other employee and third party costs related to the integration of the acquired assets that are non-recurring in nature. (3) Represents an adjustment to the FERC litigation accrual. (4) Represents amortization of negative fair values allocated to certain unfavorable storage contracts acquired in connection with the BORCO acquisition.

SUPPLEMENTAL CASH FLOW INFORMAT

SUPPLEMENTAL CASH FLOW INFORMATION	9 Months Ended
	Sep. 30, 2015
Supplemental Cash Flow Elements [Abstract]
SUPPLEMENTAL CASH FLOW INFORMATION	14. SUPPLEMENTAL CASH FLOW INFORMATION Supplemental cash flows and non-cash transactions were as follows for the periods indicated (in thousands): Nine Months Ended 2015 2014 Cash paid for interest (net of capitalized interest) $ 126,203 $ 130,323 Cash paid for income taxes 1,562 620 Capitalized interest 16,897 5,641 Non-cash investing activities: Increase (decrease) in accounts payable and accrued and other current liabilities related to capital expenditures $ 43,315 $ (25,860 )

ORGANIZATION AND BASIS OF PRE22

ORGANIZATION AND BASIS OF PRESENTATION (Policies)	9 Months Ended
	Sep. 30, 2015
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 (“NYSE”) under the ticker symbol “BPL.” Buckeye GP LLC (“Buckeye GP”) is our general partner. As used in these Notes to Unaudited Condensed Consolidated Financial Statements, “ we ,” “ us ,” “ our ” and “ Buckeye ” mean Buckeye Partners, L.P. and, where the context requires, includes our subsidiaries. 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, miles of pipeline and 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 flagship marine terminal in The Bahamas, 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 petroleum products. Our network of marine terminals enables us to facilitate global flows of crude oil, refined petroleum products, and other commodities, and to offer our customers connectivity to some of the world’s most important bulk storage and blending hubs. In September 2014, we expanded our network of marine midstream assets by acquiring a controlling interest in a company with assets located in Corpus Christi and the Eagle Ford play in Texas. We are also a wholesale distributor of refined petroleum products in certain areas served by our pipelines and terminals. Finally, Buckeye operates and/or maintains third-party pipelines under agreements with major oil and gas, petrochemical and chemical companies, and performs certain engineering and construction management services for third parties. On December 31, 2014, we completed the sale of our Natural Gas Storage disposal group and have reported the final working capital adjustments as discontinued operations in the first quarter of 2015. For additional information, see our Annual Report on Form 10-K for the year ended December 31, 2014.
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 (“VIE”) 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, 2014 .
Recent Accounting Developments	Recent Accounting Developments Business Combinations . In September 2015, the Financial Accounting Standards Board (“FASB”) issued guidance to simplify the accounting for adjustments made to provisional amounts recognized in a business combination. The amendments require that an acquirer recognize adjustments to provisional amounts identified during the measurement period in the reporting period in which the adjustment amounts are determined. This eliminates the requirement to retrospectively account for such adjustments. The guidance is effective prospectively for annual reporting periods beginning after December 15, 2015, 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. Inventory . In August 2015, the FASB issued guidance to simplify the measurement of inventory. The amendments require inventory to be measured at the lower of cost or net realizable value. Net realizable value is defined as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The guidance is effective prospectively for annual reporting periods beginning after December 15, 2016, 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. Revenue from Contracts with Customers . In July 2015, the FASB deferred the effective date of guidance that was originally issued in May 2014 to clarify principles used to recognize revenue for all entities. The guidance is now effective for annual and interim periods beginning after December 15, 2017, with early adoption permitted for annual and interim periods beginning after December 15, 2016. The standard’s core principle is that an entity will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In doing so, entities will need to use more judgment and make more estimates than under current guidance. These may include identifying performance obligations in the contract, estimating the amount of variable consideration included in the transaction price and/or allocating the transaction price to each separate performance obligation. We are currently evaluating the impact the adoption of this guidance will have on our consolidated financial statements. Debt Issuance Costs . In April 2015, the FASB issued guidance to simplify the presentation of debt issuance costs. The amendments require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. In August 2015, the FASB issued clarifying guidance allowing entities to present debt issuance costs related to line-of-credit arrangements as an asset, which must be subsequently amortized ratably over the term of the arrangement. The guidance is effective for annual reporting periods beginning after December 15, 2015, 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. Consolidations . In February 2015, the FASB issued guidance changing the criteria for reporting entities that are required to evaluate whether they should consolidate certain legal entities. The amendments require additional testing to determine if a legal entity qualifies as a VIE and whether the entity should be consolidated. These provisions are effective prospectively for annual reporting periods beginning after December 15, 2015, 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, 2015
ExxonMobil Pipeline
Statement
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 as follows (in thousands): Property, plant and equipment $ 5,541 Goodwill 7,114 Asset retirement obligation (4,200 ) Environmental liabilities (653 ) Allocated purchase price $ 7,802
Buckeye Texas
Statement
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): Current assets $ 23,061 Property, plant and equipment 527,390 Intangible assets 376,000 Goodwill 167,379 Current liabilities (54,943 ) Noncontrolling interests (207,778 ) Allocated purchase price $ 831,109

INVENTORIES (Tables)

INVENTORIES (Tables)	9 Months Ended
	Sep. 30, 2015
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) $ 219,043 $ 226,898 Materials and supplies 17,127 16,577 Total inventories $ 236,170 $ 243,475 (1) Ending inventory was 142.8 million and 140.3 million gallons of liquid petroleum products as of September 30, 2015 and December 31, 2014 , respectively.

PREPAID OTHER CURRENT ASSETS (T

PREPAID OTHER CURRENT ASSETS (Tables)	9 Months Ended
	Sep. 30, 2015
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 $ 12,790 $ 9,918 Unbilled revenue 3,403 3,556 Prepaid taxes 7,868 2,492 Other 9,773 9,089 Total prepaid and other current assets $ 33,834 $ 25,055

EQUITY INVESTMENTS (Tables)

EQUITY INVESTMENTS (Tables)	9 Months Ended
	Sep. 30, 2015
Equity Method Investments and Joint Ventures [Abstract]
Earnings from equity investments	The following table presents earnings from equity investments for the periods indicated (in thousands): Three Months Ended Nine Months Ended 2015 2014 2015 2014 West Shore Pipe Line Company $ 2,033 $ 1,551 $ 6,209 $ 3,734 Muskegon Pipeline LLC (2,761 ) 470 (3,345 ) 1,041 Transport4, LLC 183 109 456 362 South Portland Terminal LLC 515 393 1,230 822 Total (loss) earnings from equity investments $ (30 ) $ 2,523 $ 4,550 $ 5,959
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 2015 2014 2015 2014 Revenue $ 24,440 $ 23,872 $ 68,786 $ 65,337 Costs and expenses (16,642 ) (14,168 ) (43,256 ) (38,813 ) Non-operating expenses (4,033 ) (3,261 ) (11,690 ) (8,841 ) Net income $ 3,765 $ 6,443 $ 13,840 $ 17,683

DERIVATIVE INSTRUMENTS AND HE27

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables)	9 Months Ended
	Sep. 30, 2015
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, 2015 (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 22,976 2,321 Mark-to-market Physical index derivative contracts 55,751 — Mark-to-market Futures contracts for refined petroleum products 24,361 3,024 Mark-to-market Derivatives designated as hedging instruments: Futures contracts for refined petroleum products 132,132 — Fair Value Hedge Futures contracts for refined petroleum products 33,600 — Cash Flow 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 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, 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 $ 20,445 $ — $ 20,445 $ (18 ) $ 20,427 Physical index derivative contracts 49 — 49 (17 ) 32 Futures contracts for refined products 110,154 63,412 173,566 (143,342 ) 30,224 Total current derivative assets 130,648 63,412 194,060 (143,377 ) 50,683 Physical fixed price derivative contracts 377 — 377 (6 ) 371 Futures contracts for refined products 1 — 1 — 1 Total non-current derivative assets 378 — 378 (6 ) 372 Physical fixed price derivative contracts (1,178 ) — (1,178 ) 18 (1,160 ) Physical index derivative contracts (309 ) — (309 ) 17 (292 ) Futures contracts for refined products (139,173 ) (4,169 ) (143,342 ) 143,342 — Total current derivative liabilities (140,660 ) (4,169 ) (144,829 ) 143,377 (1,452 ) Physical fixed price derivative contracts (28 ) — (28 ) 6 (22 ) Futures contracts for refined products (216 ) — (216 ) — (216 ) Total non-current derivative liabilities (244 ) — (244 ) 6 (238 ) Net derivative (liabilities) assets $ (9,878 ) $ 59,243 $ 49,365 $ — $ 49,365 (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, 2014 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 $ 42,005 $ — $ 42,005 $ (12 ) $ 41,993 Physical index derivative contracts 112 — 112 (59 ) 53 Futures contracts for refined products 150,352 30,702 181,054 (153,911 ) 27,143 Total current derivative assets 192,469 30,702 223,171 (153,982 ) 69,189 Physical fixed price derivative contracts 2,919 — 2,919 — 2,919 Total non-current derivative assets 2,919 — 2,919 — 2,919 Physical fixed price derivative contracts (1,502 ) — (1,502 ) 12 (1,490 ) Physical index derivative contracts (371 ) — (371 ) 59 (312 ) Futures contracts for refined products (153,911 ) — (153,911 ) 153,911 — Total current derivative liabilities (155,784 ) — (155,784 ) 153,982 (1,802 ) Physical fixed price derivative contracts (5 ) — (5 ) — (5 ) Futures contracts for refined products (2,615 ) — (2,615 ) — (2,615 ) Total non-current derivative liabilities (2,620 ) — (2,620 ) — (2,620 ) Net derivative assets $ 36,984 $ 30,702 $ 67,686 $ — $ 67,686 (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 2015 2014 2015 2014 Derivatives NOT designated as hedging instruments: Physical fixed price derivative contracts Product sales $ 15,731 $ 16,065 $ 19,660 $ 5,413 Physical index derivative contracts Product sales (299 ) (37 ) (309 ) (110 ) Physical fixed price derivative contracts Cost of product sales 3,600 (1,442 ) 10,191 7,179 Physical index derivative contracts Cost of product sales (288 ) 207 (224 ) (506 ) Futures contracts for refined products Cost of product sales (10,992 ) (997 ) 2,591 (810 ) Derivatives designated as fair value hedging instruments: Futures contracts for refined products Cost of product sales $ 54,514 $ 35,717 $ 21,959 $ 23,264 Physical inventory - hedged items Cost of product sales (55,424 ) (34,041 ) (34,848 ) (32,312 ) Ineffectiveness excluding the time value component on fair value hedging instruments: Fair value hedge ineffectiveness (excluding time value) Cost of product sales $ 2,626 $ 2,914 $ 2,476 $ 6,524 Time value excluded from hedge assessment Cost of product sales (3,536 ) (1,238 ) (15,365 ) (15,572 ) Net (loss) gain in income $ (910 ) $ 1,676 $ (12,889 ) $ (9,048 )
Chande in value recognized in OCI on derivatives	The change in value recognized in OCI and the losses reclassified from accumulated other comprehensive income (“AOCI”) to income attributable to our derivative instruments designated as cash flow hedges were as follows for the periods indicated (in thousands): Gain (Loss) Recognized in OCI on Derivatives for the Three Months Ended Nine Months Ended 2015 2014 2015 2014 Derivatives designated as cash flow hedging instruments: Interest rate contracts $ — $ (2,612 ) $ — $ (21,424 ) Commodity derivatives 11,168 — 7,311 — Total $ 11,168 $ (2,612 ) $ 7,311 $ (21,424 )
Losses reclassified from AOCI to income (effective portion)	Loss Reclassified from AOCI to Income (Effective Portion) for the Three Months Ended Nine Months Ended Location 2015 2014 2015 2014 Derivatives designated as cash flow hedging instruments: Interest rate contracts Interest and debt expense $ (3,037 ) $ (3,159 ) $ (9,113 ) $ (6,716 ) Total $ (3,037 ) $ (3,159 ) $ (9,113 ) $ (6,716 )

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	9 Months Ended
	Sep. 30, 2015
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, 2015 December 31, 2014 Level 1 Level 2 Level 1 Level 2 Financial assets: Physical fixed price derivative contracts $ — $ 20,798 $ — $ 44,912 Physical index derivative contracts — 32 — 53 Futures contracts for refined products 30,225 — 27,143 — Financial liabilities: Physical fixed price derivative contracts — (1,182 ) — (1,495 ) Physical index derivative contracts — (292 ) — (312 ) Futures contracts for refined products (216 ) — (2,615 ) — Fair value $ 30,009 $ 19,356 $ 24,528 $ 43,158
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, 2015 December 31, 2014 Carrying Amount Fair Value Carrying Amount Fair Value Fixed-rate debt $ 3,389,843 $ 3,284,534 $ 3,388,986 $ 3,465,973 Variable-rate debt 391,450 391,450 166,000 166,000 Total debt $ 3,781,293 $ 3,675,984 $ 3,554,986 $ 3,631,973

PENSIONS AND OTHER POSTRETIRE29

PENSIONS AND OTHER POSTRETIREMENT BENEFITS (Tables)	9 Months Ended
	Sep. 30, 2015
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 months ended September 30, 2015 and 2014 (in thousands): RIGP Retiree Medical Plan Three Months Ended Three Months Ended 2015 2014 2015 2014 Service cost $ 3 $ 54 $ 92 $ 108 Interest cost 137 134 333 352 Expected return on plan assets (84 ) (98 ) — — Amortization of prior service credit — — — (406 ) Amortization of unrecognized losses 211 308 50 299 Actuarial loss due to settlements 451 193 — — Net periodic benefit cost $ 718 $ 591 $ 475 $ 353 The components of the net periodic benefit cost for the RIGP and the Retiree Medical Plan were as follows for the nine months ended September 30, 2015 and 2014 (in thousands): RIGP Retiree Medical Plan Nine Months Ended Nine Months Ended 2015 2014 2015 2014 Service cost $ 9 $ 163 $ 274 $ 323 Interest cost 413 403 1,000 1,056 Expected return on plan assets (251 ) (294 ) — — Amortization of prior service credit — — — (1,218 ) Amortization of unrecognized losses 632 924 149 895 Actuarial loss due to settlements 451 580 — — Net periodic benefit cost $ 1,254 $ 1,776 $ 1,423 $ 1,056

UNIT-BASED COMPENSATION PLANS (

UNIT-BASED COMPENSATION PLANS (Tables)	9 Months Ended
	Sep. 30, 2015
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, 2015 906 $ 63.56 Granted 435 73.45 Vested (262 ) 63.73 Forfeited (17 ) 67.08 Unvested at September 30, 2015 1,062 $ 67.50
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, 2015 26 $ 48.18 1.6 $ 703 Exercised (4 ) 48.12 Forfeited, cancelled or expired (2 ) 45.88 Outstanding at September 30, 2015 20 48.44 1.1 $ 216 Exercisable at September 30, 2015 20 $ 48.44 1.1 $ 216 (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 2015 and the exercise price, multiplied by the number of exercisable, in-the-money options.

PARTNERS' CAPITAL AND DISTRIB31

PARTNERS' CAPITAL AND DISTRIBUTIONS (Tables)	9 Months Ended
	Sep. 30, 2015
Equity [Abstract]
Summary of changes in LP units outstanding	The following is a summary of changes in LP Units outstanding for the periods indicated (in thousands): Limited Partners Outstanding at January 1, 2015 127,043 LP Units issued pursuant to the Option Plan (1) 4 LP Units issued pursuant to the LTIP (1) 198 Issuance of LP Units through Equity Distribution Agreements 1,591 Outstanding at September 30, 2015 128,836 (1) The number of units issued represents issuance net of tax withholding.

EARNINGS PER UNIT (Tables)

EARNINGS PER UNIT (Tables)	9 Months Ended
	Sep. 30, 2015
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 2015 2014 2015 2014 Net income attributable to Buckeye Partners, L.P. $ 100,040 $ 102,943 $ 303,231 $ 216,431 Basic: Weighted average units outstanding - basic 128,329 118,804 127,722 116,747 Earnings per unit - basic $ 0.78 $ 0.87 $ 2.37 $ 1.85 Diluted: Weighted average units outstanding - basic 128,329 118,804 127,722 116,747 Dilutive effect of LP Unit options and LTIP awards granted 577 625 519 558 Weighted average units outstanding - diluted 128,906 119,429 128,241 117,305 Earnings per unit - diluted $ 0.78 $ 0.86 $ 2.36 $ 1.85

BUSINESS SEGMENTS (Tables)

BUSINESS SEGMENTS (Tables)	9 Months Ended
	Sep. 30, 2015
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 2015 2014 2015 2014 Revenue: Pipelines & Terminals $ 219,942 $ 228,466 $ 652,178 $ 665,629 Global Marine Terminals 127,161 104,522 372,735 284,082 Merchant Services 386,105 1,246,462 1,586,421 4,420,205 Development & Logistics 16,553 21,003 53,610 56,637 Intersegment (21,377 ) (26,980 ) (51,677 ) (52,300 ) Total revenue $ 728,384 $ 1,573,473 $ 2,613,267 $ 5,374,253
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 2015 2014 2015 2014 Revenue: United States $ 644,445 $ 1,482,363 $ 2,358,622 $ 5,116,151 International 83,939 91,110 254,645 258,102 Total revenue $ 728,384 $ 1,573,473 $ 2,613,267 $ 5,374,253
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 2015 2014 2015 2014 Adjusted EBITDA from continuing operations: Pipelines & Terminals $ 116,711 $ 128,171 $ 362,503 $ 370,570 Global Marine Terminals 80,593 57,270 233,716 166,532 Merchant Services 2,592 10,468 13,797 (12,568 ) Development & Logistics 4,268 4,713 13,539 15,500 Adjusted EBITDA from continuing operations $ 204,164 $ 200,622 $ 623,555 $ 540,034 Reconciliation of Income from continuing operations to Adjusted EBITDA from continuing operations: Income from continuing operations $ 99,947 $ 107,008 $ 303,294 $ 270,486 Less: Net loss (income) attributable to noncontrolling interests 93 (785 ) 794 (2,547 ) Income from continuing operations attributable to Buckeye Partners, L.P. 100,040 106,223 304,088 267,939 Add: Interest and debt expense 43,413 43,838 127,097 127,063 Income tax expense 240 243 720 319 Depreciation and amortization (1) 54,830 45,406 164,204 131,791 Non-cash unit-based compensation expense 6,597 5,228 17,578 13,149 Acquisition and transition expense (2) 82 2,451 2,942 8,076 Litigation contingency accrual (3) 1,729 — 15,229 — Less: Amortization of unfavorable storage contracts (4) (2,767 ) (2,767 ) (8,303 ) (8,303 ) Adjusted EBITDA from continuing operations $ 204,164 $ 200,622 $ 623,555 $ 540,034 (1) Includes 100% of the depreciation and amortization expense of $12.2 million and $34.7 million for Buckeye Texas for the three and nine months ended September 30, 2015 . (2) Acquisition and transition expense consists of transaction costs, costs for transitional employees, and other employee and third party costs related to the integration of the acquired assets that are non-recurring in nature. (3) Represents an adjustment to the FERC litigation accrual. (4) Represents amortization of negative fair values allocated to certain unfavorable storage contracts acquired in connection with the BORCO acquisition.

SUPPLEMENTAL CASH FLOW INFORM34

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)	9 Months Ended
	Sep. 30, 2015
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 2015 2014 Cash paid for interest (net of capitalized interest) $ 126,203 $ 130,323 Cash paid for income taxes 1,562 620 Capitalized interest 16,897 5,641 Non-cash investing activities: Increase (decrease) in accounts payable and accrued and other current liabilities related to capital expenditures $ 43,315 $ (25,860 )

ACQUISITIONS (Details)

ACQUISITIONS (Details) $ in Thousands	1 Months Ended			3 Months Ended	9 Months Ended
	May. 31, 2015USD ($)	Apr. 30, 2015USD ($)	Sep. 30, 2014USD ($)facilitiysplitter	Mar. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)	Dec. 31, 2014USD ($)
Acquisition cost and other information
Payment to acquire business					$ 10,044	$ 9,510
Assets acquired and liabilities assumed
Goodwill					$ 995,236		$ 993,375
Buckeye Memphis
Acquisition cost and other information
Payment to acquire business		$ 10,000
Additional interest acquired, percentage		0.10
Ownership interest percentage, after acquisition		100.00%
ExxonMobil Pipeline
Acquisition cost and other information
Consideration for business acquisition	$ 5,800
Assets acquired and liabilities assumed
Property, plant and equipment	5,541
Goodwill	7,114
Asset retirement obligation	(4,200)
Environmental liabilities	(653)
Allocated purchase price	$ 7,802
ExxonMobil Terminal
Acquisition cost and other information
Consideration for business acquisition				$ 2,000
Condensate splitters | splitter			2
Crude oil and condensate gathering facilities | facilitiy			3
Buckeye Texas
Acquisition cost and other information
Consideration for business acquisition			$ 816,100
Ownership interest (as a percent)			80.00%			80.00%
Cash acquired in acquisition			$ 15,000
Working capital adjustment on acquisition of businesses			4,900
Assets acquired and liabilities assumed
Current assets			23,061			$ 23,061
Property, plant and equipment			527,390			527,390
Intangible assets			376,000			376,000
Goodwill			167,379			167,379
Current liabilities			(54,943)			(54,943)
Noncontrolling interests			(207,778)			(207,778)
Allocated purchase price			$ 831,109			$ 831,109

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - Claims and Legal Proceedings (Details)

Oct. 05, 2014USD ($)

Sep. 17, 2014airport

Aug. 05, 2014USD ($)

Feb. 22, 2013

Oct. 15, 2012airportdestinationorigin_point

Sep. 20, 2012airport

May. 25, 2012USD ($)

Sep. 30, 2015USD ($)

Jun. 30, 2015USD ($)

Dec. 31, 2014USD ($)allision

Sep. 30, 2015USD ($)

Sep. 30, 2014USD ($)

Sep. 30, 2015USD ($)berth

Oct. 29, 2015airline

Oct. 16, 2015airline

Commitments and Contingencies Disclosure

Proceeds from insurance reimbursements

$ 0

$ 737,000

Pipelines & Terminals

Commitments and Contingencies Disclosure

Litigation contingency reserve

$ 40,000,000

Increase in litigation liability reserve

$ 1,700,000

$ 13,500,000

Subsequent event

Commitments and Contingencies Disclosure

Number of airlines protesting the tariff | airline

3

Number of Airlines Seeking Late Intervention and Rehearing | airline

3

FERC Docket No. OR12-28 - Airlines Complaint against Buckeye Pipe Line Company, L.P. ("BPLC") New York City Jet Fuel Rates

Commitments and Contingencies Disclosure

Number of New York City airports included in legal action | airport

3

3

Past charges, maximum potential look-back period for repayment

2 years

FERC Docket No. OR13-3 - BPLC's Market-Based Rate Application

Commitments and Contingencies Disclosure

Number of New York City airports included in legal action | airport

3

Number of origin points | origin_point

3

Number of destinations | destination

5

BORCO facility jetty collision damage

Commitments and Contingencies Disclosure

Cost of repairs

23,000,000

Limitation claimed by defendant to damages sought in legal proceedings

$ 17,000,000

Loss on disposal to assets destroyed, recorded receivable for loss on disposal

6,400,000

6,400,000

$ 6,400,000

Insurance deductible

$ 5,000,000

Proceeds from insurance reimbursements

16,000,000

Gain recognized during the period

0

0

0

Deferred gain representing excess proceeds received over loss on disposal and other costs incurred

14,100,000

14,100,000

14,100,000

Pennsauken Allisions

Commitments and Contingencies Disclosure

Number of allisions | allision

2

Cost of repairs

$ 7,000,000

$ 8,000,000

$ 1,300,000

Number of vessel berths | berth

2

Limitation claimed by defendant to damages sought in legal proceedings

$ 19,000,000

Pennsauken Allisions | Other Non-current Assets

Commitments and Contingencies Disclosure

Loss on disposal to assets destroyed, recorded receivable for loss on disposal

$ 1,300,000

$ 1,300,000

$ 1,300,000

Pennsauken Allisions | Tug Owner

Commitments and Contingencies Disclosure

Limitation claimed by defendant to damages sought in legal proceedings

1,000,000

Pennsauken Allisions | Barge Owner

Commitments and Contingencies Disclosure

Limitation claimed by defendant to damages sought in legal proceedings

$ 5,000,000

COMMITMENTS AND CONTINGENCIES37

COMMITMENTS AND CONTINGENCIES - Environmental Contingencies (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Commitments and Contingencies Disclosure
Operating expenses, net of insurance recoveries related to environmental liabilities	$ 1,729	$ 0	$ 15,229	$ 0
Environmental remediation unrelated to claims and legal proceedings
Commitments and Contingencies Disclosure
Operating expenses, net of insurance recoveries related to environmental liabilities	1,700	$ 2,000	4,500	$ 4,200
Environmental remediation liabilities	48,400		48,400		$ 52,300
Receivables related to environmental remediation expenditures covered by insurance or third party claims	$ 12,900		$ 12,900		$ 13,600

INVENTORIES (Details)

INVENTORIES (Details) $ in Thousands, gal in Millions	Sep. 30, 2015USD ($)gal	Dec. 31, 2014USD ($)gal
Inventory Disclosure [Abstract]
Liquid petroleum products	$ 219,043	$ 226,898
Materials and supplies	17,127	16,577
Total inventories	$ 236,170	$ 243,475
Energy Related Inventory [Abstract]
Refined petroleum products (in gallons) | gal	142.8	140.3
Percentage of hedged refined petroleum products inventory	93.00%	90.00%

PREPAID OTHER CURRENT ASSETS (D

PREPAID OTHER CURRENT ASSETS (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Prepaid insurance	$ 12,790	$ 9,918
Unbilled revenue	3,403	3,556
Prepaid taxes	7,868	2,492
Other	9,773	9,089
Total prepaid and other current assets	$ 33,834	$ 25,055

EQUITY INVESTMENTS - Equity Inv

EQUITY INVESTMENTS - Equity Investments (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Equity investments
Total (loss) earnings from equity investments	$ (30)	$ 2,523	$ 4,550	$ 5,959
West Shore Pipe Line Company
Equity investments
Total (loss) earnings from equity investments	2,033	1,551	6,209	3,734
Muskegon Pipeline LLC
Equity investments
Total (loss) earnings from equity investments	(2,761)	470	(3,345)	1,041
Transport4, LLC
Equity investments
Total (loss) earnings from equity investments	183	109	456	362
South Portland Terminal LLC
Equity investments
Total (loss) earnings from equity investments	$ 515	$ 393	$ 1,230	$ 822

EQUITY INVESTMENTS - Income Fro

EQUITY INVESTMENTS - Income From Equity Method Investments (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
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	$ 24,440	$ 23,872	$ 68,786	$ 65,337
Costs and expenses	(16,642)	(14,168)	(43,256)	(38,813)
Non-operating expenses	(4,033)	(3,261)	(11,690)	(8,841)
Net income	$ 3,765	$ 6,443	$ 13,840	$ 17,683

DERIVATIVE INSTRUMENTS AND HE42

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Commodity Derivative Instruments (Details) gal in Thousands	9 Months Ended
	Sep. 30, 2015gal
Derivatives NOT Designated as Hedging Instruments | Physical fixed price derivative contracts | Current
Derivative Instruments And Hedging Activities
Volume	22,976
Derivatives NOT Designated as Hedging Instruments | Physical fixed price derivative contracts | Long-Term
Derivative Instruments And Hedging Activities
Volume	2,321
Derivatives NOT Designated as Hedging Instruments | Physical index derivative contracts | Current
Derivative Instruments And Hedging Activities
Volume	55,751
Derivatives NOT Designated as Hedging Instruments | Physical index derivative contracts | Long-Term
Derivative Instruments And Hedging Activities
Volume	0
Derivatives NOT Designated as Hedging Instruments | Futures contracts for refined petroleum products | Futures contracts | Current
Derivative Instruments And Hedging Activities
Volume	24,361
Derivatives NOT Designated as Hedging Instruments | Futures contracts for refined petroleum products | Futures contracts | Long-Term
Derivative Instruments And Hedging Activities
Volume	3,024
Derivatives Designated as Hedging Instruments | Fair Value Hedge | Futures contracts for refined petroleum products | Futures contracts | Current
Derivative Instruments And Hedging Activities
Volume	132,132
Derivatives Designated as Hedging Instruments | Fair Value Hedge | Futures contracts for refined petroleum products | Futures contracts | Long-Term
Derivative Instruments And Hedging Activities
Volume	0
Derivatives Designated as Hedging Instruments | Cash Flow Hedge | Futures contracts for refined petroleum products | Futures contracts | Current
Derivative Instruments And Hedging Activities
Volume	33,600
Derivatives Designated as Hedging Instruments | Cash Flow Hedge | Futures contracts for refined petroleum products | Futures contracts | Long-Term
Derivative Instruments And Hedging Activities
Volume	0

DERIVATIVE INSTRUMENTS AND HE43

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Fair Value of Each Classification of Derivative Instrument (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Derivatives, Fair Value
Fair value	$ 49,365	$ 67,686
Netting balance sheet adjustment	0	0
Net Total
Derivatives, Fair Value
Fair value	49,365	67,686
Derivatives NOT Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	(9,878)	36,984
Derivatives Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	59,243	30,702
Total current derivative assets
Derivatives, Fair Value
Fair value	194,060	223,171
Netting balance sheet adjustment	(143,377)	(153,982)
Total current derivative assets | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	20,445	42,005
Netting balance sheet adjustment	(18)	(12)
Total current derivative assets | Physical index derivative contracts
Derivatives, Fair Value
Fair value	49	112
Netting balance sheet adjustment	(17)	(59)
Total current derivative assets | Futures contracts for refined petroleum products | Futures contracts
Derivatives, Fair Value
Fair value	173,566	181,054
Netting balance sheet adjustment	(143,342)	(153,911)
Total current derivative assets | Net Total
Derivatives, Fair Value
Fair value	50,683	69,189
Total current derivative assets | Net Total | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	20,427	41,993
Total current derivative assets | Net Total | Physical index derivative contracts
Derivatives, Fair Value
Fair value	32	53
Total current derivative assets | Net Total | Futures contracts for refined petroleum products | Futures contracts
Derivatives, Fair Value
Fair value	30,224	27,143
Total current derivative assets | Derivatives NOT Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	130,648	192,469
Total current derivative assets | Derivatives NOT Designated as Hedging Instruments | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	20,445	42,005
Total current derivative assets | Derivatives NOT Designated as Hedging Instruments | Physical index derivative contracts
Derivatives, Fair Value
Fair value	49	112
Total current derivative assets | Derivatives NOT Designated as Hedging Instruments | Futures contracts for refined petroleum products | Futures contracts
Derivatives, Fair Value
Fair value	110,154	150,352
Total current derivative assets | Derivatives Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	63,412	30,702
Total current derivative assets | Derivatives Designated as Hedging Instruments | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	0	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 | Futures contracts
Derivatives, Fair Value
Fair value	63,412	30,702
Total non-current derivative assets
Derivatives, Fair Value
Fair value	378	2,919
Netting balance sheet adjustment	(6)	0
Total non-current derivative assets | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	377	2,919
Netting balance sheet adjustment	(6)	0
Total non-current derivative assets | Futures contracts for refined petroleum products | Futures contracts
Derivatives, Fair Value
Fair value	1
Netting balance sheet adjustment	0
Total non-current derivative assets | Net Total
Derivatives, Fair Value
Fair value	372	2,919
Total non-current derivative assets | Net Total | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	371	2,919
Total non-current derivative assets | Net Total | Futures contracts for refined petroleum products | Futures contracts
Derivatives, Fair Value
Fair value	1
Total non-current derivative assets | Derivatives NOT Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	378	2,919
Total non-current derivative assets | Derivatives NOT Designated as Hedging Instruments | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	377	2,919
Total non-current derivative assets | Derivatives NOT Designated as Hedging Instruments | Futures contracts for refined petroleum products | Futures contracts
Derivatives, Fair Value
Fair value	1
Total non-current derivative assets | Derivatives Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	0	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 | Futures contracts
Derivatives, Fair Value
Fair value	0
Total current derivative liabilities
Derivatives, Fair Value
Fair value	(144,829)	(155,784)
Netting balance sheet adjustment	143,377	153,982
Total current derivative liabilities | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	(1,178)	(1,502)
Netting balance sheet adjustment	18	12
Total current derivative liabilities | Physical index derivative contracts
Derivatives, Fair Value
Fair value	(309)	(371)
Netting balance sheet adjustment	17	59
Total current derivative liabilities | Futures contracts for refined petroleum products | Futures contracts
Derivatives, Fair Value
Fair value	(143,342)	(153,911)
Netting balance sheet adjustment	143,342	153,911
Total current derivative liabilities | Net Total
Derivatives, Fair Value
Fair value	(1,452)	(1,802)
Total current derivative liabilities | Net Total | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	(1,160)	(1,490)
Total current derivative liabilities | Net Total | Physical index derivative contracts
Derivatives, Fair Value
Fair value	(292)	(312)
Total current derivative liabilities | Net Total | Futures contracts for refined petroleum products | Futures contracts
Derivatives, Fair Value
Fair value	0	0
Total current derivative liabilities | Derivatives NOT Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	(140,660)	(155,784)
Total current derivative liabilities | Derivatives NOT Designated as Hedging Instruments | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	(1,178)	(1,502)
Total current derivative liabilities | Derivatives NOT Designated as Hedging Instruments | Physical index derivative contracts
Derivatives, Fair Value
Fair value	(309)	(371)
Total current derivative liabilities | Derivatives NOT Designated as Hedging Instruments | Futures contracts for refined petroleum products | Futures contracts
Derivatives, Fair Value
Fair value	(139,173)	(153,911)
Total current derivative liabilities | Derivatives Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	(4,169)	0
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 | Futures contracts
Derivatives, Fair Value
Fair value	(4,169)	0
Total non-current derivative liabilities
Derivatives, Fair Value
Fair value	(244)	(2,620)
Netting balance sheet adjustment	6	0
Total non-current derivative liabilities | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	(28)	(5)
Netting balance sheet adjustment	6	0
Total non-current derivative liabilities | Futures contracts for refined petroleum products | Futures contracts
Derivatives, Fair Value
Fair value	(216)	(2,615)
Netting balance sheet adjustment	0	0
Total non-current derivative liabilities | Net Total
Derivatives, Fair Value
Fair value	(238)	(2,620)
Total non-current derivative liabilities | Net Total | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	(22)	(5)
Total non-current derivative liabilities | Net Total | Futures contracts for refined petroleum products | Futures contracts
Derivatives, Fair Value
Fair value	(216)	(2,615)
Total non-current derivative liabilities | Derivatives NOT Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	(244)	(2,620)
Total non-current derivative liabilities | Derivatives NOT Designated as Hedging Instruments | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	(28)	(5)
Total non-current derivative liabilities | Derivatives NOT Designated as Hedging Instruments | Futures contracts for refined petroleum products | Futures contracts
Derivatives, Fair Value
Fair value	(216)	(2,615)
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	0
Total non-current derivative liabilities | Derivatives Designated as Hedging Instruments | Futures contracts for refined petroleum products | Futures contracts
Derivatives, Fair Value
Fair value	$ 0	$ 0

DERIVATIVE INSTRUMENTS AND HE44

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Gains and Losses on Derivative Instruments (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Hedge Ineffectiveness
Ineffectiveness excluding the time value component on fair value hedging instruments:
Net (loss) gain in income	$ (910)	$ 1,676	$ (12,889)	$ (9,048)
Futures contracts
Derivatives designated as fair value hedging instruments:
Futures contracts for refined products			51,900
Futures contracts for refined petroleum products
Derivatives designated as fair value hedging instruments:
Futures contracts for refined products			7,300
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	15,731	16,065	19,660	5,413
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	(299)	(37)	(309)	(110)
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	3,600	(1,442)	10,191	7,179
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	(288)	207	(224)	(506)
Derivatives NOT Designated as Hedging Instruments | Cost of product sales | Futures contracts for refined petroleum products | Futures contracts
Derivatives NOT designated as hedging instruments:
Gains (losses) on derivative instruments recognized in income	(10,992)	(997)	2,591	(810)
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)	2,626	2,914	2,476	6,524
Time value excluded from hedge assessment	(3,536)	(1,238)	(15,365)	(15,572)
Derivatives Designated as Hedging Instruments | Cost of product sales | Futures contracts for refined petroleum products
Derivatives designated as fair value hedging instruments:
Physical inventory - hedged items	(55,424)	(34,041)	(34,848)	(32,312)
Derivatives Designated as Hedging Instruments | Cost of product sales | Futures contracts for refined petroleum products | Futures contracts
Derivatives designated as fair value hedging instruments:
Futures contracts for refined products	$ 54,514	$ 35,717	$ 21,959	$ 23,264

DERIVATIVE INSTRUMENTS AND HE45

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Changes in Value Recognized in OCI (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Futures contracts for refined petroleum products
Losses reclassified from AOCI to income
Futures contracts for refined products			$ 7,300
Interest rate contracts
Losses reclassified from AOCI to income
Cash flow hedge loss to be reclassified within twelve months			12,200
Cash Flow Hedge
Losses reclassified from AOCI to income
Change in value recognized in OCI on derivatives	$ 11,168	$ (2,612)	7,311	$ (21,424)
Loss reclassified from AOCI to income (effective portion)	(3,037)	(3,159)	(9,113)	(6,716)
Cash Flow Hedge | Interest rate contracts
Losses reclassified from AOCI to income
Change in value recognized in OCI on derivatives	0	(2,612)	0	(21,424)
Cash Flow Hedge | Commodity derivatives
Losses reclassified from AOCI to income
Change in value recognized in OCI on derivatives	11,168	0	7,311	0
Interest and debt expense | Cash Flow Hedge | Interest rate contracts
Losses reclassified from AOCI to income
Loss reclassified from AOCI to income (effective portion)	$ (3,037)	$ (3,159)	$ (9,113)	$ (6,716)

FAIR VALUE MEASUREMENTS - Asset

FAIR VALUE MEASUREMENTS - Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Fair value measurements
Fair value	$ 49,365	$ 67,686
Fair Value, Measurements, Recurring | Level 1
Fair value measurements
Fair value	30,009	24,528
Fair Value, Measurements, Recurring | Level 1 | Futures contracts for refined petroleum products | Futures contracts
Fair value measurements
Financial assets	30,225	27,143
Financial liabilities	(216)	(2,615)
Fair Value, Measurements, Recurring | Level 2
Fair value measurements
Fair value	19,356	43,158
Fair Value, Measurements, Recurring | Level 2 | Physical fixed price derivative contracts
Fair value measurements
Financial assets	20,798	44,912
Financial liabilities	(1,182)	(1,495)
Level 2 fixed-price contracts assets, CVA		(100)
Fair Value, Measurements, Recurring | Level 2 | Physical index derivative contracts
Fair value measurements
Financial assets	32	53
Financial liabilities	$ (292)	$ (312)

FAIR VALUE MEASUREMENTS - Carry

FAIR VALUE MEASUREMENTS - Carrying Value and Fair Value of Debt (Details) - Level 2 - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Carrying Amount
Fair Value And Carrying Value By Balance Sheet Grouping
Total debt	$ 3,781,293	$ 3,554,986
Carrying Amount | Fixed-rate debt
Fair Value And Carrying Value By Balance Sheet Grouping
Total debt	3,389,843	3,388,986
Carrying Amount | Variable-rate debt
Fair Value And Carrying Value By Balance Sheet Grouping
Total debt	391,450	166,000
Fair Value
Fair Value And Carrying Value By Balance Sheet Grouping
Total debt	3,675,984	3,631,973
Fair Value | Fixed-rate debt
Fair Value And Carrying Value By Balance Sheet Grouping
Total debt	3,284,534	3,465,973
Fair Value | Variable-rate debt
Fair Value And Carrying Value By Balance Sheet Grouping
Total debt	$ 391,450	$ 166,000

FAIR VALUE MEASUREMENTS - Ass48

FAIR VALUE MEASUREMENTS - Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis (Details) - Fair Value, Measurements, Non-Recurring - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Fair value measurements
Fair value adjustments for asset and liability impairment	$ 0		$ 0
Natural Gas Storage
Fair value measurements
Non-cash asset impairment charge				$ 20,900,000
Reduction of non-cash impairment charge		$ (5,400,000)

PENSIONS AND OTHER POSTRETIRE49

PENSIONS AND OTHER POSTRETIREMENT BENEFITS (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Components of net periodic benefit cost:
Defined benefit plan contributions	$ 500	$ 700	$ 1,200	$ 2,100
RIGP
Components of net periodic benefit cost:
Service cost	3	54	9	163
Interest cost	137	134	413	403
Expected return on plan assets	(84)	(98)	(251)	(294)
Amortization of prior service credit	0	0	0	0
Amortization of unrecognized losses	211	308	632	924
Actuarial loss due to settlements	451	193	451	580
Net periodic benefit cost	718	591	1,254	1,776
Retiree Medical Plan
Components of net periodic benefit cost:
Service cost	92	108	274	323
Interest cost	333	352	1,000	1,056
Expected return on plan assets	0	0	0	0
Amortization of prior service credit	0	(406)	0	(1,218)
Amortization of unrecognized losses	50	299	149	895
Actuarial loss due to settlements	0	0	0	0
Net periodic benefit cost	$ 475	$ 353	$ 1,423	$ 1,056

UNIT-BASED COMPENSATION PLANS -

UNIT-BASED COMPENSATION PLANS - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013
LTIP and Option Plan
Share-based Compensation Arrangement by Share-based Payment Award
Compensation expense	$ 6.6	$ 5.2	$ 17.6	$ 13.1
Long Term Incentive Plan 2013 | Maximum
Share-based Compensation Arrangement by Share-based Payment Award
LP Units, available for issuance	2,591,003		2,591,003
Long Term Incentive Plan 2009
Share-based Compensation Arrangement by Share-based Payment Award
Awards granted (in units)			435,000
Long Term Incentive Plan 2009 | Phantom Stock Units | Employee
Share-based Compensation Arrangement by Share-based Payment Award
Awards granted (in units)			202,176
Long Term Incentive Plan 2009 | Phantom Stock Units | Employee | 2012 and 2011 Deferred Awards
Share-based Compensation Arrangement by Share-based Payment Award
Compensation awards deferred					$ 1.7	$ 2.7
Awards granted (in units)			54,592		75,870
Long Term Incentive Plan 2009 | Phantom Stock Units | Independent directors
Share-based Compensation Arrangement by Share-based Payment Award
Awards granted (in units)			22,001
Long Term Incentive Plan 2009 | Performance Shares | Employee
Share-based Compensation Arrangement by Share-based Payment Award
Awards granted (in units)			210,494

UNIT-BASED COMPENSATION PLANS51

UNIT-BASED COMPENSATION PLANS - LTIP Activity for the Period (Details) - Long Term Incentive Plan 2009 $ / shares in Units, shares in Thousands, $ in Millions	9 Months Ended
	Sep. 30, 2015USD ($)$ / sharesshares
Number of LP Units
Beginning Balance (in units) | shares	906
Granted (in units) | shares	435
Vested (in units) | shares	(262)
Forfeited (in units) | shares	(17)
Ending Balance (in units) | shares	1,062
Weighted Average Grant Date Fair Value per LP Unit
Beginning Balance (in dollars per share)	$ 63.56
Granted (in dollars per share)	73.45
Vested (in dollars per share)	63.73
Forfeited (in dollars per share)	67.08
Ending Balance (in dollars per share)	$ 67.50
Additional disclosures
Compensation expense expected to be recognized | $	$ 33.8
Unrecognized compensation cost, weighted average period of recognition (in years)	1 year 10 months 24 days

UNIT-BASED COMPENSATION PLANS52

UNIT-BASED COMPENSATION PLANS - Summary of Changes in the Options Oustanding 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, 2015	Sep. 30, 2014	Dec. 31, 2014
Number of LP Units
Beginning Balance (in units)	26
Exercised (in units)	(4)
Forfeited, cancelled or expired (in units)	(2)
Ending Balance (in units)	20		26
Exercisable (in units)	20
Weighted Average Strike Price per LP Unit
Beginning Balance (in dollars per share)	$ 48.18
Exercised (in dollars per share)	48.12
Forfeited, cancelled or expired (in dollars per share)	45.88
Ending Balance (in dollars per share)	48.44		$ 48.18
Exercisable (in dollars per share)	$ 48.44
Weighted Average Remaining Contractual Term (in years)
Weighted Average Remaining Contractual Term (in years)	1 year 1 month 6 days		1 year 7 months 6 days
Exercisable	1 year 1 month 6 days
Aggregate Intrinsic Value
Outstanding at period beginning	$ 703
Outstanding at period end	216		$ 703
Exercisable	216
Additional disclosures
Total intrinsic value of options exercised	$ 100	$ 400

PARTNERS' CAPITAL AND DISTRIB53

PARTNERS' CAPITAL AND DISTRIBUTIONS - Narrative (Details) - Limited Partners - Equity Distribution Agreements shares in Millions, $ in Millions	9 Months Ended
	Sep. 30, 2015USD ($)shares
Partner's capital and distributions
Proceeds from issuance of units	$ 117.8
Aggregate compensation expense paid to the agents under the Equity Distribution Agreements	$ 1.2
Maximum
Partner's capital and distributions
Public offering, LP units issued | shares	1.6

PARTNERS' CAPITAL AND DISTRIB54

PARTNERS' CAPITAL AND DISTRIBUTIONS - Summary of Changes in Outstanding Units (Details) - Limited Partner shares in Thousands	9 Months Ended
	Sep. 30, 2015shares
Summary of Changes in Limited Partners Units (in units)
Beginning Balance	127,043
Ending Balance	128,836
Equity Distribution Agreements
Summary of Changes in Limited Partners Units (in units)
Issuance of LP Units through Equity Distribution Agreements	1,591
Option Plan
Summary of Changes in Limited Partners Units (in units)
LP Units issued	4
Long Term Incentive Plan 2009
Summary of Changes in Limited Partners Units (in units)
LP Units issued	198

PARTNERS' CAPITAL AND DISTRIB55

PARTNERS' CAPITAL AND DISTRIBUTIONS - Distributions (Details) - USD ($) $ / shares in Units, $ in Thousands	Nov. 17, 2015	Oct. 30, 2015	Sep. 30, 2015	Sep. 30, 2014
Distributions to unitholders
Actual cash distributions			$ 439,578	$ 384,418
Limited Partners
Distributions to unitholders
Actual cash distributions			$ 442,000	$ 387,000
Limited Partners | Scenario, Forecast
Distributions to unitholders
Actual cash distributions	$ 152,000
Limited Partners | Subsequent event
Distributions to unitholders
Cash distributions declared (in dollars per unit)		$ 1.175

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, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Earnings Per Share [Abstract]
Net income attributable to Buckeye Partners, L.P.	$ 100,040	$ 102,943	$ 303,231	$ 216,431
Basic:
Weighted average units outstanding - basic (in shares)	128,329	118,804	127,722	116,747
Earnings per unit - basic (in dollars per share)	$ 0.78	$ 0.87	$ 2.37	$ 1.85
Diluted:
Weighted average units outstanding - basic (in shares)	128,329	118,804	127,722	116,747
Dilutive effect of LP Unit options and LTIP awards granted (in shares)	577	625	519	558
Weighted average units outstanding - diluted (in shares)	128,906	119,429	128,241	117,305
Earnings per unit - diluted (in dollars per share)	$ 0.78	$ 0.86	$ 2.36	$ 1.85

BUSINESS SEGMENTS - Narrative (

BUSINESS SEGMENTS - Narrative (Details)	9 Months Ended
	Sep. 30, 2015terminalsegmentpropane_storage
Segment information
Number of business segments | segment	4
Merchant Services
Segment information
Number of liquid petroleum products terminals owned	5
Pipelines & Terminals
Segment information
Number of liquid petroleum products terminals operated	5
Development & Logistics | Indiana and Illinois
Segment information
Number of underground propane storage caverns | propane_storage	2

BUSINESS SEGMENTS - Revenue by

BUSINESS SEGMENTS - Revenue by Segment (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Revenue:
Total revenue	$ 728,384	$ 1,573,473	$ 2,613,267	$ 5,374,253
United States
Revenue:
Total revenue	644,445	1,482,363	2,358,622	5,116,151
International
Revenue:
Total revenue	83,939	91,110	254,645	258,102
Operating Segments | Pipelines & Terminals
Revenue:
Total revenue	219,942	228,466	652,178	665,629
Operating Segments | Global Marine Terminals
Revenue:
Total revenue	127,161	104,522	372,735	284,082
Operating Segments | Merchant Services
Revenue:
Total revenue	386,105	1,246,462	1,586,421	4,420,205
Operating Segments | Development & Logistics
Revenue:
Total revenue	16,553	21,003	53,610	56,637
Intersegment
Revenue:
Total revenue	$ (21,377)	$ (26,980)	$ (51,677)	$ (52,300)

BUSINESS SEGMENTS - Adjusted EB

BUSINESS SEGMENTS - Adjusted EBITDA from Continuing Operations (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Segment information
Adjusted EBITDA from continuing operations	$ 204,164	$ 200,622	$ 623,555	$ 540,034
Reconciliation of Income from continuing operations to Adjusted EBITDA from continuing operations:
Income from continuing operations	99,947	107,008	303,294	270,486
Less: Net loss (income) attributable to noncontrolling interests	93	(785)	794	(2,547)
Income from continuing operations attributable to Buckeye Partners, L.P.	100,040	106,223	304,088	267,939
Add: Interest and debt expense	43,413	43,838	127,097	127,063
Income tax expense	240	243	720	319
Depreciation and amortization	54,830	45,406	164,204	131,791
Non-cash unit-based compensation expense	6,597	5,228	17,578	13,149
Acquisition and transition expense	82	2,451	2,942	8,076
Litigation contingency accrual	1,729	0	15,229	0
Less: Amortization of unfavorable storage contracts	(2,767)	(2,767)	(8,303)	(8,303)
Adjusted EBITDA from continuing operations	204,164	200,622	623,555	540,034
Pipelines & Terminals
Segment information
Adjusted EBITDA from continuing operations	116,711	128,171	362,503	370,570
Global Marine Terminals
Segment information
Adjusted EBITDA from continuing operations	80,593	57,270	233,716	166,532
Merchant Services
Segment information
Adjusted EBITDA from continuing operations	2,592	10,468	13,797	(12,568)
Development & Logistics
Segment information
Adjusted EBITDA from continuing operations	4,268	$ 4,713	13,539	$ 15,500
Buckeye Texas
Reconciliation of Income from continuing operations to Adjusted EBITDA from continuing operations:
Depreciation and amortization	$ 12,200		$ 34,700

SUPPLEMENTAL CASH FLOW INFORM60

SUPPLEMENTAL CASH FLOW INFORMATION (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Supplemental Cash Flow Elements [Abstract]
Cash paid for interest (net of capitalized interest)	$ 126,203	$ 130,323
Cash paid for income taxes	1,562	620
Capitalized interest	16,897	5,641
Non-cash investing activities:
Increase (decrease) in accounts payable and accrued and other current liabilities related to capital expenditures	$ 43,315	$ (25,860)