Buckeye Partners (BPL) 10-K 15 Feb 19 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2018	Feb. 08, 2019	Jun. 30, 2018
Document and Entity Information
Entity Registrant Name	BUCKEYE PARTNERS, L.P.
Entity Central Index Key	805,022
Document Type	10-K
Document Period End Date	Dec. 31, 2018
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Entity Public Float			$ 5.3
Entity Common Stock, Shares Outstanding		153,797,059
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	FY

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenue:
Revenue from contracts with customers	$ 3,367,487	$ 2,956,727	$ 2,601,447
Total revenue	4,108,275	3,648,145	3,248,376
Costs and expenses:
Cost of product sales	2,521,864	1,969,182	1,549,522
Operating expenses	639,769	638,103	626,582
Depreciation and amortization	269,423	269,243	254,659
General and administrative	82,393	90,975	86,098
Goodwill impairment	536,964	0	0
Gain on sale of DPTS Asset Package	(342,984)	0	0
Other, net	(16,185)	(4,722)	(5,187)
Total costs and expenses	3,691,244	2,962,781	2,511,674
Operating income	417,031	685,364	736,702
Other (expense) income:
(Loss) earnings from equity investments	(274,123)	36,005	11,536
Interest and debt expense	(190,172)	(225,583)	(194,922)
Other expense	(911)	(1,249)	(3,181)
Total other expense, net	(465,206)	(190,827)	(186,567)
(Loss) income before taxes	(48,175)	494,537	550,135
Income tax expense	(3,740)	(872)	(1,460)
Net (loss) income	(51,915)	493,665	548,675
Less: Net income attributable to noncontrolling interests	(7,123)	(14,863)	(13,067)
Net (loss) income attributable to Buckeye Partners, L.P.	$ (59,038)	$ 478,802	$ 535,608
(Loss) earnings per unit attributable to Buckeye Partners, L.P.:
Basic (in dollars per unit)	$ (0.41)	$ 3.33	$ 4.05
Diluted (in dollars per unit)	$ (0.41)	$ 3.32	$ 4.03
Weighted average units outstanding:
Basic - (in units)	152,355	142,501	132,242
Diluted (in units)	152,355	143,144	132,927
Product sales
Revenue:
Revenue from contracts with customers	$ 2,567,415	$ 2,014,980	$ 1,594,240
Transportation, storage and other services
Revenue:
Revenue from contracts with customers	$ 1,540,860	$ 1,633,165	$ 1,654,136

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Statement of Comprehensive Income [Abstract]
Net (loss) income	$ (51,915)	$ 493,665	$ 548,675
Other comprehensive (loss) income:
Unrealized gains (losses) on derivative instruments, net	29,714	(10,733)	60,281
Reclassification of derivative (gains) and losses to net income, net	(50,509)	11,922	10,884
Changes in benefit plan assets and benefit obligations	1,745	3,393	1,083
Other comprehensive (loss) income from equity method investments	(49,642)	49,642	0
Total other comprehensive (loss) income	(68,692)	54,224	72,248
Comprehensive (loss) income	(120,607)	547,889	620,923
Less: Comprehensive income attributable to noncontrolling interests	(7,123)	(14,863)	(13,067)
Comprehensive (loss) income attributable to Buckeye Partners, L.P.	$ (127,730)	$ 533,026	$ 607,856

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 1,830	$ 2,180
Accounts receivable, net	219,751	270,648
Construction and pipeline relocation receivables	14,259	11,047
Inventories	210,884	301,425
Derivative assets	18,019	34,959
Prepaid and other current assets	58,894	36,339
Total current assets	523,637	656,598
Property, plant and equipment	8,258,694	7,928,240
Less: Accumulated depreciation	(1,343,898)	(1,192,448)
Property, plant and equipment, net	6,914,796	6,735,792
Equity investments	1,111,793	1,494,412
Goodwill	470,875	1,007,313
Intangible assets	610,900	615,086
Less: Accumulated amortization	(317,589)	(256,025)
Intangible assets, net	293,311	359,061
Other non-current assets	41,138	51,483
Total assets	9,355,550	10,304,659
Current liabilities:
Line of credit	177,727	252,204
Current portion of long-term debt	525,000	0
Accounts payable	147,525	160,777
Derivative liabilities	1,320	7,172
Accrued and other current liabilities	276,193	265,207
Total current liabilities	1,127,765	685,360
Long-term debt	4,011,715	4,658,321
Other non-current liabilities	84,900	92,656
Total liabilities	5,224,380	5,436,337
Commitments and contingent liabilities (Note 5 - Commitments and Contingencies)	0	0
Buckeye Partners, L.P. capital:
Limited Partners (153,755,031 and 146,677,459 units outstanding as of December 31, 2018 and 2017, respectively)	4,160,143	4,562,306
Accumulated other comprehensive (loss) income	(40,061)	28,631
Total Buckeye Partners, L.P. capital	4,120,082	4,590,937
Noncontrolling interests	11,088	277,385
Total partners’ capital	4,131,170	4,868,322
Total liabilities and partners’ capital	$ 9,355,550	$ 10,304,659

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Dec. 31, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Limited Partners, units outstanding (in units)	153,755,031	146,677,459

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash flows from operating activities:
Net (loss) income	$ (51,915)	$ 493,665	$ 548,675
Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities:
Interest rate swap settlement deferred in comprehensive income	(50,982)	20,018	0
Depreciation and amortization	269,423	269,243	254,659
Amortization of debt issuance costs, discounts, and settled interest rate swaps	15,587	17,202	16,926
Non-cash unit-based compensation expense	21,890	30,568	33,482
Gain on sale of DPTS asset package	(342,984)	0	0
Changes in fair value of derivatives, net	(19,932)	(24,730)	103,336
Amortization of acquired storage contracts	0	0	(5,979)
Loss (earnings) from equity investments	274,123	(36,005)	(11,536)
Distributions of earnings from equity investments	24,350	35,854	3,280
Goodwill impairment	536,964	0	0
(Gain) loss on other asset retirements and disposals, net	(15,886)	(5,406)	(5,187)
Other non-cash items	4,608	3,632	7,162
Change in assets and liabilities, net of amounts related to acquisitions:
Accounts receivable, net	54,586	(28,957)	(23,646)
Construction and pipeline relocation receivables	(3,212)	6,229	(4,961)
Inventories	92,095	56,430	(162,257)
Prepaid and other current assets	(22,279)	23,278	(41,224)
Accounts payable	(25,350)	46,078	25,983
Accrued and other current liabilities	44	(4,278)	(7,347)
Other non-current assets and liabilities	6,699	(14,419)	(13,449)
Net cash provided by operating activities	767,829	888,402	717,917
Cash flows from investing activities:
Capital expenditures	(467,611)	(433,335)	(486,316)
Proceeds from sale of DPTS asset package	444,555	0	0
Proceeds from property disposals and recoveries	9,388	6,409	8,263
Acquisition of and contribution to equity investments	(42,204)	(1,387,844)	0
Distributions from equity investments in excess of earnings	76,413	31,724	2,526
Acquisitions of business, net of cash acquired	896	(26,942)	(26,025)
Proceeds from settlement of interest rate swap	50,982	0	0
Escrow returns (deposits)	0	0	19,850
Net cash provided by (used in) investing activities	72,419	(1,809,988)	(481,702)
Cash flows from financing activities:
Net proceeds from issuance of Units and exercise of Unit options	261,962	346,276	689,428
Payment of tax withholding on issuance of LTIP awards	(8,306)	(9,447)	(6,711)
Proceeds from issuance of long-term debt, net of issuance costs	394,937	394,418	841,451
Repayment of long-term debt	(700,000)	(125,000)	0
Borrowings under the BPL Credit Facility	2,391,700	1,912,872	1,007,200
Repayments under the BPL Credit Facility	(2,213,799)	(1,746,172)	(1,368,200)
Net (repayments) borrowings under the BMSC Credit Facility	(74,477)	252,204	(111,488)
Acquisition of remaining noncontrolling interest	(210,000)	0	0
Contributions from noncontrolling interests	7,400	12,000	5,000
Distributions paid to noncontrolling interests	(16,292)	(39,230)	(15,750)
Distributions to LP unitholders	(673,723)	(714,495)	(641,686)
Net cash (used in) provided by financing activities	(840,598)	283,426	399,244
Net (decrease) increase in cash and cash equivalents	(350)	(638,160)	635,459
Cash and cash equivalents — Beginning of year	2,180	640,340	4,881
Cash and cash equivalents — End of year	$ 1,830	$ 2,180	$ 640,340

CONSOLIDATED STATEMENTS OF PART

CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL - USD ($) $ in Thousands	Total	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interest	Limited Partners
Beginning balance at Dec. 31, 2015	$ 4,016,741	$ (97,841)	$ 281,352	$ 3,833,230
Increase (Decrease) in Partners' Capital [Roll Forward]
Net (loss) income	548,675		13,067	535,608
Distributions paid to unitholders	(641,686)		3,043	(644,729)
Net proceeds from issuance of LP Units	689,128			689,128
Amortization of unit-based compensation awards	33,482			33,482
Net proceeds from exercise of Unit options	300			300
Payment of tax withholding on issuance of LTIP awards	(6,711)			(6,711)
Distributions paid to noncontrolling interests	(15,750)		(15,750)
Contributions from noncontrolling interests	5,000		5,000
Other comprehensive income (loss)	72,248	72,248
Accrual of distribution equivalent rights	(3,004)			(3,004)
Other			(12)	12
Ending balance at Dec. 31, 2016	4,698,423	(25,593)	286,700	4,437,316
Increase (Decrease) in Partners' Capital [Roll Forward]
Net (loss) income	493,665		14,863	478,802
Distributions paid to unitholders	(714,495)		2,898	(717,393)
Net proceeds from issuance of LP Units	345,795			345,795
Amortization of unit-based compensation awards	30,568			30,568
Net proceeds from exercise of Unit options	481			481
Payment of tax withholding on issuance of LTIP awards	(9,447)			(9,447)
Distributions paid to noncontrolling interests	(39,230)		(39,230)
Contributions from noncontrolling interests	12,000		12,000
Other comprehensive income (loss)	54,224	54,224
Accrual of distribution equivalent rights	(3,662)			(3,662)
Other			154	(154)
Ending balance at Dec. 31, 2017	4,868,322	28,631	277,385	4,562,306
Increase (Decrease) in Partners' Capital [Roll Forward]
Net (loss) income	(51,915)		7,123	(59,038)
Acquisition of noncontrolling interest	(210,000)		(266,928)	56,928
Distributions paid to unitholders	(673,723)		2,400	(676,123)
Net proceeds from issuance of LP Units	261,962			261,962
Amortization of unit-based compensation awards	22,081			22,081
Payment of tax withholding on issuance of LTIP awards	(8,306)			(8,306)
Distributions paid to noncontrolling interests	(16,292)		(16,292)
Contributions from noncontrolling interests	7,400		7,400
Other comprehensive income (loss)	(68,692)	(68,692)
Accrual of distribution equivalent rights	333			333
Ending balance at Dec. 31, 2018	$ 4,131,170	$ (40,061)	$ 11,088	$ 4,160,143

ORGANIZATION

ORGANIZATION	12 Months Ended
	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
ORGANIZATION	ORGANIZATION Buckeye Partners, L.P. is a publicly traded Delaware master limited partnership (“MLP”), and its limited partnership units representing limited partner interests (“LP Units”), are listed on the New York Stock Exchange under the ticker symbol “BPL.” Buckeye GP LLC (“Buckeye GP”) is our general partner. As used in these Notes to Consolidated Financial Statements, “ we ,” “ us ,” “ our ” and “ Buckeye ” mean Buckeye Partners, L.P. and, where the context requires, includes our subsidiaries. We were formed as a master limited partnership in 1986 from predecessor companies and own and operate a diversified global network of integrated assets providing midstream logistic solutions, primarily consisting of the transportation, storage, processing 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, with approximately 6,000 miles of pipeline. We also use our service expertise to operate and/or maintain third-party pipelines and perform certain engineering and construction services for our customers. Our global terminal network comprises more than 115 liquid petroleum products terminals with aggregate tank capacity of over 118 million barrels across our portfolio of pipelines, inland terminals and marine terminals located primarily in key petroleum logistics hubs in the East Coast, Midwest and Gulf Coast regions of the United States as well as in the Caribbean. Our terminal assets facilitate global flows of crude oil and refined petroleum products, offering our customers connectivity between supply areas and market centers through some of the world’s most important bulk liquid storage and blending hubs. Our wholly-owned flagship marine terminal in The Bahamas, Buckeye Bahamas Hub Limited (“BBH”), is one of the largest marine crude oil and refined petroleum products storage facilities in the world and provides an array of logistics and blending services for the global flow of petroleum products. Our Gulf Coast regional hub, Buckeye Texas Partners LLC (“Buckeye Texas”), offers world-class marine terminalling, storage and processing capabilities. We are also a wholesale distributor of refined petroleum products in areas served by our pipelines and terminals.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES We adhere to the following significant accounting policies in the preparation of our consolidated financial statements: Basis of Presentation and Principles of Consolidation The consolidated financial statements and the accompanying notes are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and the rules of the U.S. Securities and Exchange Commission (“SEC”). The consolidated financial statements include the accounts of our subsidiaries controlled by us and variable interest entities (“VIEs”) of which we are the primary beneficiary. A VIE is required to be consolidated by its primary beneficiary which is generally defined as the party who has (i) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (ii) the obligation to absorb losses of the VIE or the right to receive benefits that could potentially be significant to the VIE. We evaluate our relationships with our VIEs on an ongoing basis to determine whether we continue to be the primary beneficiary. Third party or affiliate ownership interests in our subsidiaries and consolidated VIEs are presented as noncontrolling interests. Intercompany transactions are eliminated in consolidation. The preparation of consolidated financial statements in conformity with GAAP requires our management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses during the reporting period and disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Estimates and assumptions about future events and their effects cannot be made with certainty. Estimates may change as new events occur, when additional information becomes available and if our operating environment changes. Actual results could differ from our estimates. Asset Retirement Obligations We regularly assess our legal obligations with respect to estimated retirements of certain of our long-lived assets to determine if an asset retirement obligation (“ARO”) exists. The fair value of a liability related to the retirement of long-lived assets is recorded at the time a regulatory or contractual obligation is incurred, including obligations to perform an asset retirement activity in which the timing or method of settlement are conditional on a future event that may or may not be within the control of the entity. If an ARO is identified and a liability is recorded, a corresponding asset is recorded concurrently and is depreciated over the remaining useful life of the asset. After the initial measurement, the liability is periodically adjusted for costs incurred or settled, accretion expense, and any revisions made to the assumptions related to the retirement costs. Generally, the fair value of the liability is determined based on estimates and assumptions related to: (i) future retirement costs; (ii) future inflation rates; and (iii) credit-adjusted risk-free interest rates. Our assets generally consist of terminals that we own and underground liquid petroleum products pipelines installed along rights-of-way acquired from land owners and related above-ground facilities. The significant majority of our rights-of-way agreements do not require the dismantling and removal of the pipelines and reclamation of the rights-of-way upon permanent removal of the pipelines from service. In addition, we assume substantially all of our common carrier properties operate indefinitely, as these assets generally serve in high-population and high-demand markets. Accordingly, other than with respect to facilities that are expected to be taken out of service, we have recorded no liabilities, or corresponding assets because the future dismantlement and removal dates for the majority of our assets, and the amount of any associated costs, are indeterminable. The ARO liability represents our best estimate of the costs to be incurred with information currently available and is based on certain assumptions, including: (i) timing of retirement of assets; (ii) methods of abandonment to be employed; and (iii) if applicable, our requirements under right-of-way agreements; therefore, it is likely that the ultimate costs to settle this liability will be different and such differences could be material. ARO liabilities are included in accrued and other current liabilities, as well as other non-current liabilities. There were no significant changes in the estimates underlying ARO liabilities during the periods presented. Business Combinations We allocate the total purchase price of a business combination to the assets acquired and the liabilities assumed based on their estimated fair values at the acquisition date, with the excess purchase price recorded as goodwill. For material acquisitions, we may engage an independent valuation specialist to assist us in determining the fair value of the assets acquired and liabilities assumed, including goodwill, based on recognized business valuation methodologies. If the initial accounting for the business combination is incomplete by the end of the reporting period in which the acquisition occurs, an estimate will be recorded. Subsequent to the acquisition, and not later than one year from the acquisition date, we will record any material adjustments to the initial estimate in the reporting period in which the adjustment amounts are determined based on facts and circumstances that existed as of the acquisition date, as applicable. An income, market or cost valuation method may be utilized to estimate the fair value of the assets acquired or liabilities assumed in a business combination. The income valuation method represents the present value of future cash flows over the life of the asset using: (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses; (ii) long-term growth rates; and (iii) appropriate discount rates. The market valuation method uses prices paid for a reasonably similar asset by other purchasers in the market, with adjustments relating to any differences between the assets. The cost valuation method is based on the replacement cost of a comparable asset at prices at the time of the acquisition reduced for depreciation of the asset. We expense acquisition-related costs as incurred in connection with each business combination. Business Segments Our operations are reported under three business segments: (i) Domestic Pipelines & Terminals; (ii) Global Marine Terminals; and (iii) Merchant Services. Our business segments are generally organized and managed according to the geographical location of our assets and the types of services rendered. Financial information regarding these segments is evaluated regularly by our chief operating decision maker (our Chief Executive Officer) in deciding how to allocate resources and in assessing operating and financial performance. Our business segment financial performance is evaluated primarily based on Adjusted EBITDA. Refer to Note 24 - Business Segments for further discussion. Capitalization of Interest Interest on borrowed funds is capitalized on projects during construction based on the approximate average interest rate of our debt. Interest capitalized for the years ended December 31, 2018 , 2017 and 2016 was $8.9 million , $4.8 million and $4.4 million , respectively. The weighted average rates used to capitalize interest on borrowed funds was 4.6% , 4.5% and 4.6% for the years ended December 31, 2018 , 2017 and 2016 , respectively. Cash and Cash Equivalents Cash equivalents represent all highly marketable securities with original maturities of three months or less. The carrying value of cash equivalents approximates fair value because of the short-term nature of these investments. Comprehensive Income Our comprehensive income is determined based on net income adjusted for unrealized gains and losses on derivative instruments for our cash flow hedging transactions, reclassification of derivative gains and losses to net income, recognition of costs related to our pension and post-retirement benefit plans, adjustments to the funded status of our pension and post-retirement benefit plans and our proportionate share of other comprehensive income from equity method investments. Concentration of Credit Risk and Trade Receivables Trade receivables of $214.3 million and $265.0 million included within accounts receivable, net on our consolidated balance sheets as of December 31, 2018 and 2017 , respectively, are primarily due from major oil companies, national oil companies, refiners, marketing and trading companies, and commercial airlines. These concentrations of customers may affect our overall credit risk as these customers may be similarly affected by changes in economic, regulatory or other factors. We extend credit to customers and manage our credit risks through credit analysis and monitoring procedures, including credit approvals, credit limits and right of offset. Also, we manage our risk using collateral, such as letters of credit, prepayments, liens on customer assets and guarantees. Trade receivables represent valid claims against non-affiliated customers and are recognized when products are sold or services are rendered. We record an allowance for doubtful accounts for estimated losses resulting from the inability of our customers to make required payments. We review the adequacy of the allowance for doubtful accounts monthly by making judgments regarding future events and trends based on the: (i) customers’ historical relationship with us; (ii) customers’ current financial condition; and (iii) current and projected economic conditions. The following table presents activity in the allowance for doubtful accounts at the dates indicated (in thousands): December 31, 2018 2017 2016 Balance at beginning of period $ 4,893 $ 7,960 $ 8,380 Charged to expense 2,083 305 2,143 Write-offs, net of recoveries (76 ) (3,372 ) (2,563 ) Balance at end of period $ 6,900 $ 4,893 $ 7,960 Contingencies Certain conditions may exist as of the date our consolidated financial statements are issued that may result in a loss to us, but which will only be resolved when one or more future events occur or fail to occur. Our management, with input from legal counsel, assesses such contingent liabilities, and such assessment inherently involves judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in proceedings, our management, with input from legal counsel, evaluates the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein. If the assessment of a contingency indicates that it is probable that a loss has been incurred and the amount of liability can be reasonably estimated, then the estimated liability is accrued in our consolidated financial statements. If the assessment indicates that a potentially material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss if determinable and material, is disclosed. Actual results could vary from these estimates and judgments. Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed. In addition, we are subject to federal, state and local laws and regulations relating to the protection of the environment, which require us to remove or remedy the effect of the disposal or release of specified substances at our operating sites. We record environmental liabilities at a specific site when environmental assessments indicate remediation efforts are probable, and costs can be reasonably estimated based upon past experience, discussions with operating personnel, advice of outside engineering and consulting firms, discussion with legal counsel or current facts and circumstances. The estimates related to environmental matters are uncertain because: (i) estimated future expenditures are subject to cost fluctuations and change in the estimated remediation period; (ii) unanticipated liabilities may arise; and (iii) changes in federal, state and local environmental laws and regulations may significantly change the extent of remediation. Our estimated environmental remediation liabilities are generally not discounted to present value since the ultimate amount and timing of cash payments for such liabilities are typically not readily determinable. Expenditures to mitigate or prevent future environmental contamination are capitalized. We monitor the environmental liabilities regularly and record adjustments to our initial estimates, from time to time, to reflect changing circumstances and estimates based upon additional developments or information obtained in subsequent periods. We maintain insurance which may cover certain environmental expenditures. Recoveries of environmental remediation expenses from other parties are recorded when their receipt is assured beyond a reasonable doubt. Cost of Product Sales Cost of product sales relates to sales of refined petroleum products, consisting primarily of gasoline, propane, ethanol, biodiesel and middle distillates, such as heating oil, diesel fuel and kerosene, and fuel oil, as well as the effects of hedges on refined petroleum product acquisition costs and hedges of fixed-price contracts. Debt Issuance Costs Costs incurred upon the issuance of our debt instruments are capitalized and amortized over the life of the associated debt instrument on a straight-line basis, which approximates the effective interest method. If the debt instrument is retired before its scheduled maturity date, any remaining issuance costs associated with that debt instrument are expensed in the same period. Debt issuance costs related to our amended $1.5 billion revolving Credit Facility with a syndicate of lending institutions dated September 30, 2016 (the “Credit Facility”), are reported in “Other non-current assets”. Debt issuance costs related to our outstanding notes are reported as a reduction of the carrying amount of our outstanding notes. Derivative Instruments Derivatives are financial and physical instruments whose fair value is determined by changes in a specified benchmark such as interest rates or commodity prices. We use derivative instruments such as forwards, futures, swaps and other contracts to manage market price risks associated with inventories, firm commitments, interest rates and certain forecasted transactions. We do not engage in speculative trading activities. We recognize these transactions on our consolidated balance sheets as assets and liabilities based on the instrument’s fair value. Changes in fair value of derivative instrument contracts are recognized in earnings in the current period unless specific hedge accounting criteria are met. If the derivative instrument is designated as a hedging instrument in a fair value hedge, gains and losses incurred on the instrument will be recorded in earnings to offset corresponding losses and gains on the hedged item. If the derivative instrument is designated as a hedging instrument in a cash flow hedge, gains and losses incurred on the instrument are recorded in other comprehensive income. 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. Gains and losses on cash flow hedges are reclassified from accumulated other comprehensive income (“AOCI”) to earnings when the forecasted transaction occurs and affects net income or, as appropriate, over the economic life of the underlying asset or liability. Gains and losses related to a derivative instrument designated as a hedge of a forecasted transaction that is no longer likely to occur are immediately recognized in earnings. Physical forward contracts and futures contracts that have not been designated in a hedge relationship are marked-to-market. To qualify as a hedge, the item to be hedged must expose us to risk and we must have an expectation that the related hedging instrument will be effective at reducing or mitigating that exposure. In accordance with the hedging requirements, we document all hedging relationships at inception and include a description of the risk management objective and strategy for undertaking the hedge, identification of the hedging instrument, the hedged item, the nature of the risk being hedged, the method for assessing effectiveness of the hedging instrument in offsetting the hedged risk and the method of measuring any ineffectiveness. We link all derivative instruments that are designated as fair value or cash flow hedges to specific assets and liabilities on our consolidated balance sheets or to specific firm commitments or forecasted transactions. When an event or transaction occurs, such as the sale of hedged fuel inventory or the expiration of derivative contracts, we discontinue hedge accounting. We also formally assess, both at the hedge’s inception and on an ongoing basis, whether the derivative instruments that are used in designated hedging relationships are highly effective in offsetting changes in fair values or cash flows of hedged items. If it is determined that a derivative instrument is not highly effective as a hedge or that it has ceased to be a highly effective hedge, we discontinue hedge accounting prospectively. We measure ineffectiveness by comparing the change in fair value of the hedge instrument to the change in fair value of the hedged item. The time value component is excluded from our hedge assessment and reported directly in earnings. Earnings per Unit Basic and Diluted earnings per unit (“EPU”) are computed taking into account the weighted average outstanding limited partner units as well as the effect of participating securities. Our participating securities are generally comprised of certain unvested restricted units, granted under the 2013 Long Term Incentive Plan of Buckeye Partners, L.P. (the “LTIP”), and participate in earnings only to the extent of certain distribution equivalent rights. Net income allocable to participating securities reduces net income attributable to Buckeye Partners, L.P. to arrive at net income attributable to unitholders. For Diluted EPU, we use the more dilutive of the treasury stock or two-class method, taking into consideration dilutive securities resulting from restricted-unit grants under the LTIP. See Note 23 - (Loss) Earnings Per Unit for further discussion. Equity Investments We account for investments in entities in which we do not exercise control, but have significant influence, using the equity method of accounting. Under this method, an investment is recorded at acquisition cost plus our equity in undistributed earnings or losses since acquisition, reduced by distributions received and amortization of excess net investment. Excess investment is the amount by which the total investment exceeds our proportionate share of the book value of the net assets of the investment. Such excess investment not related to any specific accounts of the investee is treated as goodwill and not amortized. Amounts associated with specific accounts of the investee are amortized. The amortization of excess net investment is included in earnings from equity investments in our consolidated statement of operations. We evaluate equity method investments for impairment whenever events or changes in circumstances indicate that there is an other than temporary loss in value of the investment. In the event that the loss in value of an investment is other than temporary, we record a charge to earnings to adjust the carrying value to fair value. We assess the fair value of equity investments using commonly accepted valuation methodologies, including but not limited to, peer group multiples, comparable sales-transaction multiples, and discounted cash flow models. Estimates of future cash flows that would be used to determine fair value include: (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses; (ii) long-term growth rates; and (iii) probabilities assigned to different cash flow scenarios. A significant change in these underlying assumptions could result in an impairment charge. For the year ended December 31, 2018 , we recorded a $300.3 million non-cash loss related to the anticipated sale of our equity investment in VTTI. There were no impairments of our equity investments for the years ended December 31, 2017 or 2016 . See Note 4 - Acquisitions, Investments and Dispositions for further discussion. We account for investments in entities that we do not control and for which we do not have the ability to exercise significant influence over operating and financial policies at fair value except in situations when the equity security does not have a readily determinable fair value. In these situations, we record the equity investment at cost less impairments and changes resulting from observable price changes in orderly transactions for similar investments. Fair Value Measurements Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Our fair value estimates are based on either: (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. Recognized valuation techniques employ inputs such as product prices, operating costs, discount factors and business growth rates. These inputs may be either readily observable, corroborated by market data or generally unobservable. In developing our estimates of fair value, we endeavor to utilize the best information available and apply market-based data to the extent possible. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements based on the observability of inputs used to estimate such fair values. The characteristics of fair value amounts classified within each level of the hierarchy are described as follows: • Level 1 inputs — unadjusted quoted prices which are available in active markets for identical, unrestricted assets or liabilities as of the reporting date; • Level 2 inputs — quoted market prices in markets that are not considered to be active or financial instruments for which all significant inputs are observable, either directly or indirectly; and • Level 3 inputs — prices or valuations that require inputs that are both significant to the fair value measurement and unobservable. These inputs are typically used in connection with internally developed valuation methodologies where management makes its best estimate of an instrument’s fair value. We categorize our financial assets and liabilities using this hierarchy at each balance sheet reporting date. Foreign Currency Puerto Rico is a commonwealth country under the U.S., and thus uses the U.S. dollar as its official currency. The functional currency of our operations in BBH and St. Lucia is the U.S. dollar. Foreign exchange gains and losses arising from transactions denominated in a currency other than the U.S. dollar relate to a nominal amount of supply purchases and are included in “Other income (expense)” within the consolidated statements of operations. The effects of foreign currency transactions were not material for the years ended December 31, 2018 , 2017 and 2016 . Our investment in VTTI indirectly exposed us to foreign currency risk, primarily with respect to the Euro, Malaysian Ringgit, and United Arab Emirates Dirham. VTTI manages its exposure to foreign currency risk with foreign exchange hedging strategies. Our proportionate share of VTTI’s foreign currency risk with foreign currency transaction, hedging, and translation gains and losses is included in our earnings from equity investments and accumulated other comprehensive income, as applicable, during the time period for which we applied the equity method of accounting. We recognized our proportionate share, of $49.6 million , of VTTI’s other comprehensive loss, primarily comprised of foreign currency translation adjustments, in other comprehensive loss (income) for the nine months ended September 30, 2018. Due to certain terms of the definitive agreement regarding the divestiture of our equity interest in VTTI, beginning in the fourth quarter of 2018, we determined we no longer had the ability to exercise significant influence over the operating and financial policies of VTTI. Accordingly, we accounted for our investment at fair value and therefore included the amount of foreign currency translation deferred in AOCI as part of the impairment of our investment. See Note 4 - Acquisition, Investments and Disposition for further discussion. Goodwill Goodwill represents the excess of purchase price over fair value of net assets acquired. Our goodwill amounts are assessed for impairment: (i) on an annual basis on October 31st each year or (ii) on an interim basis if circumstances indicate it is more likely than not the fair value of a reporting unit is less than its fair value. Goodwill is tested for impairment at each reporting unit. A reporting unit is a business segment or one level below a business segment for which discrete financial information is available and regularly reviewed by segment management. Our reporting units are our business segments, with the exception of our Global Marine Terminals segment which consists of: (i) our operations in the Caribbean and New York Harbor, as well as our equity investment in VTTI, which we refer to as our “GMT Caribbean and NYH reporting unit”; and (ii) our operations in South Texas, including our equity investment in the STG Terminal (the “GMT South Texas” reporting unit). We may perform a qualitative assessment to determine whether the fair value of our reporting units are more likely than not less than the carrying amount. In 2018, we adopted Accounting Standards Update (“ASU”) ASU 2017-04 which simplified the test for goodwill impairment. Under the new guidance, if the carrying amount of a reporting unit exceeds its estimated fair value, an impairment is recorded for the amount of the excess up to the amount of goodwill for the respective reporting unit. The estimate of the fair value of the reporting unit is determined using a weighting of an expected present value of future cash flows and a market multiple valuation method, giving more weighting to our estimate of future cash flows. The present value of future cash flows is estimated using: (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses; (ii) long-term growth rates; and (iii) appropriate discount rates. The market multiple valuation method uses appropriate market multiples from comparable companies on the reporting unit’s earnings before interest, tax, depreciation and amortization. We evaluate industry and market conditions for purposes of weighting the income and market valuation approach. Using this methodology, the Partnership performed a goodwill recoverability test as of September 30, 2018, as discussed in Note 10 - Goodwill and Intangible Assets, and concluded that the goodwill attributable to the GMT Caribbean and NYH reporting units, had been impaired. Furthermore, we performed our annual assessment on October 31, 2018 to determine if any significant events or changes in circumstances had occurred that would be considered a potential triggering event. We did not identify any indication of a triggering event that would indicate the existence of further impairment of the reporting units. Income Taxes With the exception of federal and state income taxes from Buckeye Development & Logistics LLC (“BDL”), federal income taxes from Buckeye Caribbean Terminals LLC (“Buckeye Caribbean”) and certain MLP entity level state income taxes, the Partnership’s federal and certain state income taxes are the responsibility of the partners and are not reflected in these consolidated financial statements. In addition, outside the continental U.S., our operations at BBH and St. Lucia are exempt from income taxes. Our operations at BBH are tax exempt by the Bahamian government pursuant to concessions granted under the Hawksbill Creek Agreement between the Government of The Bahamas and the Grand Bahama Port Authority. These concessions have been extended through May 2036 by the Grand Bahama Investment Incentives Act. Our operations in St. Lucia are exempt from income taxes and duties pursuant to concessions granted under the terms of a tax concession agreement effective in 2007 and in effect for a minimum of 50 years . Our operations at the Yabucoa terminal are subject to income taxes within the Commonwealth of Puerto Rico. Buckeye Caribbean is the holder of a tax exemption grant issued by the Office of Industrial Tax Exemption of the Puerto Rico Department of State under the Tax Incentives Act of 1998 (the “Act”). Under the current terms of the tax exemption grant, Buckeye Caribbean is subject to an income tax rate of 4% to 7% on industrial development income. The grant also provides additional exemptions as follows: (i) 90% exempt from real and personal property taxes; (ii) 60% exempt from municipal taxes on industrial development income; and (iii) 100% exempt from excise taxes imposed under Subtitle C of the Puerto Rico Internal Revenue Code, to the extent provided in Section 6(c) of the Act. The tax exemption grant provides a 20 year exemption period, which commenced on January 1, 2002 and, unless renewed, would end with the tax year ending December 31, 2021. We are currently seeking a renewal of our tax exemption grant. We recognize deferred tax assets and liabilities for temporary differences between the amounts of assets and liabilities measured for financial reporting purposes and income tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. See Note 22 - Income Taxes for the impact of the Tax Cuts & Jobs Act. We evaluate the need for a valuation allowance and consider all available positive and negative evidence, including projected operating income or losses for the foreseeable future, to determine the likelihood of realizing the benefits of deferred tax assets. If the value of the deferred tax assets exceeds the estimated future benefit, we record a valuation allowance to reduce our deferred tax assets to the amount of future benefit that is more likely than not to be realized. In the future, if the realization of the deferred tax assets should occur, a reduction to the valuation allowance related to the deferred tax assets would increase net income in the period such determination is made. We have no unrecognized tax benefits related to uncertain tax positions. Intangible Assets Intangible assets with finite useful lives are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Intangible assets that have finite useful lives are amortized over their useful lives. Intangible assets include contracts and customer relationships. The fair values of these intangibles are based on the present value of cash flows attributable to the customer relationship or contract, which includes management’s estimates of revenue and operating expenses and costs relating to utilization of other assets to fulfill such contracts. The customer contracts are being amortized over their contractual lives with a range of 1 to 10 years . For the customer relationships, we determine the recovery period based on historical customer attrition rates and management’s assumptions on future events, including customer demand, contract renewal, useful lives of related assets and market conditions. The customer relationships are being amortized over the estimated recovery period of 12 to 20 years . When necessary, intangible assets’ useful lives are revised and the impact on amortization is reflected on a prospective basis. Inventories We generally maintain two types of inventory. Our Merchant Services segment princ

ACQUISITIONS, INVESTMENTS AND D

ACQUISITIONS, INVESTMENTS AND DISPOSITION	12 Months Ended
	Dec. 31, 2018
Business Combinations [Abstract]
ACQUISITIONS, INVESTMENTS AND DISPOSITION	ACQUISITIONS, INVESTMENTS AND DISPOSITION 2019 Transaction VTTI Acquisition and Divestiture In January 2017, we acquired an indirect 50% equity interest in VTTI for cash consideration of $1.15 billion (the “VTTI Acquisition”) and made a capital contribution to VTTI, in the amount of $236.8 million , to fund our 50% share of the aggregate cash consideration paid by VTTI to acquire all of the outstanding publicly held units of VTTI Energy Partners LP, formerly a publicly traded master limited partnership. We owned VTTI jointly with Vitol S.A. (“Vitol”). In November 2018, we executed a definitive share purchase agreement (the “SPA”) to sell our 50% equity interest in VTTI for approximately $975.0 million , excluding transaction costs of approximately $8.0 million , which was closed in January 2019. As part of the SPA, we also received a final earnings distribution of $22.6 million . As a result, effective September 30, 2018, we recorded our investment in VTTI at its estimated fair value, as determined by the proceeds, resulting in a non-cash loss of $300.3 million , which was reported in (loss) earnings from equity investments in our Consolidated Statement of Operations. Pursuant to the SPA, during the period between November 1, 2018 and the completion of the sale of our interest in VTTI, we agreed to certain governance changes with respect to the VTTI investment, and, as a result, commencing with the fourth quarter of 2018, we concluded we no longer had the ability to exercise significant influence over the operating and financial policies of VTTI. Effective September 30, 2018, we recorded our investment in VTTI at fair value based on the agreed selling price and ceased recording any further equity earnings. 2018 Transactions Domestic Asset Divestiture On December 17, 2018, we sold certain domestic pipeline and terminal assets, which included (i) our jet fuel pipeline from Port Everglades, Florida to Ft. Lauderdale-Hollywood International Airport and Miami International Airport; (ii) our pipelines and terminal facilities serving Reno-Tahoe International Airport, San Diego International Airport, and the Federal Express Corporation terminal at the Memphis International Airport; and (iii) our refined petroleum product terminals in Sacramento, California and Stockton, California (the “DPTS asset package”). Including working capital adjustments and a deferred payment of $10.0 million , we expect to receive total proceeds of $454.6 million , which excludes transaction costs of $7.7 million . We received $444.6 million in proceeds as of December 31, 2018, which resulted in an after-tax gain on the sale of approximately $342.5 million , reflected in our Consolidated Statement of Operations. South Texas Transactions In April 2018, as part of our strategy to serve the volume growth in crude oil and related products from the Permian Basin, we expanded our marine terminal presence in Corpus Christi, Texas, through the following transactions: (i) acquired our business partner’s 20% interest in our Buckeye Texas consolidated subsidiary, and (ii) formed a joint venture with Phillips 66 Partners LP (“Phillips 66 Partners”) and Gray Oak Gateway Holdings (“Marathon”) to develop a new deep-water, open-access marine terminal in Ingleside, Texas at the mouth of Corpus Christi Bay (the “STG Terminal”). We acquired our partner’s interest in Buckeye Texas for $210.0 million , and as a result we now own 100% of Buckeye Texas. The change in our ownership interest was accounted for as an equity transaction, representing the acquisition of a noncontrolling interest. The STG Terminal will be constructed and operated by us. We continue to secure additional minimum volume throughput commitments and storage contracts from customers, and our current plan is to increase the scope of this project from 3.4 million barrels of storage to 6.8 million barrels, based on current contracted throughput and storage volumes. Our construction plan also includes connectivity to multiple pipelines delivering volumes into the Corpus Christi market from growing Permian Basin production and other sources. In addition, we plan to build two deep-water vessel docks capable of berthing very large crude carrier petroleum tankers as part of the initial scope of construction. The STG Terminal is expected to commence and ramp up operations by mid-2020, and is supported by long-term minimum volume throughput commitments and storage contracts from credit-worthy customers, including our joint-venture partners. We own a 50% interest in the STG Terminal, and Phillips 66 Partners and Marathon each own a 25% interest. The total construction cost for the STG Terminal is estimated on a 100% basis at $480.9 million , or a net of $240.5 million to our interest. During 2018, we invested $42.2 million and committed to fund our proportionate share of the anticipated total construction costs. We account for our interest in STG Terminal, which is included in our Global Marine Terminals segment, using the equity method of accounting. Business Combinations 2017 Transaction Duck Island terminal acquisition In December 2017, we acquired Duck Island Terminal LLC, a liquid petroleum products terminalling business in Trenton, New Jersey, for approximately $26.1 million , net of cash acquired of $2.4 million . The assets of this entity are reported in our Domestic Pipelines & Terminals segment. The purchase price 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 represent expected synergies from combining acquired assets with our existing operations. Fair values have been developed using recognized business valuation techniques, with inputs classified as Level 3 within the fair value hierarchy. The purchase price has been allocated to tangible and intangible assets acquired as follows (in thousands): Current assets, including cash acquired of $2,444 $ 8,989 Property, plant and equipment 18,306 Intangible Assets 2,200 Goodwill 3,294 Current liabilities (3,516 ) Environmental liabilities (782 ) Allocated purchase price $ 28,491 We finalized the purchase price allocation during the fourth quarter of 2018 without significant adjustments. Unaudited Pro forma Financial Results for Duck Island terminal acquisition Our consolidated statements of operations do not include earnings from the terminalling business prior to December 20, 2017, the closing date of the acquisition. Unaudited pro forma financial information for this acquisition was not prepared because the impact was immaterial to our financial results for the year ended December 31, 2018 . 2016 Transaction Indianola terminalling facility acquisition In August 2016, we acquired a liquid petroleum products terminalling facility in Indianola, Pennsylvania from Kinder Morgan Transmix Company, LLC for $26.0 million . The operations of these assets are reported in our Domestic Pipelines & Terminals segment. The purchase price has been allocated to assets acquired based on estimated fair values at the acquisition date, with amounts exceeding the fair value recorded as goodwill, which represent expected synergies from combining the acquired assets with our existing operations. Fair values have been developed using recognized business valuation techniques, with inputs classified as Level 3 within the fair value hierarchy. The purchase price has been allocated to tangible and intangible assets acquired as follows (in thousands): Inventories $ 1,554 Property, plant and equipment 16,713 Goodwill 7,758 Allocated purchase price $ 26,025 We finalized the purchase price allocation during the third quarter of 2017 without significant adjustments. Unaudited Pro forma Financial Results for the Indianola terminalling facility acquisition Our consolidated statements of operations do not include earnings from the terminalling facility prior to August 4, 2016, the closing date of the acquisition. The preparation of unaudited pro forma financial information for the terminalling facility is impracticable due to the fact that meaningful historical revenue information is not available. The revenues and earnings impact of this acquisition was not significant to our financial results for the year ended December 31, 2016.

REVENUE FROM CONTRACTS WITH CUS

REVENUE FROM CONTRACTS WITH CUSTOMERS	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
REVENUE FROM CONTRACTS WITH CUSTOMERS	REVENUE FROM CONTRACTS WITH CUSTOMERS Contract Balances Contract assets primarily relate to our rights to consideration for completed performance obligations that are not billable at the reporting date. We recognize contract assets in situations where revenue recognition occurs prior to billing the customer based on our rights under the contract. Contract assets are transferred to accounts receivable when the rights become unconditional, which is generally upon billing. Contract liabilities primarily relate to consideration received from customers in advance of completing the performance obligation. We recognize contract liabilities under these arrangements as revenue once all contingencies or potential performance obligations have been satisfied by either the (i) transportation of volumes, (ii) performance of terminalling and storage services, or (iii) expiration of the customer’s rights under the contract. We also recognize contract liabilities in revenue to the extent it is determined that an amount of volume associated with a minimum volume commitment payment will not be shipped by the customer in a future period. The following table provides information about receivables from contracts with customers, contract assets and contract liabilities (in thousands): December 31, December 31, 2017 Receivables from contracts with customers $ 199,324 $ 245,280 Contract assets 16,989 13,999 Contract liabilities (26,999 ) (15,778 ) During the year ended December 31, 2018 , we reclassified approximately $14.0 million of contract assets at the beginning of the period to receivables as a result of the rights to the consideration becoming unconditional and billable. Revenue recognized during the year ended December 31, 2018 from amounts included in contract liabilities at the beginning of the period was approximately $8.2 million . The following table includes estimated revenue associated with contractual commitments in place related to future performance obligations as of the end of the reporting period, which are expected to be recognized in revenue in the specified periods (in thousands): Estimated Revenue (1) 2019 $ 358,060 2020 196,399 2021 126,777 2022 51,499 Thereafter 212,374 Total $ 945,109 (1) Excludes revenue arrangements accounted for as leases in the amount of $211.7 million for 2019, $207.2 million for 2020, $188.0 million for 2021, $134.8 million for 2022, and $48.5 million thereafter. Our contractually committed revenue disclosure, for purposes of the tabular presentation above, excludes estimates of variable rate escalation clauses in our contracts with customers and is generally limited to our contracts fixed pricing and minimum volume components. Our contractually committed revenue disclosure generally excludes remaining performance obligations on contracts with index-based pricing or variable volume attributes.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES Claims and Legal Proceedings In the ordinary course of business, we are involved in various claims and legal proceedings, some of which are covered by insurance. We are generally unable to predict the timing or outcome of these claims and proceedings. Based upon our evaluation of existing claims and proceedings and the probability of losses relating to such contingencies, we have accrued certain amounts relating to such claims and proceedings, none of which are considered material. Environmental Contingencies We recorded operating expenses, net of recoveries, of $13.7 million , $7.4 million and $8.2 million during the years ended December 31, 2018 , 2017 and 2016 , respectively, related to environmental remediation liabilities. See Notes 12 - Accrued and Other Current Liabilities and 14 - Other Non-Current Liabilities for further discussion regarding remaining estimated liabilities. Costs ultimately incurred may be in excess of our estimates, which may have a material impact on our financial condition, results of operations or cash flows. At December 31, 2018 and 2017 , we had $4.2 million and $5.3 million , respectively, of receivables related to these environmental remediation liabilities covered by insurance or third-party claims. Lease Obligations We lease certain property, plant and equipment under noncancelable and cancelable operating leases. Rental expense is charged to operating expenses on a straight-line basis over the period of expected benefit. Contingent rental payments are expensed as incurred. Total rental expense for the years ended December 31, 2018 , 2017 and 2016 was $34.7 million , $29.9 million and $32.8 million , respectively. The following table presents minimum lease payment obligations under our operating leases with terms in excess of one year for the years ending December 31st (in thousands): Total (1) 2019 29,050 2020 26,255 2021 22,215 2022 21,378 2023 21,126 Thereafter 138,466 Total $ 258,490 ____________________________ (1) Includes BBH facility leases for properties in connection with jetty and inland dock operations, as well as tugboats and a barge in our Global Marine Terminals segment. In addition to the rental expense discussed above, our rights-of-way expense for the years ended December 31, 2018 , 2017 and 2016 were $7.9 million , $7.4 million and $7.1 million , respectively; and are subject to an annual escalation for the remaining life of all pipelines and terminals.

INVENTORIES

INVENTORIES	12 Months Ended
	Dec. 31, 2018
Inventory Disclosure [Abstract]
INVENTORIES	INVENTORIES Our inventory amounts were as follows at the dates indicated (in thousands): December 31, 2018 2017 Liquid petroleum products (1) $ 186,683 $ 280,934 Materials and supplies 24,201 20,491 Total inventories $ 210,884 $ 301,425 ____________________________ (1) Ending inventory was 114.7 million and 142.1 million gallons of liquid petroleum products at December 31, 2018 and 2017 , respectively. At December 31, 2018 and 2017 , approximately 94% and 85% 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 consolidated statements of operations.

PREPAID AND OTHER CURRENT ASSET

PREPAID AND OTHER CURRENT ASSETS	12 Months Ended
	Dec. 31, 2018
Prepaid Expense and Other Assets, Current [Abstract]
PREPAID AND OTHER CURRENT ASSETS	PREPAID AND OTHER CURRENT ASSETS Prepaid and other current assets consist of the following at the dates indicated (in thousands): December 31, 2018 2017 Prepaid insurance $ 6,622 $ 7,146 Margin deposits 8,684 7,989 Contract assets 16,989 13,999 Prepaid taxes 5,311 2,865 Other 21,288 4,340 Total prepaid and other current assets $ 58,894 $ 36,339

PROPERTY, PLANT AND EQUIPMENT

PROPERTY, PLANT AND EQUIPMENT	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
PROPERTY, PLANT AND EQUIPMENT	PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment consist of the following at the dates indicated (in thousands): Estimated December 31, 2018 2017 Land N/A $ 669,383 $ 677,866 Rights-of-way (1) 105,811 109,282 Buildings and leasehold improvements 13-50 284,399 282,778 Jetties, subsea pipeline and docks 20-50 679,500 646,922 Gas storage facility 25-50 2,349 2,349 Pipelines and terminals 7-50 5,476,790 5,289,096 Vehicles, equipment and office furnishings 3-20 155,094 150,403 Processing facilities 30-50 630,386 589,971 Construction in progress N/A 254,982 179,573 Total property, plant and equipment 8,258,694 7,928,240 Less: Accumulated depreciation (1,343,898 ) (1,192,448 ) Total property, plant and equipment, net $ 6,914,796 $ 6,735,792 ____________________________ (1) Rights-of-way assets are depreciated over the useful life of the related pipeline assets. Depreciation expense was $203.7 million , $202.8 million and $186.6 million for the years ended December 31, 2018 , 2017 and 2016 , respectively.

EQUITY INVESTMENTS

EQUITY INVESTMENTS	12 Months Ended
	Dec. 31, 2018
Equity Method Investments and Joint Ventures [Abstract]
EQUITY INVESTMENTS	EQUITY INVESTMENTS The following table presents our investments at the dates indicated (in thousands): December 31, Segment Ownership 2018 2017 VTTI B.V. (1) Global Marine Terminals 50.0% $ 975,000 $ 1,399,825 West Shore Pipe Line Company Domestic Pipelines & Terminals 34.6% 70,727 70,035 Muskegon Pipeline LLC Domestic Pipelines & Terminals 40.0% 13,491 13,335 Transport4, LLC Domestic Pipelines & Terminals 25.0% 553 699 South Portland Terminal LLC Domestic Pipelines & Terminals 50.0% 12,055 10,518 South Texas Gateway Terminal LLC Global Marine Terminals 50.0% 39,967 — Total equity investments $ 1,111,793 $ 1,494,412 ____________________________ (1) Accounted for using fair value beginning in the fourth quarter of 2018. See Note 4 - Acquisitions, Investments and Disposition for further discussion. The following table presents earnings (loss) from equity investments for the periods indicated (in thousands): Year Ended December 31, Segment 2018 2017 2016 VTTI B.V. (1) Global Marine Terminals $ 13,651 $ 22,910 $ — Non-cash loss on write-down of investment in VTTI B.V. (2) Global Marine Terminals $ (300,280 ) $ — $ — West Shore Pipe Line Company Domestic Pipelines & Terminals 10,322 9,451 7,647 Muskegon Pipeline LLC Domestic Pipelines & Terminals 557 1,778 2,002 Transport4, LLC Domestic Pipelines & Terminals 817 850 765 South Portland Terminal LLC Domestic Pipelines & Terminals 1,536 1,016 1,122 South Texas Gateway Terminal LLC (3) Global Marine Terminals (726 ) — — Total (loss) earnings from equity investments $ (274,123 ) $ 36,005 $ 11,536 ____________________________ (1) Accounted for using fair value beginning in the fourth quarter of 2018. See Note 4 - Acquisitions, Investments and Disposition for further discussion. (2) In September 2018, we recorded a non-cash loss related to our equity investment in VTTI. (3) In April 2018, we formed the STG Terminal joint venture. See Note 4 - Acquisitions, Investments and Disposition for further discussion. Summarized combined financial information for our equity method investments is as follows for the periods indicated (amounts represent 100% of investee financial information in thousands): December 31, 2018 2017 BALANCE SHEET DATA: (1) Current assets $ 30,045 $ 288,085 Noncurrent assets 257,036 2,600,231 Total assets $ 287,081 $ 2,888,316 Current liabilities $ 31,287 $ 151,850 Other liabilities 41,070 1,246,406 Combined equity 214,724 1,490,060 Total liabilities and combined equity $ 287,081 $ 2,888,316 Year Ended December 31, 2018 2017 2016 INCOME STATEMENT DATA: (1) Revenue $ 460,596 $ 553,396 $ 87,434 Operating Income 143,817 184,692 45,932 Net income 83,479 122,506 30,942 Net income attributable to investee $ 78,962 $ 99,130 $ 30,942 ____________________________ (1) In November 2018, we executed a definitive agreement to sell our 50% equity interest in VTTI, and ceased application of the equity method of accounting. Effective September 30, 2018, we accounted for our investment in VTTI at fair value and no longer include the selected balance sheet data related to VTTI in these tables. See Note 4 - Acquisitions, Investments and Disposition for further discussion.

GOODWILL AND INTANGIBLE ASSETS

GOODWILL AND INTANGIBLE ASSETS	12 Months Ended
	Dec. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
GOODWILL AND INTANGIBLE ASSETS	GOODWILL AND INTANGIBLE ASSETS Goodwill Goodwill represents the excess of purchase price over fair value of net assets acquired. Our goodwill amounts are assessed for impairment on an annual basis on October 31st and on an interim basis if circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. Subsequent to our annual goodwill impairment test in the fourth quarter of 2017, we have experienced continuing declines in the utilization of our segregated storage assets, as well as reductions in rate and term upon recontracting, and expect this weakness in demand for segregated storage to continue for certain locations through 2019. Due to the persistence of unfavorable market conditions affecting our segregated storage operations, particularly in the Caribbean region, and considering the near-term outlook and actions resulting from our recently completed Strategic Review, we performed an interim goodwill recoverability assessment for each of our reporting units as of September 30, 2018. As described in Note 2 - Summary of Significant Accounting Policies, we adopted ASU 2017-04 which simplified the test for goodwill impairment. Under the new guidance, if the carrying amount of a reporting unit exceeds its estimated fair value, an impairment is recorded for the amount of the excess up to the amount of goodwill for the respective reporting unit. The estimate of the fair value of the reporting unit is determined using a weighting of an expected present value of future cash flows and a market multiple valuation method, giving more weighting to our estimate of future cash flows. The present value of future cash flows is estimated using: (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses; (ii) long-term growth rates; and (iii) appropriate discount rates. The market multiple valuation method uses appropriate market multiples from comparable companies on the reporting unit’s earnings before interest, tax, depreciation and amortization. We evaluate industry and market conditions for purposes of weighting the income and market valuation approach. Using this methodology, which qualifies as Level 3 within the fair value hierarchy, we estimated the fair value of each of our reporting units and determined that the fair value of each of our reporting units significantly exceed their respective carrying values, with the exception of the GMT Caribbean and NYH reporting unit. Applying reasonable sensitivities to any or a combination of the above valuation inputs would not have generated a materially different determination of fair value. As a result of the assessment described above, we concluded that the goodwill in our GMT Caribbean and NYH reporting unit was fully impaired and recorded a non-cash goodwill impairment charge of $537.0 million . In conjunction with the goodwill impairment assessment, we considered impairment indicators related to the long-lived assets and investments associated with our GMT Caribbean and NYH reporting unit. Accordingly, we evaluated these assets for impairment and concluded that no impairment of long-lived assets existed as of December 31, 2018 ; however, we did record an approximately $300.3 million non-cash loss related to the anticipated sale of our equity investment in VTTI, which closed in January 2019. For our annual goodwill impairment test as of October 31, 2018 and 2017, we performed a qualitative assessment to determine whether the fair value of each of our reporting units was more likely than not less than the carrying value. Based on economic conditions and industry market considerations, we determined that it is not more likely than not that the fair value of each reporting unit is lower than the carrying value; therefore, the quantitative impairment test was not performed. Therefore, we did not record any additional goodwill impairment for the year ended December 31, 2018 and we did not record any goodwill impairment for the year ended December 31, 2017. The changes in the carrying amount of goodwill by segment are as follows at the dates indicated (in thousands): Domestic Pipelines Merchant GMT Caribbean and NYH GMT South Texas Total January 1, 2017 $ 295,703 4,499 536,964 $ 167,379 $ 1,004,545 Acquisition 2,768 — — — 2,768 December 31, 2017 298,471 4,499 536,964 167,379 1,007,313 Purchase price adjustments 526 — — — 526 Impairment of goodwill — — (536,964 ) — (536,964 ) December 31, 2018 $ 298,997 4,499 — $ 167,379 $ 470,875 Intangible Assets Intangible assets consist of the following at the dates indicated (in thousands): December 31, 2018 2017 Customer relationships $ 229,300 $ 231,620 Accumulated amortization (106,761 ) (96,147 ) Net carrying amount 122,539 135,473 Customer contracts 381,600 383,466 Accumulated amortization (210,828 ) (159,878 ) Net carrying amount 170,772 223,588 Total intangible assets, net $ 293,311 $ 359,061 For the years ended December 31, 2018 , 2017 and 2016 , amortization expense related to intangible assets was $65.7 million , $66.4 million and $68.1 million , respectively. Amortization expense related to intangible assets is expected to be $64.9 million for 2019 , $65.1 million for 2020 , $52.0 million for 2021 , $24.5 million for 2022 and $13.4 million for 2023 .

OTHER NON-CURRENT ASSETS

OTHER NON-CURRENT ASSETS	12 Months Ended
	Dec. 31, 2018
Other Assets, Noncurrent Disclosure [Abstract]
OTHER NON-CURRENT ASSETS	OTHER NON-CURRENT ASSETS Other non-current assets consist of the following at the dates indicated (in thousands): December 31, 2018 2017 Debt issuance costs $ 2,216 $ 3,022 Insurance receivables related to environmental remediation reserves 2,057 2,794 BBH jetty-allision insurance receivable — 7,372 Derivative assets 1,003 — Other 35,862 38,295 Total other non-current assets $ 41,138 $ 51,483

ACCRUED AND OTHER CURRENT LIABI

ACCRUED AND OTHER CURRENT LIABILITIES	12 Months Ended
	Dec. 31, 2018
Accrued Liabilities and Other Liabilities [Abstract]
ACCRUED AND OTHER CURRENT LIABILITIES	ACCRUED AND OTHER CURRENT LIABILITIES Accrued and other current liabilities consist of the following at the dates indicated (in thousands): December 31, 2018 2017 Taxes - other than income $ 29,644 $ 33,327 Accrued employee benefit liabilities 6,220 7,228 Accrued environmental remediation liabilities 11,658 9,242 Interest payable 58,360 57,164 Unearned revenue 31,593 34,734 Employee compensation related accruals 27,602 32,616 Accrued capital expenditures 59,128 48,690 ARO — 1,255 Other 51,988 40,951 Total accrued and other current liabilities $ 276,193 $ 265,207

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
LONG-TERM DEBT	LONG-TERM DEBT Long-term debt consists of the following at the dates indicated (in thousands): December 31, 2018 2017 6.050% Notes due January 15, 2018 (1) $ — $ 300,000 2.650% Notes due November 15, 2018 (1) — 400,000 5.500% Notes due August 15, 2019 (1) (2) 275,000 275,000 4.875% Notes due February 1, 2021 (1) 650,000 650,000 4.150% Notes due July 1, 2023 (1) 500,000 500,000 4.350% Notes due October 15, 2024 (1) 300,000 300,000 3.950% Notes due December 1, 2026 (1) 600,000 600,000 4.125% Notes due December 1, 2027 (1) 400,000 400,000 6.750% Notes due August 15, 2033 (1) 150,000 150,000 5.850% Notes due November 15, 2043 (1) 400,000 400,000 5.600% Notes due October 15, 2044 (1) 300,000 300,000 6.375 % Junior Notes due January 22, 2078 (1) 400,000 — Term Loan due September 30, 2019 (2) 250,000 250,000 Credit Facility due September 30, 2021 522,328 418,904 Unamortized discounts & debt issuance costs (32,886 ) (33,379 ) Total debt 4,714,442 4,910,525 Less: Current portion of long-term debt and line of credit (2) (702,727 ) (252,204 ) Total long-term debt $ 4,011,715 $ 4,658,321 ____________________________ (1) We make semi-annual interest payments on these notes based on the rates noted above with the principal balances outstanding to be paid on or before the due dates as shown above. (2) A portion of the line of credit is classified as a current liability in our consolidated balance sheets as related funds are used to finance the Buckeye Merchant Service Companies’ current working capital needs. In addition, the $275.0 million of 5.500% notes due August 15, 2019 and the $250.0 million Term Loan due September 30, 2019 are classified as current portion of long-term debt as of December 31, 2018. The following table presents the scheduled maturities of principal amounts of our debt obligations for the next five years and in total thereafter (in thousands): Years Ending December 31, 2019 $ 702,727 2020 — 2021 994,601 2022 — 2023 500,000 Thereafter 2,550,000 Total $ 4,747,328 Credit Facility In September 2016, Buckeye and BMSC exercised their remaining option with consenting lenders to extend $1.4 billion of our existing $1.5 billion revolving Credit Facility by one year to September 30, 2021 (the “Initial Facility Extension”). After the consummation of the Initial Facility Extension, approximately $90.0 million of our revolving Credit Facility retained a maturity date of September 30, 2020 (the “Unextended Tranche”). In November 2017, Buckeye and BMSC entered into an agreement with the lender holding the Unextended Tranche to extend the maturity date of such tranche to September 30, 2021 matching the Initial Facility Extension. As a result of such agreement, the full amount of our $1.5 billion revolving Credit Facility now has a maturity date of September 30, 2021. Under the Credit Facility, interest accrues on advances at the London Interbank Offered Rate (“LIBOR”) rate or a base rate plus an applicable margin based on the election of the applicable borrower for each interest period. The issuing fees for all letters of credit are also based on an applicable margin. The applicable margin used in connection with interest rates and fees is based on the credit ratings assigned to our senior unsecured long-term debt securities. The applicable margin for LIBOR rate loans, swing line loans, and letter of credit fees ranges from 1.0% to 1.75% and the applicable margin for base rate loans ranges from 0% to 0.75% . Buckeye and BMSC will also pay a fee based on our credit ratings on the actual daily unused amount of the aggregate commitments. At December 31, 2018 , Buckeye and BMSC collectively had a $522.3 million outstanding balance under the Credit Facility. The weighted average interest rate for borrowings under the Credit Facility was 3.8% for the period ended December 31, 2018 . The Credit Facility includes covenants limiting, as of the last day of each fiscal quarter, the ratio of consolidated funded debt to consolidated EBITDA (“Funded Debt Ratio”), as defined in the Credit Facility, measured for the preceding twelve months , to not more than 5.0 to 1.0 . This requirement is subject to a provision for increases to 5.5 to 1.0 in connection with certain future acquisitions. The Funded Debt Ratio is calculated by dividing consolidated debt by annualized EBITDA, which is defined in the Credit Facility as earnings before interest, taxes, depreciation, amortization, and certain other adjustments determined on a consolidated basis. At December 31, 2018 , our Funded Debt Ratio was 4.14 to 1.00 , and we were in compliance with the covenants under our Credit Facility. We had committed $3.1 million and $2.4 million in support of letters of credit at both December 31, 2018 and 2017 , respectively. The obligations for letters of credit are not reflected as debt on our consolidated balance sheets. At December 31, 2018 , we had $974.6 million of availability under our Credit Facility. Term Loan In September 2016, we entered into our $250.0 million Term Loan (“Term Loan”) due September 30, 2019, with an option to extend the term with consenting lenders for up to two one -year periods. We used the proceeds from the Term Loan to reduce the indebtedness outstanding under our Credit Facility. Under the Term Loan, interest accrues at the LIBOR rate or a base rate plus an applicable margin based on the election of the borrower. The applicable margin used in connection with interest rates and fees is based on the credit ratings assigned to our senior unsecured long-term debt securities. The applicable margin for LIBOR rate loans ranges from 1.0% to 1.6% and the applicable margin for base rate loans ranges from 0% to 0.6% . The Term Loan also has the same Funded Debt Ratio requirements and provisions as the Credit Facility, as described above. At December 31, 2018 , we were in compliance with the covenants under the Term Loan. Notes Offerings In November 2016, we issued $600.0 million of senior unsecured 3.950% notes maturing on December 1, 2026 in an underwritten public offering at 99.644% of their principal amount. Total proceeds from this offering, after underwriting fees, expenses and debt issuance costs were $592.7 million . In November 2017, we issued $ 400.0 million of senior unsecured 4.125% notes maturing December 1, 2027 in an underwritten public offering at 99.503% of their principal amount. Total proceeds from this offering, after underwriting fees, expenses, and debt issuance costs, were $394.4 million . We used the net proceeds from this offering to reduce the indebtedness outstanding under our Credit Facility, a portion of which was subsequently reborrowed in January 2018 in order to repay in full the $300.0 million of 6.050% notes due on January 15, 2018 and $9.1 million of related accrued interest. In January 2018, we issued $400.0 million of junior subordinated notes (“Junior Notes”) maturing on January 22, 2078, which are redeemable at Buckeye’s option, in whole or in part, on or after January 22, 2023. The Junior Notes bear interest at a fixed rate of 6.375% per year up to, but not including, January 22, 2023. Beginning January 22, 2023, the Junior Notes will bear interest at a floating rate based on the Three-Month LIBOR Rate plus 4.02% , reset quarterly. Total proceeds from this offering, after underwriting fees, expenses and debt issuance costs, were $394.9 million . We used the net proceeds from this offering for general partnership purposes and to reduce the indebtedness outstanding under our Credit Facility. Extinguishment of Debt In July 2017, we repaid in full the $125.0 million principal amount and $3.2 million of accrued interest outstanding under our 5.125% notes, using funds available under our Credit Facility. In January 2018, we repaid in full the $300.0 million principal amount and $9.1 million of accrued interest outstanding under our 6.050% notes, using funds available under our Credit Facility. In November 2018, we repaid in full the $400.0 million principal amount and $5.3 million of accrued interest outstanding under our 2.650% notes, using funds available under our Credit Facility. Use of Divestiture Proceeds Proceeds of $444.6 million from the sale of the DPTS asset package on December 17, 2018 were used to reduce the indebtedness outstanding under our Credit Facility. In January 2019, we received proceeds from the sale of our 50% equity interest in VTTI of $975 million , excluding transaction costs of approximately $8.0 million . We utilized the proceeds to reduce leverage, including retiring our $250 million Term Loan and repaying all borrowings on our Credit Facility. We have $275 million of 5.5% notes that matures in 2019. We expect to redeem this debt in February 2019 using proceeds from the VTTI sale transaction as well as borrowings on our Credit Facility.

OTHER NON-CURRENT LIABILITIES

OTHER NON-CURRENT LIABILITIES	12 Months Ended
	Dec. 31, 2018
Other Liabilities, Noncurrent [Abstract]
OTHER NON-CURRENT LIABILITIES	OTHER NON-CURRENT LIABILITIES Other non-current liabilities consist of the following at the dates indicated (in thousands): December 31, 2018 2017 Accrued employee benefit liabilities $ 28,246 $ 31,969 Accrued environmental remediation liabilities 27,358 31,803 Deferred consideration 20,232 19,640 ARO 4,349 3,833 Other 4,715 5,411 Total other non-current liabilities $ 84,900 $ 92,656

ACCUMULATED OTHER COMPREHENSIVE

ACCUMULATED OTHER COMPREHENSIVE (LOSS) INCOME	12 Months Ended
	Dec. 31, 2018
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
ACCUMULATED OTHER COMPREHENSIVE (LOSS) INCOME	ACCUMULATED OTHER COMPREHENSIVE (LOSS) INCOME Accumulated other comprehensive (loss) income consists of the following at the dates indicated (in thousands): December 31, 2018 2017 Unrealized (losses) gains on derivative instruments $ (490 ) $ 29,530 Net loss on settlement of interest rate swaps, net of amortization (38,699 ) (47,924 ) Unrecognized loss on benefit plans (872 ) (2,617 ) Other comprehensive income from equity method investments — 49,642 Total accumulated other comprehensive (loss) income $ (40,061 ) $ 28,631

DERIVATIVE INSTRUMENTS AND HEDG

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES	12 Months Ended
	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES	DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES We are exposed to financial market risks, including changes in interest rates and commodity prices, in the course of our normal business operations. We use derivative instruments to manage such risks. Interest Rate Derivatives From time to time, we utilize forward-starting interest rate swaps to hedge the variability of the forecasted interest payments on anticipated debt issuances that may result from changes in the benchmark interest rate until the expected debt is issued. When entering into interest rate swap transactions, we become exposed to both credit risk and market risk. We are subject to credit risk when the change in fair value of the swap instrument is positive and the counterparty may fail to perform under the terms of the contract. We are subject to market risk with respect to changes in the underlying benchmark interest rate that impacts the fair value of the swaps. We manage our credit risk by entering into swap transactions only with major financial institutions with investment-grade credit ratings. We manage our market risk by aligning the swap instrument with the existing underlying debt obligation or a specified expected debt issuance, generally associated with the maturity of an existing debt obligation. We designate the swap agreements as cash flow hedges at inception and expect the changes in values to be highly correlated with the changes in value of the anticipated interest payments associated with the forecasted borrowings. During 2016, we entered into seven forward-starting interest rate swaps with a total aggregate notional amount of $350.0 million , which we entered into in anticipation of the issuance of debt on or before January 15, 2018, and eleven forward-starting interest rate swaps with a total aggregate notional amount of $500.0 million , which we entered into in anticipation of the issuance of debt on or before December 15, 2018. In November 2017, we issued $400.0 million of senior unsecured 4.125% fixed-rate notes (see Note 13 - Long-Term Debt for further discussion) and settled the related seven forward-starting interest rate swaps for $20.0 million in settlement proceeds. In December 2018, the underlying future issuance of debt designated to the eleven forward-stating interest rate swaps was no longer probable of occurring due to proceeds from certain asset divestitures being used to reduce debt. This resulted in $51.0 million being reclassified from AOCI as a reduction of interest expense in the fourth quarter of 2018. As of December 31, 2018 , we had no outstanding interest rate swaps. Commodity Derivatives Our Merchant Services segment primarily uses exchange-traded refined petroleum product futures contracts to manage the risk of market price volatility on its refined petroleum product inventories and its physical derivative contracts, which we designated as fair value hedges, with changes in fair value of both the futures contracts and physical inventory reflected in earnings. Our Merchant Services segment also uses exchange-traded refined petroleum contracts to hedge expected future transactions related to certain gasoline inventory that we manage on behalf of a third party, which 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. Any gains or losses incurred on the derivative instruments that are not effective in offsetting changes in fair value or cash flows of the hedged item are recognized immediately in earnings. Additionally, our Merchant Services segment enters into exchange-traded refined petroleum product futures contracts on behalf of our Domestic Pipelines & Terminals segment to manage the risk of market price volatility on the gasoline-to-butane pricing spreads associated with our butane blending activities managed by a third party. These futures contracts are not designated in a hedge relationship for accounting purposes. Physical forward contracts and futures contracts that have not been designated in a hedge relationship are marked-to-market through earnings. The following table summarizes the notional volumes of the net long (short) positions of our commodity derivative instruments outstanding at December 31, 2018 (amounts in thousands of gallons): Volume Derivative Purpose Current Long-Term Derivatives NOT designated as hedging instruments: Physical fixed price derivative contracts (23,119 ) (4,765 ) Physical index derivative contracts 52,912 — Futures contracts for refined petroleum products 29,771 (9,996 ) Hedge Type Derivatives designated as hedging instruments: Futures contracts for refined petroleum products (107,184 ) (420 ) Fair Value Hedge Our futures contracts designated as fair value hedges relate to our inventory portfolio and extend to the first quarter of 2020 . Our futures contracts related to forecasted purchases and sales of refined petroleum products, not designated in a hedging relationship, extend to the first quarter of 2020 . Effective January 2017, the Chicago Mercantile Exchange (“CME”) amended its rulebook, resulting in the characterization of variation margin transfers as settlement payments, as opposed to adjustments to collateral. These amendments impacted the accounting treatment of our exchange-traded derivatives contracts, primarily comprised of our futures contracts, for which the CME serves as the central clearing party, and exchange-settled derivatives traded on the over-the-counter (“OTC”) market. As a result, commencing with the first quarter of 2017, we began reducing the corresponding derivative asset and liability balances for our exchange-settled derivative contracts to reflect the settlement of those positions via the variation margin. The variation margin is now considered partial settlement of the derivative contract and will result in realized gains or losses which, prior to January 1, 2017, were classified as unrealized gains or losses on derivatives. In addition, we maintain an initial margin deposit with the broker in an amount sufficient to cover the fair value of our open futures positions. This margin deposit is considered collateral and is included within prepaid and other current assets in our consolidated balance sheets and is not offset against the fair values of our derivative instruments. The following table sets forth the fair value of each classification of derivative instruments and the locations of the derivative instruments on our consolidated balance sheets at the dates indicated (in thousands): December 31, 2018 Derivatives Derivatives Derivative Netting (1) Total Physical fixed price derivative contracts $ 17,934 $ — $ 17,934 $ (84 ) $ 17,850 Physical index derivative contracts 286 — 286 (117 ) 169 Total current derivative assets 18,220 — 18,220 (201 ) 18,019 Physical fixed price derivative contracts 1,003 — 1,003 — 1,003 Total non-current derivative assets 1,003 — 1,003 — 1,003 Physical fixed price derivative contracts (1,386 ) — (1,386 ) 84 (1,302 ) Physical index derivative contracts (135 ) — (135 ) 117 (18 ) Total current derivative liabilities (1,521 ) — (1,521 ) 201 (1,320 ) Physical fixed price derivative contracts (3 ) — (3 ) — (3 ) Total non-current derivative liabilities (3 ) — (3 ) — (3 ) Net derivative assets $ 17,699 $ — $ 17,699 $ — $ 17,699 ____________________________ (1) Amounts represent the netting of physical fixed and index contracts’ assets and liabilities when a legal right of offset exists. December 31, 2017 Derivatives Derivatives Derivative Netting (1) Total Physical fixed price derivative contracts $ 2,582 $ — $ 2,582 $ (63 ) $ 2,519 Physical index derivative contracts 455 — 455 (9 ) 446 Interest rate derivatives — 31,994 31,994 — 31,994 Total current derivative assets 3,037 31,994 35,031 (72 ) 34,959 Total non-current derivative assets — — — — — Physical fixed price derivative contracts (7,226 ) — (7,226 ) 63 (7,163 ) Physical index derivative contracts (18 ) — (18 ) 9 (9 ) Total current derivative liabilities (7,244 ) — (7,244 ) 72 (7,172 ) Total non-current derivative liabilities — — — — — Net derivative (liabilities) assets $ (4,207 ) $ 31,994 $ 27,787 $ — $ 27,787 ____________________________ (1) Amounts represent the netting of physical fixed and index contracts’ assets and liabilities when a legal right of offset exists. At December 31, 2018 , open refined petroleum product derivative contracts (represented by the physical fixed-price contracts, physical index contracts, and futures contracts for refined products contracts noted above) varied in duration in the overall portfolio, but did not extend beyond July 2020 . In addition, at December 31, 2018 , 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): Year Ended December 31, Location 2018 2017 Derivatives NOT designated as hedging instruments: Physical fixed price derivative contracts Product sales $ 22,046 $ (6,748 ) Physical index derivative contracts Product sales 440 82 Physical fixed price derivative contracts Cost of product sales (1,777 ) 3,937 Physical index derivative contracts Cost of product sales (81 ) 1,147 Futures contracts for refined products Cost of product sales 7,661 13,710 Derivatives designated as fair value hedging instruments: Futures contracts for refined products Cost of product sales $ 42,658 $ (22,362 ) Physical inventory - hedged items Cost of product sales (46,397 ) 32,016 Ineffectiveness excluding the time value component on fair value hedging instruments: Fair value hedge ineffectiveness (excluding time value) Cost of product sales $ 1,335 $ (4,673 ) Time value excluded from hedge assessment Cost of product sales (5,074 ) 14,327 Net (loss) gain for ineffectiveness in income $ (3,739 ) $ 9,654 The change in value recognized in OCI and the losses reclassified from AOCI to income attributable to our derivative instruments designated as cash flow hedges were as follows for the periods indicated (in thousands): Gain (Loss) Recognized 2018 2017 Derivatives designated as cash flow hedging instruments: Interest rate contracts $ 27,739 $ (10,597 ) Commodity derivatives 1,975 (136 ) Total $ 29,714 $ (10,733 ) Gain (Loss) Reclassified Location 2018 2017 Derivatives designated as cash flow hedging instruments: Interest rate contracts Interest and debt expense $ 50,509 $ (11,922 ) Total $ 50,509 $ (11,922 ) Over the next twelve months, we expect to reclassify $9.2 million of net losses attributable to interest rate derivatives from AOCI to earnings as an increase to interest and debt expense. These net losses consist of $11.2 million of amortization of hedge losses on settled forward-starting interest rate swaps, partially offset by $2.0 million of amortization of hedge gains on settled forward-starting interest rate swaps settled in November 2017. Additionally, the unrealized gains and losses for refined petroleum products designated as cash flow hedges at December 31, 2018 , of $2.0 million , are estimated to be realized and reclassified from AOCI to product sales during over the next twelve months. The ineffective portion of the change in fair value of cash flow hedges was not material for the years ended December 31, 2018 and 2017 .

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	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): December 31, 2018 December 31, 2017 Level 1 Level 2 Level 1 Level 2 Financial assets: Physical fixed price derivative contracts $ — $ 18,937 $ — $ 2,582 Physical index derivative contracts — 286 — 455 Interest rate derivatives — — — 31,994 Financial liabilities: Physical fixed price derivative contracts — (1,389 ) — (7,226 ) Physical index derivative contracts — (135 ) — (18 ) Futures contracts for refined products — — — — Fair value $ — $ 17,699 $ — $ 27,787 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 for exchange-settled commodity derivatives at December 31, 2018 are presented after the application of the CME rulebook amendment, which deems that these instruments are settled daily via variation margin payments. As a result of this rulebook amendment, CME-settled derivatives, primarily comprised of our futures contracts for refined petroleum products, are considered to have no fair value at the balance sheet date for financial reporting purposes; however, the derivatives remain outstanding and subject to future commodity price fluctuations until they are settled in accordance with their contractual terms. The values of the Level 2 interest rate derivatives were determined using fair value estimates obtained from our counterparties, which are verified using other available market data, including cash flow models which incorporate market inputs including the implied forward LIBOR yield curve for the same period as the future interest rate swap settlements. Credit value adjustments (“CVAs”), which are used to reflect the potential nonperformance risk of our counterparties, are considered in the fair value assessment of interest rate derivatives. We determined that the impact of CVAs was not significant to the overall valuation of interest rate derivatives as of December 31, 2017 . The values of the Level 2 commodity derivative contracts were calculated using market approaches based on observable market data inputs, including published commodity pricing data, which is verified against other available market data, and market interest rate and volatility data. Level 2 physical fixed price derivative assets are net of CVAs determined using an expected cash flow model, which incorporates assumptions about the credit risk of the derivative contracts based on the historical and expected payment history of each customer, the amount of product contracted for under the agreement and the customer’s historical and expected purchase performance under each contract. The Merchant Services segment determined CVAs are appropriate because few of the Merchant Services segment’s customers entering into these derivative contracts are large organizations with nationally recognized credit ratings. The CVAs were nominal as of December 31, 2018 and 2017 . As of December 31, 2018 and 2017 , 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 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 historical market prices of our publicly issued debt with the market prices of the publicly issued debt of other MLPs with similar credit ratings and terms. The fair value of our variable-rate debt approximates the carrying amount since the associated interest rates are market-based. The carrying value and fair value of our debt, using Level 2 input values, were as follows at the dates indicated (in thousands): December 31, 2018 December 31, 2017 Carrying Fair Value Carrying Fair Value Fixed-rate debt $ 3,546,396 $ 3,364,549 $ 4,241,963 $ 4,384,336 Variable-rate debt 1,168,046 1,172,328 668,562 668,904 Total debt $ 4,714,442 $ 4,536,877 $ 4,910,525 $ 5,053,240 In addition, our pension plan assets are measured at fair value on a recurring basis, based on Level 1 and Level 3 inputs. See Note 18 - Pensions and Other Postretirement Benefits for additional discussion. 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 years ended December 31, 2018 and 2017 . 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. See Note 2 - Summary of Significant Accounting Policies for further discussion of our fair value techniques. For the year ended December 31, 2018 , we recorded a $300.3 million non-cash loss related to the anticipated sale of our equity investment in VTTI based on Level 2 inputs and a $537.0 million non-cash goodwill impairment charge related to our GMT Caribbean and NYH reporting unit based on Level 3 inputs. See Notes 4 - Acquisitions, Investments and Disposition and 10 - Goodwill and Intangible Assets for further discussion on fair value adjustments recorded during the year ended December 31, 2018 . For the year ended December 31, 2017 , there were no significant fair value adjustments related to assets or liabilities reflected in our consolidated financial statements.

PENSIONS AND OTHER POSTRETIREME

PENSIONS AND OTHER POSTRETIREMENT BENEFITS	12 Months Ended
	Dec. 31, 2018
Retirement Benefits [Abstract]
PENSIONS AND OTHER POSTRETIREMENT BENEFITS	PENSIONS AND OTHER POSTRETIREMENT BENEFITS RIGP and Retiree Medical Plan Services Company, which employs the majority of our workforce, sponsors a Retirement Income Guarantee Plan (“RIGP”), which is a defined benefit plan that generally guarantees employees hired before January 1, 1986 a retirement benefit based on years of service and the employee’s highest compensation for any consecutive 5 -year period during the last 10 years of service or other compensation measures as defined under the respective plan provisions. The retirement benefit is subject to reduction at varying percentages for certain offsetting amounts, including benefits payable under a retirement and savings plan discussed further below. Services Company funds this benefit plan through contributions to pension trust assets, generally subject to minimum funding requirements as provided by applicable law. Services Company also sponsors an unfunded post-retirement benefit plan (the “Retiree Medical Plan”), which provides health care and life insurance benefits to certain of its retirees. To be eligible for the health care benefits, an employee must have been hired prior to January 1, 1991 and meet certain age and service requirements. To be eligible for the life insurance benefits, an employee must have been hired prior to January 1, 2002 and meet certain service requirements. The RIGP and Retiree Medical Plan are closed for new participants. The components of projected benefit obligations and plan assets, and the funded status of the RIGP and the Retiree Medical Plan (“the Plans”) were as follows for the periods indicated (in thousands): RIGP Retiree Medical Plan Year Ended December 31, Year Ended December 31, 2018 2017 2018 2017 Change in benefit obligation: Benefit obligation at beginning of year $ 9,847 $ 13,178 $ 29,363 $ 31,958 Service cost (84 ) (58 ) 199 287 Interest cost 293 333 1,029 1,209 Plan participants’ contributions — — 533 481 Actuarial (gain) loss (270 ) (1,524 ) (1,531 ) 689 Settlements (2,127 ) (1,900 ) — — Benefit payments (206 ) (182 ) (2,573 ) (3,074 ) Substantive provision change — — — (2,187 ) Benefit obligation at end of year $ 7,453 $ 9,847 $ 27,020 $ 29,363 Change in plan assets: Fair value of plan assets at beginning of year $ 4,484 $ 4,524 $ — $ — Actual return on plan assets 221 452 — — Plan participants’ contributions — — 533 481 Employer contributions 1,047 1,590 2,040 2,593 Settlements (2,127 ) (1,900 ) — — Benefit payments (206 ) (182 ) (2,573 ) (3,074 ) Fair value of plan assets at end of year $ 3,419 $ 4,484 $ — $ — Funded status at end of year $ (4,034 ) $ (5,363 ) $ (27,020 ) $ (29,363 ) During 2017, the Retiree Medical Plan had a substantive provision change whereby plan participants began sharing a higher portion of future increases in health care costs. Amounts recognized in our consolidated balance sheets for the Plans consist of the following at the dates indicated below (in thousands): RIGP Retiree Medical Plan December 31, December 31, 2018 2017 2018 2017 Liabilities: Accrued employee benefit liabilities - current $ — $ — $ (2,808 ) $ (2,757 ) Accrued employee benefit liabilities - noncurrent (4,034 ) (5,363 ) (24,212 ) (26,606 ) Total $ (4,034 ) $ (5,363 ) $ (27,020 ) $ (29,363 ) AOCI: Prior service credit $ — $ — $ (1,727 ) $ (2,187 ) Net actuarial loss 310 722 2,289 4,082 Total $ 310 $ 722 $ 562 $ 1,895 Information regarding the accumulated benefit obligation in excess of plan assets for the RIGP is as follows at the dates indicated (in thousands): RIGP December 31, 2018 2017 Projected benefit obligation $ 7,453 $ 9,847 Accumulated benefit obligation (1) 7,177 9,128 Fair value of plan assets 3,419 4,484 ____________________________ (1) The accumulated benefit obligation does not include an assumption for future compensation increases. The weighted average assumptions used in determining net periodic benefit cost for the Plans were as follows for the periods indicated: RIGP Retiree Medical Plan Year Ended December 31, Year Ended December 31, 2018 2017 2016 2018 2017 2016 Discount rate 3.3 % 3.2 % 3.0 % 3.6 % 4.0 % 4.1 % Expected return on plan assets 4.0 % 5.8 % 5.8 % N/A N/A N/A Rate of compensation increase 2.0 % 3.0 % 3.0 % 2.0 % 3.0 % 3.0 % The assumptions used in determining benefit obligations for the Plans were as follows at the dates indicated: RIGP Retiree Medical Plan December 31, December 31, 2018 2017 2018 2017 Discount rate 4.3 % 3.3 % 4.4 % 3.6 % Rate of compensation increase 3.0 % 3.0 % 3.0 % 3.0 % The discount rate reflects the rate at which benefits could be effectively settled on the measurement date. The discount rate directly affects the measurement of the benefit obligations of our pension and other postretirement benefit plans. The discount rate is used to allocate the cost of future benefits over time. An increase in the discount rate would reduce the future liability due to higher expected returns and a decrease in the discount rate would increase the liability. The discount rate is determined through general economic and market conditions that affect interest rates as well as the duration of our future liabilities. For the years ended December 31, 2018 , 2017 , and 2016 , the discount rate was determined based on a projection of expected cash flows from the Plans using relevant economic benchmarks available as of each year end. The expected return on plan assets was determined based on projected long-term market returns for each asset class in which the Plans are invested, weighted by the target asset class allocations. The rate of compensation increase represents the long-term assumption for future increases to salaries. The assumed annual rate of increase in the per capita cost of covered health care benefits as of December 31, 2018 in the Retiree Medical Plan was 6.5% for 2019 , grading down to 4.5% in 2025, and thereafter. The assumption of annual change in health care costs is estimated based on national trend rates as well as our historical claims experience. A hypothetical 1% movement in the assumed health care cost trend rates would not significantly affect our benefit cost or obligation. The components of the net periodic benefit cost and other changes recognized in OCI for the Plans were as follows for the periods indicated (in thousands): RIGP Retiree Medical Plan Year Ended December 31, Year Ended December 31, 2018 2017 2016 2018 2017 2016 Components of net periodic benefit cost: Service cost $ (84 ) $ (58 ) $ (34 ) $ 199 $ 287 $ 323 Interest cost (1) 293 333 421 1,029 1,209 1,309 Expected return on plan assets (1) (168 ) (251 ) (256 ) — — — Amortization of prior service credit (1) — — — (461 ) — — Actuarial loss due to settlements (1) 88 150 598 — — — Amortization of unrecognized loss (1) — 19 522 263 — 766 Net periodic benefit cost $ 129 $ 193 $ 1,251 $ 1,030 $ 1,496 $ 2,398 RIGP Retiree Medical Plan Year Ended December 31, Year Ended December 31, 2018 2017 2016 2018 2017 2016 Other changes in plan assets and benefit obligations recognized in OCI: Prior service credit $ — $ — $ — $ — $ (2,187 ) — Net actuarial (gain) loss (324 ) (1,725 ) (2,068 ) (1,531 ) 688 2,871 Amortization of unrecognized loss — (19 ) (522 ) (263 ) — (766 ) Actuarial loss due to settlements (88 ) (150 ) (598 ) — — — Amortization of prior service credit — — — 461 — — Total recognized in OCI $ (412 ) $ (1,894 ) $ (3,188 ) $ (1,333 ) $ (1,499 ) $ 2,105 Total recognized in net period benefit cost and OCI $ (283 ) $ (1,701 ) $ (1,937 ) $ (303 ) $ (3 ) $ 4,503 ___________________________ (1) These components of net periodic benefit cost are reported on the Consolidated Statements of Operations as other expense. See Note 2 - Summary of Significant Accounting Policies for further discussion on the accounting guidance. Actuarial gains and losses are amortized over the average future service period of current plan participants expected to receive benefits. The corridor approach is used to determine when actuarial gains and losses are to be amortized and is equal to 10 percent of the greater of the projected benefit obligation or the fair value of plan assets. The amount of gain or loss in excess of the calculated corridor is subject to amortization. We expect that the following amounts, currently included in OCI, for the Plans will be recognized in our consolidated statement of operations during the year ending December 31, 2019 (in thousands): RIGP Retiree Medical Plan Prior service credit $ — $ (461 ) We estimate the following benefit payments, which reflect expected future service, as appropriate, will be paid for the Plans in the years indicated below as such (in thousands): RIGP Retiree Medical Plan 2019 $ 2,081 $ 2,870 2020 674 2,718 2021 847 2,581 2022 735 2,503 2023 653 2,473 Thereafter 1,520 9,151 We expect to contribute $3.2 million to our benefit plans in 2019. Funding requirements for subsequent years are uncertain and will depend on whether there are any changes in the actuarial assumptions used to calculate plan funding levels, the actual return on plan assets and any legislative or regulatory changes affecting plan funding requirements. For tax planning, financial planning, cash flow management or cost reduction purposes, we may increase, accelerate, decrease or delay contributions to the plan to the extent permitted by law. We do not fund the Retiree Medical Plan and, accordingly, no assets are invested in the plan. A summary of investments in the RIGP are as follows at the dates indicated (in thousands): December 31, 2018 December 31, 2017 Level 1 Level 3 Level 1 Level 3 Mutual fund - fixed-income securities $ 1,576 $ — $ 2,454 $ — Mutual fund - money market 105 — 222 — Coal lease — 1,738 — 1,808 Fair value of plan assets $ 1,681 $ 1,738 $ 2,676 $ 1,808 The values of the Level 1 mutual funds were based on quoted market prices in active markets for identical assets. The mutual fund — fixed-income securities generally seeks long-term growth of capital and income and invests in a portfolio consisting primarily of fixed-income securities. The values of the Level 3 coal lease were determined using an expected present value of future cash flows valuation model. This investment relates to a 20.8% interest in a coal lease, which derives value from specified minimum royalty payments received from CONSOL Energy Inc. related to coal reserves mined from two Pennsylvania mines owned by the lessor. The coal lease extends through 2023. The following table summarizes the activity in our Level 3 pension assets for the periods indicated (in thousands): Year Ended 2018 2017 Beginning balance, January 1 $ 1,808 $ 2,007 Royalty payments received 400 380 Unrealized loss (70 ) (199 ) Transfers out of Level 3 (400 ) (380 ) Ending balance, December 31 $ 1,738 $ 1,808 The RIGP investment policy does not target specific asset classes, but seeks to balance the preservation and growth of capital in the plan’s mutual funds with the income derived with proceeds from the coal lease. While no significant changes in the asset class allocation of the plan are expected during the upcoming year, Services Company may make changes at any time. Retirement and Savings Plans Services Company also sponsors the Retirement and Savings Plan (“RASP”) through which it provides retirement benefits for substantially all of its regular full-time employees located in the continental United States, except those covered by certain labor contracts. The RASP consists of two components. Under the first component, Services Company contributes 5% of each eligible employee’s covered salary to an employee’s separate account maintained in the RASP. Under the second component, Services Company makes a matching contribution into the employee’s separate account for 100% of an employee’s contribution to the RASP up to 5% (or 6% if an employee has over 20 years of service) of an employee’s eligible covered salary. Total costs of providing these benefits through the RASP were $18.0 million , $17.6 million and $16.4 million during the years ended December 31, 2018 , 2017 and 2016 , respectively. Services Company also participates in a multi-employer retirement income plan and a multi-employer postretirement benefit plan, both of which provide retirement and health care and life insurance benefits to employees covered by certain labor contracts. We do not administer these plans and contribute to them in accordance with the provisions of negotiated labor contracts. The costs of providing these benefits, in aggregate, were $1.4 million for all years ended December 31, 2018 , 2017 , and 2016 , respectively. Additionally, certain of our wholly owned subsidiaries provide a savings and retirement plan to employees. The costs of providing these benefits were $1.5 million , $2.1 million and $1.4 million for the years ended December 31, 2018 , 2017 and 2016 , respectively. Employee Stock Ownership Plan Services Company provides the ESOP to the majority of its employees hired before September 16, 2004. Employees hired by Services Company after September 15, 2004 and certain employees covered by a union multi-employer pension plan do not participate in the ESOP. The ESOP owns all of the outstanding common stock of Services Company. Buckeye, as primary beneficiary, consolidates Services Company. The ESOP was frozen with respect to benefits effective March 27, 2011 (the “Freeze Date”). No Services Company contributions (other than dividend equivalent payments) have been made on behalf of current participants in the Plan after the Freeze Date. Even though contributions under the ESOP are no longer being made, each eligible participant’s ESOP account continues to be credited with its share of any stock dividends or other stock distributions associated with Services Company stock. Individual employees were allocated shares based upon the ratio of their eligible compensation to total eligible compensation. Eligible compensation generally included base salary, overtime payments and certain bonuses. All Services Company stock has been released to ESOP participants. Total ESOP related costs charged to earnings were nominal for each of the years ended December 31, 2018 , 2017 , and 2016 .

UNIT-BASED COMPENSATION PLANS

UNIT-BASED COMPENSATION PLANS	12 Months Ended
	Dec. 31, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
UNIT-BASED COMPENSATION PLANS	UNIT-BASED COMPENSATION PLANS We award unit-based compensation to employees and directors primarily under the LTIP, which was approved by the Partnership’s unitholders in June 2013 and subsequently amended and restated in June 2017. The LTIP replaced the 2009 Long-Term Incentive Plan (the “2009 Plan”), which was merged with and into the LTIP, and no further grants have since been made under the 2009 Plan. We formerly awarded options to acquire LP Units to employees pursuant to the Buckeye Partners, L.P. Unit Option and Distribution Equivalent Plan (the “Option Plan”). We recognized compensation expense related to the LTIP, which includes awards under the LTIP, and the Option Plan of $22.1 million , $30.6 million and $33.5 million for the years ended December 31, 2018 , 2017 and 2016 , respectively. LTIP The LTIP, which is overseen by the Compensation Committee of the Board of Directors of Buckeye GP (the “Compensation Committee”), provides for the grant of phantom units, performance units and in certain cases, distribution equivalent rights (“DERs”), which provide the participant a right to receive payments based on distributions we make on our LP Units. Phantom units are notional LP Units whose vesting is subject to service-based restrictions or other conditions established by the Compensation Committee in its discretion. Phantom units entitle a participant to receive an LP Unit without payment of an exercise price upon vesting. Performance units are notional LP Units whose vesting is subject to the attainment of one or more performance goals, and which also entitle a participant to receive LP Units without payment of an exercise price upon vesting. DERs are rights to receive a cash payment per phantom unit or performance unit, as applicable, equal to the per unit cash distribution we pay on our LP Units. If awards are forfeited, terminated or otherwise not paid in full, the LP Units underlying such awards will again be available for purposes of the LTIP, subject to certain limitations. Persons eligible to receive grants under the LTIP are (i) officers and employees of Buckeye GP and any of our affiliates who provide services to us and (ii) independent members of the Board of Directors of Buckeye GP. Phantom units or performance units may be granted to participants at any time as determined by the Compensation Committee. A total of 2,115,169 LP Units were available for issuance under the LTIP as of December 31, 2018 . Deferral Plan under the LTIP On December 13, 2016, the Compensation Committee approved the terms of the amended and restated Buckeye Partners, L.P. Unit Deferral and Incentive Plan (“Deferral Plan”). The Compensation Committee is expressly authorized to adopt the Deferral Plan under the terms of the LTIP, which grants the Compensation Committee the authority to establish a program pursuant to which our phantom units may be awarded in lieu of cash compensation at the election of the employee. At December 31, 2018 , 2017 and 2016 , eligible employees were allowed to defer up to 50% of their 2018 , 2017 and 2016 compensation awards under our Annual Incentive Compensation Plan or other discretionary bonus program in exchange for grants of phantom units equal in value to the amount of their cash award deferral (each such unit, a “Deferral Unit”). Participants also receive one matching phantom unit for each Deferral Unit. Deferral Units and their matching phantom units vest on December 15 of the second year after the year in which such units are granted. During 2018 and 2017 , 149,726 and 145,138 phantom units were granted under this plan, respectively. These grants are included as granted in the LTIP activity table below. Awards under the LTIP During the year ended December 31, 2018 , the Compensation Committee granted 454,994 phantom units to employees (including the 149,726 phantom units granted pursuant to the Deferral Plan discussed above), 18,000 phantom units to independent directors of Buckeye GP and 274,688 performance units to employees. Generally, vesting criteria for the performance units are the attainment of certain performance goals during the third year of a three-year period and remaining employed by us throughout such three -year period. Phantom unit grantees will be paid quarterly distributions on DERs associated with the applicable phantom units over their respective vesting periods of one to three years in the same amounts per phantom unit as distributions paid on our LP Units over those same periods. The phantom unit DERs distributions were $4.3 million and $4.1 million for the years ended December 31, 2018 and 2017 , respectively. Distributions may be paid on performance units at the end of the three -year vesting period. In such case, DERs will be paid on the number of LP Units for which the performance units will be settled. Quarterly distributions related to DERs associated with phantom and performance units are recorded as a reduction of our Limited Partners’ Capital on our consolidated balance sheets. The following table sets forth the LTIP activity for the periods indicated (in thousands, except per unit amounts): Number of Weighted (1) Unvested at January 1, 2017 1,296 $ 63.54 Granted (2) 547 69.91 Performance adjustment (3) 32 71.50 Vested (386 ) 70.98 Forfeited (39 ) 64.26 Unvested at December 31, 2017 1,450 $ 64.04 Granted (2) 748 48.16 Performance adjustment (3) 39 73.17 Vested (544 ) 68.84 Forfeited (48 ) 58.46 Unvested at December 31, 2018 1,645 $ 55.52 ____________________________ (1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. The weighted-average grant date fair value per LP Unit for forfeited and vested awards is determined before an allowance for forfeitures. (2) Includes both phantom and performance awards. Performance awards are granted at a target amount but, depending on our performance during the vesting period with respect to certain pre-established goals, the number of LP Units issued upon vesting of such performance awards can be greater or less than the target amount. (3) Represents the LP Units issued in excess of target amounts for performance awards that vested during the year ended December 31, 2018 and 2017 as a result of our above target performance with respect to applicable performance goals. At December 31, 2018 , we expect to recognize $27.5 million of compensation expense related to the unvested LTIP over a weighted average remaining period of 1.5 years . Unit Option and Distribution Equivalent Plan We also sponsor the Option Plan pursuant to which we historically granted options to employees to purchase LP Units at the market price of our LP Units on the date of grant. Generally, the options vest three years from the date of grant and expire ten years from the date of grant. As unit options are exercised, we issue new LP Units to the holder. We have not historically repurchased, and do not expect to repurchase in 2019 , any of our LP Units. Following the adoption of the 2009 Plan, effective March 20, 2009, we ceased making additional grants under the Option Plan. For the year ended December 31, 2017, options to purchase ten LP Units were exercised under the Option Plan at a weighted average strike price of $50.36 per LP Unit. The total intrinsic value of options exercised during the years ended December 31, 2018 , 2017 and 2016 was zero , $0.2 million and $0.1 million , respectively. At December 31, 2018 and 2017 , there was no unrecognized compensation cost related to unvested options, as all options were vested as of November 24, 2011. The fair value of options vested was zero for each of the years ended December 31, 2018 , 2017 and 2016 , respectively. There were no options outstanding for the years ended December 31, 2018 and 2017.

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2018
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	RELATED PARTY TRANSACTIONS We are managed by Buckeye GP, our general partner. Services Company is considered a related party with respect to us. Services Company employees provide services to the majority of our operating subsidiaries. Pursuant to a services agreement entered into in December 2004, our operating subsidiaries reimburse Services Company for the costs of the services provided by Services Company. As Services Company is consolidated, these amounts eliminate in consolidation. Services Company, which is beneficially owned by the ESOP, owned 0.5 million of our LP Units ( 0.3% of our LP Units outstanding) as of December 31, 2018 . Distributions received by Services Company from us on such LP Units are distributed to ESOP participants for investment pursuant to the terms of the ESOP. Distributions paid to Services Company totaled $2.4 million , $2.9 million and $3.0 million for the years ended December 31, 2018 , 2017 and 2016 , respectively. Total distributions paid to Services Company decrease over time as Services Company sells LP Units to fund benefits payable to ESOP participants who exit the ESOP or otherwise choose to diversify their holdings.

PARTNERS' CAPITAL AND DISTRIBUT

PARTNERS' CAPITAL AND DISTRIBUTIONS	12 Months Ended
	Dec. 31, 2018
Equity [Abstract]
PARTNERS' CAPITAL AND DISTRIBUTIONS	PARTNERS’ CAPITAL AND DISTRIBUTIONS Our LP Units represent limited partner interests, which give the holders thereof the right to participate in distributions and to exercise the other rights and privileges available to them under our partnership agreement. There were no Class C Units outstanding as of December 31, 2018 . The partnership agreement provides that, without prior approval of our limited partners holding an aggregate of at least two-thirds of the outstanding LP Units, we cannot issue any limited partnership interests of a class or series having preferences or other special or senior rights over the LP Units. Equity Offerings In October 2016, we completed a public offering of 7.75 million LP Units pursuant to an effective shelf registration statement, which priced at $66.05 per unit. The underwriters also exercised an option to purchase 1.16 million additional LP Units, resulting in total gross proceeds of $588.7 million before deducting underwriting fees and other related expenses of $8.0 million. We used the net proceeds from this offering to initially reduce the indebtedness outstanding under our Credit Facility and for general partnership purposes, as well as to subsequently fund a portion of the purchase price for the VTTI Acquisition in January 2017. In March 2018, we issued approximately 6.2 million Class C Units in a private placement for aggregate gross proceeds of $265.0 million . The net proceeds were $262.0 million , after deducting issuance costs of approximately $3.0 million . We used the net proceeds from this offering to reduce the indebtedness outstanding under our Credit Facility, to partially fund growth capital expenditures and for general partnership purposes. Class C Units represented a separate class of our limited partnership interests. The Class C Units were substantially similar in all respects to our existing LP units, except that Buckeye had the option to pay distributions on the Class C Units in cash or by issuing additional Class C Units. In November 2018, we announced a reduction in our declared quarterly cash distribution. As a result, all 6,714,963 Class C Units outstanding as of September 30, 2018 converted into LP Units on a one-for-one basis on November 5, 2018. Accordingly, the holders of these newly converted LP Units received the quarterly cash distribution of $0.75 per LP Unit, instead of an in-kind distribution of additional Class C Units. At-the-Market Offering Program In March 2016, we entered into an equity distribution agreement (the “Equity Distribution Agreement”) with J.P. Morgan Securities LLC, BB&T Capital Markets, a division of BB&T Securities, LLC, BNP Paribas Securities Corp., Deutsche Bank Securities Inc., Jefferies LLC, Morgan Stanley & Co. LLC, RBC Capital Markets, LLC, and SMBC Nikko Securities America, Inc. (collectively, the “ATM Underwriters”). Under the terms of the Equity Distribution Agreement, we could offer and sell up to $500.0 million in aggregate gross sales proceeds of LP Units from time to time through the ATM Underwriters, acting as agents of Buckeye or as principals, subject in each case to the terms and conditions set forth in the Equity Distribution Agreement. Sales of LP Units, if any, may be made by means of ordinary brokers’ transactions on the New York Stock Exchange or otherwise at market prices prevailing at the time of sale, at prices related to prevailing market prices or at negotiated prices or as otherwise agreed with any of such firms. During the years ended December 31, 2017 and 2016 , we sold 6.2 million and 1.6 million LP Units in aggregate under the equity distribution agreements and received $345.8 million and $108.4 million in net proceeds after deducting commissions and other related expenses, including $1.9 million and $1.1 million of compensation paid in aggregate to the agents under their equity distribution agreements, respectively. The 6.2 million LP Units sold under the Equity Distribution Agreement in 2017 included a block sale of approximately 3.8 million LP Units on September 21, 2017. We did not issue any LP Units during the year ended December 31, 2018 under the Equity Distribution Agreement, which expired on January 15, 2018. Summary of Changes in Outstanding Units The following is a summary of changes in Buckeye’s outstanding units for the periods indicated (in thousands): LP Units Class C Units Total Units outstanding at January 1, 2016 129,524 — 129,524 LP Units issued pursuant to the Option Plan (1) 6 — 6 LP Units issued pursuant to the LTIP (1) 254 — 254 Issuance of units to institutional investors 8,913 — 8,913 Issuance of units through equity distribution agreements 1,567 — 1,567 Units outstanding at December 31, 2016 140,264 — 140,264 LP Units issued pursuant to the Option Plan (1) 10 — 10 LP Units issued pursuant to the LTIP (1) 244 — 244 Issuance of units through equity distribution agreements 6,159 — 6,159 Units outstanding at December 31, 2017 146,677 — 146,677 LP Units issued pursuant to the LTIP (1) 363 — 363 Issuance of Class C Units — 6,221 6,221 Issuance of Class C Units in lieu of quarterly cash distributions — 494 494 Conversion of Class C Units to LP Units 6,715 (6,715 ) — Units outstanding at December 31, 2018 153,755 — 153,755 ____________________________ (1) The number of units issued represents issuance net of tax withholding. Cash Distributions We generally make quarterly cash distributions to unitholders of a portion of our available cash, generally defined in our partnership agreement as consolidated cash receipts less consolidated cash expenditures and such retentions for working capital, anticipated cash expenditures and contingencies as our general partner deems appropriate. Cash distributions are paid for LP Units and for DERs with respect to certain unit-based compensation awards outstanding as of each respective period. Cash distributions paid to unitholders of Buckeye for the periods indicated were as follows (in thousands, except per unit amounts): Amount Per Total Cash Record Date Payment Date LP Unit Distributions February 23, 2016 March 1, 2016 $ 1.1875 $ 154,928 May 16, 2016 May 23, 2016 1.2000 157,247 August 15, 2016 August 22, 2016 1.2125 159,881 November 15, 2016 November 22, 2016 1.2250 172,673 Total $ 644,729 February 21, 2017 February 28, 2017 $ 1.2375 $ 174,888 May 15, 2017 May 22, 2017 1.2500 176,832 August 14, 2017 August 21, 2017 1.2625 179,631 November 13, 2017 November 20, 2017 1.2625 186,042 Total $ 717,393 February 20, 2018 February 27, 2018 $ 1.2625 $ 186,764 May 14, 2018 May 21, 2018 1.2625 186,766 August 13, 2018 August 20, 2018 1.2625 186,624 November 13, 2018 November 20, 2018 0.7500 115,969 Total $ 676,123 On February 8, 2019 , we announced a quarterly distribution of $0.75 per LP Unit that will be paid on February 26, 2019 , to unitholders of record on February 19, 2019 . Based on the LP Units and distribution equivalent rights with respect to certain unit-based compensation awards outstanding as of December 31, 2018 , cash expected to be distributed to LP unitholders on February 26, 2019 is estimated to be approximately $115.9 million .

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES Our current and deferred income tax expense (benefit) was as follows (in thousands): December 31, 2018 2017 2016 Current income tax expense (benefit) $ 2,603 $ 297 $ (276 ) Deferred income tax expense 1,137 575 1,736 Total income tax expense $ 3,740 $ 872 $ 1,460 We have no unrecognized tax benefits related to uncertain tax positions. Deferred tax assets and liabilities as of December 31, 2018 and 2017 relate to BDL and Buckeye Caribbean. The Tax Act, which went into effect January 1, 2018, did not have a significant impact on our consolidated financial statements. Our effective tax rate differs from statutory rates, primarily due to being structured as an MLP, which is a pass-through entity for federal income tax purposes, while being treated as a taxable entity in certain states. The two primary drivers of our state income taxes are the New York City Unincorporated Business Tax and Texas Margin Tax. The net operating loss carryforwards, underlying related deferred tax assets, will expire between 2020 and 2022 for Buckeye Caribbean, and 2036 and 2037 for BDL. A valuation allowance has been provided for deferred tax assets that are not more likely than not to be realized. The tax effects of significant items comprising our net deferred tax assets and liabilities at December 31, 2018 and 2017 are as follows (in thousands): December 31, 2018 2017 Deferred tax asset: Net operating loss carryforward $ 18,757 $ 19,234 Capital loss carryforward 11,453 11,453 Other 2,452 2,697 Total deferred tax asset $ 32,662 $ 33,384 Deferred tax liability: Property, plant and equipment $ 1,132 $ 1,536 Other 132 83 Total deferred tax liability 1,264 1,619 Net deferred tax asset 31,398 31,765 Less: Valuation allowance (30,203 ) (29,451 ) Deferred taxes, net $ 1,195 $ 2,314 As of December 31, 2018 , BDL’s tax years from 2015 forward and Buckeye Caribbean’s tax years from 2014 forward were open to examination by the Internal Revenue Service and Puerto Rico Treasury Department, respectively.

(LOSS) EARNINGS PER UNIT

(LOSS) EARNINGS PER UNIT	12 Months Ended
	Dec. 31, 2018
Earnings Per Share [Abstract]
(LOSS) EARNINGS PER UNIT	(LOSS) EARNINGS PER UNIT The following tables set forth the calculation of basic and diluted (loss) earnings per unit, attributable to Buckeye’s unit holders, taking into consideration net income allocable to participating securities, as well as the reconciliation of basic weighted average units outstanding to diluted weighted average units outstanding (in thousands, except per unit amounts). Year Ended December 31, 2018 2017 2016 Net (loss) income attributable to unitholders $ (62,853 ) $ 474,794 $ 535,608 Basic: Weighted average units outstanding - basic 152,355 142,501 132,242 (Loss) earnings per unit - basic $ (0.41 ) $ 3.33 $ 4.05 Diluted: Weighted average units outstanding - basic 152,355 142,501 132,242 Effect of dilutive securities (1) — 643 685 Weighted average units outstanding - diluted 152,355 143,144 132,927 (Loss) earnings per unit - diluted $ (0.41 ) $ 3.32 $ 4.03 ____________________________ (1) Excludes 413,732 units from the computation of (loss) earnings per unit on a diluted basis as their effect was anti-dilutive for the year ended December 31, 2018 .

BUSINESS SEGMENTS

BUSINESS SEGMENTS	12 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
BUSINESS SEGMENTS	BUSINESS SEGMENTS We operate and report in three business segments: (i) Domestic Pipelines & Terminals; (ii) Global Marine Terminals; and (iii) Merchant Services. All inter-segment transactions have been eliminated in consolidation. Domestic Pipelines & Terminals The Domestic Pipelines & Terminals segment receives liquid petroleum products from refineries, connecting pipelines, vessels, trains, and bulk and marine terminals, transports those products to other locations for a fee, and provides bulk liquid storage and terminal throughput services. The segment also has butane blending capabilities and provides crude oil services, including train loading/unloading, storage and throughput. This segment owns and operates pipeline systems and liquid petroleum products terminals in the continental United States, including three terminals owned by the Merchant Services segment but operated by the Domestic Pipelines & Terminals segment, and two underground propane storage caverns. Additionally, this segment provides turn-key operations and maintenance of third-party pipelines and performs pipeline construction management services typically for cost plus a fixed or variable fee. Global Marine Terminals The Global Marine Terminals segment provides marine accessible bulk storage and blending services, rail and truck rack loading/unloading along with petroleum processing services across our network of marine terminals located primarily in the East Coast and Gulf Coast regions of the United States, as well as in the Caribbean. Our operating locations facilitate global flows of crude and refined petroleum products, offer connectivity between supply areas and market centers, and provide premier storage, marine terminalling, blending, and processing services to a diverse customer base. Merchant Services The Merchant Services segment is a wholesale distributor of refined petroleum products in the continental United States and in the Caribbean. The segment’s products include gasoline, natural gas liquids, ethanol, biodiesel and petroleum distillates such as heating oil, diesel fuel, kerosene and fuel oil. The segment owns three terminals, which are operated by the Domestic Pipelines & Terminals segment. The segment’s customers consist principally of product wholesalers, as well as major commercial users of these refined petroleum products. Financial Information by Segment For the years ended December 31, 2018 , 2017 and 2016 , no customer contributed 10% or more of consolidated revenue. The following tables provide information about our revenue types by reportable segment for the periods indicated (in thousands). Prior periods have been disaggregated for comparison purposes. Year Ended December 31, 2018 Domestic Pipelines & Terminals Global Marine Terminals Merchant Services Intersegment Eliminations Total Revenue from contracts with customers Pipeline transportation $ 503,781 $ — $ — $ (11,656 ) $ 492,125 Terminalling and storage services 437,845 386,021 — (37,017 ) 786,849 Product sales — 5,412 2,033,646 (2,629 ) 2,036,429 Other services 44,880 1,209 7,385 (1,390 ) 52,084 Total revenue from contracts with customers 986,506 392,642 2,041,031 (52,692 ) 3,367,487 Revenue from leases 37,684 172,260 — (284 ) 209,660 Commodity derivative contracts, net 5,894 — 531,128 (5,894 ) 531,128 Total revenue $ 1,030,084 $ 564,902 $ 2,572,159 $ (58,870 ) $ 4,108,275 Year Ended December 31, 2017 Domestic Pipelines & Terminals Global Marine Terminals Merchant Services Intersegment Eliminations Total Revenue from contracts with customers Pipeline transportation $ 498,974 $ — $ — $ (17,648 ) $ 481,326 Terminalling and storage services 447,703 466,489 — (28,822 ) 885,370 Product sales — 3,891 1,531,433 (12,788 ) 1,522,536 Other services 50,484 3,547 14,171 (707 ) 67,495 Total revenue from contracts with customers 997,161 473,927 1,545,604 (59,965 ) 2,956,727 Revenue from leases 38,504 160,822 — (525 ) 198,801 Commodity derivative contracts, net (2 ) — 492,617 2 492,617 Total revenue $ 1,035,663 $ 634,749 $ 2,038,221 $ (60,488 ) $ 3,648,145 Year Ended December 31, 2016 Domestic Pipelines & Terminals Global Marine Terminals Merchant Services Intersegment Eliminations Total Revenue from contracts with customers Pipeline transportation $ 480,730 $ — $ — $ (18,224 ) $ 462,506 Terminalling and storage services 448,322 520,411 — (29,645 ) 939,088 Product sales — 304 1,155,276 (5,902 ) 1,149,678 Other services 39,780 435 11,584 (1,624 ) 50,175 Total revenue from contracts with customers 968,832 521,150 1,166,860 (55,395 ) 2,601,447 Revenue from leases 42,084 150,315 — (525 ) 191,874 Commodity derivative contracts, net 780 — 455,055 (780 ) 455,055 Total revenue $ 1,011,696 $ 671,465 $ 1,621,915 $ (56,700 ) $ 3,248,376 The following tables summarize our revenues by major geographic area, for the periods indicated (in thousands): Year Ended December 31, 2018 2017 2016 Revenue: United States $ 3,868,364 $ 3,361,160 $ 2,915,619 International 239,911 286,985 332,757 Total revenue $ 4,108,275 $ 3,648,145 $ 3,248,376 The following tables summarize our earnings (losses) from equity investments by each segment for the periods indicated (in thousands): Year Ended December 31, 2018 2017 2016 Earnings (loss) from equity investments: Domestic Pipelines & Terminals $ 13,232 $ 13,095 $ 11,536 Global Marine Terminals (287,355 ) 22,910 — Total earnings from equity investments $ (274,123 ) $ 36,005 $ 11,536 Year Ended December 31, 2018 2017 2016 Capital expenditures (1) Domestic Pipelines & Terminals $ 311,335 $ 250,454 $ 294,849 Global Marine Terminals 156,258 182,267 191,422 Merchant Services 18 614 45 Total capital expenditures, net $ 467,611 $ 433,335 $ 486,316 ____________________________ (1) Amounts exclude the impact of accruals. See Note 25 - Supplemental Cash Flow Information for further discussion. December 31, 2018 2017 Total Assets: Domestic Pipelines & Terminals $ 4,042,864 $ 3,936,058 Global Marine Terminals 4,989,503 5,924,731 Merchant Services 323,183 443,870 Total assets $ 9,355,550 $ 10,304,659 The Global Marine Terminals segment’s long-lived assets consist of property, plant and equipment, goodwill, intangible assets and other non-current assets. Total long-lived assets located in our international locations were $1.6 billion and $2.1 billion for the years ended December 31, 2018 and 2017 , respectively. Adjusted EBITDA Adjusted EBITDA is a measure not defined by GAAP. We define Adjusted EBITDA as earnings (losses) before interest expense, income taxes, depreciation and amortization, further adjusted to exclude certain non-cash items, such as non-cash compensation expense; transaction, transition, and integration costs associated with acquisitions; certain gains and losses on foreign currency transactions and foreign currency derivative financial instruments, as applicable; and certain other operating expense or income items, reflected in net income, that we do not believe are indicative of our core operating performance results and business outlook, such as hurricane-related costs, gains and losses on property damage recoveries, non-cash impairment charges, and gains and losses on asset sales. The definition of Adjusted EBITDA is also applied to our proportionate share in the Adjusted EBITDA of significant equity method investments, such as that in VTTI, and is not applied to our less significant equity method investments. The calculation of our proportionate share of the reconciling items used to derive Adjusted EBITDA was based upon our 50% equity interest in VTTI, prior to adjustments related to noncontrolling interests in several of its subsidiaries and partnerships, which are immaterial. Due to certain terms of the definitive agreement regarding the divestiture of our equity interest in VTTI, we determined we no longer had the ability to exercise significant influence over the operating and financial policies of VTTI and therefore, accounted for our investment at fair value. Accordingly, beginning in the fourth quarter of 2018 and prospectively, we no longer applied the definition of Adjusted EBITDA to our investment in VTTI. Adjusted EBITDA is a non-GAAP financial measure that is used by our senior management, including our Chief Executive Officer, to assess the operating performance of our business and optimize resource allocation. We use Adjusted EBITDA as a primary measure 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. 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 table presents a reconciliation of consolidated net (loss) income, which is the most comparable financial measure under GAAP, to Adjusted EBITDA, as well as Adjusted EBITDA by segment for the periods indicated (in thousands): December 31, 2018 2017 2016 Reconciliation of Net (loss) income to Adjusted EBITDA: Net (loss) income $ (51,915 ) $ 493,665 $ 548,675 Less: Net income attributable to noncontrolling interests (7,123 ) (14,863 ) (13,067 ) Net (loss) income attributable to Buckeye Partners, L.P. (59,038 ) 478,802 535,608 Add: Interest and debt expense 190,172 225,583 194,922 Income tax expense 3,740 872 1,460 Depreciation and amortization (1) 269,423 269,243 254,659 Non-cash unit-based compensation expense 21,776 30,302 33,344 Acquisition and transition expense (2) 11,321 4,226 8,196 Hurricane-related costs, net of recoveries (3) 124 5,780 16,795 Proportionate share of Adjusted EBITDA for equity method investment in VTTI (4) 101,435 126,642 — Goodwill impairment 536,964 — — Loss (earnings) from the equity method investment in VTTI (4) 286,633 (22,910 ) — Less: Amortization of unfavorable storage contracts (5) — — (5,979 ) Gains on property damage recoveries (6) (14,535 ) (4,621 ) (5,700 ) Gain on sale of ammonia pipeline — — (5,299 ) Gain on sale of DPTS asset package (342,984 ) — — Adjusted EBITDA $ 1,005,031 $ 1,113,919 $ 1,028,006 Adjusted EBITDA Domestic Pipelines & Terminals $ 561,961 $ 573,021 $ 568,405 Global Marine Terminals 428,663 512,821 427,229 Merchant Services 14,407 28,077 32,372 Adjusted EBITDA $ 1,005,031 $ 1,113,919 $ 1,028,006 ____________________________ (1) Includes 100% of the depreciation and amortization expense of $73.8 million , $72.4 million and $71.7 million for Buckeye Texas for the years ended December 31, 2018 , 2017 and 2016 , respectively. In April 2018, we acquired our business partner’s 20% ownership interest in Buckeye Texas and, as a result, own 100% of Buckeye Texas. (2) Represents transaction, internal and third-party costs related to asset acquisition and integration. (3) Represents costs incurred at our BBH facility in the Bahamas, Yabucoa Terminal in Puerto Rico, Corpus Christi facilities in Texas, and certain terminals in Florida, as a result of hurricanes which occurred in 2017 and 2016, consisting of operating expenses and write-offs of damaged long-lived assets, net of insurance recoveries. (4) Due to the significance of our equity method investment in VTTI, effective January 1, 2017, we applied the definition of Adjusted EBITDA, covered in our description of Adjusted EBITDA, with respect to our proportionate share of VTTI’s Adjusted EBITDA. The calculation of our proportionate share of the reconciling items used to derive Adjusted EBITDA is based upon our 50% equity interest in VTTI, prior to adjustments related to noncontrolling interests in several of its subsidiaries and partnerships, which are immaterial. Due to certain terms of the definitive agreement regarding the divestiture of our equity interest in VTTI, we discontinued the equity method of accounting and recorded our interest at fair value. Accordingly, beginning in the fourth quarter of 2018 and prospectively, we no longer recorded any equity earnings or reflected any contributions from VTTI to our Adjusted EBITDA. Included in loss (earnings) from the equity method investment in VTTI for the year ended December 31, 2018 , is a $300.3 million non-cash loss on the sale of our investment in VTTI as discussed in Note 4 - Acquisitions, Investments and Disposition. (5) Represents fair value adjustment amortization related to certain storage contracts acquired in the BBH acquisition. These contracts were fully amortized by December 31, 2016. (6) Represents gains on recoveries of property damages caused by third parties, which, for 2018, primarily related to a settlement in connection with a 2012 vessel allision with a jetty at our BBH facility in the Bahamas, and for 2017, primarily related to a settlement in connection with a 2014 vessel allision with a ship dock at our terminal located in Pennsauken, New Jersey.

SUPPLEMENTAL CASH FLOW INFORMAT

SUPPLEMENTAL CASH FLOW INFORMATION	12 Months Ended
	Dec. 31, 2018
Supplemental Cash Flow Elements [Abstract]
SUPPLEMENTAL CASH FLOW INFORMATION	SUPPLEMENTAL CASH FLOW INFORMATION Supplemental cash flows and non-cash transactions were as follows for the periods indicated (in thousands): Year Ended December 31, 2018 2017 2016 Cash paid for interest (net of capitalized interest) (1) $ 224,371 $ 210,723 $ 174,555 Cash paid for income taxes 1,282 1,333 812 Capitalized interest 8,921 4,792 4,371 ____________________________ (1) Excludes proceeds of $51.0 million related to the settlement of our interest rate swaps. See Note 16 - Derivative Instruments and Hedging Activities for further discussion. Liabilities related to capital projects outstanding at December 31, 2018 , 2017 , and 2016 of $85.3 million , $62.6 million , and $59.1 million , respectively, are not included under “Capital expenditures” within the consolidated statement of cash flows.

QUARTERLY FINANCIAL DATA (UNAUD

QUARTERLY FINANCIAL DATA (UNAUDITED)	12 Months Ended
	Dec. 31, 2018
Quarterly Financial Information Disclosure [Abstract]
QUARTERLY FINANCIAL DATA (UNAUDITED)	QUARTERLY FINANCIAL DATA (UNAUDITED) Summarized quarterly financial data for the periods indicated is set forth below (in thousands, except per unit amounts). Quarterly results were influenced by seasonal and other factors inherent in our business. First Second Third Fourth Total 2018 Revenue $ 1,183,105 $ 940,839 $ 909,548 $ 1,074,783 $ 4,108,275 Operating (loss) income (1) 169,513 145,697 (391,831 ) 493,652 417,031 Net (loss) income 117,092 93,317 (745,336 ) 483,012 (51,915 ) Net (loss) income attributable to Buckeye Partners, L.P. 112,373 91,904 (745,835 ) 482,520 (59,038 ) Earnings (loss) per unit - basic $ 0.75 $ 0.59 $ (4.86 ) $ 3.14 $ (0.41 ) Earnings (loss) per unit - diluted $ 0.74 $ 0.59 $ (4.86 ) $ 3.13 $ (0.41 ) 2017 Revenue $ 969,273 $ 810,201 $ 922,619 $ 946,052 $ 3,648,145 Operating income 172,576 170,754 168,329 173,705 685,364 Net income 126,309 116,379 120,224 130,753 493,665 Net income attributable to Buckeye Partners, L.P. 123,576 112,722 116,187 126,317 478,802 Earnings per unit - basic $ 0.88 $ 0.80 $ 0.82 $ 0.85 $ 3.33 Earnings per unit - diluted $ 0.88 $ 0.80 $ 0.81 $ 0.85 $ 3.32 ____________________________ (1) Fourth quarter of 2018 includes the gain on sale of the DPTS asset package. See Note 4 - Acquisitions, Investments and Disposition for further discussion.

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Basis of Presentation and Principles of Consolidation	Basis of Presentation and Principles of Consolidation The consolidated financial statements and the accompanying notes are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and the rules of the U.S. Securities and Exchange Commission (“SEC”). The consolidated financial statements include the accounts of our subsidiaries controlled by us and variable interest entities (“VIEs”) of which we are the primary beneficiary. A VIE is required to be consolidated by its primary beneficiary which is generally defined as the party who has (i) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (ii) the obligation to absorb losses of the VIE or the right to receive benefits that could potentially be significant to the VIE. We evaluate our relationships with our VIEs on an ongoing basis to determine whether we continue to be the primary beneficiary. Third party or affiliate ownership interests in our subsidiaries and consolidated VIEs are presented as noncontrolling interests. Intercompany transactions are eliminated in consolidation. The preparation of consolidated financial statements in conformity with GAAP requires our management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses during the reporting period and disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Estimates and assumptions about future events and their effects cannot be made with certainty. Estimates may change as new events occur, when additional information becomes available and if our operating environment changes. Actual results could differ from our estimates.
Asset Retirement Obligations	Asset Retirement Obligations We regularly assess our legal obligations with respect to estimated retirements of certain of our long-lived assets to determine if an asset retirement obligation (“ARO”) exists. The fair value of a liability related to the retirement of long-lived assets is recorded at the time a regulatory or contractual obligation is incurred, including obligations to perform an asset retirement activity in which the timing or method of settlement are conditional on a future event that may or may not be within the control of the entity. If an ARO is identified and a liability is recorded, a corresponding asset is recorded concurrently and is depreciated over the remaining useful life of the asset. After the initial measurement, the liability is periodically adjusted for costs incurred or settled, accretion expense, and any revisions made to the assumptions related to the retirement costs. Generally, the fair value of the liability is determined based on estimates and assumptions related to: (i) future retirement costs; (ii) future inflation rates; and (iii) credit-adjusted risk-free interest rates. Our assets generally consist of terminals that we own and underground liquid petroleum products pipelines installed along rights-of-way acquired from land owners and related above-ground facilities. The significant majority of our rights-of-way agreements do not require the dismantling and removal of the pipelines and reclamation of the rights-of-way upon permanent removal of the pipelines from service. In addition, we assume substantially all of our common carrier properties operate indefinitely, as these assets generally serve in high-population and high-demand markets. Accordingly, other than with respect to facilities that are expected to be taken out of service, we have recorded no liabilities, or corresponding assets because the future dismantlement and removal dates for the majority of our assets, and the amount of any associated costs, are indeterminable. The ARO liability represents our best estimate of the costs to be incurred with information currently available and is based on certain assumptions, including: (i) timing of retirement of assets; (ii) methods of abandonment to be employed; and (iii) if applicable, our requirements under right-of-way agreements; therefore, it is likely that the ultimate costs to settle this liability will be different and such differences could be material. ARO liabilities are included in accrued and other current liabilities, as well as other non-current liabilities. There were no significant changes in the estimates underlying ARO liabilities during the periods presented.
Business Combinations	Business Combinations We allocate the total purchase price of a business combination to the assets acquired and the liabilities assumed based on their estimated fair values at the acquisition date, with the excess purchase price recorded as goodwill. For material acquisitions, we may engage an independent valuation specialist to assist us in determining the fair value of the assets acquired and liabilities assumed, including goodwill, based on recognized business valuation methodologies. If the initial accounting for the business combination is incomplete by the end of the reporting period in which the acquisition occurs, an estimate will be recorded. Subsequent to the acquisition, and not later than one year from the acquisition date, we will record any material adjustments to the initial estimate in the reporting period in which the adjustment amounts are determined based on facts and circumstances that existed as of the acquisition date, as applicable. An income, market or cost valuation method may be utilized to estimate the fair value of the assets acquired or liabilities assumed in a business combination. The income valuation method represents the present value of future cash flows over the life of the asset using: (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses; (ii) long-term growth rates; and (iii) appropriate discount rates. The market valuation method uses prices paid for a reasonably similar asset by other purchasers in the market, with adjustments relating to any differences between the assets. The cost valuation method is based on the replacement cost of a comparable asset at prices at the time of the acquisition reduced for depreciation of the asset. We expense acquisition-related costs as incurred in connection with each business combination
Business Segments	Business Segments Our operations are reported under three business segments: (i) Domestic Pipelines & Terminals; (ii) Global Marine Terminals; and (iii) Merchant Services. Our business segments are generally organized and managed according to the geographical location of our assets and the types of services rendered. Financial information regarding these segments is evaluated regularly by our chief operating decision maker (our Chief Executive Officer) in deciding how to allocate resources and in assessing operating and financial performance. Our business segment financial performance is evaluated primarily based on Adjusted EBITDA. Refer to Note 24 - Business Segments for further discussion.
Capitalization of Interest	Capitalization of Interest Interest on borrowed funds is capitalized on projects during construction based on the approximate average interest rate of our debt.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash equivalents represent all highly marketable securities with original maturities of three months or less. The carrying value of cash equivalents approximates fair value because of the short-term nature of these investments.
Comprehensive Income	Comprehensive Income Our comprehensive income is determined based on net income adjusted for unrealized gains and losses on derivative instruments for our cash flow hedging transactions, reclassification of derivative gains and losses to net income, recognition of costs related to our pension and post-retirement benefit plans, adjustments to the funded status of our pension and post-retirement benefit plans and our proportionate share of other comprehensive income from equity method investments.
Concentration of Credit Risk and Trade Receivables	Concentration of Credit Risk and Trade Receivables Trade receivables of $214.3 million and $265.0 million included within accounts receivable, net on our consolidated balance sheets as of December 31, 2018 and 2017 , respectively, are primarily due from major oil companies, national oil companies, refiners, marketing and trading companies, and commercial airlines. These concentrations of customers may affect our overall credit risk as these customers may be similarly affected by changes in economic, regulatory or other factors. We extend credit to customers and manage our credit risks through credit analysis and monitoring procedures, including credit approvals, credit limits and right of offset. Also, we manage our risk using collateral, such as letters of credit, prepayments, liens on customer assets and guarantees. Trade receivables represent valid claims against non-affiliated customers and are recognized when products are sold or services are rendered. We record an allowance for doubtful accounts for estimated losses resulting from the inability of our customers to make required payments. We review the adequacy of the allowance for doubtful accounts monthly by making judgments regarding future events and trends based on the: (i) customers’ historical relationship with us; (ii) customers’ current financial condition; and (iii) current and projected economic conditions.
Contingencies	Contingencies Certain conditions may exist as of the date our consolidated financial statements are issued that may result in a loss to us, but which will only be resolved when one or more future events occur or fail to occur. Our management, with input from legal counsel, assesses such contingent liabilities, and such assessment inherently involves judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in proceedings, our management, with input from legal counsel, evaluates the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein. If the assessment of a contingency indicates that it is probable that a loss has been incurred and the amount of liability can be reasonably estimated, then the estimated liability is accrued in our consolidated financial statements. If the assessment indicates that a potentially material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss if determinable and material, is disclosed. Actual results could vary from these estimates and judgments. Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed. In addition, we are subject to federal, state and local laws and regulations relating to the protection of the environment, which require us to remove or remedy the effect of the disposal or release of specified substances at our operating sites. We record environmental liabilities at a specific site when environmental assessments indicate remediation efforts are probable, and costs can be reasonably estimated based upon past experience, discussions with operating personnel, advice of outside engineering and consulting firms, discussion with legal counsel or current facts and circumstances. The estimates related to environmental matters are uncertain because: (i) estimated future expenditures are subject to cost fluctuations and change in the estimated remediation period; (ii) unanticipated liabilities may arise; and (iii) changes in federal, state and local environmental laws and regulations may significantly change the extent of remediation. Our estimated environmental remediation liabilities are generally not discounted to present value since the ultimate amount and timing of cash payments for such liabilities are typically not readily determinable. Expenditures to mitigate or prevent future environmental contamination are capitalized. We monitor the environmental liabilities regularly and record adjustments to our initial estimates, from time to time, to reflect changing circumstances and estimates based upon additional developments or information obtained in subsequent periods. We maintain insurance which may cover certain environmental expenditures. Recoveries of environmental remediation expenses from other parties are recorded when their receipt is assured beyond a reasonable doubt.
Cost of Product Sales	Cost of Product Sales Cost of product sales relates to sales of refined petroleum products, consisting primarily of gasoline, propane, ethanol, biodiesel and middle distillates, such as heating oil, diesel fuel and kerosene, and fuel oil, as well as the effects of hedges on refined petroleum product acquisition costs and hedges of fixed-price contracts.
Debt Issuance Costs	Debt Issuance Costs Costs incurred upon the issuance of our debt instruments are capitalized and amortized over the life of the associated debt instrument on a straight-line basis, which approximates the effective interest method. If the debt instrument is retired before its scheduled maturity date, any remaining issuance costs associated with that debt instrument are expensed in the same period. Debt issuance costs related to our amended $1.5 billion revolving Credit Facility with a syndicate of lending institutions dated September 30, 2016 (the “Credit Facility”), are reported in “Other non-current assets”. Debt issuance costs related to our outstanding notes are reported as a reduction of the carrying amount of our outstanding notes.
Derivative Instruments	Derivative Instruments Derivatives are financial and physical instruments whose fair value is determined by changes in a specified benchmark such as interest rates or commodity prices. We use derivative instruments such as forwards, futures, swaps and other contracts to manage market price risks associated with inventories, firm commitments, interest rates and certain forecasted transactions. We do not engage in speculative trading activities. We recognize these transactions on our consolidated balance sheets as assets and liabilities based on the instrument’s fair value. Changes in fair value of derivative instrument contracts are recognized in earnings in the current period unless specific hedge accounting criteria are met. If the derivative instrument is designated as a hedging instrument in a fair value hedge, gains and losses incurred on the instrument will be recorded in earnings to offset corresponding losses and gains on the hedged item. If the derivative instrument is designated as a hedging instrument in a cash flow hedge, gains and losses incurred on the instrument are recorded in other comprehensive income. 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. Gains and losses on cash flow hedges are reclassified from accumulated other comprehensive income (“AOCI”) to earnings when the forecasted transaction occurs and affects net income or, as appropriate, over the economic life of the underlying asset or liability. Gains and losses related to a derivative instrument designated as a hedge of a forecasted transaction that is no longer likely to occur are immediately recognized in earnings. Physical forward contracts and futures contracts that have not been designated in a hedge relationship are marked-to-market. To qualify as a hedge, the item to be hedged must expose us to risk and we must have an expectation that the related hedging instrument will be effective at reducing or mitigating that exposure. In accordance with the hedging requirements, we document all hedging relationships at inception and include a description of the risk management objective and strategy for undertaking the hedge, identification of the hedging instrument, the hedged item, the nature of the risk being hedged, the method for assessing effectiveness of the hedging instrument in offsetting the hedged risk and the method of measuring any ineffectiveness. We link all derivative instruments that are designated as fair value or cash flow hedges to specific assets and liabilities on our consolidated balance sheets or to specific firm commitments or forecasted transactions. When an event or transaction occurs, such as the sale of hedged fuel inventory or the expiration of derivative contracts, we discontinue hedge accounting. We also formally assess, both at the hedge’s inception and on an ongoing basis, whether the derivative instruments that are used in designated hedging relationships are highly effective in offsetting changes in fair values or cash flows of hedged items. If it is determined that a derivative instrument is not highly effective as a hedge or that it has ceased to be a highly effective hedge, we discontinue hedge accounting prospectively. We measure ineffectiveness by comparing the change in fair value of the hedge instrument to the change in fair value of the hedged item. The time value component is excluded from our hedge assessment and reported directly in earnings.
Earnings per Unit	Earnings per Unit Basic and Diluted earnings per unit (“EPU”) are computed taking into account the weighted average outstanding limited partner units as well as the effect of participating securities. Our participating securities are generally comprised of certain unvested restricted units, granted under the 2013 Long Term Incentive Plan of Buckeye Partners, L.P. (the “LTIP”), and participate in earnings only to the extent of certain distribution equivalent rights. Net income allocable to participating securities reduces net income attributable to Buckeye Partners, L.P. to arrive at net income attributable to unitholders. For Diluted EPU, we use the more dilutive of the treasury stock or two-class method, taking into consideration dilutive securities resulting from restricted-unit grants under the LTIP. See Note 23 - (Loss) Earnings Per Unit for further discussion.
Equity Investments	nvestments We account for investments in entities in which we do not exercise control, but have significant influence, using the equity method of accounting. Under this method, an investment is recorded at acquisition cost plus our equity in undistributed earnings or losses since acquisition, reduced by distributions received and amortization of excess net investment. Excess investment is the amount by which the total investment exceeds our proportionate share of the book value of the net assets of the investment. Such excess investment not related to any specific accounts of the investee is treated as goodwill and not amortized. Amounts associated with specific accounts of the investee are amortized. The amortization of excess net investment is included in earnings from equity investments in our consolidated statement of operations. We evaluate equity method investments for impairment whenever events or changes in circumstances indicate that there is an other than temporary loss in value of the investment. In the event that the loss in value of an investment is other than temporary, we record a charge to earnings to adjust the carrying value to fair value. We assess the fair value of equity investments using commonly accepted valuation methodologies, including but not limited to, peer group multiples, comparable sales-transaction multiples, and discounted cash flow models. Estimates of future cash flows that would be used to determine fair value include: (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses; (ii) long-term growth rates; and (iii) probabilities assigned to different cash flow scenarios. A significant change in these underlying assumptions could result in an impairment charge. For the year ended December 31, 2018 , we recorded a $300.3 million non-cash loss related to the anticipated sale of our equity investment in VTTI. There were no impairments of our equity investments for the years ended December 31, 2017 or 2016 . See Note 4 - Acquisitions, Investments and Dispositions for further discussion. We account for investments in entities that we do not control and for which we do not have the ability to exercise significant influence over operating and financial policies at fair value except in situations when the equity security does not have a readily determinable fair value. In these situations, we record the equity investment at cost less impairments and changes resulting from observable price changes in orderly transactions for similar investments.
Fair Value Measurements	Fair Value Measurements Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Our fair value estimates are based on either: (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. Recognized valuation techniques employ inputs such as product prices, operating costs, discount factors and business growth rates. These inputs may be either readily observable, corroborated by market data or generally unobservable. In developing our estimates of fair value, we endeavor to utilize the best information available and apply market-based data to the extent possible. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements based on the observability of inputs used to estimate such fair values. The characteristics of fair value amounts classified within each level of the hierarchy are described as follows: • Level 1 inputs — unadjusted quoted prices which are available in active markets for identical, unrestricted assets or liabilities as of the reporting date; • Level 2 inputs — quoted market prices in markets that are not considered to be active or financial instruments for which all significant inputs are observable, either directly or indirectly; and • Level 3 inputs — prices or valuations that require inputs that are both significant to the fair value measurement and unobservable. These inputs are typically used in connection with internally developed valuation methodologies where management makes its best estimate of an instrument’s fair value. We categorize our financial assets and liabilities using this hierarchy at each balance sheet reporting date.
Foreign Currency	Foreign Currency Puerto Rico is a commonwealth country under the U.S., and thus uses the U.S. dollar as its official currency. The functional currency of our operations in BBH and St. Lucia is the U.S. dollar. Foreign exchange gains and losses arising from transactions denominated in a currency other than the U.S. dollar relate to a nominal amount of supply purchases and are included in “Other income (expense)” within the consolidated statements of operations. The effects of foreign currency transactions were not material for the years ended December 31, 2018 , 2017 and 2016 . Our investment in VTTI indirectly exposed us to foreign currency risk, primarily with respect to the Euro, Malaysian Ringgit, and United Arab Emirates Dirham. VTTI manages its exposure to foreign currency risk with foreign exchange hedging strategies. Our proportionate share of VTTI’s foreign currency risk with foreign currency transaction, hedging, and translation gains and losses is included in our earnings from equity investments and accumulated other comprehensive income, as applicable, during the time period for which we applied the equity method of accounting. We recognized our proportionate share, of $49.6 million , of VTTI’s other comprehensive loss, primarily comprised of foreign currency translation adjustments, in other comprehensive loss (income) for the nine months ended September 30, 2018. Due to certain terms of the definitive agreement regarding the divestiture of our equity interest in VTTI, beginning in the fourth quarter of 2018, we determined we no longer had the ability to exercise significant influence over the operating and financial policies of VTTI. Accordingly, we accounted for our investment at fair value and therefore included the amount of foreign currency translation deferred in AOCI as part of the impairment of our investment. See Note 4 - Acquisition, Investments and Disposition for further discussion.
Goodwill	Goodwill Goodwill represents the excess of purchase price over fair value of net assets acquired. Our goodwill amounts are assessed for impairment: (i) on an annual basis on October 31st each year or (ii) on an interim basis if circumstances indicate it is more likely than not the fair value of a reporting unit is less than its fair value. Goodwill is tested for impairment at each reporting unit. A reporting unit is a business segment or one level below a business segment for which discrete financial information is available and regularly reviewed by segment management. Our reporting units are our business segments, with the exception of our Global Marine Terminals segment which consists of: (i) our operations in the Caribbean and New York Harbor, as well as our equity investment in VTTI, which we refer to as our “GMT Caribbean and NYH reporting unit”; and (ii) our operations in South Texas, including our equity investment in the STG Terminal (the “GMT South Texas” reporting unit). We may perform a qualitative assessment to determine whether the fair value of our reporting units are more likely than not less than the carrying amount. In 2018, we adopted Accounting Standards Update (“ASU”) ASU 2017-04 which simplified the test for goodwill impairment. Under the new guidance, if the carrying amount of a reporting unit exceeds its estimated fair value, an impairment is recorded for the amount of the excess up to the amount of goodwill for the respective reporting unit. The estimate of the fair value of the reporting unit is determined using a weighting of an expected present value of future cash flows and a market multiple valuation method, giving more weighting to our estimate of future cash flows. The present value of future cash flows is estimated using: (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses; (ii) long-term growth rates; and (iii) appropriate discount rates. The market multiple valuation method uses appropriate market multiples from comparable companies on the reporting unit’s earnings before interest, tax, depreciation and amortization. We evaluate industry and market conditions for purposes of weighting the income and market valuation approach. Using this methodology, the Partnership performed a goodwill recoverability test as of September 30, 2018, as discussed in Note 10 - Goodwill and Intangible Assets, and concluded that the goodwill attributable to the GMT Caribbean and NYH reporting units, had been impaired. Furthermore, we performed our annual assessment on October 31, 2018 to determine if any significant events or changes in circumstances had occurred that would be considered a potential triggering event. We did not identify any indication of a triggering event that would indicate the existence of further impairment of the reporting units.
Income Taxes	Income Taxes With the exception of federal and state income taxes from Buckeye Development & Logistics LLC (“BDL”), federal income taxes from Buckeye Caribbean Terminals LLC (“Buckeye Caribbean”) and certain MLP entity level state income taxes, the Partnership’s federal and certain state income taxes are the responsibility of the partners and are not reflected in these consolidated financial statements. In addition, outside the continental U.S., our operations at BBH and St. Lucia are exempt from income taxes. Our operations at BBH are tax exempt by the Bahamian government pursuant to concessions granted under the Hawksbill Creek Agreement between the Government of The Bahamas and the Grand Bahama Port Authority. These concessions have been extended through May 2036 by the Grand Bahama Investment Incentives Act. Our operations in St. Lucia are exempt from income taxes and duties pursuant to concessions granted under the terms of a tax concession agreement effective in 2007 and in effect for a minimum of 50 years . Our operations at the Yabucoa terminal are subject to income taxes within the Commonwealth of Puerto Rico. Buckeye Caribbean is the holder of a tax exemption grant issued by the Office of Industrial Tax Exemption of the Puerto Rico Department of State under the Tax Incentives Act of 1998 (the “Act”). Under the current terms of the tax exemption grant, Buckeye Caribbean is subject to an income tax rate of 4% to 7% on industrial development income. The grant also provides additional exemptions as follows: (i) 90% exempt from real and personal property taxes; (ii) 60% exempt from municipal taxes on industrial development income; and (iii) 100% exempt from excise taxes imposed under Subtitle C of the Puerto Rico Internal Revenue Code, to the extent provided in Section 6(c) of the Act. The tax exemption grant provides a 20 year exemption period, which commenced on January 1, 2002 and, unless renewed, would end with the tax year ending December 31, 2021. We are currently seeking a renewal of our tax exemption grant. We recognize deferred tax assets and liabilities for temporary differences between the amounts of assets and liabilities measured for financial reporting purposes and income tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. See Note 22 - Income Taxes for the impact of the Tax Cuts & Jobs Act. We evaluate the need for a valuation allowance and consider all available positive and negative evidence, including projected operating income or losses for the foreseeable future, to determine the likelihood of realizing the benefits of deferred tax assets. If the value of the deferred tax assets exceeds the estimated future benefit, we record a valuation allowance to reduce our deferred tax assets to the amount of future benefit that is more likely than not to be realized. In the future, if the realization of the deferred tax assets should occur, a reduction to the valuation allowance related to the deferred tax assets would increase net income in the period such determination is made
Intangible Assets	Intangible Assets Intangible assets with finite useful lives are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Intangible assets that have finite useful lives are amortized over their useful lives. Intangible assets include contracts and customer relationships. The fair values of these intangibles are based on the present value of cash flows attributable to the customer relationship or contract, which includes management’s estimates of revenue and operating expenses and costs relating to utilization of other assets to fulfill such contracts. The customer contracts are being amortized over their contractual lives with a range of 1 to 10 years . For the customer relationships, we determine the recovery period based on historical customer attrition rates and management’s assumptions on future events, including customer demand, contract renewal, useful lives of related assets and market conditions. The customer relationships are being amortized over the estimated recovery period of 12 to 20 years . When necessary, intangible assets’ useful lives are revised and the impact on amortization is reflected on a prospective basis.
Inventories	Inventories We generally maintain two types of inventory. Our Merchant Services segment principally maintains refined petroleum products inventory, consisting of gasoline, propane, butane, ethanol, biodiesel and middle distillates, such as heating oil, diesel fuel and kerosene. Inventory is generally valued at the lower of weighted average cost or net realizable value, unless such inventories are hedged. 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. Hedged inventory is adjusted for the effects of applying fair value hedge accounting. We also maintain materials and supplies inventory such as pipe, valves, pumps, electrical/electronic components, drag reducing agent and other miscellaneous items that are valued at the lower of weighted average cost or net realizable value.
Noncontrolling Interests	Noncontrolling Interests The consolidated balance sheets and statements of operations include noncontrolling interests that relate primarily to Buckeye Texas, Buckeye Pipe Line Services Company (“Services Company”) and the Sabina crude butadiene pipeline (the “Sabina Pipeline”) that are not wholly owned by Buckeye. In April 2018, we acquired our partner’s interest in Buckeye Texas and own 100% of the entity. See Note 4 - Acquisition, Investments and Dispositions for further discussion.
Pensions and Postretirement Benefits	Pensions and Postretirement Benefits Services Company sponsors a defined contribution plan, a defined benefit plan and the Employee Stock Ownership Plan (“ESOP”) that provide retirement benefits to certain regular full-time employees. Services Company also sponsors an unfunded post-retirement plan that provides health care and life insurance benefits for certain of its retirees. We develop pension and postretirement health care and life insurance benefits costs from actuarial valuations. The measurement of expenses and liabilities related to these plans is based on management’s assumptions related to future events, including discount rate, expected return on plan assets, rate of compensation increase, and health care cost trend rates. The estimates and assumptions directly affect net periodic benefit expense and obligations for these plans. The actuarial assumptions that we use may differ from actual results due to changing market rates or other factors. These differences could affect the amount of pension and postretirement health care and life insurance benefit expense we have recorded or may record.
Property, Plant and Equipment	Property, Plant and Equipment We record property, plant and equipment at its original acquisition cost. Property, plant and equipment consist primarily of pipelines, terminals, storage and processing facilities, jetties, subsea pipelines and docks, and pumping and station equipment. Generally, we depreciate property, plant and equipment based on the straight-line or group depreciation methods over the estimated useful lives, except for land. Relocations of assets for certain regulated operations are accounted for as reimbursements of capital expenditures. See Note 8 - Property, Plant and Equipment for the depreciation life of our assets. Additions to property, plant and equipment, including maintenance and expansion and cost reduction capital expenditures, are recorded at cost. Maintenance capital expenditures maintain and enhance the safety and integrity of our pipelines, terminals, storage and processing facilities, and related assets, and expansion and cost reduction capital expenditures expand the reach or capacity of those assets, to improve the efficiency of our operations and to pursue new business opportunities. We expense routine maintenance and repairs as incurred. The cost of property, plant and equipment sold or retired and the related accumulated depreciation, except for certain pipeline system assets, are removed from our consolidated balance sheet in the period of sale or disposition, and any resulting gain or loss is included in earnings. For our pipeline system assets where we apply group depreciation method, we generally charge the original cost of property sold or retired to accumulated depreciation and amortization, net of salvage and cost of removal. When a separately identifiable group of assets, such as a stand-alone pipeline system is sold, we will recognize a gain or loss in our consolidated statements of operations for the difference between the cash received and the net book value of the assets sold. We assess the recoverability of our long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. We determine the estimated undiscounted future cash flows expected to result from the use of the asset and its eventual disposal. If the sum of the estimated undiscounted future cash flows exceeds the carrying amount, no impairment is necessary. If the carrying amount exceeds the sum of the undiscounted cash flows, an impairment charge is recognized based on the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or estimated fair value less costs to sell. Estimates of undiscounted future cash flows include: (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses; (ii) long-term growth rates; and (iii) estimates of useful lives of the assets. Such estimates of future undiscounted net cash flows are highly subjective and are based on numerous assumptions about future operations and market conditions.
Revenue Recognition	Revenue Recognition The majority of our service-based revenue is derived from fee-based transportation, terminalling, and storage services that we provide to our customers. We also generate revenue from the marketing and sale of petroleum products. We recognize revenues from customer fees for services rendered or by selling petroleum products. Under Accounting Standards Codification (“ASC”) Topic 606, Revenue from Contracts with Customers (“ASC 606”), we recognize revenue over time or at a point in time, depending on the nature of the performance obligations contained in the respective contract with our customer. A performance obligation is a promise in a contract to transfer goods or services to the customer. The contract transaction price is allocated to each performance obligation and recognized as revenue when, or as, the performance obligation is satisfied. In certain situations, we recognize revenue pursuant to guidance in the Accounting Standards Codification other than ASC 606. These situations primarily relate to leases and derivatives. The adoption of ASC 606 did not have a material impact on the timing or amount of our revenue recognition. The following is an overview of our significant revenue streams, including a description of the respective performance obligations and related methods of revenue recognition. Pipeline Transportation Revenue from pipeline operations is comprised of tariffs and fees associated with the transportation of liquid petroleum products, generally at published tariffs, and in certain instances, revenue from committed capacity contracts at negotiated rates. Tariff revenue is recognized either at the point of delivery or at the point of receipt, pursuant to specifications outlined in the respective tariffs. Revenue associated with capacity reservation is recognized ratably over the respective term, regardless of whether the capacity is actually utilized. Our tariffs generally include product loss allowance factors intended to, among other things, compensate for losses due to evaporation, measurement tolerances, interface downgrades and other product losses in transit. We value the difference of allowance volumes to actual losses at the estimated net realizable value in the period the variance occurred, and the result is recorded as an adjustment to pipeline transportation revenue. The majority of our contracts have a single performance obligation to provide pipeline transportation service, and the performance obligation is primarily satisfied over time as transportation services are provided, whereby progress is generally measured based on the volume of product transported. Our services are typically billed on a weekly basis, and we generally do not offer extended payment terms. In addition, we have certain agreements that require counterparties to throughput a minimum volume over an agreed-upon period. Revenue pursuant to such agreements is recognized at the earlier of when the volume is throughput or proportionally if we determine that the customer is not expected to meet its volume commitment. Terminalling and Storage Services Revenue from terminalling and storage operations is recognized as services are performed. Terminalling and storage revenue includes terminalling or throughput fees, which are generated when we receive and redeliver liquid petroleum products from and to pipelines, marine vessels, trucks, or rail-cars, as well as storage fees, which are generated as we provide storage capacity. We generate revenue through a combination of month-to-month and multi-year terminalling service and storage capacity arrangements. The majority of our contracts have a single performance obligation to provide terminalling and storage services that is primarily satisfied over time as these services are provided. Terminalling fees, as applicable, are recognized as the liquid petroleum product is delivered to a connecting carrier or to a customer’s designated mode of transport, which could include a pipeline, truck, marine vessel, or rail-car or, in certain situations, as product is received, based on the volume of product handled. Storage fees for contracted capacity are typically recognized in revenue ratably over the term of the contract, regardless of the amount of the contracted storage capacity utilized by the customer. As discussed above with respect to transportation services, progress in performing terminalling services is generally measured based upon the volume of product handled. Certain of our terminalling and storage services arrangements include product loss allowance provisions intended to, among other things, compensate for losses due to evaporation, measurement tolerances, and other product recoveries and losses. We value the difference of allowance volumes to actual losses at the estimated net realizable value in the period the variance occurred, and the result is recorded as an adjustment to terminalling and storage services revenue. We have certain contracts containing tiered pricing or volume-based discounts, which are recognized in revenue as a purchase option to acquire additional services in the period the services are performed. In addition, we have certain agreements that require counterparties to throughput a minimum volume over an agreed-upon period. Revenue pursuant to such agreements is recognized at the earlier of when the volume is throughput or proportionally if we determine that the customer is not expected to meet its volume commitment. Revenue from other ancillary services is recognized as services are rendered. Our services are typically billed on a monthly basis, and we generally do not offer extended payment terms. Merchant Services Revenue from the sale of petroleum products, on a wholesale basis, is recognized at the time title to the product sold transfers to the purchaser, which generally occurs upon delivery of the product to the purchaser or its designee. Our contracts contain a single performance obligation to sell a particular petroleum product, which is generally satisfied as quantities are delivered to our customer. Our commodity sales are typically billed at the time product is delivered, and we generally do not offer extended payment terms. Operation and Construction Services Revenue from contract operation and construction services for facilities and pipelines not directly owned by us is recognized as the services are performed. Contract and construction services revenue typically includes costs to be reimbursed by the customer plus an operator fee. Our contracts have a single performance obligation to provide operation and construction services, which is satisfied over time as services are provided. Revenue is generally recognized utilizing costs incurred to measure our progress in fulfilling our performance obligation. Our services are typically billed on a monthly basis, and we generally do not offer extended payment terms.
Unit-Based Compensation	Unit-Based Compensation We award unit-based compensation to employees and directors primarily under the LTIP. All unit-based payments to employees under the LTIP, including grants of phantom units and performance units, are recognized in our consolidated statements of operations based on their grant date fair values. Compensation expense equal to the fair value of those performance unit and phantom unit awards that are expected to vest is estimated and recorded over the period the grants are earned, which is the vesting period. Compensation expense estimates are updated periodically. The vesting of the performance unit awards is also contingent upon the attainment of predetermined performance goals. Depending on the estimated probability of attainment of those performance goals, the compensation expense recognized related to the awards could increase or decrease over the remaining vesting period.
Variable Interest Entities	Variable Interest Entities We evaluate our financial interests in business enterprises to determine if they represent VIEs of which we are the primary beneficiary. If such criteria are met (as discussed above in “Basis of Presentation and Principles of Consolidation”), we reflect these entities as consolidated subsidiaries. There were no changes to the entities consolidated for the year ended December 31, 2018 . Services Company and Sabina Pipeline are VIEs of which we are the primary beneficiary and are, therefore, consolidated. We own a 63% interest in Sabina Pipeline. In April 2018, we acquired the remaining 20% interest in Buckeye Texas, which was a VIE, as discussed in Note 4 - Acquisition, Investments and Disposition. Third party or affiliate ownership interests in our consolidated VIEs are presented as noncontrolling interests.
Recent Accounting Developments/Recent Accounting Guidance Not Yet Adopted	Recently Adopted Accounting Guidance Goodwill Impairment . Effective July 1, 2018, we adopted ASU 2017-04, which simplifies the accounting for goodwill. The guidance eliminates Step 2 from the goodwill impairment test, which required entities to calculate the implied fair value of a reporting unit’s goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. An impairment charge is now determined by the amount by which the carrying amount of a reporting unit exceeds its fair value up to the amount of goodwill. The guidance is applied using a prospective approach. We applied this standard to the calculation of the goodwill impairment charge referenced above. See Note 10 - Goodwill and Intangible Assets for further discussion. Revenue from Contracts with Customers . Effective January 1, 2018, we adopted ASC 606, using the modified retrospective transition method, which required us to apply the new standard to (i) all new revenue contracts entered into after January 1, 2018, and (ii) revenue contracts which were not completed as of January 1, 2018. ASC 606 replaces existing revenue recognition requirements in GAAP and required entities to recognize revenue at an amount that reflects the consideration to which we expect to be entitled in exchange for transferring goods or services to a customer. ASC 606 also required certain disclosures regarding qualitative and quantitative information with respect to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The adoption of ASC 606 did not result in a transition adjustment nor did it have a material impact on the timing or amount of our revenue recognition. See Note 3 - Revenue from Contracts with Customers for additional discussion. Recognition and Measurement of Financial Assets and Liabilities . Effective January 1, 2018, we adopted ASU 2016-01, and it will be applied prospectively. This ASU issued a new standard related to certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. Most prominent among the changes in this standard is the requirement for changes in the fair value of marketable equity investments, with certain exceptions, to be recognized through net income rather than other comprehensive income (“OCI”). Under the standard, marketable equity investments that do not have a readily determinable fair value are eligible for the measurement alternative. Using the measurement alternative, investments without readily determinable fair values will be valued at cost, with adjustments to fair value for changes in price or impairments reflected through net income. The adoption of this guidance did not have an impact on our consolidated financial statements. Classification of Certain Cash Receipts and Cash Payments . Effective January 1, 2018, we adopted ASU 2016-15, applying the retrospective transition method. This ASU requires changes in the presentation of certain items, including but not limited to debt prepayment or debt extinguishment costs; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. The adoption of this guidance did not have a material impact on our consolidated financial statements. Business Combinations . Effective January 1, 2018, we adopted ASU 2017-01, and it will be applied prospectively to future business combinations. This ASU clarifies the definition of a business in order to assist entities with evaluating whether transactions should be accounted for as acquisitions/disposals of assets or businesses. The guidance provides a screen to help entities determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set of assets is not a business. If the threshold of the screen is not met, the guidance further clarifies that the set of assets is not a business unless it includes an input and a substantive process that together significantly contribute to the ability to create output. Retirement Benefits . Effective January 1, 2018, we adopted ASU 2017-07, which improves the presentation of net periodic pension and postretirement benefit costs. The interest cost, expected return on plan assets, actuarial loss due to settlements, and the amortization of unrecognized loss have been reclassified from operating expenses to other expense, applying the retrospective transition method. We elected to apply the practical expedient which allows us to reclassify amounts disclosed previously in the retirement benefits note as the basis for applying retrospective presentation for comparative periods as it is impracticable to determine the disaggregation of the cost components for amounts capitalized and amortized in those periods. On a prospective basis, the components of net periodic benefit costs discussed above will not be included in amounts capitalized in property, plant, and equipment. The adoption of this guidance did not have a material impact on our consolidated financial statements. In connection with the adoption of ASU 2017-07, using the retrospective transition method, we reclassified $1.5 million and $3.4 million of expenses related to our Retirement Income Guarantee Plan and unfunded post-retirement medical benefit plan, originally included in operating expenses for the years ended December 31, 2017 and 2016 , respectively, to other expense. Such reclassifications had no impact on net income. Modifications to Share-Based Payment Awards . Effective January 1, 2018, we adopted ASU 2017-09, and it will be applied prospectively to future modifications of our unit-based awards, if any. This guidance clarifies when changes in the terms or conditions of share-based payment awards must be accounted for as modifications under existing guidance. The guidance requires that entities apply modification accounting unless the award’s fair value, vesting conditions and classification as an equity or liability instrument are the same immediately before and after the change. Tax Cuts and Jobs Act . In December 2017, the Tax Cuts and Jobs Act (the “Tax Act”) was passed into law. The Tax Act makes changes to the U.S. tax code including, but not limited to (i) reducing the U.S. federal corporate income tax rate from a top rate of 35% to 21% effective January 1, 2018, (ii) requiring a one-time transition tax on certain unrepatriated earnings of foreign subsidiaries that may electively be paid over eight years, and (iii) accelerated first year expensing of certain capital expenditures. Shortly after the Tax Act was enacted, the SEC staff issued Staff Accounting Bulletin (“SAB”) No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (“SAB 118”) which provides guidance on accounting for the Tax Act’s impact. SAB 118 provided a measurement period, which in no case may extend beyond one year from the Tax Act enactment date, during which an entity acting in good faith may complete the accounting for the impacts of the Tax Act under ASC Topic 740. In accordance with SAB 118, the entity must reflect the income tax effects of the Tax Act in the reporting period in which the accounting under ASC Topic 740 is complete. With the exception of federal and state income taxes from BDL, federal income taxes from Buckeye Caribbean and certain MLP entity level state income taxes, the Partnership’s federal and certain state income taxes are the responsibility of the partners and are not reflected in these consolidated financial statements. Accordingly, the Tax Act did not have a material impact on our consolidated financial statements or on our disclosures. Recent Accounting Guidance Not Yet Adopted Collaborative Arrangements . In November 2018, the Financial Accounting Standards Board (“FASB”) issued ASU 2018-18, which clarifies whether certain transactions between collaborative arrangement participants should be accounted for as revenue under ASC 606. The new guidance also provides more comparability in the presentation of revenue for certain transactions between collaborative arrangement participants. The guidance is effective for fiscal years beginning after December 15, 2019 and interim periods within those fiscal years, with early adoption permitted. The guidance should be applied retrospectively to the date of initial application of ASC 606. We expect to adopt this standard effective January 1, 2020 and are currently evaluating the impact that it will have on our consolidated financial statements and disclosures. Targeted Improvements to Related Party Guidance for Variable Interest Entities . In October 2018, the FASB issued ASU 2018-17 that changes the guidance for determining whether a decision-making fee is a variable interest. The guidance provides that indirect interests held through related parties under common control will be considered on a proportional basis when determining whether certain decision-making fees are variable interests. The guidance is effective for fiscal years beginning after December 15, 2019 and interim periods within those fiscal years, with early adoption permitted. The guidance should be applied retrospectively, with a cumulative effect adjustment to retained earnings. We expect to adopt this standard effective January 1, 2020 and are currently evaluating the impact that it will have on our consolidated financial statements and disclosures. Cloud Computing Arrangements . In August 2018, the FASB issued ASU 2018-15, which aligns a customer’s accounting for capitalizing implementation costs in a cloud computing service arrangement that is hosted by the vendor with the requirements for capitalizing implementation costs incurred to develop or obtain an internal-use software license. The guidance is effective for fiscal years beginning after December 15, 2019 and interim periods within those fiscal years, with early adoption permitted. The guidance can be applied prospectively or retrospectively. We expect to adopt this standard effective January 1, 2020 and are currently evaluating the impact that it will have on our consolidated financial statements and disclosures. Changes to the Disclosure Requirements for Defined Benefit Plans . In August 2018, the FASB issued ASU 2018-14, which amends existing guidance on disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The new guidance is effective for fiscal years ending after December 15, 2020, with early adoption permitted. The new guidance requires retrospective application. We expect to adopt this standard effective January 1, 2021 and are currently evaluating the impact that it will have on our disclosures. Changes to the Disclosure Requirements for Fair Value Measurement . In August 2018, the FASB issued ASU 2018-13, which amends existing guidance on disclosure requirements for fair value measurements. The new guidance is effective for fiscal years beginning after December 15, 2019 and interim periods within those fiscal years, with early adoption permitted. The new guidance requires prospective application on changes in unrealized gains and losses, the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements, and the narrative description of measurement uncertainty. The effects of other amendments must be applied retrospectively to all periods presented. We expect to adopt this standard effective January 1, 2020 and are currently evaluating the impact that it will have on our disclosures. Improvements to Nonemployee Share-Based Payment Accounting . In May 2018, the FASB issued ASU 2018-07, which conformed the current nonemployee share-based accounting with employee share-based accounting. The new standard is effective as of January 1, 2019 with early adoption permitted. We adopted this standard on January 1, 2019 and it did not have a material impact on our consolidated financial statements and disclosures. Derivatives and Hedging . In August 2017, the FASB issued ASU 2017-12, which amends and simplifies existing guidance in order to improve the financial reporting of hedging relationships to better align risk management activities in financial statements and make targeted improvements to simplify the application of current guidance related to the assessment of hedge effectiveness. In October 2018, the FASB issued ASU 2018-16, which includes the Overnight Index Swap Rate based on Secured Overnight Financing Rate as a U.S. benchmark interest rate for hedge accounting purposed under ASC Topic 815 “ Derivatives and Hedging. ” The amendments are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with early application permitted. The new guidance requires prospective application, with a cumulative effect adjustment to the beginning balance of partners’ capital for existing hedging relationships. We adopted this standard on January 1, 2019 and it did not have a material impact on our consolidated financial statements and disclosures. Measurement of Credit Losses on Financial Instruments . In June 2016, the FASB issued ASU 2016-13, which replaces the current incurred loss impairment method with a method that reflects expected credit losses on financial instruments. In November 2018, the FASB issued update ASU 2018-19 that clarify the scope of the standard in the amendments in ASU 2016-13. The new standard is effective as of January 1, 2020, and early adoption is permitted as of January 1, 2019. We expect to adopt this standard effective January 1, 2020 and are currently evaluating the impact that the adoption of this standard will have on our consolidated financial statements and disclosures. Leases . In February 2016, the FASB issued ASU 2016-02, as amended by subsequent accounting standard updates (collectively, “Topic 842”), requiring lessees to recognize a right-of-use (“ROU”) asset and a lease liability on the balance sheet for leases with lease terms greater than twelve months, in addition to enhanced disclosure requirements. Topic 842, through an alternative transition method, permits an entity to adopt the provisions of ASU 2016-02 by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption without adjustment to the financial statements for periods prior to adoption. Consequently, an entity’s reporting for the comparative periods presented in the financial statements in which it adopts the new leases standard will continue to be in accordance with the previous lease guidance in ASC Topic 840 “ Leases. ” In December 2018, the FASB issued ASU 2018-20, allowing an accounting policy election that permits lessors to account for sales tax and other similar taxes collected from a lessee as lessee costs. The new guidance also clarifies the accounting for certain lessor costs. In July 2018, the FASB issued ASU 2018-11, allowing a practical expedient that permits lessors to not separate non-lease components from the associated lease component if certain conditions are present. In July 2018, the FASB issued update ASU 2018-10 that provides narrow-scope improvements to the new standard including clarification on reassessment, change in reference index or rate, and periods included in the lease term. In January 2018, the FASB issued ASU 2018-01, permitting an entity to elect a transition practical expedient to not apply the provisions of ASU 2016-02 to land easements that existed or expired before the effective date of ASU 2016-02 and that were not previously accounted for as leases under the previous lease guidance in ASC Topic 840 “ Leases. ” ASU 2016-02 also provides an election for a package of practical expedients which permits an entity to not reassess whether any expired or existing contracts contain leases, the classification of the lease, and any initial direct costs. We applied these practical expedients as part of our adoption. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2018 and interim periods within those annual periods, with early adoption permitted. We adopted this guidance effective January 1, 2019. The most significant impact of the new standard is the recognition of ROU assets and lease liabilities as part of our consolidated balance sheet upon adoption. The implementation did not have an impact on our debt-covenant compliance under our current agreements. The ASU requires increased disclosures which will be included in our quarterly and annual consolidated financial statements beginning with our 2019 reporting periods. We currently estimate the ROU assets and lease liabilities will be approximately $160.0 million as of March 31, 2019.

SUMMARY OF SIGNIFICANT ACCOUN_3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Schedule of activity in the allowance for doubtful accounts	The following table presents activity in the allowance for doubtful accounts at the dates indicated (in thousands): December 31, 2018 2017 2016 Balance at beginning of period $ 4,893 $ 7,960 $ 8,380 Charged to expense 2,083 305 2,143 Write-offs, net of recoveries (76 ) (3,372 ) (2,563 ) Balance at end of period $ 6,900 $ 4,893 $ 7,960

ACQUISITIONS, INVESTMENTS AND_2

ACQUISITIONS, INVESTMENTS AND DISPOSITION (Tables)	12 Months Ended
	Dec. 31, 2018
Duck Island
Business Acquisition [Line Items]
Schedule of purchase price allocated to tangible and intangible assets acquired and liabilities assumed	The purchase price has been allocated to tangible and intangible assets acquired as follows (in thousands): Current assets, including cash acquired of $2,444 $ 8,989 Property, plant and equipment 18,306 Intangible Assets 2,200 Goodwill 3,294 Current liabilities (3,516 ) Environmental liabilities (782 ) Allocated purchase price $ 28,491
Indianola Pipeline
Business Acquisition [Line Items]
Schedule of purchase price allocated to tangible and intangible assets acquired and liabilities assumed	The purchase price has been allocated to tangible and intangible assets acquired as follows (in thousands): Inventories $ 1,554 Property, plant and equipment 16,713 Goodwill 7,758 Allocated purchase price $ 26,025

REVENUE FROM CONTRACTS WITH C_2

REVENUE FROM CONTRACTS WITH CUSTOMERS (Tables)	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Contract with Customer, Asset and Liability	The following table provides information about receivables from contracts with customers, contract assets and contract liabilities (in thousands): December 31, December 31, 2017 Receivables from contracts with customers $ 199,324 $ 245,280 Contract assets 16,989 13,999 Contract liabilities (26,999 ) (15,778 )
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction	The following table includes estimated revenue associated with contractual commitments in place related to future performance obligations as of the end of the reporting period, which are expected to be recognized in revenue in the specified periods (in thousands): Estimated Revenue (1) 2019 $ 358,060 2020 196,399 2021 126,777 2022 51,499 Thereafter 212,374 Total $ 945,109 (1) Excludes revenue arrangements accounted for as leases in the amount of $211.7 million for 2019, $207.2 million for 2020, $188.0 million for 2021, $134.8 million for 2022, and $48.5 million thereafter.

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Schedule of minimum lease payment obligations under operating leases	The following table presents minimum lease payment obligations under our operating leases with terms in excess of one year for the years ending December 31st (in thousands): Total (1) 2019 29,050 2020 26,255 2021 22,215 2022 21,378 2023 21,126 Thereafter 138,466 Total $ 258,490 ____________________________ (1) Includes BBH facility leases for properties in connection with jetty and inland dock operations, as well as tugboats and a barge in our Global Marine Terminals segment.

INVENTORIES (Tables)

INVENTORIES (Tables)	12 Months Ended
	Dec. 31, 2018
Inventory Disclosure [Abstract]
Schedule of inventory	Our inventory amounts were as follows at the dates indicated (in thousands): December 31, 2018 2017 Liquid petroleum products (1) $ 186,683 $ 280,934 Materials and supplies 24,201 20,491 Total inventories $ 210,884 $ 301,425 ____________________________ (1) Ending inventory was 114.7 million and 142.1 million gallons of liquid petroleum products at December 31, 2018 and 2017 , respectively.

PREPAID AND OTHER CURRENT ASS_2

PREPAID AND OTHER CURRENT ASSETS (Tables)	12 Months Ended
	Dec. 31, 2018
Prepaid Expense and Other Assets, Current [Abstract]
Schedule of prepaid and other current assets	Prepaid and other current assets consist of the following at the dates indicated (in thousands): December 31, 2018 2017 Prepaid insurance $ 6,622 $ 7,146 Margin deposits 8,684 7,989 Contract assets 16,989 13,999 Prepaid taxes 5,311 2,865 Other 21,288 4,340 Total prepaid and other current assets $ 58,894 $ 36,339

PROPERTY, PLANT AND EQUIPMENT (

PROPERTY, PLANT AND EQUIPMENT (Tables)	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Schedule of property, plant and equipment	Property, plant and equipment consist of the following at the dates indicated (in thousands): Estimated December 31, 2018 2017 Land N/A $ 669,383 $ 677,866 Rights-of-way (1) 105,811 109,282 Buildings and leasehold improvements 13-50 284,399 282,778 Jetties, subsea pipeline and docks 20-50 679,500 646,922 Gas storage facility 25-50 2,349 2,349 Pipelines and terminals 7-50 5,476,790 5,289,096 Vehicles, equipment and office furnishings 3-20 155,094 150,403 Processing facilities 30-50 630,386 589,971 Construction in progress N/A 254,982 179,573 Total property, plant and equipment 8,258,694 7,928,240 Less: Accumulated depreciation (1,343,898 ) (1,192,448 ) Total property, plant and equipment, net $ 6,914,796 $ 6,735,792 ____________________________ (1) Rights-of-way assets are depreciated over the useful life of the related pipeline assets.

EQUITY INVESTMENTS (Tables)

EQUITY INVESTMENTS (Tables)	12 Months Ended
	Dec. 31, 2018
Equity Method Investments and Joint Ventures [Abstract]
Schedule of equity investments	The following table presents our investments at the dates indicated (in thousands): December 31, Segment Ownership 2018 2017 VTTI B.V. (1) Global Marine Terminals 50.0% $ 975,000 $ 1,399,825 West Shore Pipe Line Company Domestic Pipelines & Terminals 34.6% 70,727 70,035 Muskegon Pipeline LLC Domestic Pipelines & Terminals 40.0% 13,491 13,335 Transport4, LLC Domestic Pipelines & Terminals 25.0% 553 699 South Portland Terminal LLC Domestic Pipelines & Terminals 50.0% 12,055 10,518 South Texas Gateway Terminal LLC Global Marine Terminals 50.0% 39,967 — Total equity investments $ 1,111,793 $ 1,494,412 ____________________________ (1) Accounted for using fair value beginning in the fourth quarter of 2018. See Note 4 - Acquisitions, Investments and Disposition for further discussion.
Schedule of earnings (loss) from equity investments	The following table presents earnings (loss) from equity investments for the periods indicated (in thousands): Year Ended December 31, Segment 2018 2017 2016 VTTI B.V. (1) Global Marine Terminals $ 13,651 $ 22,910 $ — Non-cash loss on write-down of investment in VTTI B.V. (2) Global Marine Terminals $ (300,280 ) $ — $ — West Shore Pipe Line Company Domestic Pipelines & Terminals 10,322 9,451 7,647 Muskegon Pipeline LLC Domestic Pipelines & Terminals 557 1,778 2,002 Transport4, LLC Domestic Pipelines & Terminals 817 850 765 South Portland Terminal LLC Domestic Pipelines & Terminals 1,536 1,016 1,122 South Texas Gateway Terminal LLC (3) Global Marine Terminals (726 ) — — Total (loss) earnings from equity investments $ (274,123 ) $ 36,005 $ 11,536 ____________________________ (1) Accounted for using fair value beginning in the fourth quarter of 2018. See Note 4 - Acquisitions, Investments and Disposition for further discussion. (2) In September 2018, we recorded a non-cash loss related to our equity investment in VTTI. (3) In April 2018, we formed the STG Terminal joint venture. See Note 4 - Acquisitions, Investments and Disposition for further discussion.
Summary of combined financial information for equity method investments	Summarized combined financial information for our equity method investments is as follows for the periods indicated (amounts represent 100% of investee financial information in thousands): December 31, 2018 2017 BALANCE SHEET DATA: (1) Current assets $ 30,045 $ 288,085 Noncurrent assets 257,036 2,600,231 Total assets $ 287,081 $ 2,888,316 Current liabilities $ 31,287 $ 151,850 Other liabilities 41,070 1,246,406 Combined equity 214,724 1,490,060 Total liabilities and combined equity $ 287,081 $ 2,888,316 Year Ended December 31, 2018 2017 2016 INCOME STATEMENT DATA: (1) Revenue $ 460,596 $ 553,396 $ 87,434 Operating Income 143,817 184,692 45,932 Net income 83,479 122,506 30,942 Net income attributable to investee $ 78,962 $ 99,130 $ 30,942 ____________________________ (1) In November 2018, we executed a definitive agreement to sell our 50% equity interest in VTTI, and ceased application of the equity method of accounting. Effective September 30, 2018, we accounted for our investment in VTTI at fair value and no longer include the selected balance sheet data related to VTTI in these tables. See Note 4 - Acquisitions, Investments and Disposition for further discussion.

GOODWILL AND INTANGIBLE ASSETS

GOODWILL AND INTANGIBLE ASSETS (Tables)	12 Months Ended
	Dec. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of changes in the carrying amount of goodwill by segment	The changes in the carrying amount of goodwill by segment are as follows at the dates indicated (in thousands): Domestic Pipelines Merchant GMT Caribbean and NYH GMT South Texas Total January 1, 2017 $ 295,703 4,499 536,964 $ 167,379 $ 1,004,545 Acquisition 2,768 — — — 2,768 December 31, 2017 298,471 4,499 536,964 167,379 1,007,313 Purchase price adjustments 526 — — — 526 Impairment of goodwill — — (536,964 ) — (536,964 ) December 31, 2018 $ 298,997 4,499 — $ 167,379 $ 470,875
Schedule of intangible assets	Intangible assets consist of the following at the dates indicated (in thousands): December 31, 2018 2017 Customer relationships $ 229,300 $ 231,620 Accumulated amortization (106,761 ) (96,147 ) Net carrying amount 122,539 135,473 Customer contracts 381,600 383,466 Accumulated amortization (210,828 ) (159,878 ) Net carrying amount 170,772 223,588 Total intangible assets, net $ 293,311 $ 359,061

OTHER NON-CURRENT ASSETS (Table

OTHER NON-CURRENT ASSETS (Tables)	12 Months Ended
	Dec. 31, 2018
Other Assets, Noncurrent Disclosure [Abstract]
Schedule of other non-current assets	Other non-current assets consist of the following at the dates indicated (in thousands): December 31, 2018 2017 Debt issuance costs $ 2,216 $ 3,022 Insurance receivables related to environmental remediation reserves 2,057 2,794 BBH jetty-allision insurance receivable — 7,372 Derivative assets 1,003 — Other 35,862 38,295 Total other non-current assets $ 41,138 $ 51,483

ACCRUED AND OTHER CURRENT LIA_2

ACCRUED AND OTHER CURRENT LIABILITIES (Tables)	12 Months Ended
	Dec. 31, 2018
Accrued Liabilities and Other Liabilities [Abstract]
Schedule of accrued and other current liabilities	Accrued and other current liabilities consist of the following at the dates indicated (in thousands): December 31, 2018 2017 Taxes - other than income $ 29,644 $ 33,327 Accrued employee benefit liabilities 6,220 7,228 Accrued environmental remediation liabilities 11,658 9,242 Interest payable 58,360 57,164 Unearned revenue 31,593 34,734 Employee compensation related accruals 27,602 32,616 Accrued capital expenditures 59,128 48,690 ARO — 1,255 Other 51,988 40,951 Total accrued and other current liabilities $ 276,193 $ 265,207

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Schedule of long-term debt	Long-term debt consists of the following at the dates indicated (in thousands): December 31, 2018 2017 6.050% Notes due January 15, 2018 (1) $ — $ 300,000 2.650% Notes due November 15, 2018 (1) — 400,000 5.500% Notes due August 15, 2019 (1) (2) 275,000 275,000 4.875% Notes due February 1, 2021 (1) 650,000 650,000 4.150% Notes due July 1, 2023 (1) 500,000 500,000 4.350% Notes due October 15, 2024 (1) 300,000 300,000 3.950% Notes due December 1, 2026 (1) 600,000 600,000 4.125% Notes due December 1, 2027 (1) 400,000 400,000 6.750% Notes due August 15, 2033 (1) 150,000 150,000 5.850% Notes due November 15, 2043 (1) 400,000 400,000 5.600% Notes due October 15, 2044 (1) 300,000 300,000 6.375 % Junior Notes due January 22, 2078 (1) 400,000 — Term Loan due September 30, 2019 (2) 250,000 250,000 Credit Facility due September 30, 2021 522,328 418,904 Unamortized discounts & debt issuance costs (32,886 ) (33,379 ) Total debt 4,714,442 4,910,525 Less: Current portion of long-term debt and line of credit (2) (702,727 ) (252,204 ) Total long-term debt $ 4,011,715 $ 4,658,321 ____________________________ (1) We make semi-annual interest payments on these notes based on the rates noted above with the principal balances outstanding to be paid on or before the due dates as shown above. (2) A portion of the line of credit is classified as a current liability in our consolidated balance sheets as related funds are used to finance the Buckeye Merchant Service Companies’ current working capital needs. In addition, the $275.0 million of 5.500% notes due August 15, 2019 and the $250.0 million Term Loan due September 30, 2019 are classified as current portion of long-term debt as of December 31, 2018.
Scheduled maturities of principal amounts of debt obligations	The following table presents the scheduled maturities of principal amounts of our debt obligations for the next five years and in total thereafter (in thousands): Years Ending December 31, 2019 $ 702,727 2020 — 2021 994,601 2022 — 2023 500,000 Thereafter 2,550,000 Total $ 4,747,328

OTHER NON-CURRENT LIABILITIES (

OTHER NON-CURRENT LIABILITIES (Tables)	12 Months Ended
	Dec. 31, 2018
Other Liabilities, Noncurrent [Abstract]
Schedule of other non-current liabilities	Other non-current liabilities consist of the following at the dates indicated (in thousands): December 31, 2018 2017 Accrued employee benefit liabilities $ 28,246 $ 31,969 Accrued environmental remediation liabilities 27,358 31,803 Deferred consideration 20,232 19,640 ARO 4,349 3,833 Other 4,715 5,411 Total other non-current liabilities $ 84,900 $ 92,656

ACCUMULATED OTHER COMPREHENSI_2

ACCUMULATED OTHER COMPREHENSIVE (LOSS) INCOME (Tables)	12 Months Ended
	Dec. 31, 2018
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
Schedule of accumulated other comprehensive income (loss)	Accumulated other comprehensive (loss) income consists of the following at the dates indicated (in thousands): December 31, 2018 2017 Unrealized (losses) gains on derivative instruments $ (490 ) $ 29,530 Net loss on settlement of interest rate swaps, net of amortization (38,699 ) (47,924 ) Unrecognized loss on benefit plans (872 ) (2,617 ) Other comprehensive income from equity method investments — 49,642 Total accumulated other comprehensive (loss) income $ (40,061 ) $ 28,631

DERIVATIVE INSTRUMENTS AND HE_2

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables)	12 Months Ended
	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of commodity derivative instruments outstanding	The following table summarizes the notional volumes of the net long (short) positions of our commodity derivative instruments outstanding at December 31, 2018 (amounts in thousands of gallons): Volume Derivative Purpose Current Long-Term Derivatives NOT designated as hedging instruments: Physical fixed price derivative contracts (23,119 ) (4,765 ) Physical index derivative contracts 52,912 — Futures contracts for refined petroleum products 29,771 (9,996 ) Hedge Type Derivatives designated as hedging instruments: Futures contracts for refined petroleum products (107,184 ) (420 ) Fair Value Hedge
Schedule of fair value of each classification of derivative instruments	The following table sets forth the fair value of each classification of derivative instruments and the locations of the derivative instruments on our consolidated balance sheets at the dates indicated (in thousands): December 31, 2018 Derivatives Derivatives Derivative Netting (1) Total Physical fixed price derivative contracts $ 17,934 $ — $ 17,934 $ (84 ) $ 17,850 Physical index derivative contracts 286 — 286 (117 ) 169 Total current derivative assets 18,220 — 18,220 (201 ) 18,019 Physical fixed price derivative contracts 1,003 — 1,003 — 1,003 Total non-current derivative assets 1,003 — 1,003 — 1,003 Physical fixed price derivative contracts (1,386 ) — (1,386 ) 84 (1,302 ) Physical index derivative contracts (135 ) — (135 ) 117 (18 ) Total current derivative liabilities (1,521 ) — (1,521 ) 201 (1,320 ) Physical fixed price derivative contracts (3 ) — (3 ) — (3 ) Total non-current derivative liabilities (3 ) — (3 ) — (3 ) Net derivative assets $ 17,699 $ — $ 17,699 $ — $ 17,699 ____________________________ (1) Amounts represent the netting of physical fixed and index contracts’ assets and liabilities when a legal right of offset exists. December 31, 2017 Derivatives Derivatives Derivative Netting (1) Total Physical fixed price derivative contracts $ 2,582 $ — $ 2,582 $ (63 ) $ 2,519 Physical index derivative contracts 455 — 455 (9 ) 446 Interest rate derivatives — 31,994 31,994 — 31,994 Total current derivative assets 3,037 31,994 35,031 (72 ) 34,959 Total non-current derivative assets — — — — — Physical fixed price derivative contracts (7,226 ) — (7,226 ) 63 (7,163 ) Physical index derivative contracts (18 ) — (18 ) 9 (9 ) Total current derivative liabilities (7,244 ) — (7,244 ) 72 (7,172 ) Total non-current derivative liabilities — — — — — Net derivative (liabilities) assets $ (4,207 ) $ 31,994 $ 27,787 $ — $ 27,787 ____________________________ (1) Amounts represent the netting of physical fixed and index contracts’ assets and liabilities when a legal right of offset exists.
Schedule of 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): Year Ended December 31, Location 2018 2017 Derivatives NOT designated as hedging instruments: Physical fixed price derivative contracts Product sales $ 22,046 $ (6,748 ) Physical index derivative contracts Product sales 440 82 Physical fixed price derivative contracts Cost of product sales (1,777 ) 3,937 Physical index derivative contracts Cost of product sales (81 ) 1,147 Futures contracts for refined products Cost of product sales 7,661 13,710 Derivatives designated as fair value hedging instruments: Futures contracts for refined products Cost of product sales $ 42,658 $ (22,362 ) Physical inventory - hedged items Cost of product sales (46,397 ) 32,016 Ineffectiveness excluding the time value component on fair value hedging instruments: Fair value hedge ineffectiveness (excluding time value) Cost of product sales $ 1,335 $ (4,673 ) Time value excluded from hedge assessment Cost of product sales (5,074 ) 14,327 Net (loss) gain for ineffectiveness in income $ (3,739 ) $ 9,654
Schedule of change in value recognized in OCI and Losses reclassified from AOCI	The change in value recognized in OCI and the losses reclassified from AOCI to income attributable to our derivative instruments designated as cash flow hedges were as follows for the periods indicated (in thousands): Gain (Loss) Recognized 2018 2017 Derivatives designated as cash flow hedging instruments: Interest rate contracts $ 27,739 $ (10,597 ) Commodity derivatives 1,975 (136 ) Total $ 29,714 $ (10,733 ) Gain (Loss) Reclassified Location 2018 2017 Derivatives designated as cash flow hedging instruments: Interest rate contracts Interest and debt expense $ 50,509 $ (11,922 ) Total $ 50,509 $ (11,922 )

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Schedule of financial assets and liabilities measured at fair value	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): December 31, 2018 December 31, 2017 Level 1 Level 2 Level 1 Level 2 Financial assets: Physical fixed price derivative contracts $ — $ 18,937 $ — $ 2,582 Physical index derivative contracts — 286 — 455 Interest rate derivatives — — — 31,994 Financial liabilities: Physical fixed price derivative contracts — (1,389 ) — (7,226 ) Physical index derivative contracts — (135 ) — (18 ) Futures contracts for refined products — — — — Fair value $ — $ 17,699 $ — $ 27,787
Schedule of carrying value and fair value using Level 2 inputs	The carrying value and fair value of our debt, using Level 2 input values, were as follows at the dates indicated (in thousands): December 31, 2018 December 31, 2017 Carrying Fair Value Carrying Fair Value Fixed-rate debt $ 3,546,396 $ 3,364,549 $ 4,241,963 $ 4,384,336 Variable-rate debt 1,168,046 1,172,328 668,562 668,904 Total debt $ 4,714,442 $ 4,536,877 $ 4,910,525 $ 5,053,240

PENSIONS AND OTHER POSTRETIRE_2

PENSIONS AND OTHER POSTRETIREMENT BENEFITS (Tables)	12 Months Ended
	Dec. 31, 2018
Retirement Benefits [Abstract]
Schedule of components of projected benefit obligations and plan assets, and the funded status of the plans	The components of projected benefit obligations and plan assets, and the funded status of the RIGP and the Retiree Medical Plan (“the Plans”) were as follows for the periods indicated (in thousands): RIGP Retiree Medical Plan Year Ended December 31, Year Ended December 31, 2018 2017 2018 2017 Change in benefit obligation: Benefit obligation at beginning of year $ 9,847 $ 13,178 $ 29,363 $ 31,958 Service cost (84 ) (58 ) 199 287 Interest cost 293 333 1,029 1,209 Plan participants’ contributions — — 533 481 Actuarial (gain) loss (270 ) (1,524 ) (1,531 ) 689 Settlements (2,127 ) (1,900 ) — — Benefit payments (206 ) (182 ) (2,573 ) (3,074 ) Substantive provision change — — — (2,187 ) Benefit obligation at end of year $ 7,453 $ 9,847 $ 27,020 $ 29,363 Change in plan assets: Fair value of plan assets at beginning of year $ 4,484 $ 4,524 $ — $ — Actual return on plan assets 221 452 — — Plan participants’ contributions — — 533 481 Employer contributions 1,047 1,590 2,040 2,593 Settlements (2,127 ) (1,900 ) — — Benefit payments (206 ) (182 ) (2,573 ) (3,074 ) Fair value of plan assets at end of year $ 3,419 $ 4,484 $ — $ — Funded status at end of year $ (4,034 ) $ (5,363 ) $ (27,020 ) $ (29,363 )
Schedule of amounts recognized in consolidated balance sheets for the Plans	Amounts recognized in our consolidated balance sheets for the Plans consist of the following at the dates indicated below (in thousands): RIGP Retiree Medical Plan December 31, December 31, 2018 2017 2018 2017 Liabilities: Accrued employee benefit liabilities - current $ — $ — $ (2,808 ) $ (2,757 ) Accrued employee benefit liabilities - noncurrent (4,034 ) (5,363 ) (24,212 ) (26,606 ) Total $ (4,034 ) $ (5,363 ) $ (27,020 ) $ (29,363 ) AOCI: Prior service credit $ — $ — $ (1,727 ) $ (2,187 ) Net actuarial loss 310 722 2,289 4,082 Total $ 310 $ 722 $ 562 $ 1,895
Schedule of accumulated benefit obligation in excess of plan assets	Information regarding the accumulated benefit obligation in excess of plan assets for the RIGP is as follows at the dates indicated (in thousands): RIGP December 31, 2018 2017 Projected benefit obligation $ 7,453 $ 9,847 Accumulated benefit obligation (1) 7,177 9,128 Fair value of plan assets 3,419 4,484 ____________________________ (1) The accumulated benefit obligation does not include an assumption for future compensation increases.
Schedule of weighted average assumptions used in determining net periodic benefit cost for the Plans	The weighted average assumptions used in determining net periodic benefit cost for the Plans were as follows for the periods indicated: RIGP Retiree Medical Plan Year Ended December 31, Year Ended December 31, 2018 2017 2016 2018 2017 2016 Discount rate 3.3 % 3.2 % 3.0 % 3.6 % 4.0 % 4.1 % Expected return on plan assets 4.0 % 5.8 % 5.8 % N/A N/A N/A Rate of compensation increase 2.0 % 3.0 % 3.0 % 2.0 % 3.0 % 3.0 %
Schedule of assumptions used in determining benefit obligations for the Plans	The assumptions used in determining benefit obligations for the Plans were as follows at the dates indicated: RIGP Retiree Medical Plan December 31, December 31, 2018 2017 2018 2017 Discount rate 4.3 % 3.3 % 4.4 % 3.6 % Rate of compensation increase 3.0 % 3.0 % 3.0 % 3.0 %
Schedule of components of net periodic benefit cost and other changes recognized in OCI	The components of the net periodic benefit cost and other changes recognized in OCI for the Plans were as follows for the periods indicated (in thousands): RIGP Retiree Medical Plan Year Ended December 31, Year Ended December 31, 2018 2017 2016 2018 2017 2016 Components of net periodic benefit cost: Service cost $ (84 ) $ (58 ) $ (34 ) $ 199 $ 287 $ 323 Interest cost (1) 293 333 421 1,029 1,209 1,309 Expected return on plan assets (1) (168 ) (251 ) (256 ) — — — Amortization of prior service credit (1) — — — (461 ) — — Actuarial loss due to settlements (1) 88 150 598 — — — Amortization of unrecognized loss (1) — 19 522 263 — 766 Net periodic benefit cost $ 129 $ 193 $ 1,251 $ 1,030 $ 1,496 $ 2,398 RIGP Retiree Medical Plan Year Ended December 31, Year Ended December 31, 2018 2017 2016 2018 2017 2016 Other changes in plan assets and benefit obligations recognized in OCI: Prior service credit $ — $ — $ — $ — $ (2,187 ) — Net actuarial (gain) loss (324 ) (1,725 ) (2,068 ) (1,531 ) 688 2,871 Amortization of unrecognized loss — (19 ) (522 ) (263 ) — (766 ) Actuarial loss due to settlements (88 ) (150 ) (598 ) — — — Amortization of prior service credit — — — 461 — — Total recognized in OCI $ (412 ) $ (1,894 ) $ (3,188 ) $ (1,333 ) $ (1,499 ) $ 2,105 Total recognized in net period benefit cost and OCI $ (283 ) $ (1,701 ) $ (1,937 ) $ (303 ) $ (3 ) $ 4,503 ___________________________ (1) These components of net periodic benefit cost are reported on the Consolidated Statements of Operations as other expense. See Note 2 - Summary of Significant Accounting Policies for further discussion on the accounting guidance.
Schedule of amounts in AOCI to recognized in the next fiscal year	We expect that the following amounts, currently included in OCI, for the Plans will be recognized in our consolidated statement of operations during the year ending December 31, 2019 (in thousands): RIGP Retiree Medical Plan Prior service credit $ — $ (461 )
Schedule of expected employer contributions to benefit plans	We estimate the following benefit payments, which reflect expected future service, as appropriate, will be paid for the Plans in the years indicated below as such (in thousands): RIGP Retiree Medical Plan 2019 $ 2,081 $ 2,870 2020 674 2,718 2021 847 2,581 2022 735 2,503 2023 653 2,473 Thereafter 1,520 9,151
Summary of investments in the RIGP	A summary of investments in the RIGP are as follows at the dates indicated (in thousands): December 31, 2018 December 31, 2017 Level 1 Level 3 Level 1 Level 3 Mutual fund - fixed-income securities $ 1,576 $ — $ 2,454 $ — Mutual fund - money market 105 — 222 — Coal lease — 1,738 — 1,808 Fair value of plan assets $ 1,681 $ 1,738 $ 2,676 $ 1,808
Summary of the activity in Level 3 pension assets	The following table summarizes the activity in our Level 3 pension assets for the periods indicated (in thousands): Year Ended 2018 2017 Beginning balance, January 1 $ 1,808 $ 2,007 Royalty payments received 400 380 Unrealized loss (70 ) (199 ) Transfers out of Level 3 (400 ) (380 ) Ending balance, December 31 $ 1,738 $ 1,808

UNIT-BASED COMPENSATION PLANS (

UNIT-BASED COMPENSATION PLANS (Tables)	12 Months Ended
	Dec. 31, 2018
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 Weighted (1) Unvested at January 1, 2017 1,296 $ 63.54 Granted (2) 547 69.91 Performance adjustment (3) 32 71.50 Vested (386 ) 70.98 Forfeited (39 ) 64.26 Unvested at December 31, 2017 1,450 $ 64.04 Granted (2) 748 48.16 Performance adjustment (3) 39 73.17 Vested (544 ) 68.84 Forfeited (48 ) 58.46 Unvested at December 31, 2018 1,645 $ 55.52 ____________________________ (1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. The weighted-average grant date fair value per LP Unit for forfeited and vested awards is determined before an allowance for forfeitures. (2) Includes both phantom and performance awards. Performance awards are granted at a target amount but, depending on our performance during the vesting period with respect to certain pre-established goals, the number of LP Units issued upon vesting of such performance awards can be greater or less than the target amount. (3) Represents the LP Units issued in excess of target amounts for performance awards that vested during the year ended December 31, 2018 and 2017 as a result of our above target performance with respect to applicable performance goals.

PARTNERS' CAPITAL AND DISTRIB_2

PARTNERS' CAPITAL AND DISTRIBUTIONS (Tables)	12 Months Ended
	Dec. 31, 2018
Equity [Abstract]
Reconciliation of LP units outstanding	The following is a summary of changes in Buckeye’s outstanding units for the periods indicated (in thousands): LP Units Class C Units Total Units outstanding at January 1, 2016 129,524 — 129,524 LP Units issued pursuant to the Option Plan (1) 6 — 6 LP Units issued pursuant to the LTIP (1) 254 — 254 Issuance of units to institutional investors 8,913 — 8,913 Issuance of units through equity distribution agreements 1,567 — 1,567 Units outstanding at December 31, 2016 140,264 — 140,264 LP Units issued pursuant to the Option Plan (1) 10 — 10 LP Units issued pursuant to the LTIP (1) 244 — 244 Issuance of units through equity distribution agreements 6,159 — 6,159 Units outstanding at December 31, 2017 146,677 — 146,677 LP Units issued pursuant to the LTIP (1) 363 — 363 Issuance of Class C Units — 6,221 6,221 Issuance of Class C Units in lieu of quarterly cash distributions — 494 494 Conversion of Class C Units to LP Units 6,715 (6,715 ) — Units outstanding at December 31, 2018 153,755 — 153,755 ____________________________ (1) The number of units issued represents issuance net of tax withholding.
Schedule of cash distributions	Cash distributions paid to unitholders of Buckeye for the periods indicated were as follows (in thousands, except per unit amounts): Amount Per Total Cash Record Date Payment Date LP Unit Distributions February 23, 2016 March 1, 2016 $ 1.1875 $ 154,928 May 16, 2016 May 23, 2016 1.2000 157,247 August 15, 2016 August 22, 2016 1.2125 159,881 November 15, 2016 November 22, 2016 1.2250 172,673 Total $ 644,729 February 21, 2017 February 28, 2017 $ 1.2375 $ 174,888 May 15, 2017 May 22, 2017 1.2500 176,832 August 14, 2017 August 21, 2017 1.2625 179,631 November 13, 2017 November 20, 2017 1.2625 186,042 Total $ 717,393 February 20, 2018 February 27, 2018 $ 1.2625 $ 186,764 May 14, 2018 May 21, 2018 1.2625 186,766 August 13, 2018 August 20, 2018 1.2625 186,624 November 13, 2018 November 20, 2018 0.7500 115,969 Total $ 676,123

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Current and deferred income tax expense (benefit)	Our current and deferred income tax expense (benefit) was as follows (in thousands): December 31, 2018 2017 2016 Current income tax expense (benefit) $ 2,603 $ 297 $ (276 ) Deferred income tax expense 1,137 575 1,736 Total income tax expense $ 3,740 $ 872 $ 1,460
Schedule of tax effects of significant items comprising net deferred tax assets and liabilities	The tax effects of significant items comprising our net deferred tax assets and liabilities at December 31, 2018 and 2017 are as follows (in thousands): December 31, 2018 2017 Deferred tax asset: Net operating loss carryforward $ 18,757 $ 19,234 Capital loss carryforward 11,453 11,453 Other 2,452 2,697 Total deferred tax asset $ 32,662 $ 33,384 Deferred tax liability: Property, plant and equipment $ 1,132 $ 1,536 Other 132 83 Total deferred tax liability 1,264 1,619 Net deferred tax asset 31,398 31,765 Less: Valuation allowance (30,203 ) (29,451 ) Deferred taxes, net $ 1,195 $ 2,314

(LOSS) EARNINGS PER UNIT (Table

(LOSS) EARNINGS PER UNIT (Tables)	12 Months Ended
	Dec. 31, 2018
Earnings Per Share [Abstract]
Reconciliation of weighted average number of LP Units used in basic and diluted earnings per LP Unit calculations	The following tables set forth the calculation of basic and diluted (loss) earnings per unit, attributable to Buckeye’s unit holders, taking into consideration net income allocable to participating securities, as well as the reconciliation of basic weighted average units outstanding to diluted weighted average units outstanding (in thousands, except per unit amounts). Year Ended December 31, 2018 2017 2016 Net (loss) income attributable to unitholders $ (62,853 ) $ 474,794 $ 535,608 Basic: Weighted average units outstanding - basic 152,355 142,501 132,242 (Loss) earnings per unit - basic $ (0.41 ) $ 3.33 $ 4.05 Diluted: Weighted average units outstanding - basic 152,355 142,501 132,242 Effect of dilutive securities (1) — 643 685 Weighted average units outstanding - diluted 152,355 143,144 132,927 (Loss) earnings per unit - diluted $ (0.41 ) $ 3.32 $ 4.03 ____________________________ (1) Excludes 413,732 units from the computation of (loss) earnings per unit on a diluted basis as their effect was anti-dilutive for the year ended December 31, 2018 .

BUSINESS SEGMENTS (Tables)

BUSINESS SEGMENTS (Tables)	12 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
Disaggregation of Revenue	The following tables provide information about our revenue types by reportable segment for the periods indicated (in thousands). Prior periods have been disaggregated for comparison purposes. Year Ended December 31, 2018 Domestic Pipelines & Terminals Global Marine Terminals Merchant Services Intersegment Eliminations Total Revenue from contracts with customers Pipeline transportation $ 503,781 $ — $ — $ (11,656 ) $ 492,125 Terminalling and storage services 437,845 386,021 — (37,017 ) 786,849 Product sales — 5,412 2,033,646 (2,629 ) 2,036,429 Other services 44,880 1,209 7,385 (1,390 ) 52,084 Total revenue from contracts with customers 986,506 392,642 2,041,031 (52,692 ) 3,367,487 Revenue from leases 37,684 172,260 — (284 ) 209,660 Commodity derivative contracts, net 5,894 — 531,128 (5,894 ) 531,128 Total revenue $ 1,030,084 $ 564,902 $ 2,572,159 $ (58,870 ) $ 4,108,275 Year Ended December 31, 2017 Domestic Pipelines & Terminals Global Marine Terminals Merchant Services Intersegment Eliminations Total Revenue from contracts with customers Pipeline transportation $ 498,974 $ — $ — $ (17,648 ) $ 481,326 Terminalling and storage services 447,703 466,489 — (28,822 ) 885,370 Product sales — 3,891 1,531,433 (12,788 ) 1,522,536 Other services 50,484 3,547 14,171 (707 ) 67,495 Total revenue from contracts with customers 997,161 473,927 1,545,604 (59,965 ) 2,956,727 Revenue from leases 38,504 160,822 — (525 ) 198,801 Commodity derivative contracts, net (2 ) — 492,617 2 492,617 Total revenue $ 1,035,663 $ 634,749 $ 2,038,221 $ (60,488 ) $ 3,648,145 Year Ended December 31, 2016 Domestic Pipelines & Terminals Global Marine Terminals Merchant Services Intersegment Eliminations Total Revenue from contracts with customers Pipeline transportation $ 480,730 $ — $ — $ (18,224 ) $ 462,506 Terminalling and storage services 448,322 520,411 — (29,645 ) 939,088 Product sales — 304 1,155,276 (5,902 ) 1,149,678 Other services 39,780 435 11,584 (1,624 ) 50,175 Total revenue from contracts with customers 968,832 521,150 1,166,860 (55,395 ) 2,601,447 Revenue from leases 42,084 150,315 — (525 ) 191,874 Commodity derivative contracts, net 780 — 455,055 (780 ) 455,055 Total revenue $ 1,011,696 $ 671,465 $ 1,621,915 $ (56,700 ) $ 3,248,376
Summary of financial information for continuing operations by geographical area	The following tables summarize our revenues by major geographic area, for the periods indicated (in thousands): Year Ended December 31, 2018 2017 2016 Revenue: United States $ 3,868,364 $ 3,361,160 $ 2,915,619 International 239,911 286,985 332,757 Total revenue $ 4,108,275 $ 3,648,145 $ 3,248,376
Schedule of segment reporting information	The following tables summarize our earnings (losses) from equity investments by each segment for the periods indicated (in thousands): Year Ended December 31, 2018 2017 2016 Earnings (loss) from equity investments: Domestic Pipelines & Terminals $ 13,232 $ 13,095 $ 11,536 Global Marine Terminals (287,355 ) 22,910 — Total earnings from equity investments $ (274,123 ) $ 36,005 $ 11,536 Year Ended December 31, 2018 2017 2016 Capital expenditures (1) Domestic Pipelines & Terminals $ 311,335 $ 250,454 $ 294,849 Global Marine Terminals 156,258 182,267 191,422 Merchant Services 18 614 45 Total capital expenditures, net $ 467,611 $ 433,335 $ 486,316 ____________________________ (1) Amounts exclude the impact of accruals. See Note 25 - Supplemental Cash Flow Information for further discussion. December 31, 2018 2017 Total Assets: Domestic Pipelines & Terminals $ 4,042,864 $ 3,936,058 Global Marine Terminals 4,989,503 5,924,731 Merchant Services 323,183 443,870 Total assets $ 9,355,550 $ 10,304,659
Adjusted EBITDA by segment and reconciliation of income from continuing operations to Adjusted EBITDA	The following table presents a reconciliation of consolidated net (loss) income, which is the most comparable financial measure under GAAP, to Adjusted EBITDA, as well as Adjusted EBITDA by segment for the periods indicated (in thousands): December 31, 2018 2017 2016 Reconciliation of Net (loss) income to Adjusted EBITDA: Net (loss) income $ (51,915 ) $ 493,665 $ 548,675 Less: Net income attributable to noncontrolling interests (7,123 ) (14,863 ) (13,067 ) Net (loss) income attributable to Buckeye Partners, L.P. (59,038 ) 478,802 535,608 Add: Interest and debt expense 190,172 225,583 194,922 Income tax expense 3,740 872 1,460 Depreciation and amortization (1) 269,423 269,243 254,659 Non-cash unit-based compensation expense 21,776 30,302 33,344 Acquisition and transition expense (2) 11,321 4,226 8,196 Hurricane-related costs, net of recoveries (3) 124 5,780 16,795 Proportionate share of Adjusted EBITDA for equity method investment in VTTI (4) 101,435 126,642 — Goodwill impairment 536,964 — — Loss (earnings) from the equity method investment in VTTI (4) 286,633 (22,910 ) — Less: Amortization of unfavorable storage contracts (5) — — (5,979 ) Gains on property damage recoveries (6) (14,535 ) (4,621 ) (5,700 ) Gain on sale of ammonia pipeline — — (5,299 ) Gain on sale of DPTS asset package (342,984 ) — — Adjusted EBITDA $ 1,005,031 $ 1,113,919 $ 1,028,006 Adjusted EBITDA Domestic Pipelines & Terminals $ 561,961 $ 573,021 $ 568,405 Global Marine Terminals 428,663 512,821 427,229 Merchant Services 14,407 28,077 32,372 Adjusted EBITDA $ 1,005,031 $ 1,113,919 $ 1,028,006 ____________________________ (1) Includes 100% of the depreciation and amortization expense of $73.8 million , $72.4 million and $71.7 million for Buckeye Texas for the years ended December 31, 2018 , 2017 and 2016 , respectively. In April 2018, we acquired our business partner’s 20% ownership interest in Buckeye Texas and, as a result, own 100% of Buckeye Texas. (2) Represents transaction, internal and third-party costs related to asset acquisition and integration. (3) Represents costs incurred at our BBH facility in the Bahamas, Yabucoa Terminal in Puerto Rico, Corpus Christi facilities in Texas, and certain terminals in Florida, as a result of hurricanes which occurred in 2017 and 2016, consisting of operating expenses and write-offs of damaged long-lived assets, net of insurance recoveries. (4) Due to the significance of our equity method investment in VTTI, effective January 1, 2017, we applied the definition of Adjusted EBITDA, covered in our description of Adjusted EBITDA, with respect to our proportionate share of VTTI’s Adjusted EBITDA. The calculation of our proportionate share of the reconciling items used to derive Adjusted EBITDA is based upon our 50% equity interest in VTTI, prior to adjustments related to noncontrolling interests in several of its subsidiaries and partnerships, which are immaterial. Due to certain terms of the definitive agreement regarding the divestiture of our equity interest in VTTI, we discontinued the equity method of accounting and recorded our interest at fair value. Accordingly, beginning in the fourth quarter of 2018 and prospectively, we no longer recorded any equity earnings or reflected any contributions from VTTI to our Adjusted EBITDA. Included in loss (earnings) from the equity method investment in VTTI for the year ended December 31, 2018 , is a $300.3 million non-cash loss on the sale of our investment in VTTI as discussed in Note 4 - Acquisitions, Investments and Disposition. (5) Represents fair value adjustment amortization related to certain storage contracts acquired in the BBH acquisition. These contracts were fully amortized by December 31, 2016. (6) Represents gains on recoveries of property damages caused by third parties, which, for 2018, primarily related to a settlement in connection with a 2012 vessel allision with a jetty at our BBH facility in the Bahamas, and for 2017, primarily related to a settlement in connection with a 2014 vessel allision with a ship dock at our terminal located in Pennsauken, New Jersey.

SUPPLEMENTAL CASH FLOW INFORM_2

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2018
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): Year Ended December 31, 2018 2017 2016 Cash paid for interest (net of capitalized interest) (1) $ 224,371 $ 210,723 $ 174,555 Cash paid for income taxes 1,282 1,333 812 Capitalized interest 8,921 4,792 4,371 ____________________________ (1) Excludes proceeds of $51.0 million related to the settlement of our interest rate swaps. See Note 16 - Derivative Instruments and Hedging Activities for further discussion.

QUARTERLY FINANCIAL DATA (UNA_2

QUARTERLY FINANCIAL DATA (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2018
Quarterly Financial Information Disclosure [Abstract]
Summarized quarterly financial data	Summarized quarterly financial data for the periods indicated is set forth below (in thousands, except per unit amounts). Quarterly results were influenced by seasonal and other factors inherent in our business. First Second Third Fourth Total 2018 Revenue $ 1,183,105 $ 940,839 $ 909,548 $ 1,074,783 $ 4,108,275 Operating (loss) income (1) 169,513 145,697 (391,831 ) 493,652 417,031 Net (loss) income 117,092 93,317 (745,336 ) 483,012 (51,915 ) Net (loss) income attributable to Buckeye Partners, L.P. 112,373 91,904 (745,835 ) 482,520 (59,038 ) Earnings (loss) per unit - basic $ 0.75 $ 0.59 $ (4.86 ) $ 3.14 $ (0.41 ) Earnings (loss) per unit - diluted $ 0.74 $ 0.59 $ (4.86 ) $ 3.13 $ (0.41 ) 2017 Revenue $ 969,273 $ 810,201 $ 922,619 $ 946,052 $ 3,648,145 Operating income 172,576 170,754 168,329 173,705 685,364 Net income 126,309 116,379 120,224 130,753 493,665 Net income attributable to Buckeye Partners, L.P. 123,576 112,722 116,187 126,317 478,802 Earnings per unit - basic $ 0.88 $ 0.80 $ 0.82 $ 0.85 $ 3.33 Earnings per unit - diluted $ 0.88 $ 0.80 $ 0.81 $ 0.85 $ 3.32 ____________________________ (1) Fourth quarter of 2018 includes the gain on sale of the DPTS asset package. See Note 4 - Acquisitions, Investments and Disposition for further discussion.

ORGANIZATION (Details)

ORGANIZATION (Details) mi in Thousands, bbl in Millions	12 Months Ended
	Dec. 31, 2018terminalmibbl
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Length of refined petroleum products pipelines (in miles) | mi	6
Number of terminals in network (more than) | terminal	115
Aggregate storage capacity of terminals (more than) (in barrels) | bbl	118

SUMMARY OF SIGNIFICANT ACCOUN_4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Narrative (Details)	Jan. 01, 2018	Dec. 31, 2018USD ($)segmentitem	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Mar. 31, 2019USD ($)	Apr. 30, 2018	Jan. 31, 2017
Finite-Lived Intangible Assets [Line Items]
Number of operating segments | segment		3
Number of reportable segments | segment		3
Interest capitalized		$ 8,900,000	$ 4,800,000	$ 4,400,000
Weighted average rates used to capitalize interest on borrowed funds		4.60%	4.50%	4.60%
Trade receivables		$ 214,300,000	$ 265,000,000
Impairments of equity investments		300,300,000	0	$ 0
Unrecognized tax benefits related to uncertain tax positions		$ 0
Number of inventory types | item		2
Federal tax rate	21.00%
Sabina Pipeline
Finite-Lived Intangible Assets [Line Items]
Percentage of equity investment ownership acquired		63.00%
Buckeye Texas
Finite-Lived Intangible Assets [Line Items]
Percentage of equity investment ownership acquired						20.00%
Buckeye Caribbean
Finite-Lived Intangible Assets [Line Items]
Income tax exemption from real and personal property taxes (as a percent)		90.00%
Income tax exemption from municipal taxes on industrial development income (as a percent)		60.00%
Income tax exemption on excise taxes imposed (as a percent)		100.00%
Minimum | Customer contracts
Finite-Lived Intangible Assets [Line Items]
Useful lives		1 year
Minimum | Customer relationships
Finite-Lived Intangible Assets [Line Items]
Useful lives		12 years
Minimum | Buckeye Caribbean
Finite-Lived Intangible Assets [Line Items]
Income tax rate on industrial development income (as a percent)		4.00%
Minimum | St. Lucia in the Caribbean
Finite-Lived Intangible Assets [Line Items]
Tax holidays period		50 years
Maximum | Customer contracts
Finite-Lived Intangible Assets [Line Items]
Useful lives		10 years
Maximum | Customer relationships
Finite-Lived Intangible Assets [Line Items]
Useful lives		20 years
Maximum | Buckeye Caribbean
Finite-Lived Intangible Assets [Line Items]
Income tax rate on industrial development income (as a percent)		7.00%
Line of Credit | Credit Facility
Finite-Lived Intangible Assets [Line Items]
Maximum borrowing capacity		$ 1,500,000,000
VTTI B.V.
Finite-Lived Intangible Assets [Line Items]
Other comprehensive loss related to foreign currency translation adjustments		$ 49,600,000
Ownership percentage		50.00%					50.00%
Buckeye Texas
Finite-Lived Intangible Assets [Line Items]
Ownership percentage		100.00%				100.00%
ASU 2017-07
Finite-Lived Intangible Assets [Line Items]
Expenses			1,500,000	3,400,000
Other expenses			$ 1,500,000	$ 3,400,000
Forecast | ASU 2016-02
Finite-Lived Intangible Assets [Line Items]
ROU asset					$ 160,000,000
Lease liability					$ 160,000,000

SUMMARY OF SIGNIFICANT ACCOUN_5

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Activity in Allowance for Doubtful Accounts (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Allowance for Doubtful Accounts Receivable [Roll Forward]
Balance at beginning of period	$ 4,893	$ 7,960	$ 8,380
Charged to expense	2,083	305	2,143
Write-offs, net of recoveries	(76)	(3,372)	(2,563)
Balance at end of period	$ 6,900	$ 4,893	$ 7,960

ACQUISITIONS, INVESTMENTS AND_3

ACQUISITIONS, INVESTMENTS AND DISPOSITION - Equity Investment Transactions (Details) - USD ($) $ in Thousands	Dec. 17, 2018	Nov. 30, 2018	Jan. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Schedule of Equity Method Investments [Line Items]
Distributions of earnings from equity investments				$ 24,350	$ 35,854	$ 3,280
Loss of disposal of equity interest				274,123	(36,005)	(11,536)
Gain on sale of DPTS Asset Package				342,984	0	$ 0
VTTI Acquisition
Schedule of Equity Method Investments [Line Items]
Percentage of equity investment ownership acquired			50.00%
Cash consideration			$ 1,150,000
VTTI Energy Partners LP
Schedule of Equity Method Investments [Line Items]
Cash consideration					$ 236,800
Percent of cash consideration					50.00%
Disposed of by Sale | DPTS Asset Package
Schedule of Equity Method Investments [Line Items]
Transaction costs	$ 7,700
Deferred payment	10,000
Proceeds from sale of assets	$ 454,600			444,600
Gain on sale of DPTS Asset Package				$ 342,500
Disposed of by Sale | VTTI B.V.
Schedule of Equity Method Investments [Line Items]
Percentage of equity interest sold		50.00%
Proceeds from sale of equity interest		$ 975,000
Distributions of earnings from equity investments		22,600
Transaction costs		8,000
Loss of disposal of equity interest		$ 300,300

REVENUE FROM CONTRACTS WITH C_3

REVENUE FROM CONTRACTS WITH CUSTOMERS - Contract Asset and Liability (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Revenue from Contract with Customer [Abstract]
Receivables from contracts with customers	$ 199,324	$ 245,280
Contract assets	16,989	13,999
Contract liabilities	(26,999)	$ (15,778)
Reclassified to receivables	(14,000)
Amounts included in deferred revenue	$ 8,200

ACQUISITIONS, INVESTMENTS AND_4

ACQUISITIONS, INVESTMENTS AND DISPOSITION - South Texas Transactions (Details) $ in Thousands, bbl in Millions	1 Months Ended	12 Months Ended
	Apr. 30, 2018USD ($)bbl	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Business Acquisition [Line Items]
Capital expenditures incurred but not yet paid		$ 85,300	$ 62,600	$ 59,100
Acquisition of and contribution to equity investments		$ 42,204	$ 1,387,844	$ 0
Buckeye Texas
Business Acquisition [Line Items]
Percentage of equity investment ownership acquired	20.00%
Consideration for business acquisition	$ 210,000
Buckeye Texas
Business Acquisition [Line Items]
Ownership percentage	100.00%	100.00%
Joint Venture
Business Acquisition [Line Items]
Ownership percentage	50.00%
Additional capacity over initial design (in barrels) | bbl	6.8
Initial capacity of design (in barrels) | bbl	3.4
Construction cost basis	100.00%
Capital expenditures incurred but not yet paid	$ 480,900
Joint Venture, Buckeye Partners 50% Interest
Business Acquisition [Line Items]
Capital expenditures incurred but not yet paid	$ 240,500
Phillips 66 Partners LP | Joint Venture
Business Acquisition [Line Items]
Ownership percentage	25.00%

REVENUE FROM CONTRACTS WITH C_4

REVENUE FROM CONTRACTS WITH CUSTOMERS - Performance Obligations (Details) $ in Thousands	Dec. 31, 2018USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 358,060
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 196,399
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 126,777
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 51,499
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 945,109
Remaining performance obligation, period
Leasing arrangement | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 211,700
Remaining performance obligation, period	1 year
Leasing arrangement | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 207,200
Remaining performance obligation, period	1 year
Leasing arrangement | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 188,000
Remaining performance obligation, period	1 year
Leasing arrangement | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 134,800
Remaining performance obligation, period	1 year
Leasing arrangement | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 48,500
Remaining performance obligation, period

ACQUISITIONS, INVESTMENTS AND_5

ACQUISITIONS, INVESTMENTS AND DISPOSITION - 2017 Acquisitions (Details) - Duck Island $ in Millions	1 Months Ended
	Dec. 31, 2017USD ($)
Business Acquisition [Line Items]
Consideration for business acquisition	$ 26.1
Cash acquired	$ 2.4

ACQUISITIONS, INVESTMENTS AND_6

ACQUISITIONS, INVESTMENTS AND DISPOSITION - Purchase Price Allocation of Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Aug. 31, 2016
Business Acquisition [Line Items]
Goodwill	$ 470,875	$ 1,007,313	$ 1,004,545
Duck Island
Business Acquisition [Line Items]
Current assets, including cash acquired of $2,444		8,989
Cash acquired		2,444
Property, plant and equipment		18,306
Intangible Assets		2,200
Goodwill		3,294
Current liabilities		(3,516)
Environmental liabilities		(782)
Allocated purchase price		$ 28,491
Indianola Pipeline
Business Acquisition [Line Items]
Inventories				$ 1,554
Property, plant and equipment				16,713
Goodwill				7,758
Allocated purchase price				$ 26,025

ACQUISITIONS, INVESTMENTS AND_7

ACQUISITIONS, INVESTMENTS AND DISPOSITION - 2016 Acquisitions (Details) $ in Millions	1 Months Ended
	Aug. 31, 2016USD ($)
Indianola Pipeline
Business Acquisition [Line Items]
Consideration for business acquisition	$ 26

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Commitments and Contingencies Disclosure
Total rental expense	$ 34.7	$ 29.9	$ 32.8
Rights-of-way payments	7.9	7.4	7.1
Environmental Remediation
Commitments and Contingencies Disclosure
Operating expenses, net of recoveries	13.7	7.4	$ 8.2
Insurance settlements receivable	$ 4.2	$ 5.3

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES - Minimum Lease Payment Obligations (Detail) $ in Thousands	Dec. 31, 2018USD ($)
Minimum lease payment obligations under operating leases
2,019	$ 29,050
2,020	26,255
2,021	22,215
2,022	21,378
2,023	21,126
Thereafter	138,466
Total	$ 258,490

INVENTORIES (Details)

INVENTORIES (Details) $ in Thousands, gal in Millions	Dec. 31, 2018USD ($)gal	Dec. 31, 2017USD ($)gal
Inventory Disclosure [Abstract]
Liquid petroleum products	$ 186,683	$ 280,934
Materials and supplies	24,201	20,491
Total inventories	$ 210,884	$ 301,425
Refined petroleum products (in gallons) | gal	114.7	142.1
Percentage of hedged refined petroleum products inventory	94.00%	85.00%

PREPAID AND OTHER CURRENT ASS_3

PREPAID AND OTHER CURRENT ASSETS (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Prepaid Expense and Other Assets, Current [Abstract]
Prepaid insurance	$ 6,622	$ 7,146
Margin deposits	8,684	7,989
Contract assets	16,989	13,999
Prepaid taxes	5,311	2,865
Other	21,288	4,340
Total prepaid and other current assets	$ 58,894	$ 36,339

PROPERTY, PLANT AND EQUIPMENT_2

PROPERTY, PLANT AND EQUIPMENT (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Property, plant and equipment
Total property, plant and equipment	$ 8,258,694	$ 7,928,240
Less: Accumulated depreciation	(1,343,898)	(1,192,448)
Property, plant and equipment, net	6,914,796	6,735,792
Depreciation expense	203,700	202,800	$ 186,600
Land
Property, plant and equipment
Total property, plant and equipment	669,383	677,866
Rights-of-way
Property, plant and equipment
Total property, plant and equipment	105,811	109,282
Buildings and leasehold improvements
Property, plant and equipment
Total property, plant and equipment	$ 284,399	282,778
Buildings and leasehold improvements | Minimum
Property, plant and equipment
Estimated Useful Lives	13 years
Buildings and leasehold improvements | Maximum
Property, plant and equipment
Estimated Useful Lives	50 years
Jetties, subsea pipeline and docks
Property, plant and equipment
Total property, plant and equipment	$ 679,500	646,922
Jetties, subsea pipeline and docks | Minimum
Property, plant and equipment
Estimated Useful Lives	20 years
Jetties, subsea pipeline and docks | Maximum
Property, plant and equipment
Estimated Useful Lives	50 years
Gas storage facility
Property, plant and equipment
Total property, plant and equipment	$ 2,349	2,349
Gas storage facility | Minimum
Property, plant and equipment
Estimated Useful Lives	25 years
Gas storage facility | Maximum
Property, plant and equipment
Estimated Useful Lives	50 years
Pipelines and terminals
Property, plant and equipment
Total property, plant and equipment	$ 5,476,790	5,289,096
Pipelines and terminals | Minimum
Property, plant and equipment
Estimated Useful Lives	7 years
Pipelines and terminals | Maximum
Property, plant and equipment
Estimated Useful Lives	50 years
Vehicles, equipment and office furnishings
Property, plant and equipment
Total property, plant and equipment	$ 155,094	150,403
Vehicles, equipment and office furnishings | Minimum
Property, plant and equipment
Estimated Useful Lives	3 years
Vehicles, equipment and office furnishings | Maximum
Property, plant and equipment
Estimated Useful Lives	20 years
Processing facilities
Property, plant and equipment
Total property, plant and equipment	$ 630,386	589,971
Processing facilities | Minimum
Property, plant and equipment
Estimated Useful Lives	30 years
Processing facilities | Maximum
Property, plant and equipment
Estimated Useful Lives	50 years
Construction in progress
Property, plant and equipment
Total property, plant and equipment	$ 254,982	$ 179,573

EQUITY INVESTMENTS - Schedule o

EQUITY INVESTMENTS - Schedule of Equity Method Investment Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jan. 31, 2017
Schedule of Equity Method Investments [Line Items]
Total equity investments	$ 1,111,793,000	$ 1,494,412,000
Total (loss) earnings from equity investments	(274,123,000)	36,005,000	$ 11,536,000
Non-cash loss on write-down of investment in VTTI B.V. (2)	(300,300,000)	0	0
Domestic Pipelines & Terminals
Schedule of Equity Method Investments [Line Items]
Total equity investments	$ 1,111,793,000	1,494,412,000
VTTI B.V.
Schedule of Equity Method Investments [Line Items]
Ownership	50.00%			50.00%
Total (loss) earnings from equity investments	$ 286,633,000	(22,910,000)	0
VTTI B.V. | Global Marine Terminals
Schedule of Equity Method Investments [Line Items]
Ownership	50.00%
Total equity investments	$ 975,000,000	1,399,825,000
Total (loss) earnings from equity investments	13,651,000	22,910,000	0
Non-cash loss on write-down of investment in VTTI B.V. (2)	$ (300,280,000)	0	0
West Shore Pipe Line Company | Domestic Pipelines & Terminals
Schedule of Equity Method Investments [Line Items]
Ownership	34.60%
Total equity investments	$ 70,727,000	70,035,000
Total (loss) earnings from equity investments	$ 10,322,000	9,451,000	7,647,000
Muskegon Pipeline LLC | Domestic Pipelines & Terminals
Schedule of Equity Method Investments [Line Items]
Ownership	40.00%
Total equity investments	$ 13,491,000	13,335,000
Total (loss) earnings from equity investments	$ 557,000	1,778,000	2,002,000
Transport4, LLC | Domestic Pipelines & Terminals
Schedule of Equity Method Investments [Line Items]
Ownership	25.00%
Total equity investments	$ 553,000	699,000
Total (loss) earnings from equity investments	$ 817,000	850,000	765,000
South Portland Terminal LLC | Domestic Pipelines & Terminals
Schedule of Equity Method Investments [Line Items]
Ownership	50.00%
Total equity investments	$ 12,055,000	10,518,000
Total (loss) earnings from equity investments	$ 1,536,000	1,016,000	1,122,000
South Texas Gateway Terminal LLC | Global Marine Terminals
Schedule of Equity Method Investments [Line Items]
Ownership	50.00%
Total equity investments	$ 39,967,000	0
Total (loss) earnings from equity investments	$ (726,000)	$ 0	$ 0

EQUITY INVESTMENTS - Financial

EQUITY INVESTMENTS - Financial Information of Equity Method Investments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jan. 31, 2017
Schedule of Equity Method Investments [Line Items]
Representation of investee financial information in the summarized equity method investments (as a percent)	100.00%
BALANCE SHEET DATA: (1)
Current assets	$ 30,045	$ 288,085
Noncurrent assets	257,036	2,600,231
Total assets	287,081	2,888,316
Current liabilities	31,287	151,850
Other liabilities	41,070	1,246,406
Combined equity	214,724	1,490,060
Total liabilities and combined equity	287,081	2,888,316
INCOME STATEMENT DATA: (1)
Revenue	460,596	553,396	$ 87,434
Operating Income	143,817	184,692	45,932
Net income	83,479	122,506	30,942
Net income attributable to investee	$ 78,962	$ 99,130	$ 30,942
VTTI B.V.
INCOME STATEMENT DATA: (1)
Ownership percentage	50.00%			50.00%

GOODWILL AND INTANGIBLE ASSET_2

GOODWILL AND INTANGIBLE ASSETS - Changes in Carrying Amount of Goodwill (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Goodwill
Impairment of long lived assets	$ 0
Impairments of equity investments	300,300,000	$ 0	$ 0
Changes in the carrying amount of goodwill
Balance at the beginning of the period	1,007,313,000	1,004,545,000
Acquisition		2,768,000
Purchase price adjustments	526,000
Impairment of goodwill	(536,964,000)	0	0
Balance at the end of the period	470,875,000	1,007,313,000	1,004,545,000
Domestic Pipelines & Terminals
Changes in the carrying amount of goodwill
Balance at the beginning of the period	298,471,000	295,703,000
Acquisition		2,768,000
Purchase price adjustments	526,000
Impairment of goodwill	0
Balance at the end of the period	298,997,000	298,471,000	295,703,000
Merchant Services
Changes in the carrying amount of goodwill
Balance at the beginning of the period	4,499,000	4,499,000
Acquisition		0
Purchase price adjustments	0
Impairment of goodwill	0
Balance at the end of the period	4,499,000	4,499,000	4,499,000
GMT Caribbean and NYH
Changes in the carrying amount of goodwill
Balance at the beginning of the period	536,964,000	536,964,000
Acquisition		0
Purchase price adjustments	0
Impairment of goodwill	(536,964,000)
Balance at the end of the period	0	536,964,000	536,964,000
GMT South Texas
Changes in the carrying amount of goodwill
Balance at the beginning of the period	167,379,000	167,379,000
Acquisition		0
Purchase price adjustments	0
Impairment of goodwill	0
Balance at the end of the period	$ 167,379,000	$ 167,379,000	$ 167,379,000

GOODWILL AND INTANGIBLE ASSET_3

GOODWILL AND INTANGIBLE ASSETS - Schedule of Intangible Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Finite-Lived Intangible Assets [Line Items]
Intangible assets	$ 610,900	$ 615,086
Accumulated amortization	(317,589)	(256,025)
Intangible assets, net	293,311	359,061
Amortization expense	65,700	66,400	$ 68,100
Future amortization expense
2,019	64,900
2,020	65,100
2,021	52,000
2,022	24,500
2,023	13,400
Customer relationships
Finite-Lived Intangible Assets [Line Items]
Intangible assets	229,300	231,620
Accumulated amortization	(106,761)	(96,147)
Intangible assets, net	122,539	135,473
Customer contracts
Finite-Lived Intangible Assets [Line Items]
Intangible assets	381,600	383,466
Accumulated amortization	(210,828)	(159,878)
Intangible assets, net	$ 170,772	$ 223,588

OTHER NON-CURRENT ASSETS (Detai

OTHER NON-CURRENT ASSETS (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Other Assets, Noncurrent Disclosure [Abstract]
Debt issuance costs	$ 2,216	$ 3,022
Insurance receivables related to environmental remediation reserves	2,057	2,794
BBH jetty-allision insurance receivable	0	7,372
Derivative assets	1,003	0
Other	35,862	38,295
Total other non-current assets	$ 41,138	$ 51,483

ACCRUED AND OTHER CURRENT LIA_3

ACCRUED AND OTHER CURRENT LIABILITIES (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Accrued Liabilities and Other Liabilities [Abstract]
Taxes - other than income	$ 29,644	$ 33,327
Accrued employee benefit liabilities	6,220	7,228
Accrued environmental remediation liabilities	11,658	9,242
Interest payable	58,360	57,164
Unearned revenue	31,593	34,734
Employee compensation related accruals	27,602	32,616
Accrued capital expenditures	59,128	48,690
ARO	0	1,255
Other	51,988	40,951
Total accrued and other current liabilities	$ 276,193	$ 265,207

LONG-TERM DEBT - Schedule of Lo

LONG-TERM DEBT - Schedule of Long-term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Debt instrument
Notes payable, gross	$ 4,747,328
Unamortized discounts & debt issuance costs	(32,886)	$ (33,379)
Total debt	4,714,442	4,910,525
Less: Current portion of long-term debt and line of credit	(702,727)	(252,204)
Long-term debt	4,011,715	4,658,321
6.050% Notes due January 15, 2018
Debt instrument
Notes payable, gross	$ 0	300,000
Debt instrument, stated percentage rate	6.05%
2.650% Notes due November 15, 2018
Debt instrument
Notes payable, gross	$ 0	400,000
Debt instrument, stated percentage rate	2.65%
5.500% Notes due August 15, 2019
Debt instrument
Notes payable, gross	$ 275,000	275,000
Debt instrument, stated percentage rate	5.50%
4.875% Notes due February 1, 2021
Debt instrument
Notes payable, gross	$ 650,000	650,000
Debt instrument, stated percentage rate	4.875%
4.150% Notes due July 1, 2023
Debt instrument
Notes payable, gross	$ 500,000	500,000
Debt instrument, stated percentage rate	4.15%
4.350% Notes due October 15, 2024
Debt instrument
Notes payable, gross	$ 300,000	300,000
Debt instrument, stated percentage rate	4.35%
3.950% Notes due December 1, 2026
Debt instrument
Notes payable, gross	$ 600,000	600,000
Debt instrument, stated percentage rate	3.95%
4.125% Notes due December 1, 2027
Debt instrument
Notes payable, gross	$ 400,000	400,000
Debt instrument, stated percentage rate	4.125%
6.750% Notes due August 15, 2033
Debt instrument
Notes payable, gross	$ 150,000	150,000
Debt instrument, stated percentage rate	6.75%
5.850% Notes due November 15, 2043
Debt instrument
Notes payable, gross	$ 400,000	400,000
Debt instrument, stated percentage rate	5.85%
5.600% Notes due October 15, 2044
Debt instrument
Notes payable, gross	$ 300,000	300,000
Debt instrument, stated percentage rate	5.60%
6.375 % Junior Notes due January 22, 2078
Debt instrument
Notes payable, gross	$ 400,000	0
Debt instrument, stated percentage rate	6.375%
Term Loan due September 30, 2019 (2)
Debt instrument
Notes payable, gross	$ 250,000	250,000
Credit Facility due September 30, 2021
Debt instrument
Notes payable, gross	$ 522,328	$ 418,904

LONG-TERM DEBT - Scheduled Matu

LONG-TERM DEBT - Scheduled Maturities of Principal (Details) $ in Thousands	Dec. 31, 2018USD ($)
Debt Disclosure [Abstract]
2,019	$ 702,727
2,020	0
2,021	994,601
2,022	0
2,023	500,000
Thereafter	2,550,000
Total	$ 4,747,328

LONG-TERM DEBT - Narrative (Det

LONG-TERM DEBT - Narrative (Details)

Dec. 17, 2018USD ($)

Jan. 31, 2019USD ($)

Nov. 30, 2018USD ($)

Jan. 31, 2018USD ($)

Nov. 30, 2017USD ($)

Jul. 31, 2017USD ($)

Nov. 30, 2016USD ($)

Sep. 30, 2016USD ($)extension

Dec. 31, 2018USD ($)

Dec. 31, 2017USD ($)

Dec. 31, 2016

Sep. 29, 2016USD ($)

Debt instrument

Weighted average interest rate

4.60%

4.50%

4.60%

Notes payable

$ 4,747,328,000

Credit Facility

Debt instrument

Amount outstanding under the credit facility

$ 522,300,000

Number of preceding months used to calculate consolidated EBITDA for debt covenants

12 months

Maximum funded debt ratio

5

Maximum funded debt ratio subject to certain future acquisitions

5.5

Actual funded debt ratio

4.14

Amount committed in support of letters of credit

$ 3,100,000

$ 2,400,000

Credit Facility | LIBOR rate | Minimum

Debt instrument

Applicable margin on variable interest rate basis

1.00%

Credit Facility | LIBOR rate | Maximum

Debt instrument

Applicable margin on variable interest rate basis

1.75%

Credit Facility | Base rate | Minimum

Debt instrument

Applicable margin on variable interest rate basis

0.00%

Credit Facility | Base rate | Maximum

Debt instrument

Applicable margin on variable interest rate basis

0.75%

3.950% Notes due December 1, 2026

Debt instrument

Debt instrument, stated percentage rate

3.95%

Notes payable

$ 600,000,000

600,000,000

4.125% Notes due December 1, 2027

Debt instrument

Debt instrument, stated percentage rate

4.125%

Notes payable

$ 400,000,000

400,000,000

5.125% Notes due July 1, 2017

Debt instrument

Debt instrument, stated percentage rate

5.125%

Repayment of notes

$ 125,000,000

Repayment of interest payable

$ (3,200,000)

6.050% Notes

Debt instrument

Debt instrument, stated percentage rate

6.05%

Repayment of notes

$ 300,000,000

Repayment of interest payable

(9,100,000)

2.650% Notes

Debt instrument

Debt instrument, stated percentage rate

2.65%

Repayment of notes

$ 400,000,000

Repayment of interest payable

$ (5,300,000)

Term Loan due September 30, 2019 (2)

Debt instrument

Notes payable

$ 250,000,000

250,000,000

5.500% Notes due August 15, 2019

Debt instrument

Debt instrument, stated percentage rate

5.50%

Notes payable

$ 275,000,000

$ 275,000,000

Revolving Credit Facility

Debt instrument

Weighted average interest rate

3.80%

Line of Credit | Credit Facility

Debt instrument

Maximum borrowing capacity

$ 1,500,000,000

Line of Credit | Revolving Credit Facility

Debt instrument

Maximum borrowing capacity extension amount

$ 1,400,000,000

Maximum borrowing capacity

$ 1,500,000,000

Extension term

1 year

Available borrowing capacity

974,600,000

Line of Credit | Revolving Credit Facility | Unextended Tranche

Debt instrument

Maximum borrowing capacity

$ 90,000,000

Line of Credit | Prior Revolving Credit Facility

Debt instrument

Maximum borrowing capacity

$ 1,500,000,000

Line of Credit | Term Loan

Debt instrument

Maximum borrowing capacity

$ 250,000,000

Extension term

1 year

Number of extension periods | extension

2

Line of Credit | Term Loan | LIBOR rate | Minimum

Debt instrument

Applicable margin on variable interest rate basis

1.00%

Line of Credit | Term Loan | LIBOR rate | Maximum

Debt instrument

Applicable margin on variable interest rate basis

1.60%

Line of Credit | Term Loan | Base rate | Minimum

Debt instrument

Applicable margin on variable interest rate basis

0.00%

Line of Credit | Term Loan | Base rate | Maximum

Debt instrument

Applicable margin on variable interest rate basis

0.60%

Unsecured Debt | 3.950% Notes due December 1, 2026

Debt instrument

Notes issued

$ 600,000,000

Debt instrument, stated percentage rate

3.95%

Proceeds from issuance of debt

$ 592,700,000

Redemption price percentage

99.644%

Unsecured Debt | 4.125% Notes due December 1, 2027

Debt instrument

Notes issued

$ 400,000,000

Debt instrument, stated percentage rate

4.125%

Proceeds from issuance of debt

$ 394,400,000

Redemption price percentage

99.503%

Junior subordinated debt

Debt instrument

Notes issued

$ 400,000,000

Debt instrument, stated percentage rate

6.375%

Proceeds from issuance of debt

$ 394,900,000

Junior subordinated debt | LIBOR rate

Debt instrument

Applicable margin on variable interest rate basis

4.02%

DPTS Asset Package | Disposed of by Sale

Debt instrument

Proceeds from sale of assets

$ 454,600,000

$ 444,600,000

Transaction costs

$ 7,700,000

VTTI B.V. | Disposed of by Sale

Debt instrument

Percentage of equity interest sold

50.00%

Proceeds from sale of equity interest

$ 975,000,000

Transaction costs

$ 8,000,000

Subsequent event | VTTI B.V. | Disposed of by Sale

Debt instrument

Percentage of equity interest sold

50.00%

Proceeds from sale of equity interest

$ 975,000,000

Transaction costs

$ 8,000,000

OTHER NON-CURRENT LIABILITIES_2

OTHER NON-CURRENT LIABILITIES (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Other Liabilities, Noncurrent [Abstract]
Accrued employee benefit liabilities	$ 28,246	$ 31,969
Accrued environmental remediation liabilities	27,358	31,803
Deferred consideration	20,232	19,640
ARO	4,349	3,833
Other	4,715	5,411
Total other non-current liabilities	$ 84,900	$ 92,656

ACCUMULATED OTHER COMPREHENSI_3

ACCUMULATED OTHER COMPREHENSIVE (LOSS) INCOME (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
Unrealized (losses) gains on derivative instruments	$ (490)	$ 29,530
Net loss on settlement of interest rate swaps, net of amortization	(38,699)	(47,924)
Unrecognized loss on benefit plans	(872)	(2,617)
Other comprehensive income from equity method investments	0	49,642
Total accumulated other comprehensive (loss) income	$ (40,061)	$ 28,631

DERIVATIVE INSTRUMENTS AND HE_3

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Narrative (Details)	12 Months Ended
	Dec. 31, 2018USD ($)	Dec. 31, 2016USD ($)instrument	Nov. 30, 2017USD ($)
Derivative Instruments And Hedging Activities
AOCI reclassified into earnings	$ 51,000,000
4.125% Notes
Derivative Instruments And Hedging Activities
Debt instrument, stated percentage rate	4.125%
Unsecured Debt | 4.125% Notes
Derivative Instruments And Hedging Activities
Notes issued			$ 400,000,000
Debt instrument, stated percentage rate			4.125%
Interest Rate Swap Entered Into In Anticipation of Debt Due January 2018
Derivative Instruments And Hedging Activities
Number of derivative contracts | instrument		7
Notional amount		$ 350,000,000
Derivatives settled		$ 20,000,000
Interest Rate Swap Entered Into In Anticipation of Debt Due November 2018
Derivative Instruments And Hedging Activities
Number of derivative contracts | instrument		11
Notional amount		$ 500,000,000
Future contracts | Cash Flow Hedge
Derivative Instruments And Hedging Activities
Futures contracts for refined products	$ (2,000,000)
Interest rate contracts
Derivative Instruments And Hedging Activities
Hedges to be reclassified within the next twelve months	9,200,000
Settled forward-starting interest rate swaps
Derivative Instruments And Hedging Activities
Hedges to be reclassified within the next twelve months	11,200,000
Forward-starting interest rate swaps
Derivative Instruments And Hedging Activities
Hedges to be reclassified within the next twelve months	$ (2,000,000)

DERIVATIVE INSTRUMENTS AND HE_4

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Commodity Derivative Instruments Outstanding (Details) gal in Thousands	12 Months Ended
	Dec. 31, 2018gal
Derivatives NOT Designated as Hedging Instruments | Current Derivative Contract | Physical fixed price derivative contracts
Derivative Instruments And Hedging Activities
Volume (in gallons)	23,119
Derivatives NOT Designated as Hedging Instruments | Current Derivative Contract | Physical index derivative contracts
Derivative Instruments And Hedging Activities
Volume (in gallons)	52,912
Derivatives NOT Designated as Hedging Instruments | Current Derivative Contract | Futures contracts for refined petroleum products
Derivative Instruments And Hedging Activities
Volume (in gallons)	29,771
Derivatives NOT Designated as Hedging Instruments | Long-term Derivative Contract | Physical fixed price derivative contracts
Derivative Instruments And Hedging Activities
Volume (in gallons)	4,765
Derivatives NOT Designated as Hedging Instruments | Long-term Derivative Contract | Physical index derivative contracts
Derivative Instruments And Hedging Activities
Volume (in gallons)	0
Derivatives NOT Designated as Hedging Instruments | Long-term Derivative Contract | Futures contracts for refined petroleum products
Derivative Instruments And Hedging Activities
Volume (in gallons)	9,996
Derivatives Designated as Hedging Instruments | Current Derivative Contract | Futures contracts for refined petroleum products | Fair Value Hedge
Derivative Instruments And Hedging Activities
Volume (in gallons)	107,184
Derivatives Designated as Hedging Instruments | Long-term Derivative Contract | Futures contracts for refined petroleum products | Fair Value Hedge
Derivative Instruments And Hedging Activities
Volume (in gallons)	420

DERIVATIVE INSTRUMENTS AND HE_5

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Fair Value of Each Classification of Derivative Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Derivatives, Fair Value
Fair value	$ 17,699	$ 27,787
Netting Balance Sheet Adjustment	0	0
Total
Derivatives, Fair Value
Fair value	17,699	27,787
Derivatives NOT Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	17,699	(4,207)
Derivatives Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	0	31,994
Total current derivative assets
Derivatives, Fair Value
Fair value	18,220	35,031
Netting Balance Sheet Adjustment	(201)	(72)
Total current derivative assets | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	17,934	2,582
Netting Balance Sheet Adjustment	(84)	(63)
Total current derivative assets | Physical index derivative contracts
Derivatives, Fair Value
Fair value	286	455
Netting Balance Sheet Adjustment	(117)	(9)
Total current derivative assets | Interest rate derivatives
Derivatives, Fair Value
Fair value		31,994
Netting Balance Sheet Adjustment		0
Total current derivative assets | Total
Derivatives, Fair Value
Fair value	18,019	34,959
Total current derivative assets | Total | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	17,850	2,519
Total current derivative assets | Total | Physical index derivative contracts
Derivatives, Fair Value
Fair value	169	446
Total current derivative assets | Total | Interest rate derivatives
Derivatives, Fair Value
Fair value		31,994
Total current derivative assets | Derivatives NOT Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	18,220	3,037
Total current derivative assets | Derivatives NOT Designated as Hedging Instruments | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	17,934	2,582
Total current derivative assets | Derivatives NOT Designated as Hedging Instruments | Physical index derivative contracts
Derivatives, Fair Value
Fair value	286	455
Total current derivative assets | Derivatives NOT Designated as Hedging Instruments | Interest rate derivatives
Derivatives, Fair Value
Fair value		0
Total current derivative assets | Derivatives Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	0	31,994
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 | Interest rate derivatives
Derivatives, Fair Value
Fair value		31,994
Total non-current derivative assets
Derivatives, Fair Value
Fair value	1,003	0
Netting Balance Sheet Adjustment	0	0
Total non-current derivative assets | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	1,003
Netting Balance Sheet Adjustment	0
Total non-current derivative assets | Total
Derivatives, Fair Value
Fair value	1,003	0
Total non-current derivative assets | Total | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	1,003
Total non-current derivative assets | Derivatives NOT Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	1,003	0
Total non-current derivative assets | Derivatives NOT Designated as Hedging Instruments | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	1,003
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
Total current derivative liabilities
Derivatives, Fair Value
Fair value	(1,521)	(7,244)
Netting Balance Sheet Adjustment	201	72
Total current derivative liabilities | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	(1,386)	(7,226)
Netting Balance Sheet Adjustment	84	63
Total current derivative liabilities | Physical index derivative contracts
Derivatives, Fair Value
Fair value	(135)	(18)
Netting Balance Sheet Adjustment	117	9
Total current derivative liabilities | Total
Derivatives, Fair Value
Fair value	(1,320)	(7,172)
Total current derivative liabilities | Total | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	(1,302)	(7,163)
Total current derivative liabilities | Total | Physical index derivative contracts
Derivatives, Fair Value
Fair value	(18)	(9)
Total current derivative liabilities | Derivatives NOT Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	(1,521)	(7,244)
Total current derivative liabilities | Derivatives NOT Designated as Hedging Instruments | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	(1,386)	(7,226)
Total current derivative liabilities | Derivatives NOT Designated as Hedging Instruments | Physical index derivative contracts
Derivatives, Fair Value
Fair value	(135)	(18)
Total current derivative liabilities | Derivatives Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	0	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 non-current derivative liabilities
Derivatives, Fair Value
Fair value	(3)	0
Netting Balance Sheet Adjustment	0	0
Total non-current derivative liabilities | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	(3)
Netting Balance Sheet Adjustment	0
Total non-current derivative liabilities | Total
Derivatives, Fair Value
Fair value	(3)	0
Total non-current derivative liabilities | Total | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	(3)
Total non-current derivative liabilities | Derivatives NOT Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	(3)	0
Total non-current derivative liabilities | Derivatives NOT Designated as Hedging Instruments | Physical fixed price derivative contracts
Derivatives, Fair Value
Fair value	(3)
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

DERIVATIVE INSTRUMENTS AND HE_6

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Gains and Losses of Derivative Instruments Recognized in Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Hedge Ineffectiveness
Ineffectiveness excluding the time value component on fair value hedging instruments:
Net (loss) gain for ineffectiveness in income	$ (3,739)	$ 9,654
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	22,046	(6,748)
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	440	82
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	(1,777)	3,937
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	(81)	1,147
Derivatives NOT Designated as Hedging Instruments | Cost of product sales | Futures contracts for refined petroleum products
Derivatives NOT designated as hedging instruments:
Gains (losses) on derivative instruments recognized in income	7,661	13,710
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)	1,335	(4,673)
Time value excluded from hedge assessment	(5,074)	14,327
Derivatives Designated as Hedging Instruments | Cost of product sales | Futures contracts for refined petroleum products
Derivatives designated as fair value hedging instruments:
Futures contracts for refined products	42,658	(22,362)
Derivatives Designated as Hedging Instruments | Cost of product sales | Physical inventory - hedged items
Derivatives designated as fair value hedging instruments:
Physical inventory - hedged items	$ (46,397)	$ 32,016

DERIVATIVE INSTRUMENTS AND HE_7

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Changes in Value Recognized in OCI (Details) - Cash Flow Hedge - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Losses reclassified from AOCI to income
Gain (Loss) recognized in OCI on derivatives	$ 29,714	$ (10,733)
Gain (Loss) reclassified from AOCI to income	50,509	(11,922)
Interest rate contracts
Losses reclassified from AOCI to income
Gain (Loss) recognized in OCI on derivatives	27,739	(10,597)
Interest rate contracts | Interest and debt expense
Losses reclassified from AOCI to income
Gain (Loss) reclassified from AOCI to income	50,509	(11,922)
Commodity derivatives
Losses reclassified from AOCI to income
Gain (Loss) recognized in OCI on derivatives	$ 1,975	$ (136)

FAIR VALUE MEASUREMENTS - Finan

FAIR VALUE MEASUREMENTS - Financial Assets and Liability Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Fair value measurements
Fair value	$ 17,699	$ 27,787
Fair Value, Measurements, Recurring | Level 1
Fair value measurements
Fair value	0	0
Fair Value, Measurements, Recurring | Level 1 | Physical fixed price derivative contracts
Fair value measurements
Financial assets	0	0
Financial liabilities	0	0
Fair Value, Measurements, Recurring | Level 1 | Physical index derivative contracts
Fair value measurements
Financial assets	0	0
Financial liabilities	0	0
Fair Value, Measurements, Recurring | Level 1 | Interest rate derivatives
Fair value measurements
Financial assets	0	0
Fair Value, Measurements, Recurring | Level 1 | Futures contracts for refined petroleum products
Fair value measurements
Financial liabilities	0	0
Fair Value, Measurements, Recurring | Level 2
Fair value measurements
Fair value	17,699	27,787
Fair Value, Measurements, Recurring | Level 2 | Physical fixed price derivative contracts
Fair value measurements
Financial assets	18,937	2,582
Financial liabilities	(1,389)	(7,226)
Fair Value, Measurements, Recurring | Level 2 | Physical index derivative contracts
Fair value measurements
Financial assets	286	455
Financial liabilities	(135)	(18)
Fair Value, Measurements, Recurring | Level 2 | Interest rate derivatives
Fair value measurements
Financial assets	0	31,994
Fair Value, Measurements, Recurring | Level 2 | Futures contracts for refined petroleum products
Fair value measurements
Financial liabilities	$ 0	$ 0

FAIR VALUE MEASUREMENTS - Carry

FAIR VALUE MEASUREMENTS - Carrying Value and Fair Value of Debt (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Fair Value And Carrying Value By Balance Sheet Grouping
Impairments of equity investments	$ 300,300,000	$ 0	$ 0
Goodwill impairment	536,964,000	0	$ 0
Carrying Amount | Level 2
Fair Value And Carrying Value By Balance Sheet Grouping
Total debt	4,714,442,000	4,910,525,000
Carrying Amount | Level 2 | Fixed-rate debt
Fair Value And Carrying Value By Balance Sheet Grouping
Total debt	3,546,396,000	4,241,963,000
Carrying Amount | Level 2 | Variable-rate debt
Fair Value And Carrying Value By Balance Sheet Grouping
Total debt	1,168,046,000	668,562,000
Fair Value | Level 2
Fair Value And Carrying Value By Balance Sheet Grouping
Total debt	4,536,877,000	5,053,240,000
Fair Value | Level 2 | Fixed-rate debt
Fair Value And Carrying Value By Balance Sheet Grouping
Total debt	3,364,549,000	4,384,336,000
Fair Value | Level 2 | Variable-rate debt
Fair Value And Carrying Value By Balance Sheet Grouping
Total debt	1,172,328,000	$ 668,904,000
GMT Caribbean and NYH
Fair Value And Carrying Value By Balance Sheet Grouping
Goodwill impairment	$ 536,964,000

PENSIONS AND OTHER POSTRETIRE_3

PENSIONS AND OTHER POSTRETIREMENT BENEFITS - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)itemcoal_mine	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Expected employer contributions to benefit plans in 2019	$ 3.2
Certain wholly owned subsidiaries including BORCO
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total costs of providing benefits	$ 1.5	$ 2.1	$ 1.4
Services company
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Number of components | item	2
First component of RASP, percentage of eligible employee's covered salary	5.00%
Second component of RASP, percentage of employer's matching contribution	100.00%
Second component of RASP, percentage of eligible employee's covered salary (up to)	5.00%
Second component of RASP, percentage of gross pay of employees with specified service period for which employer contributes a matching contribution (up to)	6.00%
Second component of RASP, minimum service period required for employer's specified matching contribution	20 years
Total costs of RASP	$ 18	17.6	16.4
Total costs of providing benefits	$ 1.4	$ 1.4	$ 1.4
RIGP
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Consecutive service period before retirement used in calculation of employee's highest compensation	5 years
Service period before retirement considered for calculation of employee's highest compensation	10 years
RIGP | Coal lease
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Ownership interest percentage in coal lease	20.80%
Number of coal reserve mines | coal_mine	2
Retiree Medical Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Assumed annual increase in health care cost trend rate for 2019 (as a percent)	6.50%
Ultimate health care cost trend rate in 2025 and thereafter (as a percent)	4.50%

PENSIONS AND OTHER POSTRETIRE_4

PENSIONS AND OTHER POSTRETIREMENT BENEFITS - Projected Benefit Obligations and Plan Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
RIGP
Change in benefit obligation:
Benefit obligation at beginning of year	$ 9,847	$ 13,178
Service cost	(84)	(58)	$ (34)
Interest cost	293	333	421
Plan participants’ contributions	0	0
Actuarial (gain) loss	(270)	(1,524)
Settlements	(2,127)	(1,900)
Benefit payments	(206)	(182)
Substantive provision change	0	0
Benefit obligation at end of year	7,453	9,847	13,178
Change in plan assets:
Fair value of plan assets at beginning of year	4,484	4,524
Actual return on plan assets	221	452
Plan participants’ contributions	0	0
Employer contributions	1,047	1,590
Settlements	(2,127)	(1,900)
Benefit payments	(206)	(182)
Fair value of plan assets at end of year	3,419	4,484	4,524
Funded status at end of year	(4,034)	(5,363)
Retiree Medical Plan
Change in benefit obligation:
Benefit obligation at beginning of year	29,363	31,958
Service cost	199	287	323
Interest cost	1,029	1,209	1,309
Plan participants’ contributions	533	481
Actuarial (gain) loss	(1,531)	689
Settlements	0	0
Benefit payments	(2,573)	(3,074)
Substantive provision change	0	(2,187)
Benefit obligation at end of year	27,020	29,363	31,958
Change in plan assets:
Fair value of plan assets at beginning of year	0	0
Actual return on plan assets	0	0
Plan participants’ contributions	533	481
Employer contributions	2,040	2,593
Settlements	0	0
Benefit payments	(2,573)	(3,074)
Fair value of plan assets at end of year	0	0	$ 0
Funded status at end of year	$ (27,020)	$ (29,363)

PENSIONS AND OTHER POSTRETIRE_5

PENSIONS AND OTHER POSTRETIREMENT BENEFITS - Schedules Related to RIGP and Retiree Medical Plan (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
AOCI:
Total	$ 872	$ 2,617
RIGP
Liabilities:
Accrued employee benefit liabilities - current	0	0
Accrued employee benefit liabilities - noncurrent	(4,034)	(5,363)
Total	(4,034)	(5,363)
AOCI:
Prior service credit	0	0
Net actuarial loss	310	722
Total	310	722
Accumulated benefit obligation in excess of plan assets
Projected benefit obligation	7,453	9,847
Accumulated benefit obligation	7,177	9,128
Fair value of plan assets	$ 3,419	$ 4,484
Weighted average assumptions used in determining net periodic benefit cost for the Plans
Discount rate	3.30%	3.20%	3.00%
Expected return on plan assets	4.00%	5.80%	5.80%
Rate of compensation increase	2.00%	3.00%	3.00%
Assumptions used in determining benefit obligations for the Plans
Discount rate	4.30%	3.30%
Rate of compensation increase	3.00%	3.00%
Retiree Medical Plan
Liabilities:
Accrued employee benefit liabilities - current	$ (2,808)	$ (2,757)
Accrued employee benefit liabilities - noncurrent	(24,212)	(26,606)
Total	(27,020)	(29,363)
AOCI:
Prior service credit	(1,727)	(2,187)
Net actuarial loss	2,289	4,082
Total	$ 562	$ 1,895
Weighted average assumptions used in determining net periodic benefit cost for the Plans
Discount rate	3.60%	4.00%	4.10%
Rate of compensation increase	2.00%	3.00%	3.00%
Assumptions used in determining benefit obligations for the Plans
Discount rate	4.40%	3.60%
Rate of compensation increase	3.00%	3.00%

PENSIONS AND OTHER POSTRETIRE_6

PENSIONS AND OTHER POSTRETIREMENT BENEFITS - Components of Net Periodic Benefit Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
RIGP
Components of net periodic benefit cost:
Service cost	$ (84)	$ (58)	$ (34)
Interest cost	293	333	421
Expected return on plan assets	(168)	(251)	(256)
Amortization of prior service credit	0	0	0
Actuarial loss due to settlements	88	150	598
Amortization of unrecognized loss	0	19	522
Net periodic benefit cost	129	193	1,251
Other changes in plan assets and benefit obligations recognized in OCI:
Prior service credit	0	0	0
Net actuarial (gain) loss	(324)	(1,725)	(2,068)
Amortization of unrecognized loss	0	(19)	(522)
Actuarial loss due to settlements	(88)	(150)	(598)
Amortization of prior service credit	0	0	0
Total recognized in OCI	(412)	(1,894)	(3,188)
Total recognized in net period benefit cost and OCI	(283)	(1,701)	(1,937)
Prior service credit	0
Estimated benefit payments
2,019	2,081,000
2,020	674,000
2,021	847,000
2,022	735,000
2,023	653,000
Thereafter	1,520,000
Retiree Medical Plan
Components of net periodic benefit cost:
Service cost	199	287	323
Interest cost	1,029	1,209	1,309
Expected return on plan assets	0	0	0
Amortization of prior service credit	(461)	0	0
Actuarial loss due to settlements	0	0	0
Amortization of unrecognized loss	263	0	766
Net periodic benefit cost	1,030	1,496	2,398
Other changes in plan assets and benefit obligations recognized in OCI:
Prior service credit	0	(2,187)	0
Net actuarial (gain) loss	(1,531)	688	2,871
Amortization of unrecognized loss	(263)	0	(766)
Actuarial loss due to settlements	0	0	0
Amortization of prior service credit	461	0	0
Total recognized in OCI	(1,333)	(1,499)	2,105
Total recognized in net period benefit cost and OCI	(303)	$ (3)	$ 4,503
Prior service credit	(461)
Estimated benefit payments
2,019	2,870,000
2,020	2,718,000
2,021	2,581,000
2,022	2,503,000
2,023	2,473,000
Thereafter	$ 9,151,000

PENSIONS AND OTHER POSTRETIRE_7

PENSIONS AND OTHER POSTRETIREMENT BENEFITS - Summary of Investments in the RIGP (Details) - RIGP - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension and other postretirement benefits
Fair value of plan assets	$ 3,419	$ 4,484	$ 4,524
Level 1
Pension and other postretirement benefits
Fair value of plan assets	1,681	2,676
Level 3
Pension and other postretirement benefits
Fair value of plan assets	1,738	1,808	$ 2,007
Mutual fund - fixed-income securities | Level 1
Pension and other postretirement benefits
Fair value of plan assets	1,576	2,454
Mutual fund - fixed-income securities | Level 3
Pension and other postretirement benefits
Fair value of plan assets	0	0
Mutual fund - money market | Level 1
Pension and other postretirement benefits
Fair value of plan assets	105	222
Mutual fund - money market | Level 3
Pension and other postretirement benefits
Fair value of plan assets	0	0
Coal lease | Level 1
Pension and other postretirement benefits
Fair value of plan assets	0	0
Coal lease | Level 3
Pension and other postretirement benefits
Fair value of plan assets	$ 1,738	$ 1,808

PENSIONS AND OTHER POSTRETIRE_8

PENSIONS AND OTHER POSTRETIREMENT BENEFITS - Summary of Activity in Level 3 Pension Assets (Details) - RIGP - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Activity in Level 3 pension assets
Fair value of plan assets at beginning of year	$ 4,484	$ 4,524
Unrealized loss	221	452
Fair value of plan assets at end of year	3,419	4,484
Level 3
Activity in Level 3 pension assets
Fair value of plan assets at beginning of year	1,808	2,007
Royalty payments received	400	380
Unrealized loss	(70)	(199)
Transfers out of Level 3	(400)	(380)
Fair value of plan assets at end of year	$ 1,738	$ 1,808

UNIT-BASED COMPENSATION PLANS -

UNIT-BASED COMPENSATION PLANS - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
LTIP and other plans
Share-based Compensation Arrangement by Share-based Payment Award
Compensation expense	$ 22.1	$ 30.6	$ 33.5
LTIP
Share-based Compensation Arrangement by Share-based Payment Award
LP Units, additional units available for issuance	2,115,169
Awards granted (in units)	748,000	547,000
Compensation expense not yet recognized	$ 27.5
Duration to recognize compensation expense not yet recognized	1 year 5 months 27 days
LTIP | Phantom Stock Units
Share-based Compensation Arrangement by Share-based Payment Award
Compensation expense not yet recognized	$ 4.3	$ 4.1
LTIP | Phantom Stock Units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award
Vesting period	1 year
LTIP | Phantom Stock Units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award
Vesting period	3 years
LTIP | Phantom Stock Units | Independent directors
Share-based Compensation Arrangement by Share-based Payment Award
Awards granted (in units)	18,000,000
LTIP | Performance Shares | Employee
Share-based Compensation Arrangement by Share-based Payment Award
Awards granted (in units)	274,688
Requisite service period	3 years
Deferral Plan | Employee | Maximum
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of compensation awards allowed to be deferred (up to)	50.00%	50.00%	50.00%
Deferral Plan | Phantom Stock Units
Share-based Compensation Arrangement by Share-based Payment Award
Awards granted (in units)	454,994
Deferral Plan | Phantom Stock Units | Employee
Share-based Compensation Arrangement by Share-based Payment Award
Number of equity instruments awarded for each deferral unit	1
Awards granted (in units)	149,726,000,000	145,138
Option Plan | Limited Partners
Share-based Compensation Arrangement by Share-based Payment Award
Vesting period	3 years

UNIT-BASED COMPENSATION PLANS_2

UNIT-BASED COMPENSATION PLANS - Schedule of LTIP Activity (Details) - LTIP - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Number of LP Units
Beginning Balance (in units)	1,450	1,296
Granted (in units)	748	547
Performance adjustment (in units)	39	32
Vested (in units)	(544)	(386)
Forfeited (in units)	(48)	(39)
Ending Balance (in units)	1,645	1,450
Weighted Average Grant Date Fair Value per LP Unit
Beginning Balance (in dollars per unit)	$ 64.04	$ 63.54
Granted (in dollars per unit)	48.16	69.91
Performance adjustment (in dollars per unit)	73.17	71.50
Vested (in dollars per unit)	68.84	70.98
Forfeited (in dollars per unit)	58.46	64.26
Ending Balance (in dollars per unit)	$ 55.52	$ 64.04

UNIT-BASED COMPENSATION PLANS_3

UNIT-BASED COMPENSATION PLANS - Unit Option and Distribution Equivalent Plan (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award
Fair value of options vested	$ 0	$ 0	$ 0
Option Plan | Limited Partners
Share-based Compensation Arrangement by Share-based Payment Award
Vesting period	3 years
Exercised (in units)	10
Exercised (in dollars per unit)	$ 50.36
Expiration period	10 years
Total intrinsic value of options exercised	$ 0	$ 200,000	$ 100,000

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details) - Services company - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Related party transaction
Distributions paid to related party	$ 2.4	$ 2.9	$ 3
Limited Partners
Related party transaction
LP Units owned by related party (in shares)	0.5
Percentage of LP Units owned	0.30%

PARTNERS' CAPITAL AND DISTRIB_3

PARTNERS' CAPITAL AND DISTRIBUTIONS - Narrative (Details) - USD ($)	Sep. 21, 2017	Mar. 30, 2018	Oct. 31, 2016	Mar. 31, 2016	Dec. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Sep. 30, 2018	Mar. 31, 2018
Limited Partners' Capital Account [Line Items]
Holding percentage					66.67%	66.67%
Issuance of Class C Units (in units)						6,221,000
Net proceeds from issuance of Units						$ 261,962,000	$ 346,276,000	$ 689,428,000
Limited Partners, units outstanding (in units)					153,755,031	153,755,031	146,677,459
Class C Unit
Limited Partners' Capital Account [Line Items]
Issuance of Class C Units (in units)		6,200,000				6,221,000
Units sold in private placement		$ 265,000,000
Net proceeds from issuance of Units		$ 262,000,000	$ 588,700,000
Offering costs										$ 3,000,000
Limited Partners, units outstanding (in units)									6,714,963
Limited Partners
Limited Partners' Capital Account [Line Items]
Cash distributions declared (in dollars per unit)					$ 0.75
Amount per unit of equity securities issued by non-development stage entity			$ 66.05
Underwriting fees and offering expenses			$ 8,000,000
Sale of units			$ 7,750,000
Limited Partners | Equity Distribution Agreements
Limited Partners' Capital Account [Line Items]
Net proceeds from issuance of Units							$ 345,800,000	$ 108,400,000
Authorized amount				$ 500,000,000
LP Units sold under equity distribution agreements							6,200,000	1,600,000
Aggregate compensation expense paid to the agents under the Equity Distribution Agreements							$ 1,900,000	$ 1,100,000
Over-Allotment Option | Limited Partners
Limited Partners' Capital Account [Line Items]
Sale of units (in units)			1,160,000
Limited Partners
Limited Partners' Capital Account [Line Items]
Issuance of Class C Units (in units)						0
Limited Partners | Equity Distribution Agreements
Limited Partners' Capital Account [Line Items]
Sale of units (in units)	3,800,000

PARTNERS' CAPITAL AND DISTRIB_4

PARTNERS' CAPITAL AND DISTRIBUTIONS - Summary of Changes in Outstanding Units (Details) - shares shares in Thousands	1 Months Ended	12 Months Ended
	Mar. 30, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Increase (Decrease) in Partners' Capital [Roll Forward]
Beginning Balance (in units)		146,677	140,264	129,524
Issuance of Class C Units (in units)		6,221
Issuance of Class C Units in lieu of quarterly cash distributions (in units)		494
Conversion of Class C Units to LP Units (in units)		0
Ending Balance (in units)		153,755	146,677	140,264
Institutional investors
Increase (Decrease) in Partners' Capital [Roll Forward]
LP Units issued (in units)				8,913
Equity Distribution Agreements
Increase (Decrease) in Partners' Capital [Roll Forward]
Issuance of units through equity distribution agreements (in units)			6,159	1,567
Option Plan
Increase (Decrease) in Partners' Capital [Roll Forward]
LP Units issued (in units)			10	6
LTIP
Increase (Decrease) in Partners' Capital [Roll Forward]
LP Units issued (in units)		363	244	254
Limited Partners
Increase (Decrease) in Partners' Capital [Roll Forward]
Beginning Balance (in units)		146,677	140,264	129,524
Issuance of Class C Units (in units)		0
Issuance of Class C Units in lieu of quarterly cash distributions (in units)		0
Conversion of Class C Units to LP Units (in units)		6,715
Ending Balance (in units)		153,755	146,677	140,264
Limited Partners | Institutional investors
Increase (Decrease) in Partners' Capital [Roll Forward]
LP Units issued (in units)				8,913
Limited Partners | Equity Distribution Agreements
Increase (Decrease) in Partners' Capital [Roll Forward]
Issuance of units through equity distribution agreements (in units)			6,159	1,567
Limited Partners | Option Plan
Increase (Decrease) in Partners' Capital [Roll Forward]
LP Units issued (in units)			10	6
Limited Partners | LTIP
Increase (Decrease) in Partners' Capital [Roll Forward]
LP Units issued (in units)		363	244	254
Class C Unit
Increase (Decrease) in Partners' Capital [Roll Forward]
Beginning Balance (in units)		0
Issuance of Class C Units (in units)	6,200	6,221
Issuance of Class C Units in lieu of quarterly cash distributions (in units)		494
Conversion of Class C Units to LP Units (in units)		(6,715)
Ending Balance (in units)		0	0
Class C Unit | LTIP
Increase (Decrease) in Partners' Capital [Roll Forward]
LP Units issued (in units)		0

PARTNERS' CAPITAL AND DISTRIB_5

PARTNERS' CAPITAL AND DISTRIBUTIONS - Distributions to Unitholders (Details) - USD ($) $ / shares in Units, $ in Thousands	Feb. 26, 2019	Feb. 08, 2019	Nov. 20, 2018	Aug. 13, 2018	May 21, 2018	Feb. 27, 2018	Nov. 20, 2017	Aug. 21, 2017	May 22, 2017	Feb. 28, 2017	Nov. 22, 2016	Aug. 22, 2016	May 23, 2016	Mar. 01, 2016	Dec. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Distributions to unitholders
Total cash distributions																$ 673,723	$ 714,495	$ 641,686
Limited Partners
Distributions to unitholders
Amount Per LP Unit (in dollars per unit)			$ 0.75	$ 1.2625	$ 1.2625	$ 1.2625	$ 1.2625	$ 1.2625	$ 1.25	$ 1.2375	$ 1.225	$ 1.2125	$ 1.2	$ 1.1875
Total cash distributions			$ 115,969	$ 186,624	$ 186,766	$ 186,764	$ 186,042	$ 179,631	$ 176,832	$ 174,888	$ 172,673	$ 159,881	$ 157,247	$ 154,928		$ 676,123	$ 717,393	$ 644,729
Cash distributions declared (in dollars per unit)															$ 0.75
Limited Partners | Forecast
Distributions to unitholders
Total cash distributions	$ 115,900
Limited Partners | Subsequent event
Distributions to unitholders
Cash distributions declared (in dollars per unit)		$ 0.75

INCOME TAXES - Narrative (Detai

INCOME TAXES - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Current income tax expense (benefit)	$ 2,603,000	$ 297,000	$ (276,000)
Deferred income tax expense	1,137,000	575,000	1,736,000
Total income tax expense	3,740,000	$ 872,000	$ 1,460,000
Unrecognized tax benefits	$ 0

INCOME TAXES - Tax Effect of Si

INCOME TAXES - Tax Effect of Significant Items Comprising Net Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Deferred tax asset:
Net operating loss carryforward	$ 18,757	$ 19,234
Capital loss carryforward	11,453	11,453
Other	2,452	2,697
Total deferred tax asset	32,662	33,384
Deferred tax liability:
Property, plant and equipment	1,132	1,536
Other	132	83
Total deferred tax liability	1,264	1,619
Net deferred tax asset	31,398	31,765
Less: Valuation allowance	(30,203)	(29,451)
Deferred taxes, net	$ 1,195	$ 2,314

(LOSS) EARNINGS PER UNIT (Detai

(LOSS) EARNINGS PER UNIT (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Earnings Per Share [Abstract]
Net (loss) income attributable to unitholders	$ (62,853)	$ 474,794	$ 535,608
Basic:
Weighted average units outstanding - basic (in units)	152,355,000	142,501,000	132,242,000
(Loss) earnings per unit - basic (in dollars per share)	$ (0.41)	$ 3.33	$ 4.05
Diluted:
Weighted average units outstanding - basic (in units)	152,355,000	142,501,000	132,242,000
Effect of dilutive securities (in units)	0	643,000	685,000
Weighted average units outstanding - diluted (in units)	152,355,000	143,144,000	132,927,000
(Loss) earnings per unit - diluted (in dollars per share)	$ (0.41)	$ 3.32	$ 4.03
Antidilutive securities	413,732

BUSINESS SEGMENTS - Narrative (

BUSINESS SEGMENTS - Narrative (Details)	12 Months Ended
	Dec. 31, 2018segmentterminalpropane_storage
Segment Reporting Information [Line Items]
Number of reportable segments | segment	3
Domestic Pipelines & Terminals
Segment Reporting Information [Line Items]
Number of liquid petroleum products terminals operated	3
Domestic Pipelines & Terminals | Indiana and Illinois
Segment Reporting Information [Line Items]
Number of underground propane storage caverns | propane_storage	2
Merchant Services
Segment Reporting Information [Line Items]
Number of liquid petroleum products terminals owned	3

BUSINESS SEGMENTS - Disaggregat

BUSINESS SEGMENTS - Disaggregated Revenue (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Revenue from contracts with customers									$ 3,367,487	$ 2,956,727	$ 2,601,447
Revenue from leases									209,660	198,801	191,874
Commodity derivative contracts, net									531,128	492,617	455,055
Total revenue	$ 1,074,783	$ 909,548	$ 940,839	$ 1,183,105	$ 946,052	$ 922,619	$ 810,201	$ 969,273	4,108,275	3,648,145	3,248,376
Domestic Pipelines & Terminals
Segment Reporting Information [Line Items]
Revenue from contracts with customers									986,506	997,161	968,832
Revenue from leases									37,684	38,504	42,084
Commodity derivative contracts, net									5,894	(2)	780
Total revenue									1,030,084	1,035,663	1,011,696
Global Marine Terminals
Segment Reporting Information [Line Items]
Revenue from contracts with customers									392,642	473,927	521,150
Revenue from leases									172,260	160,822	150,315
Commodity derivative contracts, net									0	0	0
Total revenue									564,902	634,749	671,465
Merchant Services
Segment Reporting Information [Line Items]
Revenue from contracts with customers									2,041,031	1,545,604	1,166,860
Revenue from leases									0	0	0
Commodity derivative contracts, net									531,128	492,617	455,055
Total revenue									2,572,159	2,038,221	1,621,915
Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenue from contracts with customers									(52,692)	(59,965)	(55,395)
Revenue from leases									(284)	(525)	(525)
Commodity derivative contracts, net									(5,894)	2	(780)
Total revenue									(58,870)	(60,488)	(56,700)
Pipeline transportation
Segment Reporting Information [Line Items]
Revenue from contracts with customers									492,125	481,326	462,506
Pipeline transportation | Domestic Pipelines & Terminals
Segment Reporting Information [Line Items]
Revenue from contracts with customers									503,781	498,974	480,730
Pipeline transportation | Global Marine Terminals
Segment Reporting Information [Line Items]
Revenue from contracts with customers									0	0	0
Pipeline transportation | Merchant Services
Segment Reporting Information [Line Items]
Revenue from contracts with customers									0	0	0
Pipeline transportation | Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenue from contracts with customers									(11,656)	(17,648)	(18,224)
Terminalling and storage services
Segment Reporting Information [Line Items]
Revenue from contracts with customers									786,849	885,370	939,088
Terminalling and storage services | Domestic Pipelines & Terminals
Segment Reporting Information [Line Items]
Revenue from contracts with customers									437,845	447,703	448,322
Terminalling and storage services | Global Marine Terminals
Segment Reporting Information [Line Items]
Revenue from contracts with customers									386,021	466,489	520,411
Terminalling and storage services | Merchant Services
Segment Reporting Information [Line Items]
Revenue from contracts with customers									0	0	0
Terminalling and storage services | Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenue from contracts with customers									(37,017)	(28,822)	(29,645)
Product sales
Segment Reporting Information [Line Items]
Revenue from contracts with customers									2,036,429	1,522,536	1,149,678
Product sales | Domestic Pipelines & Terminals
Segment Reporting Information [Line Items]
Revenue from contracts with customers									0	0	0
Product sales | Global Marine Terminals
Segment Reporting Information [Line Items]
Revenue from contracts with customers									5,412	3,891	304
Product sales | Merchant Services
Segment Reporting Information [Line Items]
Revenue from contracts with customers									2,033,646	1,531,433	1,155,276
Product sales | Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenue from contracts with customers									(2,629)	(12,788)	(5,902)
Other services
Segment Reporting Information [Line Items]
Revenue from contracts with customers									52,084	67,495	50,175
Other services | Domestic Pipelines & Terminals
Segment Reporting Information [Line Items]
Revenue from contracts with customers									44,880	50,484	39,780
Other services | Global Marine Terminals
Segment Reporting Information [Line Items]
Revenue from contracts with customers									1,209	3,547	435
Other services | Merchant Services
Segment Reporting Information [Line Items]
Revenue from contracts with customers									7,385	14,171	11,584
Other services | Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenue from contracts with customers									$ (1,390)	$ (707)	$ (1,624)

BUSINESS SEGMENTS - Schedule of

BUSINESS SEGMENTS - Schedule of Financial Information by Major Geographic Area (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Total revenue	$ 1,074,783	$ 909,548	$ 940,839	$ 1,183,105	$ 946,052	$ 922,619	$ 810,201	$ 969,273	$ 4,108,275	$ 3,648,145	$ 3,248,376
United States
Segment Reporting Information [Line Items]
Total revenue									3,868,364	3,361,160	2,915,619
International
Segment Reporting Information [Line Items]
Total revenue									$ 239,911	$ 286,985	$ 332,757

BUSINESS SEGMENTS - Summary of

BUSINESS SEGMENTS - Summary of Financial Information by Each Segment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Total earnings from equity investments	$ (274,123)	$ 36,005	$ 11,536
Total capital expenditures, net	467,611	433,335	486,316
Total assets	9,355,550	10,304,659
Tangible long-lived assets	6,914,796	6,735,792
Domestic Pipelines & Terminals | Operating Segments
Segment Reporting Information [Line Items]
Total earnings from equity investments	13,232	13,095	11,536
Total capital expenditures, net	311,335	250,454	294,849
Total assets	4,042,864	3,936,058
Global Marine Terminals | Tangible long-lived assets | International | Geographic concentration
Segment Reporting Information [Line Items]
Tangible long-lived assets	1,600,000	2,100,000
Global Marine Terminals | Operating Segments
Segment Reporting Information [Line Items]
Total earnings from equity investments	(287,355)	22,910	0
Total capital expenditures, net	156,258	182,267	191,422
Total assets	4,989,503	5,924,731
Merchant Services | Operating Segments
Segment Reporting Information [Line Items]
Total capital expenditures, net	18	614	$ 45
Total assets	$ 323,183	$ 443,870

BUSINESS SEGMENTS - Schedule _2

BUSINESS SEGMENTS - Schedule of Adjusted EBITDA by Segment on a Consolidated Basis (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Apr. 30, 2018	Jan. 31, 2017
Segment Reporting Information [Line Items]
Impairments of equity investments									$ 300,300,000	$ 0	$ 0
Reconciliation of Income from continuing operations to Adjusted EBITDA from continuing operations:
Net (loss) income	$ 483,012,000	$ (745,336,000)	$ 93,317,000	$ 117,092,000	$ 130,753,000	$ 120,224,000	$ 116,379,000	$ 126,309,000	(51,915,000)	493,665,000	548,675,000
Less: Net income attributable to noncontrolling interests									(7,123,000)	(14,863,000)	(13,067,000)
Net (loss) income attributable to Buckeye Partners, L.P.	$ 482,520,000	$ (745,835,000)	$ 91,904,000	$ 112,373,000	$ 126,317,000	$ 116,187,000	$ 112,722,000	$ 123,576,000	(59,038,000)	478,802,000	535,608,000
Add: Interest and debt expense									190,172,000	225,583,000	194,922,000
Income tax expense									3,740,000	872,000	1,460,000
Depreciation and amortization									269,423,000	269,243,000	254,659,000
Goodwill impairment									536,964,000	0	0
(Loss) earnings from equity investments									274,123,000	(36,005,000)	(11,536,000)
Gain on sale of ammonia pipeline									(342,984,000)	0	0
Adjusted EBITDA from continuing operations									$ 1,005,031,000	1,113,919,000	1,028,006,000
Buckeye Texas
Segment Reporting Information [Line Items]
Ownership percentage	100.00%								100.00%
Reconciliation of Income from continuing operations to Adjusted EBITDA from continuing operations:
Depreciation and amortization									$ 73,800,000	72,400,000	71,700,000
Domestic Pipelines & Terminals
Reconciliation of Income from continuing operations to Adjusted EBITDA from continuing operations:
Adjusted EBITDA from continuing operations									561,961,000	573,021,000	568,405,000
Global Marine Terminals
Reconciliation of Income from continuing operations to Adjusted EBITDA from continuing operations:
Adjusted EBITDA from continuing operations									428,663,000	512,821,000	427,229,000
Merchant Services
Reconciliation of Income from continuing operations to Adjusted EBITDA from continuing operations:
Adjusted EBITDA from continuing operations									14,407,000	28,077,000	32,372,000
Reconciling Items
Reconciliation of Income from continuing operations to Adjusted EBITDA from continuing operations:
Non-cash unit-based compensation expense									21,776,000	30,302,000	33,344,000
Acquisition and transition expense									11,321,000	4,226,000	8,196,000
Hurricane-related costs, net of recoveries									124,000	5,780,000	16,795,000
Proportionate share of Adjusted EBITDA for the equity method investment in VTTI (5)									101,435,000	126,642,000	0
Less: Amortization of unfavorable storage contracts									0	0	(5,979,000)
Gains on property damage recoveries									$ (14,535,000)	(4,621,000)	(5,700,000)
VTTI B.V.
Segment Reporting Information [Line Items]
Ownership percentage	50.00%								50.00%				50.00%
Reconciliation of Income from continuing operations to Adjusted EBITDA from continuing operations:
(Loss) earnings from equity investments									$ (286,633,000)	22,910,000	0
VTTI B.V. | Global Marine Terminals
Segment Reporting Information [Line Items]
Ownership percentage	50.00%								50.00%
Impairments of equity investments									$ 300,280,000	0	0
Reconciliation of Income from continuing operations to Adjusted EBITDA from continuing operations:
(Loss) earnings from equity investments									$ (13,651,000)	(22,910,000)	0
Buckeye Texas
Segment Reporting Information [Line Items]
Ownership percentage	100.00%								100.00%			100.00%
Buckeye Texas
Segment Reporting Information [Line Items]
Percentage of equity investment ownership acquired												20.00%
Ammonia pipeline | Reconciling Items
Reconciliation of Income from continuing operations to Adjusted EBITDA from continuing operations:
Gain on sale of ammonia pipeline									$ 0	0	(5,299,000)
DPTS asset package | Reconciling Items
Reconciliation of Income from continuing operations to Adjusted EBITDA from continuing operations:
Gain on sale of ammonia pipeline									$ (342,984,000)	$ 0	$ 0

SUPPLEMENTAL CASH FLOW INFORM_3

SUPPLEMENTAL CASH FLOW INFORMATION (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Supplemental Cash Flow Elements [Abstract]
AOCI reclassified into earnings	$ 51,000
Cash paid for interest (net of capitalized interest) (1)	224,371	$ 210,723	$ 174,555
Cash paid for income taxes	1,282	1,333	812
Capitalized interest	8,921	4,792	4,371
Proceeds from settlement of interest rate swap	50,982	0	0
Capital expenditures incurred but not yet paid	$ 85,300	$ 62,600	$ 59,100

QUARTERLY FINANCIAL DATA (UNA_3

QUARTERLY FINANCIAL DATA (UNAUDITED) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Revenue	$ 1,074,783	$ 909,548	$ 940,839	$ 1,183,105	$ 946,052	$ 922,619	$ 810,201	$ 969,273	$ 4,108,275	$ 3,648,145	$ 3,248,376
Operating (loss) income (1)	493,652	(391,831)	145,697	169,513	173,705	168,329	170,754	172,576	417,031	685,364	736,702
Net (loss) income	483,012	(745,336)	93,317	117,092	130,753	120,224	116,379	126,309	(51,915)	493,665	548,675
Net (loss) income attributable to Buckeye Partners, L.P.	$ 482,520	$ (745,835)	$ 91,904	$ 112,373	$ 126,317	$ 116,187	$ 112,722	$ 123,576	$ (59,038)	$ 478,802	$ 535,608
Earnings (loss) per unit - basic (in dollars per unit)	$ 3.14	$ (4.86)	$ 0.59	$ 0.75	$ 0.85	$ 0.82	$ 0.80	$ 0.88	$ (0.41)	$ 3.33	$ 4.05
Earnings (loss) per unit - diluted (in dollars per unit)	$ 3.13	$ (4.86)	$ 0.59	$ 0.74	$ 0.85	$ 0.81	$ 0.80	$ 0.88	$ (0.41)	$ 3.32	$ 4.03