BUCKEYE PARTNERS, L.P. - FORM 10-Q

Attached files

file	filename
EX-32.2 - EXHIBIT 32.2 - BUCKEYE PARTNERS, L.P.	exhibit322-bplq12018.htm
EX-32.1 - EXHIBIT 32.1 - BUCKEYE PARTNERS, L.P.	exhibit321-bplq12018.htm
EX-31.2 - EXHIBIT 31.2 - BUCKEYE PARTNERS, L.P.	exhibit312-bplq12018.htm
EX-31.1 - EXHIBIT 31.1 - BUCKEYE PARTNERS, L.P.	exhibit311-bplq12018.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2018

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

For the transition period from to

Commission file number 1-9356

Buckeye Partners, L.P.

(Exact name of registrant as specified in its charter)



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

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

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

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

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

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



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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

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

Limited partner units and Class C Units outstanding as of April 27, 2018: 146,936,380 and 6,220,658, respectively.

Table of Contents

TABLE OF CONTENTS



			Page
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2018 and 2017 (Unaudited)		1
	Condensed Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2018 and 2017 (Unaudited)		2
	Condensed Consolidated Balance Sheets as of March 31, 2018 and December 31, 2017 (Unaudited)		3
	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2018 and 2017 (Unaudited)		4
	Condensed Consolidated Statements of Partners’ Capital for the Three Months Ended March 31, 2018 and 2017 (Unaudited)		5
	Notes to Unaudited Condensed Consolidated Financial Statements:
	1.	Organization and Basis of Presentation	6
	2.	Revenue from Contracts with Customers	9
	3.	Acquisitions	11
	4.	Commitments and Contingencies	12
	5.	Inventories	13
	6.	Prepaid and Other Current Assets	13
	7.	Equity Investments	13
	8.	Long-Term Debt	14
	9.	Derivative Instruments and Hedging Activities	14
	10.	Fair Value Measurements	18
	11.	Unit-Based Compensation Plans	19
	12.	Partners’ Capital and Distributions	20
	13.	Earnings Per Unit	22
	14.	Business Segments	22
	15.	Supplemental Cash Flow Information	26

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

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		37

Item 4.	Controls and Procedures		39

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings		39

Item 1A.	Risk Factors		39

Item 6.	Exhibits		40

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

BUCKEYE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit amounts)

(Unaudited)



	Three Months Ended March 31,
	2018			2017
Revenue:
Product sales	$	792,187		$	565,420
Transportation, storage and other services	390,918			403,853
Total revenue	1,183,105			969,273

Costs and expenses:
Cost of product sales	785,327			548,050
Operating expenses	154,868			161,422
Depreciation and amortization	64,138			65,488
General and administrative	23,289			21,737
Other, net	(14,030		)	—
Total costs and expenses	1,013,592			796,697
Operating income	169,513			172,576

Other income (expense):
Earnings from equity investments	7,489			10,358
Interest and debt expense	(59,105		)	(55,885		)
Other expense	(315		)	(518		)
Total other expense, net	(51,931		)	(46,045		)

Income before taxes	117,582			126,531
Income tax expense	(490		)	(222		)
Net income	117,092			126,309
Less: Net income attributable to noncontrolling interests	(4,719		)	(2,733		)
Net income attributable to Buckeye Partners, L.P.	$	112,373		$	123,576

Earnings per unit attributable to Buckeye Partners, L.P.:
Basic	$	0.75		$	0.88
Diluted	$	0.74		$	0.88

Weighted average units outstanding:
Basic	148,904			140,377
Diluted	149,532			140,998

See Notes to Unaudited Condensed Consolidated Financial Statements.

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BUCKEYE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)

(Unaudited)



	Three Months Ended March 31,
	2018			2017
Net income	$	117,092		$	126,309
Other comprehensive income:
Unrealized gains on derivative instruments, net	14,138			2,985
Reclassification of derivative losses to net income, net	2,337			3,038
Changes in benefit plan assets and benefit obligations	18			177
Other comprehensive income from equity method investments	13,963			2,891
Total other comprehensive income	30,456			9,091
Comprehensive income	147,548			135,400
Less: Comprehensive income attributable to noncontrolling interests	(4,719		)	(2,733		)
Comprehensive income attributable to Buckeye Partners, L.P.	$	142,829		$	132,667

See Notes to Unaudited Condensed Consolidated Financial Statements.

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BUCKEYE PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except unit amounts)

(Unaudited)



	March 31, 2018			December 31, 2017
Assets:
Current assets:
Cash and cash equivalents	$	6,607		$	2,180
Accounts receivable, net	255,554			270,648
Construction and pipeline relocation receivables	10,636			11,047
Inventories	158,193			301,425
Derivative assets	47,411			34,959
Prepaid and other current assets	41,595			36,339
Total current assets	519,996			656,598

Property, plant and equipment	8,046,476			7,928,240
Less: Accumulated depreciation	(1,240,246		)	(1,192,448		)
Property, plant and equipment, net	6,806,230			6,735,792

Equity investments	1,496,552			1,494,412
Goodwill	1,007,341			1,007,313

Intangible assets	615,086			615,086
Less: Accumulated amortization	(272,237		)	(256,025		)
Intangible assets, net	342,849			359,061

Other non-current assets	42,543			51,483
Total assets	$	10,215,511		$	10,304,659

Liabilities and partners’ capital:
Current liabilities:
Line of credit	$	115,200		$	252,204
Accounts payable	92,884			160,777
Derivative liabilities	5,232			7,172
Accrued and other current liabilities	232,872			265,207
Total current liabilities	446,188			685,360

Long-term debt	4,587,949			4,658,321
Other non-current liabilities	92,186			92,656
Total liabilities	5,126,323			5,436,337

Commitments and contingent liabilities (Note 4)	—			—


Buckeye Partners, L.P. capital:
Limited Partners (146,934,972 and 146,677,459 units outstanding as of March 31, 2018 and December 31, 2017, respectively)	4,487,030			4,562,306
Class C Units (6,220,658 and zero units outstanding as of March 31, 2018 and December 31, 2017, respectively)	263,631			—
Accumulated other comprehensive income	59,087			28,631
Total Buckeye Partners, L.P. capital	4,809,748			4,590,937
Noncontrolling interests	279,440			277,385
Total partners’ capital	5,089,188			4,868,322
Total liabilities and partners’ capital	$	10,215,511		$	10,304,659

See Notes to Unaudited Condensed Consolidated Financial Statements.

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BUCKEYE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)



	Three Months Ended March 31,
	2018			2017
Cash flows from operating activities:
Net income	$	117,092		$	126,309
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization	64,138			65,488
Amortization of debt issuance costs, discounts and terminated interest rate swaps	3,900			4,361
Non-cash unit-based compensation expense	8,764			8,715
Gain on asset impairments, disposals and recoveries, net	(13,982		)	—
Changes in fair value of derivatives, net	(233		)	(26,394		)
Earnings from equity investments	(7,489		)	(10,358		)
Distributions of earnings from equity investments	—			1,728
Other non-cash items	20			103
Change in assets and liabilities, net of amounts related to acquisitions:
Accounts receivable, net	14,267			30,722
Construction and pipeline relocation receivables	411			(4,464		)
Inventories	143,246			51,676
Prepaid and other current assets	(5,266		)	26,253
Accounts payable	(71,100		)	(53,814		)
Accrued and other current liabilities	(32,650		)	(24,412		)
Other non-current assets and liabilities	15,073			(2,869		)
Net cash provided by operating activities	236,191			193,044
Cash flows from investing activities:
Capital expenditures	(116,916		)	(98,252		)
Acquisition of equity investment	—			(1,150,000		)
Distributions from equity investments in excess of earnings	19,238			672
Acquisition working capital settlement	895			—
Proceeds from property disposals and recoveries	7,715			402
Net cash used in investing activities	(89,068		)	(1,247,178		)
Cash flows from financing activities:
Net proceeds from issuance of Units and exercise of Unit options	262,066			3,693
Payment of tax withholding on vesting of LTIP awards	(6,596		)	(8,175		)
Net proceeds from issuance of long-term debt	394,966			—
Repayment of long-term debt	(300,000		)	—
Borrowings under the BPL Credit Facility	612,600			597,290
Repayments under the BPL Credit Facility	(779,300		)	(255,077		)
Net (repayments) borrowings under the BMSC Credit Facility	(137,004		)	258,310
Contributions from noncontrolling interests	4,400			3,600
Distributions to noncontrolling interests	(7,759		)	(6,825		)
Distributions to unitholders	(186,069		)	(174,149		)
Net cash (used in) provided by financing activities	(142,696		)	418,667
Net increase (decrease) in cash and cash equivalents	4,427			(635,467		)
Cash and cash equivalents — Beginning of period	2,180			640,340
Cash and cash equivalents — End of period	$	6,607		$	4,873

See Notes to Unaudited Condensed Consolidated Financial Statements.

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BUCKEYE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(In thousands)

(Unaudited)



	Limited Partners			Class C Units		Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
Partners’ capital - January 1, 2018	$	4,562,306		$	—	$	28,631		277,385			$	4,868,322
Net income	110,808			1,565		—			4,719			117,092
Distributions paid to unitholders	(186,764		)	—		—			695			(186,069		)
Net proceeds from issuance of Units	—			262,066		—			—			262,066
Amortization of unit-based compensation awards	8,764			—		—			—			8,764
Payment of tax withholding on vesting of LTIP awards	(6,596		)	—		—			—			(6,596		)
Distributions paid to noncontrolling interests	—			—		—			(7,759		)	(7,759		)
Contributions from noncontrolling interests	—			—		—			4,400			4,400
Other comprehensive income	—			—		30,456			—			30,456
Accrual of distribution equivalent rights	(1,488		)	—		—			—			(1,488		)
Partners’ capital - March 31, 2018	$	4,487,030		$	263,631	$	59,087		$	279,440		$	5,089,188

Partners’ capital - January 1, 2017	$	4,437,316		$	—	$	(25,593	)	286,700			$	4,698,423
Net income	123,576			—		—			2,733			126,309
Distributions paid to unitholders	(174,886		)	—		—			737			(174,149		)
Net proceeds from issuance of LP Units	3,212			—		—			—			3,212
Amortization of unit-based compensation awards	8,715			—		—			—			8,715
Net proceeds from exercise of Unit options	481			—		—			—			481
Payment of tax withholding on vesting of LTIP awards	(8,175		)	—		—			—			(8,175		)
Distributions paid to noncontrolling interests	—			—		—			(6,825		)	(6,825		)
Contributions from noncontrolling interests	—			—		—			3,600			3,600
Other comprehensive income	—			—		9,091			—			9,091
Accrual of distribution equivalent rights	(1,193		)	—		—			—			(1,193		)
Other	(17		)	—		—			17			—
Partners’ capital - March 31, 2017	$	4,389,029		$	—	$	(16,502	)	$	286,962		$	4,659,489

See Notes to Unaudited Condensed Consolidated Financial Statements.

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND BASIS OF PRESENTATION

Organization

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

We own and operate, or own a significant interest in, 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, including through our interest in VTTI B.V. (“VTTI”), comprises more than 135 liquid petroleum products terminals with aggregate tank capacity of over 176 million barrels across our portfolio of pipelines, inland terminals and marine terminals located primarily in the East Coast, Midwest and Gulf Coast regions of the United States as well as in the Caribbean, Northwest Europe, the Middle East and Southeast Asia. Our global network of marine terminals enables us to facilitate global flows of crude oil and refined petroleum products, offering our customers connectivity between supply areas and market centers through some of the world’s most important bulk liquid storage and blending hubs. Our 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. Through our 50% equity interest in VTTI, our global terminal network offers premier storage and marine terminalling services for petroleum product logistics in key international energy hubs. We are also a wholesale distributor of refined petroleum products in certain areas served by our pipelines and terminals.

Basis of Presentation and Principles of Consolidation

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

We believe that the disclosures in these unaudited condensed consolidated financial statements are adequate to make the information presented not misleading. These interim financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto contained in our Annual Report on Form 10-K for the year ended December 31, 2017.

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Recently Adopted Accounting Guidance

Revenue from Contracts with Customers. Effective January 1, 2018, we adopted Accounting Standards Codification (“ASC”) Topic 606, Revenue from Contracts with Customers (“ASC 606”), applying 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 requires 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 requires certain disclosures regarding qualitative and quantitative information regarding 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. Please see Note 2 for additional information.

Recognition and Measurement of Financial Assets and Liabilities. Effective January 1, 2018, we adopted Accounting Standards Update (“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 unaudited condensed 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 unaudited condensed 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 unaudited condensed consolidated financial statements. In connection with the adoption of ASU 2017-07 using the retrospective transition method, we reclassified $0.5 million of expenses related to our Retirement Income Guarantee Plan and unfunded post-retirement benefit plan, originally included in Operating expenses as of March 31, 2017, 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.

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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 provides a measurement period, which in no case should 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 Buckeye Development & Logistics I LLC (“BDL”), 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 unaudited condensed consolidated financial statements or on our disclosures. We continue to evaluate certain aspects of the Tax Act and have recorded certain adjustments to our deferred taxes.

Recent Accounting Guidance Not Yet Adopted

Derivatives and Hedging. In August 2017, the Financial Accounting Standards Board (“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. 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 are currently evaluating the impact the adoption of this guidance will have on our consolidated financial statements.

Leases. In February 2016, the FASB issued ASU 2016-02 requiring lessees to recognize a right-of-use asset and a lease liability on the balance sheet for leases with lease terms greater than twelve months. This update also requires enhanced disclosures regarding the amount, timing and uncertainty of cash flows arising from leases. The guidance must be applied using a modified retrospective approach. 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 expect to adopt this guidance on January 1, 2019. We are currently evaluating the impact the adoption of this guidance will have on our consolidated financial statements.

Goodwill Impairment. In January 2017, the FASB issued ASU 2017-04 simplifying the test for goodwill impairment. 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. Under the new guidance, entities will recognize an impairment charge for the amount by which the carrying amount of a reporting unit exceeds its fair value. The guidance must be applied using a prospective approach and is effective for interim and annual goodwill impairment tests in fiscal years beginning after December 15, 2019, with early adoption permitted. We do not believe our adoption of this guidance will have a material impact on our consolidated financial statements or on our 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. 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 on January 1, 2020. We are currently evaluating the impact the adoption of this standard will have on our consolidated financial statements.

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2. REVENUE FROM CONTRACTS WITH CUSTOMERS

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 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 of 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 obligation and related method 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 for 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 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 transportation, storage and other service 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 the customer is not expected to meet its commitment.

Terminalling and Storage Services

Revenue from storage and terminalling operations is recognized as services are performed. Storage and terminalling revenue include storage fees, which are generated as we provide storage capacity, and terminalling or throughput fees, which are generated when we receive liquid petroleum products from pipelines, sea-going vessels, trucks, or rail-car and redeliver such products to pipelines, sea-going vessels, railroads, or truck-loading racks. We generate revenue through a combination of month-to-month and multi-year storage capacity and terminalling service arrangements. The majority of our contracts have a single performance obligation to provide storage and terminalling services that is primarily satisfied over time as these services are provided. Storage fees for contract 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. 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. As discussed above with respect to transportation services, progress in performing terminalling services is generally measured based upon the volume of product handled. We have certain contracts containing tiered pricing or volume based discounts, which are recognized in revenue as an optional purchase 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 the customer is not expected to meet its 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, which are sold on a wholesale basis, is recognized at the time title to the product sold transfers to the purchaser, which 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 do not offer extended payment terms.

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Operation and Construction Services

Revenue from contract operation and construction services of 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.

Contract Balances

Contract assets primarily relate to our rights to consideration for completed performance obligations but 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 either been satisfied by 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 from contracts with customers (in thousands):



	March 31, 2018			December 31, 2017
Receivables from contracts with customers	$	223,327		$	245,280
Contract assets	21,094			13,999
Contract liabilities	(29,528		)	(15,778		)

During the three months ended March 31, 2018, we reclassified approximately $13.6 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 three months ended March 31, 2018 from amounts included in contract liabilities at the beginning of the period was approximately $5.4 million.

The following table includes estimated revenue associated with contractual commitments in place, which are expected to be recognized in revenue in the specified period related to future performance obligations as of the end of the reporting period (in thousands):



	Estimated Revenue ⁽¹⁾
Remainder of 2018	$	303,306
2019	252,813
2020	179,797
2021	110,346
Thereafter	229,115
Total	$	1,075,377

(1) Excludes revenue arrangements accounted for as leases in the amount of $146.0 million for the remainder of 2018, $190.1 million for 2019, $188.3 million for 2020, $170.9 million for 2021, and $162.1 million thereafter.

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Our contractually committed revenue, for purposes of the tabular presentation above, excludes estimates of variable rate escalation clauses in our contracts with customers and is generally limited to contracts which have fixed pricing and minimum volume terms and conditions. Our contractually committed revenue amounts generally exclude remaining performance obligations for contracts with index-based pricing or variable volume attributes in which such variable consideration relates to the remaining performance obligation.

3. ACQUISITIONS

Business Combination

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 and the final working capital settlement of $0.9 million received in the first quarter of 2018. The assets of this entity are reported in our Domestic Pipelines & Terminals segment. The purchase price has been allocated on a preliminary basis 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 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):



Current assets, including cash acquired of $2,444	$	8,989
Property, plant and equipment	18,306
Intangible assets	2,200
Goodwill	2,796
Current liabilities	(3,501		)
Environmental liabilities	(299		)
Allocated purchase price	$	28,491

Adjustments to the preliminary purchase price allocation during the quarter resulted in nominal decreases to current assets and current liabilities, with a corresponding increase to goodwill.

Unaudited Pro forma Financial Results for Duck Island terminal acquisition

Our unaudited condensed 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 three months ended March 31, 2018.

Equity Investment Transaction

VTTI Acquisition

In January 2017, we acquired an indirect 50% equity interest in VTTI for cash consideration of $1.15 billion (the “VTTI Acquisition”). We own VTTI jointly with Vitol S.A. (“Vitol”). VTTI is one of the largest independent global marine terminal businesses which, through its subsidiaries and partnership interests, owns and operates approximately 58 million barrels of petroleum products storage across 15 terminals located on five continents. These marine terminals are predominately located in key global energy hubs, including Northwest Europe, the Middle East and Southeast Asia, and offer world-class storage and marine terminalling services for liquid petroleum products. We and VIP Terminals Finance B.V., a subsidiary of Vitol, have equal board representation and voting rights in the VTTI joint venture. We account for this investment 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. The earnings from our equity investment in VTTI are reported in our Global Marine Terminals segment. In addition, we include our proportionate share of our equity method investments’ unrealized gains and losses in OCI in our unaudited condensed consolidated financial statements.

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The fair values used to calculate the excess net investment in VTTI were primarily developed using an income approach, with inputs classified as Level 3 within the fair value hierarchy. The excess net investment was $584.4 million at the acquisition date and was comprised of the following components: (i) $240.7 million related to the excess of the fair values of identifiable property, plant and equipment and intangible assets over their carrying values, which is being amortized on a straight-line basis over the estimated useful lives of these underlying assets of approximately 28 years; and (ii) $343.7 million of implied goodwill, which is not subject to amortization. The amortization of the excess net investment is included in earnings from equity investments on our unaudited condensed consolidated statements of operations.

In September 2017, VTTI acquired all of the outstanding publicly held units of VTTI Energy Partners LP, formerly a publicly traded master limited partnership (“VTTI MLP”), for an aggregate cash consideration of $473.6 million (the “VTTI Merger”). In connection with the VTTI Merger, VTTI MLP merged with and into a direct wholly owned subsidiary of VTTI. We funded our 50% share of the aggregate cash consideration, in the amount of $236.8 million, excluding transaction costs, through a capital contribution to VTTI, using borrowings under our $1.5 billion revolving credit facility with SunTrust Bank (the “Credit Facility”).

4. 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

At March 31, 2018 and December 31, 2017, we had $40.4 million and $41.0 million, respectively, of environmental remediation liabilities unrelated to claims and legal proceedings. 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 March 31, 2018 and December 31, 2017, we had $5.0 million and $5.3 million, respectively, of receivables related to these environmental remediation liabilities covered by insurance or third-party claims.

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5. INVENTORIES

Our inventory amounts were as follows at the dates indicated (in thousands):



	March 31, 2018		December 31, 2017
Liquid petroleum products ⁽¹⁾	$	136,693	$	280,934
Materials and supplies	21,500		20,491
Total inventories	$	158,193	$	301,425


(1)	Ending inventory was 69.7 million and 142.1 million gallons of liquid petroleum products as of March 31, 2018 and December 31, 2017, respectively.

At March 31, 2018 and December 31, 2017, approximately 91% 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 unaudited condensed consolidated statements of operations.

6. PREPAID AND OTHER CURRENT ASSETS

Prepaid and other current assets consist of the following at the dates indicated (in thousands):



	March 31, 2018		December 31, 2017
Prepaid insurance	$	2,754	$	7,146
Margin deposits	4,825		7,989
Contract assets	21,094		13,999
Prepaid taxes	5,778		2,865
Other	7,144		4,340
Total prepaid and other current assets	$	41,595	$	36,339

7. EQUITY INVESTMENTS

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



		Three Months Ended March 31,
	Segment	2018		2017
VTTI B.V.	Global Marine Terminals	$	4,390	$	8,389
West Shore Pipe Line Company	Domestic Pipelines & Terminals	2,326		1,342
Muskegon Pipeline LLC	Domestic Pipelines & Terminals	325		334
Transport4, LLC	Domestic Pipelines & Terminals	229		173
South Portland Terminal LLC	Domestic Pipelines & Terminals	219		120
Total earnings from equity investments		$	7,489	$	10,358

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



	Three Months Ended March 31,
	2018		2017
Revenue	$	145,068	$	126,684
Operating income	49,782		45,645
Net income	24,750		30,112
Net income attributable to investee	22,959		23,987

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8. LONG-TERM DEBT

Extinguishment of Debt

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.

Notes Offerings

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. From January 22, 2023, the Junior Notes will bear interest at a floating rate based on the Three-Month London Interbank Offered Rate (“LIBOR”) plus 4.02%, reset quarterly. Total proceeds from this offering, after underwriting fees, expenses, and debt issuance costs, were $395.0 million. We used the net proceeds from this offering to reduce indebtedness outstanding under our Credit Facility and for general partnership purposes.

Current Maturities Expected to be Refinanced

We have classified $400.0 million of 2.650% notes due on November 15, 2018 as long-term debt in the unaudited condensed consolidated balance sheet at March 31, 2018 because we have the intent and the ability to refinance these obligations on a long-term basis under our Credit Facility. At March 31, 2018, we had $1,382.4 million of additional borrowing capacity under our Credit Facility.

9. 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 underlying borrowings.

During 2016, we entered into eleven forward-starting interest rate swaps with a total aggregate notional amount of $500.0 million, in anticipation of the issuance of debt on or before November 15, 2018. We expect to issue new fixed-rate debt on or before November 15, 2018 to repay the $400.0 million of 2.650% notes that are due on November 15, 2018, as well as to fund capital expenditures and other general partnership purposes, although no assurances can be given that the issuance of fixed-rate debt will be possible on acceptable terms.

During the three months ended March 31, 2018, unrealized gains of $14.8 million were recorded in accumulated other comprehensive income (“AOCI”) to reflect the change in the fair values of the forward-starting interest rate swaps.

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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 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 our commodity derivative instruments outstanding at March 31, 2018 (amounts in thousands of gallons):



	Volume ⁽¹⁾
Derivative Purpose	Current	Long-Term
Derivatives NOT designated as hedging instruments:
Physical fixed-price derivative contracts	9,592	535
Physical index derivative contracts	41,892	—
Futures contracts for refined petroleum products	9,505	924
			Hedge Type
Derivatives designated as hedging instruments:
Cash flow hedge futures contracts	1,974	—	Cash Flow Hedge
Futures contracts for refined petroleum products	63,420	—	Fair Value Hedge


(1)	Volume represents absolute value of net notional volume position. All volumes represent net short positions.

Our futures contracts designated as fair value hedges relate to our inventory portfolio and extend to the fourth quarter of 2018. Our futures contracts relate to forecasted purchases and sales of refined petroleum products and extend to the third quarter of 2019.

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In accordance with the Chicago Mercantile Exchange (“CME”) rulebook, variation margin transfers are considered settlement payments, thereby reducing the corresponding derivative asset and liability balances for our exchange-settled derivative contracts. These settlement payments result in realized gains and losses on derivatives.

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



	March 31, 2018
	Derivatives NOT Designated as Hedging Instruments			Derivatives Designated as Hedging Instruments			Derivative Carrying Value			Netting Balance Sheet Adjustment ⁽¹⁾			Net Total
Physical fixed-price derivative contracts	$	414		$	—		$	414		$	(48	)	$	366
Physical index derivative contracts	306			—			306			(15		)	291
Interest rate derivative contracts	—			46,754			46,754			—			46,754
Total current derivative assets	720			46,754			47,474			(63		)	47,411
Physical fixed-price derivative contracts	1			—			1			—			1
Total non-current derivative assets	1			—			1			—			1
Physical fixed-price derivative contracts	(2,272		)	(3,008		)	(5,280		)	48			(5,232		)
Physical index derivative contracts	(15		)	—			(15		)	15			—
Total current derivative liabilities	(2,287		)	(3,008		)	(5,295		)	63			(5,232		)
Physical fixed-price derivative contracts	(22		)	—			(22		)	—			(22		)
Total non-current derivative liabilities	(22		)	—			(22		)	—			(22		)
Net derivative (liabilities) assets	$	(1,588	)	$	43,746		$	42,158		$	—		$	42,158


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



	December 31, 2017
	Derivatives NOT Designated as Hedging Instruments			Derivatives Designated as Hedging Instruments		Derivative Carrying Value			Netting Balance Sheet Adjustment ⁽¹⁾			Net Total
Physical fixed-price derivative contracts	$	2,582		$	—	$	2,582		$	(63	)	$	2,519
Physical index derivative contracts	455			—		455			(9		)	446
Interest rate derivative contracts	—			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. Futures contracts are subject to settlement through margin requirements and are additionally presented on a net basis.

At March 31, 2018, open refined petroleum product derivative contracts (represented by the physical fixed-price contracts, and physical index contracts noted above) varied in duration in the overall portfolio, but did not extend beyond September 2019. In addition, at March 31, 2018, we had refined petroleum product inventories that we intend to use to satisfy a portion of the physical derivative contracts.

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



		Three Months Ended March 31,
	Location	2018			2017
Derivatives NOT designated as hedging instruments:
Physical fixed-price derivative contracts	Product sales	$	1,354		$	2,487
Physical index derivative contracts	Product sales	177			(16		)
Physical fixed-price derivative contracts	Cost of product sales	(605		)	467
Physical index derivative contracts	Cost of product sales	2			163
Futures contracts for refined products	Cost of product sales	(2,298		)	(90		)

		Three Months Ended March 31,
	Location	2018			2017
Derivatives designated as fair value hedging instruments:
Futures contracts for refined products	Cost of product sales	$	5,707		$	33,577
Physical inventory - hedged items	Cost of product sales	(5,990		)	(20,351		)

		Three Months Ended March 31,
	Location	2018			2017
Ineffectiveness excluding the time value component on fair value hedging instruments:
Fair value hedge ineffectiveness (excluding time value)	Cost of product sales	$	(82	)	$	(959	)
Time value excluded from hedge assessment	Cost of product sales	(201		)	14,185

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 in OCI on Derivatives for the
	Three Months Ended March 31,
	2018			2017
Derivatives designated as cash flow hedging instruments:
Interest rate derivative contracts	$	14,761		$	1,710
Commodity derivatives	(623		)	1,275
Total	$	14,138		$	2,985



		Loss Reclassified from AOCI to Income (Effective Portion) for the
		Three Months Ended March 31,
	Location	2018			2017
Derivatives designated as cash flow hedging instruments:
Interest rate derivative contracts	Interest and debt expense	$	(2,337	)	$	(3,038	)
Commodity derivatives	Product Sales	—			—
Total		$	(2,337	)	$	(3,038	)

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Over the next twelve months, we expect to reclassify $6.7 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 $4.5 million of amortization of hedge gains on settled forward-starting interest rate swaps settled in November 2017 and forecasted hedge gains on forward-starting interest rate swaps that we expect to settle in late 2018. Additionally, the unrealized gains and losses for refined petroleum products designated as cash flow hedges at March 31, 2018, of $0.6 million, are estimated to be realized and reclassified from AOCI to product sales over the next twelve months. The ineffective portion of the change in fair value of cash flow hedges was not material for the three months ended March 31, 2018 and 2017.

10. FAIR VALUE MEASUREMENTS

We categorize our financial assets and liabilities using the three-tier fair value 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):



	March 31, 2018					December 31, 2017
	Level 1		Level 2			Level 1		Level 2
Financial assets:
Physical fixed-price derivative contracts	$	—	$	415		$	—	$	2,582
Physical index derivative contracts	—		306			—		455
Interest rate derivatives	—		46,754			—		31,994

Financial liabilities:
Physical fixed-price derivative contracts	—		(5,302		)	—		(7,226		)
Physical index derivative contracts	—		(15		)	—		(18		)
Futures contracts for refined products	—		—			—		—
Fair value	$	—	$	42,158		$	—	$	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 March 31, 2018 are presented in accordance with the CME rulebook, which deems that these instruments are settled daily via variation margin payments. As a result of this rulebook guidance, 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 is not significant to the overall valuation of interest rate derivatives as of March 31, 2018 and 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 March 31, 2018 and December 31, 2017. As of March 31, 2018 and December 31, 2017, the Merchant Services segment did not hold any net liability derivative position containing credit contingent features.

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Financial instruments included in current assets and current liabilities are reported in the unaudited condensed consolidated balance sheets at amounts which approximate fair value due to the relatively short period to maturity of these financial instruments. The fair values of our fixed-rate debt were estimated by observing market trading prices and by comparing the historic market prices of our publicly issued debt with the market prices of the publicly issued debt of other MLPs with similar credit ratings and terms. The fair values 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):



	March 31, 2018				December 31, 2017
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Fixed-rate debt	$	3,938,242	$	3,973,115	$	4,241,963	$	4,384,336
Variable-rate debt	764,907		765,200		668,562		668,904
Total debt	$	4,703,149	$	4,738,315	$	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.

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 three months ended March 31, 2018 and 2017, respectively.

Non-Recurring

Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments in certain circumstances, such as when there is evidence of impairment. For the three months ended March 31, 2018 and 2017, there were no significant fair value adjustments related to such assets or liabilities reflected in our unaudited condensed consolidated financial statements.

11. UNIT-BASED COMPENSATION PLANS

We award unit-based compensation to employees and directors primarily under the 2013 Long Term Incentive Plan of Buckeye Partners, L.P. (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 awards under the LTIP and the Option Plan of $8.8 million and $8.7 million for the three months ended March 31, 2018 and 2017, respectively.

LTIP

As of March 31, 2018, there were 2,135,404 LP Units available for issuance under the LTIP.

Deferral Plan under the LTIP

We also maintain the Buckeye Partners, L.P. Unit Deferral and Incentive Plan, as amended and restated effective December 13, 2016 (the “Deferral Plan”), pursuant to which we issue phantom and matching units under the LTIP to certain employees in lieu of cash compensation at the election of the employee. During the three months ended March 31, 2018, 149,726 phantom units (including matching units) were granted under this plan. These grants are included as granted in the LTIP activity table below.

Awards under the LTIP

During the three months ended March 31, 2018, the Compensation Committee of the board of directors of Buckeye GP (the “Board”) granted 345,899 phantom units to employees (including the 149,726 phantom units granted pursuant to the Deferral Plan, as discussed above), 18,000 phantom units to independent directors of Buckeye GP and 272,518 performance units to employees.

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



	Number of LP Units		Weighted Average Grant Date Fair Value per LP Unit ⁽¹⁾
Unvested at January 1, 2018	1,450		$	64.04
Granted ⁽²⁾	636		51.60
Performance adjustment ⁽³⁾	39		73.17
Vested	(384	)	72.83
Forfeited	(12	)	58.02
Unvested at March 31, 2018	1,729		$	57.71


(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 three months ended March 31, 2018 as a result of our above target performance with respect to applicable performance goals.

At March 31, 2018, $58.2 million of compensation expense related to the unvested LTIP is expected to be recognized over a weighted average remaining period of 2.2 years.

We ceased making additional grants under the Option Plan following the adoption of the 2009 Plan. At December 31, 2017, there was no unrecognized compensation cost related to unvested options, as all options were vested and exercised as of November 24, 2017. The total intrinsic value of options exercised during each of the three months ended March 31, 2018 and 2017 were zero and $0.2 million, respectively.

12. PARTNERS’ CAPITAL AND DISTRIBUTIONS

Our LP Units and Class C Units represent limited partnership 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. 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 and Class C Units (voting together as a single class), we cannot issue any limited partnership interests of a class or series having preferences or other special or senior rights over the LP Units and Class C Units.

Equity Offering

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 $262.1 million, after deducting issuance costs of approximately $2.9 million. We used the net proceeds from this offering to reduce the indebtedness outstanding under our Credit Facility, to pre-fund the equity portion of our remaining 2018 and 2019 growth capital expenditure program and for general partnership purposes.

Class C Units represent a separate class of our limited partnership interests. The Class C Units are substantially similar in all respects to our existing LP Units, except that Buckeye has the option to pay distributions on the Class C Units in cash or by issuing additional Class C Units, with the number of Class C Units issued based upon the volume-weighted average price per LP Unit, less a discount of 12.5%, for the 10 trading days immediately preceding the date the distributions are declared.

The Class C Units will convert into LP Units on a one-for-one basis at the earliest of (i) March 2, 2020, (ii) the date on which the Partnership delivers notice to the holders of the Class C Units that the Class C Units have converted, (iii) the date on which a change of control of the Partnership occurs, (iv) the business day following any notice or press release from the Partnership of a cash distribution for any quarterly period in an amount less than $1.2625 per LP Unit and (v) the date on which the Partnership issues any class or series of LP Units having preferences or senior rights over the LP Units and Class C Units.

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At-the-Market Offering Program

Our 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”) expired on January 15, 2018. During the three months ended March 31, 2018, no LP Units were sold under the Equity Distribution Agreement.

Summary of Changes in Outstanding Units

The following is a summary of changes in Buckeye’s outstanding LP Units and Class C Units for the periods indicated (in thousands):



	LP Units	Class C Units	Total
Units outstanding at January 1, 2018	146,677	—	146,677
LP units issued pursuant to the LTIP ⁽¹⁾	258	—	258
Issuance of Class C units	—	6,221	6,221
Units outstanding at March 31, 2018	146,935	6,221	153,156

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

Cash Distributions

We generally make quarterly cash distributions to unitholders of substantially all of our available cash, generally defined in our partnership agreement as consolidated cash receipts less consolidated cash expenditures and such retentions for working capital, anticipated cash expenditures and contingencies as our general partner deems appropriate. Cash distributions are paid for LP Units and for distribution equivalent rights (“DERs”) with respect to certain unit-based compensation awards outstanding as of each respective period. Actual cash distributions on our LP Units totaled $186.8 million ($1.2625 per LP Unit) and $174.9 million ($1.2375 per LP Unit) during the three months ended March 31, 2018 and 2017, respectively.

On May 4, 2018, we announced a quarterly distribution of $1.2625 per LP Unit that will be paid on May 21, 2018 to unitholders of record on May 14, 2018. Based on the LP Units and DERs with respect to certain unit-based compensation awards outstanding as of March 31, 2018, cash expected to be distributed to LP unitholders on May 21, 2018 is estimated to be approximately $186.8 million. We also expect to issue approximately 218,673 Class C Units to our Class C unitholders in lieu of cash distributions on May 21, 2018.

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13. EARNINGS PER UNIT

The following tables set forth the calculation of basic and diluted earnings per unit, attributable to Buckeye’s unitholders (including LP Units and Class C Units), 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):



	Three Months Ended March 31,
	2018		2017

Net income attributable to unitholders	$	111,120	$	123,576

Basic:
Weighted average units outstanding - basic	148,904		140,377
Earnings per unit - basic	$	0.75	$	0.88

Diluted:
Weighted average units outstanding - basic	148,904		140,377
Effect of dilutive securities	628		621
Weighted average units outstanding - diluted	149,532		140,998
Earnings per unit - diluted	$	0.74	$	0.88

14. 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 revenues, expenses, operating income, assets and liabilities have been eliminated.

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, including through its interest in VTTI, provides marine accessible bulk storage and blending services, rail and truck rack loading/unloading along with petroleum processing services in the New York Harbor on the East Coast and Corpus Christi, Texas in the Gulf Coast region of the United States, as well as The Bahamas, Puerto Rico and St Lucia in the Caribbean, Northwest Europe, the Middle East and Southeast Asia. The segment owns and operates, or owns a significant interest in, 22 liquid petroleum product terminals, located in these key domestic and international energy hubs, that enable us to 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.

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Merchant Services

The Merchant Services segment is a wholesale distributor of refined petroleum products in the United States and 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 three months ended March 31, 2018 and 2017, 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.



	Three Months Ended March 31,
	2018
	Domestic Pipelines & Terminals			Global Marine Terminals		Merchant Services		Intersegment Eliminations			Total
Revenue from contracts with customers
Pipeline transportation	$	121,470		$	—	$	—	$	(3,639	)	$	117,831
Terminalling and storage services	115,976			101,218		—		(8,593		)	208,601
Product sales	—			13		643,508		(3,354		)	640,167
Other services	12,089			21		2,900		(1,347		)	13,663
Total revenue from contracts with customers	249,535			101,252		646,408		(16,933		)	980,262
Revenue from leases	7,990			42,833		—		—			50,823
Revenue from derivatives	(2,090		)	—		152,020		2,090			152,020
Total revenue	$	255,435		$	144,085	$	798,428	$	(14,843	)	$	1,183,105



	Three Months Ended March 31,
	2017
	Domestic Pipelines & Terminals		Global Marine Terminals		Merchant Services		Intersegment Eliminations			Total
Revenue from contracts with customers
Pipeline transportation	$	115,937	$	—	$	—	$	(2,983	)	$	112,954
Terminalling and storage services	109,586		125,732		—		(7,579		)	227,739
Product sales	—		11		444,134		(3,725		)	440,420
Other services	12,991		102		1,992		(1,683		)	13,402
Total revenue from contracts with customers	238,514		125,845		446,126		(15,970		)	794,515
Revenue from leases	11,127		38,631		—		—			49,758
Revenue from derivatives	3,871		—		125,000		(3,871		)	125,000
Total revenue	$	253,512	$	164,476	$	571,126	$	(19,841	)	$	969,273

The following table summarizes revenue by major geographic area for the periods indicated (in thousands):



	Three Months Ended March 31,
	2018		2017
Revenue:
United States	$	1,122,220	$	887,862
International	60,885		81,411
Total revenue	$	1,183,105	$	969,273

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Adjusted EBITDA

Adjusted EBITDA is a measure not defined by GAAP. We define Adjusted EBITDA as earnings 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, 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 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. 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.

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The following table presents net income on a consolidated basis and a reconciliation of net 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):



	Three Months Ended March 31,
	2018			2017
Reconciliation of Net Income to Adjusted EBITDA:
Net income	$	117,092		$	126,309
Less: Net income attributable to noncontrolling interests	(4,719		)	(2,733		)
Net income attributable to Buckeye Partners, L.P.	112,373			123,576
Add: Interest and debt expense	59,105			55,885
Income tax expense	490			222
Depreciation and amortization ⁽¹⁾	64,138			65,488
Non-cash unit-based compensation expense	8,690			8,678
Acquisition and transition expense ⁽²⁾	282			1,029
Hurricane-related costs ⁽³⁾	581			2,403
Proportionate share of Adjusted EBITDA for the equity method investment in VTTI ⁽⁴⁾	34,540			28,617
Less: Gains on property damage recoveries ⁽⁵⁾	(14,085		)	—
Earnings from the equity method investment in VTTI ⁽⁴⁾	(4,390		)	(8,389		)
Adjusted EBITDA	$	261,724		$	277,509

Adjusted EBITDA:
Domestic Pipelines & Terminals	$	140,651		$	139,443
Global Marine Terminals	117,418			130,631
Merchant Services	3,655			7,435
Adjusted EBITDA	$	261,724		$	277,509


(1)	Includes 100% of the depreciation and amortization expense of $17.8 million and $17.5 million for Buckeye Texas for the three months ended March 31, 2018 and 2017, respectively.


(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.


(5)	Represents gains on recoveries, which settled property damages caused by a third party, primarily related to vessel allision with a jetty at our BBH facility in the Bahamas, which occurred in May 2012.

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15. SUPPLEMENTAL CASH FLOW INFORMATION

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



	Three Months Ended March 31,
	2018		2017
Cash paid for interest (net of capitalized interest)	$	52,329	$	54,539
Cash paid for income taxes	159		180
Capitalized interest	1,788		1,029

Liabilities related to capital projects outstanding at March 31, 2018 and 2017 of $64.7 million and $49.6 million, respectively, are not included under capital expenditures within the unaudited condensed consolidated statements of cash flows.

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

Cautionary Note Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q (this “Report”) contains various forward-looking statements and information that are based on our beliefs, as well as assumptions made by us and information currently available to us. When used in this Report, words such as “proposed,” “anticipate,” “project,” “potential,” “could,” “should,” “continue,” “estimate,” “expect,” “may,” “believe,” “will,” “plan,” “seek,” “outlook” and similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements. Although we believe that such expectations reflected in such forward-looking statements are reasonable, we cannot give any assurances that such expectations will prove to be correct. Such statements are subject to a variety of risks, uncertainties and assumptions as described in more detail in Part I “Item 1A, Risk Factors” included in our Annual Report on Form 10-K for the year ended December 31, 2017. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Although the expectations in the forward-looking statements are based on our current beliefs and expectations, caution should be taken not to place undue reliance on any such forward-looking statements because such statements speak only as of the date hereof. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason.

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

Overview of Business

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

We own and operate, or own a significant interest in, 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, including through our interest in VTTI B.V. (“VTTI”), comprises more than 135 liquid petroleum products terminals with aggregate tank capacity of over 176 million barrels across our portfolio of pipelines, inland terminals and marine terminals located primarily in the East Coast, Midwest and Gulf Coast regions of the United States as well as in the Caribbean, Northwest Europe, the Middle East and Southeast Asia. Our global network of marine terminals enables us to facilitate global flows of crude oil and refined petroleum products, offering our customers connectivity between supply areas and market centers through some of the world’s most important bulk storage and blending hubs. Our flagship marine terminal in The Bahamas, Buckeye Bahamas Hub Limited (“BBH”), 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. Through our 50% equity interest in VTTI, our global terminal network offers premier storage and marine terminalling services for petroleum product logistics in key international energy hubs. We are also a wholesale distributor of refined petroleum products in certain areas served by our pipelines and terminals.

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

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Recent Developments

Class C Units Issuance

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 Class C Units are substantially similar in all respects to our existing LP Units, except that Buckeye may elect to pay distributions in respect of the Class C Units through the issuance of additional Class C Units rather than cash. The Class C Units will convert into LP Units on a one-for-one basis no later than March 2, 2020. We used the net proceeds from this offering to reduce the indebtedness outstanding under our $1.5 billion revolving credit facility with SunTrust Bank (the “Credit Facility”), to pre-fund the equity portion of our remaining 2018 and 2019 growth capital expenditure program and for general partnership purposes.

Notes Issuance and Repayments

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. From January 22, 2023, the Junior Notes will bear interest at a floating rate based on the Three-Month London Interbank Offered Rate (“LIBOR”) plus 4.02%, reset quarterly. Total proceeds from this offering, after underwriting fees, expenses and debt issuance costs, were $395.0 million. We used the net proceeds from this offering for general partnership purposes and to reduce the indebtedness outstanding under our Credit Facility.

In January 2018, we repaid in full the $300.0 million of 6.050% notes due on January 15, 2018 and $9.1 million of related accrued interest, using funds available under our Credit Facility.

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Results of Operations

Consolidated Summary

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



	Three Months Ended March 31,
	2018			2017
Revenue	$	1,183,105		$	969,273
Costs and expenses	1,013,592			796,697
Operating income	169,513			172,576
Other expense, net	(51,931		)	(46,045		)
Income before taxes	117,582			126,531
Income tax expense	(490		)	(222		)
Net income	117,092			126,309
Less: Net income attributable to noncontrolling interests	(4,719		)	(2,733		)
Net income attributable to Buckeye Partners, L.P.	$	112,373		$	123,576

Non-GAAP Financial Measures

Adjusted EBITDA and distributable cash flow are not measures defined by accounting principles generally accepted in the United States of America (“GAAP”). We define Adjusted EBITDA as earnings 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 unrealized 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, and gains and losses on asset sales. We define distributable cash flow as Adjusted EBITDA less cash interest expense, cash income tax expense, and maintenance capital expenditures incurred to maintain the operating, safety, and/or earnings capacity of our existing assets, plus or minus realized gains or losses on certain foreign currency derivative financial instruments, as applicable. These definitions of Adjusted EBITDA and distributable cash flow are also applied to our proportionate share in the Adjusted EBITDA and distributable cash flow of significant equity method investments, such as that in VTTI, and are not applied to our less significant equity method investments. The calculation of our proportionate share of the reconciling items used to derive these VTTI performance metrics 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. These adjustments include gains and losses on foreign currency derivative financial instruments used to hedge VTTI’s United States dollar denominated distributions which are excluded from Adjusted EBITDA and included in distributable cash flow when realized. Adjusted EBITDA and distributable cash flow are non-GAAP financial measures that are 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 use distributable cash flow as a performance metric to compare the cash-generating performance of Buckeye from period to period and to compare the cash-generating performance for specific periods to the cash distributions (if any) that are expected to be paid to our unitholders. Distributable cash flow is not intended to be a liquidity measure.

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

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



	Three Months Ended March 31,
	2018			2017
Adjusted EBITDA:
Domestic Pipelines & Terminals	$	140,651		$	139,443
Global Marine Terminals	117,418			130,631
Merchant Services	3,655			7,435
Total Adjusted EBITDA	$	261,724		$	277,509
Reconciliation of Net Income to Adjusted EBITDA and Distributable cash flow:
Net income	$	117,092		$	126,309
Less: Net income attributable to noncontrolling interests	(4,719		)	(2,733		)
Net income attributable to Buckeye Partners, L.P.	112,373			123,576
Add: Interest and debt expense	59,105			55,885
Income tax expense	490			222
Depreciation and amortization ⁽¹⁾	64,138			65,488
Non-cash unit-based compensation expense	8,690			8,678
Acquisition and transition expense ⁽²⁾	282			1,029
Hurricane-related costs ⁽³⁾	581			2,403
Proportionate share of Adjusted EBITDA for the equity method investment in VTTI ⁽⁴⁾	34,540			28,617
Less: Gains on property damage recoveries ⁽⁵⁾	(14,085		)	—
Earnings from the equity method investment in VTTI ⁽⁴⁾	(4,390		)	(8,389		)
Adjusted EBITDA	$	261,724		$	277,509
Less: Interest and debt expense, excluding amortization of deferred financing costs, debt discounts and other	(55,205		)	(51,524		)
Income tax expense, excluding non-cash taxes	(401		)	(222		)
Maintenance capital expenditures	(28,200		)	(32,586		)
Proportionate share of VTTI’s interest expense, current income tax expense, realized foreign currency derivative gains and losses, and maintenance capital expenditures ⁽⁴⁾	(10,836		)	(8,018		)
Add: Hurricane-related maintenance capital expenditures	2,098			5,550
Distributable cash flow	$	169,180		$	190,709

_________________________


(1)	Includes 100% of the depreciation and amortization expense of $17.8 million and $17.5 million for Buckeye Texas for the three months ended March 31, 2018 and 2017, respectively.


(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 definitions of Adjusted EBITDA and distributable cash flow, covered in our description of non-GAAP financial measures, with respect to our proportionate share of VTTI’s Adjusted EBITDA and distributable cash flow. The calculation of our proportionate share of the reconciling items used to derive these VTTI performance metrics 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.


(5)	Represents gains on recoveries, which settled property damages caused by a third party, primarily related to vessel allision with a jetty at our BBH facility in the Bahamas, which occurred in May 2012.

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The following table presents product volumes in barrels per day (“bpd”) and average tariff rates in cents per barrel for our Domestic Pipelines & Terminals segment, capacity utilization percentages for our Global Marine Terminals segment and total sales volumes for the Merchant Services segment for the periods indicated:



	Three Months Ended March 31,
	2018		2017
Domestic Pipelines & Terminals (average bpd in thousands):
Pipelines:
Gasoline	732.5		703.1
Jet fuel	353.2		355.0
Middle distillates ⁽¹⁾	357.2		329.4
Other products ⁽²⁾	12.5		21.2
Total throughput	1,455.4		1,408.7
Terminals:
Throughput ⁽³⁾	1,315.1		1,183.8

Pipeline average tariff (cents/bbl)	91.1		90.0

Global Marine Terminals (percent of capacity):
Average capacity utilization rate ⁽⁴⁾	88	%	99	%

Merchant Services (in millions of gallons):
Sales volumes	396.0		349.1

___________________________


(1)	Includes diesel fuel and heating oil.


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


(3)	Includes throughput of two underground propane storage caverns.


(4)	Represents the ratio of contracted capacity to capacity available to be contracted. Based on total capacity (i.e., including out of service capacity), average capacity utilization rates are approximately 83% and 96% for the three months ended March 31, 2018 and 2017, respectively.

Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017

Consolidated Overview

Net income was $117.1 million for the three months ended March 31, 2018, a decrease of $9.2 million, or 7.3%, from $126.3 million for the corresponding period in 2017. The decrease was driven by (i) lower operating results primarily in the Global Marine Terminals segment’s Caribbean facilities which were partially offset by higher results at Buckeye Texas; (ii) lower operating results in the Merchant Services segment, as further explained in the discussion of Adjusted EBITDA by segment below; and (iii) a $3.2 million increase in interest and debt expense, primarily due to the long-term debt issued in November 2017. The decrease was partially offset by stronger results from the Domestic Pipelines & Terminals segment, as further explained in the discussion of Adjusted EBITDA by segment below, as well as a $1.4 million decrease in depreciation and amortization expense and a $14.0 million gain on insurance recoveries related to a property damage claim that was settled during the quarter.

Total Adjusted EBITDA was $261.7 million for the three months ended March 31, 2018, a decrease of $15.8 million, or 5.7%, from $277.5 million for the corresponding period in 2017. The decrease in Adjusted EBITDA was driven by decreases in segment Adjusted EBITDA of $13.2 million and $3.7 million from the Global Marine Terminals segment and Merchant Services segment, respectively, which were partially offset by a $1.1 million increase in Adjusted EBITDA from the Domestic Pipelines & Terminals segment, as further explained in the discussion of Adjusted EBITDA by segment below.

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Distributable cash flow was $169.2 million for the three months ended March 31, 2018, a decrease of $21.5 million, or 11.3%, from $190.7 million for the corresponding period in 2017, driven by (i) a $15.8 million decrease in Adjusted EBITDA from our segments, net of a $5.9 million increase in Adjusted EBITDA contribution from VTTI, as further described below; (ii) a $2.8 million increase in the proportionate share of VTTI’s interest expense and current income tax expense resulting in VTTI’s $3.1 million incremental contribution to distributable cash flow; and (iii) a $3.7 million increase in our interest and debt expense, excluding amortization of deferred financing costs, debt discounts and other; and (iv) partially offset by a $0.9 million decrease in maintenance capital expenditures, excluding hurricane-related maintenance capital expenditures.

Adjusted EBITDA by Segment

Domestic Pipelines & Terminals. Adjusted EBITDA from the Domestic Pipelines & Terminals segment was $140.6 million for the three months ended March 31, 2018, an increase of $1.1 million, or 0.8%, from $139.5 million for the corresponding period in 2017. The increase in Adjusted EBITDA was primarily due to a $1.9 million increase in revenue, partially offset by a $0.8 million net increase in operating expenses and other.

Pipeline volumes increased by 3.3% due to strong demand for gasoline and distillate shipments. Terminalling volumes increased by 11.1%, primarily due to higher gasoline and distillate volumes, reflecting strong customer throughput demand, particularly in our Northeast and Southeast region.

The volume increases contributed to an increase of $5.3 million in pipeline transportation revenues, reflecting contributions from internal growth capital investments in service for a full quarter in 2018 as well as increases in certain tariff rates and higher-rate long-haul movements. In addition, product recoveries increased by $3.5 million, while terminalling throughput revenues increased by $0.4 million, net of the impact of the expiration of a crude-by-rail contract at our Chicago Complex. These increases were partially offset by a $3.8 million decrease in storage revenue, primarily due to lower capacity utilization, as well as a $3.5 million decrease in project management and other revenues, primarily due to a decrease in project activity. The net increase in operating expenses and other primarily relates to increased labor and general and administrative expenses, partially offset by decreased activity within our project management business.

Global Marine Terminals. Adjusted EBITDA from the Global Marine Terminals segment was $117.4 million for the three months ended March 31, 2018, a decrease of $13.2 million, or 10.1%, from $130.6 million for the corresponding period in 2017. The decrease in Adjusted EBITDA was primarily due to a $21.8 million decrease in revenue, partially offset by a $5.9 million increase in the Adjusted EBITDA contribution from our equity investment in VTTI, as well as a $2.7 million decrease in operating expenses.

The decrease in revenue was due to a $25.4 million decrease in revenue from storage and terminalling services, reflecting lower capacity utilization and average rates primarily due to lower demand for storage services at our Caribbean facilities as a result of overall weaker market conditions, partially offset by a $3.6 million increase in processing services revenues at Buckeye Texas. The average capacity utilization (i.e., ratio of contracted capacity to capacity available to be contracted) of our marine storage assets was 88% for the three months ended March 31, 2018, which was a decrease from 99% in the corresponding period in 2017. The decrease in operating expenses reflected cost improvements at Buckeye Texas, as well as lower general and administrative expenses.

Merchant Services. Adjusted EBITDA from the Merchant Services segment was $3.7 million for the three months ended March 31, 2018, a decrease of $3.7 million, or 50.0%, from $7.4 million for the corresponding period in 2017. Adjusted EBITDA was negatively impacted by weaker market conditions, primarily in the distillate market, partially offset by higher rack margins as well as a decrease in operating expenses.

Revenue increased by $227.3 million primarily due to (i) a $76.7 million increase as a result of 13.4% higher sales volumes and (ii) $150.6 million due to higher commodity prices (average sales prices per gallon were $2.02 and $1.64 for the 2018 and 2017 periods, respectively).

Cost of product sales increased by $231.2 million primarily due to (i) a $75.2 million increase due to higher sales volumes and (ii) $156.0 million due to higher commodity prices (average prices per gallon were $2.00 and $1.60 for the 2018 and 2017 periods, respectively).

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Liquidity and Capital Resources

General

Our primary cash requirements, in addition to normal operating expenses and debt service, are for working capital, capital expenditures, business acquisitions and distributions to unitholders. Our principal sources of liquidity are cash from operations, borrowings under our Credit Facility and proceeds from the issuance of our LP Units, or in certain instances, other types of units. We will, from time to time, issue debt securities to refinance amounts borrowed under our Credit Facility. Buckeye Energy Services LLC, Buckeye West Indies Holdings LP, and Buckeye Caribbean Terminals LLC (collectively the Buckeye Merchant Service Companies or “BMSC”) fund their working capital needs principally from their own operations and their portion of our Credit Facility. Our financial policy is to fund maintenance capital expenditures with cash from operations. Expansion and cost reduction capital expenditures, along with acquisitions, have typically been funded from external sources including our Credit Facility, as well as debt and equity offerings. Our goal has been to fund at least half of these expenditures with proceeds from equity offerings in order to maintain an appropriate leverage ratio and our investment-grade credit rating. Based on current market conditions, we believe our borrowing capacity under our Credit Facility, cash flows from operations and access to debt and equity markets, if necessary, will be sufficient to fund our primary cash requirements, including our expansion plans over the next 12 months.

Current Liquidity

As of March 31, 2018, we had working capital of $73.8 million and $1,382.4 million of availability under our Credit Facility.

Capital Structure Transactions

As part of our ongoing efforts to maintain a capital structure that is closely aligned with the cash-generating potential of our asset-based business, we may explore additional sources of external liquidity, including public or private debt or equity issuances. Matters to be considered will include cash interest expense and maturity profile, all to be balanced with maintaining adequate liquidity. We have a universal shelf registration statement that does not place any dollar limits on the amount of debt and equity securities that we may issue thereunder and a traditional shelf registration statement on file with the U.S. Securities and Exchange Commission (“SEC”) that allows us to issue up to an aggregate of $1 billion in equity securities. From time to time, we enter into equity distribution agreements in connection with our at-the-market (“ATM”) offering program pursuant to which we may issue and sell LP Units registered under our traditional shelf registration statement. In the fourth quarter of 2017, we filed a new traditional shelf registration statement with the SEC, under which we had $1 billion of unsold securities available as of March 31, 2018. The universal and traditional shelf registration statements will expire in November and December 2020, respectively. Our 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”) expired on January 15, 2018. We do not intend to enter into a new equity distribution agreement in connection with our ATM offering program in 2018.

The timing of any transaction may be impacted by events, such as strategic growth opportunities, legal judgments or regulatory or environmental requirements. The receptiveness of the capital markets to an offering of debt or equity securities cannot be assured and may be negatively impacted by, among other things, our long-term business prospects and other factors beyond our control, including market conditions.

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

Capital Allocation

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

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Current Maturities Expected to be Refinanced

Debt

At March 31, 2018, we had total fixed-rate and variable-rate debt obligations of $3,938.2 million and $764.9 million, respectively, with an aggregate fair value of $4,738.3 million. At March 31, 2018, we were in compliance with the covenants under our Credit Facility and our $250.0 million variable-rate term loan due September 30, 2019 (the “Term Loan”).

In January 2018, we issued $400.0 million of 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. From 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 $395.0 million. We used the net proceeds from this offering to reduce the indebtedness outstanding under our Credit Facility and for general partnership purposes.

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.

Equity

Class C Units represent a separate class of our limited partnership interests. The Class C Units are substantially similar in all respects to our existing LP Units, except that Buckeye has the option to pay distributions on the Class C Units in cash or by issuing additional Class C Units, with the number of Class C Units issued based upon the volume-weighted average price of the LP Units, less a discount of 12.5%, for the 10 trading days immediately preceding the date the distributions are declared.

Cash Flows from Operating, Investing and Financing Activities

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



	Three Months Ended March 31,
	2018			2017
Cash provided by (used in):
Operating activities	$	236,191		$	193,044
Investing activities	(89,068		)	(1,247,178		)
Financing activities	(142,696		)	418,667
Net increase (decrease) in cash and cash equivalents	$	4,427		$	(635,467	)

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Operating Activities

Net cash provided by operating activities of $236.2 million for the three months ended March 31, 2018 primarily resulted from $117.1 million of net income, $64.1 million of depreciation and amortization expense, and a $143.2 million decrease in inventory, reflecting the Merchant Services segment’s reduced inventory levels, partially offset by a $71.1 million decrease in accounts payable.

Net cash provided by operating activities of $193.0 million for the three months ended March 31, 2017 primarily resulted from $126.3 million of net income and $65.5 million of depreciation and amortization expense, which were partially offset by a $26.4 million net increase in fair value of derivatives.

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

Investing Activities

Net cash used in investing activities of $89.1 million for the three months ended March 31, 2018 primarily resulted from $116.9 million of capital expenditures, partially offset by $19.2 million of distributions from equity method investments in excess of cumulative earnings.

Net cash used in investing activities of $1.25 billion for the three months ended March 31, 2017 primarily resulted from $98.3 million of capital expenditures and $1.15 billion of equity investment acquisition costs related to the VTTI Acquisition. See below for a discussion of capital spending.

Financing Activities

Net cash used in financing activities of $142.7 million for the three months ended March 31, 2018 primarily resulted from $303.7 million of net repayments under the Credit Facility, a $300.0 million principal repayment of our 6.050% notes, and $186.1 million of cash distributions paid to our unitholders ($1.2625 per LP Unit), partially offset by $395.0 million of net proceeds from our 6.375% notes issuance and $262.1 million of net proceeds from the issuance of 6.2 million Class C Units in a private placement.

Net cash provided by financing activities of $418.7 million for the three months ended March 31, 2017 primarily resulted from $600.5 million of net borrowings under the Credit Facility, partially offset by $174.1 million of cash distributions paid to our unitholders ($1.2375 per LP Unit) and $8.2 million of payments of tax withholdings on the issuance of Long-Term Incentive Plan awards.

Capital Expenditures

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



	Three Months Ended March 31,
	2018		2017
Maintenance capital expenditures ⁽¹⁾	$	28,200	$	32,586
Expansion and cost reduction	88,716		65,666
Total capital expenditures ⁽²⁾	$	116,916	$	98,252

____________________________


(1)	Includes maintenance capital expenditures of $2.1 million related to the BBH facility and Yabucoa Terminal in Puerto Rico as a result of Hurricanes Matthew and Maria for the three months ended March 31, 2018 and $5.6 million for the three months ended March 31, 2017 as a result of Hurricane Matthew.


(2)	Amounts exclude the impact of accruals. On an accrual basis, capital expenditure additions to property, plant and equipment were $118.9 million and $88.8 million for the three months ended March 31, 2018 and 2017, respectively.

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Capital expenditures increased for the three months ended March 31, 2018, as compared to the corresponding period in 2017, primarily due to increases in expansion and cost reduction capital projects. Our expansion and cost reduction capital expenditures were $88.7 million for the three months ended March 31, 2018, an increase of $23.0 million, or 35.0%, from $65.7 million for the corresponding period in 2017. The period-over-period fluctuations in our expansion and cost reduction capital expenditures primarily reflected the ongoing expansion of certain large organic-growth capital projects, including the Michigan/Ohio Pipeline Expansion Project, New York Harbor, and Jacksonville assets. Our maintenance capital expenditures were $28.2 million for the three months ended March 31, 2018, a decrease of $4.4 million, or 13.5%, from $32.6 million for the corresponding period in 2017, primarily driven by lower hurricane-related capital replacements.

We have estimated our capital expenditures as follows for the year ending December 31, 2018 (in thousands):



	2018
	Low		High
Domestic Pipelines & Terminals:
Maintenance capital expenditures	$	66,000	$	76,000
Expansion and cost reduction	255,000		285,000
Total capital expenditures	$	321,000	$	361,000

Global Marine Terminals:
Maintenance capital expenditures	$	39,000	$	49,000
Expansion and cost reduction	80,000		100,000
Total capital expenditures ⁽¹⁾	$	119,000	$	149,000

Overall:
Maintenance capital expenditures	$	105,000	$	125,000
Expansion and cost reduction	335,000		385,000
Total capital expenditures	$	440,000	$	510,000

_________________________

(1) Includes 100% of Buckeye Texas’ capital expenditures.

Estimated maintenance capital expenditures include tank refurbishments and upgrades to station and terminalling equipment, asset integrity, field instrumentation and cathodic protection systems and exclude capital expenditures expected to be incurred in response to hurricane related damages. Estimated major expansion and cost reduction expenditures include the continuing capacity expansion of our pipeline system and terminalling capacity in the Midwest, continuing expansion of the facilities in the New York Harbor, continued investment in South Texas facilities, an expansion of the Jacksonville terminal, and various tank construction and conversion projects in our Global Marine Terminals and Domestic Pipelines & Terminals segments.

Off-Balance Sheet Arrangements

At March 31, 2018 and December 31, 2017, we had no off-balance sheet debt or arrangements.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following should be read in conjunction with Quantitative and Qualitative Disclosures About Market Risk included under Item 7A in our Annual Report on Form 10-K for the year ended December 31, 2017. There have been no material changes in that information other than as discussed below. Also, see Note 9 in the Notes to Unaudited Condensed Consolidated Financial Statements for additional discussion related to derivative instruments and hedging activities.

Market Risk — Non-Trading Instruments

We are exposed to financial market risks, including changes in commodity prices and interest rates. The primary factors affecting our market risk and the fair value of our derivative portfolio at any point in time are the volume of open derivative positions, changing refined petroleum commodity prices, and prevailing interest rates for our interest rate swaps. We are also susceptible to basis risk created when we enter into financial hedges that are priced at a certain location, but the sales or exchanges of the underlying commodity are at another location where prices and price changes might differ from the prices and price changes at the location upon which the hedging instrument is based. Since prices for refined petroleum products and interest rates are volatile, there may be material changes in the fair value of our derivatives over time, driven both by price volatility and the changes in volume of open derivative transactions.

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



	Commodity Instruments			Interest Rate Swaps		Total
Fair value of contracts outstanding at January 1, 2018	$	(4,207	)	$	31,994	$	27,787
Cash settlements during the period	(4,102		)	—		(4,102		)
Change in fair value attributable to new deals during the period	(7,922		)	—		(7,922		)
Change in fair value attributable to existing deals at January 1st	11,635			14,760		26,395
Fair value of contracts outstanding at March 31, 2018	$	(4,596	)	$	46,754	$	42,158

Commodity Price Risk

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 contracts accounted for at fair value. In addition, the segment uses exchange-traded refined petroleum product futures and over-the-counter (“OTC”) traded physical fixed-price derivative contracts to hedge expected future transactions related to certain forecasted purchases and sales of refined petroleum products. Finally, 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 pricing spreads between gasoline and butane and butane inventory in connection with our butane blending activities managed by a third party. Based on a hypothetical 10% movement in the underlying quoted market prices of the futures contracts, as well as observable market data from third-party pricing publications for refined petroleum product inventories and physical contracts accounted for at fair value designated in hedging relationships at March 31, 2018, the estimated fair value, excluding variation margins, would be as follows (in thousands):



Scenario	Resulting Classification	Fair Value
Fair value assuming no change in underlying commodity prices (as is)	Asset	$	121,119
Fair value assuming 10% increase in underlying commodity prices	Asset	$	128,301
Fair value assuming 10% decrease in underlying commodity prices	Asset	$	113,937

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Interest Rate Risk

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 are exposed to both credit risk and market risk. We manage our credit risk by entering into swap transactions only with major financial institutions with investment-grade credit ratings. We are subject to credit risk when the change in fair value of the swap instruments is positive and the counterparty may fail to perform under the terms of the contract. We are subject to market risk with respect to changes in the underlying benchmark interest rate that impact the fair value of swaps. We manage our market risk by aligning the swap instrument with the existing underlying debt obligation or a specified expected debt issuance generally associated with the maturity of an existing debt obligation.

Our practice with respect to derivative transactions related to interest rate risk has been to have each transaction in connection with non-routine borrowings authorized by the board of directors of Buckeye GP (the “Board”). In February 2009, the Board adopted an interest rate hedging policy which permits us to enter into certain short-term interest rate swap agreements to manage our interest rate and cash flow risks associated with a credit facility. In addition, in August 2016, the Board authorized us to enter into forward-starting interest rate swaps to manage our interest rate and cash flow risks related to certain expected debt issuances associated with the maturity of existing debt obligations. Based on a hypothetical 10% movement in the underlying interest rates at March 31, 2018, the estimated fair value of the interest rate derivative contracts would be as follows (in thousands):



Scenario	Resulting Classification	Fair Value
Fair value assuming no change in underlying interest rates (as is)	Asset	$	46,754
Fair value assuming 10% increase in underlying interest rates	Asset	$	42,078
Fair value assuming 10% decrease in underlying interest rates	Asset	$	51,430

See Note 9 in the Notes to Unaudited Condensed Consolidated Financial Statements for additional discussion related to derivative instruments and hedging activities.

Foreign Currency Risk

Puerto Rico is a commonwealth territory under the U.S., and thus uses the U.S. dollar as its official currency. BBH’s functional currency is the U.S. dollar, and it is equivalent in value to the Bahamian dollar. St. Lucia is a sovereign island country in the Caribbean, and its official currency is the Eastern Caribbean dollar, which is pegged to the U.S. dollar and has remained fixed for many years. The functional currency for our operations in 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 unaudited condensed consolidated statements of operations. The effects of foreign currency transactions were not considered to be material for the three months ended March 31, 2018 and 2017.

Our equity method investment in VTTI indirectly exposes 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 transaction, hedging and translation gains and losses is included in our earnings from equity investments and accumulated other comprehensive income, as applicable. We recognized, in other comprehensive income, $14.0 million and $2.9 million, representing our proportionate share of VTTI’s other comprehensive income, primarily comprised of foreign currency translation adjustments, for the three months ended March 31, 2018 and 2017, respectively.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

During the quarter ended March 31, 2018, there were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) or in other factors that materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting. We did, however, implement certain changes to our internal control over financial reporting in connection with the implementation of the revenue recognition and disclosure requirements of Accounting Standards Codification Topic 606. The changes primarily related to the design and implementation of controls related to the preparation and review of the new disclosure requirements of the accounting standard.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

In the ordinary course of business, we are involved in various claims and legal proceedings, some of which are covered by insurance. We are generally unable to predict the timing or outcome of these claims and proceedings. For information on unresolved legal proceedings, see Part I, Item 1, Financial Statements, Note 4, “Commitments and Contingencies” in the Notes to Unaudited Condensed Consolidated Financial Statements included in this quarterly report, which is incorporated into this item by reference.

Item 1A. Risk Factors

Security holders and potential investors in our securities should carefully consider the risk factors in Part I, “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2017. We have identified these risk factors as important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.

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Item 6. Exhibits

(a) Exhibits



3.1	Amended and Restated Certificate of Limited Partnership of Buckeye Partners, L.P., dated as of February 4, 1998 (Incorporated by reference to Exhibit 3.2 of Buckeye Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 1997).

3.2	Certificate of Amendment to Amended and Restated Certificate of Limited Partnership of Buckeye Partners, L.P., dated as of April 26, 2002 (Incorporated by reference to Exhibit 3.2 of Buckeye Partners, L.P.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2002).

3.3	Certificate of Amendment to Amended and Restated Certificate of Limited Partnership of Buckeye Partners, L.P., dated as of June 1, 2004, effective as of June 3, 2004 (Incorporated by reference to Exhibit 3.3 of the Buckeye Partners, L.P.’s Registration Statement on Form S-3 filed June 16, 2004).

3.4	Certificate of Amendment to Amended and Restated Certificate of Limited Partnership of Buckeye Partners, L.P., dated as of December 15, 2004 (Incorporated by reference to Exhibit 3.5 of Buckeye Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2004).

3.5	Amended and Restated Agreement of Limited Partnership of Buckeye Partners, L.P., dated as of November 19, 2010 (Incorporated by reference to Exhibit 3.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed November 22, 2010).

3.6	Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Buckeye Partners, L.P., dated as of January 18, 2011 (Incorporated by reference to Exhibit 3.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on January 20, 2011).

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

3.8	Amendment No. 3 to Amended and Restated Agreement of Limited Partnership of Buckeye Partners, L.P., dated as of October 1, 2013, (Incorporated by reference to Exhibit 3.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on October 7, 2013).

3.9	Amendment No. 4 to Amended and Restated Agreement of Limited Partnership of Buckeye Partners, L.P., dated as of September 29, 2014, (Incorporated by reference to Exhibit 3.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on September 29, 2014).

3.10	Amendment No. 5 to Amended and Restated Agreement of Limited Partnership of Buckeye Partners, L.P., dated as of December 13, 2017, (Incorporated by reference to Exhibit 3.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on December 18, 2017).

3.11	Amendment No. 6 to Amended and Restated Agreement of Limited Partnership of Buckeye Partners, L.P., dated as of March 2, 2018 (Incorporated by reference to Exhibit 3.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on March 5, 2018).

4.1	Subordinated Indenture, dated January 22, 2018, between Buckeye Partners, L.P. and Branch Banking and Trust Company, as trustee (Incorporated by reference to Exhibit 4.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on January 24, 2018).

4.2	First Supplemental Indenture, dated January 22, 2018, between Buckeye Partners, L.P. and Branch Banking and Trust Company, as trustee (Incorporated by reference to Exhibit 4.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on January 24, 2018).

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4.3	Registration Rights Agreement by and among Buckeye Partners, L.P. and the Investors named on Schedule A, dated as of March 2, 2018 (Incorporated by reference to Exhibit 4.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on March 5, 2018).

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

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

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

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

*101.INS	XBRL Instance Document.

*101.SCH	XBRL Taxonomy Extension Schema Document.

*101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.

*101.LAB	XBRL Taxonomy Extension Label Linkbase Document.

*101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.

*101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.

* Filed herewith.

** Furnished herewith.

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SIGNATURES

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



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

		By:	Buckeye GP LLC,
			as General Partner


Date:	May 4, 2018	By:	/s/ Keith E. St.Clair
			Keith E. St.Clair
			Executive Vice President and Chief Financial Officer
			(Principal Financial Officer)

BUCKEYE PARTNERS, L.P. - FORM 10-Q - May 4, 2018

Attached files

BUCKEYE PARTNERS, L.P. Reports