Edgar Filing: BUCKEYE PARTNERS, L.P.

Large accelerated filer x

Accelerated filer o

Non-accelerated filer o

Smaller reporting company o

Emerging growth company o

Document

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

______________________________________________________

FORM 10-K

______________________________________________________

(Mark One)

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

For the fiscal year ended December 31, 2018

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

For the transition period from to

Commission file number 1-9356

______________________________________________________

Buckeye Partners, L.P.

(Exact name of registrant as specified in its charter)

_____________________________________________________________________________



Delaware		23-2432497
(State or other jurisdiction of 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

Securities registered pursuant to Section 12(b) of the Act:



Title of each class		Name of each exchange on which registered
Limited partner units representing limited partnership interests		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No ý

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 o

Indicate by check mark whether the registrant has submitted electronically every Interactive Date File required to be submitted 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 such files). Yes ý No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

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

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 o No ý

At June 30, 2018, the aggregate market value of the registrant’s limited partner units held by non-affiliates was $5.3 billion. The calculation of such market value should not be construed as an admission or conclusion by the registrant that any person is in fact an affiliate of the registrant.

As of February 8, 2019, there were 153,797,059 limited partner units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Proxy Statement being prepared for the solicitation of proxies in connection with the 2019 Annual Meeting of Limited Partners are incorporated by reference in Part III of this Form 10-K.

TABLE OF CONTENTS



		Page
PART I
Item 1.	Business	1
Item 1A.	Risk Factors	17
Item 1B.	Unresolved Staff Comments	34
Item 2.	Properties	34
Item 3.	Legal Proceedings	34
Item 4.	Mine Safety Disclosures	34

PART II
Item 5.	Market for the Registrant’s LP Units, Related Unitholder Matters, and Issuer Purchases of LP Units	35
Item 6.	Selected Financial Data	36
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	37
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	55
Item 8.	Financial Statements and Supplementary Data	57
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	116
Item 9A.	Controls and Procedures	116
Item 9B.	Other Information	116

PART III
Item 10.	Directors, Executive Officers and Corporate Governance	117
Item 11.	Executive Compensation	117
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	117
Item 13.	Certain Relationships and Related Transactions and Director Independence	117
Item 14.	Principal Accounting Fees and Services	117

PART IV
Item 15.	Exhibits, Financial Statement Schedules	117
Item 16.	Form 10-K Summary	122

Table of Contents

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

The information contained in this Annual Report on Form 10-K (this “Report”) includes “forward-looking statements.” All statements that express belief, expectation, estimates or intentions, as well as those that are not statements of historical facts, are forward-looking statements. Such statements use forward-looking words such as “proposed,” “anticipate,” “project,” “potential,” “could,” “should,” “continue,” “estimate,” “expect,” “may,” “believe,” “will,” “plan,” “seek,” “outlook” and other similar expressions that are intended to identify forward-looking statements, although some forward-looking statements are expressed differently. These statements discuss future expectations and contain projections. Specific factors that could cause actual results to differ from those in the forward-looking statements include, but are not limited to: (i) changes in federal, state, local and foreign laws or regulations to which we are subject, including those governing pipeline tariff rates and those that permit the treatment of us as a partnership for federal income tax purposes; (ii) terrorism and other security risks, including cyber risk, adverse weather conditions, including hurricanes, environmental releases and natural disasters; (iii) changes in the marketplace for our products or services, such as increased competition, changes in product flows, better energy efficiency or general reductions in demand; (iv) adverse regional, national, or international economic conditions, adverse capital market conditions and adverse political developments; (v) shutdowns or interruptions at our pipeline, terminalling, storage and processing assets or at the source points for the products we transport, store or sell; (vi) unanticipated capital expenditures in connection with the construction, repair or replacement of our assets; (vii) volatility in the price of liquid petroleum products; (viii) nonpayment or nonperformance by our customers; (ix) our ability to successfully complete our organic growth projects and to realize the anticipated financial benefits; and (x) our ability to integrate acquired assets with our existing assets and to realize anticipated cost savings and other efficiencies and benefits. These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other known or unpredictable factors could also have material adverse effects on future results. Consequently, all of the forward-looking statements made in this document are qualified by these cautionary statements, and we cannot assure you that actual results or developments that we anticipate will be realized or, even if substantially realized, will have the expected consequences to or effect on us or our business or operations. Also note that we provide additional cautionary discussion of risks and uncertainties under the captions “Risk Factors” and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Report.

The forward-looking statements contained in this Report speak only as of the date hereof. 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. All forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this Report and in our future periodic reports filed with the U.S. Securities and Exchange Commission (“SEC”). In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this Report may not occur.

Table of Contents

PART I

Item 1. Business

Introduction

The original Buckeye Pipe Line Company was founded in 1886 as part of the Standard Oil Company (“Standard Oil”) and became a publicly owned, independent company after the dissolution of Standard Oil in 1911. Expansion into petroleum products transportation after World War II and subsequent acquisitions thereafter ultimately led to Buckeye Pipe Line Company becoming a leading independent common carrier pipeline. In 1964, Buckeye Pipe Line Company was acquired by a subsidiary of the Pennsylvania Railroad, which later became the Penn Central Corporation. In 1986, Buckeye Pipe Line Company was reorganized into a master limited partnership (“MLP”), Buckeye Partners, L.P. We are a publicly traded Delaware master limited partnership, and our limited partnership units representing limited partner interests (“LP Units”) are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “BPL.” Buckeye GP LLC (“Buckeye GP”) is our general partner. Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” or “Buckeye” are intended to mean the business and operations of Buckeye Partners, L.P. and its consolidated subsidiaries.

We own and operate a diversified global network of integrated assets providing midstream logistic solutions, primarily consisting of the transportation, storage, processing and marketing of liquid petroleum products. We are one of the largest independent liquid petroleum products pipeline operators in the United States in terms of volumes delivered, with approximately 6,000 miles of pipeline. We also use our service expertise to operate and/or maintain third-party pipelines and terminals and perform certain engineering and construction services for our customers. Our global terminal network comprises more than 115 liquid petroleum products terminals with aggregate tank capacity of over 118 million barrels across our portfolio of pipelines, inland terminals and marine terminals located primarily in the East Coast, Midwest and Gulf Coast regions of the United States as well as in the Caribbean. 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. We are also a wholesale distributor of refined petroleum products in certain areas served by our pipelines and terminals.

Recent Developments

Strategic Review

In November 2018, we announced the completion of a comprehensive review of the Partnership’s near and long-term strategy (the “Strategic Review”), conducted with oversight from the Board of Directors of Buckeye GP (the “Board”). The Strategic Review included an evaluation of various alternatives designed to maximize long-term value for our unitholders by:


•	Maintaining our investment-grade credit rating by reducing leverage;


•	Providing increased financial flexibility, eliminating the need to access the public equity markets to fund planned annual growth capital; and


•	Reallocating capital to the higher return growth opportunities across our remaining assets.

As a result, we have taken the following actions to accomplish these objectives:

(i)

On December 17, 2018, we closed on the $450.0 million sale of a package of non-integrated domestic pipeline and terminal assets. These assets include: (i) our jet fuel pipeline from Port Everglades, Florida to Ft. Lauderdale-Hollywood International Airport and Miami International Airport; (ii) our pipelines and terminal facilities serving Reno-Tahoe International Airport, San Diego International Airport, and the Federal Express Corporation terminal at the Memphis International Airport; and (iii) our refined petroleum product terminals in Sacramento, California and Stockton, California (the “DPTS asset package”). Proceeds were used to reduce debt in December 2018.


(ii)	On January 17, 2019, we closed on the sale of our 50% equity interest in VTTI for $975.0 million. Proceeds were used to reduce debt during the first quarter of 2019.


(iii)	Established a distribution policy that allows us to retain a portion of internally generated cash flow to deploy to investments such that we do not expect to need to access the public equity markets for the foreseeable future.

Table of Contents

South Texas Transactions

In April 2018, as part of our strategy to serve the production growth in crude oil and related products from the Permian Basin, we expanded our marine terminal presence in Corpus Christi, Texas through the following transactions: (i) acquired our business partner’s 20% interest in our Buckeye Texas consolidated subsidiary, and (ii) formed a joint venture with Phillips 66 Partners LP (“Phillips 66 Partners”) and Gray Oak Gateway Holdings (“Marathon”) to develop a new deep-water, open-access marine terminal in Ingleside, Texas at the mouth of Corpus Christi Bay (the “South Texas Gateway Terminal” or “STG Terminal”).

We acquired our partner’s interest in Buckeye Texas for $210.0 million, and as a result we now own 100% of Buckeye Texas. The change in our ownership interest was accounted for as an equity transaction, representing the acquisition of a noncontrolling interest.

The STG Terminal will be constructed and operated by us. We continue to secure additional minimum volume throughput commitments and storage contracts from customers, and our current plan is to increase the scope of this project from 3.4 million barrels of storage to 6.8 million barrels, based on current contracted throughput and storage volumes. Our construction plan also includes connectivity to multiple pipelines delivering volumes into the Corpus Christi market from growing Permian Basin production and other sources. In addition, we plan to build two deep-water vessel docks capable of berthing very large crude carrier (“VLCC”) petroleum tankers as part of the initial scope of construction.

The STG Terminal is expected to commence and ramp up operations by mid-2020, and is supported by long-term minimum volume throughput commitments and storage contracts from credit-worthy customers, including our joint-venture partners. We own a 50% interest in the STG Terminal, and Phillips 66 Partners and Marathon each own a 25% interest. The total construction cost for the STG Terminal is estimated on a 100% basis at $480.9 million, or a net of $240.5 million to our interest. During 2018, we invested $42.2 million and committed to fund our proportionate share of the anticipated total construction costs. We account for our interest in STG Terminal, which is included in our Global Marine Terminals segment, using the equity method of accounting.

Class C Units Issuance and Conversion to LP Units

In March 2018, we issued approximately 6.2 million Class C Units in a private placement for aggregate gross proceeds of $265.0 million. We used the net proceeds from this offering to reduce the indebtedness outstanding under our $1.5 billion revolving Credit Facility with the SunTrust Bank (the “Credit Facility”), to partially fund growth capital expenditures and for general partnership purposes.

The Class C Units represented a separate class of our limited partnership interests. The Class C Units were substantially similar in all respects to our existing LP units, except that Buckeye had the option to pay distributions on the Class C Units in cash or by issuing additional Class C Units.

The reduction in our quarterly distribution in November 2018 resulted in the conversion of all 6,714,963 Class C Units outstanding as of September 30, 2018 into LP Units on a one-for-one basis on November 5, 2018. Accordingly, the holders of these newly converted LP Units received a cash distribution of $0.75 per LP Unit, instead of an in-kind distribution of additional Class C Units. There were no Class C Units outstanding as of December 31, 2018.

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. Beginning 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 $394.9 million. We used the net proceeds from this offering for general partnership purposes and to reduce the indebtedness outstanding under our Credit Facility.

Table of Contents

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.

In November 2018, we repaid in full the $400.0 million of 2.65% notes due on November 15, 2018 and $5.3 million of related accrued interest, using funds available under our Credit Facility.

In January 2019, we repaid in full the $250.0 million variable-rate Term Loan due September 30, 2019 (the “Term Loan”). We expect to retire the $275.0 million of 5.50% notes due on August 15, 2019 in the first quarter of 2019.

VTTI Divestiture

In November 2018, we executed a definitive agreement to sell our 50% equity interest in VTTI for approximately $975.0 million, excluding transaction costs of approximately $8.0 million, plus a final earnings distribution of $22.6 million. The sale closed in January 2019. As a result, effective September 30, 2018, we recorded our investment in VTTI at its estimated fair value, as determined by the expected proceeds, resulting in a non-cash loss of $300.3 million, which was reported in (loss) earnings from equity investments in our Consolidated Statement of Operations. For additional information, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Report.

Business Activities

The following discussion describes the business activities of our business segments, which include Domestic Pipelines & Terminals, Global Marine Terminals and Merchant Services.

The Domestic Pipelines & Terminals, Global Marine Terminals and Merchant Services segments derive a nominal amount of their revenue from U.S. governmental agencies. All of our operated assets are located in the continental United States, except for our terminals located in Puerto Rico, St. Lucia and The Bahamas and, from time to time, our Merchant Services segment buys and/or sells diesel fuel, butane, and distribution services to third parties at various locations in the Caribbean. The following table shows our consolidated revenue and each segment’s revenue and percentage of consolidated revenue for the periods indicated (revenue in thousands):



	Year Ended December 31,
	2018					2017					2016
	Revenue			Percent		Revenue			Percent		Revenue			Percent
Domestic Pipelines & Terminals	$	1,030,084		25.0	%	$	1,035,663		28.4	%	$	1,011,696		31.1	%
Global Marine Terminals	564,902			13.8	%	634,749			17.4	%	671,465			20.7	%
Merchant Services ⁽¹⁾	2,572,159			62.6	%	2,038,221			55.9	%	1,621,915			49.9	%
Intersegment	(58,870		)	(1.4	)%	(60,488		)	(1.7	)%	(56,700		)	(1.7	)%
Total	$	4,108,275		100.0	%	$	3,648,145		100.0	%	$	3,248,376		100.0	%

____________________________________


(1)	The change in revenue year to year for Merchant Services is largely driven by fluctuations in refined petroleum products prices, as well as changes in sales volumes. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations for further discussion.

Domestic Pipelines & Terminals Segment

The Domestic Pipelines & Terminals segment owns a significant interest in and operates approximately 6,000 miles of pipeline located primarily in the northeastern and upper midwestern portions of the United States, and services over 100 delivery locations. This segment transports primarily liquid petroleum products, including gasoline, jet fuel and a variety of distillates, from major supply sources to terminals and airports located within end-use markets. The segment also includes 110 active terminals that provide bulk storage and throughput services with respect to liquid petroleum products and renewable fuels, including ethanol, and have an aggregate tank capacity of over 55 million barrels. In addition, certain terminals provide rail loading/unloading services for a variety of petroleum products. Over half of the terminals in the Domestic Pipelines & Terminals segment are connected to our pipelines. We generally own property on which the terminals are located. The segment’s geographical diversity, connections to multiple sources of supply, and extensive delivery system help create a stable base business.

Table of Contents

Pipelines

The Domestic Pipelines & Terminals segment’s pipelines conduct business without the benefit of exclusive franchises from government entities. Our pipelines generally operate as a common carrier, providing transportation services at posted tariffs and without long-term contracts. Additionally, we have secured long-term commitments to support our Michigan-Ohio pipeline expansion project and certain other pipeline expansion projects. Demand for the services provided by our pipelines derives from end-users’ demand for liquid petroleum products in the regions served and the ability and willingness of refiners and marketers to supply such demand by deliveries through our pipelines. Factors affecting demand for liquid petroleum products include price and prevailing general economic conditions. Many of the factors impacting demand for the services provided by our pipelines are, therefore, partially or entirely beyond our control. Typically, this segment receives liquid petroleum products from refineries, connecting pipelines, and bulk and marine terminals and transports those products to other locations for a fee.

The following table presents product volumes and percentage of products transported by the pipelines in the Domestic Pipelines & Terminals segment for the periods indicated (barrels per day (“bpd”) in thousands):



	Year Ended December 31,
	2018			2017			2016
Pipelines:
Gasoline	783.2	52.2	%	756.3	51.8	%	759.6	53.2	%
Jet fuel	375.2	25.0	%	373.8	25.6	%	361.1	25.3	%
Middle distillates ⁽¹⁾	329.5	22.0	%	309.7	21.2	%	289.4	20.3	%
Other products ⁽²⁾	12.3	0.8	%	19.1	1.4	%	16.9	1.2	%
Total pipelines throughput ⁽³⁾	1,500.2	100.0	%	1,458.9	100.0	%	1,427.0	100.0	%

_____________________________


(1)	Includes diesel fuel and heating oil.


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


(3)	Includes 105.4 bpd, 105.0 bpd, and 102.6 bpd of total pipelines throughput for the years ended 2018, 2017, and 2016, respectively, related to the DPTS asset package divested on December 17, 2018.

We provide pipeline transportation services in the following states: Connecticut, Illinois, Indiana, Iowa, Maine, Massachusetts, Michigan, Missouri, New Jersey, New York, Ohio, and Pennsylvania. The geographical location and description of these pipelines is as follows:

Pennsylvania—New York—New Jersey. Our operating subsidiary Buckeye Pipe Line Company, L.P. (“BPLC”) serves major population centers in Pennsylvania, New York and New Jersey through approximately 825 miles of pipeline. Liquid petroleum products are received at Linden, New Jersey from 17 major source points and are then transported through two lines to Macungie, Pennsylvania. From Macungie, the pipeline continues west through a connection with a pipeline owned by our operating subsidiary, Laurel Pipe Line Company, L.P. (“Laurel”), to Pittsburgh, Pennsylvania and north through eastern Pennsylvania into New York. In addition, product can also be transported from southeast Pennsylvania to upstate New York. We lease capacity in one of the pipelines extending from Pennsylvania to upstate New York to a major public pipeline company. Products received at Linden, New Jersey are also transported to commercial liquid petroleum products terminals at Long Island City and Inwood, New York and to Newark Airport, JFK Airport, and LaGuardia Airport. Buckeye Linden Pipe Line Company LLC (“Buckeye Linden”) provides transportation services within New York Harbor.

A pipeline system owned by our operating subsidiary, Buckeye Pipe Line Transportation LLC (“BPL Transportation”), delivers liquid petroleum products from a refinery located in Paulsboro, New Jersey to destinations in New Jersey, Pennsylvania and upstate New York through approximately 420 miles of pipeline. A portion of the pipeline system extends from Paulsboro, New Jersey to Malvern, Pennsylvania. From Malvern, a pipeline segment delivers liquid petroleum products to locations in upstate New York.

The Laurel pipeline system transports liquid petroleum products through a 350-mile pipeline extending westward from three refineries, a marine terminal and a connection to the Colonial pipeline system in the Philadelphia area to locations across Pennsylvania.

Table of Contents

Illinois—Indiana—Michigan—Missouri—Ohio. BPLC, BPL Transportation and our operating subsidiary NORCO Pipe Line Company, LLC (“NORCO”), a subsidiary of Buckeye Pipe Line Holdings, L.P. (“BPH”), transport liquid petroleum products through approximately 1,800 miles of pipeline in northern Illinois, central Indiana, eastern Michigan, western and northern Ohio, and western Pennsylvania. A number of receiving lines and delivery lines connect to a central corridor which runs from Lima, Ohio through Toledo, Ohio to Detroit, Michigan. Liquid petroleum products are received at refineries and other pipeline connection points near Toledo and Lima, Ohio; Detroit, Michigan; and East Chicago, Indiana. Major market areas served include Huntington/Fort Wayne, Indianapolis and South Bend, Indiana; Bay City, Detroit and Flint, Michigan; Cleveland, Columbus, Lima, Warren and Toledo, Ohio; and Pittsburgh, Pennsylvania.

Our operating subsidiary, Wood River Pipe Lines LLC (“Wood River”), owns liquid petroleum products pipelines with aggregate mileage of approximately 1,000 miles located in the Midwestern United States. Liquid petroleum products are received from the Wood River refinery in the East St. Louis, Illinois area and transported to the Chicago area (the “Chicago Complex”), to our terminal in the St. Louis, Missouri area and to the Lambert-St. Louis Airport, to delivery points across Illinois and Indiana and to our pipeline in Lima, Ohio, and from the Chicago Complex to the Kankakee, Illinois area.

Other Liquid Petroleum Products Pipelines. BPLC serves Connecticut and Massachusetts through an approximately 110-mile pipeline that carries liquid petroleum products from New Haven, Connecticut to Hartford, Connecticut and Springfield, Massachusetts. This pipeline also serves Bradley International Airport in Windsor Locks, Connecticut. Also, BPL Transportation owns an approximately 650-mile refined product pipeline that originates in Dubuque, Iowa and runs southwest into Missouri and then northwest back into Iowa, serving the Sugar Creek, Missouri, and Council Bluffs and Des Moines, Iowa markets. BPL Transportation also has an approximately 125-mile pipeline that runs from Portland, Maine to Bangor, Maine

Additionally, BPH indirectly owns an approximate 63% interest in the Sabina crude butadiene pipeline (the “Sabina Pipeline”) and owns and operates approximately 25 miles of pipeline, which it leases to third parties, all located in Texas.

Terminals

The Domestic Pipelines & Terminals segment’s terminals receive products from pipelines and, in certain cases, barges, ships or trains, and distribute them to third parties, who in turn deliver them to end-users and retail outlets. This segment’s terminals play a key role in moving products to the end-user market by providing efficient product receipt, storage and distribution capabilities, inventory management, ethanol and biodiesel blending, and other ancillary services including additives injection. Typically, the Domestic Pipelines & Terminals segment’s terminalling facilities consist of multiple storage tanks and are equipped with automated truck loading equipment available 24 hours a day.

The Domestic Pipelines & Terminals segment’s terminals derive most of their revenues from various fees paid by customers. A throughput fee is charged for receiving products into the terminal and delivering them to trucks, barges, ships or pipelines. In addition to these throughput fees, revenues are generated by charging customers fees for blending with renewable fuels, injecting additives and providing storage capacity to customers on either a short-term or long-term basis. Finally, the terminals derive service fees and blending margins from butane blending activities primarily during certain months (generally mid-September through mid-March), whereby butane is blended into various grades of gasoline. Blending margins depend upon pricing spreads between gasoline and butane, and we use financial derivative instruments to manage the commodity price risk associated with gasoline-to-butane pricing spreads, as deemed necessary. The fair value of such derivative instruments is recorded in our consolidated balance sheets, with the change in fair value recorded currently in earnings. These derivative instruments consist primarily of futures contracts cleared on the New York Mercantile Exchange (“NYMEX”) that are executed and managed by our Merchant Services segment.

The following table sets forth the total average daily throughput for terminals and storage caverns within the Domestic Pipelines & Terminals segment for the periods indicated (volume of bpd in thousands):



	Year Ended December 31,
	2018	2017	2016
Products throughput ⁽¹⁾⁽²⁾	1,336.5	1,251.5	1,238.4

____________________________


(1)	Amounts include throughput at the three terminals owned by the Merchant Services segment and operated by the Domestic Pipelines & Terminals segment (as discussed below), as well as two underground propane storage caverns.


(2)	Includes 60.3 bpd, 58.6 bpd, and 59.4 bpd of total terminals throughput for the years ended 2018, 2017, and 2016, respectively, related to the DPTS asset package divested on December 17, 2018.

Table of Contents

The following table sets forth the number of terminals and tank capacity in barrels by location for terminals reported in the Domestic Pipelines & Terminals segment (barrels in thousands):



Location	Number of Terminals⁽¹⁾	Tank Capacity ⁽²⁾
Alabama	2	605
Connecticut	2	1,212
Florida	4	1,951
Illinois	7	2,772
Indiana	11	9,846
Iowa	5	1,302
Kentucky	1	214
Louisiana	1	304
Maine	1	140
Maryland	1	3,232
Massachusetts	2	433
Michigan	14	5,467
Missouri	3	1,767
New Jersey	4	5,296
New York	16	8,450
North Carolina	1	572
Ohio	13	3,861
Pennsylvania	10	3,027
South Carolina	4	2,191
Virginia	4	1,805
Wisconsin	4	1,228
Total	110	55,675

____________________________


(1)	This table includes three terminals in Pennsylvania with aggregate storage capacity of approximately 1 million barrels, which are owned by the Merchant Services segment and operated by the Domestic Pipelines & Terminals segment (as discussed below).


(2)	This table includes approximately 19.1 million barrels of storage capacity, with the remaining capacity being used for throughput.

Operation and Maintenance and Project Management Services

We provide turn-key operations and maintenance, asset development and construction services for third-party pipeline, terminal, and energy assets across the United States. We also operate and/or maintain third-party pipelines under agreements with major oil and gas, petrochemical, chemical, and certain financial operating entities, which are located primarily in Texas, California, and certain locations in the Midwest and Southeastern United States, and perform pipeline construction management services, typically for cost plus a fixed fee, for these same customers as well as other energy companies in the United States.

Equity Investments

We own a 34.6% equity interest in West Shore Pipe Line Company (“West Shore”). West Shore owns an approximately 500-mile pipeline system that originates in the Chicago, Illinois area and extends north to Granville, Wisconsin and west and then north to Madison, Wisconsin. The pipeline system transports liquid petroleum products to markets in northern Illinois and Wisconsin. The other equity holders of West Shore are affiliated with major oil and gas companies. Since January 1, 2009, we have operated the West Shore pipeline system on behalf of West Shore.

We also own a 40% equity interest in Muskegon Pipeline LLC (“Muskegon”). Marathon Pipeline LLC is the majority owner and operator of Muskegon. Muskegon owns an approximately 170-mile pipeline that delivers petroleum products from Griffith, Indiana to Muskegon, Michigan.

Table of Contents

Additionally, we own a 25% equity interest in Transport4, LLC (“Transport4”). Transport4 provides an internet-based shipper information system that allows its customers, including shippers, suppliers and tankage partners to access nominations, schedules, tickets, inventories, invoices and bulletins over a secure internet connection.

We also own a 50% equity interest in South Portland Terminal LLC (“South Portland”), which owns a terminal in South Portland, Maine that has approximately 725,000 barrels of storage capacity. We have operated this terminal since July 19, 2011.

Global Marine Terminals Segment

The Global Marine Terminals segment provides marine accessible bulk storage and blending services, rail and truck rack loading/unloading, and petroleum processing services across our network of marine terminals located primarily in the East Coast and Gulf Coast regions of the United States, as well as in the Caribbean. The segment owns and operates seven liquid petroleum product terminals, located in these key domestic and global energy hubs.

The following table sets forth the capacity utilization percentage within the Global Marine Terminals segment:



	Year Ended December 31,
	2018		2017		2016
Average capacity utilization rate ⁽¹⁾	83	%	92	%	99	%

___________________________


(1)	Represents the average ratio of contracted capacity to capacity available to be contracted during the respective period. Based on total capacity (i.e., including out of service capacity), average capacity utilization rates are approximately 79%, 88% and 92% for the years ended December 31, 2018, 2017 and 2016, respectively.

The following table sets forth terminal locations and tank capacity in barrels for terminals reported in the Global Marine Terminals segment (barrels in thousands):



Location	Number of Terminals	Tank Capacity
Global Marine Terminals:
Caribbean
Grand Bahama Island, Bahamas	1	26,173
Castries, St. Lucia	1	10,241
Yabucoa, Puerto Rico	1	3,891
U.S. East Coast
New York Harbor	3	15,177
U.S. Gulf Coast
Corpus Christi, Texas	1	6,893
Total Global Marine Terminals ⁽¹⁾	7	62,375

_____________________________


(1)	This total represents total tank capacity as of December 31, 2018, of which approximately 6.4 million barrels are unavailable for contracting to third parties due to being out of service for maintenance, capital enhancements or used for internal purposes.

The following descriptions set forth additional information about our terminals located in key petroleum logistics hubs around the world.

Caribbean

BBH Facility

BBH owns a terminalling facility located along the Northwest Providence Channel of Grand Bahama Island, which it uses to operate a fully integrated terminalling business, and offers customers storage, blending and ancillary services, including but not limited to, berthing, heating, transshipment, product treating and bunkering. Ancillary services also facilitate customer activities within the tank farm and at the jetties.

Table of Contents

BBH’s terminalling facility includes more than 80 above ground storage tanks, which store crude oil, fuel oil and refined petroleum products. The existing marine infrastructure of BBH’s terminalling facility consists of three deep-water jetties, which provide six deep-water berths and an inland dock with two berths that serve as the access points to the storage facilities and marine bunkering services. Certain of these jetties are capable of handling both very large crude carriers and ultra large crude carriers.

We own the 500 acres of property on which the BBH terminalling facility is located. BBH leases 330 acres of seabed on which the deep water jetties are located pursuant to a long-term agreement with The Bahamas government that runs through 2057. BBH also leases the land on which the inland dock is located pursuant to a long-term agreement with the Freeport Harbour Company that runs through 2067.

St. Lucia Terminal

The St. Lucia terminal sits on approximately 700 acres on Cul de Sac Bay in St. Lucia and includes 34 storage tanks. It has over 10 million barrels of crude oil and refined petroleum products tank capacity, as well as deep-water access capable of berthing very large crude carriers and serves the local market’s refined product demand. The facility provides transshipment services for handling, blending and distribution of crude oil from growing Latin American production to U.S. and global refining centers. Access to the St. Lucia terminal is provided through two ship docks and a truck rack.

Yabucoa Terminal

The Yabucoa terminal in Puerto Rico includes 39 storage tanks, which store gasoline, jet fuel, diesel, fuel oil and crude oil. The facility provides terminalling services for the handling, blending and distribution of liquid petroleum products within the Puerto Rico market as well as residual fuel oil and petroleum distillate fuel for the local and regional Caribbean markets. Access to the Yabucoa terminal is provided through one ship dock, which is leased from the Puerto Rico Ports Authority, two barge docks and an eight-bay truck rack.

U.S. East Coast

New York Harbor Terminals

The New York Harbor storage and marine terminals, which consist of our Perth Amboy, Port Reading and Raritan Bay terminals, provide a link between our inland pipelines and terminals, owned and operated by the Domestic Pipelines & Terminals segment, and our BBH facility, enabling our customers to take advantage of BBH’s deep water access and ability to aggregate product. The Perth Amboy facility sits on approximately 250 acres on the Arthur Kill tidal strait in Perth Amboy, New Jersey; it has water, pipeline, rail and truck access and is connected to our Linden hub by a high capacity pipeline connection. Furthermore, the Perth Amboy terminal includes 42 storage tanks, a dock, and three operational berths, each with articulated loading arms, allowing both ship and barge berthing. The Port Reading terminal is located on 211 acres in Port Reading, New Jersey and includes 70 storage tanks, a deep-water dock and five operational berths, allowing for both ship and barge berthing. In addition, the facility has bi-directional pipeline access, rail unloading capabilities, and a six-bay driver-operated truck loading rack. The Raritan Bay terminal is located on 62 acres on the Raritan River in Perth Amboy, New Jersey, and includes 30 storage tanks, a barge dock and two operational berths. The Raritan Bay facility also has bi-directional pipeline access to a third-party pipeline and a six-bay driver-operated truck loading rack. Additionally, the Perth Amboy, Port Reading and Raritan Bay terminals are NYMEX delivery locations for both gasoline and ultra low sulfur diesel. The Perth Amboy, Port Reading and Raritan Bay terminals have approximately 4 million, 6 million and 5 million barrels of liquid petroleum products storage capacity, respectively. These terminals extend Buckeye’s connectivity in New York Harbor by offering diverse storage capabilities that include terminalling services for gasoline, blendstocks, distillate and fuel oil. In the spring of 2018, Buckeye completed construction of a 16” bi-directional pipeline between our Perth Amboy and Raritan Bay terminals, which allows for customer product movements between the facilities and access to the Linden hub.

Table of Contents

U.S. Gulf Coast

South Texas

Buckeye Texas owns storage, petroleum processing and marine terminalling facilities that sit on approximately 730 acres along the Corpus Christi Ship Channel in Corpus Christi, Texas. The Buckeye Texas facilities have five vessel berths, including three deep-water docks, two 25,000 barrels per day condensate splitters and approximately 6.9 million barrels of liquid petroleum products storage capacity, including a refrigerated and pressurized LPG storage complex, along with rail and truck loading/unloading capabilities. The system also comprises three field gathering facilities with associated storage in the Eagle Ford play and pipeline connectivity that allows Buckeye Texas to receive Permian Basin and Eagle Ford shale crude oil and condensate production directly to the terminalling complex in Corpus Christi. These assets form an integrated system with connectivity from the production in the field to the marine terminal infrastructure and the processing complex in Corpus Christi.

In April 2018, we announced the formation of a joint venture to develop the STG Terminal, a marine terminal to be constructed in Ingleside, Texas and operated by us. Our current plan is to increase the scope of this project from 3.4 million barrels of storage to 6.8 million barrels, based on current contracted throughput and storage volumes. Our construction plan also includes connectivity to multiple pipelines delivering volumes into the Corpus Christi market from growing Permian Basin production and other sources. In addition, we plan to build two deep-water vessel docks capable of berthing VLCCs as part of the initial scope of construction.

Merchant Services Segment

The Merchant Services segment is a wholesale distributor of refined petroleum products in the continental United States and in the Caribbean. We increase the utilization of our existing pipeline and terminalling assets by marketing refined petroleum products in certain areas served by our pipelines and terminals. The segment’s customers consist principally of product wholesalers and major commercial users of refined petroleum products including gasoline, natural gas liquids, ethanol, biodiesel and petroleum distillates such as heating oil, diesel fuel and kerosene. The segment also provides fuel oil supply, butane, and distribution services to customers in the Caribbean.

The Merchant Services segment owns three terminals in Pennsylvania with aggregate storage capacity of approximately 1 million barrels, which are operated by the Domestic Pipelines & Terminals segment. Each terminal is equipped with multiple storage tanks and automated truck loading equipment that is available 24 hours a day. We also own the property on which the terminals are located.

The following table sets forth the total gallons of refined petroleum products sold by the Merchant Services segment for the periods indicated (in millions of gallons):



	Year Ended December 31,
	2018	2017	2016
Sales volumes	1,231.7	1,214.8	1,179.7

Table of Contents

The Merchant Services segment’s operations are segregated into three categories based on the type of fuel delivered and the delivery method:


•	Wholesale — liquid fuels and propane gas are delivered to distributors and large commercial customers. These customers take delivery of the products using truck loading equipment at storage facilities;


•	Wholesale Delivered — liquid fuels are delivered to commercial customers, construction companies, school districts and trucking companies through third-party carriers; or via vessel using our marine terminals.


•	Branded Gasoline — gasoline and on-highway diesel fuel are delivered through third-party trucking companies to independently owned retail gas stations under many leading gasoline brands.

The operations of the Merchant Services segment expose us to commodity price risk. The commodity price risk is managed by entering into financial derivative instruments to offset the effect of commodity price fluctuations on the segment’s inventory and fixed price contracts. The fair value of our derivative instruments is recorded in our consolidated balance sheets, with the change in fair value recorded currently in earnings. The derivative instruments the Merchant Services segment uses consist primarily of futures contracts traded on the NYMEX for the purposes of managing our market price risk from holding physical inventory and entering into physical fixed-price contracts. A majority of the futures contracts executed are designated as fair value hedges of our refined petroleum inventory. The changes in fair value of the hedging instruments and hedged items are both recognized in cost of product sales. However, hedge accounting has not been elected for all of the Merchant Services segment’s derivative instruments. Fixed-price purchase and sales contracts are generally economically hedged with financial instruments; however, these instruments are not designated in a hedge relationship. In the cases in which hedge accounting has not been used for physical derivative contracts, changes in the fair values of the financial instruments, which are included in revenue and cost of product sales, generally are offset by changes in the values of the physical derivative contracts which are also derivative instruments whose changes in value are recognized in product sales or cost of product sales. In addition, hedge accounting has not been elected for financial instruments that have been executed to economically hedge a portion of the Merchant Services segment’s refined petroleum products held in inventory. The changes in value of the financial instruments that are economically hedging inventory are recognized in cost of product sales.

Competition and Customers

Competitive Strengths

We believe that we have the following competitive strengths:


•	We operate in a safe, regulatory compliant, and environmentally responsible manner;


•	We own and operate high quality assets that are strategically located;


•	We have stable, long-term relationships with our customers;


•	We own relatively predictable and stable fee-based businesses with opportunistic revenue generating capabilities that support distribution growth; and


•	We maintain a conservative financial position with an investment-grade credit rating.

Domestic Pipelines & Terminals Segment

Generally, pipelines are the lowest cost method for long-haul overland movement of liquid petroleum products. Therefore, the Domestic Pipelines & Terminals segment’s most significant competitors for large volume shipments are other pipelines, some of which are owned or controlled by major integrated oil and gas companies. Although it is unlikely that a pipeline system comparable in size and scope to the Domestic Pipelines & Terminals segment’s pipeline systems will be built in the foreseeable future, new pipelines (including pipeline segments that connect with existing pipeline systems) could be built to effectively compete with the Domestic Pipelines & Terminals segment in particular locations.

In addition to competition from other pipelines, the Domestic Pipelines & Terminals segment faces competition from trucks and rail in a number of areas that we serve. While their costs may not be competitive for longer hauls or large volume shipments, these sources of transportation compete effectively for smaller volumes in many local areas. The availability of truck or rail transportation places a competitive constraint on the ability of the Domestic Pipelines & Terminals segment to increase its market-based and indexed tariff rates.

The Domestic Pipelines & Terminals segment also faces competition from marine transportation in some areas. Tankers and barges account for some deliveries into areas that we serve near the East Coast, Great Lakes, Ohio River and Mississippi River.

Table of Contents

Privately arranged exchanges of liquid petroleum products between marketers in different locations are another form of competition. Generally, such exchanges reduce both parties’ costs by eliminating or reducing transportation charges. In addition, consolidation among refiners and marketers can alter distribution patterns, reducing demand for transportation services in some markets and increasing them in other markets.

The production and use of biofuels may be a competitive factor in that, to the extent the usage of biofuels increases, some alternative means of transport that compete with our pipelines may be able to provide transportation services for biofuels that our pipelines cannot because of safety or pipeline integrity issues. However, most of our terminals have the necessary infrastructure to blend ethanol with gasoline, and to a lesser extent biodiesel with distillates, and we earn revenue for these services. Biofuel usage may also create opportunities for additional pipeline transportation and blending opportunities, if such biofuels can be transported through our pipelines, although that potential cannot be quantified at present.

The Domestic Pipelines & Terminals segment also generally competes with other terminals in the same geographic market. Many competitive terminals are owned by major integrated oil and gas companies. These major oil and gas companies may have the opportunity for product exchanges that are not available to the Domestic Pipelines & Terminals segment’s terminals. While the Domestic Pipelines & Terminals segment’s terminal throughput fees are not regulated, they are subject to price competition from competitive terminals and alternate modes of transporting liquid petroleum products to end-users such as retail gasoline stations.

Global Marine Terminals Segment

Our Global Marine Terminals segment competes on the basis of geographic location, breadth of services, and price with proprietary or third-party terminal operators as well as with major oil and gas companies and with major pipeline and terminal operators in the energy hubs in which we operate. We believe that we are favorably positioned to compete in the industry on a global scale due to the quality and safety of our operations, the geographical locations of our facilities, deep drafts, storage capacity, and the variety of ancillary service capabilities of our facilities. The competitiveness of our service offerings, including the rates we charge for our services, is affected by the availability of storage relative to the overall demand for storage in a given market area and could be impacted by the entry of new competitors into the markets in which we operate. However, we believe that significant barriers to entry exist in the marine terminalling business. These barriers include capital costs, execution risk, a lengthy permitting and development cycle, financing challenges, shortage of personnel with the requisite expertise, and a finite number of sites suitable for development.

Our Corpus Christi facility, owned by Buckeye Texas, is fully contracted under long-term, take-or-pay arrangements. There is no current or near-term capacity available for new customers.

Merchant Services Segment

The Merchant Services segment competes with major energy companies, their marketing affiliates and independent gatherers, investment banks that have established trading platforms, master limited partnerships with marketing businesses, and brokers and marketers of widely varying sizes, financial resources and experience. Some of these competitors have capital resources greater than the Merchant Services segment, and control greater supplies of refined petroleum products.

Customers

For the years ended December 31, 2018, 2017 and 2016, no customer contributed 10% or more of our consolidated revenue. Revenue from Buckeye Texas, which is almost fully contracted to one customer under long-term take-or-pay arrangements, accounted for approximately 47% of total revenue in the Global Marine Terminals segment for the year ended December 31, 2018.

BBH’s revenue accounted for approximately 25% of total revenue in the Global Marine Terminals segment for the year ended December 31, 2018. Currently, BBH has a limited number of long-term storage customers, consisting of major oil companies, energy companies, physical traders and national oil companies. For the year ended December 31, 2018, approximately 33% of BBH’s revenue was derived from its top customer.

Table of Contents

Seasonality

The Domestic Pipelines & Terminals segment’s mix and volume of products transported and stored tends to vary seasonally. Declines in demand for heating oil during the summer months are, to a certain extent, offset by increased demand for gasoline and jet fuel. Overall, this segment’s business has been only moderately seasonal, with somewhat lower than average volumes being transported and stored during March, April and May and somewhat higher than average volumes being transported and stored in November, December and January.

The Merchant Services segment’s mix and volume of product sales tend to vary seasonally, with the fourth and first quarters’ volumes generally being higher than the second and third quarters, primarily due to the increased demand for home heating oil in the winter months.

The Domestic Pipelines & Terminals and Merchant Services segments both benefit from increased sales of heating oil and butane blending activities at our terminals during the winter months. Blending butane into various grades of gasoline generally increases in the mid-September through mid-March time frame.

The Global Marine Terminals segment’s mix and volume of products stored does not vary significantly by season; however, it can be affected by market structure.

Employees

Except as noted below, we are managed and operated by employees of Buckeye Pipe Line Services Company (“Services Company”). We reimburse Services Company for the cost of providing employee services pursuant to a services agreement. At December 31, 2018, Services Company had approximately 1,600 employees, approximately 280 of whom were represented by labor unions. Additionally, at December 31, 2018, certain of our wholly owned subsidiaries had approximately 250 employees, approximately 150 of whom were employed at our BBH facility. We have not experienced significant work stoppages or other labor problems.

Regulation

General

The operation of pipelines, terminals, and associated facilities is subject to extensive laws and regulations, resulting in regulatory oversight by numerous federal, state and local departments and agencies, many of which are authorized by statute to issue binding rules and regulations. In some states, we are subject to the jurisdiction of public utility commissions and state corporation commissions, which have authority over, among other things, intrastate tariffs, the issuance of debt and equity securities, transfers of assets and safety. The failure to comply with such laws and regulations can result in substantial penalties. The regulatory burden on our operations increases our cost of doing business and, consequently, affects our profitability. However, except for certain exemptions that apply to smaller companies, we do not believe that we are affected in a significantly different manner by these laws and regulations than are our competitors.

The following is a discussion of certain laws and regulations affecting us. However, this discussion should not be relied upon as an exhaustive review of all regulatory considerations affecting our business and operations.

Rate Regulation

Overview. BPLC, Wood River, BPL Transportation, Buckeye Linden and NORCO operate pipelines subject to the regulatory jurisdiction of the Federal Energy Regulatory Commission (“FERC”) under the Interstate Commerce Act, the Energy Policy Act of 1992 and the Department of Energy Organization Act. FERC regulations require that interstate oil pipeline rates be posted publicly and that these rates be “just and reasonable” and not unduly discriminatory. FERC regulations also enforce common carrier obligations and specify a uniform system of accounts, among certain other obligations.

The generic oil pipeline regulations issued under the Energy Policy Act of 1992 rely primarily on an index methodology that allows a pipeline to change its rates in accordance with an index that the FERC believes reflects cost changes appropriate for application to pipeline rates. In December 2015, the FERC amended its regulations to change the index to the Producer Price Index (“PPI”) - finished goods plus 1.23% effective July 1, 2016.

Table of Contents

The indexing methodology is used to establish rates on the pipelines owned by BPL Transportation and NORCO, and for certain rates charged by Wood River and BPLC, and such rates are therefore subject to change annually according to the index. If the index is negative in a future period, we could be required to reduce these rates if they exceed the new maximum allowable rate. Shippers may file protests against the application of the index to the rates of an individual pipeline and may also file complaints against indexed rates as being unjust and unreasonable, subject to the FERC’s standards.

Under the FERC’s rules, as one alternative to indexed rates, a pipeline is allowed to charge market-based rates if the pipeline establishes that it does not possess significant market power in a particular market. BPLC charges market-based rates in its competitive markets and index-based rates in certain of its other markets. Buckeye Linden also charges market-based rates in its market. Wood River charges settlement rates in its market.

Other types of rate regulation. Laurel operates a pipeline in intrastate service across Pennsylvania, and its tariff rates are regulated by the Pennsylvania Public Utility Commission. Wood River operates a pipeline providing some intrastate services in Illinois, and tariff rates related to this pipeline are regulated by the Illinois Commerce Commission.

Environmental Regulation

General

We are subject to federal, state and local laws and regulations relating to the protection of the environment. Although we believe that our operations comply in all material respects with applicable environmental laws and regulations, risks of substantial environmental liabilities are inherent in pipeline, terminalling and processing operations, and we may incur material environmental liabilities in the future. It is possible that other developments, such as increasingly rigorous environmental laws, regulations and enforcement policies, and claims for damages to property or injuries to persons resulting from our operations, could result in substantial costs and liabilities to us. Furthermore, new projects may require approvals and environmental analysis under federal and state laws, including the National Environmental Policy Act and the Endangered Species Act. The resulting costs and delays could materially and negatively affect the viability of such projects. The following is a summary of the significant current environmental laws and regulations to which our business operations are subject and for which compliance may require material capital expenditures or have a material adverse impact on our results of operations or financial position.

Water

The Oil Pollution Act of 1990 (“OPA”) amended certain provisions of the federal Water Pollution Control Act of 1972, commonly referred to as the Clean Water Act (“CWA”), and other statutes, as they pertain to the prevention of and response to petroleum product spills into navigable waters. The OPA subjects owners of facilities to strict joint and several liability for all containment and clean-up costs and certain other damages arising from a spill. The CWA provides penalties for the discharge of petroleum products in reportable quantities and imposes substantial liability for the costs of removing a spill. State laws for the control of water pollution also provide varying civil and criminal penalties and liabilities in the case of releases of petroleum or its derivatives into surface waters or into the ground.

Contamination resulting from spills or releases of liquid petroleum products sometimes occurs in the petroleum pipeline, terminalling and processing industry. Our pipelines cross, and certain facilities are located near, numerous navigable rivers and streams. Although we believe that we comply in all material respects with the spill prevention, control and countermeasure and facility response plan requirements of federal laws, any spill or other release of petroleum products into navigable waters may result in material costs and liabilities to us.

Hazardous Substances and Wastes

The Resource Conservation and Recovery Act (“RCRA”), as amended, establishes a comprehensive program of regulation of “hazardous wastes.” Hazardous waste generators, transporters, and owners or operators of hazardous waste treatment, storage and disposal facilities must comply with regulations designed to ensure detailed tracking, handling and monitoring of these wastes. RCRA also regulates the disposal of certain non-hazardous wastes. As a result of these regulations, certain wastes typically generated by pipeline, terminalling and processing operations are considered “hazardous wastes,” “special wastes” or regulated solid waste. Hazardous wastes are subject to more rigorous and costly disposal requirements than are non-hazardous wastes. Changes in any of the RCRA regulations to, for example, expand the universe of regulated wastes or impose more stringent management requirements, could have a material adverse effect on our maintenance capital expenditures and operating expenses.

Table of Contents

The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”), also known as “Superfund,” authorizes the federal and state governments to address the release or threat of release of a “hazardous substance.” Although CERCLA contains a “petroleum exclusion,” that provision generally applies only to unused product not contaminated by contact with other substances, and may exclude product recovered after a release, as well as contact water. A release of a hazardous substance, whether on or off-site, may subject the generator of that substance or the owner of the property on which the release occurred to joint and several liability under CERCLA for the costs of clean-up and other remedial action. Pipeline and facility maintenance and other activities in the ordinary course of our business generate “hazardous substances.” As a result, to the extent a hazardous substance generated by us or our predecessors is released or was released or otherwise disposed of in the past, we may in the future be required to remediate the contaminated property. Governmental authorities such as the Environmental Protection Agency (“EPA”), and in some instances third parties, are authorized under CERCLA to seek to recover remediation and other costs from responsible persons, without regard to fault or the legality of the original disposal. In addition to our potential liability as a generator of “hazardous substances,” to the extent that our property or right-of-way is affected by a release of hazardous substances such that it becomes part of a Superfund or other hazardous waste site, we may be responsible under CERCLA for all or part of the costs required to clean up that site, which could be material.

Air Emissions

The Clean Air Act (“CAA”), amended by the Clean Air Act Amendments of 1990 (the “Amendments”), imposes controls on the emission of pollutants into the air. The Amendments required states to develop facility-wide permitting programs to comply with a wide range of federal air pollution regulatory programs. States also have their own air pollution regulatory programs that impose permitting and control requirements in addition to the federal requirements.

Due to differing EPA air quality standards in certain areas of the country, obtaining permits for constructing new emitting facilities or increasing emissions at existing facilities may be more complicated and may require more expensive emission controls than in other areas.

EPA has also promulgated greenhouse gas (“GHG”) regulations and is otherwise increasing its scrutiny of the oil and gas industry. In addition, certain states and regions have adopted or are considering various GHG regulations which may require controls separate from or in conjunction with federal programs.

It is possible that new or more stringent controls will be imposed on us through these programs which could have a material adverse effect on our maintenance capital expenditures and operating expenses.

State, Local and Foreign Regulations

We are also subject to other environmental laws and regulations adopted by the various states, localities and territories in which we operate. In certain instances, the regulatory standards adopted by the states and/or territories are more stringent than applicable federal laws. In addition, our BBH terminal in The Bahamas and our St. Lucia terminal are subject to the environmental regulatory programs applicable in those countries. While these regulatory programs are today less stringent than in the United States, they have the potential to impose material liabilities on us, particularly in the event of a spill or other release, and if they are made more stringent in the future, we could be required to make significant capital expenditures to meet the new standards.

Pipeline and Terminal Maintenance and Safety Regulation

The pipelines we operate are subject to regulation by the U.S. Department of Transportation (“DOT”), its agency, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), and state pipeline regulatory bodies as appropriate and consistent with the federal Pipeline Safety Act (“PSA”). The PSA and PHMSA implementing regulations govern the design, installation, testing, construction, operation, replacement and management of pipeline facilities and require any entity that owns or operates pipeline facilities to comply with applicable safety standards, to establish and maintain plans for inspection and maintenance and to comply with such plans and programs. Among others, these programs include: construction, operation and maintenance, integrity management for pipelines located in high consequence areas, operator qualification, control room management, public awareness, and drug and alcohol. Certain states in which we operate participate in oversight and inspection of intrastate and interstate pipeline facilities through certifications and agreements with PHMSA. For intrastate pipelines located in PHMSA certified states, the State may impose additional or more stringent pipeline safety regulations as long as they are not inconsistent with PHMSA standards.

Table of Contents

We believe that we currently comply in all material respects with the pipeline safety laws and regulations. However, the industry, including us, will likely incur additional pipeline and tank integrity expenditures in the future, and we are likely to incur increased operating costs based on the implementation of PHMSA and other government regulations.

The PSA was amended in 2011 and again in 2016. Combined, those statutory amendments have extended the jurisdictional reach of federal pipeline regulation, and mandated additional rulemaking by PHMSA. PHMSA issued two Interim Final Rules in 2016, including its new ability to issue ‘Emergency Orders’ without prior notice or hearing and to establish minimum standards for underground natural gas storage.

In 2017, PHMSA issued final rules to, among other things, address incident notification, which would impact both gas (49 CFR Part 192) and liquid regulations (49 CFR Part 195), and liquid pipeline integrity assessment, integrity management, and leak detection requirements. Rules regarding incident notification, among other things, were issued in January 2017 and became effective in March 2017. PHMSA issued a pre-publication copy of another final rule on liquid pipeline issues in January 2017. Before that rule became effective, the new Administration issued an Executive Order on January 20, 2017, freezing all pending federal rules. PHMSA subsequently withdrew the rule in light of the Administration’s Executive Orders on deregulation, but the agency plans to finalize a version of that rule in 2019. Because parts of the new PHMSA rule were directed by Congressional mandates which are to be exempt from the regulatory freeze, it is not yet clear whether and to what extent the final rule will continue to be subject to the regulatory freeze, or be allowed to become effective. The PSA is up for reauthorization again in 2019. Although no new statutory amendments have been proposed, Congress may add new obligations that could result in additional expenditures in the future.

Safety

We are also subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. At qualifying facilities, we are subject to OSHA Process Safety Management regulations that are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. We believe that our operations comply in all material respects with applicable OSHA requirements, including general industry standards, record-keeping and the training and monitoring of occupational exposures.

We cannot predict whether or in what form any new legislation or regulatory requirements might be enacted or adopted or the costs of compliance. In general, any such new regulations could increase operating costs and impose additional capital expenditure requirements, but we do not presently expect that such costs or capital expenditure requirements would have a material adverse effect on our results of operations or financial condition.

Environmental Hazards and Insurance

Our business involves a variety of risks, including the risk of natural disasters, adverse weather, fire, explosions, and equipment failures, any of which could lead to environmental hazards such as crude oil and petroleum product spills and other releases. If any of these should occur, we could incur legal defense costs and environmental remediation costs, and could be required to pay amounts due to injury, loss of life, damage or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations.

We are covered by site pollution legal liability insurance policies with per incident and aggregate limits of $100.0 million, subject to a maximum self-insured retention of $5.0 million. The policies include coverage for sudden and accidental or gradual releases at our listed sites, and also include a contractor’s pollution coverage endorsement. The policies insure: (i) claims, remediation costs, and associated legal defense expenses for pollution conditions at, or migrating from, a covered location, and (ii) the transportation risks associated with moving waste from a covered location to any location for unloading or disposal. The site pollution legal liability policies contain exclusions, conditions, and limitations that could apply to a particular pollution claim, and may not cover all claims or liabilities we incur. The insurance policies expire on May 1, 2019.

In addition to the site pollution legal liability insurance policies, we maintain excess liability insurance policies that provide coverage for claims involving sudden and accidental releases with aggregate and per occurrence limits of $375.0 million. Coverage under the excess liability insurance policies is secondary to the site pollution legal liability policies for sudden and accidental releases. The pollution coverage provided in the excess liability insurance policies contain exclusions, definitions, conditions and limitations that could apply to a particular pollution claim, and may not cover all claims or liabilities we incur. The insurance policies expire on May 1, 2019.

Table of Contents

We generally are not entitled to seek indemnification from our contractual counterparties for any environmental damage caused by the release of products we store, throughput or transport for such counterparties. As discussed above, we maintain insurance policies that are designed to mitigate the risk that we may incur in connection with any such release of products from our facilities, and we believe that the policy limits under site pollution legal liability and excess liability insurance policies are within the range that is customary for entities of our size that operate in our business segments and are appropriate for our business.

We attempt to reduce our exposure to third-party liability by requiring indemnification and access to third party insurance from our contractors or entities who require access to our facilities and our right-of-way. We have requirements for limits of insurance provided by third parties which we believe are in accordance with industry standards and proof of third-party insurance documentation is retained prior to commencement of work.

We have written plans for responding to emergencies along our pipeline systems and at our terminalling and processing facilities. These plans, which describe the organization, responsibilities and actions for responding to emergencies, are reviewed annually and updated as necessary. Our facilities are designed with product containment structures, and we maintain various additional crude oil containment and recovery equipment that would be deployed in the event of an emergency. We are a member of oil spill cooperatives or mutual aid groups, and we maintain contract relationships with United States Coast Guard certified spill response organizations, spill response contractors and remediation management consultants. We also contract with a third-party to provide enterprise-wide emergency spill response services for certain incidents, which includes the strategic staging of response equipment at our BBH, Yabucoa and St. Lucia terminals. This service contract provides access to additional local United States Coast Guard certified spill response organizations. This further ensures access to spill response equipment (including boom, recovery pumps, response vehicles, response vessels and response trailers), monitoring and sampling equipment, personal protective equipment and technical expertise needed to respond to an emergency event. We also perform spill response drills to review and exercise the response capabilities of our personnel, contractors and emergency management agencies. Additionally, we have a Crisis Management Team within our organization to provide strategic direction, ensure availability of company resources and manage communications in the event of an emergency situation.

Available Information

We file annual, quarterly and current reports and other documents with the SEC under the Securities Exchange Act of 1934. The public can obtain any documents that we file with the SEC at www.sec.gov. We also make available free of charge our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after filing such materials with, or furnishing such materials to, the SEC, on or through our internet website, www.buckeye.com. We are not including the information contained on our website as a part of, or incorporating it by reference into, this Report.

You can also find information about us at the offices of the NYSE, 20 Broad Street, New York, New York 10005 or at the NYSE’s internet website, www.nyse.com.

Table of Contents

Item 1A. Risk Factors

There are many factors that may affect us and investments in us. Security holders and potential investors in our securities should carefully consider the risk factors set forth below, as well as the discussion of other factors that could affect us or investments in us included elsewhere in this Report. If one or more of these risks were to materialize, our business, financial position or results of operations could be materially and adversely affected. We are identifying these risk factors as important risk 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.

Risks Inherent in our Business

Changes in petroleum demand and distribution and weakness in the United States economy may adversely affect our business.

Demand for the services we provide depends upon the demand for the products we handle in the regions we serve and the supply of products in the regions connected to our pipelines or from which our customers source products handled by our terminals. Prevailing economic conditions, refined petroleum product, fuel oil and crude oil price levels and weather affect the demand for liquid petroleum products. Changes in transportation and travel patterns in the areas served by our pipelines also affect the demand for petroleum products because a substantial portion of the refined petroleum products transported by our pipelines and throughput at our terminals is ultimately used as fuel for motor vehicles and aircraft. If these factors result in a decline in demand for refined petroleum products, our pipeline and terminals business would be particularly susceptible to adverse effects because we operate without the benefit of exclusive franchises from government entities and generally without long-term contracts.

Demand for the services we provide in the Caribbean is partially driven by global demand for crude oil and other refinery feedstocks supplied from United States and Latin American crude oil production, and by Latin American demand for clean petroleum products supplied from the United States and European refinery output. Changes in these and other global patterns of supply and demand for fuel oil, crude oil and clean petroleum products could affect the demand for the services we provide in the Caribbean and the prices we can charge for those services.

In recent years, the federal government has enacted renewable fuel or energy efficiency statutory mandates that may have the impact over time of reducing the demand for fuel oil or clean refined petroleum products, particularly with respect to gasoline, in certain markets. Other legislative changes may similarly alter the expected demand and supply projections for refined petroleum products in ways that cannot be predicted.

Energy conservation, changing sources of supply, structural changes in the oil industry and new energy technologies also could adversely affect our business. We cannot predict or control the effect of these factors on us.

Economic conditions worldwide have from time to time contributed to slowdowns in the oil and gas industry, as well as in the specific segments and markets in which we operate, resulting in reduced oil production, reduced supply or demand and increased price competition for our products and services. In addition, economic conditions could result in a loss of customers in our operating segments because their access to the capital necessary to purchase services we provide is limited. Our operating results may also be affected by uncertain or changing economic conditions in certain regions of the United States. If global economic and market conditions (including volatility or sustained weakness in commodity markets) or economic conditions in the United States remain uncertain or persist, spread or deteriorate further, we may experience material impacts on our business, financial condition, results of operations or cash flows.

A significant decline in production at certain refineries served by certain of our pipelines and terminals, disruptions at facilities on which our customers rely, or a fundamental change in the source of supply of petroleum products to a region, could materially reduce the volume of liquid petroleum products we transport and adversely impact our operating results.

Refineries that are the primary source of supply of product to our pipelines and terminals could partially or completely shut down their operations, temporarily or permanently, due to factors such as unscheduled maintenance, catastrophes, labor difficulties, environmental proceedings or other litigation, loss of significant downstream customers; or legislation or regulation that adversely impacts the economics of refinery operations. For example, a significant decline in production at the Wood River refinery, Whiting refinery, Paulsboro refinery or Lima refinery could negatively impact the financial performance of such assets and adversely affect our business, financial position, results of operations or cash flows.

Table of Contents

In addition, if there is a fundamental shift in the primary source of supply of petroleum products to a region our pipelines serve and our pipeline infrastructure in the region is not well-suited to serve the new primary source, the performance of such assets could be negatively impacted, and adversely affect our business, financial position, results of operations and cash flows.

Furthermore, our customers are dependent upon the ongoing operations of certain facilities owned or operated by such customers or third parties, such as the pipelines, barges and retail fuel distribution assets, as well as refineries and other facilities that generate products our customers handle. Any significant interruption at these facilities or inability to transport products to or from these facilities or to or from our customers for any reason would adversely affect our customers’ operations, and possibly cash flow and in turn this could affect our operations and cash flow and ability to make distributions to our unitholders. Operations at our facilities and at the facilities owned or operated by our customers and their suppliers could be partially or completely shut down, temporarily or permanently, as the result of any number of circumstances that are not within our control.

Competition could adversely affect our operating results.

Our Domestic Pipelines & Terminals and Global Marine Terminals segments compete with other existing pipelines and terminals that provide similar services in the same markets as our assets. In addition, our competitors could construct new assets or redeploy existing assets in a manner that would result in more intense competition in the markets we serve. We compete with other transportation, storage and distribution alternatives on the basis of many factors, including but not limited to rates, service levels, geographic location, connectivity and reliability. Our customers could utilize the assets and services of our competitors instead of our assets and services, or we could be required to lower our prices or increase our costs to retain our customers.

Our Merchant Services segment buys and sells refined petroleum products in connection with its marketing activities, and must compete with major energy companies, their marketing affiliates, and independent brokers and marketers of widely varying sizes, financial resources and experience. Some of these companies have superior access to capital resources, which could affect our ability to effectively compete with them.

All of these competitive pressures could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We are a holding company and depend entirely on cash flows from our operating subsidiaries to service our debt obligations and pay cash distributions to our unitholders. Our distributions are not guaranteed.

We are a holding company with no material operations, and, as a result, our ability to pay distributions to our unitholders and to service our debt obligations is dependent upon the earnings and cash flows of our operating subsidiaries. If we do not receive distribution of earnings, loans or other payments from our operating subsidiaries, we will not be able to meet our debt service obligations or to make cash distributions to our unitholders. Among other things, this would adversely affect the market price of our LP Units. We are currently bound by the terms of our Credit Facility, which prohibit us from making distributions to our unitholders if a default under the Credit Facility exists at the time of the distribution or would result from the distribution. Our operating subsidiaries may from time to time incur additional indebtedness under agreements that contain restrictions which could further limit each operating subsidiary’s ability to make distributions to us.

Our distributable cash flow does not depend solely on profitability, which is affected by non-cash items. As a result, we could pay cash distributions during periods when we record net losses and could be unable to pay cash distributions during periods when we record net income. In addition, the amount of cash we generate from operations is affected by numerous factors beyond our control, fluctuates from quarter to quarter and may change over time. Significant or sustained reductions in the cash generated by our operations could reduce our ability to pay quarterly distributions. Any failure to pay distributions at expected levels could result in a loss of investor confidence and a decrease in the value of our unit price.

We may incur unknown and contingent liabilities from assets we have acquired.

Some of the assets we have acquired have been used for many years to distribute, store or transport petroleum products. Releases from terminals or along pipeline rights-of-way may have occurred prior to our acquisition. In addition, releases may have occurred in the past that have not yet been discovered, which could require costly future remediation.

We perform a certain level of diligence in connection with our acquisitions and attempt to ascertain the extent of liabilities that might be associated with an acquired facility, but there may be unknown and contingent liabilities related to our acquisitions of which we are unaware.

Table of Contents

If a significant release or event occurred in the past at any of our acquired assets and we are responsible for all or a significant portion of the liability associated with such release or event, it could adversely affect our business, financial position, results of operations and cash flows. We could be liable for unknown obligations relating to any of our acquired assets, for which indemnification or insurance is not available, which could materially adversely affect our business, financial condition, results of operations or cash flow.

If we incorrectly predict the future results of acquired operations or assets, we may not realize all of the benefits we expect from an acquisition. We may make dispositions on terms that are less favorable than we anticipated.

Part of our business strategy includes making acquisitions and, when appropriate, dispositions. In evaluating acquisitions and dispositions, we prepare one or more financial cases based on a number of business, industry, economic, legal, regulatory, and other assumptions applicable to the proposed transaction. Although we expect a reasonable basis will exist for those assumptions, the assumptions typically involve current estimates of future conditions. Many assumptions are beyond our control and may not materialize. Because of the uncertainty and risk of inaccuracy associated with these assumptions, including financial projections, we may not realize the full benefits we anticipate from an acquisition, or we may encounter unanticipated difficulties locating buyers and securing favorable terms for dispositions, each of which could materially adversely affect our business, financial condition, results of operations or cash flow. Dispositions may also involve continued financial involvement in the divested business, such as through continuing minority equity ownership, guarantees, indemnities or other financial obligations. Under these arrangements, performance by the divested businesses or other conditions outside of our control could adversely affect our future financial results.

Potential future acquisitions and organic growth projects, if any, may affect our business by substantially increasing the level of our indebtedness and contingent liabilities and increasing the risks of our being unable to effectively complete and integrate these new operations.

From time to time, we evaluate and acquire assets and businesses that we believe complement our existing assets and businesses. If we consummate any future acquisitions, our capitalization and results of operations may change significantly. We also routinely execute organic growth projects that complement our existing assets. Our decisions regarding new organic growth projects rely on numerous estimates, including predictions of future demand for our services, future supply shifts, crude oil and refined products production estimates, commodity price environments, economic conditions and potential changes in the financial condition of our customers. Our predictions of such factors could cause us to forgo certain investments or to lose opportunities to competitors who make investments based on more aggressive predictions. Acquisitions and organic growth projects, including the integration of assets into our existing businesses, may require substantial capital.

Acquisitions and organic growth projects involve numerous risks, including difficulties in the assimilation of the assets and operations of the acquired businesses, inefficiencies and difficulties that arise because of unfamiliarity with new assets and the businesses associated with them and new geographic areas and the diversion of management’s attention from other business concerns. Further, we may experience unanticipated delays in realizing the benefits of an acquisition or project or we may be unable to integrate certain assets to the extent such assets relate to a business for which we have no or limited experience. Our failure to properly assess the levels of capital or time required to acquire or build and integrate these assets, or our failure to accurately predict the returns from these assets could have an adverse effect on our business, financial condition, results of operations or cash flows.

Debt securities we issue are, and will continue to be, junior to claims of our operating subsidiaries’ creditors.

Our outstanding debt securities are structurally subordinated to the claims of our operating subsidiaries’ creditors. In addition, any debt securities we issue in the future will likewise be subordinated in the same manner. Holders of the debt securities will not be creditors of our operating subsidiaries. Our claim to the assets of our operating subsidiaries derives from our own ownership interests in those operating subsidiaries. Claims of our operating subsidiaries’ creditors will generally have priority as to the assets of our operating subsidiaries over our own ownership interests and will therefore have priority over the holders of our debt, including our debt securities.

Table of Contents

Limited access to the debt and equity markets or adverse credit events could adversely affect our business.

Our ability to acquire assets or businesses or make other growth capital investments depends on whether we can access adequate financing. Changes in the debt and equity markets, including market disruptions, limited liquidity, and interest rate volatility, may limit our access to the capital markets, increase the cost of financing and adversely impact our ability to refinance maturing debt. Instability in the financial markets may increase our cost of capital while reducing the availability of funds, affecting our ability to raise capital. If access to the debt and equity markets were limited or not available, our ability to grow our business through acquisitions or other capital investments could be restricted, and it is not certain if other adequate financing options would be available to us on terms and conditions that are acceptable. Any disruption could require us to take additional measures to conserve cash until the markets stabilize or until we can arrange alternative credit arrangements or other funding for our business needs. Such measures could include reducing or delaying investment activities, reducing our operating expenses, limiting our distributions or reducing other uses of cash. Furthermore, a downgrade below our current ratings levels by any of the credit rating agencies could increase our borrowing costs, reduce our borrowing capacity and cause our counterparties to reduce the amount of open credit we receive from them. This could negatively impact our ability to capitalize on market opportunities. Loss of our investment-grade credit rating could also adversely impact our cash flows, our ability to make distributions at our current levels and the value of our outstanding equity and debt securities. Under such circumstances, we may be unable to execute our growth strategy or take advantage of other business opportunities, which could negatively impact our business.

Our rate structures are subject to regulation and change by FERC; required changes could be adverse.

BPLC, Wood River, BPL Transportation, Buckeye Linden and NORCO are interstate common carriers regulated by FERC under the Interstate Commerce Act, the Energy Policy Act of 1992 and the Department of Energy Organization Act. FERC’s primary ratemaking methodology is indexing rates for inflation. Where circumstances justify it, FERC permits pipelines to use one of three alternatives to index-based rates: market-based, cost-based, or settlement-based rates. A pipeline is allowed to charge (1) market-based rates if the pipeline establishes that it does not possess significant market power in a particular market, (2) cost-based rates if the pipeline establishes that its costs substantially exceed its indexed rates, and (3) settlement-based rates if the rates are agreed by all shippers receiving a service.

The indexing methodology is used to establish rates on pipelines owned by BPL Transportation and NORCO, and for certain rates charged by Wood River and BPLC. In December 2015, FERC amended its regulations to change the index to the Producer Price Index (“PPI”) — finished goods plus 1.23% effective July 1, 2016. If the index were to be negative, we could be required to reduce the rates charged by BPL Transportation and NORCO, and certain rates charged by Wood River and BPLC, if they exceed the new maximum allowable rate. In addition, changes in the PPI might not fully reflect actual increases in the costs associated with these pipelines, thus potentially hampering our ability to recover our costs by relying on the index.

In addition to the risks described above, at any time shippers on any of our FERC-regulated pipelines have the right to challenge the application of the index to a pipeline’s rates or the underlying rates themselves as being unjust and unreasonable, subject to the FERC’s cost-of-service standards or that market-based authority is no longer justified because we possess significant market power in a particular market. Such shipper challenges may seek adjustments to our rates prospectively and, subject to limitations, for certain past periods. If a significant shipper challenge were to result in an outcome that is unfavorable to us, our business, financial condition, results of operations and/or cash flows could be adversely impacted.

Climate change legislation or regulations restricting emissions of GHGs or setting fuel economy or air quality standards could result in increased operating costs or reduced demand for the liquid petroleum products and other hydrocarbon products that we transport, store or otherwise handle in connection with our business.

In recent years, federal authorities such as the EPA and various state regulatory bodies have increasingly sought to regulate emissions of carbon dioxide, methane and other GHGs. Such regulation has targeted emissions from large industrial sources, such as factories, refineries and other manufacturing facilities, and for increasingly large classes of motor vehicles. Numerous proposals have been made and could continue to be made at the international, federal, state, and local levels of government to monitor and limit emissions of GHGs, which include carbon dioxide and methane. These efforts have included consideration of cap-and-trade programs, carbon taxes and GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources.

Table of Contents

While most of the currently effective regulations have not had a material effect on our operations, expansions of the existing regulations or any future laws or regulations that may be adopted to address GHG emissions could require us to incur additional costs to reduce emissions of GHG associated with our operations. The effect on our operations could include increased costs to operate and maintain our facilities, measure and report our emissions, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay any taxes related to our greenhouse gas emissions and administer and manage a GHG emissions program. While we may be able to include some or all of such increased costs in the rates we charge, such recovery of costs is uncertain and may depend on events beyond our control, including the outcome of future rate proceedings before the FERC and the provisions of any final regulations. In addition, laws or regulations regarding fuel economy, air quality or GHG gas emissions (for motor vehicles or otherwise) could include efficiency requirements or other methods of curbing carbon emissions that could adversely affect demand for the liquid petroleum products and other hydrocarbon products that we transport, store or otherwise handle in connection with our business. A significant decrease in demand for petroleum products would have a material adverse effect on our business, financial condition, results of operations or cash flows.

In addition to the regulatory and associated financial risks from climate change discussed above, the effects of climate change may have significant physical impacts, such as an increase in sea level, wetland and barrier island erosion, flooding and increased frequency and severity of storms. We own assets and have employees in, and serve, communities that are at risk of being adversely affected by the physical impacts of climate change and, if any such effects were to occur, they could have an adverse impact on our assets and operations.

Environmental regulation may impose significant costs and liabilities on us.

We are subject to federal, state and local laws and regulations relating to the protection of the environment. Risks of substantial environmental liabilities are inherent in our operations, and we cannot assure you that we will not incur material environmental liabilities. Additionally, our costs could increase significantly, and we could face substantial liabilities, if, among other developments, environmental laws, regulations and enforcement policies become more rigorous; or claims for property damage or personal injury resulting from our operations are asserted against us.

Existing or future state or federal government regulations relating to certain chemicals or additives in gasoline or diesel fuel could require capital expenditures or result in lower pipeline volumes and thereby adversely affect our results of operations and cash flows.

Changes made to governmental regulations governing the components of liquid petroleum products may necessitate changes to our pipelines and terminals which may require significant capital expenditures or result in lower pipeline volumes. For instance, the increasing use of ethanol as a fuel additive, which is blended with gasoline at product terminals, may lead to reduced pipeline volumes and revenue which may not be totally offset by increased terminal blending fees we may receive at our terminals.

DOT and state-level regulations may impose significant costs and liabilities on us.

Our pipeline operations are subject to regulation by the DOT and by some of the states in which we do business. Certain states have been reviewing pipeline safety regulations and increasing inspections and audits. These federal regulations require, among other things, that pipeline operators engage in a regular program of pipeline integrity testing and other inspections to assess, evaluate, repair and validate the integrity of their pipelines, which, in the event of a leak or failure, could affect populated areas, unusually sensitive environmental areas or commercially navigable waterways. In compliance with these regulations, we conduct pipeline integrity tests on an ongoing and regular basis. Depending on the results of these integrity tests, we could incur significant and unexpected capital and operating expenditures, not accounted for in anticipated capital or operating budgets, in order to repair such pipelines to ensure their continued safe and reliable operation. In addition, any new regulations that are the result of PSA 2011, 2016 or any subsequent PSA reauthorization laws in the 2019 reauthorization or new DOT pipeline safety regulations may affect our operations.

Table of Contents

Our international operations may be adversely affected by economic, political and regulatory developments.

Our international operations include BBH’s marine terminal facility in the Bahamas and our marine terminal facility in St. Lucia. As a result, we are exposed to the risks of international operations, including political, economic and regulatory developments and changes in laws or policies affecting our terminalling operations, restrictions on foreign exchange and repatriation, as well as changes in domestic and foreign governmental laws, regulations, sanctions and embargoes. Any such developments or changes could limit or disrupt markets for our operations, restrict payments or limit the movement of funds, or impose sanctions on our ability to conduct business with certain customers or persons, which, in turn, could have a material adverse effect on our business, results of operations and cash flow.

Compliance with laws and regulations that apply to our international operations increases the cost of doing business and could interfere with our ability to offer services or expose us to fines and penalties. These numerous laws and regulations include the Foreign Corrupt Practices Act and local laws prohibiting corrupt payments to government officials or agents. Although policies designed to fully ensure compliance with these laws are in place, employees, contractors, or agents may violate the policies. Any such violations could include prohibitions on our ability to offer services internationally and could have a material adverse effect on our business, financial results and cash flow.

We may not be able to fully implement or capitalize upon planned organic growth projects.

We have a number of organic growth projects that involve the construction, expansion or modification of existing assets. Many of these projects involve numerous regulatory, environmental, commercial, economic, weather-related, political and legal uncertainties that are beyond our control, including the following:


•	As these projects are undertaken, required state, federal and other approvals, permits and licenses may not be obtained, we may not be able to fully implement or capitalize upon certain projects, and projects may also be delayed or may be obtained with conditions that materially alter the expected return associated with the underlying projects;


•	A depressed crude oil price environment may make it more difficult for producers and other customers to commit to long-term contracts that provide commercial support for certain organic growth projects.


•	Despite the fact that we will expend significant amounts of capital during the construction phase of these projects, revenues associated with these organic growth projects will not materialize until the projects have been completed and placed into commercial service, and the amount of revenue generated from these projects could be significantly lower than anticipated for a variety of reasons;


•	We may not be able to secure, or we may be significantly delayed in obtaining, all of the rights of way or other real property interests we need to complete such projects, or the costs we incur in order to obtain such rights of way or other interests may be greater than we anticipated;


•	We may construct pipelines, facilities or other assets in anticipation of market demand that dissipates or market growth that never materializes;


•	Due to unavailability or costs of materials, supplies, power, labor or equipment, the cost of completing these projects could turn out to be significantly higher than we budgeted and the time it takes to complete construction of these projects and place them into commercial service could be significantly longer than planned; and


•	The completion or success of our projects may depend on the completion or success of third-party facilities over which we have no control.

As a result of these uncertainties, the anticipated benefits associated with our capital projects may not be achieved. In turn, this could negatively impact our cash flow and our ability to make or increase cash distributions to our unitholders.

Table of Contents

The results of our Merchant Services segment could be adversely affected by volatility in the price of refined petroleum products.

The Merchant Services segment buys and sells refined petroleum products in connection with its marketing activities. If the values of refined petroleum products change in a direction or manner that we do not anticipate, we could experience financial losses from these activities. Furthermore, when refined petroleum product prices decrease rapidly, we may be unable to promptly pass our additional costs to our customers, resulting in lower margins for us which could adversely affect our results of operations. Factors that could cause significant increases or decreases in commodity prices include changes in supply due to production constraints, weather, governmental regulations, and changes in consumer demand. It is our practice to maintain a position that is substantially balanced between commodity purchases, on the one hand, and expected commodity sales or future delivery obligations, on the other hand. Through these transactions, we seek to establish a margin for the commodity purchased by selling the same commodity for physical delivery to third-party users, such as wholesalers or retailers. While our hedging policies are designed to minimize commodity price risk, some degree of exposure to unforeseen fluctuations in market conditions remains. For example, any event that disrupts our anticipated physical supply could expose us to risk of loss resulting from price changes if we are required to obtain alternative supplies to cover these sales transactions. In addition, we are also exposed to basis risk which is created when a commodity of a certain grade or location is purchased, sold, or exchanged for a like commodity at a different time or location. For example, we use NYMEX traded products, which deliver in New York Harbor, to hedge our commodity risk associated with physical transactions that will be delivered at other locations, such as Macungie, Pennsylvania. We are also susceptible to basis risk in our hedging activities that arises when a commodity, such as the purchase of heating oil at one location must be hedged against the New York Harbor ultra low sulfur diesel futures contract as a result of limitations within the financial markets for derivative products.

A decrease in storage contract renewals or renewals at substantially lower rates at our storage terminals could cause our storage revenue to decline, which could adversely impact our results of operations and cash flow.

The revenue we earn from storage services at our storage terminals is provided for in contracts negotiated with our storage services customers. Many of those contracts are for multi-year periods and require our customers to pay a fixed rate for storage capacity regardless of market conditions during the contract period. Changing market conditions, including changes in petroleum product supply or demand patterns, availability of storage, forward-price structure, financial market conditions, regulations, accounting rules or other factors could cause our customers to be unwilling to renew their storage services contracts with us when those contracts terminate, or make them willing to renew only at lower rates or for shorter contract periods. Failure by our customers to renew their storage contracts on terms and at rates substantially similar to our existing contracts could result in lower utilization of our facilities and could adversely impact our results of operations and cash flow. Any sustained decrease in demand for refined products in the markets our pipelines and terminals serve that extends beyond the expiration of our existing throughput and deficiency and/or storage agreements, as applicable, could result in a significant reduction in throughput in our pipelines and/or storage in our terminals.

The loss of one or more key customers in our Global Marine Terminals segment could adversely affect our results of operations and cash flow.

Revenue from Buckeye Texas, which is contracted predominantly to one customer under long-term take-or-pay arrangements, accounted for approximately 47% of total revenue in the Global Marine Terminals segment for the year ended December 31, 2018. If any one or more of our long-term take-or-pay arrangements with this customer are terminated and we are unable to secure comparable alternative arrangements with one or more third parties, we may not be able to generate sufficient additional revenue to fully replace that generated by the current customer.

In addition, BBH’s revenue accounted for approximately 25% of total revenue in the Global Marine Terminals segment for the year ended December 31, 2018. Currently, BBH has a diversified set of storage customers, consisting of major oil companies, energy companies, physical traders and national oil companies; however, for the year ended December 31, 2018, 33% of BBH’s revenue was derived from its top customer. We expect BBH to continue to derive a substantial portion of its total revenue from a small number of customers in the future. BBH may be unsuccessful in renewing its storage contracts with its customers, and those customers may discontinue or reduce contracted storage from BBH. In particular, if BBH’s top customer significantly reduces its contracted storage with BBH and if BBH is unable to find other storage customers on terms substantially similar to the terms under BBH’s existing storage contracts, our business, results of operations and cash flow could be adversely affected.

Table of Contents

We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to the possibility of increased costs or the inability to retain necessary land use.

We obtain the rights to construct and operate our pipelines, storage terminals, and other facilities on land owned by third parties and governmental agencies. Many of our rights-of-way or other property rights are perpetual in duration while, but others are for a specific period of time. In addition, some of our facilities are located on leased premises. Our loss of property rights, through our inability to renew right-of-way contracts or leases or otherwise, could adversely affect our operations and cash flows available for distribution to unitholders.

In addition, the construction of additions to our existing assets may require us to obtain new rights-of-way or property rights prior to construction. We may be unable to obtain such rights-of-way or other property rights to connect new supplies to our existing pipelines, storage terminals or other facilities or to capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or other property rights or to renew existing rights-of-way or property rights. If the cost of obtaining new or renewing existing rights-of-way or other property rights increases, it may adversely affect our operations and cash flows available for distribution to unitholders.

Reduced volatility in energy prices or new government regulations could discourage our storage customers from holding positions in petroleum products, which could adversely affect the demand for our storage services.

We have constructed and continue to build new storage tanks in response to increased customer demand for storage. Many of our competitors have also built new storage facilities. The demand for new storage has resulted in part from our customers’ desire to have the ability to take advantage of profit opportunities created by volatility in the prices of petroleum products. If the prices of petroleum products become relatively stable, or if federal or state regulations are passed that discourage our customers from storing these commodities, demand for our storage services could decrease, in which case we may be unable to lease storage capacity or be forced to reduce the rates we charge for storage services capacity, and we may experience material impacts on our business, financial condition, results of operations or cash flows.

Changes in the method of determining LIBOR, or the replacement of LIBOR with an alternative reference rate, may adversely affect interest expense related to outstanding debt.

As a result of concerns about the accuracy of the calculation of the benchmark LIBOR, a number of British Bankers’ Association (“BBA”) member banks entered into settlements with regulators and law enforcement agencies with respect to the alleged manipulation of LIBOR. Actions by the BBA, regulators or law enforcement agencies, as a result of these or future events, may result in changes to the manner in which LIBOR is determined. On July 27, 2017, the Financial Conduct Authority (“FCA”) announced that it would phase out LIBOR as a benchmark by the end of 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. Potential changes, or uncertainty related to such potential changes may adversely affect the market for loans with LIBOR-indexed interest rates. When LIBOR ceases to exist, we may need to amend the credit and loan agreements with our lenders that utilize LIBOR as a factor in determining the interest rate based on a new standard that is established, if any. The transition to an alternative rate will require careful and deliberate consideration and implementation so as to not disrupt stability of financial markets. There is no guarantee that a transition from LIBOR to an alternative will not result in financial market disruptions, significant increases in benchmark rates, or borrowing costs to borrowers, any of which could have an adverse effect on our business, results of operations, financial condition, or LP Unit price.

Table of Contents

Failure of critical information technology systems as a result of cybersecurity breaches and other disruptions could compromise our information and expose us to liability, which could cause our business and reputation to suffer and reduce the amount of cash available for distribution.

We utilize information technology systems to operate our assets and manage our businesses. Some of these systems are proprietary systems that require specialized programming capabilities, while others are based upon or reside on technology that has been in service for many years. Cybersecurity attacks are evolving and include but are not limited to, malicious software, attempts to gain unauthorized access to, or otherwise disrupt, our pipeline control systems, attempts to gain unauthorized access to proprietary information, and other electronic security breaches that could lead to disruptions in critical systems, including our pipeline control systems, unauthorized release of confidential or otherwise protected information and corruption of data. Although we have implemented protocols to test for breaches, identify and address weaknesses and appropriately report discovered issues, failures of our information technology systems or these protocols as a result of cybersecurity attacks or other disruptions could result in a breach of critical operational or financial controls and lead to a disruption of our operations, commercial activities or financial processes. Similarly, cybersecurity attacks or other disruptions impacting significant customers and/or suppliers could also lead to a disruption of our operations or commercial activities. These events could damage our reputation and cause us to incur liabilities that have a material adverse impact on the Partnership, including financial losses from remedial actions, business interruptions, loss of business and reduced ability to pay cash distributions. Additionally, there has been increased public attention regarding the use of personal information and data transfer, accompanied by evolving legislation and regulations from federal, state, and foreign governments intended to strengthen data protection, information security and consumer and personal privacy. To the extent we are subject to changes in data privacy and data protection laws and regulations, any failure to comply with such laws and regulations, could adversely affect our business and financial results.

Terrorist attacks or other security threats could adversely affect our business.

Since the attacks of September 11, 2001, the United States government has issued warnings that energy assets, specifically our nation’s pipeline infrastructure, may be the future target of terrorist organizations. In addition to the threat of terrorist attacks, we face various other security threats, including cybersecurity threats to gain unauthorized access to sensitive information or systems or to render data or systems unusable; threats to the safety of our employees; threats to the security of our facilities, such as terminals and pipelines, and infrastructure or third-party facilities and infrastructure. These developments have subjected our operations to increased risks.

Although we utilize various procedures and controls to monitor these threats and mitigate our exposure to security threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities, essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations, or cash flows.

The Department of Homeland Security promulgated the Chemical Facility Anti-Terrorism Standards (“CFATS”) to regulate the security of facilities that handle certain chemicals. We submit to the Department of Homeland Security certain required information concerning our facilities in compliance with CFATS and, as a result, several of our facilities have been determined to be “high risk” by the Department of Homeland Security. Due to this determination, we are required to prepare a security vulnerability assessment and, in certain locations, develop and implement site security plans required by CFATS. At this time, we do not believe that compliance with CFATS will have a material effect on our business, financial condition, results of operations or cash flows.

In addition to CFATS, our domestic operations are also subject to other laws and regulations promulgated and enforced by the Department of Homeland Security, the Department of Transportation and the United States Coast Guard, including Transportation Security Administration Pipeline Security Guidelines. Our operations in The Bahamas and in St. Lucia are subject to similar security-related regulations. We believe that we currently comply in all material respects with security-related laws and regulations. However, this is an area of continued regulatory developments for our industry and as such, we may incur increased operating costs based on developments associated with these regulations and ongoing compliance. At this time, we do not believe that future compliance with these requirements will have a material effect on our business, financial condition, results of operations or cash flows.

Table of Contents

We may face opposition to the operation of our pipelines and facilities from various groups.

We may face opposition to the operations of our pipelines and facilities from environmental groups, landowners, tribal groups, local groups, and other advocates. Such opposition could take many forms, including organized protests, attempts to block or sabotage our operations, intervention in regulatory or administrative proceedings involving our assets, or lawsuits or other actions designed to prevent, disrupt, or delay the operation of our assets and business. For example, repairing our pipelines often involves securing consent from individual landowners to access their property; one or more landowners may resist our efforts to make needed repairs, which could lead to an interruption in the operation of the affected pipeline or facility for a period of time that is significantly longer than would have otherwise been the case. In addition, acts of sabotage or eco-terrorism could cause significant damage or injury to people, property or the environment or lead to extended interruptions of our operations. Any such event that interrupts our operations, or which causes us to make significant expenditures not covered by insurance, could adversely affect our operations and cash flows available for distribution to unitholders.

We could be adversely affected by violations of the U.S. Foreign Corrupt Practices Act and similar worldwide anti-bribery laws.

Our international operations require us to comply with a number of U.S. and international laws and regulations, including those involving anti-bribery and anti-corruption. For example, the U.S. Foreign Corrupt Practices Act (“FCPA”) and similar international laws and regulations prohibit improper payments to foreign officials for the purpose of obtaining or retaining business. The scope and enforcement of anti-corruption laws and regulations may vary.

We operate in parts of the world that have experienced governmental corruption to some degree, and in certain circumstances, strict compliance with anti-bribery laws may conflict with local customs and practices. Our compliance programs and internal control policies and procedures may not always protect us from reckless or negligent acts committed by our employees or agents. Violations of these laws, or allegations of such violations, could disrupt our business and result in a material adverse effect on our business and operations.

Derivative reform mandated by the Dodd-Frank Act and rules and regulations under the Dodd-Frank Act may have an adverse effect on our ability to use certain derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) in 2010. Among other things, the Dodd-Frank Act mandated significant changes to the over-the-counter derivative market and requires the Commodities Futures Trading Commission and the SEC and other regulators to promulgate rules and regulations establishing federal oversight and regulation of the over-the-counter derivative market. Although as of December 31, 2018, the rules and regulations under the Dodd-Frank Act have not had an adverse effect on our ability to use certain derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business, such rules and regulations may have an adverse effect on our ability to do so in the future.

The rulemaking process under the Dodd-Frank Act has not been fully completed, and in certain cases where rule-making is final, the rules will be phased in over a period of time. As a result, it is not possible at this time to determine the full effect that the Dodd-Frank Act will have on our ability to continue to use the derivative products we currently utilize. The rules and regulations under the Dodd-Frank Act may increase the costs of certain derivative products as a result of the imposition of capital, margin, clearing and exchange-trading requirements either on us or on our counterparties. Any requirement to post more collateral to our counterparties in excess of what we currently post to collateralize our obligations may have a negative impact upon our liquidity. Position limits may be imposed upon certain derivative transactions, which may further restrict our ability to utilize these products. The effects of the rules and regulations under the Dodd-Frank Act may also reduce our ability to monetize or restructure our existing derivative contracts. If, as a result of the Dodd-Frank Act and the rules and regulations promulgated thereunder, we reduce our use of certain derivatives, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures or increase our distributions. Any of these consequences could have a material adverse effect on us, our financial condition, and our results of operations.

Table of Contents

Our business is exposed to customer credit risk, and we may not be able to fully protect ourselves against such risk.

Our businesses are subject to the risks of nonpayment and nonperformance by our customers. We have in the past and expect to continue to undertake capital expenditures based on commitments, including take-or-pay commitments, from customers upon which we expect to realize a return. Nonperformance by our customers of those commitments or termination of those commitments resulting from our inability to timely meet our obligations could result in substantial losses to us. In addition, some of our customers, counterparties and suppliers may be highly leveraged and subject to their own operating and regulatory risks and, even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with such parties. Volatility in commodity prices might have an impact on many of our customers, which in turn could have a negative impact on their ability to meet their obligations to us. We manage our exposure to credit risk through credit analysis and monitoring procedures, and sometimes collateral, such as letters of credit, prepayments, liens on customer assets and guarantees. However, these procedures and policies cannot fully eliminate customer credit risk, and to the extent our policies and procedures prove to be inadequate, it could negatively affect our financial condition and results of operations.

The marketing business in our Merchant Services segment enters into sales contracts pursuant to which customers agree to buy refined petroleum products from us at a fixed price on a future date. If our customers have not hedged their exposure to reductions in refined petroleum product prices and there is a price drop, then they could have a significant loss upon settlement of their fixed-price contracts with us, which could increase the risk of their nonpayment or nonperformance. In addition, we generally have entered into futures contracts to hedge our exposure under these fixed-price contracts to increases in refined petroleum product prices. If price levels decrease during the duration of the futures contract, we will be required to make settlement payments during the contract period. Ordinarily, such settlement payments are offset by the payment received from the customer pursuant to the associated fixed-price contract. We are, however, required, as applicable, to make settlement payments under the futures contract even if a fixed-price contract customer does not perform. Nonperformance under fixed-price contracts by a significant number of our customers could have an adverse effect on our business, financial condition, results of operations or cash flows.

Our operations are subject to operational hazards and unforeseen interruptions for which we may not be insured or entitled to indemnification.

Our operations are subject to operational hazards and unforeseen interruptions such as natural disasters, adverse weather, accidents, fires, explosions, marine allisions, hazardous materials releases and other events beyond our control. These events might result in a loss of equipment or life, injury, or extensive property or environmental damage, as well as an interruption in our operations. Our operations are currently covered by property, casualty, workers’ compensation and environmental insurance policies. In the future, however, we may not be able to maintain or obtain insurance of the type and amount desired at reasonable rates. As a result of market conditions, premiums and deductibles for certain insurance policies have increased substantially, and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. For example, insurance carriers are now requiring broad exclusions for losses due to war risk and terrorist acts. Further, our environmental pollution coverage is subject to exclusions, conditions and limitations that could apply to a particular pollution claim or may not cover all claims or liabilities we incur. The contracts with our customers and other business partners involve risk-allocation and indemnification provisions. However, pursuant to these contracts we generally may not seek indemnification from a counterparty for liabilities, including those associated with the release of petroleum products, arising at a time in which we are in possession of the product owned by the counterparty. If we were to incur a significant liability for which we were not fully insured, or insured at all, it could have a material adverse effect on our business, financial condition, results of operation or cash flows.

Our risk management policies cannot eliminate all commodity price risk and any noncompliance with our risk management policies could result in significant financial losses.

We follow risk management practices that are designed to minimize commodity price risk, credit risk and operational risk. These practices and policies cannot, however, eliminate all price and price-related risks. Additionally, noncompliance with such practices and policies by our employees or agents may create additional risk. We cannot make any assurances that we will detect and prevent all violations of our risk management practices and policies, particularly if deception or other intentional misconduct is involved. Any violations of these practices or policies by our employees or agents could result in significant financial losses.

Table of Contents

Hurricanes and other severe weather conditions, which may become more frequent as a result of climatic changes, could damage our facilities or disrupt our marine terminals or the operations of their customers, which could have a material adverse effect on our business, financial results and cash flow.

The operations of our facilities, in particular our marine terminals, could be impacted by severe weather conditions, including hurricanes. Any such event could cause a serious business disruption or serious damage to our facilities, which could affect such facilities’ ability to provide services. Additionally, such events could impact our facilities’ customers, and they may be unable to utilize our services. In addition, many scientists believe that global climatic changes are occurring and are likely to lead to increased physical risks, including an increase in sea level, wetland and barrier island erosion, risks of flooding and changes in weather conditions, such as precipitation, average temperatures and extreme weather conditions or storms. We own assets in communities that may be at risk from sea level rise, changes in weather conditions, storms and loss of the protection offered by coastal wetlands. The portion of our assets that is located in these areas may be increasingly susceptible to storm damage that could be aggravated by wetland and barrier island erosion. Existing weather-related risks and increased risks from additional future climate changes could have a material adverse effect on our business, financial condition, results of operation or cash flows.

Increases in interest rates could adversely affect our unit price and our business.

Interest rates on future debt offerings could be higher than current levels, causing our financing costs to increase accordingly. An increase in interest rates could also cause a corresponding decline in demand for equity investments, in general, and in particular for yield-based equity investments such as our LP Units. Lower demand for our LP Units for any reason, including competition from other more attractive investment opportunities, would likely cause the trading price of our LP Units to decline. If we issue additional equity at a significantly lower price, material dilution to our existing unitholders could result.

Additionally, we use both fixed and variable rate debt, and we are exposed to market risk due to the floating interest rates on our Credit Facility. From time to time we use interest rate derivatives to hedge interest obligations on specific debt. In addition, interest rates on future debt offerings could be higher, causing our financing costs to increase accordingly. Our results of operations, cash flows and financial position could be adversely affected by significant increases in interest rates above current levels.

Risks Relating to Partnership Structure

We may sell additional units, diluting existing interests of unitholders.

Our partnership agreement allows us to issue additional units and certain other equity securities without unitholder approval. There is no limit on the total number of units and other equity securities we may issue. We regularly issue additional units, through our at-the-market offering program and otherwise, and when we issue additional units or other equity securities, the proportionate partnership interest of our existing unitholders will decrease. The issuance could negatively affect the amount of cash distributed to unitholders and the market price of the units. Issuance of additional units will also diminish the relative voting strength of the previously outstanding LP Units.

Our partnership agreement limits the liability of our general partner and its directors and officers.

Our general partner and its directors and officers owe fiduciary duties to our unitholders. Provisions of our partnership agreement and partnership agreements for each of our operating partnerships, however, contain language limiting the liability of the general partner and its directors and officers to the unitholders for actions or omissions taken in good faith which do not involve gross negligence or willful misconduct. In addition, these partnership agreements grant broad rights of indemnification to the general partner and its directors, officers, employees and affiliates.

Unitholders may not have limited liability in some circumstances.

The limitations on the liability of holders of limited partnership interests for the obligations of a limited partnership have not been clearly established in some states. If it were determined that we had been conducting business in any state without compliance with the applicable limited partnership statute, or that the unitholders as a group took any action pursuant to our partnership agreement that constituted participation in the “control” of our business, then the unitholders could be held liable under some circumstances for our obligations to the same extent as a general partner.

Table of Contents

Under applicable state law, our general partner has unlimited liability for our obligations, including our debts and environmental liabilities, if any, except for our contractual obligations that are expressly made without recourse to the general partner.

In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that under some circumstances a unitholder may be liable to us for the amount of distributions paid to the unitholder for a period of three years from the date of the distribution.

Tax Risks to Unitholders

Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for U.S. federal income tax purposes, or we become subject to entity-level taxation for state tax purposes, our cash available for distribution to you would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our LP Units depends largely on our being treated as a partnership for U.S. federal income tax purposes.

Despite the fact that we are organized as a limited partnership under Delaware law, we will be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations and the private letter rulings we have received with respect to certain aspects of our business, we believe we satisfy the qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation.

If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate, which, effective January 1, 2018, is currently a maximum of 21%. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to holders of our LP Units, likely causing a substantial reduction in the value of our LP Units.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for U.S. federal, state, local or foreign income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law or interpretation on us. At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to you would be reduced and the value of our LP Units could be negatively impacted.

The tax treatment of publicly traded partnerships or an investment in our LP Units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our LP Units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. Although there is no current legislative proposal, a prior legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly-traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.

In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. We believe we qualify as a partnership for U.S. federal income tax purposes under current regulations.

However, any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our LP Units.

Table of Contents

If the IRS were to contest the U.S. federal income tax positions we take, it may adversely impact the market for our LP Units, and the costs of any such contest would reduce cash available for distribution to you.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our LP Units and the price at which they trade. Moreover, the costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders’ behalf.

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. Under our limited partnership agreement, our general partner is permitted to make elections under the new rules to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised Schedule K-1 to each unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders’ behalf. These rules are not applicable for tax years beginning on or prior to December 31, 2017.

Even if you do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.

You will be required to pay U.S. federal income taxes and, in some cases, state and local income taxes, on your share of our taxable income, whether or not you receive cash distributions from us. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, you may be allocated taxable income and gain resulting from the sale, and our cash available for distribution would not increase. Similarly, taking advantage of opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt could result in “cancellation of indebtedness income” being allocated to our unitholders as taxable income without any increase in our cash available for distribution. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax due from you with respect to that income.

Tax gain or loss on disposition of our LP Units could be more or less than expected.

If you sell your LP Units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those LP Units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your LP Units, the amount, if any, of such prior excess distributions with respect to the LP Units you sell will, in effect, become taxable income to you if you sell such LP Units at a price greater than your tax basis in those LP Units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing a gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because your amount realized includes your share of our nonrecourse liabilities, if you sell your LP Units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

Table of Contents

A substantial portion of the amount realized from the sale of your units, whether or not representing gain, may be taxed as ordinary income to you due to potential recapture items, including depreciation recapture. Thus, you may recognize both ordinary income and capital loss from the sale of your units if the amount realized on a sale of your units is less than your adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which you sell your units, you may recognize ordinary income from our allocations of income and gain to you prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.

Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.

In general, our unitholders are entitled to a deduction for the interest we have paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Cuts and Jobs Act (the “Tax Act”), for taxable years beginning after December 31, 2017, our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the purposes of this limitation, adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion. While actual results may differ significantly from current projections, we do not expect the interest expense limitation to impact the interest deductions attributable to our domestic operations.

Tax-exempt entities face unique tax issues from owning our LP Units that may result in adverse tax consequences to them.

Investment in our LP Units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs) raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. With respect to taxable years beginning after December 31, 2017, subject to the proposed aggregation rules for certain similarly situated businesses or activities issued by the Treasury Department, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our LP Units.

Non-U.S. Unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our LP Units.

Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business (“effectively connected income”). Income allocated to our unitholders and any gain from the sale of our LP Units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to a Non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a Non-U.S. unitholder who sells or otherwise disposes of an LP Unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that LP Unit to the extent the gain is effectively connected with a U.S. trade or business of the Non-U.S. unitholder.

The Tax Act imposes a withholding obligation of 10% of the amount realized upon a Non-U.S. unitholder’s sale or exchange of an interest in a partnership that is engaged in a U.S. trade or business. However, due to challenges of administering a withholding obligation applicable to open market trading and other complications, the IRS has temporarily suspended the application of this withholding rule to open market transfers of interest in publicly traded partnerships pending promulgation of regulations or other guidance that resolves the challenges. It is not clear if or when such regulations or other guidance will be issued. Non-U.S. unitholders should consult a tax advisor before investing in our LP Units.

Table of Contents

We treat each purchaser of LP Units as having the same tax benefits without regard to the LP Units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of the LP Units.

Because we cannot match transferors and transferees of LP Units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing U.S. Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of LP Units and could have a negative impact on the value of our LP Units or result in audit adjustments to your tax returns.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our LP Units each month based upon the ownership of our LP Units on the first day of each month, instead of on the basis of the date a particular LP Unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our LP Units each month based upon the ownership of our LP Units on the first day of each month (the “Allocation Date”), instead of on the basis of the date a particular LP Unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. The U.S. Department of the Treasury adopted final Treasury Regulations allowing a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose LP Units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of LP Units) may be considered to have disposed of those LP Units. If so, he would no longer be treated for tax purposes as a partner with respect to those LP Units during the period of the loan and could recognize gain or loss from the disposition.

Because there are no specific rules governing the U.S. federal income tax consequences of loaning a partnership interest, a unitholder whose LP Units are the subject of a securities loan may be considered to have disposed of the loaned LP Units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those LP Units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those LP Units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those LP Units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their LP Units.

Taxable income from our non-U.S. businesses is not eligible for the 20% deduction for qualified publicly traded partnership income.

For taxable years beginning after December 31, 2017 and ending on or before December 31, 2025, an individual unitholder is generally allowed a deduction equal to 20% of his or her allocable share of our “qualified publicly traded partnership income.” For purposes of the deduction, the term qualified publicly traded partnership income includes the net amount of such unitholder’s allocable share of our income that is effectively connected to our U.S. trade or business activities. Because our non-U.S. business operations earn income that is not effectively connected with a U.S. trade or business, unitholders may not apply the 20% deduction for qualified publicly traded partnership income to that portion of our income.

Table of Contents

Our gross income with respect to the VTTI business and divestiture may not be qualifying income.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a publicly traded partnership such as ours to be treated as a corporation for U.S. federal income tax purposes. In order to maintain our status as a partnership for U.S. federal income tax purposes, 90% or more of our gross income in each tax year must be qualifying income under Section 7704 of the Internal Revenue Code, as amended. We expect to derive income from (i) the transportation and storage of refined petroleum products, crude oil and LPG refined petroleum products in part through direct or indirect non-U.S. subsidiaries of VTTI, including VTTI MLP Investments BV, that are treated as corporations for U.S. federal income tax purposes, and (ii) the divestiture of our VTTI operations. In specific circumstances we may be required to include certain amounts of this corporate income in our own gross income whether or not these corporations make matching cash distributions and whether or not we own these operations at the time the income is earned. Our counsel on matters of U.S. federal income tax law is unable to opine as to the qualifying income nature of portions of such income inclusions derived from the VTTI assets, operations, or divestitures. Consequently, there is a risk that we will earn significant amounts of income that our counsel cannot opine is qualifying income, and we intend to actively monitor the amounts of any such income inclusions and may seek a ruling from the IRS with respect to the qualifying income nature of these income inclusion amounts.

Notwithstanding our treatment for U.S. federal income tax purposes, we may be subject to additional tax on our non-U.S. income. If a taxing authority were to successfully assert that we have more tax liability than we anticipate or legislation were enacted that increased the taxes to which we are subject, the cash available for distribution to you could be further reduced.

A portion of our business operations and subsidiaries are generally subject to income, withholding and other taxes in the non-U.S. jurisdictions in which they are organized or from which they receive income, reducing the amount of cash available for distribution. In computing our tax obligation in these non-U.S. jurisdictions, we are required to take various tax accounting and reporting positions on matters that are not entirely free from doubt and for which we have not received rulings from the governing tax authorities, such as whether withholding taxes will be reduced by the application of certain tax treaties. Upon review of these positions the applicable authorities may not agree with our positions. A successful challenge by a tax authority could result in additional tax being imposed on us, reducing the cash available for distribution to unitholders. In addition, changes in our operations or ownership could result in higher than anticipated tax being imposed in jurisdictions in which we are organized or from which we receive income and further reduce the cash available for distribution.

Unitholders will likely be subject to state and local taxes and income tax return filing requirements in jurisdictions where such unitholders do not live.

In addition to U.S. federal income taxes, unitholders may be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if a unitholder does not live in any of those jurisdictions. Unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We own property and conduct business in a number of states in the United States. Most of these states impose an income tax on individuals, corporations and other entities. Additionally, we also directly and indirectly own property and conduct business in multiple non-U.S. jurisdictions. Under current law, unitholders are not required to file a tax return or pay taxes in any of the non-U.S. jurisdictions where we currently directly and indirectly own property or operate in. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or non-U.S. jurisdictions that impose a personal income tax. It is a unitholder’s responsibility to file all non-U.S., federal, state and local tax returns and pay taxes due in these jurisdictions. Unitholders should consult with their own tax advisors regarding the filing of such tax returns, the payment of such taxes, and the deductibility of taxes paid.

We have subsidiaries that are treated as corporations for U.S. federal income tax purposes and subject to corporate-level income taxes.

We conduct a portion of our operations through subsidiaries that are corporations for U.S. federal income tax purposes. We may elect to conduct additional operations in corporate form in the future. The corporate subsidiaries will be subject to corporate-level tax, which will reduce the cash available for distribution to us and, in turn, to our unitholders. If the IRS were to successfully assert that the corporate subsidiary has more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, our cash available for distribution would be further reduced.

Table of Contents

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

We are managed primarily from two leased commercial business offices located in Breinigsville, Pennsylvania and Houston, Texas that are approximately 75,000 and 73,000 square feet in size, respectively.

In general, our pipelines are located on land owned by others pursuant to rights granted under easements, licenses and permits from railroads, utilities, governmental entities and private parties. Like other pipelines, certain of our rights are revocable at the election of the grantor or are subject to renewal at various intervals, and some require periodic payments. We have not experienced any revocations or lapses of such rights which were material to our business or operations, and we have no reason to expect any such revocation or lapse in the foreseeable future. Most delivery points, gathering, pumping stations and terminalling facilities are located on land that we own.

See Item 1, Business for a description of the location and general character of our material property.

We believe that we have sufficient title to our material assets and properties, possess all material authorizations and revocable consents from state and local governmental and regulatory authorities and have all other material rights necessary to conduct our business substantially in accordance with past practice. Although in certain cases our title to assets and properties or our other rights, including our rights to occupy the land of others under easements, leases, licenses and permits, may be subject to encumbrances, restrictions and other imperfections, we do not expect any of such imperfections to materially detract from the value of such assets or properties or interfere materially with the conduct of our businesses.

Item 3. 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.

Item 4. Mine Safety Disclosures

Not applicable.

Table of Contents

PART II

Item 5. Market for the Registrant’s LP Units, Related Unitholder Matters, and Issuer Purchases of LP Units

Our LP Units are listed and traded on the NYSE under the symbol “BPL.” The following graph compares the total unitholder return performance of our LP Units with the performance of: (i) the Standard & Poor’s 500 Stock Index (“S&P 500”) and (ii) the Alerian MLP Index. The Alerian MLP Index is a composite of the 50 most prominent energy master limited partnerships that provides investors with a comprehensive benchmark for this asset class. The graph assumes that $100 was invested in our LP Units and each comparison index beginning on December 31, 2013 and that all distributions or dividends were reinvested on a quarterly basis.



	12/31/2013		12/31/2014		12/31/2015		12/30/2016		12/31/2017		12/31/2018
Buckeye Partners, L.P.	$	100.00	$	112.83	$	104.85	$	113.11	$	91.96	$	60.26
S&P 500	100.00		113.69		115.26		129.05		157.22		150.33
Alerian MLP Index	100.00		104.80		70.65		83.58		78.13		68.43

We have gathered tax information from our known unitholders and from brokers/nominees and, based on the information collected, we estimate our number of beneficial unitholders to be approximately 158,000 at December 31, 2018.

Recent Sales of Unregistered Securities

In March 2018, we issued approximately 6.2 million Class C Units in a private placement for aggregate gross proceeds of $265.0 million. The net proceeds were $262.0 million, after deducting issuance costs of approximately $3.0 million. We used the net proceeds from this offering to reduce the indebtedness outstanding under our Credit Facility, to partially fund growth capital expenditures and for general partnership purposes.

Table of Contents

Issuer Purchases of Equity Securities

None.

Item 6. Selected Financial Data

The following tables present our selected consolidated financial data from our audited consolidated financial statements for the periods and at the dates indicated. The tables should be read in conjunction with our consolidated financial statements and our accompanying notes thereto included in Item 8, Financial Statements and Supplementary Data of this Report (in thousands, except per unit amounts):



	Year Ended December 31,
	2018			2017		2016		2015		2014
Income Statement Data:
Revenue ⁽¹⁾	$	4,108,275		$	3,648,145	$	3,248,376	$	3,453,434	$	6,620,247
Operating income ⁽²⁾	417,031			685,364		736,702		607,177		497,685
Net (loss) income	(51,915		)	493,665		548,675		438,391		334,498
Diluted (loss) earnings per unit	$	(0.41	)	$	3.32	$	4.03	$	3.41	$	2.78
Cash distributions per LP Unit - declared for the period	$	4.03		$	5.04	$	4.88	$	4.68	$	4.48
Diluted weighted average units outstanding	152,355			143,144		132,927		128,617		119,899



	December 31,
	2018		2017		2016		2015		2014
Balance Sheet Data:
Total assets ⁽³⁾	$	9,355,550	$	10,304,659	$	9,421,103	$	8,369,281	$	8,065,720
Long-term debt, including current portion ^{(3) (4)}	4,536,715		4,658,321		4,217,695		3,732,824		3,368,618
Total Buckeye Partners, L.P. capital	4,120,082		4,590,937		4,411,723		3,735,389		3,702,628

____________________________


(1)	The change in revenue year to year for Merchant Services is largely driven by fluctuations in refined petroleum products prices, as well as any changes in sales volumes. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations for further discussion.

(2)

Includes the pre-tax gain on the sale of the DPTS asset package and goodwill impairment charge of $343.0 million and $537.0 million, respectively for the year ended December 31, 2018. See Notes 4 - Acquisitions, Investments and Disposition and 10 - Goodwill and Intangible Assets of the Notes to Consolidated Financial Statements for further discussion. Prior year amounts reflect the adoption of Accounting Standards Updates ASU 2017-07 resulting in the reclassification of $1.5 million, $3.4 million, $3.1 million, and $2.3 million for the year ended December 31, 2017 through 2014, respectively.

(3)

Certain reclassifications of debt issuance costs have been made to prior year amounts to conform to current year presentation. In connection with the retrospective application of new accounting standard for debt issuance costs, we reclassified $20.4 million of debt issuance costs originally included in “Other non-current assets” as of December 31, 2014 to “Long-term debt” as a direct deduction from the carrying amount of debt liabilities, consistent with debt discounts.


(4)	Excludes $177.7 million, $252.2 million, $0.0 million, $111.5 million, and $166.0 million of borrowings under the Credit Facility used to finance the Buckeye Merchant Services Companies’ current working capital needs for the years ended December 31, 2018 through 2014, respectively.

Table of Contents

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Introduction

The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our Consolidated Financial Statements and the accompanying notes thereto included in Item 8, Financial Statements and Supplementary Data of this Report. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook future. Our discussion and analysis includes the following:


•	Overview


•	Results of Operations


•	General Outlook for 2019


•	Liquidity and Capital Resources


•	Off Balance Sheet Arrangements


•	Critical Accounting Policies and Estimates

Overview

Business

We are a growth-oriented master limited partnership principally engaged in owning and operating a diversified network of integrated assets providing midstream logistic solutions, primarily consisting of the transportation, storage, processing and marketing of liquid petroleum products. Our assets include terminals and processing facilities that we own and underground liquid petroleum product pipelines installed along rights-of-way acquired from land owners and related above-ground facilities. 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. Our business activities are conducted through three reportable segments:


•	Our Domestic Pipelines and Terminals segment, comprised of our 6,000 miles of pipeline with 110 terminal locations;


•	Our Global Marine Terminals segment, consisting of seven liquid petroleum product terminals located in key global energy hubs with 62 million barrels of liquid petroleum product storage capacity and;


•	Our Merchant Services segment markets refined petroleum products primarily in conjunction with the facilities owned by our other segments.

Strategy

Our primary business objective is to create value by generating stable cash flows that may be distributed to our unitholders or reinvested in the business, while maintaining a relatively low investment risk profile. The key elements of our strategy are to:


•	Operate in a safe, regulatory compliant, and environmentally responsible manner;


•	Maximize utilization and efficiency of our assets;


•	Maintain strong, stable and long-term customer relationships;


•	Optimize, expand and diversify our portfolio of energy assets through strategic investments;


•	Maintain a strong financial position including our investment-grade credit rating; and


•	Retain a portion of our internally generated cash flow and utilize capacity under our Credit Facility to fund our planned growth initiatives without the need to access the public equity markets for the foreseeable future.

We intend to achieve our strategy by:


•	Building, acquiring and operating high quality, strategically-located assets and continually evaluating potential monetization opportunities related to our current asset portfolio;


•	Maintaining and enhancing the integrity of our pipelines, terminals and storage assets, and operating them in a safe and environmentally responsible manner;


•	Seeking to acquire or develop other energy-related assets without compromising our strong financial position that:


•	Complement our existing footprint;


•	Provide geographic, product and/or asset class diversity; and


•	Leverage existing management capabilities and infrastructure;


•	Valuing the effort, teamwork and innovation of our employees; and


•	Providing superior customer service.

Results of Operations

Consolidated Summary

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



	Year Ended December 31,
	2018			2017			2016
Revenue	$	4,108,275		$	3,648,145		$	3,248,376
Costs and expenses	3,497,264			2,962,781			2,511,674
Goodwill impairment	536,964			—			—
Gain on sale of DPTS asset package	(342,984		)	—			—
Operating income	417,031			685,364			736,702
(Loss) earnings from equity investments	(274,123		)	36,005			11,536
Interest and debt expense	(190,172		)	(225,583		)	(194,922		)
Other expense	(911		)	(1,249		)	(3,181		)
(Loss) income before taxes	(48,175		)	494,537			550,135
Income tax expense	(3,740		)	(872		)	(1,460		)
Net (loss) income	(51,915		)	493,665			548,675
Less: Net income attributable to noncontrolling interests	(7,123		)	(14,863		)	(13,067		)
Net (loss) income attributable to Buckeye Partners, L.P.	$	(59,038	)	$	478,802		$	535,608
Diluted (loss) earnings per unit attributable to Buckeye Partners, L.P.:	$	(0.41	)	$	3.32		$	4.03

Table of Contents

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 (losses) before interest expense, income taxes, depreciation and amortization, further adjusted to exclude certain non-cash items, such as non-cash compensation expense; transaction, transition, and integration costs associated with acquisitions; certain 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, non-cash impairment charges, 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 of significant equity method investments, such as that in VTTI, and is not applied to our less significant equity method investments. The calculation of our proportionate share of the reconciling items used to derive Adjusted EBITDA was based upon our 50% equity interest in VTTI, prior to adjustments related to noncontrolling interests in several of its subsidiaries and partnerships, which are immaterial. Due to certain terms of the definitive agreement regarding the divestiture of our equity interest in VTTI, we determined we no longer had the ability to exercise significant influence over the operating and financial policies of VTTI and therefore, accounted for our investment at fair value. Accordingly, beginning in the fourth quarter of 2018 and prospectively, we no longer applied the definition of Adjusted EBITDA to our investment in VTTI. Adjusted EBITDA 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 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 used by management 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.

Table of Contents

The following table presents consolidated net (loss) income, which is the most comparable financial measure under GAAP, to Adjusted EBITDA and distributable cash flow, as well as Adjusted EBITDA by segment for the periods indicated (in thousands):



		Year Ended December 31,
		2018			2017			2016
Reconciliation of Net (loss) income to Adjusted EBITDA and Distributable cash flow:
Net (loss) income		$	(51,915	)	$	493,665		$	548,675
Less:	Net income attributable to noncontrolling interests	(7,123		)	(14,863		)	(13,067		)
Net (loss) income attributable to Buckeye Partners, L.P.		(59,038		)	478,802			535,608
Add:	Interest and debt expense	190,172			225,583			194,922
	Income tax expense	3,740			872			1,460
	Depreciation and amortization⁽¹⁾	269,423			269,243			254,659
	Non-cash unit-based compensation expense	21,776			30,302			33,344
	Acquisition and transition expense ⁽²⁾	11,321			4,226			8,196
	Hurricane-related costs, net of recoveries ⁽³⁾	124			5,780			16,795
	Proportionate share of Adjusted EBITDA for the equity method investment in VTTI ⁽⁴⁾	101,435			126,642			—
	Goodwill impairment	536,964			—			—
	Loss (earnings) from the equity method investment in VTTI ⁽⁴⁾	286,633			(22,910		)	—
Less:	Amortization of unfavorable storage contracts⁽⁵⁾	—			—			(5,979		)
	Gains on property damage recoveries ⁽⁶⁾	(14,535		)	(4,621		)	(5,700		)
	Gain on sale of ammonia pipeline	—			—			(5,299		)
	Gain on sale of DPTS asset package	(342,984		)	—			—
Adjusted EBITDA		$	1,005,031		$	1,113,919		$	1,028,006
Less:	Interest and debt expense, excluding amortization of deferred financing costs, debt discounts, interest rate swap settlements and amortization, and other	(225,567		)	(208,380		)	(177,996		)
	Income tax (expense) benefit, excluding non-cash taxes	(2,137		)	(297		)	276
	Maintenance capital expenditures	(120,936		)	(144,046		)	(129,691		)
	Proportionate share of VTTI’s interest expense, current income tax expense, realized foreign currency derivative gains and losses, and maintenance capital expenditures ⁽⁴⁾	(28,873		)	(43,855		)	—
Add:	Hurricane-related maintenance capital expenditures	4,110			14,577			6,054
Distributable cash flow		$	631,628		$	731,918		$	726,649

Adjusted EBITDA by segment:
Domestic Pipelines & Terminals		$	561,961		$	573,021		$	568,405
Global Marine Terminals		428,663			512,821			427,229
Merchant Services		14,407			28,077			32,372
Adjusted EBITDA		$	1,005,031		$	1,113,919		$	1,028,006

____________________________


(1)	Includes 100% of the depreciation and amortization expense of $73.8 million, $72.4 million and $71.7 million for Buckeye Texas for the years ended December 31, 2018, 2017 and 2016, respectively. In April 2018, we acquired our business partner’s 20% ownership interest in Buckeye Texas and, as a result, own 100% of Buckeye Texas.


(2)	Represents transaction, internal and third-party costs related to asset acquisition, divestitures, 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.

Table of Contents

(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. Due to certain terms of the definitive agreement regarding the divestiture of our equity interest in VTTI, we discontinued the equity method of accounting and recorded our interest at fair value. Accordingly, beginning in the fourth quarter of 2018 and prospectively, we no longer recorded any equity earnings or reflected any contributions from VTTI to our Adjusted EBITDA or distributable cash flow. Included in loss (earnings) from the equity method investment in VTTI for the year ended December 31, 2018, is a $300.3 million non-cash loss on the sale of our investment in VTTI as discussed in Note 4 - Acquisitions, Investments and Disposition of the Notes to Consolidated Financial Statements.


(5)	Represents fair value adjustment amortization related to certain storage contracts acquired in the BBH acquisition. These contracts were fully amortized by December 31, 2016.


(6)	Represents gains on recoveries of property damages caused by third parties, which, for 2018, primarily related to a settlement in connection with a 2012 vessel allision with a jetty at our BBH facility in the Bahamas, and for 2017, primarily related to a settlement in connection with a 2014 vessel allision with a ship dock at our terminal located in Pennsauken, New Jersey.

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 percentage for our Global Marine Terminals segment and total sales volumes for the Merchant Services segment for the periods indicated:



	Year Ended December 31,
	2018		2017		2016
Domestic Pipelines & Terminals (average bpd in thousands):
Pipelines:
Gasoline	783.2		756.3		759.6
Jet fuel	375.2		373.8		361.1
Middle distillates ⁽¹⁾	329.5		309.7		289.4
Other products ⁽²⁾	12.3		19.1		16.9
Total throughput ⁽³⁾	1,500.2		1,458.9		1,427.0
Terminals:
Throughput ^{(4) (5)}	1,336.5		1,251.5		1,238.4

Pipeline average tariff (cents/bbl)	90.2		89.7		85.9

Global Marine Terminals (percent of capacity):
Average capacity utilization rate ⁽⁶⁾	83	%	92	%	99	%

Merchant Services (in millions of gallons):
Sales volumes	1,231.7		1,214.8		1,179.7

_____________________________


(1)	Includes diesel fuel and heating oil.


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


(3)	Includes 105.4 bpd, 105.0 bpd, and 102.6 bpd of total pipelines throughput for the years ended 2018, 2017, and 2016, respectively, related to the DPTS asset package divested on December 17, 2018.


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


(5)	Includes 60.3 bpd, 58.6 bpd, and 59.4 bpd of total terminals throughput for the years ended 2018, 2017, and 2016, respectively, related to the DPTS asset package divested on December 17, 2018.


(6)	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 79%, 88% and 92% for the years ended December 31, 2018, 2017 and 2016, respectively.

Table of Contents

Year Ended December 31, 2018 Compared to Year Ended December 31, 2017

Consolidated Overview

Net loss was $51.9 million for the year ended December 31, 2018, as compared to net income of $493.7 million for the year ended December 31, 2017. The decrease was primarily driven by (i) a $537.0 million impairment of the goodwill associated with our assets in the Caribbean and New York Harbor, which was recorded in the third quarter 2018 (See Note 10 - Goodwill and Intangible Assets of the Notes to the Consolidated Financial Statements for further discussion); (ii) a $300.3 million non-cash loss on the write-down of our investment in VTTI, which was recorded in the third quarter 2018 and is included in loss from equity investments on our Consolidated Statement of Operations; (iii) lower operating results from the Global Marine Terminals segment’s Caribbean segregated storage services, partially offset by stronger results in our South Texas operations; and (iv) lower operating results in the Merchant Services segment, all as further explained in the discussion of Adjusted EBITDA by segment below. The decrease was partially offset by (i) an after-tax gain of $342.5 million on the sale of the Domestic Pipelines and Terminals asset package during the fourth quarter of 2018; (ii) a $35.4 million decrease in interest expense, primarily due to a $51.0 million gain from the settlement of forward interest rate swaps, applied as a reduction to interest expense, which was partially offset by a $15.6 million increase in interest expense driven by an increased average interest rate on our Credit Facility and higher average borrowings; (iii) a $9.9 million increase in gains on property damage recoveries, reflecting a $14.0 million property damage claim that was settled during the second quarter of 2018 and lower hurricane-related costs, net of recoveries, and (iv) lower non-cash unit-based compensation expense.

Total Adjusted EBITDA was $1,005.0 million for the year ended December 31, 2018, a decrease of $108.9 million, or 9.8% , from $1,113.9 million in 2017. The decrease in Adjusted EBITDA was driven by decreases in segment Adjusted EBITDA of $84.1 million, $11.1 million, and $13.7 million from the Global Marine Terminals, Domestic Pipelines & Terminals, and Merchant Services segments, respectively, as further explained in the discussion of Adjusted EBITDA by segment below.

Distributable cash flow was $631.6 million for the year ended December 31, 2018, a decrease of $100.3 million, or 13.7%, from $731.9 million for the corresponding period in 2017, primarily driven by a $108.9 million decrease in Adjusted EBITDA from our segments, as further described below, and a $17.2 million increase in interest and debt expense, excluding settlements on swaps, amortization of deferred financing costs, debt discounts and other. This net decrease in distributable cash flow was partially offset by a $12.6 million decrease in maintenance capital expenditures, excluding hurricane-related maintenance capital expenditures, primarily reflecting the completion of certain large projects during the prior year.

VTTI Adjusted EBITDA and distributable cash flow contribution decreased year over year by $25.2 million and $15.0 million respectively, primarily due to the fact that following entering into the definitive agreement in the fourth quarter, we no longer recorded any equity earnings or reflected additional adjusted EBITDA and distributable cash flow from our interest in VTTI, but rather accounted for our interest at fair value effective September 30, 2018.

Adjusted EBITDA by Segment

Domestic Pipelines & Terminals. Adjusted EBITDA from the Domestic Pipelines & Terminals segment was $561.9 million for the year ended December 31, 2018, a decrease of $11.1 million, or approximately 2%, from $573.0 million in 2017.

Pipeline volumes increased by 2.8% due to strong demand for distillate, gasoline, and jet fuel shipments. Terminalling throughput volumes increased by 6.8%, primarily due to higher gasoline and distillate volumes, reflecting strong customer throughput demand, particularly in our Midwest and Northeast regions.

Table of Contents

The pipeline volumes increase contributed to an increase of $15.0 million in pipeline transportation revenues, including product recoveries and other pipeline revenues, reflecting contributions from internal growth capital investments and favorable demand for transportation services in the Midwest. In addition, other revenues increased by $12.3 million primarily due to higher butane blending margins, while project management revenues decreased by $6.8 million due to a reduction in project activity. These revenue increases were offset by a $13.2 million decrease in terminalling throughput revenue, primarily due to the expiration of a crude-by-rail contract at our Chicago Complex, and a $13.1 million decrease in storage revenue, primarily due to lower storage capacity utilization. Operating expenses increased by $5.5 million due to incident response and remediation costs associated with two pipeline product releases during the year, one in our Midwest region and one in our Southeast region, as well as increased labor, power and utilities, and additives expenses. These operating expense increases were partially offset by a reduction in project management costs corresponding to the decrease in project management revenues discussed above and lower general and administrative expenses.

Global Marine Terminals. Adjusted EBITDA from the Global Marine Terminals segment was $428.7 million for the year ended December 31, 2018, a decrease of $84.1 million, or 16.4%, from $512.8 million in 2017. The decrease was primarily due to (i) the execution of a definitive agreement to sell our equity interest in VTTI, which resulted in a $25.2 million decrease in Adjusted EBITDA primarily due to the fact that following entering into the definitive agreement in the fourth quarter, we no longer recorded any equity earnings or reflected additional Adjusted EBITDA and distributable cash flow from our interest in VTTI, but rather accounted for our interest at fair value effective September 30, 2018; (ii) a $70.8 million unfavorable impact to revenue due to a decline in demand for our segregated storage services as further discussed below, which were partially offset by (iii) a $9.9 million increase in Adjusted EBITDA resulting from the acquisition of our business partner’s 20% equity interest in Buckeye Texas in April 2018.

Revenue from storage and terminalling services decreased by $77.0 million, reflecting lower capacity utilization and average rates primarily due to lower demand for segregated storage services primarily at our Caribbean, and to a lesser extent, our New York Harbor facilities as a result of overall weaker market conditions and a $2.1 million decrease in revenue from ancillary services. These decreases were partially offset by an $8.3 million increase in processing services revenues at Buckeye Texas as a result of contract escalations and increased processing rates. We expect that weak market conditions currently impacting Global Marine Terminals revenue from segregated storage services will persist for certain locations through 2019. The average capacity utilization (i.e., ratio of contracted capacity to capacity available to be contracted) of our marine storage assets was 83% for the year ended December 31, 2018, which was a decrease from 92% in the corresponding period in 2017. A $2.0 million decrease in operating expenses reflected cost management efforts across segment operations and lower general and administrative expenses, partially offset by incident response and remediation costs associated with a product release at our Port Reading terminal.

Merchant Services. Adjusted EBITDA from the Merchant Services segment was $14.4 million for the year ended December 31, 2018, a decrease of $13.7 million, or 48.8%, from $28.1 million in 2017. Adjusted EBITDA was negatively impacted by a reduced contribution from distillate storage due to insufficient pricing spreads to support margins on storing product during the period as compared to 2017. This impact was partially offset by slightly higher distillate rack margins.

Revenue from bulk and rack product sales increased by $534.0 million due to (i) a $28.4 million increase as a result of 1.4% higher sales volumes and (ii) a $505.6 million increase in refined petroleum product sales due to higher average sales prices per gallon of $2.09 for 2018 as compared to $1.68 for the prior year.

Cost of product sales, including both bulk and rack sales increased by $546.8 million primarily due to (i) a $27.8 million increase due to higher sales volumes and (ii) a $519.0 million increase in refined petroleum product cost due to higher average cost per gallon of $2.07 for 2018 as compared to $1.64 for the prior year.

Table of Contents

Year Ended December 31, 2017 Compared to Year Ended December 31, 2016

Consolidated Overview

Income from continuing operations was $493.7 million for the year ended December 31, 2017, a decrease of $55.0 million, or 10.0%, from $548.7 million in 2016. The decrease was driven by (i) lower operating results primarily in the Global Marine Terminal segment’s Caribbean facilities which were partially offset by earnings from equity investments from the January 2017 investment in VTTI; and (ii) lower operating results in the Merchant Services segment, as further explained in the discussion of Adjusted EBITDA by segment below; as well as (iii) a $14.5 million increase in depreciation and amortization expense related to assets placed in service during the period; and (iv) a $30.7 million increase in interest and debt expense, due to long-term debt issued in the fourth quarter of 2016 to partially fund the VTTI Acquisition, as well as 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.

Total Adjusted EBITDA was $1,113.9 million for the year ended December 31, 2017, an increase of $85.9 million, or 8.4% , from $1,028.0 million in 2016. The increase in Adjusted EBITDA was driven by increases in segment Adjusted EBITDA of $85.6 million and $4.6 million from the Global Marine Terminals segment and Domestic Pipelines & Terminals segment, respectively, which was partially offset by a $4.3 million decrease in Adjusted EBITDA from the Merchant Services segment, as further explained in the discussion of Adjusted EBITDA by segment below.

Distributable cash flow was $731.9 million for the year ended December 31, 2017, an increase of $5.3 million, or 0.7%, from $726.6 million for the corresponding period in 2016, primarily driven by an $85.9 million increase in Adjusted EBITDA from our segments, as described above, which was partially offset by (i) a $30.4 million increase in interest and debt expense, excluding amortization of deferred financing costs, debt discounts and other; (ii) a $5.9 million increase in maintenance capital expenditures, excluding hurricane-related maintenance capital expenditures, primarily resulting from increased asset integrity project costs and upgrades to station and terminalling equipment; and (iii) our $43.9 million net proportionate share of VTTI’s interest expense, current income tax expense, realized foreign currency derivatives gains and losses, and maintenance capital expenditures.

Adjusted EBITDA by Segment

Domestic Pipelines & Terminals. Adjusted EBITDA from the Domestic Pipelines & Terminals segment was $573.0 million for the year ended December 31, 2017, an increase of $4.6 million, or approximately 1%, from $568.4 million in 2016. The increase was primarily due to a $24.2 million increase in revenue, partially offset by a $19.6 million net increase in operating expenses and other.

Pipeline volumes increased by 2.2% due to strong demand for distillate and jet fuel shipments, which were partially offset by weaker demand for gasoline transportation services. Terminalling throughput volumes increased by 1.1% due to higher volumes, reflecting strong customer throughput demand, particularly in the Southeast, partially offset by lower pipeline transfers at our Chicago Complex.

The increase in revenue was due to a $30.2 million increase in pipeline transportation revenues, reflecting contributions from internal growth capital investments placed in service and an increase in average pipeline tariff rates, including the impact of an increase in higher-rate long-haul volumes; a $13.2 million increase in project management revenues due to an increase in project activity; a $7.1 million increase in product recoveries; and a $4.2 million increase in storage revenues, primarily due to storage capacity returned to service and new storage contracts. These revenue increases were partially offset by a $28.6 million decrease in terminalling throughput revenue, primarily due to the exercise by a customer of an early buy-out provision in a crude-by-rail throughput contract at our Albany, New York terminal, in September 2016, partially offset by the positive impact of higher throughput volumes; and a $1.9 million decrease in other revenues. The net increase in operating expenses and other primarily relates to the increased activity within our project management business, as well as increased labor and general and administrative expenses.

Table of Contents

Global Marine Terminals. Adjusted EBITDA from the Global Marine Terminals segment was $512.8 million for the year ended December 31, 2017, an increase of $85.6 million, or 20.0%, from $427.2 million in 2016. The increase was primarily due to the $126.6 million Adjusted EBITDA contribution from our equity investment in VTTI, acquired in January 2017, partially offset by a $35.8 million decrease in revenue and a $5.2 million increase in operating expenses.

Revenue from storage and terminalling services decreased by $47.5 million due to lower capacity utilization, driven by lower demand for storage services at our Caribbean facilities as a result of weaker market conditions, as well as the exit of a long-term customer from one of our facilities; partially offset by an increase in processing services revenues at Buckeye Texas. This decrease was further offset by a $11.7 million increase in revenue from ancillary services, including tank cleaning, water disposal, berthing and heating. The average capacity utilization of our marine storage assets was 92% for the year ended December 31, 2017, which was a decrease from 99% in the corresponding period in 2016. The increase in operating expenses was primarily driven by higher property taxes as well as business development costs, and general and administrative expenses.

Merchant Services. Adjusted EBITDA from the Merchant Services segment was $28.1 million for the year ended December 31, 2017, a decrease of $4.3 million, or 13.3%, from $32.4 million in 2016. Adjusted EBITDA was negatively impacted by lower rack margins and weaker market conditions, primarily in the distillate market, partially offset by a decrease in operating expenses.

Revenue increased by $416.3 million due to (i) a $48.3 million increase as a result of 3.0% higher sales volumes and (ii) a $368.0 million increase in refined petroleum product sales due to higher commodity prices (average sales prices per gallon were $1.68 and $1.37 for the 2017 and 2016 periods, respectively).

Cost of product sales increased by $421.7 million primarily due to (i) a $46.9 million increase due to higher sales volumes and (ii) a $374.8 million increase in refined petroleum product cost due to higher commodity prices (average prices per gallon were $1.64 and $1.34 for the 2017 and 2016 periods, respectively). This increase was partially offset by a $1.1 million decrease in operating expenses.

Table of Contents

General Outlook for 2019

We expect that incremental contributions associated with growth capital investments, as well as increased pipeline and terminalling revenues, particularly in our Domestic Pipelines & Terminals segment, will contribute to solid financial performance in 2019. The impact of the sale of our equity interest in VTTI and the sale of the DPTS asset package will offset these contributions. In our Global Marine Terminals segment, we expect continued improvements in performance from our Buckeye Texas Partners assets. We expect that contributions from these improvements will be offset by the anticipated continuing challenges in storage market conditions. In the near term, we do not expect market pricing structure to improve to levels sufficient to incentivize incremental storage demand beyond existing levels needed to support product flows.

As previously indicated following the completion of our Strategic Review, we are targeting a distribution coverage ratio of 1.2 times or greater and a debt-to-Adjusted EBITDA ratio of 4.5 times or less.

Domestic Pipelines & Terminals Segment Business Outlook and Growth Projects

We expect to benefit in 2019 from tariff increases on both our market-based and FERC index-based tariff pipelines which generally become effective in January and July 2019, respectively. Tariffs negotiated with customers on certain of our Midwest pipelines are also expected to generate revenue growth in 2019. Pipeline throughput revenues are anticipated to benefit from the initiation of service on the second phase of our Michigan/Ohio Expansion Project. Throughput volumes across our domestic terminals are expected to increase moderately as we benefit from contributions from a number of growth capital investments across our terminal portfolio, including the completion of our Chicago Complex expansion project. Our butane blending and settlement revenues, including revenues associated with the operation of our vapor recovery equipment, are expected to be negatively impacted by reduced commodity prices compared to the prior year.

The completion of the expansion of our Chicago Complex in mid-2019, which will provide additional midstream services to a major Midwestern-area refiner, is anticipated to contribute to our performance. This project will further expand storage, component blending, throughput capacity and service capabilities and serve to further enhance the liquidity of our premier storage and trading facility in the Midwest. This project is backed by a long-term agreement with a credit worthy customer. We continue to have conversations with this customer and others about the potential for further expansions of the Chicago Complex.

We continue to await approval from the FERC of our request for a ruling on the lawfulness of certain commercial terms and tariff steps relating to the second phase of our Michigan/Ohio expansion project. This second phase builds on the initial phase of the project to further expand Buckeye’s capabilities to deliver refined products from Midwestern refineries to destinations in Western Pennsylvania, as well as to Altoona in central Pennsylvania, through adding bi-directional service capabilities to a segment of our Laurel pipeline. We also believe that a state regulatory proceeding brought by parties opposing the proposed interstate service lacks merit. Once we receive appropriate FERC and other regulatory orders and approvals, we have to complete necessary operational and safety testing, including a hydrotest, prior to initiating operations. Although the timing of obtaining regulatory approval is not in our control, we remain optimistic we will receive the requested FERC order and commence commercial service in 2019.

We are advancing and have completed a number of smaller projects that require moderate capital investments and offer attractive return profiles that we expect to contribute to our 2019 financial performance. We have ongoing return capital projects at a number of our terminals that are intended to increase capacity, connectivity and optionality for our customers by adding storage capacity, multi-modal product handling, offloading and take-away capacity at these facilities. Our teams continue to identify opportunities to invest capital across our diverse domestic asset portfolio to drive incremental contributions to Buckeye.

Global Marine Terminals Segment Business Outlook and South Texas Gateway Terminal Construction

We anticipate challenging market conditions in segregated storage to continue into 2019 as the expiration of certain higher priced crude oil storage contracts will result in overall realized rates and utilization levels to be marginally lower than 2018. We expect to see improved utilization in the latter part of 2019 as market participants prepare for implementation of IMO 2020, which is a change to the marine bunker fuel sulfur specifications mandated by the International Maritime Organization and expected to be effective January 1, 2020.

Table of Contents

Overall, given the available capacity and handling capabilities at our storage facilities in both the Caribbean and New York Harbor, should market conditions for storage improve as a result of changing product flows, supply and demand imbalances, or favorable changes in the forward commodity prices, we are well positioned to realize a meaningful favorable impact to our asset utilization and cash flows with minimal capital investment.

Our Buckeye Texas Partners facility in Corpus Christi remains fully contracted and will benefit from contractual rate escalations in 2019. We continue to evaluate opportunities with customers to expand, debottleneck and further improve our supply connectivity and other capabilities around the services this facility offers.

We continue to advance our South Texas Gateway terminal project in Ingleside, Texas on the Corpus Christi ship channel. Buckeye formed a joint venture with Phillips 66 Partners and Marathon to develop the STG Terminal. The STG Terminal is a deep-water open access marine terminal that is positioned to serve as a primary destination point and export outlet for crude oil volumes delivered via pipeline from growing Permian Basin production and other sources. We continue to secure additional minimum volume throughput commitments and storage contracts from customers, and our current plan is to increase the scope of this project from 3.4 million barrels of storage to 6.8 million barrels, based on current contracted throughput and storage volumes. We continue to advance discussions for further potential expansions of the facility, which could ultimately be expanded to include up to approximately 10 million barrels of storage capacity on our 212-acre site. We expect our share of project spend to be approximately $115.0 million to $130.0 million on this project in 2019 and expect to commence and ramp up operations by mid-2020.

Merchant Services Segment Business Outlook

Our Merchant Services segment continues to focus on optimizing our portfolio of domestic assets to drive utilization and incremental value to Buckeye.

Capital Planning and Financing Activities

We announced significant deleveraging efforts in connection with the outcome of our Strategic Review in November 2018. Both of the announced dispositions are completed and we utilized the proceeds received to reduce leverage, including retiring our $250.0 million Term Loan and repaying all borrowings on our Credit Facility. We have $275.0 million of long-term debt that matures in 2019. We expect to redeem this debt in February 2019 using proceeds from the dispositions as well as borrowings on our Credit Facility. These actions are expected to allow us to avoid accessing the debt capital markets until we refinance our 2021 debt maturity.

We also announced as part of our Strategic Review that we expect the actions taken, including the adjustment to our distribution, would allow us to fund our expected growth capital projects for 2019 without the need to access the public equity capital markets or investments from private sources of capital. We expect that we will have sufficient cash flow in excess of distributions to unitholders in combination with sufficient debt capacity on our Credit Facility to fund our growth capital in 2019, while maintaining our investment-grade credit rating.

We may continue to evaluate a number of additional opportunities to invest capital in assets consistent with our long-term growth strategy. We will determine the appropriate financing structure, including but not limited to joint ventures or project-level financing, as needed, for any opportunity we pursue.

The forward-looking statements contained in this “General Outlook for 2019” speak only as of the date hereof. 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 are inherently uncertain and 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. All such forward-looking statements are expressly qualified in their entirety by the cautionary statements contained or referred to in this Report, including under the captions “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” and elsewhere in this Report and in our future periodic reports filed with the SEC. In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this “General Outlook for 2019” may not occur.

Table of Contents

Liquidity and Capital Resources

General

Our primary cash requirements, in addition to normal operating expenses and debt service, are for working capital, capital expenditures, equity investments, business acquisitions and distributions to unitholders. Our principal ongoing sources of liquidity are cash from operations and borrowings under our $1.5 billion revolving Credit Facility. 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 continuing operations. Expansion and cost reduction capital expenditures, along with acquisitions and investments, have typically been funded from external sources including our Credit Facility, as well as debt and equity offerings. Previously, 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. In light of current market conditions and the actions we undertook as a result of the Strategic Review, we plan to retain sufficient cash flow to fund a portion of our near term annual growth capital projects without the need to access the public equity capital markets. Based on current market conditions, we believe our borrowing capacity under our Credit Facility and cash flows from operations will be sufficient to fund our primary cash requirements. We continually evaluate engaging in strategic transactions for potential additional sources of capital which may include (i) divesting non-strategic assets where our evaluation suggests such a transaction is in the best interest of our business, including the potential monetization of full or partial equity interests in certain joint ventures or other assets, (ii) issuances of public or private debt and (iii) investments from private sources of capital. We believe availability under our Credit Facility in combination with our cash flows from operations, as well the use of other sources of capital described above, where appropriate, will be sufficient to fund our current expansion plans over the next twelve months while maintaining adequate liquidity without the need for additional equity capital. In the fourth quarter of 2018 and January 2019, we raised a total of approximately $1.4 billion through asset divestitures which were used to reduce debt.

Current Liquidity

As of December 31, 2018, we had a working capital deficit of $604.1 million and $974.6 million of availability under our Credit Facility. The working capital deficit is in part the result of $525.0 million of current portion of long-term debt to be paid down in the first quarter of 2019, including our $250.0 million Term Loan repaid in January 2019.

Capital Structuring Transactions

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. The universal and traditional shelf registration statements will expire in November and December 2020, respectively.

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.

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.

Table of Contents

As discussed in the Recent Developments section above, management has completed the Strategic Review of our near and long-term strategy, with oversight from the Board. The Strategic Review included an evaluation of various alternatives designed to maximize long-term value for our unitholders by:


•	Maintaining our investment-grade credit rating by reducing leverage;


•	Providing increased financial flexibility, eliminating the need to access the public equity markets to fund planned annual growth capital; and


•	Reallocating capital to the higher return growth opportunities across our remaining assets.

In connection with our Strategic Review, we have closed on the two previously announced transactions to divest the DPTS asset package and our equity investment in VTTI, respectively. The proceeds from these transactions were used or will be used to pay down debt. In addition, through a reduction in our quarterly distribution, we are retaining substantially more of our internally generated cash flow to provide increased financial flexibility. By retaining substantially more of our internally generated cash and reducing leverage, we expect to generate distributable cash flow significantly in excess of planned distributions going forward to allow us to (i) fund a portion of annual growth capital projects, (ii) maintain a leverage ratio reflective of an investment-grade credit rating, and (iii) manage through periods of cash flow volatility with adequate distribution coverage.

Use of Divestiture Proceeds

Proceeds of $444.6 million from the sale of the DPTS asset package on December 17, 2018 were used to reduce the indebtedness outstanding under our Credit Facility.

In January 2019, we received proceeds from the sale of our 50% equity interest in VTTI of $975.0 million, excluding transaction costs of approximately $8.0 million. We utilized the proceeds to reduce leverage, including retiring our $250.0 million Term Loan and repaying all borrowings on our Credit Facility. We have $275.0 million of 5.5% notes that matures in 2019. We expect to redeem this debt in February 2019 using proceeds from the sale transaction as well as borrowings on our Credit Facility. These actions are expected to allow us to avoid accessing the debt capital markets until we need to refinance our next debt maturity in 2021.

Debt

At December 31, 2018, we had the following debt obligations (in thousands):



5.500% Notes due August 15, 2019	$	275,000
4.875% Notes due February 1, 2021	650,000
4.150% Notes due July 1, 2023	500,000
4.350% Notes due October 15, 2024	300,000
3.950% Notes due December 1, 2026	600,000
4.125% Notes due December 1, 2027	400,000
6.750% Notes due August 15, 2033	150,000
5.850% Notes due November 15, 2043	400,000
5.600% Notes due October 15, 2044	300,000
6.375% Junior Notes due January 22, 2078	400,000
Term Loan due September 30, 2019	250,000
Credit Facility due September 30, 2021	522,328
Unamortized discounts & debt issuance costs	(32,886		)
Total debt	$	4,714,442

At December 31, 2018, the aggregate principal amount outstanding of our various long-term debt obligations (including current maturities) was $4,747.3 million. At December 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. As of December 31, 2018, we have $974.6 million of availability under our Credit Facility. For more information regarding our debt-related transactions, see Note 13 - Long-Term Debt of the Notes to Consolidated Financial Statements for further discussion.

Table of Contents

In November 2018, we repaid in full the $400.0 million principal amount and $5.3 million of accrued interest outstanding under our 2.650% notes, using funds available under our Credit Facility.

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. Beginning January 22, 2023, the Junior Notes will bear interest at a floating rate based on the Three-Month LIBOR Rate plus 4.02%, reset quarterly. Total proceeds from this offering, after underwriting fees, expenses, and debt issuance costs, were $394.9 million. We used the net proceeds from this offering for general partnership purposes and to reduce the indebtedness outstanding under our Credit Facility.

Equity

In November 2018, we announced a reduction in our declared quarterly cash distribution. As a result, all 6,714,963 Class C Units, outstanding as of September 30, 2018 (representing the initial issuance and the issuance of additional Class C Units in lieu of quarterly cash distributions) converted into LP Units on a one-for-one basis on November 5, 2018 and participated in cash distributions. No Class C Units were outstanding as of December 31, 2018.

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):



	Year Ended December 31,
	2018			2017			2016
Cash provided by (used in):
Operating activities	$	767,829		$	888,402		$	717,917
Investing activities	72,419			(1,809,988		)	(481,702		)
Financing activities	(840,598		)	283,426			399,244

Operating Activities

2018. Net cash provided by operating activities was $767.8 million for the year ended December 31, 2018, primarily resulted from $51.9 million of net loss, adjusted for (i) a $537.0 million non-cash goodwill impairment charge associated with our GMT Caribbean and NYH reporting unit, as discussed in Note 10 - Goodwill and Intangible Assets of the Notes to Consolidated Financial Statements; (ii) a pre-tax $343.0 million gain on sale of the DPTS asset package, as discussed in Note 4 - Acquisitions, Investments, and Disposition of the Notes to Consolidated Financial Statements; (iii) $274.1 million of loss from equity investments driven by the non-cash impairment loss related to the announced sale of our investment in VTTI; (iv) $269.4 million of depreciation and amortization; (v) a $51.0 million gain from the settlement of forward interest rate swaps and (vi) the favorable impact of a $95.9 million decrease in net working capital items, primarily reflecting a decrease in liquid petroleum products inventory in the Merchant Services segment, as well as other net working capital fluctuations.

2017. Net cash provided by operating activities was $888.4 million for the year ended December 31, 2017, primarily related to $493.7 million of net income, $269.2 million of depreciation and amortization, a $56.4 million decrease in inventory in the Merchant Services segment, $17.2 million in amortization of debt issuance costs, discounts and interest rate swaps, $20.0 million in interest rate swap settlements, and $30.6 million of non-cash unit-based compensation expense, which were partially offset by a $24.7 million net increase in the fair value of derivative assets.

Table of Contents

2016. Net cash provided by operating activities was $717.9 million for the year ended December 31, 2016, primarily related to $548.7 million of net income, $254.7 million of depreciation and amortization, and a $103.3 million net decrease in the fair value of derivatives, which were partially offset by $162.3 million increase in inventory, primarily driven by an increase in commodity prices.

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

2018. Net cash provided by investing activities of $72.4 million for the year ended December 31, 2018 primarily related to $444.6 million proceeds from the sale of DPTS asset package, as discussed in Note 4 - Acquisition, Investments, and Disposition of the Notes to Consolidated Financial Statements, $51.0 million proceeds from the settlement of the forward interest rate swaps, $76.4 million distributions in excess of earnings primarily from VTTI, partially offset by $467.6 million of capital expenditures and $42.2 million invested in our STG Terminal joint venture.

2017. Net cash used in investing activities of $1.8 billion for the year ended December 31, 2017 primarily related to $433.3 million of capital expenditures, $1.2 billion related to the acquisition of an equity investment, and $237.8 million related to the contribution to the same equity investment.

2016. Net cash used in investing activities of $481.7 million for the year ended December 31, 2016 primarily related to $486.3 million of capital expenditures and $26.0 million related to the acquisition of the Indianola terminal, which were partially offset by $19.9 million in refunded escrow deposits.

See below for a discussion of capital spending. See Note 4 - Acquisitions, Investments and Disposition of the Notes to Consolidated Financial Statements for further discussion.

We have capital expenditures, which we define as “maintenance capital expenditures,” in order to maintain and enhance the safety and integrity of our pipelines, terminals, storage 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):



	Year Ended December 31,
	2018		2017		2016
Maintenance capital expenditures ⁽¹⁾	$	120,936	$	144,046	$	129,691
Expansion and cost reduction	346,675		289,289		356,625
Total capital expenditures⁽²⁾	$	467,611	$	433,335	$	486,316

_____________________________


(1)	Includes maintenance capital expenditures of $4.1 million and $14.6 million at the BBH facility and Yabucoa Terminal in Puerto Rico as a result of Hurricanes Matthew and Maria for the year ended December 31, 2018 and 2017 and $6.1 million for the year ended December 31, 2016 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 $490.2 million, $436.9 million and $457.4 million for the years ended December 31, 2018, 2017 and 2016, respectively.

Total capital expenditures increased for the year ended December 31, 2018, as compared to 2017. Our expansion and cost reduction capital expenditures were $346.7 million for the year ended December 31, 2018, which is an increase of $57.4 million, or 19.8%, from $289.3 million for the corresponding period in 2017. Year-to-year 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 and growth projects in the, New York Harbor, Jacksonville Terminals, and Chicago Complex. Our maintenance capital expenditures were $120.9 million for the year ended December 31, 2018, which is a decrease of $23.1 million, or 16.0%, from $144.0 million for the corresponding period in 2017. Year-to-year fluctuations in our maintenance capital expenditures were primarily driven by a temporary increase in maintenance capital during the first half of 2017 related to upgrades in station and terminal equipment and asset integrity work necessary to maintain operating capacity, and a decrease in expenditures associated with Hurricanes Matthew and Maria as compared to 2017.

Table of Contents

Total capital expenditures decreased for the year ended December 31, 2017, as compared to 2016. Our expansion and cost reduction capital expenditures were $289.3 million for the year ended December 31, 2017, which is a decrease of $67.3 million, or 18.9%, from $356.6 million for the corresponding period in 2016. Year-to-year fluctuations in our expansion and cost reduction capital expenditures were primarily driven by the completion of construction activities and certain large organic growth capital projects, including the first phase of the Michigan/Ohio pipeline expansion project in the fourth quarter of 2016, the continuation of subsequent phases in 2017 for projects in the Midwest and New York Harbor, and new expansion, tank capacity optimization and cost reduction projects in 2017 in our Caribbean locations. Our maintenance capital expenditures were $144.0 million for the year ended December 31, 2017, which is an increase of $14.3 million, or 11.0%, from $129.7 million for the corresponding period in 2016. Year-to-year fluctuations in our maintenance capital expenditures were primarily driven by increased asset integrity and facility infrastructure projects. Our most significant maintenance capital expenditures for the year ended December 31, 2017 included tank integrity work across our asset locations to maintain operating capacity, replacements at our BBH facility and Yabucoa Terminal as a result of Hurricanes Matthew and Maria, marine dock improvements and upgrades to station and terminalling equipment across our asset locations.

We estimate our capital expenditures for the period indicated as follows (in thousands):



	2019
	Low		High
Domestic Pipelines & Terminals:
Maintenance capital expenditures	$	70,000	$	80,000
Expansion and cost reduction	120,000		140,000
Total capital expenditures	$	190,000	$	220,000

Global Marine Terminals:
Maintenance capital expenditures	$	34,000	$	44,000
Expansion and cost reduction ⁽¹⁾	25,000		40,000
Total capital expenditures	$	59,000	$	84,000

Overall:
Maintenance capital expenditures	$	104,000	$	124,000
Expansion and cost reduction	145,000		180,000
Total capital expenditures	$	249,000	$	304,000

_____________________________


(1)	Excludes our estimated capital contributions to unconsolidated joint ventures for expansion expenditures. In 2019, our capital contributions to the STG Terminal joint venture are expected to fall within the range from $115.0 million to $130.0 million, depending on the timing of the construction of the STG Terminal.

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, continued investment in South Texas facilities, and various tank construction and conversion projects in our Global Marine Terminals and Domestic Pipelines & Terminals segments.

Financing Activities

2018. Net cash flows used in financing activities of $840.6 million for the year ended December 31, 2018 primarily related to $400.0 million principal repayment of our 2.650% notes and $300.0 million principal repayment of our 6.050% notes, $673.7 million of cash distributions paid to unitholders ($4.538 per LP Unit), and a $210.0 million acquisition of our business partner’s 20% interest in our Buckeye Texas consolidated subsidiary, partially offset by $394.9 million of net proceeds from our 6.375% notes issuance, $262.0 million of net proceeds from the issuance of an aggregate 6.2 million Class C Units in a private placement, and $103.4 million of net borrowings under the Credit Facility.

Table of Contents

2017. Net cash flows provided by financing activities of $283.4 million for the year ended December 31, 2017 primarily related to $418.9 million of net borrowings under the Credit Facility, $398.0 million of proceeds from the issuance of the 4.125% notes due November 2027, and $345.8 million of proceeds from the issuance of an aggregate 6.2 million LP Units under the Equity Distribution Agreement, partially offset by $714.5 million of cash distributions paid to unitholders ($5.013 per LP Unit) and a $125.0 million principal repayment of our 5.125% notes in July 2017.

2016. Net cash flows provided by financing activities of $399.2 million for the year ended December 31, 2016 primarily related to $689.1 million of net proceeds from the issuance of an aggregate 10.5 million LP Units, $597.9 million of proceeds from the issuance of the 3.950% notes due December 1, 2026, and $250.0 million of borrowings on our Term Loan, partially offset by $641.7 million of cash distributions paid to unitholders ($4.825 per LP Unit) and $472.5 million of net repayments under the Credit Facility.

See Note 21 - Partners’ Capital and Distributions of the Notes to Consolidated Financial Statements for further discussion about our equity offerings.

Contractual Obligations

The following table summarizes our significant contractual obligations as of December 31, 2018 (in thousands):



	Payments Due by Period
	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Long-term debt ⁽¹⁾	$	4,044,601	—		994,601		500,000		2,550,000
Interest payments ⁽²⁾	3,294,869		202,842		367,028		289,190		2,435,809
Operating leases:
Office space and other	22,057		5,141		7,657		3,583		5,676
Equipment ⁽³⁾	123,904		20,540		34,438		33,109		35,817
Land leases ⁽⁴⁾	112,529		3,369		6,375		5,812		96,973
Purchase obligations ⁽⁵⁾	121,483		121,483		—		—		—
Total contractual obligations	$	7,719,443	$	353,375	$	1,410,099	$	831,694	$	5,124,275

_____________________________


(1)	Includes long-term debt portion borrowed under our Credit Facility. See Note 13 - Long-Term Debt of the Notes to Consolidated Financial Statements for further discussion regarding our debt obligations.

(2)

Includes amounts due on our notes and amounts and commitment fees due on our Credit Facility. The interest amount calculated on the Credit Facility is based on the assumption that the amount outstanding and the interest rate charged both remain at their current levels. With respect to our Junior Notes due January 22, 2078, interest payments were estimated using the interest rate as of December 31, 2018, applied to the entire remaining term through the maturity date. To the extent interest rates change, our contractual obligation for interest payments will change.


(3)	Includes leases for tugboats and a barge in our Global Marine Terminals segment.


(4)	Includes leases for properties in connection with both the jetty and inland dock operations in our Global Marine Terminals segment.


(5)	Includes short-term purchase obligations for products and services with third-party suppliers and payment obligations relating to capital projects. The prices that we are obligated to pay under these contracts approximate current market prices.

For the year ended December 31, 2019, our rights-of-way payments are expected to be $8.1 million, which include an estimated amount for annual escalation.

See Note 18 - Pensions and Other Postretirement Benefits of the Notes to Consolidated Financial Statements for further discussion about our obligations related to our pension and postretirement benefit plans.

Off-Balance Sheet Arrangements

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

Table of Contents

Critical Accounting Policies and Estimates

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. See Note 2 - Summary of Significant Accounting Policies of the Notes to Consolidated Financial Statements for further discussion. The following describes significant estimates and assumptions affecting the application of these policies:

Valuation of Goodwill

Goodwill represents the excess of purchase price over fair value of net assets acquired. Our goodwill amounts are assessed for impairment: (i) on an annual basis on October 31st of each year; or (ii) on an interim basis if circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying value.

During the third quarter of 2018, we performed an interim qualitative assessment to evaluate the recoverability of each reporting unit's goodwill. Qualitative factors considered in this assessment include economic conditions, industry and market considerations, overall financial performance and other relevant events and factors affecting each reporting unit. Based on our assessment, we determined a triggering event had occurred as a result of continuing declines in the utilization of our segregated storage assets, as well as reductions in the rate and term upon recontracting. As a result, we performed a quantitative test in which the fair value of our reporting units were compared to their carrying amounts. If the reporting unit’s carrying value exceeds its fair value, we recognized an impairment charge to the extent that the carrying value of goodwill exceeds its fair value. As part of the interim goodwill impairment test, we estimated the fair value of each of our reporting units using a weighting of an expected present value of future cash flows and a market multiple valuation method, giving more weighting to our estimate of future cash flows. The present value of future cash flows is estimated using: (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses; (ii) long-term growth rates; and (iii) appropriate discount rates. The market multiple valuation method uses appropriate market multiples from comparable companies on the reporting unit’s earnings before interest, tax, depreciation and amortization. We evaluate industry and market conditions for purposes of weighting the income and market valuation approach. Using this methodology, which qualifies as Level 3 within the fair value hierarchy, we estimated the fair value of each of our reporting units and determined that the fair value of each of our reporting units significantly exceed their respective carrying values, with the exception of the GMT Caribbean and NYH reporting unit, which is one of the two reporting units comprising our Global Marine Terminals segment. Applying reasonable sensitivities to any or a combination of the above valuation inputs would not have generated a materially different determination of fair value. As a result of the assessment described above, we concluded that the goodwill in our GMT Caribbean and NYH reporting unit was fully impaired and recorded a non-cash goodwill impairment charge of $537.0 million.

We performed our annual assessment as of October 31, 2018 to determine if any significant events or changes in circumstances had occurred that would be considered a potential triggering event. We did not identify any indication of a triggering event that would indicate the existence of further impairment of the reporting units.

Valuation of Long-Lived Assets and Equity Method Investments

We assess the recoverability of our long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If events or circumstances are identified, the carrying amount of the asset is compared to the estimated undiscounted future cash flows to determine if an impairment exists. Estimates of undiscounted future cash flows include: (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses; (ii) long-term growth rates; and (iii) estimates of useful lives of the assets. The identification of impairment indicators and the estimates of future undiscounted cash flows are highly subjective and are based on numerous assumptions about future operations and market conditions.

We evaluate equity method investments for impairment whenever events or changes in circumstances indicate that there is an “other than temporary” loss in value of the investment. Estimates of future cash flows include: (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses; (ii) long-term growth rates; and (iii) probabilities assigned to different cash flow scenarios. For the year ended December 31, 2018, as a result of our decision to divest our interest in VTTI, we recorded a $300.3 million non-cash loss related to our equity method investment in VTTI. There were no impairments of our equity investments during the years ended December 2017 and 2016.

Table of Contents

Reserves for Environmental Matters

We record environmental liabilities for a specific site when environmental assessments occur or remediation efforts are probable, and the costs can be reasonably estimated based upon past experience, discussion with operating personnel, advice of outside engineering and consulting firms, discussion with legal counsel, and current facts and circumstances. The estimates related to environmental matters are uncertain because: (i) estimated future expenditures are subject to cost fluctuations and change in the estimated remediation period; (ii) unanticipated liabilities may arise; and (iii) changes in federal, state and local environmental laws and regulations may significantly change the extent of remediation.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — Trading Instruments

We have no trading derivative instruments.

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	(51,016		)	(50,982		)	(101,998		)
Change in fair value attributable to new deals during the period	32,715			—			32,715
Change in fair value attributable to existing deals at January 1st	40,207			18,988			59,195
Fair value of contracts outstanding at December 31, 2018	$	17,699		$	—		$	17,699

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 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 December 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	$	233,058
Fair value assuming 10% increase in underlying commodity prices	Asset	$	241,014
Fair value assuming 10% decrease in underlying commodity prices	Asset	$	225,102

Table of Contents

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. 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.

At December 31, 2018, we had total fixed-rate debt obligations under various public notes at an aggregate carrying value of $3.5 billion. Based on a hypothetical one percentage point movement in the underlying interest rates at December 31, 2018, the estimated fair value of these debt obligations would be as follows (in millions):



Scenario	Fair Value of Fixed-Rate Debt
Fair value assuming no change in underlying interest rates (as is)	$	3,365
Fair value assuming 1% increase in underlying interest rates	$	3,179
Fair value assuming 1% decrease in underlying interest rates	$	3,574

At December 31, 2018, our variable-rate obligations were $1,172.3 million. Based on the balance outstanding at December 31, 2018, we estimate that a one percentage point increase or decrease in underlying interest rates would increase or decrease annual interest expense by $11.7 million.

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 (expense) income” within our consolidated statements of operations. The effects of foreign currency transactions were not considered to be material for the years ended December 31, 2018, 2017 and 2016.

Table of Contents

Item 8. Financial Statements and Supplementary Data



	Page

Management’s Report On Internal Control Over Financial Reporting	58

Reports of Independent Registered Public Accounting Firm	59

Consolidated Statements of Operations for the Years Ended December 31, 2018, 2017 and 2016	61

Consolidated Statements of Comprehensive (Loss) Income for the Years Ended December 31, 2018, 2017 and 2016	62

Consolidated Balance Sheets as of December 31, 2018 and 2017	63

Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 and 2016	64

Consolidated Statements of Partners’ Capital for the Years Ended December 31, 2018, 2017 and 2016	65

Notes to Consolidated Financial Statements:
1. Organization	66
2. Summary of Significant Accounting Policies	66
3. Revenue from Contracts with Customers	80
4. Acquisitions, Investment and Disposition	81
5. Commitments and Contingencies	83
6. Inventories	84
7. Prepaid and Other Current Assets	85
8. Property, Plant and Equipment	85
9. Equity Investments	86
10. Goodwill and Intangible Assets	87
11. Other Non-Current Assets	89
12. Accrued and Other Current Liabilities	89
13. Long-Term Debt	90
14. Other Non-Current Liabilities	92
15. Accumulated Other Comprehensive (Loss) Income	92
16. Derivative Instruments and Hedging Activities	93
17. Fair Value Measurements	97
18. Pensions and Other Postretirement Benefits	98
19. Unit-Based Compensation Plans	103
20. Related Party Transactions	106
21. Partners’ Capital and Distributions	106
22. Income Taxes	108
23. (Loss) Earnings Per Unit	109
24. Business Segments	110
25. Supplemental Cash Flow Information	115
26. Quarterly Financial Data (Unaudited)	115

Table of Contents

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of Buckeye GP LLC, as general partner of Buckeye Partners, L.P. (“Buckeye”), is responsible for establishing and maintaining adequate internal control over financial reporting of Buckeye. Internal control over financial reporting is a process designed to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. A company’s internal control over financial reporting includes those policies and procedures that pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America (“GAAP”), and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management evaluated the internal control over financial reporting of Buckeye as of December 31, 2018. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework (2013) (“COSO”). As a result of this assessment and based on the criteria in the COSO framework, management has concluded that, as of December 31, 2018, the internal control over financial reporting of Buckeye was effective.

Buckeye’s independent registered public accounting firm, Deloitte & Touche LLP, has audited the internal control over financial reporting of Buckeye. Their opinion on the effectiveness of internal control over financial reporting of Buckeye appears herein.



/s/ CLARK C. SMITH	/s/ KEITH E. ST.CLAIR
Clark C. Smith	Keith E. St.Clair
Chief Executive Officer, President and	Executive Vice President and
Chairman of the Board	Chief Financial Officer

February 15, 2019

Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Buckeye GP LLC and the

Partners of Buckeye Partners, L.P.

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Buckeye Partners, L.P. and subsidiaries (“Buckeye”) as of December 31, 2018, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, Buckeye maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control—Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2018 of Buckeye and our report dated February 15, 2019 expressed an unqualified opinion on those financial statements.

Basis for Opinion

Buckeye’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on Buckeye’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Buckeye in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 15, 2019

Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Buckeye GP LLC and the

Partners of Buckeye Partners, L.P.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Buckeye Partners, L.P. and subsidiaries (“Buckeye”) as of December 31, 2018 and 2017, the related consolidated statements of operations, comprehensive income, partners’ capital, and cash flows, for each of the three years in the period ended December 31, 2018, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of Buckeye as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), Buckeye’s internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 15, 2019 expressed an unqualified opinion on Buckeye’s internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of Buckeye’s management. Our responsibility is to express an opinion on Buckeye’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Buckeye in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 15, 2019

We have served as Buckeye’s auditor since 1985.

Table of Contents

BUCKEYE PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit amounts)



	Year Ended December 31,
	2018			2017			2016
Revenue:
Product sales	$	2,567,415		$	2,014,980		$	1,594,240
Transportation, storage and other services	1,540,860			1,633,165			1,654,136
Total revenue	4,108,275			3,648,145			3,248,376

Costs and expenses:
Cost of product sales	2,521,864			1,969,182			1,549,522
Operating expenses	639,769			638,103			626,582
Depreciation and amortization	269,423			269,243			254,659
General and administrative	82,393			90,975			86,098
Goodwill impairment	536,964			—			—
Gain on sale of DPTS asset package	(342,984		)	—			—
Other, net	(16,185		)	(4,722		)	(5,187		)
Total costs and expenses	3,691,244			2,962,781			2,511,674
Operating income	417,031			685,364			736,702

Other (expense) income:
(Loss) earnings from equity investments	(274,123		)	36,005			11,536
Interest and debt expense	(190,172		)	(225,583		)	(194,922		)
Other expense	(911		)	(1,249		)	(3,181		)
Total other expense, net	(465,206		)	(190,827		)	(186,567		)

(Loss) income before taxes	(48,175		)	494,537			550,135
Income tax expense	(3,740		)	(872		)	(1,460		)
Net (loss) income	(51,915		)	493,665			548,675
Less: Net income attributable to noncontrolling interests	(7,123		)	(14,863		)	(13,067		)
Net (loss) income attributable to Buckeye Partners, L.P.	$	(59,038	)	$	478,802		$	535,608

(Loss) earnings per unit attributable to Buckeye Partners, L.P.:
Basic	$	(0.41	)	$	3.33		$	4.05
Diluted	$	(0.41	)	$	3.32		$	4.03

Weighted average units outstanding:
Basic	152,355			142,501			132,242
Diluted	152,355			143,144			132,927

See Notes to Consolidated Financial Statements

Table of Contents

BUCKEYE PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME

(In thousands)



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

See Notes to Consolidated Financial Statements

Table of Contents

BUCKEYE PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands, except unit amounts)



	December 31,
	2018			2017
Assets:
Current assets:
Cash and cash equivalents	$	1,830		$	2,180
Accounts receivable, net	219,751			270,648
Construction and pipeline relocation receivables	14,259			11,047
Inventories	210,884			301,425
Derivative assets	18,019			34,959
Prepaid and other current assets	58,894			36,339
Total current assets	523,637			656,598

Property, plant and equipment	8,258,694			7,928,240
Less: Accumulated depreciation	(1,343,898		)	(1,192,448		)
Property, plant and equipment, net	6,914,796			6,735,792

Equity investments	1,111,793			1,494,412
Goodwill	470,875			1,007,313

Intangible assets	610,900			615,086
Less: Accumulated amortization	(317,589		)	(256,025		)
Intangible assets, net	293,311			359,061

Other non-current assets	41,138			51,483
Total assets	$	9,355,550		$	10,304,659

Liabilities and partners’ capital:
Current liabilities:
Line of credit	$	177,727		$	252,204
Current portion of long-term debt	525,000			—
Accounts payable	147,525			160,777
Derivative liabilities	1,320			7,172
Accrued and other current liabilities	276,193			265,207
Total current liabilities	1,127,765			685,360

Long-term debt	4,011,715			4,658,321
Other non-current liabilities	84,900			92,656
Total liabilities	5,224,380			5,436,337

Commitments and contingent liabilities (Note 5 - Commitments and Contingencies)	—			—

Partners’ capital:
Buckeye Partners, L.P. capital:
Limited Partners (153,755,031 and 146,677,459 units outstanding as of December 31, 2018 and 2017, respectively)	4,160,143			4,562,306
Accumulated other comprehensive (loss) income	(40,061		)	28,631
Total Buckeye Partners, L.P. capital	4,120,082			4,590,937
Noncontrolling interests	11,088			277,385
Total partners’ capital	4,131,170			4,868,322
Total liabilities and partners’ capital	$	9,355,550		$	10,304,659

See Notes to Consolidated Financial Statements

Table of Contents

BUCKEYE PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)



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

See Notes to Consolidated Financial Statements

Table of Contents

BUCKEYE PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(In thousands)



	Limited Partners			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest			Total
Partners' capital - January 1, 2016	$	3,833,230		$	(97,841	)	$	281,352		$	4,016,741
Net income	535,608			—			13,067			548,675
Distributions paid to unitholders	(644,729		)	—			3,043			(641,686		)
Net proceeds from issuance of LP Units	689,128			—			—			689,128
Amortization of unit-based compensation awards	33,482			—			—			33,482
Net proceeds from exercise of Unit options	300			—			—			300
Payment of tax withholding on issuance of LTIP awards	(6,711		)	—			—			(6,711		)
Distributions paid to noncontrolling interests	—			—			(15,750		)	(15,750		)
Contributions from noncontrolling interests	—			—			5,000			5,000
Other comprehensive income	—			72,248			—			72,248
Accrual of distribution equivalent rights	(3,004		)	—			—			(3,004		)
Other	12			—			(12		)	—
Partners' capital - December 31, 2016	4,437,316			(25,593		)	286,700			4,698,423
Net income	478,802			—			14,863			493,665
Distributions paid to unitholders	(717,393		)	—			2,898			(714,495		)
Net proceeds from issuance of LP Units	345,795			—			—			345,795
Amortization of unit-based compensation awards	30,568			—			—			30,568
Net proceeds from exercise of Unit options	481			—			—			481
Payment of tax withholding on issuance of LTIP awards	(9,447		)	—			—			(9,447		)
Distributions paid to noncontrolling interests	—			—			(39,230		)	(39,230		)
Contributions from noncontrolling interests	—			—			12,000			12,000
Other comprehensive income	—			54,224			—			54,224
Accrual of distribution equivalent rights	(3,662		)	—			—			(3,662		)
Other	(154		)	—			154			—
Partners' capital - December 31, 2017	4,562,306			28,631			277,385			4,868,322
Net (loss) income	(59,038		)	—			7,123			(51,915		)
Acquisition of noncontrolling interest	56,928			—			(266,928		)	(210,000		)
Distributions paid to unitholders	(676,123		)	—			2,400			(673,723		)
Net proceeds from issuance of LP Units	261,962			—			—			261,962
Amortization of unit-based compensation awards	22,081			—			—			22,081
Payment of tax withholding on issuance of LTIP awards	(8,306		)	—			—			(8,306		)
Distributions paid to noncontrolling interests	—			—			(16,292		)	(16,292		)
Contributions from noncontrolling interests	—			—			7,400			7,400
Other comprehensive loss	—			(68,692		)	—			(68,692		)
Accrual of distribution equivalent rights	333			—			—			333
Partners' capital - December 31, 2018	$	4,160,143		$	(40,061	)	$	11,088		$	4,131,170

See Notes to Consolidated Financial Statements

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION

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

We were formed as a master limited partnership in 1986 from predecessor companies and own and operate a diversified global network of integrated assets providing midstream logistic solutions, primarily consisting of the transportation, storage, processing and marketing of liquid petroleum products. We are one of the largest independent liquid petroleum products pipeline operators in the United States in terms of volumes delivered, with approximately 6,000 miles of pipeline. We also use our service expertise to operate and/or maintain third-party pipelines and perform certain engineering and construction services for our customers. Our global terminal network comprises more than 115 liquid petroleum products terminals with aggregate tank capacity of over 118 million barrels across our portfolio of pipelines, inland terminals and marine terminals located primarily in key petroleum logistics hubs in the East Coast, Midwest and Gulf Coast regions of the United States as well as in the Caribbean. Our terminal assets facilitate global flows of crude oil and refined petroleum products, offering our customers connectivity between supply areas and market centers through some of the world’s most important bulk liquid storage and blending hubs. Our wholly-owned flagship marine terminal in The Bahamas, Buckeye Bahamas Hub Limited (“BBH”), is one of the largest marine crude oil and refined petroleum products storage facilities in the world and provides an array of logistics and blending services for the global flow of petroleum products. Our Gulf Coast regional hub, Buckeye Texas Partners LLC (“Buckeye Texas”), offers world-class marine terminalling, storage and processing capabilities. We are also a wholesale distributor of refined petroleum products in areas served by our pipelines and terminals.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

We adhere to the following significant accounting policies in the preparation of our consolidated financial statements:

Basis of Presentation and Principles of Consolidation

The consolidated financial statements and the accompanying notes are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and the rules of the U.S. Securities and Exchange Commission (“SEC”). The consolidated financial statements include the accounts of our subsidiaries controlled by us and variable interest entities (“VIEs”) of which we are the primary beneficiary. A VIE is required to be consolidated by its primary beneficiary which is generally defined as the party who has (i) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (ii) the obligation to absorb losses of the VIE or the right to receive benefits that could potentially be significant to the VIE. We evaluate our relationships with our VIEs on an ongoing basis to determine whether we continue to be the primary beneficiary. Third party or affiliate ownership interests in our subsidiaries and consolidated VIEs are presented as noncontrolling interests. Intercompany transactions are eliminated in consolidation.

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Asset Retirement Obligations

We regularly assess our legal obligations with respect to estimated retirements of certain of our long-lived assets to determine if an asset retirement obligation (“ARO”) exists. The fair value of a liability related to the retirement of long-lived assets is recorded at the time a regulatory or contractual obligation is incurred, including obligations to perform an asset retirement activity in which the timing or method of settlement are conditional on a future event that may or may not be within the control of the entity. If an ARO is identified and a liability is recorded, a corresponding asset is recorded concurrently and is depreciated over the remaining useful life of the asset. After the initial measurement, the liability is periodically adjusted for costs incurred or settled, accretion expense, and any revisions made to the assumptions related to the retirement costs. Generally, the fair value of the liability is determined based on estimates and assumptions related to: (i) future retirement costs; (ii) future inflation rates; and (iii) credit-adjusted risk-free interest rates.

Our assets generally consist of terminals that we own and underground liquid petroleum products pipelines installed along rights-of-way acquired from land owners and related above-ground facilities. The significant majority of our rights-of-way agreements do not require the dismantling and removal of the pipelines and reclamation of the rights-of-way upon permanent removal of the pipelines from service. In addition, we assume substantially all of our common carrier properties operate indefinitely, as these assets generally serve in high-population and high-demand markets. Accordingly, other than with respect to facilities that are expected to be taken out of service, we have recorded no liabilities, or corresponding assets because the future dismantlement and removal dates for the majority of our assets, and the amount of any associated costs, are indeterminable. The ARO liability represents our best estimate of the costs to be incurred with information currently available and is based on certain assumptions, including: (i) timing of retirement of assets; (ii) methods of abandonment to be employed; and (iii) if applicable, our requirements under right-of-way agreements; therefore, it is likely that the ultimate costs to settle this liability will be different and such differences could be material.

ARO liabilities are included in accrued and other current liabilities, as well as other non-current liabilities. There were no significant changes in the estimates underlying ARO liabilities during the periods presented.

Business Combinations

We allocate the total purchase price of a business combination to the assets acquired and the liabilities assumed based on their estimated fair values at the acquisition date, with the excess purchase price recorded as goodwill. For material acquisitions, we may engage an independent valuation specialist to assist us in determining the fair value of the assets acquired and liabilities assumed, including goodwill, based on recognized business valuation methodologies. If the initial accounting for the business combination is incomplete by the end of the reporting period in which the acquisition occurs, an estimate will be recorded. Subsequent to the acquisition, and not later than one year from the acquisition date, we will record any material adjustments to the initial estimate in the reporting period in which the adjustment amounts are determined based on facts and circumstances that existed as of the acquisition date, as applicable. An income, market or cost valuation method may be utilized to estimate the fair value of the assets acquired or liabilities assumed in a business combination. The income valuation method represents the present value of future cash flows over the life of the asset using: (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses; (ii) long-term growth rates; and (iii) appropriate discount rates. The market valuation method uses prices paid for a reasonably similar asset by other purchasers in the market, with adjustments relating to any differences between the assets. The cost valuation method is based on the replacement cost of a comparable asset at prices at the time of the acquisition reduced for depreciation of the asset. We expense acquisition-related costs as incurred in connection with each business combination.

Business Segments

Our operations are reported under three business segments: (i) Domestic Pipelines & Terminals; (ii) Global Marine Terminals; and (iii) Merchant Services. Our business segments are generally organized and managed according to the geographical location of our assets and the types of services rendered. Financial information regarding these segments is evaluated regularly by our chief operating decision maker (our Chief Executive Officer) in deciding how to allocate resources and in assessing operating and financial performance. Our business segment financial performance is evaluated primarily based on Adjusted EBITDA. Refer to Note 24 - Business Segments for further discussion.

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Capitalization of Interest

Interest on borrowed funds is capitalized on projects during construction based on the approximate average interest rate of our debt. Interest capitalized for the years ended December 31, 2018, 2017 and 2016 was $8.9 million, $4.8 million and $4.4 million, respectively. The weighted average rates used to capitalize interest on borrowed funds was 4.6%, 4.5% and 4.6% for the years ended December 31, 2018, 2017 and 2016, respectively.

Cash and Cash Equivalents

Cash equivalents represent all highly marketable securities with original maturities of three months or less. The carrying value of cash equivalents approximates fair value because of the short-term nature of these investments.

Comprehensive Income

Our comprehensive income is determined based on net income adjusted for unrealized gains and losses on derivative instruments for our cash flow hedging transactions, reclassification of derivative gains and losses to net income, recognition of costs related to our pension and post-retirement benefit plans, adjustments to the funded status of our pension and post-retirement benefit plans and our proportionate share of other comprehensive income from equity method investments.

Concentration of Credit Risk and Trade Receivables

Trade receivables of $214.3 million and $265.0 million included within accounts receivable, net on our consolidated balance sheets as of December 31, 2018 and 2017, respectively, are primarily due from major oil companies, national oil companies, refiners, marketing and trading companies, and commercial airlines. These concentrations of customers may affect our overall credit risk as these customers may be similarly affected by changes in economic, regulatory or other factors. We extend credit to customers and manage our credit risks through credit analysis and monitoring procedures, including credit approvals, credit limits and right of offset. Also, we manage our risk using collateral, such as letters of credit, prepayments, liens on customer assets and guarantees.

Trade receivables represent valid claims against non-affiliated customers and are recognized when products are sold or services are rendered. We record an allowance for doubtful accounts for estimated losses resulting from the inability of our customers to make required payments. We review the adequacy of the allowance for doubtful accounts monthly by making judgments regarding future events and trends based on the: (i) customers’ historical relationship with us; (ii) customers’ current financial condition; and (iii) current and projected economic conditions.

The following table presents activity in the allowance for doubtful accounts at the dates indicated (in thousands):



	December 31,
	2018			2017			2016
Balance at beginning of period	$	4,893		$	7,960		$	8,380
Charged to expense	2,083			305			2,143
Write-offs, net of recoveries	(76		)	(3,372		)	(2,563		)
Balance at end of period	$	6,900		$	4,893		$	7,960

Contingencies

Certain conditions may exist as of the date our consolidated financial statements are issued that may result in a loss to us, but which will only be resolved when one or more future events occur or fail to occur. Our management, with input from legal counsel, assesses such contingent liabilities, and such assessment inherently involves judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in proceedings, our management, with input from legal counsel, evaluates the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

If the assessment of a contingency indicates that it is probable that a loss has been incurred and the amount of liability can be reasonably estimated, then the estimated liability is accrued in our consolidated financial statements. If the assessment indicates that a potentially material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss if determinable and material, is disclosed. Actual results could vary from these estimates and judgments.

Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed.

In addition, we are subject to federal, state and local laws and regulations relating to the protection of the environment, which require us to remove or remedy the effect of the disposal or release of specified substances at our operating sites. We record environmental liabilities at a specific site when environmental assessments indicate remediation efforts are probable, and costs can be reasonably estimated based upon past experience, discussions with operating personnel, advice of outside engineering and consulting firms, discussion with legal counsel or current facts and circumstances. The estimates related to environmental matters are uncertain because: (i) estimated future expenditures are subject to cost fluctuations and change in the estimated remediation period; (ii) unanticipated liabilities may arise; and (iii) changes in federal, state and local environmental laws and regulations may significantly change the extent of remediation.

Our estimated environmental remediation liabilities are generally not discounted to present value since the ultimate amount and timing of cash payments for such liabilities are typically not readily determinable. Expenditures to mitigate or prevent future environmental contamination are capitalized. We monitor the environmental liabilities regularly and record adjustments to our initial estimates, from time to time, to reflect changing circumstances and estimates based upon additional developments or information obtained in subsequent periods. We maintain insurance which may cover certain environmental expenditures. Recoveries of environmental remediation expenses from other parties are recorded when their receipt is assured beyond a reasonable doubt.

Cost of Product Sales

Cost of product sales relates to sales of refined petroleum products, consisting primarily of gasoline, propane, ethanol, biodiesel and middle distillates, such as heating oil, diesel fuel and kerosene, and fuel oil, as well as the effects of hedges on refined petroleum product acquisition costs and hedges of fixed-price contracts.

Debt Issuance Costs

Costs incurred upon the issuance of our debt instruments are capitalized and amortized over the life of the associated debt instrument on a straight-line basis, which approximates the effective interest method. If the debt instrument is retired before its scheduled maturity date, any remaining issuance costs associated with that debt instrument are expensed in the same period. Debt issuance costs related to our amended $1.5 billion revolving Credit Facility with a syndicate of lending institutions dated September 30, 2016 (the “Credit Facility”), are reported in “Other non-current assets”. Debt issuance costs related to our outstanding notes are reported as a reduction of the carrying amount of our outstanding notes.

Derivative Instruments

Derivatives are financial and physical instruments whose fair value is determined by changes in a specified benchmark such as interest rates or commodity prices. We use derivative instruments such as forwards, futures, swaps and other contracts to manage market price risks associated with inventories, firm commitments, interest rates and certain forecasted transactions. We do not engage in speculative trading activities.

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

We recognize these transactions on our consolidated balance sheets as assets and liabilities based on the instrument’s fair value. Changes in fair value of derivative instrument contracts are recognized in earnings in the current period unless specific hedge accounting criteria are met. If the derivative instrument is designated as a hedging instrument in a fair value hedge, gains and losses incurred on the instrument will be recorded in earnings to offset corresponding losses and gains on the hedged item. If the derivative instrument is designated as a hedging instrument in a cash flow hedge, gains and losses incurred on the instrument are recorded in other comprehensive income. Any gains or losses incurred on the derivative instrument that are not effective in offsetting changes in fair value or cash flows of the hedged item are recognized immediately in earnings. Gains and losses on cash flow hedges are reclassified from accumulated other comprehensive income (“AOCI”) to earnings when the forecasted transaction occurs and affects net income or, as appropriate, over the economic life of the underlying asset or liability. Gains and losses related to a derivative instrument designated as a hedge of a forecasted transaction that is no longer likely to occur are immediately recognized in earnings. Physical forward contracts and futures contracts that have not been designated in a hedge relationship are marked-to-market.

To qualify as a hedge, the item to be hedged must expose us to risk and we must have an expectation that the related hedging instrument will be effective at reducing or mitigating that exposure. In accordance with the hedging requirements, we document all hedging relationships at inception and include a description of the risk management objective and strategy for undertaking the hedge, identification of the hedging instrument, the hedged item, the nature of the risk being hedged, the method for assessing effectiveness of the hedging instrument in offsetting the hedged risk and the method of measuring any ineffectiveness. We link all derivative instruments that are designated as fair value or cash flow hedges to specific assets and liabilities on our consolidated balance sheets or to specific firm commitments or forecasted transactions. When an event or transaction occurs, such as the sale of hedged fuel inventory or the expiration of derivative contracts, we discontinue hedge accounting. We also formally assess, both at the hedge’s inception and on an ongoing basis, whether the derivative instruments that are used in designated hedging relationships are highly effective in offsetting changes in fair values or cash flows of hedged items. If it is determined that a derivative instrument is not highly effective as a hedge or that it has ceased to be a highly effective hedge, we discontinue hedge accounting prospectively. We measure ineffectiveness by comparing the change in fair value of the hedge instrument to the change in fair value of the hedged item. The time value component is excluded from our hedge assessment and reported directly in earnings.

Earnings per Unit

Basic and Diluted earnings per unit (“EPU”) are computed taking into account the weighted average outstanding limited partner units as well as the effect of participating securities. Our participating securities are generally comprised of certain unvested restricted units, granted under the 2013 Long Term Incentive Plan of Buckeye Partners, L.P. (the “LTIP”), and participate in earnings only to the extent of certain distribution equivalent rights. Net income allocable to participating securities reduces net income attributable to Buckeye Partners, L.P. to arrive at net income attributable to unitholders. For Diluted EPU, we use the more dilutive of the treasury stock or two-class method, taking into consideration dilutive securities resulting from restricted-unit grants under the LTIP. See Note 23 - (Loss) Earnings Per Unit for further discussion.

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Equity Investments

We account for investments in entities in which we do not exercise control, but have significant influence, using the equity method of accounting. Under this method, an investment is recorded at acquisition cost plus our equity in undistributed earnings or losses since acquisition, reduced by distributions received and amortization of excess net investment. Excess investment is the amount by which the total investment exceeds our proportionate share of the book value of the net assets of the investment. Such excess investment not related to any specific accounts of the investee is treated as goodwill and not amortized. Amounts associated with specific accounts of the investee are amortized. The amortization of excess net investment is included in earnings from equity investments in our consolidated statement of operations. We evaluate equity method investments for impairment whenever events or changes in circumstances indicate that there is an other than temporary loss in value of the investment. In the event that the loss in value of an investment is other than temporary, we record a charge to earnings to adjust the carrying value to fair value. We assess the fair value of equity investments using commonly accepted valuation methodologies, including but not limited to, peer group multiples, comparable sales-transaction multiples, and discounted cash flow models. Estimates of future cash flows that would be used to determine fair value include: (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses; (ii) long-term growth rates; and (iii) probabilities assigned to different cash flow scenarios. A significant change in these underlying assumptions could result in an impairment charge. For the year ended December 31, 2018, we recorded a $300.3 million non-cash loss related to the anticipated sale of our equity investment in VTTI. There were no impairments of our equity investments for the years ended December 31, 2017 or 2016. See Note 4 - Acquisitions, Investments and Dispositions for further discussion.

We account for investments in entities that we do not control and for which we do not have the ability to exercise significant influence over operating and financial policies at fair value except in situations when the equity security does not have a readily determinable fair value. In these situations, we record the equity investment at cost less impairments and changes resulting from observable price changes in orderly transactions for similar investments.

Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Our fair value estimates are based on either: (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. Recognized valuation techniques employ inputs such as product prices, operating costs, discount factors and business growth rates. These inputs may be either readily observable, corroborated by market data or generally unobservable. In developing our estimates of fair value, we endeavor to utilize the best information available and apply market-based data to the extent possible. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements based on the observability of inputs used to estimate such fair values. The characteristics of fair value amounts classified within each level of the hierarchy are described as follows:


•	Level 1 inputs — unadjusted quoted prices which are available in active markets for identical, unrestricted assets or liabilities as of the reporting date;


•	Level 2 inputs — quoted market prices in markets that are not considered to be active or financial instruments for which all significant inputs are observable, either directly or indirectly; and


•	Level 3 inputs — prices or valuations that require inputs that are both significant to the fair value measurement and unobservable. These inputs are typically used in connection with internally developed valuation methodologies where management makes its best estimate of an instrument’s fair value.

We categorize our financial assets and liabilities using this hierarchy at each balance sheet reporting date.

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Foreign Currency

Puerto Rico is a commonwealth country under the U.S., and thus uses the U.S. dollar as its official currency. The functional currency of our operations in BBH and St. Lucia is the U.S. dollar. Foreign exchange gains and losses arising from transactions denominated in a currency other than the U.S. dollar relate to a nominal amount of supply purchases and are included in “Other income (expense)” within the consolidated statements of operations. The effects of foreign currency transactions were not material for the years ended December 31, 2018, 2017 and 2016.

Our investment in VTTI indirectly exposed us to foreign currency risk, primarily with respect to the Euro, Malaysian Ringgit, and United Arab Emirates Dirham. VTTI manages its exposure to foreign currency risk with foreign exchange hedging strategies. Our proportionate share of VTTI’s foreign currency risk with foreign currency transaction, hedging, and translation gains and losses is included in our earnings from equity investments and accumulated other comprehensive income, as applicable, during the time period for which we applied the equity method of accounting. We recognized our proportionate share, of $49.6 million, of VTTI’s other comprehensive loss, primarily comprised of foreign currency translation adjustments, in other comprehensive loss (income) for the nine months ended September 30, 2018. Due to certain terms of the definitive agreement regarding the divestiture of our equity interest in VTTI, beginning in the fourth quarter of 2018, we determined we no longer had the ability to exercise significant influence over the operating and financial policies of VTTI. Accordingly, we accounted for our investment at fair value and therefore included the amount of foreign currency translation deferred in AOCI as part of the impairment of our investment. See Note 4 - Acquisition, Investments and Disposition for further discussion.

Goodwill

Goodwill represents the excess of purchase price over fair value of net assets acquired. Our goodwill amounts are assessed for impairment: (i) on an annual basis on October 31st each year or (ii) on an interim basis if circumstances indicate it is more likely than not the fair value of a reporting unit is less than its fair value.

Goodwill is tested for impairment at each reporting unit. A reporting unit is a business segment or one level below a business segment for which discrete financial information is available and regularly reviewed by segment management. Our reporting units are our business segments, with the exception of our Global Marine Terminals segment which consists of: (i) our operations in the Caribbean and New York Harbor, as well as our equity investment in VTTI, which we refer to as our “GMT Caribbean and NYH reporting unit”; and (ii) our operations in South Texas, including our equity investment in the STG Terminal (the “GMT South Texas” reporting unit).

We may perform a qualitative assessment to determine whether the fair value of our reporting units are more likely than not less than the carrying amount. In 2018, we adopted Accounting Standards Update (“ASU”) ASU 2017-04 which simplified the test for goodwill impairment. Under the new guidance, if the carrying amount of a reporting unit exceeds its estimated fair value, an impairment is recorded for the amount of the excess up to the amount of goodwill for the respective reporting unit. The estimate of the fair value of the reporting unit is determined using a weighting of an expected present value of future cash flows and a market multiple valuation method, giving more weighting to our estimate of future cash flows. The present value of future cash flows is estimated using: (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses; (ii) long-term growth rates; and (iii) appropriate discount rates. The market multiple valuation method uses appropriate market multiples from comparable companies on the reporting unit’s earnings before interest, tax, depreciation and amortization. We evaluate industry and market conditions for purposes of weighting the income and market valuation approach. Using this methodology, the Partnership performed a goodwill recoverability test as of September 30, 2018, as discussed in Note 10 - Goodwill and Intangible Assets, and concluded that the goodwill attributable to the GMT Caribbean and NYH reporting units, had been impaired. Furthermore, we performed our annual assessment on October 31, 2018 to determine if any significant events or changes in circumstances had occurred that would be considered a potential triggering event. We did not identify any indication of a triggering event that would indicate the existence of further impairment of the reporting units.

Income Taxes

With the exception of federal and state income taxes from Buckeye Development & Logistics LLC (“BDL”), federal income taxes from Buckeye Caribbean Terminals LLC (“Buckeye Caribbean”) and certain MLP entity level state income taxes, the Partnership’s federal and certain state income taxes are the responsibility of the partners and are not reflected in these consolidated financial statements.

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In addition, outside the continental U.S., our operations at BBH and St. Lucia are exempt from income taxes. Our operations at BBH are tax exempt by the Bahamian government pursuant to concessions granted under the Hawksbill Creek Agreement between the Government of The Bahamas and the Grand Bahama Port Authority. These concessions have been extended through May 2036 by the Grand Bahama Investment Incentives Act. Our operations in St. Lucia are exempt from income taxes and duties pursuant to concessions granted under the terms of a tax concession agreement effective in 2007 and in effect for a minimum of 50 years. Our operations at the Yabucoa terminal are subject to income taxes within the Commonwealth of Puerto Rico. Buckeye Caribbean is the holder of a tax exemption grant issued by the Office of Industrial Tax Exemption of the Puerto Rico Department of State under the Tax Incentives Act of 1998 (the “Act”). Under the current terms of the tax exemption grant, Buckeye Caribbean is subject to an income tax rate of 4% to 7% on industrial development income. The grant also provides additional exemptions as follows: (i) 90% exempt from real and personal property taxes; (ii) 60% exempt from municipal taxes on industrial development income; and (iii) 100% exempt from excise taxes imposed under Subtitle C of the Puerto Rico Internal Revenue Code, to the extent provided in Section 6(c) of the Act. The tax exemption grant provides a 20 year exemption period, which commenced on January 1, 2002 and, unless renewed, would end with the tax year ending December 31, 2021. We are currently seeking a renewal of our tax exemption grant.

We recognize deferred tax assets and liabilities for temporary differences between the amounts of assets and liabilities measured for financial reporting purposes and income tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. See Note 22 - Income Taxes for the impact of the Tax Cuts & Jobs Act. We evaluate the need for a valuation allowance and consider all available positive and negative evidence, including projected operating income or losses for the foreseeable future, to determine the likelihood of realizing the benefits of deferred tax assets. If the value of the deferred tax assets exceeds the estimated future benefit, we record a valuation allowance to reduce our deferred tax assets to the amount of future benefit that is more likely than not to be realized. In the future, if the realization of the deferred tax assets should occur, a reduction to the valuation allowance related to the deferred tax assets would increase net income in the period such determination is made. We have no unrecognized tax benefits related to uncertain tax positions.

Intangible Assets

Intangible assets with finite useful lives are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Intangible assets that have finite useful lives are amortized over their useful lives. Intangible assets include contracts and customer relationships. The fair values of these intangibles are based on the present value of cash flows attributable to the customer relationship or contract, which includes management’s estimates of revenue and operating expenses and costs relating to utilization of other assets to fulfill such contracts. The customer contracts are being amortized over their contractual lives with a range of 1 to 10 years. For the customer relationships, we determine the recovery period based on historical customer attrition rates and management’s assumptions on future events, including customer demand, contract renewal, useful lives of related assets and market conditions. The customer relationships are being amortized over the estimated recovery period of 12 to 20 years. When necessary, intangible assets’ useful lives are revised and the impact on amortization is reflected on a prospective basis.

Inventories

We generally maintain two types of inventory. Our Merchant Services segment principally maintains refined petroleum products inventory, consisting of gasoline, propane, butane, ethanol, biodiesel and middle distillates, such as heating oil, diesel fuel and kerosene. Inventory is generally valued at the lower of weighted average cost or net realizable value, unless such inventories are hedged. Net realizable value is defined as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. Hedged inventory is adjusted for the effects of applying fair value hedge accounting.

We also maintain materials and supplies inventory such as pipe, valves, pumps, electrical/electronic components, drag reducing agent and other miscellaneous items that are valued at the lower of weighted average cost or net realizable value.

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Noncontrolling Interests

The consolidated balance sheets and statements of operations include noncontrolling interests that relate primarily to Buckeye Texas, Buckeye Pipe Line Services Company (“Services Company”) and the Sabina crude butadiene pipeline (the “Sabina Pipeline”) that are not wholly owned by Buckeye. In April 2018, we acquired our partner’s interest in Buckeye Texas and own 100% of the entity. See Note 4 - Acquisition, Investments and Dispositions for further discussion.

Pensions and Postretirement Benefits

Services Company sponsors a defined contribution plan, a defined benefit plan and the Employee Stock Ownership Plan (“ESOP”) that provide retirement benefits to certain regular full-time employees. Services Company also sponsors an unfunded post-retirement plan that provides health care and life insurance benefits for certain of its retirees. We develop pension and postretirement health care and life insurance benefits costs from actuarial valuations. The measurement of expenses and liabilities related to these plans is based on management’s assumptions related to future events, including discount rate, expected return on plan assets, rate of compensation increase, and health care cost trend rates. The estimates and assumptions directly affect net periodic benefit expense and obligations for these plans. The actuarial assumptions that we use may differ from actual results due to changing market rates or other factors. These differences could affect the amount of pension and postretirement health care and life insurance benefit expense we have recorded or may record.

Property, Plant and Equipment

We record property, plant and equipment at its original acquisition cost. Property, plant and equipment consist primarily of pipelines, terminals, storage and processing facilities, jetties, subsea pipelines and docks, and pumping and station equipment. Generally, we depreciate property, plant and equipment based on the straight-line or group depreciation methods over the estimated useful lives, except for land. Relocations of assets for certain regulated operations are accounted for as reimbursements of capital expenditures. See Note 8 - Property, Plant and Equipment for the depreciation life of our assets.

Additions to property, plant and equipment, including maintenance and expansion and cost reduction capital expenditures, are recorded at cost. Maintenance capital expenditures maintain and enhance the safety and integrity of our pipelines, terminals, storage and processing facilities, and related assets, and expansion and cost reduction capital expenditures expand the reach or capacity of those assets, to improve the efficiency of our operations and to pursue new business opportunities. We expense routine maintenance and repairs as incurred. The cost of property, plant and equipment sold or retired and the related accumulated depreciation, except for certain pipeline system assets, are removed from our consolidated balance sheet in the period of sale or disposition, and any resulting gain or loss is included in earnings. For our pipeline system assets where we apply group depreciation method, we generally charge the original cost of property sold or retired to accumulated depreciation and amortization, net of salvage and cost of removal. When a separately identifiable group of assets, such as a stand-alone pipeline system is sold, we will recognize a gain or loss in our consolidated statements of operations for the difference between the cash received and the net book value of the assets sold.

We assess the recoverability of our long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. We determine the estimated undiscounted future cash flows expected to result from the use of the asset and its eventual disposal. If the sum of the estimated undiscounted future cash flows exceeds the carrying amount, no impairment is necessary. If the carrying amount exceeds the sum of the undiscounted cash flows, an impairment charge is recognized based on the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or estimated fair value less costs to sell. Estimates of undiscounted future cash flows include: (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses; (ii) long-term growth rates; and (iii) estimates of useful lives of the assets. Such estimates of future undiscounted net cash flows are highly subjective and are based on numerous assumptions about future operations and market conditions.

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Revenue Recognition

The majority of our service-based revenue is derived from fee-based transportation, terminalling, and storage services that we provide to our customers. We also generate revenue from the marketing and sale of petroleum products. We recognize revenues from customer fees for services rendered or by selling petroleum products. Under Accounting Standards Codification (“ASC”) Topic 606, Revenue from Contracts with Customers (“ASC 606”), we recognize revenue over time or at a point in time, depending on the nature of the performance obligations contained in the respective contract with our customer. A performance obligation is a promise in a contract to transfer goods or services to the customer. The contract transaction price is allocated to each performance obligation and recognized as revenue when, or as, the performance obligation is satisfied. In certain situations, we recognize revenue pursuant to guidance in the Accounting Standards Codification other than ASC 606. These situations primarily relate to leases and derivatives. The adoption of ASC 606 did not have a material impact on the timing or amount of our revenue recognition. The following is an overview of our significant revenue streams, including a description of the respective performance obligations and related methods of revenue recognition.

Pipeline Transportation

Revenue from pipeline operations is comprised of tariffs and fees associated with the transportation of liquid petroleum products, generally at published tariffs, and in certain instances, revenue from committed capacity contracts at negotiated rates. Tariff revenue is recognized either at the point of delivery or at the point of receipt, pursuant to specifications outlined in the respective tariffs. Revenue associated with capacity reservation is recognized ratably over the respective term, regardless of whether the capacity is actually utilized. Our tariffs generally include product loss allowance factors intended to, among other things, compensate for losses due to evaporation, measurement tolerances, interface downgrades and other product losses in transit. We value the difference of allowance volumes to actual losses at the estimated net realizable value in the period the variance occurred, and the result is recorded as an adjustment to pipeline transportation revenue. The majority of our contracts have a single performance obligation to provide pipeline transportation service, and the performance obligation is primarily satisfied over time as transportation services are provided, whereby progress is generally measured based on the volume of product transported. Our services are typically billed on a weekly basis, and we generally do not offer extended payment terms. In addition, we have certain agreements that require counterparties to throughput a minimum volume over an agreed-upon period. Revenue pursuant to such agreements is recognized at the earlier of when the volume is throughput or proportionally if we determine that the customer is not expected to meet its volume commitment.

Terminalling and Storage Services

Revenue from terminalling and storage operations is recognized as services are performed. Terminalling and storage revenue includes terminalling or throughput fees, which are generated when we receive and redeliver liquid petroleum products from and to pipelines, marine vessels, trucks, or rail-cars, as well as storage fees, which are generated as we provide storage capacity. We generate revenue through a combination of month-to-month and multi-year terminalling service and storage capacity arrangements. The majority of our contracts have a single performance obligation to provide terminalling and storage services that is primarily satisfied over time as these services are provided. Terminalling fees, as applicable, are recognized as the liquid petroleum product is delivered to a connecting carrier or to a customer’s designated mode of transport, which could include a pipeline, truck, marine vessel, or rail-car or, in certain situations, as product is received, based on the volume of product handled. Storage fees for contracted capacity are typically recognized in revenue ratably over the term of the contract, regardless of the amount of the contracted storage capacity utilized by the customer. As discussed above with respect to transportation services, progress in performing terminalling services is generally measured based upon the volume of product handled. Certain of our terminalling and storage services arrangements include product loss allowance provisions intended to, among other things, compensate for losses due to evaporation, measurement tolerances, and other product recoveries and losses. We value the difference of allowance volumes to actual losses at the estimated net realizable value in the period the variance occurred, and the result is recorded as an adjustment to terminalling and storage services revenue. We have certain contracts containing tiered pricing or volume-based discounts, which are recognized in revenue as a purchase option to acquire additional services in the period the services are performed. In addition, we have certain agreements that require counterparties to throughput a minimum volume over an agreed-upon period. Revenue pursuant to such agreements is recognized at the earlier of when the volume is throughput or proportionally if we determine that the customer is not expected to meet its volume commitment. Revenue from other ancillary services is recognized as services are rendered. Our services are typically billed on a monthly basis, and we generally do not offer extended payment terms.

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Merchant Services

Revenue from the sale of petroleum products, on a wholesale basis, is recognized at the time title to the product sold transfers to the purchaser, which generally occurs upon delivery of the product to the purchaser or its designee. Our contracts contain a single performance obligation to sell a particular petroleum product, which is generally satisfied as quantities are delivered to our customer. Our commodity sales are typically billed at the time product is delivered, and we generally do not offer extended payment terms.

Operation and Construction Services

Revenue from contract operation and construction services for facilities and pipelines not directly owned by us is recognized as the services are performed. Contract and construction services revenue typically includes costs to be reimbursed by the customer plus an operator fee. Our contracts have a single performance obligation to provide operation and construction services, which is satisfied over time as services are provided. Revenue is generally recognized utilizing costs incurred to measure our progress in fulfilling our performance obligation. Our services are typically billed on a monthly basis, and we generally do not offer extended payment terms.

Unit-Based Compensation

We award unit-based compensation to employees and directors primarily under the LTIP. All unit-based payments to employees under the LTIP, including grants of phantom units and performance units, are recognized in our consolidated statements of operations based on their grant date fair values. Compensation expense equal to the fair value of those performance unit and phantom unit awards that are expected to vest is estimated and recorded over the period the grants are earned, which is the vesting period. Compensation expense estimates are updated periodically. The vesting of the performance unit awards is also contingent upon the attainment of predetermined performance goals. Depending on the estimated probability of attainment of those performance goals, the compensation expense recognized related to the awards could increase or decrease over the remaining vesting period.

Variable Interest Entities

We evaluate our financial interests in business enterprises to determine if they represent VIEs of which we are the primary beneficiary. If such criteria are met (as discussed above in “Basis of Presentation and Principles of Consolidation”), we reflect these entities as consolidated subsidiaries. There were no changes to the entities consolidated for the year ended December 31, 2018.

Services Company and Sabina Pipeline are VIEs of which we are the primary beneficiary and are, therefore, consolidated. We own a 63% interest in Sabina Pipeline. In April 2018, we acquired the remaining 20% interest in Buckeye Texas, which was a VIE, as discussed in Note 4 - Acquisition, Investments and Disposition. Third party or affiliate ownership interests in our consolidated VIEs are presented as noncontrolling interests.

Recently Adopted Accounting Guidance

Goodwill Impairment. Effective July 1, 2018, we adopted ASU 2017-04, which simplifies the accounting for goodwill. The guidance eliminates Step 2 from the goodwill impairment test, which required entities to calculate the implied fair value of a reporting unit’s goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. An impairment charge is now determined by the amount by which the carrying amount of a reporting unit exceeds its fair value up to the amount of goodwill. The guidance is applied using a prospective approach. We applied this standard to the calculation of the goodwill impairment charge referenced above. See Note 10 - Goodwill and Intangible Assets for further discussion.

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Revenue from Contracts with Customers. Effective January 1, 2018, we adopted ASC 606, using the modified retrospective transition method, which required us to apply the new standard to (i) all new revenue contracts entered into after January 1, 2018, and (ii) revenue contracts which were not completed as of January 1, 2018. ASC 606 replaces existing revenue recognition requirements in GAAP and required entities to recognize revenue at an amount that reflects the consideration to which we expect to be entitled in exchange for transferring goods or services to a customer. ASC 606 also required certain disclosures regarding qualitative and quantitative information with respect to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The adoption of ASC 606 did not result in a transition adjustment nor did it have a material impact on the timing or amount of our revenue recognition. See Note 3 - Revenue from Contracts with Customers for additional discussion.

Recognition and Measurement of Financial Assets and Liabilities. Effective January 1, 2018, we adopted ASU 2016-01, and it will be applied prospectively. This ASU issued a new standard related to certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. Most prominent among the changes in this standard is the requirement for changes in the fair value of marketable equity investments, with certain exceptions, to be recognized through net income rather than other comprehensive income (“OCI”). Under the standard, marketable equity investments that do not have a readily determinable fair value are eligible for the measurement alternative. Using the measurement alternative, investments without readily determinable fair values will be valued at cost, with adjustments to fair value for changes in price or impairments reflected through net income. The adoption of this guidance did not have an impact on our consolidated financial statements.

Classification of Certain Cash Receipts and Cash Payments. Effective January 1, 2018, we adopted ASU 2016-15, applying the retrospective transition method. This ASU requires changes in the presentation of certain items, including but not limited to debt prepayment or debt extinguishment costs; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. The adoption of this guidance did not have a material impact on our consolidated financial statements.

Business Combinations. Effective January 1, 2018, we adopted ASU 2017-01, and it will be applied prospectively to future business combinations. This ASU clarifies the definition of a business in order to assist entities with evaluating whether transactions should be accounted for as acquisitions/disposals of assets or businesses. The guidance provides a screen to help entities determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set of assets is not a business. If the threshold of the screen is not met, the guidance further clarifies that the set of assets is not a business unless it includes an input and a substantive process that together significantly contribute to the ability to create output.

Retirement Benefits. Effective January 1, 2018, we adopted ASU 2017-07, which improves the presentation of net periodic pension and postretirement benefit costs. The interest cost, expected return on plan assets, actuarial loss due to settlements, and the amortization of unrecognized loss have been reclassified from operating expenses to other expense, applying the retrospective transition method. We elected to apply the practical expedient which allows us to reclassify amounts disclosed previously in the retirement benefits note as the basis for applying retrospective presentation for comparative periods as it is impracticable to determine the disaggregation of the cost components for amounts capitalized and amortized in those periods. On a prospective basis, the components of net periodic benefit costs discussed above will not be included in amounts capitalized in property, plant, and equipment. The adoption of this guidance did not have a material impact on our consolidated financial statements. In connection with the adoption of ASU 2017-07, using the retrospective transition method, we reclassified $1.5 million and $3.4 million of expenses related to our Retirement Income Guarantee Plan and unfunded post-retirement medical benefit plan, originally included in operating expenses for the years ended December 31, 2017 and 2016, respectively, to other expense. Such reclassifications had no impact on net income.

Modifications to Share-Based Payment Awards. Effective January 1, 2018, we adopted ASU 2017-09, and it will be applied prospectively to future modifications of our unit-based awards, if any. This guidance clarifies when changes in the terms or conditions of share-based payment awards must be accounted for as modifications under existing guidance. The guidance requires that entities apply modification accounting unless the award’s fair value, vesting conditions and classification as an equity or liability instrument are the same immediately before and after the change.

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Tax Cuts and Jobs Act. In December 2017, the Tax Cuts and Jobs Act (the “Tax Act”) was passed into law. The Tax Act makes changes to the U.S. tax code including, but not limited to (i) reducing the U.S. federal corporate income tax rate from a top rate of 35% to 21% effective January 1, 2018, (ii) requiring a one-time transition tax on certain unrepatriated earnings of foreign subsidiaries that may electively be paid over eight years, and (iii) accelerated first year expensing of certain capital expenditures.

Shortly after the Tax Act was enacted, the SEC staff issued Staff Accounting Bulletin (“SAB”) No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (“SAB 118”) which provides guidance on accounting for the Tax Act’s impact. SAB 118 provided a measurement period, which in no case may extend beyond one year from the Tax Act enactment date, during which an entity acting in good faith may complete the accounting for the impacts of the Tax Act under ASC Topic 740. In accordance with SAB 118, the entity must reflect the income tax effects of the Tax Act in the reporting period in which the accounting under ASC Topic 740 is complete. With the exception of federal and state income taxes from BDL, federal income taxes from Buckeye Caribbean and certain MLP entity level state income taxes, the Partnership’s federal and certain state income taxes are the responsibility of the partners and are not reflected in these consolidated financial statements. Accordingly, the Tax Act did not have a material impact on our consolidated financial statements or on our disclosures.

Recent Accounting Guidance Not Yet Adopted

Collaborative Arrangements. In November 2018, the Financial Accounting Standards Board (“FASB”) issued ASU 2018-18, which clarifies whether certain transactions between collaborative arrangement participants should be accounted for as revenue under ASC 606. The new guidance also provides more comparability in the presentation of revenue for certain transactions between collaborative arrangement participants. The guidance is effective for fiscal years beginning after December 15, 2019 and interim periods within those fiscal years, with early adoption permitted. The guidance should be applied retrospectively to the date of initial application of ASC 606. We expect to adopt this standard effective January 1, 2020 and are currently evaluating the impact that it will have on our consolidated financial statements and disclosures.

Targeted Improvements to Related Party Guidance for Variable Interest Entities. In October 2018, the FASB issued ASU 2018-17 that changes the guidance for determining whether a decision-making fee is a variable interest. The guidance provides that indirect interests held through related parties under common control will be considered on a proportional basis when determining whether certain decision-making fees are variable interests. The guidance is effective for fiscal years beginning after December 15, 2019 and interim periods within those fiscal years, with early adoption permitted. The guidance should be applied retrospectively, with a cumulative effect adjustment to retained earnings. We expect to adopt this standard effective January 1, 2020 and are currently evaluating the impact that it will have on our consolidated financial statements and disclosures.

Cloud Computing Arrangements. In August 2018, the FASB issued ASU 2018-15, which aligns a customer’s accounting for capitalizing implementation costs in a cloud computing service arrangement that is hosted by the vendor with the requirements for capitalizing implementation costs incurred to develop or obtain an internal-use software license. The guidance is effective for fiscal years beginning after December 15, 2019 and interim periods within those fiscal years, with early adoption permitted. The guidance can be applied prospectively or retrospectively. We expect to adopt this standard effective January 1, 2020 and are currently evaluating the impact that it will have on our consolidated financial statements and disclosures.

Changes to the Disclosure Requirements for Defined Benefit Plans. In August 2018, the FASB issued ASU 2018-14, which amends existing guidance on disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The new guidance is effective for fiscal years ending after December 15, 2020, with early adoption permitted. The new guidance requires retrospective application. We expect to adopt this standard effective January 1, 2021 and are currently evaluating the impact that it will have on our disclosures.

Changes to the Disclosure Requirements for Fair Value Measurement. In August 2018, the FASB issued ASU 2018-13, which amends existing guidance on disclosure requirements for fair value measurements. The new guidance is effective for fiscal years beginning after December 15, 2019 and interim periods within those fiscal years, with early adoption permitted. The new guidance requires prospective application on changes in unrealized gains and losses, the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements, and the narrative description of measurement uncertainty. The effects of other amendments must be applied retrospectively to all periods presented. We expect to adopt this standard effective January 1, 2020 and are currently evaluating the impact that it will have on our disclosures.

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Improvements to Nonemployee Share-Based Payment Accounting. In May 2018, the FASB issued ASU 2018-07, which conformed the current nonemployee share-based accounting with employee share-based accounting. The new standard is effective as of January 1, 2019 with early adoption permitted. We adopted this standard on January 1, 2019 and it did not have a material impact on our consolidated financial statements and disclosures.

Derivatives and Hedging. In August 2017, the FASB issued ASU 2017-12, which amends and simplifies existing guidance in order to improve the financial reporting of hedging relationships to better align risk management activities in financial statements and make targeted improvements to simplify the application of current guidance related to the assessment of hedge effectiveness. In October 2018, the FASB issued ASU 2018-16, which includes the Overnight Index Swap Rate based on Secured Overnight Financing Rate as a U.S. benchmark interest rate for hedge accounting purposed under ASC Topic 815 “Derivatives and Hedging.” The amendments are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with early application permitted. The new guidance requires prospective application, with a cumulative effect adjustment to the beginning balance of partners’ capital for existing hedging relationships. We adopted this standard on January 1, 2019 and it did not have a material impact on our consolidated financial statements and disclosures.

Measurement of Credit Losses on Financial Instruments. In June 2016, the FASB issued ASU 2016-13, which replaces the current incurred loss impairment method with a method that reflects expected credit losses on financial instruments. In November 2018, the FASB issued update ASU 2018-19 that clarify the scope of the standard in the amendments in ASU 2016-13. The new standard is effective as of January 1, 2020, and early adoption is permitted as of January 1, 2019. We expect to adopt this standard effective January 1, 2020 and are currently evaluating the impact that the adoption of this standard will have on our consolidated financial statements and disclosures.

Leases. In February 2016, the FASB issued ASU 2016-02, as amended by subsequent accounting standard updates (collectively, “Topic 842”), requiring lessees to recognize a right-of-use (“ROU”) asset and a lease liability on the balance sheet for leases with lease terms greater than twelve months, in addition to enhanced disclosure requirements. Topic 842, through an alternative transition method, permits an entity to adopt the provisions of ASU 2016-02 by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption without adjustment to the financial statements for periods prior to adoption. Consequently, an entity’s reporting for the comparative periods presented in the financial statements in which it adopts the new leases standard will continue to be in accordance with the previous lease guidance in ASC Topic 840 “Leases.” In December 2018, the FASB issued ASU 2018-20, allowing an accounting policy election that permits lessors to account for sales tax and other similar taxes collected from a lessee as lessee costs. The new guidance also clarifies the accounting for certain lessor costs. In July 2018, the FASB issued ASU 2018-11, allowing a practical expedient that permits lessors to not separate non-lease components from the associated lease component if certain conditions are present. In July 2018, the FASB issued update ASU 2018-10 that provides narrow-scope improvements to the new standard including clarification on reassessment, change in reference index or rate, and periods included in the lease term. In January 2018, the FASB issued ASU 2018-01, permitting an entity to elect a transition practical expedient to not apply the provisions of ASU 2016-02 to land easements that existed or expired before the effective date of ASU 2016-02 and that were not previously accounted for as leases under the previous lease guidance in ASC Topic 840 “Leases.” ASU 2016-02 also provides an election for a package of practical expedients which permits an entity to not reassess whether any expired or existing contracts contain leases, the classification of the lease, and any initial direct costs. We applied these practical expedients as part of our adoption.

The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2018 and interim periods within those annual periods, with early adoption permitted. We adopted this guidance effective January 1, 2019. The most significant impact of the new standard is the recognition of ROU assets and lease liabilities as part of our consolidated balance sheet upon adoption. The implementation did not have an impact on our debt-covenant compliance under our current agreements. The ASU requires increased disclosures which will be included in our quarterly and annual consolidated financial statements beginning with our 2019 reporting periods.

We currently estimate the ROU assets and lease liabilities will be approximately $160.0 million as of March 31, 2019.

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

3. REVENUE FROM CONTRACTS WITH CUSTOMERS

Contract Balances

Contract assets primarily relate to our rights to consideration for completed performance obligations that are not billable at the reporting date. We recognize contract assets in situations where revenue recognition occurs prior to billing the customer based on our rights under the contract. Contract assets are transferred to accounts receivable when the rights become unconditional, which is generally upon billing.

Contract liabilities primarily relate to consideration received from customers in advance of completing the performance obligation. We recognize contract liabilities under these arrangements as revenue once all contingencies or potential performance obligations have been satisfied by either the (i) transportation of volumes, (ii) performance of terminalling and storage services, or (iii) expiration of the customer’s rights under the contract. We also recognize contract liabilities in revenue to the extent it is determined that an amount of volume associated with a minimum volume commitment payment will not be shipped by the customer in a future period.

The following table provides information about receivables from contracts with customers, contract assets and contract liabilities (in thousands):



	December 31, 2018			December 31, 2017
Receivables from contracts with customers	$	199,324		$	245,280
Contract assets	16,989			13,999
Contract liabilities	(26,999		)	(15,778		)

During the year ended December 31, 2018, we reclassified approximately $14.0 million of contract assets at the beginning of the period to receivables as a result of the rights to the consideration becoming unconditional and billable. Revenue recognized during the year ended December 31, 2018 from amounts included in contract liabilities at the beginning of the period was approximately $8.2 million.

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



	Estimated Revenue ⁽¹⁾
2019	$	358,060
2020	196,399
2021	126,777
2022	51,499
Thereafter	212,374
Total	$	945,109


(1)	Excludes revenue arrangements accounted for as leases in the amount of $211.7 million for 2019, $207.2 million for 2020, $188.0 million for 2021, $134.8 million for 2022, and $48.5 million thereafter.

Our contractually committed revenue disclosure, for purposes of the tabular presentation above, excludes estimates of variable rate escalation clauses in our contracts with customers and is generally limited to our contracts fixed pricing and minimum volume components. Our contractually committed revenue disclosure generally excludes remaining performance obligations on contracts with index-based pricing or variable volume attributes.

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

4. ACQUISITIONS, INVESTMENTS AND DISPOSITION

2019 Transaction

VTTI Acquisition and Divestiture

In January 2017, we acquired an indirect 50% equity interest in VTTI for cash consideration of $1.15 billion (the “VTTI Acquisition”) and made a capital contribution to VTTI, in the amount of $236.8 million, to fund our 50% share of the aggregate

cash consideration paid by VTTI to acquire all of the outstanding publicly held units of VTTI Energy Partners LP, formerly a

publicly traded master limited partnership. We owned VTTI jointly with Vitol S.A. (“Vitol”).

In November 2018, we executed a definitive share purchase agreement (the “SPA”) to sell our 50% equity interest in VTTI for approximately $975.0 million, excluding transaction costs of approximately $8.0 million, which was closed in January 2019. As part of the SPA, we also received a final earnings distribution of $22.6 million. As a result, effective September 30, 2018, we recorded our investment in VTTI at its estimated fair value, as determined by the proceeds, resulting in a non-cash loss of $300.3 million, which was reported in (loss) earnings from equity investments in our Consolidated Statement of Operations. Pursuant to the SPA, during the period between November 1, 2018 and the completion of the sale of our interest in VTTI, we agreed to certain governance changes with respect to the VTTI investment, and, as a result, commencing with the fourth quarter of 2018, we concluded we no longer had the ability to exercise significant influence over the operating and financial policies of VTTI. Effective September 30, 2018, we recorded our investment in VTTI at fair value based on the agreed selling price and ceased recording any further equity earnings.

2018 Transactions

Domestic Asset Divestiture

On December 17, 2018, we sold certain domestic pipeline and terminal assets, which included (i) our jet fuel pipeline from Port Everglades, Florida to Ft. Lauderdale-Hollywood International Airport and Miami International Airport; (ii) our pipelines and terminal facilities serving Reno-Tahoe International Airport, San Diego International Airport, and the Federal Express Corporation terminal at the Memphis International Airport; and (iii) our refined petroleum product terminals in Sacramento, California and Stockton, California (the “DPTS asset package”). Including working capital adjustments and a deferred payment of $10.0 million, we expect to receive total proceeds of $454.6 million, which excludes transaction costs of $7.7 million. We received $444.6 million in proceeds as of December 31, 2018, which resulted in an after-tax gain on the sale of approximately $342.5 million, reflected in our Consolidated Statement of Operations.

South Texas Transactions

In April 2018, as part of our strategy to serve the volume growth in crude oil and related products from the Permian Basin, we expanded our marine terminal presence in Corpus Christi, Texas, through the following transactions: (i) acquired our business partner’s 20% interest in our Buckeye Texas consolidated subsidiary, and (ii) formed a joint venture with Phillips 66 Partners LP (“Phillips 66 Partners”) and Gray Oak Gateway Holdings (“Marathon”) to develop a new deep-water, open-access marine terminal in Ingleside, Texas at the mouth of Corpus Christi Bay (the “STG Terminal”).

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The STG Terminal will be constructed and operated by us. We continue to secure additional minimum volume throughput commitments and storage contracts from customers, and our current plan is to increase the scope of this project from 3.4 million barrels of storage to 6.8 million barrels, based on current contracted throughput and storage volumes. Our construction plan also includes connectivity to multiple pipelines delivering volumes into the Corpus Christi market from growing Permian Basin production and other sources. In addition, we plan to build two deep-water vessel docks capable of berthing very large crude carrier petroleum tankers as part of the initial scope of construction.

Business Combinations

2017 Transaction

Duck Island terminal acquisition

In December 2017, we acquired Duck Island Terminal LLC, a liquid petroleum products terminalling business in Trenton, New Jersey, for approximately $26.1 million, net of cash acquired of $2.4 million. The assets of this entity are reported in our Domestic Pipelines & Terminals segment. The purchase price has been allocated to assets acquired and liabilities assumed based on estimated fair values at the acquisition date, with amounts exceeding the fair value recorded as goodwill, which represent expected synergies from combining acquired assets with our existing operations. Fair values have been developed using recognized business valuation techniques, with inputs classified as Level 3 within the fair value hierarchy. The purchase price has been allocated to tangible and intangible assets acquired as follows (in thousands):



Current assets, including cash acquired of $2,444	$	8,989
Property, plant and equipment	18,306
Intangible Assets	2,200
Goodwill	3,294
Current liabilities	(3,516		)
Environmental liabilities	(782		)
Allocated purchase price	$	28,491

We finalized the purchase price allocation during the fourth quarter of 2018 without significant adjustments.

Unaudited Pro forma Financial Results for Duck Island terminal acquisition

Our consolidated statements of operations do not include earnings from the terminalling business prior to December 20, 2017, the closing date of the acquisition. Unaudited pro forma financial information for this acquisition was not prepared because the impact was immaterial to our financial results for the year ended December 31, 2018.

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2016 Transaction

Indianola terminalling facility acquisition

In August 2016, we acquired a liquid petroleum products terminalling facility in Indianola, Pennsylvania from Kinder Morgan Transmix Company, LLC for $26.0 million. The operations of these assets are reported in our Domestic Pipelines & Terminals segment. The purchase price has been allocated to assets acquired based on estimated fair values at the acquisition date, with amounts exceeding the fair value recorded as goodwill, which represent expected synergies from combining the acquired assets with our existing operations. Fair values have been developed using recognized business valuation techniques, with inputs classified as Level 3 within the fair value hierarchy. The purchase price has been allocated to tangible and intangible assets acquired as follows (in thousands):



Inventories	$	1,554
Property, plant and equipment	16,713
Goodwill	7,758
Allocated purchase price	$	26,025

We finalized the purchase price allocation during the third quarter of 2017 without significant adjustments.

Unaudited Pro forma Financial Results for the Indianola terminalling facility acquisition

Our consolidated statements of operations do not include earnings from the terminalling facility prior to August 4, 2016, the closing date of the acquisition. The preparation of unaudited pro forma financial information for the terminalling facility is impracticable due to the fact that meaningful historical revenue information is not available. The revenues and earnings impact of this acquisition was not significant to our financial results for the year ended December 31, 2016.

5. COMMITMENTS AND CONTINGENCIES

Claims and Legal Proceedings

Environmental Contingencies

We recorded operating expenses, net of recoveries, of $13.7 million, $7.4 million and $8.2 million during the years ended December 31, 2018, 2017 and 2016, respectively, related to environmental remediation liabilities. See Notes 12 - Accrued and Other Current Liabilities and 14 - Other Non-Current Liabilities for further discussion regarding remaining estimated liabilities. Costs ultimately incurred may be in excess of our estimates, which may have a material impact on our financial condition, results of operations or cash flows. At December 31, 2018 and 2017, we had $4.2 million and $5.3 million, respectively, of receivables related to these environmental remediation liabilities covered by insurance or third-party claims.

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Lease Obligations

We lease certain property, plant and equipment under noncancelable and cancelable operating leases. Rental expense is charged to operating expenses on a straight-line basis over the period of expected benefit. Contingent rental payments are expensed as incurred. Total rental expense for the years ended December 31, 2018, 2017 and 2016 was $34.7 million, $29.9 million and $32.8 million, respectively. The following table presents minimum lease payment obligations under our operating leases with terms in excess of one year for the years ending December 31st (in thousands):



	Total ⁽¹⁾
2019	29,050
2020	26,255
2021	22,215
2022	21,378
2023	21,126
Thereafter	138,466
Total	$	258,490

____________________________


(1)	Includes BBH facility leases for properties in connection with jetty and inland dock operations, as well as tugboats and a barge in our Global Marine Terminals segment.

In addition to the rental expense discussed above, our rights-of-way expense for the years ended December 31, 2018, 2017 and 2016 were $7.9 million, $7.4 million and $7.1 million, respectively; and are subject to an annual escalation for the remaining life of all pipelines and terminals.

6. INVENTORIES

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



	December 31,
	2018		2017
Liquid petroleum products ⁽¹⁾	$	186,683	$	280,934
Materials and supplies	24,201		20,491
Total inventories	$	210,884	$	301,425

____________________________


(1)	Ending inventory was 114.7 million and 142.1 million gallons of liquid petroleum products at December 31, 2018 and 2017, respectively.

At December 31, 2018 and 2017, approximately 94% and 85% of our liquid petroleum products inventory volumes were designated in a fair value hedge relationship, respectively. Because we generally designate inventory as a hedged item upon purchase, hedged inventory is valued at current market prices with the change in value of the inventory reflected in our consolidated statements of operations.

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

7. PREPAID AND OTHER CURRENT ASSETS

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



	December 31,
	2018		2017
Prepaid insurance	$	6,622	$	7,146
Margin deposits	8,684		7,989
Contract assets	16,989		13,999
Prepaid taxes	5,311		2,865
Other	21,288		4,340
Total prepaid and other current assets	$	58,894	$	36,339

8. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consist of the following at the dates indicated (in thousands):



	Estimated Useful Lives (Years)	December 31,
	Estimated Useful Lives (Years)	2018			2017
Land	N/A	$	669,383		$	677,866
Rights-of-way	(1)	105,811			109,282
Buildings and leasehold improvements	13-50	284,399			282,778
Jetties, subsea pipeline and docks	20-50	679,500			646,922
Gas storage facility	25-50	2,349			2,349
Pipelines and terminals	7-50	5,476,790			5,289,096
Vehicles, equipment and office furnishings	3-20	155,094			150,403
Processing facilities	30-50	630,386			589,971
Construction in progress	N/A	254,982			179,573
Total property, plant and equipment		8,258,694			7,928,240
Less: Accumulated depreciation		(1,343,898		)	(1,192,448		)
Total property, plant and equipment, net		$	6,914,796		$	6,735,792

____________________________


(1)	Rights-of-way assets are depreciated over the useful life of the related pipeline assets.

Depreciation expense was $203.7 million, $202.8 million and $186.6 million for the years ended December 31, 2018, 2017 and 2016, respectively.

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

9. EQUITY INVESTMENTS

The following table presents our investments at the dates indicated (in thousands):



			December 31,
	Segment	Ownership	2018		2017
VTTI B.V. ⁽¹⁾	Global Marine Terminals	50.0%	$	975,000	$	1,399,825
West Shore Pipe Line Company	Domestic Pipelines & Terminals	34.6%	70,727		70,035
Muskegon Pipeline LLC	Domestic Pipelines & Terminals	40.0%	13,491		13,335
Transport4, LLC	Domestic Pipelines & Terminals	25.0%	553		699
South Portland Terminal LLC	Domestic Pipelines & Terminals	50.0%	12,055		10,518
South Texas Gateway Terminal LLC	Global Marine Terminals	50.0%	39,967		—
Total equity investments			$	1,111,793	$	1,494,412

____________________________


(1)	Accounted for using fair value beginning in the fourth quarter of 2018. See Note 4 - Acquisitions, Investments and Disposition for further discussion.

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



		Year Ended December 31,
	Segment	2018			2017		2016
VTTI B.V. ⁽¹⁾	Global Marine Terminals	$	13,651		$	22,910	$	—
Non-cash loss on write-down of investment in VTTI B.V. ⁽²⁾	Global Marine Terminals	$	(300,280	)	$	—	$	—
West Shore Pipe Line Company	Domestic Pipelines & Terminals	10,322			9,451		7,647
Muskegon Pipeline LLC	Domestic Pipelines & Terminals	557			1,778		2,002
Transport4, LLC	Domestic Pipelines & Terminals	817			850		765
South Portland Terminal LLC	Domestic Pipelines & Terminals	1,536			1,016		1,122
South Texas Gateway Terminal LLC ⁽³⁾	Global Marine Terminals	(726		)	—		—
Total (loss) earnings from equity investments		$	(274,123	)	$	36,005	$	11,536

____________________________


(1)	Accounted for using fair value beginning in the fourth quarter of 2018. See Note 4 - Acquisitions, Investments and Disposition for further discussion.


(2)	In September 2018, we recorded a non-cash loss related to our equity investment in VTTI.


(3)	In April 2018, we formed the STG Terminal joint venture. See Note 4 - Acquisitions, Investments and Disposition for further discussion.

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Summarized combined financial information for our equity method investments is as follows for the periods indicated (amounts represent 100% of investee financial information in thousands):



	December 31,
	2018		2017
BALANCE SHEET DATA: ⁽¹⁾
Current assets	$	30,045	$	288,085
Noncurrent assets	257,036		2,600,231
Total assets	$	287,081	$	2,888,316

Current liabilities	$	31,287	$	151,850
Other liabilities	41,070		1,246,406
Combined equity	214,724		1,490,060
Total liabilities and combined equity	$	287,081	$	2,888,316



	Year Ended December 31,
	2018		2017		2016
INCOME STATEMENT DATA: ⁽¹⁾
Revenue	$	460,596	$	553,396	$	87,434
Operating Income	143,817		184,692		45,932
Net income	83,479		122,506		30,942
Net income attributable to investee	$	78,962	$	99,130	$	30,942

____________________________

(1)

In November 2018, we executed a definitive agreement to sell our 50% equity interest in VTTI, and ceased application of the equity method of accounting. Effective September 30, 2018, we accounted for our investment in VTTI at fair value and no longer include the selected balance sheet data related to VTTI in these tables. See Note 4 - Acquisitions, Investments and Disposition for further discussion.

10. GOODWILL AND INTANGIBLE ASSETS

Goodwill

Goodwill represents the excess of purchase price over fair value of net assets acquired. Our goodwill amounts are assessed for impairment on an annual basis on October 31st and on an interim basis if circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying amount.

Subsequent to our annual goodwill impairment test in the fourth quarter of 2017, we have experienced continuing declines in the utilization of our segregated storage assets, as well as reductions in rate and term upon recontracting, and expect this weakness in demand for segregated storage to continue for certain locations through 2019. Due to the persistence of unfavorable market conditions affecting our segregated storage operations, particularly in the Caribbean region, and considering the near-term outlook and actions resulting from our recently completed Strategic Review, we performed an interim goodwill recoverability assessment for each of our reporting units as of September 30, 2018.

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As described in Note 2 - Summary of Significant Accounting Policies, we adopted ASU 2017-04 which simplified the test for goodwill impairment. Under the new guidance, if the carrying amount of a reporting unit exceeds its estimated fair value, an impairment is recorded for the amount of the excess up to the amount of goodwill for the respective reporting unit. The estimate of the fair value of the reporting unit is determined using a weighting of an expected present value of future cash flows and a market multiple valuation method, giving more weighting to our estimate of future cash flows. The present value of future cash flows is estimated using: (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses; (ii) long-term growth rates; and (iii) appropriate discount rates. The market multiple valuation method uses appropriate market multiples from comparable companies on the reporting unit’s earnings before interest, tax, depreciation and amortization. We evaluate industry and market conditions for purposes of weighting the income and market valuation approach. Using this methodology, which qualifies as Level 3 within the fair value hierarchy, we estimated the fair value of each of our reporting units and determined that the fair value of each of our reporting units significantly exceed their respective carrying values, with the exception of the GMT Caribbean and NYH reporting unit. Applying reasonable sensitivities to any or a combination of the above valuation inputs would not have generated a materially different determination of fair value. As a result of the assessment described above, we concluded that the goodwill in our GMT Caribbean and NYH reporting unit was fully impaired and recorded a non-cash goodwill impairment charge of $537.0 million. In conjunction with the goodwill impairment assessment, we considered impairment indicators related to the long-lived assets and investments associated with our GMT Caribbean and NYH reporting unit. Accordingly, we evaluated these assets for impairment and concluded that no impairment of long-lived assets existed as of December 31, 2018; however, we did record an approximately $300.3 million non-cash loss related to the anticipated sale of our equity investment in VTTI, which closed in January 2019.

For our annual goodwill impairment test as of October 31, 2018 and 2017, we performed a qualitative assessment to determine whether the fair value of each of our reporting units was more likely than not less than the carrying value. Based on economic conditions and industry market considerations, we determined that it is not more likely than not that the fair value of each reporting unit is lower than the carrying value; therefore, the quantitative impairment test was not performed. Therefore, we did not record any additional goodwill impairment for the year ended December 31, 2018 and we did not record any goodwill impairment for the year ended December 31, 2017.

The changes in the carrying amount of goodwill by segment are as follows at the dates indicated (in thousands):



	Domestic Pipelines & Terminals		Merchant Services	GMT Caribbean and NYH		GMT South Texas		Total
January 1, 2017	$	295,703	4,499	536,964		$	167,379	$	1,004,545
Acquisition	2,768		—	—		—		2,768
December 31, 2017	298,471		4,499	536,964		167,379		1,007,313
Purchase price adjustments	526		—	—		—		526
Impairment of goodwill	—		—	(536,964	)	—		(536,964		)
December 31, 2018	$	298,997	4,499	—		$	167,379	$	470,875

Intangible Assets

Intangible assets consist of the following at the dates indicated (in thousands):



	December 31,
	2018			2017
Customer relationships	$	229,300		$	231,620
Accumulated amortization	(106,761		)	(96,147		)
Net carrying amount	122,539			135,473

Customer contracts	381,600			383,466
Accumulated amortization	(210,828		)	(159,878		)
Net carrying amount	170,772			223,588
Total intangible assets, net	$	293,311		$	359,061

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2018, 2017 and 2016, amortization expense related to intangible assets was $65.7 million, $66.4 million and $68.1 million, respectively. Amortization expense related to intangible assets is expected to be $64.9 million for 2019, $65.1 million for 2020, $52.0 million for 2021, $24.5 million for 2022 and $13.4 million for 2023.

11. OTHER NON-CURRENT ASSETS

Other non-current assets consist of the following at the dates indicated (in thousands):



	December 31,
	2018		2017
Debt issuance costs	$	2,216	$	3,022
Insurance receivables related to environmental remediation reserves	2,057		2,794
BBH jetty-allision insurance receivable	—		7,372
Derivative assets	1,003		—
Other	35,862		38,295
Total other non-current assets	$	41,138	$	51,483

12. ACCRUED AND OTHER CURRENT LIABILITIES

Accrued and other current liabilities consist of the following at the dates indicated (in thousands):



	December 31,
	2018		2017
Taxes - other than income	$	29,644	$	33,327
Accrued employee benefit liabilities	6,220		7,228
Accrued environmental remediation liabilities	11,658		9,242
Interest payable	58,360		57,164
Unearned revenue	31,593		34,734
Employee compensation related accruals	27,602		32,616
Accrued capital expenditures	59,128		48,690
ARO	—		1,255
Other	51,988		40,951
Total accrued and other current liabilities	$	276,193	$	265,207

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

13. LONG-TERM DEBT

Long-term debt consists of the following at the dates indicated (in thousands):



	December 31,
	2018			2017
6.050% Notes due January 15, 2018 ⁽¹⁾	$	—		$	300,000
2.650% Notes due November 15, 2018 ⁽¹⁾	—			400,000
5.500% Notes due August 15, 2019 ^{(1) (2)}	275,000			275,000
4.875% Notes due February 1, 2021 ⁽¹⁾	650,000			650,000
4.150% Notes due July 1, 2023 ⁽¹⁾	500,000			500,000
4.350% Notes due October 15, 2024 ⁽¹⁾	300,000			300,000
3.950% Notes due December 1, 2026 ⁽¹⁾	600,000			600,000
4.125% Notes due December 1, 2027 ⁽¹⁾	400,000			400,000
6.750% Notes due August 15, 2033 ⁽¹⁾	150,000			150,000
5.850% Notes due November 15, 2043 ⁽¹⁾	400,000			400,000
5.600% Notes due October 15, 2044 ⁽¹⁾	300,000			300,000
6.375 % Junior Notes due January 22, 2078 ⁽¹⁾	400,000			—
Term Loan due September 30, 2019 ⁽²⁾	250,000			250,000
Credit Facility due September 30, 2021	522,328			418,904
Unamortized discounts & debt issuance costs	(32,886		)	(33,379		)
Total debt	4,714,442			4,910,525
Less: Current portion of long-term debt and line of credit ⁽²⁾	(702,727		)	(252,204		)
Total long-term debt	$	4,011,715		$	4,658,321

____________________________


(1)	We make semi-annual interest payments on these notes based on the rates noted above with the principal balances outstanding to be paid on or before the due dates as shown above.

(2)

A portion of the line of credit is classified as a current liability in our consolidated balance sheets as related funds are used to finance the Buckeye Merchant Service Companies’ current working capital needs. In addition, the $275.0 million of 5.500% notes due August 15, 2019 and the $250.0 million Term Loan due September 30, 2019 are classified as current portion of long-term debt as of December 31, 2018.

The following table presents the scheduled maturities of principal amounts of our debt obligations for the next five years and in total thereafter (in thousands):



	Years Ending
	December 31,
2019	$	702,727
2020	—
2021	994,601
2022	—
2023	500,000
Thereafter	2,550,000
Total	$	4,747,328

Credit Facility

In September 2016, Buckeye and BMSC exercised their remaining option with consenting lenders to extend $1.4 billion of our existing $1.5 billion revolving Credit Facility by one year to September 30, 2021 (the “Initial Facility Extension”).

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

After the consummation of the Initial Facility Extension, approximately $90.0 million of our revolving Credit Facility retained a maturity date of September 30, 2020 (the “Unextended Tranche”). In November 2017, Buckeye and BMSC entered into an agreement with the lender holding the Unextended Tranche to extend the maturity date of such tranche to September 30, 2021 matching the Initial Facility Extension. As a result of such agreement, the full amount of our $1.5 billion revolving Credit Facility now has a maturity date of September 30, 2021.

Under the Credit Facility, interest accrues on advances at the London Interbank Offered Rate (“LIBOR”) rate or a base rate plus an applicable margin based on the election of the applicable borrower for each interest period. The issuing fees for all letters of credit are also based on an applicable margin. The applicable margin used in connection with interest rates and fees is based on the credit ratings assigned to our senior unsecured long-term debt securities. The applicable margin for LIBOR rate loans, swing line loans, and letter of credit fees ranges from 1.0% to 1.75% and the applicable margin for base rate loans ranges from 0% to 0.75%. Buckeye and BMSC will also pay a fee based on our credit ratings on the actual daily unused amount of the aggregate commitments.

At December 31, 2018, Buckeye and BMSC collectively had a $522.3 million outstanding balance under the Credit Facility. The weighted average interest rate for borrowings under the Credit Facility was 3.8% for the period ended December 31, 2018.

The Credit Facility includes covenants limiting, as of the last day of each fiscal quarter, the ratio of consolidated funded debt to consolidated EBITDA (“Funded Debt Ratio”), as defined in the Credit Facility, measured for the preceding twelve months, to not more than 5.0 to 1.0. This requirement is subject to a provision for increases to 5.5 to 1.0 in connection with certain future acquisitions. The Funded Debt Ratio is calculated by dividing consolidated debt by annualized EBITDA, which is defined in the Credit Facility as earnings before interest, taxes, depreciation, amortization, and certain other adjustments determined on a consolidated basis. At December 31, 2018, our Funded Debt Ratio was 4.14 to 1.00, and we were in compliance with the covenants under our Credit Facility.

We had committed $3.1 million and $2.4 million in support of letters of credit at both December 31, 2018 and 2017, respectively. The obligations for letters of credit are not reflected as debt on our consolidated balance sheets. At December 31, 2018, we had $974.6 million of availability under our Credit Facility.

Term Loan

In September 2016, we entered into our $250.0 million Term Loan (“Term Loan”) due September 30, 2019, with an option to extend the term with consenting lenders for up to two one-year periods. We used the proceeds from the Term Loan to reduce the indebtedness outstanding under our Credit Facility. Under the Term Loan, interest accrues at the LIBOR rate or a base rate plus an applicable margin based on the election of the borrower. The applicable margin used in connection with interest rates and fees is based on the credit ratings assigned to our senior unsecured long-term debt securities. The applicable margin for LIBOR rate loans ranges from 1.0% to 1.6% and the applicable margin for base rate loans ranges from 0% to 0.6%.

The Term Loan also has the same Funded Debt Ratio requirements and provisions as the Credit Facility, as described above. At December 31, 2018, we were in compliance with the covenants under the Term Loan.

Notes Offerings

In November 2016, we issued $600.0 million of senior unsecured 3.950% notes maturing on December 1, 2026 in an underwritten public offering at 99.644% of their principal amount. Total proceeds from this offering, after underwriting fees, expenses and debt issuance costs were $592.7 million.

In November 2017, we issued $400.0 million of senior unsecured 4.125% notes maturing December 1, 2027 in an underwritten public offering at 99.503% of their principal amount. Total proceeds from this offering, after underwriting fees, expenses, and debt issuance costs, were $394.4 million. We used the net proceeds from this offering to reduce the indebtedness outstanding under our Credit Facility, a portion of which was subsequently reborrowed in January 2018 in order to repay in full the $300.0 million of 6.050% notes due on January 15, 2018 and $9.1 million of related accrued interest.

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In January 2018, we issued $400.0 million of junior subordinated notes (“Junior Notes”) maturing on January 22, 2078, which are redeemable at Buckeye’s option, in whole or in part, on or after January 22, 2023. The Junior Notes bear interest at a fixed rate of 6.375% per year up to, but not including, January 22, 2023. Beginning January 22, 2023, the Junior Notes will bear interest at a floating rate based on the Three-Month LIBOR Rate plus 4.02%, reset quarterly. Total proceeds from this offering, after underwriting fees, expenses and debt issuance costs, were $394.9 million. We used the net proceeds from this offering for general partnership purposes and to reduce the indebtedness outstanding under our Credit Facility.

Extinguishment of Debt

In July 2017, we repaid in full the $125.0 million principal amount and $3.2 million of accrued interest outstanding under our 5.125% notes, using funds available under our Credit Facility.

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

In November 2018, we repaid in full the $400.0 million principal amount and $5.3 million of accrued interest outstanding under our 2.650% notes, using funds available under our Credit Facility.

Use of Divestiture Proceeds

Proceeds of $444.6 million from the sale of the DPTS asset package on December 17, 2018 were used to reduce the indebtedness outstanding under our Credit Facility.

In January 2019, we received proceeds from the sale of our 50% equity interest in VTTI of $975 million, excluding transaction costs of approximately $8.0 million. We utilized the proceeds to reduce leverage, including retiring our $250 million Term Loan and repaying all borrowings on our Credit Facility. We have $275 million of 5.5% notes that matures in 2019. We expect to redeem this debt in February 2019 using proceeds from the VTTI sale transaction as well as borrowings on our Credit Facility.

14. OTHER NON-CURRENT LIABILITIES

Other non-current liabilities consist of the following at the dates indicated (in thousands):



	December 31,
	2018		2017
Accrued employee benefit liabilities	$	28,246	$	31,969
Accrued environmental remediation liabilities	27,358		31,803
Deferred consideration	20,232		19,640
ARO	4,349		3,833
Other	4,715		5,411
Total other non-current liabilities	$	84,900	$	92,656

15. ACCUMULATED OTHER COMPREHENSIVE (LOSS) INCOME

Accumulated other comprehensive (loss) income consists of the following at the dates indicated (in thousands):



	December 31,
	2018			2017
Unrealized (losses) gains on derivative instruments	$	(490	)	$	29,530
Net loss on settlement of interest rate swaps, net of amortization	(38,699		)	(47,924		)
Unrecognized loss on benefit plans	(872		)	(2,617		)
Other comprehensive income from equity method investments	—			49,642
Total accumulated other comprehensive (loss) income	$	(40,061	)	$	28,631

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

16. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

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

Interest Rate Derivatives

From time to time, we utilize forward-starting interest rate swaps to hedge the variability of the forecasted interest payments on anticipated debt issuances that may result from changes in the benchmark interest rate until the expected debt is issued. When entering into interest rate swap transactions, we become exposed to both credit risk and market risk. We are subject to credit risk when the change in fair value of the swap instrument is positive and the counterparty may fail to perform under the terms of the contract. We are subject to market risk with respect to changes in the underlying benchmark interest rate that impacts the fair value of the swaps. We manage our credit risk by entering into swap transactions only with major financial institutions with investment-grade credit ratings. We manage our market risk by aligning the swap instrument with the existing underlying debt obligation or a specified expected debt issuance, generally associated with the maturity of an existing debt obligation. We designate the swap agreements as cash flow hedges at inception and expect the changes in values to be highly correlated with the changes in value of the anticipated interest payments associated with the forecasted borrowings.

During 2016, we entered into seven forward-starting interest rate swaps with a total aggregate notional amount of $350.0 million, which we entered into in anticipation of the issuance of debt on or before January 15, 2018, and eleven forward-starting interest rate swaps with a total aggregate notional amount of $500.0 million, which we entered into in anticipation of the issuance of debt on or before December 15, 2018. In November 2017, we issued $400.0 million of senior unsecured 4.125% fixed-rate notes (see Note 13 - Long-Term Debt for further discussion) and settled the related seven forward-starting interest rate swaps for $20.0 million in settlement proceeds. In December 2018, the underlying future issuance of debt designated to the eleven forward-stating interest rate swaps was no longer probable of occurring due to proceeds from certain asset divestitures being used to reduce debt. This resulted in $51.0 million being reclassified from AOCI as a reduction of interest expense in the fourth quarter of 2018. As of December 31, 2018, we had no outstanding interest rate swaps.

Commodity Derivatives

Our Merchant Services segment primarily uses exchange-traded refined petroleum product futures contracts to manage the risk of market price volatility on its refined petroleum product inventories and its physical derivative contracts, which we designated as fair value hedges, with changes in fair value of both the futures contracts and physical inventory reflected in earnings. Our Merchant Services segment also uses exchange-traded refined petroleum contracts to hedge expected future transactions related to certain gasoline inventory that we manage on behalf of a third party, which are designated as cash flow hedges, with the effective portion of the hedge reported in other comprehensive income (“OCI”) and reclassified into earnings when the expected future transaction affects earnings. Any gains or losses incurred on the derivative instruments that are not effective in offsetting changes in fair value or cash flows of the hedged item are recognized immediately in earnings.

Additionally, our Merchant Services segment enters into exchange-traded refined petroleum product futures contracts on behalf of our Domestic Pipelines & Terminals segment to manage the risk of market price volatility on the gasoline-to-butane pricing spreads associated with our butane blending activities managed by a third party. These futures contracts are not designated in a hedge relationship for accounting purposes. Physical forward contracts and futures contracts that have not been designated in a hedge relationship are marked-to-market through earnings.

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes the notional volumes of the net long (short) positions of our commodity derivative instruments outstanding at December 31, 2018 (amounts in thousands of gallons):



	Volume
Derivative Purpose	Current		Long-Term
Derivatives NOT designated as hedging instruments:
Physical fixed price derivative contracts	(23,119	)	(4,765	)
Physical index derivative contracts	52,912		—
Futures contracts for refined petroleum products	29,771		(9,996	)
					Hedge Type
Derivatives designated as hedging instruments:
Futures contracts for refined petroleum products	(107,184	)	(420	)	Fair Value Hedge

Our futures contracts designated as fair value hedges relate to our inventory portfolio and extend to the first quarter of 2020. Our futures contracts related to forecasted purchases and sales of refined petroleum products, not designated in a hedging relationship, extend to the first quarter of 2020.

Effective January 2017, the Chicago Mercantile Exchange (“CME”) amended its rulebook, resulting in the characterization of variation margin transfers as settlement payments, as opposed to adjustments to collateral. These amendments impacted the accounting treatment of our exchange-traded derivatives contracts, primarily comprised of our futures contracts, for which the CME serves as the central clearing party, and exchange-settled derivatives traded on the over-the-counter (“OTC”) market. As a result, commencing with the first quarter of 2017, we began reducing the corresponding derivative asset and liability balances for our exchange-settled derivative contracts to reflect the settlement of those positions via the variation margin. The variation margin is now considered partial settlement of the derivative contract and will result in realized gains or losses which, prior to January 1, 2017, were classified as unrealized gains or losses on derivatives. In addition, we maintain an initial margin deposit with the broker in an amount sufficient to cover the fair value of our open futures positions. This margin deposit is considered collateral and is included within prepaid and other current assets in our consolidated balance sheets and is not offset against the fair values of our derivative instruments.

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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



	December 31, 2018
	Derivatives NOT Designated as Hedging Instruments			Derivatives Designated as Hedging Instruments		Derivative Carrying Value			Netting Balance Sheet Adjustment ⁽¹⁾			Total
Physical fixed price derivative contracts	$	17,934		$	—	$	17,934		$	(84	)	$	17,850
Physical index derivative contracts	286			—		286			(117		)	169
Total current derivative assets	18,220			—		18,220			(201		)	18,019
Physical fixed price derivative contracts	1,003			—		1,003			—			1,003
Total non-current derivative assets	1,003			—		1,003			—			1,003
Physical fixed price derivative contracts	(1,386		)	—		(1,386		)	84			(1,302		)
Physical index derivative contracts	(135		)	—		(135		)	117			(18		)
Total current derivative liabilities	(1,521		)	—		(1,521		)	201			(1,320		)
Physical fixed price derivative contracts	(3		)	—		(3		)	—			(3		)
Total non-current derivative liabilities	(3		)	—		(3		)	—			(3		)
Net derivative assets	$	17,699		$	—	$	17,699		$	—		$	17,699

____________________________


(1)	Amounts represent the netting of physical fixed and index contracts’ assets and liabilities when a legal right of offset exists.



	December 31, 2017
	Derivatives NOT Designated as Hedging Instruments			Derivatives Designated as Hedging Instruments		Derivative Carrying Value			Netting Balance Sheet Adjustment ⁽¹⁾			Total
Physical fixed price derivative contracts	$	2,582		$	—	$	2,582		$	(63	)	$	2,519
Physical index derivative contracts	455			—		455			(9		)	446
Interest rate derivatives	—			31,994		31,994			—			31,994
Total current derivative assets	3,037			31,994		35,031			(72		)	34,959
Total non-current derivative assets	—			—		—			—			—
Physical fixed price derivative contracts	(7,226		)	—		(7,226		)	63			(7,163		)
Physical index derivative contracts	(18		)	—		(18		)	9			(9		)
Total current derivative liabilities	(7,244		)	—		(7,244		)	72			(7,172		)
Total non-current derivative liabilities	—			—		—			—			—
Net derivative (liabilities) assets	$	(4,207	)	$	31,994	$	27,787		$	—		$	27,787

____________________________


(1)	Amounts represent the netting of physical fixed and index contracts’ assets and liabilities when a legal right of offset exists.

At December 31, 2018, open refined petroleum product derivative contracts (represented by the physical fixed-price contracts, physical index contracts, and futures contracts for refined products contracts noted above) varied in duration in the overall portfolio, but did not extend beyond July 2020. In addition, at December 31, 2018, we had refined petroleum product inventories that we intend to use to satisfy a portion of the physical derivative contracts.

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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



		Year Ended December 31,
	Location	2018			2017
Derivatives NOT designated as hedging instruments:
Physical fixed price derivative contracts	Product sales	$	22,046		$	(6,748	)
Physical index derivative contracts	Product sales	440			82
Physical fixed price derivative contracts	Cost of product sales	(1,777		)	3,937
Physical index derivative contracts	Cost of product sales	(81		)	1,147
Futures contracts for refined products	Cost of product sales	7,661			13,710

Derivatives designated as fair value hedging instruments:
Futures contracts for refined products	Cost of product sales	$	42,658		$	(22,362	)
Physical inventory - hedged items	Cost of product sales	(46,397		)	32,016

Ineffectiveness excluding the time value component on fair value hedging instruments:
Fair value hedge ineffectiveness (excluding time value)	Cost of product sales	$	1,335		$	(4,673	)
Time value excluded from hedge assessment	Cost of product sales	(5,074		)	14,327
Net (loss) gain for ineffectiveness in income		$	(3,739	)	$	9,654

The change in value recognized in OCI and the losses reclassified from AOCI to income attributable to our derivative instruments designated as cash flow hedges were as follows for the periods indicated (in thousands):



	Gain (Loss) Recognized in OCI on Derivatives for the Year Ended December 31,
	2018		2017
Derivatives designated as cash flow hedging instruments:
Interest rate contracts	$	27,739	$	(10,597	)
Commodity derivatives	1,975		(136		)
Total	$	29,714	$	(10,733	)



		Gain (Loss) Reclassified From AOCI to Income (Effective Portion) for the Year Ended December 31,
	Location	2018		2017
Derivatives designated as cash flow hedging instruments:
Interest rate contracts	Interest and debt expense	$	50,509	$	(11,922	)
Total		$	50,509	$	(11,922	)

Over the next twelve months, we expect to reclassify $9.2 million of net losses attributable to interest rate derivatives from AOCI to earnings as an increase to interest and debt expense. These net losses consist of $11.2 million of amortization of hedge losses on settled forward-starting interest rate swaps, partially offset by $2.0 million of amortization of hedge gains on settled forward-starting interest rate swaps settled in November 2017. Additionally, the unrealized gains and losses for refined petroleum products designated as cash flow hedges at December 31, 2018, of $2.0 million, are estimated to be realized and reclassified from AOCI to product sales during over the next twelve months. The ineffective portion of the change in fair value of cash flow hedges was not material for the years ended December 31, 2018 and 2017.

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

17. FAIR VALUE MEASUREMENTS

We categorize our financial assets and liabilities using the three-tier hierarchy as follows:

Recurring

The following table sets forth financial assets and liabilities, measured at fair value on a recurring basis, as of the measurement dates indicated, and the basis for that measurement, by level within the fair value hierarchy (in thousands):



	December 31, 2018					December 31, 2017
	Level 1		Level 2			Level 1		Level 2
Financial assets:
Physical fixed price derivative contracts	$	—	$	18,937		$	—	$	2,582
Physical index derivative contracts	—		286			—		455
Interest rate derivatives	—		—			—		31,994

Financial liabilities:
Physical fixed price derivative contracts	—		(1,389		)	—		(7,226		)
Physical index derivative contracts	—		(135		)	—		(18		)
Futures contracts for refined products	—		—			—		—
Fair value	$	—	$	17,699		$	—	$	27,787

The values of the Level 1 derivative assets and liabilities were based on quoted market prices obtained from the New York Mercantile Exchange. The values for exchange-settled commodity derivatives at December 31, 2018 are presented after the application of the CME rulebook amendment, which deems that these instruments are settled daily via variation margin payments. As a result of this rulebook amendment, CME-settled derivatives, primarily comprised of our futures contracts for refined petroleum products, are considered to have no fair value at the balance sheet date for financial reporting purposes; however, the derivatives remain outstanding and subject to future commodity price fluctuations until they are settled in accordance with their contractual terms.

The values of the Level 2 interest rate derivatives were determined using fair value estimates obtained from our counterparties, which are verified using other available market data, including cash flow models which incorporate market inputs including the implied forward LIBOR yield curve for the same period as the future interest rate swap settlements. Credit value adjustments (“CVAs”), which are used to reflect the potential nonperformance risk of our counterparties, are considered in the fair value assessment of interest rate derivatives. We determined that the impact of CVAs was not significant to the overall valuation of interest rate derivatives as of December 31, 2017.

The values of the Level 2 commodity derivative contracts were calculated using market approaches based on observable market data inputs, including published commodity pricing data, which is verified against other available market data, and market interest rate and volatility data. Level 2 physical fixed price derivative assets are net of CVAs determined using an expected cash flow model, which incorporates assumptions about the credit risk of the derivative contracts based on the historical and expected payment history of each customer, the amount of product contracted for under the agreement and the customer’s historical and expected purchase performance under each contract. The Merchant Services segment determined CVAs are appropriate because few of the Merchant Services segment’s customers entering into these derivative contracts are large organizations with nationally recognized credit ratings. The CVAs were nominal as of December 31, 2018 and 2017. As of December 31, 2018 and 2017, the Merchant Services segment did not hold any net liability derivative position containing credit contingent features.

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Financial instruments included in current assets and current liabilities are reported in the consolidated balance sheets at amounts which approximate fair value due to the relatively short period to maturity of these financial instruments. The fair values of our fixed-rate debt were estimated by observing market trading prices and by comparing the historical market prices of our publicly issued debt with the market prices of the publicly issued debt of other MLPs with similar credit ratings and terms. The fair value of our variable-rate debt approximates the carrying amount since the associated interest rates are market-based. The carrying value and fair value of our debt, using Level 2 input values, were as follows at the dates indicated (in thousands):



	December 31, 2018				December 31, 2017
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Fixed-rate debt	$	3,546,396	$	3,364,549	$	4,241,963	$	4,384,336
Variable-rate debt	1,168,046		1,172,328		668,562		668,904
Total debt	$	4,714,442	$	4,536,877	$	4,910,525	$	5,053,240

In addition, our pension plan assets are measured at fair value on a recurring basis, based on Level 1 and Level 3 inputs. See Note 18 - Pensions and Other Postretirement Benefits for additional discussion.

We recognize transfers between levels within the fair value hierarchy as of the beginning of the reporting period. We did not have any transfers between Level 1 and Level 2 during the years ended December 31, 2018 and 2017.

Non-Recurring

Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments in certain circumstances, such as when there is evidence of impairment. See Note 2 - Summary of Significant Accounting Policies for further discussion of our fair value techniques. For the year ended December 31, 2018, we recorded a $300.3 million non-cash loss related to the anticipated sale of our equity investment in VTTI based on Level 2 inputs and a $537.0 million non-cash goodwill impairment charge related to our GMT Caribbean and NYH reporting unit based on Level 3 inputs. See Notes 4 - Acquisitions, Investments and Disposition and 10 - Goodwill and Intangible Assets for further discussion on fair value adjustments recorded during the year ended December 31, 2018. For the year ended December 31, 2017, there were no significant fair value adjustments related to assets or liabilities reflected in our consolidated financial statements.

18. PENSIONS AND OTHER POSTRETIREMENT BENEFITS

RIGP and Retiree Medical Plan

Services Company, which employs the majority of our workforce, sponsors a Retirement Income Guarantee Plan (“RIGP”), which is a defined benefit plan that generally guarantees employees hired before January 1, 1986 a retirement benefit based on years of service and the employee’s highest compensation for any consecutive 5-year period during the last 10 years of service or other compensation measures as defined under the respective plan provisions. The retirement benefit is subject to reduction at varying percentages for certain offsetting amounts, including benefits payable under a retirement and savings plan discussed further below. Services Company funds this benefit plan through contributions to pension trust assets, generally subject to minimum funding requirements as provided by applicable law.

Services Company also sponsors an unfunded post-retirement benefit plan (the “Retiree Medical Plan”), which provides health care and life insurance benefits to certain of its retirees. To be eligible for the health care benefits, an employee must have been hired prior to January 1, 1991 and meet certain age and service requirements. To be eligible for the life insurance benefits, an employee must have been hired prior to January 1, 2002 and meet certain service requirements. The RIGP and Retiree Medical Plan are closed for new participants.

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The components of projected benefit obligations and plan assets, and the funded status of the RIGP and the Retiree Medical Plan (“the Plans”) were as follows for the periods indicated (in thousands):



	RIGP						Retiree Medical Plan
	Year Ended December 31,						Year Ended December 31,
	2018			2017			2018			2017
Change in benefit obligation:
Benefit obligation at beginning of year	$	9,847		$	13,178		$	29,363		$	31,958
Service cost	(84		)	(58		)	199			287
Interest cost	293			333			1,029			1,209
Plan participants’ contributions	—			—			533			481
Actuarial (gain) loss	(270		)	(1,524		)	(1,531		)	689
Settlements	(2,127		)	(1,900		)	—			—
Benefit payments	(206		)	(182		)	(2,573		)	(3,074		)
Substantive provision change	—			—			—			(2,187		)
Benefit obligation at end of year	$	7,453		$	9,847		$	27,020		$	29,363

Change in plan assets:
Fair value of plan assets at beginning of year	$	4,484		$	4,524		$	—		$	—
Actual return on plan assets	221			452			—			—
Plan participants’ contributions	—			—			533			481
Employer contributions	1,047			1,590			2,040			2,593
Settlements	(2,127		)	(1,900		)	—			—
Benefit payments	(206		)	(182		)	(2,573		)	(3,074		)
Fair value of plan assets at end of year	$	3,419		$	4,484		$	—		$	—

Funded status at end of year	$	(4,034	)	$	(5,363	)	$	(27,020	)	$	(29,363	)

During 2017, the Retiree Medical Plan had a substantive provision change whereby plan participants began sharing a higher portion of future increases in health care costs.

Amounts recognized in our consolidated balance sheets for the Plans consist of the following at the dates indicated below (in thousands):



	RIGP						Retiree Medical Plan
	December 31,						December 31,
	2018			2017			2018			2017
Liabilities:
Accrued employee benefit liabilities - current	$	—		$	—		$	(2,808	)	$	(2,757	)
Accrued employee benefit liabilities - noncurrent	(4,034		)	(5,363		)	(24,212		)	(26,606		)
Total	$	(4,034	)	$	(5,363	)	$	(27,020	)	$	(29,363	)

AOCI:
Prior service credit	$	—		$	—		$	(1,727	)	$	(2,187	)
Net actuarial loss	310			722			2,289			4,082
Total	$	310		$	722		$	562		$	1,895

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Information regarding the accumulated benefit obligation in excess of plan assets for the RIGP is as follows at the dates indicated (in thousands):



	RIGP
	December 31,
	2018		2017
Projected benefit obligation	$	7,453	$	9,847
Accumulated benefit obligation ⁽¹⁾	7,177		9,128
Fair value of plan assets	3,419		4,484

____________________________


(1)	The accumulated benefit obligation does not include an assumption for future compensation increases.

The weighted average assumptions used in determining net periodic benefit cost for the Plans were as follows for the periods indicated:



	RIGP						Retiree Medical Plan
	Year Ended December 31,						Year Ended December 31,
	2018		2017		2016		2018		2017		2016
Discount rate	3.3	%	3.2	%	3.0	%	3.6	%	4.0	%	4.1	%
Expected return on plan assets	4.0	%	5.8	%	5.8	%	N/A		N/A		N/A
Rate of compensation increase	2.0	%	3.0	%	3.0	%	2.0	%	3.0	%	3.0	%

The assumptions used in determining benefit obligations for the Plans were as follows at the dates indicated:



	RIGP				Retiree Medical Plan
	December 31,				December 31,
	2018		2017		2018		2017
Discount rate	4.3	%	3.3	%	4.4	%	3.6	%
Rate of compensation increase	3.0	%	3.0	%	3.0	%	3.0	%

The discount rate reflects the rate at which benefits could be effectively settled on the measurement date. The discount rate directly affects the measurement of the benefit obligations of our pension and other postretirement benefit plans. The discount rate is used to allocate the cost of future benefits over time. An increase in the discount rate would reduce the future liability due to higher expected returns and a decrease in the discount rate would increase the liability. The discount rate is determined through general economic and market conditions that affect interest rates as well as the duration of our future liabilities. For the years ended December 31, 2018, 2017, and 2016, the discount rate was determined based on a projection of expected cash flows from the Plans using relevant economic benchmarks available as of each year end. The expected return on plan assets was determined based on projected long-term market returns for each asset class in which the Plans are invested, weighted by the target asset class allocations. The rate of compensation increase represents the long-term assumption for future increases to salaries.

The assumed annual rate of increase in the per capita cost of covered health care benefits as of December 31, 2018 in the Retiree Medical Plan was 6.5% for 2019, grading down to 4.5% in 2025, and thereafter. The assumption of annual change in health care costs is estimated based on national trend rates as well as our historical claims experience. A hypothetical 1% movement in the assumed health care cost trend rates would not significantly affect our benefit cost or obligation.

100

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The components of the net periodic benefit cost and other changes recognized in OCI for the Plans were as follows for the periods indicated (in thousands):



	RIGP									Retiree Medical Plan
	Year Ended December 31,									Year Ended December 31,
	2018			2017			2016			2018			2017			2016
Components of net periodic benefit cost:
Service cost	$	(84	)	$	(58	)	$	(34	)	$	199		$	287		$	323
Interest cost ⁽¹⁾	293			333			421			1,029			1,209			1,309
Expected return on plan assets ⁽¹⁾	(168		)	(251		)	(256		)	—			—			—
Amortization of prior service credit ⁽¹⁾	—			—			—			(461		)	—			—
Actuarial loss due to settlements ⁽¹⁾	88			150			598			—			—			—
Amortization of unrecognized loss ⁽¹⁾	—			19			522			263			—			766
Net periodic benefit cost	$	129		$	193		$	1,251		$	1,030		$	1,496		$	2,398

	RIGP									Retiree Medical Plan
	Year Ended December 31,									Year Ended December 31,
	2018			2017			2016			2018			2017			2016
Other changes in plan assets and benefit obligations recognized in OCI:
Prior service credit	$	—		$	—		$	—		$	—		$	(2,187	)	—
Net actuarial (gain) loss	(324		)	(1,725		)	(2,068		)	(1,531		)	688			2,871
Amortization of unrecognized loss	—			(19		)	(522		)	(263		)	—			(766		)
Actuarial loss due to settlements	(88		)	(150		)	(598		)	—			—			—
Amortization of prior service credit	—			—			—			461			—			—
Total recognized in OCI	$	(412	)	$	(1,894	)	$	(3,188	)	$	(1,333	)	$	(1,499	)	$	2,105
Total recognized in net period benefit cost and OCI	$	(283	)	$	(1,701	)	$	(1,937	)	$	(303	)	$	(3	)	$	4,503

___________________________


(1)	These components of net periodic benefit cost are reported on the Consolidated Statements of Operations as other expense. See Note 2 - Summary of Significant Accounting Policies for further discussion on the accounting guidance.

Actuarial gains and losses are amortized over the average future service period of current plan participants expected to receive benefits. The corridor approach is used to determine when actuarial gains and losses are to be amortized and is equal to 10 percent of the greater of the projected benefit obligation or the fair value of plan assets. The amount of gain or loss in excess of the calculated corridor is subject to amortization. We expect that the following amounts, currently included in OCI, for the Plans will be recognized in our consolidated statement of operations during the year ending December 31, 2019 (in thousands):



	RIGP		Retiree Medical Plan
Prior service credit	$	—	$	(461	)

101

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

We estimate the following benefit payments, which reflect expected future service, as appropriate, will be paid for the Plans in the years indicated below as such (in thousands):



	RIGP		Retiree Medical Plan
2019	$	2,081	$	2,870
2020	674		2,718
2021	847		2,581
2022	735		2,503
2023	653		2,473
Thereafter	1,520		9,151

We expect to contribute $3.2 million to our benefit plans in 2019. Funding requirements for subsequent years are uncertain and will depend on whether there are any changes in the actuarial assumptions used to calculate plan funding levels, the actual return on plan assets and any legislative or regulatory changes affecting plan funding requirements. For tax planning, financial planning, cash flow management or cost reduction purposes, we may increase, accelerate, decrease or delay contributions to the plan to the extent permitted by law.

We do not fund the Retiree Medical Plan and, accordingly, no assets are invested in the plan. A summary of investments in the RIGP are as follows at the dates indicated (in thousands):



	December 31, 2018				December 31, 2017
	Level 1		Level 3		Level 1		Level 3
Mutual fund - fixed-income securities	$	1,576	$	—	$	2,454	$	—
Mutual fund - money market	105		—		222		—
Coal lease	—		1,738		—		1,808
Fair value of plan assets	$	1,681	$	1,738	$	2,676	$	1,808

The values of the Level 1 mutual funds were based on quoted market prices in active markets for identical assets. The mutual fund — fixed-income securities generally seeks long-term growth of capital and income and invests in a portfolio consisting primarily of fixed-income securities.

The values of the Level 3 coal lease were determined using an expected present value of future cash flows valuation model. This investment relates to a 20.8% interest in a coal lease, which derives value from specified minimum royalty payments received from CONSOL Energy Inc. related to coal reserves mined from two Pennsylvania mines owned by the lessor. The coal lease extends through 2023.

The following table summarizes the activity in our Level 3 pension assets for the periods indicated (in thousands):



	Year Ended December 31,
	2018			2017
Beginning balance, January 1	$	1,808		$	2,007
Royalty payments received	400			380
Unrealized loss	(70		)	(199		)
Transfers out of Level 3	(400		)	(380		)
Ending balance, December 31	$	1,738		$	1,808

The RIGP investment policy does not target specific asset classes, but seeks to balance the preservation and growth of capital in the plan’s mutual funds with the income derived with proceeds from the coal lease. While no significant changes in the asset class allocation of the plan are expected during the upcoming year, Services Company may make changes at any time.

102

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Retirement and Savings Plans

Services Company also sponsors the Retirement and Savings Plan (“RASP”) through which it provides retirement benefits for substantially all of its regular full-time employees located in the continental United States, except those covered by certain labor contracts. The RASP consists of two components. Under the first component, Services Company contributes 5% of each eligible employee’s covered salary to an employee’s separate account maintained in the RASP. Under the second component, Services Company makes a matching contribution into the employee’s separate account for 100% of an employee’s contribution to the RASP up to 5% (or 6% if an employee has over 20 years of service) of an employee’s eligible covered salary. Total costs of providing these benefits through the RASP were $18.0 million, $17.6 million and $16.4 million during the years ended December 31, 2018, 2017 and 2016, respectively.

Services Company also participates in a multi-employer retirement income plan and a multi-employer postretirement benefit plan, both of which provide retirement and health care and life insurance benefits to employees covered by certain labor contracts. We do not administer these plans and contribute to them in accordance with the provisions of negotiated labor contracts. The costs of providing these benefits, in aggregate, were $1.4 million for all years ended December 31, 2018, 2017, and 2016, respectively.

Additionally, certain of our wholly owned subsidiaries provide a savings and retirement plan to employees. The costs of providing these benefits were $1.5 million, $2.1 million and $1.4 million for the years ended December 31, 2018, 2017 and 2016, respectively.

Employee Stock Ownership Plan

Services Company provides the ESOP to the majority of its employees hired before September 16, 2004. Employees hired by Services Company after September 15, 2004 and certain employees covered by a union multi-employer pension plan do not participate in the ESOP. The ESOP owns all of the outstanding common stock of Services Company. Buckeye, as primary beneficiary, consolidates Services Company.

The ESOP was frozen with respect to benefits effective March 27, 2011 (the “Freeze Date”). No Services Company contributions (other than dividend equivalent payments) have been made on behalf of current participants in the Plan after the Freeze Date. Even though contributions under the ESOP are no longer being made, each eligible participant’s ESOP account continues to be credited with its share of any stock dividends or other stock distributions associated with Services Company stock.

Individual employees were allocated shares based upon the ratio of their eligible compensation to total eligible compensation. Eligible compensation generally included base salary, overtime payments and certain bonuses. All Services Company stock has been released to ESOP participants. Total ESOP related costs charged to earnings were nominal for each of the years ended December 31, 2018, 2017, and 2016.

19. UNIT-BASED COMPENSATION PLANS

We award unit-based compensation to employees and directors primarily under the LTIP, which was approved by the Partnership’s unitholders in June 2013 and subsequently amended and restated in June 2017. The LTIP replaced the 2009 Long-Term Incentive Plan (the “2009 Plan”), which was merged with and into the LTIP, and no further grants have since been made under the 2009 Plan. We formerly awarded options to acquire LP Units to employees pursuant to the Buckeye Partners, L.P. Unit Option and Distribution Equivalent Plan (the “Option Plan”).

We recognized compensation expense related to the LTIP, which includes awards under the LTIP, and the Option Plan of $22.1 million, $30.6 million and $33.5 million for the years ended December 31, 2018, 2017 and 2016, respectively.

103

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

LTIP

The LTIP, which is overseen by the Compensation Committee of the Board of Directors of Buckeye GP (the “Compensation Committee”), provides for the grant of phantom units, performance units and in certain cases, distribution equivalent rights (“DERs”), which provide the participant a right to receive payments based on distributions we make on our LP Units. Phantom units are notional LP Units whose vesting is subject to service-based restrictions or other conditions established by the Compensation Committee in its discretion. Phantom units entitle a participant to receive an LP Unit without payment of an exercise price upon vesting. Performance units are notional LP Units whose vesting is subject to the attainment of one or more performance goals, and which also entitle a participant to receive LP Units without payment of an exercise price upon vesting. DERs are rights to receive a cash payment per phantom unit or performance unit, as applicable, equal to the per unit cash distribution we pay on our LP Units. If awards are forfeited, terminated or otherwise not paid in full, the LP Units underlying such awards will again be available for purposes of the LTIP, subject to certain limitations. Persons eligible to receive grants under the LTIP are (i) officers and employees of Buckeye GP and any of our affiliates who provide services to us and (ii) independent members of the Board of Directors of Buckeye GP. Phantom units or performance units may be granted to participants at any time as determined by the Compensation Committee.

A total of 2,115,169 LP Units were available for issuance under the LTIP as of December 31, 2018.

Deferral Plan under the LTIP

On December 13, 2016, the Compensation Committee approved the terms of the amended and restated Buckeye Partners, L.P. Unit Deferral and Incentive Plan (“Deferral Plan”). The Compensation Committee is expressly authorized to adopt the Deferral Plan under the terms of the LTIP, which grants the Compensation Committee the authority to establish a program pursuant to which our phantom units may be awarded in lieu of cash compensation at the election of the employee. At December 31, 2018, 2017 and 2016, eligible employees were allowed to defer up to 50% of their 2018, 2017 and 2016 compensation awards under our Annual Incentive Compensation Plan or other discretionary bonus program in exchange for grants of phantom units equal in value to the amount of their cash award deferral (each such unit, a “Deferral Unit”). Participants also receive one matching phantom unit for each Deferral Unit. Deferral Units and their matching phantom units vest on December 15 of the second year after the year in which such units are granted. During 2018 and 2017, 149,726 and 145,138 phantom units were granted under this plan, respectively. These grants are included as granted in the LTIP activity table below.

Awards under the LTIP

During the year ended December 31, 2018, the Compensation Committee granted 454,994 phantom units to employees (including the 149,726 phantom units granted pursuant to the Deferral Plan discussed above), 18,000 phantom units to independent directors of Buckeye GP and 274,688 performance units to employees. Generally, vesting criteria for the performance units are the attainment of certain performance goals during the third year of a three-year period and remaining employed by us throughout such three-year period.

Phantom unit grantees will be paid quarterly distributions on DERs associated with the applicable phantom units over their respective vesting periods of one to three years in the same amounts per phantom unit as distributions paid on our LP Units over those same periods. The phantom unit DERs distributions were $4.3 million and $4.1 million for the years ended December 31, 2018 and 2017, respectively. Distributions may be paid on performance units at the end of the three-year vesting period. In such case, DERs will be paid on the number of LP Units for which the performance units will be settled. Quarterly distributions related to DERs associated with phantom and performance units are recorded as a reduction of our Limited Partners’ Capital on our consolidated balance sheets.

104

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2017	1,296		$	63.54
Granted ⁽²⁾	547		69.91
Performance adjustment ⁽³⁾	32		71.50
Vested	(386	)	70.98
Forfeited	(39	)	64.26
Unvested at December 31, 2017	1,450		$	64.04
Granted ⁽²⁾	748		48.16
Performance adjustment ⁽³⁾	39		73.17
Vested	(544	)	68.84
Forfeited	(48	)	58.46
Unvested at December 31, 2018	1,645		$	55.52

____________________________


(1)	Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. The weighted-average grant date fair value per LP Unit for forfeited and vested awards is determined before an allowance for forfeitures.


(2)	Includes both phantom and performance awards. Performance awards are granted at a target amount but, depending on our performance during the vesting period with respect to certain pre-established goals, the number of LP Units issued upon vesting of such performance awards can be greater or less than the target amount.


(3)	Represents the LP Units issued in excess of target amounts for performance awards that vested during the year ended December 31, 2018 and 2017 as a result of our above target performance with respect to applicable performance goals.

At December 31, 2018, we expect to recognize $27.5 million of compensation expense related to the unvested LTIP over a weighted average remaining period of 1.5 years.

Unit Option and Distribution Equivalent Plan

We also sponsor the Option Plan pursuant to which we historically granted options to employees to purchase LP Units at the market price of our LP Units on the date of grant. Generally, the options vest three years from the date of grant and expire ten years from the date of grant. As unit options are exercised, we issue new LP Units to the holder. We have not historically repurchased, and do not expect to repurchase in 2019, any of our LP Units. Following the adoption of the 2009 Plan, effective March 20, 2009, we ceased making additional grants under the Option Plan.

For the year ended December 31, 2017, options to purchase ten LP Units were exercised under the Option Plan at a weighted average strike price of $50.36 per LP Unit.

The total intrinsic value of options exercised during the years ended December 31, 2018, 2017 and 2016 was zero, $0.2 million and $0.1 million, respectively. At December 31, 2018 and 2017, there was no unrecognized compensation cost related to unvested options, as all options were vested as of November 24, 2011. The fair value of options vested was zero for each of the years ended December 31, 2018, 2017 and 2016, respectively. There were no options outstanding for the years ended December 31, 2018 and 2017.

105

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

20. RELATED PARTY TRANSACTIONS

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

21. PARTNERS’ CAPITAL AND DISTRIBUTIONS

Our LP Units represent limited partner interests, which give the holders thereof the right to participate in distributions and to exercise the other rights and privileges available to them under our partnership agreement. There were no Class C Units outstanding as of December 31, 2018. The partnership agreement provides that, without prior approval of our limited partners holding an aggregate of at least two-thirds of the outstanding LP Units, we cannot issue any limited partnership interests of a class or series having preferences or other special or senior rights over the LP Units.

Equity Offerings

In October 2016, we completed a public offering of 7.75 million LP Units pursuant to an effective shelf registration statement, which priced at $66.05 per unit. The underwriters also exercised an option to purchase 1.16 million additional LP Units, resulting in total gross proceeds of $588.7 million before deducting underwriting fees and other related expenses of $8.0 million. We used the net proceeds from this offering to initially reduce the indebtedness outstanding under our Credit Facility and for general partnership purposes, as well as to subsequently fund a portion of the purchase price for the VTTI Acquisition in January 2017.

Class C Units represented a separate class of our limited partnership interests. The Class C Units were substantially similar in all respects to our existing LP units, except that Buckeye had the option to pay distributions on the Class C Units in cash or by issuing additional Class C Units.

In November 2018, we announced a reduction in our declared quarterly cash distribution. As a result, all 6,714,963 Class C Units outstanding as of September 30, 2018 converted into LP Units on a one-for-one basis on November 5, 2018. Accordingly, the holders of these newly converted LP Units received the quarterly cash distribution of $0.75 per LP Unit, instead of an in-kind distribution of additional Class C Units.

106

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

At-the-Market Offering Program

In March 2016, we entered into an equity distribution agreement (the “Equity Distribution Agreement”) with J.P. Morgan Securities LLC, BB&T Capital Markets, a division of BB&T Securities, LLC, BNP Paribas Securities Corp., Deutsche Bank Securities Inc., Jefferies LLC, Morgan Stanley & Co. LLC, RBC Capital Markets, LLC, and SMBC Nikko Securities America, Inc. (collectively, the “ATM Underwriters”). Under the terms of the Equity Distribution Agreement, we could offer and sell up to $500.0 million in aggregate gross sales proceeds of LP Units from time to time through the ATM Underwriters, acting as agents of Buckeye or as principals, subject in each case to the terms and conditions set forth in the Equity Distribution Agreement. Sales of LP Units, if any, may be made by means of ordinary brokers’ transactions on the New York Stock Exchange or otherwise at market prices prevailing at the time of sale, at prices related to prevailing market prices or at negotiated prices or as otherwise agreed with any of such firms. During the years ended December 31, 2017 and 2016, we sold 6.2 million and 1.6 million LP Units in aggregate under the equity distribution agreements and received $345.8 million and $108.4 million in net proceeds after deducting commissions and other related expenses, including $1.9 million and $1.1 million of compensation paid in aggregate to the agents under their equity distribution agreements, respectively. The 6.2 million LP Units sold under the Equity Distribution Agreement in 2017 included a block sale of approximately 3.8 million LP Units on September 21, 2017. We did not issue any LP Units during the year ended December 31, 2018 under the Equity Distribution Agreement, which expired on January 15, 2018.

Summary of Changes in Outstanding Units

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



	LP Units	Class C Units		Total
Units outstanding at January 1, 2016	129,524	—		129,524
LP Units issued pursuant to the Option Plan ⁽¹⁾	6	—		6
LP Units issued pursuant to the LTIP ⁽¹⁾	254	—		254
Issuance of units to institutional investors	8,913	—		8,913
Issuance of units through equity distribution agreements	1,567	—		1,567
Units outstanding at December 31, 2016	140,264	—		140,264
LP Units issued pursuant to the Option Plan ⁽¹⁾	10	—		10
LP Units issued pursuant to the LTIP ⁽¹⁾	244	—		244
Issuance of units through equity distribution agreements	6,159	—		6,159
Units outstanding at December 31, 2017	146,677	—		146,677
LP Units issued pursuant to the LTIP ⁽¹⁾	363	—		363
Issuance of Class C Units	—	6,221		6,221
Issuance of Class C Units in lieu of quarterly cash distributions	—	494		494
Conversion of Class C Units to LP Units	6,715	(6,715	)	—
Units outstanding at December 31, 2018	153,755	—		153,755

____________________________


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

107

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Cash Distributions

We generally make quarterly cash distributions to unitholders of a portion of our available cash, generally defined in our partnership agreement as consolidated cash receipts less consolidated cash expenditures and such retentions for working capital, anticipated cash expenditures and contingencies as our general partner deems appropriate. Cash distributions are paid for LP Units and for DERs with respect to certain unit-based compensation awards outstanding as of each respective period. Cash distributions paid to unitholders of Buckeye for the periods indicated were as follows (in thousands, except per unit amounts):



		Amount Per		Total Cash
Record Date	Payment Date	LP Unit		Distributions
February 23, 2016	March 1, 2016	$	1.1875	$	154,928
May 16, 2016	May 23, 2016	1.2000		157,247
August 15, 2016	August 22, 2016	1.2125		159,881
November 15, 2016	November 22, 2016	1.2250		172,673
Total				$	644,729

February 21, 2017	February 28, 2017	$	1.2375	$	174,888
May 15, 2017	May 22, 2017	1.2500		176,832
August 14, 2017	August 21, 2017	1.2625		179,631
November 13, 2017	November 20, 2017	1.2625		186,042
Total				$	717,393

February 20, 2018	February 27, 2018	$	1.2625	$	186,764
May 14, 2018	May 21, 2018	1.2625		186,766
August 13, 2018	August 20, 2018	1.2625		186,624
November 13, 2018	November 20, 2018	0.7500		115,969
Total				$	676,123

On February 8, 2019, we announced a quarterly distribution of $0.75 per LP Unit that will be paid on February 26, 2019, to unitholders of record on February 19, 2019. Based on the LP Units and distribution equivalent rights with respect to certain unit-based compensation awards outstanding as of December 31, 2018, cash expected to be distributed to LP unitholders on February 26, 2019 is estimated to be approximately $115.9 million.

22. INCOME TAXES

Our current and deferred income tax expense (benefit) was as follows (in thousands):



	December 31,
	2018		2017		2016
Current income tax expense (benefit)	$	2,603	$	297	$	(276	)
Deferred income tax expense	1,137		575		1,736
Total income tax expense	$	3,740	$	872	$	1,460

We have no unrecognized tax benefits related to uncertain tax positions. Deferred tax assets and liabilities as of December 31, 2018 and 2017 relate to BDL and Buckeye Caribbean. The Tax Act, which went into effect January 1, 2018, did not have a significant impact on our consolidated financial statements.

Our effective tax rate differs from statutory rates, primarily due to being structured as an MLP, which is a pass-through entity for federal income tax purposes, while being treated as a taxable entity in certain states. The two primary drivers of our state income taxes are the New York City Unincorporated Business Tax and Texas Margin Tax.

108

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The net operating loss carryforwards, underlying related deferred tax assets, will expire between 2020 and 2022 for Buckeye Caribbean, and 2036 and 2037 for BDL. A valuation allowance has been provided for deferred tax assets that are not more likely than not to be realized.

The tax effects of significant items comprising our net deferred tax assets and liabilities at December 31, 2018 and 2017 are as follows (in thousands):



	December 31,
	2018			2017
Deferred tax asset:
Net operating loss carryforward	$	18,757		$	19,234
Capital loss carryforward	11,453			11,453
Other	2,452			2,697
Total deferred tax asset	$	32,662		$	33,384

Deferred tax liability:
Property, plant and equipment	$	1,132		$	1,536
Other	132			83
Total deferred tax liability	1,264			1,619
Net deferred tax asset	31,398			31,765
Less: Valuation allowance	(30,203		)	(29,451		)
Deferred taxes, net	$	1,195		$	2,314

As of December 31, 2018, BDL’s tax years from 2015 forward and Buckeye Caribbean’s tax years from 2014 forward were open to examination by the Internal Revenue Service and Puerto Rico Treasury Department, respectively.

23. (LOSS) EARNINGS PER UNIT

The following tables set forth the calculation of basic and diluted (loss) earnings per unit, attributable to Buckeye’s unit holders, taking into consideration net income allocable to participating securities, as well as the reconciliation of basic weighted average units outstanding to diluted weighted average units outstanding (in thousands, except per unit amounts).



	Year Ended December 31,
	2018			2017		2016
Net (loss) income attributable to unitholders	$	(62,853	)	$	474,794	$	535,608

Basic:
Weighted average units outstanding - basic	152,355			142,501		132,242
(Loss) earnings per unit - basic	$	(0.41	)	$	3.33	$	4.05

Diluted:
Weighted average units outstanding - basic	152,355			142,501		132,242
Effect of dilutive securities ⁽¹⁾	—			643		685
Weighted average units outstanding - diluted	152,355			143,144		132,927
(Loss) earnings per unit - diluted	$	(0.41	)	$	3.32	$	4.03

____________________________


(1)	Excludes 413,732 units from the computation of (loss) earnings per unit on a diluted basis as their effect was anti-dilutive for the year ended December 31, 2018.

109

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

24. BUSINESS SEGMENTS

We operate and report in three business segments: (i) Domestic Pipelines & Terminals; (ii) Global Marine Terminals; and (iii) Merchant Services. All inter-segment transactions have been eliminated in consolidation.

Domestic Pipelines & Terminals

The Domestic Pipelines & Terminals segment receives liquid petroleum products from refineries, connecting pipelines, vessels, trains, and bulk and marine terminals, transports those products to other locations for a fee, and provides bulk liquid storage and terminal throughput services. The segment also has butane blending capabilities and provides crude oil services, including train loading/unloading, storage and throughput. This segment owns and operates pipeline systems and liquid petroleum products terminals in the continental United States, including three terminals owned by the Merchant Services segment but operated by the Domestic Pipelines & Terminals segment, and two underground propane storage caverns. Additionally, this segment provides turn-key operations and maintenance of third-party pipelines and performs pipeline construction management services typically for cost plus a fixed or variable fee.

Global Marine Terminals

The Global Marine Terminals segment provides marine accessible bulk storage and blending services, rail and truck rack loading/unloading along with petroleum processing services across our network of marine terminals located primarily in the East Coast and Gulf Coast regions of the United States, as well as in the Caribbean. Our operating locations facilitate global flows of crude and refined petroleum products, offer connectivity between supply areas and market centers, and provide premier storage, marine terminalling, blending, and processing services to a diverse customer base.

Merchant Services

The Merchant Services segment is a wholesale distributor of refined petroleum products in the continental United States and in the Caribbean. The segment’s products include gasoline, natural gas liquids, ethanol, biodiesel and petroleum distillates such as heating oil, diesel fuel, kerosene and fuel oil. The segment owns three terminals, which are operated by the Domestic Pipelines & Terminals segment. The segment’s customers consist principally of product wholesalers, as well as major commercial users of these refined petroleum products.

Financial Information by Segment

For the years ended December 31, 2018, 2017 and 2016, no customer contributed 10% or more of consolidated revenue.

110

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following tables provide information about our revenue types by reportable segment for the periods indicated (in thousands). Prior periods have been disaggregated for comparison purposes.



	Year Ended December 31,
	2018
	Domestic Pipelines & Terminals		Global Marine Terminals		Merchant Services		Intersegment Eliminations			Total
Revenue from contracts with customers
Pipeline transportation	$	503,781	$	—	$	—	$	(11,656	)	$	492,125
Terminalling and storage services	437,845		386,021		—		(37,017		)	786,849
Product sales	—		5,412		2,033,646		(2,629		)	2,036,429
Other services	44,880		1,209		7,385		(1,390		)	52,084
Total revenue from contracts with customers	986,506		392,642		2,041,031		(52,692		)	3,367,487
Revenue from leases	37,684		172,260		—		(284		)	209,660
Commodity derivative contracts, net	5,894		—		531,128		(5,894		)	531,128
Total revenue	$	1,030,084	$	564,902	$	2,572,159	$	(58,870	)	$	4,108,275



	Year Ended December 31,
	2017
	Domestic Pipelines & Terminals			Global Marine Terminals		Merchant Services		Intersegment Eliminations			Total
Revenue from contracts with customers
Pipeline transportation	$	498,974		$	—	$	—	$	(17,648	)	$	481,326
Terminalling and storage services	447,703			466,489		—		(28,822		)	885,370
Product sales	—			3,891		1,531,433		(12,788		)	1,522,536
Other services	50,484			3,547		14,171		(707		)	67,495
Total revenue from contracts with customers	997,161			473,927		1,545,604		(59,965		)	2,956,727
Revenue from leases	38,504			160,822		—		(525		)	198,801
Commodity derivative contracts, net	(2		)	—		492,617		2			492,617
Total revenue	$	1,035,663		$	634,749	$	2,038,221	$	(60,488	)	$	3,648,145



	Year Ended December 31,
	2016
	Domestic Pipelines & Terminals		Global Marine Terminals		Merchant Services		Intersegment Eliminations			Total
Revenue from contracts with customers
Pipeline transportation	$	480,730	$	—	$	—	$	(18,224	)	$	462,506
Terminalling and storage services	448,322		520,411		—		(29,645		)	939,088
Product sales	—		304		1,155,276		(5,902		)	1,149,678
Other services	39,780		435		11,584		(1,624		)	50,175
Total revenue from contracts with customers	968,832		521,150		1,166,860		(55,395		)	2,601,447
Revenue from leases	42,084		150,315		—		(525		)	191,874
Commodity derivative contracts, net	780		—		455,055		(780		)	455,055
Total revenue	$	1,011,696	$	671,465	$	1,621,915	$	(56,700	)	$	3,248,376

111

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following tables summarize our revenues by major geographic area, for the periods indicated (in thousands):



	Year Ended December 31,
	2018		2017		2016
Revenue:
United States	$	3,868,364	$	3,361,160	$	2,915,619
International	239,911		286,985		332,757
Total revenue	$	4,108,275	$	3,648,145	$	3,248,376

The following tables summarize our earnings (losses) from equity investments by each segment for the periods indicated (in thousands):



	Year Ended December 31,
	2018			2017		2016
Earnings (loss) from equity investments:
Domestic Pipelines & Terminals	$	13,232		$	13,095	$	11,536
Global Marine Terminals	(287,355		)	22,910		—
Total earnings from equity investments	$	(274,123	)	$	36,005	$	11,536



	Year Ended December 31,
	2018		2017		2016
Capital expenditures ⁽¹⁾
Domestic Pipelines & Terminals	$	311,335	$	250,454	$	294,849
Global Marine Terminals	156,258		182,267		191,422
Merchant Services	18		614		45
Total capital expenditures, net	$	467,611	$	433,335	$	486,316

____________________________


(1)	Amounts exclude the impact of accruals. See Note 25 - Supplemental Cash Flow Information for further discussion.



	December 31,
	2018		2017
Total Assets:
Domestic Pipelines & Terminals	$	4,042,864	$	3,936,058
Global Marine Terminals	4,989,503		5,924,731
Merchant Services	323,183		443,870
Total assets	$	9,355,550	$	10,304,659

The Global Marine Terminals segment’s long-lived assets consist of property, plant and equipment, goodwill, intangible assets and other non-current assets. Total long-lived assets located in our international locations were $1.6 billion and $2.1 billion for the years ended December 31, 2018 and 2017, respectively.

112

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Adjusted EBITDA

Adjusted EBITDA is a measure not defined by GAAP. We define Adjusted EBITDA as earnings (losses) before interest expense, income taxes, depreciation and amortization, further adjusted to exclude certain non-cash items, such as non-cash compensation expense; transaction, transition, and integration costs associated with acquisitions; certain gains and losses on foreign currency transactions and foreign currency derivative financial instruments, as applicable; and certain other operating expense or income items, reflected in net income, that we do not believe are indicative of our core operating performance results and business outlook, such as hurricane-related costs, gains and losses on property damage recoveries, non-cash impairment charges, and gains and losses on asset sales. The definition of Adjusted EBITDA is also applied to our proportionate share in the Adjusted EBITDA of significant equity method investments, such as that in VTTI, and is not applied to our less significant equity method investments. The calculation of our proportionate share of the reconciling items used to derive Adjusted EBITDA was based upon our 50% equity interest in VTTI, prior to adjustments related to noncontrolling interests in several of its subsidiaries and partnerships, which are immaterial. Due to certain terms of the definitive agreement regarding the divestiture of our equity interest in VTTI, we determined we no longer had the ability to exercise significant influence over the operating and financial policies of VTTI and therefore, accounted for our investment at fair value. Accordingly, beginning in the fourth quarter of 2018 and prospectively, we no longer applied the definition of Adjusted EBITDA to our investment in VTTI. Adjusted EBITDA is a non-GAAP financial measure that is used by our senior management, including our Chief Executive Officer, to assess the operating performance of our business and optimize resource allocation. We use Adjusted EBITDA as a primary measure to: (i) evaluate our consolidated operating performance and the operating performance of our business segments; (ii) allocate resources and capital to business segments; (iii) evaluate the viability of proposed projects; and (iv) determine overall rates of return on alternative investment opportunities.

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

113

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table presents a reconciliation of consolidated net (loss) income, which is the most comparable financial measure under GAAP, to Adjusted EBITDA, as well as Adjusted EBITDA by segment for the periods indicated (in thousands):



		December 31,
		2018			2017			2016
Reconciliation of Net (loss) income to Adjusted EBITDA:
Net (loss) income		$	(51,915	)	$	493,665		$	548,675
Less:	Net income attributable to noncontrolling interests	(7,123		)	(14,863		)	(13,067		)
Net (loss) income attributable to Buckeye Partners, L.P.		(59,038		)	478,802			535,608
Add:	Interest and debt expense	190,172			225,583			194,922
	Income tax expense	3,740			872			1,460
	Depreciation and amortization ⁽¹⁾	269,423			269,243			254,659
	Non-cash unit-based compensation expense	21,776			30,302			33,344
	Acquisition and transition expense ⁽²⁾	11,321			4,226			8,196
	Hurricane-related costs, net of recoveries⁽³⁾	124			5,780			16,795
	Proportionate share of Adjusted EBITDA for equity method investment in VTTI ⁽⁴⁾	101,435			126,642			—
	Goodwill impairment	536,964			—			—
	Loss (earnings) from the equity method investment in VTTI ⁽⁴⁾	286,633			(22,910		)	—
Less:	Amortization of unfavorable storage contracts ⁽⁵⁾	—			—			(5,979		)
	Gains on property damage recoveries ⁽⁶⁾	(14,535		)	(4,621		)	(5,700		)
	Gain on sale of ammonia pipeline	—			—			(5,299		)
	Gain on sale of DPTS asset package	(342,984		)	—			—
Adjusted EBITDA		$	1,005,031		$	1,113,919		$	1,028,006



Adjusted EBITDA
Domestic Pipelines & Terminals	$	561,961	$	573,021	$	568,405
Global Marine Terminals	428,663		512,821		427,229
Merchant Services	14,407		28,077		32,372
Adjusted EBITDA	$	1,005,031	$	1,113,919	$	1,028,006

____________________________


(1)	Includes 100% of the depreciation and amortization expense of $73.8 million, $72.4 million and $71.7 million for Buckeye Texas for the years ended December 31, 2018, 2017 and 2016, respectively. In April 2018, we acquired our business partner’s 20% ownership interest in Buckeye Texas and, as a result, own 100% of Buckeye Texas.


(2)	Represents transaction, internal and third-party costs related to asset acquisition and integration.


(3)	Represents costs incurred at our BBH facility in the Bahamas, Yabucoa Terminal in Puerto Rico, Corpus Christi facilities in Texas, and certain terminals in Florida, as a result of hurricanes which occurred in 2017 and 2016, consisting of operating expenses and write-offs of damaged long-lived assets, net of insurance recoveries.

(4)

Due to the significance of our equity method investment in VTTI, effective January 1, 2017, we applied the definition of Adjusted EBITDA, covered in our description of Adjusted EBITDA, with respect to our proportionate share of VTTI’s Adjusted EBITDA. The calculation of our proportionate share of the reconciling items used to derive Adjusted EBITDA is based upon our 50% equity interest in VTTI, prior to adjustments related to noncontrolling interests in several of its subsidiaries and partnerships, which are immaterial. Due to certain terms of the definitive agreement regarding the divestiture of our equity interest in VTTI, we discontinued the equity method of accounting and recorded our interest at fair value. Accordingly, beginning in the fourth quarter of 2018 and prospectively, we no longer recorded any equity earnings or reflected any contributions from VTTI to our Adjusted EBITDA. Included in loss (earnings) from the equity method investment in VTTI for the year ended December 31, 2018, is a $300.3 million non-cash loss on the sale of our investment in VTTI as discussed in Note 4 - Acquisitions, Investments and Disposition.


(5)	Represents fair value adjustment amortization related to certain storage contracts acquired in the BBH acquisition. These contracts were fully amortized by December 31, 2016.

114

Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(6)	Represents gains on recoveries of property damages caused by third parties, which, for 2018, primarily related to a settlement in connection with a 2012 vessel allision with a jetty at our BBH facility in the Bahamas, and for 2017, primarily related to a settlement in connection with a 2014 vessel allision with a ship dock at our terminal located in Pennsauken, New Jersey.

25. SUPPLEMENTAL CASH FLOW INFORMATION

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



	Year Ended December 31,
	2018		2017		2016
Cash paid for interest (net of capitalized interest) ⁽¹⁾	$	224,371	$	210,723	$	174,555
Cash paid for income taxes	1,282		1,333		812
Capitalized interest	8,921		4,792		4,371

____________________________


(1)	Excludes proceeds of $51.0 million related to the settlement of our interest rate swaps. See Note 16 - Derivative Instruments and Hedging Activities for further discussion.

Liabilities related to capital projects outstanding at December 31, 2018, 2017, and 2016 of $85.3 million, $62.6 million, and $59.1 million, respectively, are not included under “Capital expenditures” within the consolidated statement of cash flows.

26. QUARTERLY FINANCIAL DATA (UNAUDITED)

Summarized quarterly financial data for the periods indicated is set forth below (in thousands, except per unit amounts). Quarterly results were influenced by seasonal and other factors inherent in our business.



	First Quarter		Second Quarter		Third Quarter			Fourth Quarter		Total
2018
Revenue	$	1,183,105	$	940,839	$	909,548		$	1,074,783	$	4,108,275
Operating (loss) income ⁽¹⁾	169,513		145,697		(391,831		)	493,652		417,031
Net (loss) income	117,092		93,317		(745,336		)	483,012		(51,915		)
Net (loss) income attributable to Buckeye Partners, L.P.	112,373		91,904		(745,835		)	482,520		(59,038		)

Earnings (loss) per unit - basic	$	0.75	$	0.59	$	(4.86	)	$	3.14	$	(0.41	)
Earnings (loss) per unit - diluted	$	0.74	$	0.59	$	(4.86	)	$	3.13	$	(0.41	)

2017
Revenue	$	969,273	$	810,201	$	922,619		$	946,052	$	3,648,145
Operating income	172,576		170,754		168,329			173,705		685,364
Net income	126,309		116,379		120,224			130,753		493,665
Net income attributable to Buckeye Partners, L.P.	123,576		112,722		116,187			126,317		478,802

Earnings per unit - basic	$	0.88	$	0.80	$	0.82		$	0.85	$	3.33
Earnings per unit - diluted	$	0.88	$	0.80	$	0.81		$	0.85	$	3.32

____________________________


(1)	Fourth quarter of 2018 includes the gain on sale of the DPTS asset package. See Note 4 - Acquisitions, Investments and Disposition for further discussion.

115

Table of Contents

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. 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.

Management’s Report on Internal Control Over Financial Reporting

Management’s report on internal control over financial reporting is set forth in Item 8, Financial Statements and Supplementary Data of this Report and is incorporated by reference herein.

Attestation Report of the Registered Public Accounting Firm

The attestation report of our registered public accounting firm with respect to internal controls over financial reporting is set forth in Item 8, Financial Statements and Supplementary Data of this Report and is incorporated by reference herein.

Change in Internal Control Over Financial Reporting

There have been no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) or in other factors during the fourth quarter of 2018, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

Item 9B. Other Information

None.

116

Table of Contents

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information required by this item will be included in our definitive Proxy Statement in connection with our 2019 Annual Meeting of unitholders (the “2019 Proxy Statement”), which will be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2018, under the headings “Proposal One: Election of Directors,” “Executive Officers of Our General Partner” and “Section 16(a) Beneficial Ownership Reporting Compliance” and is incorporated herein by reference.

Item 11. Executive Compensation

The information required by this item will be set forth in our 2019 Proxy Statement, which will be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2018, under the headings “Compensation of Executive Officers and Directors,” “Compensation Discussion and Analysis,” “Executive Compensation” and “Compensation Committee Interlocks and Insider Participation” and is incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

The information required by this item will be set forth in our 2019 Proxy Statement, which will be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2018, under the headings “Security Ownership of Certain Beneficial Owners and Management” and “Securities Authorized for Issuance under Equity Compensation Plans” and is incorporated herein by reference.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information required by this item will be set forth in our 2019 Proxy Statement, which will be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2018, under the headings “Director Independence” and “Transactions with Related Persons, Promoters and Certain Control Persons” and is incorporated herein by reference.

Item 14. Principal Accounting Fees and Services

The information required by this item will be included in our 2019 Proxy Statement, which will be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2018, under the heading “Audit and Non Audit Fees” and is incorporated herein by reference.

PART IV

Item 15. Exhibits, Financial Statement Schedules


(a)	The following documents are filed as a part of this Report:


(1)	Financial Statements — See Item 8, Financial Statements and Supplementary Data of this Report.


(2)	Financial Statement Schedules — None.


(3)	Exhibits — The following is a list of exhibits filed as part of this Report including those incorporated by reference.

117

Table of Contents



Exhibit Number		Description

2.1		Share Purchase Agreement, dated as of November 1, 2018, by and between Terminals Finance B.V. and Buckeye North Sea Coöperatief U.A. (Incorporated by reference to Exhibit 2.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on November 1, 2018).

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		Indenture dated as of July 10, 2003, between Buckeye Partners, L.P. and SunTrust Bank, as Trustee (Incorporated by reference to Exhibit 4.1 of Buckeye Partners, L.P.’s Registration Statement on Form S-4 filed September 19, 2003).

118

Table of Contents




4.2		Second Supplemental Indenture dated as of August 19, 2003, between Buckeye Partners, L.P. and SunTrust Bank, as Trustee (Incorporated by reference to Exhibit 4.3 of Buckeye Partners, L.P.’s Registration Statement on Form S-4 filed September 19, 2003).

4.3		Third Supplemental Indenture dated as of October 12, 2004, between Buckeye Partners, L.P. and SunTrust Bank, as Trustee (Incorporated by reference to Exhibit 4.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on October 14, 2004).

4.4		Fourth Supplemental Indenture dated as of June 30, 2005, between Buckeye Partners, L.P. and SunTrust Bank, as Trustee (Incorporated by reference to Exhibit 4.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on June 30, 2005).

4.5		Fifth Supplemental Indenture dated as of January 11, 2008, between Buckeye Partners, L.P. and U.S. Bank National Association (successor to SunTrust Bank), as Trustee (Incorporated by reference to Exhibit 4.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on January 11, 2008).

4.6		Sixth Supplemental Indenture dated as of August 18, 2009, between Buckeye Partners, L.P. and U.S. Bank National Association (successor-in-interest to SunTrust Bank), as Trustee (Incorporated by reference to Exhibit 4.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on August 24, 2009).

4.7		Seventh Supplemental Indenture dated as of January 13, 2011, between Buckeye Partners, L.P. and U.S. Bank National Association (successor-in-interest to SunTrust Bank), as Trustee (Incorporated by reference to Exhibit 4.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on January 20, 2011).

4.8		Eighth Supplemental Indenture dated as of June 10, 2013, between Buckeye Partners, L.P. and U.S. Bank National Association (successor-in-interest to SunTrust Bank), as Trustee (Incorporated by reference to Exhibit 4.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on June 12, 2013).

4.9		Ninth Supplemental Indenture dated as of November 14, 2013, between Buckeye Partners, L.P. and U.S. Bank National Association (successor-in-interest to SunTrust Bank), as Trustee (Incorporated by reference to Exhibit 4.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on November 19, 2013).

4.10		Tenth Supplemental Indenture, dated September 12, 2014, between Buckeye Partners, L.P. and U.S. Bank National Association (successor-in-interest to SunTrust Bank), as trustee (Incorporated by reference to Exhibit 4.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on September 12, 2014).

4.11		Eleventh Supplemental Indenture, dated November 7, 2016, between Buckeye Partners, L.P. and U.S. Bank National Association (successor-in-interest to SunTrust Bank), as trustee (Incorporated by reference to Exhibit 4.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on November 7, 2016).

4.12		Twelfth Supplemental Indenture, dated November 20, 2017, between Buckeye Partners, L.P. and Branch Banking and Trust Company (successor-in-interest to U.S. Bank National Association), as trustee (Incorporated by reference to Exhibit 4.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on November 20, 2017).

4.13		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).

4.14		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 4.2 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on January 24, 2018).

119

Table of Contents




4.15		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).

10.1		Buckeye Partners, L.P. Unit Deferral and Incentive Plan, as amended and restated effective January 1, 2017 (Incorporated by reference to Exhibit 10.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on December 19, 2016).

10.2		Services Agreement dated as of February 21, 2013, among Buckeye Partners, L.P., certain operating subsidiaries of Buckeye Partners, L.P. and Services Company (Incorporated by reference to Exhibit 10.2 of Buckeye Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2012).

*10.3		Form of Severance Agreement for each Named Executive Officer (Incorporated by reference to Exhibit 10.1 of Buckeye Partners, L.P.’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2015).

*10.4		Amended and Restated Unit Option and Distribution Equivalent Plan of Buckeye Partners, L.P., dated as of April 1, 2005 (Incorporated by reference to Exhibit 10.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on April 4, 2005).

*10.5		Buckeye Partners, L.P. 2013 Long-Term Incentive Plan (as amended and restated, effective June 6, 2017) (Incorporated by reference to Exhibit A of Buckeye Partners, L.P.’s Definitive Proxy Statement filed April 19, 2017).

*10.6		Buckeye Partners, L.P. Annual Incentive Compensation Plan (Incorporated by reference to Exhibit 10.6 of Buckeye Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2017).

*10.7		Buckeye Partners, L.P. Non-Employee Director Deferred Compensation Plan, effective as of January 1, 2013 (Incorporated by reference to Exhibit 10.8 of Buckeye Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2012).

*10.8		Buckeye Pipe Line Company Benefit Equalization Plan, effective as of January 1, 2012 (Incorporated by reference to Exhibit 10.9 of Buckeye Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2012).

*10.9		Revolving Credit Agreement, dated September 30, 2014, by and among Buckeye Partners, L.P., Buckeye Energy Services LLC, Buckeye Caribbean Terminals LLC, Buckeye West Indies Holdings LP, SunTrust Bank and other lenders party thereto (Incorporated by reference to Exhibit 10.1 to Buckeye Partners, L.P.’s Current Report on Form 8-K filed on October 6, 2014).

10.10		First Amendment to Revolving Credit Agreement dated as of December 16, 2015, by and among Buckeye Partners, L.P., Buckeye Energy Services LLC, Buckeye Caribbean Terminals LLC and Buckeye West Indies Holdings LP, as borrowers, the lenders party thereto and SunTrust Bank, as administrative agent (Incorporated by reference to Exhibit 10.1 to Buckeye Partners, L.P.’s Current Report on Form 8-K filed on December 18, 2015).

10.11		Second Amendment to Revolving Credit Agreement dated as of September 30, 2016, by and among Buckeye Partners, L.P., Buckeye Energy Services LLC, Buckeye Caribbean Terminals LLC and Buckeye West Indies Holdings LP, as borrowers, the lenders party thereto and SunTrust Bank, as administrative agent (Incorporated by reference to Exhibit 10.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on October 3, 2016).

120

Table of Contents



10.12		Third Amendment to Revolving Credit Agreement dated as of June 6, 2017, by and among Buckeye Partners, L.P., Buckeye Energy Services LLC, Buckeye Caribbean Terminals LLC and Buckeye West Indies Holdings LP, as borrowers, the lenders party thereto and SunTrust Bank, as administrative agent (Incorporated by reference to Exhibit 10.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on June 9, 2017)

10.13		Term Loan Agreement dated as of September 30, 2016, by and among Buckeye Partners, L.P., as borrower, the lenders party thereto and SunTrust Bank, as administrative agent (Incorporated by reference to Exhibit 10.2 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on October 3, 2016).

10.14		First Amendment to Term Loan Agreement dated as of June 6, 2017, by and among Buckeye Partners, L.P., as borrower, the lenders party thereto and SunTrust Bank, as administrative agent (Incorporated by reference to Exhibit 10.2 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on June 9, 2017).

* **10.15		Form of Phantom Unit Grant Agreement (Employee)

* **10.16		Form of Phantom Unit Grant Agreement (UDIP - Employee)

* **10.17		Form of Phantom Unit Grant Agreement (Director)

* **10.18		Form of Performance Unit Grant Agreement (Employee)

**21.1		List of Subsidiaries of Buckeye Partners, L.P.

**23.1		Consent of Deloitte & Touche LLP.

**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.

121

Table of Contents

____________________________

* Represents management contract or compensatory plan or arrangement.

** Filed herewith.

† Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. Buckeye agrees to furnish supplementally a copy of the omitted schedules to the SEC upon request.

(b) Exhibits — See Item 15(a)(3) above.

Item 16. Form 10-K Summary

None.

122

Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 of 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



	BUCKEYE PARTNERS, L.P.
	(Registrant)
	By:		Buckeye GP LLC,
			as General Partner

Dated: February 15, 2019	By:	/s/	CLARK C. SMITH
			Clark C. Smith
			Chief Executive Officer, President and
			Chairman of the Board
			(Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.



Dated: February 15, 2019	By:	/s/	CLARK C. SMITH
			Clark C. Smith
			Chairman of the Board, President and Chief Executive Officer
			(Principal Executive Officer)

Dated: February 15, 2019	By:	/s/	KEITH E. ST.CLAIR
			Keith E. St.Clair
			Executive Vice President and Chief Financial Officer
			(Principal Financial Officer)

Dated: February 15, 2019	By:	/s/	GARY L. BOHNSACK
			Gary L. Bohnsack
			Vice President, Controller and Chief Accounting Officer
			(Principal Accounting Officer)

Dated: February 15, 2019	By:	/s/	PIETER BAKKER
			Pieter Bakker
			Director

Dated: February 15, 2019	By:	/s/	BARBARA M. BAUMANN
			Barbara M. Baumann
			Director

Dated: February 15, 2019	By:	/s/	BARBARA J. DUGANIER
			Barbara J. Duganier
			Director

123

Table of Contents



Dated: February 15, 2019	By:	/s/	JOSEPH A. LASALA, JR.
			Joseph A. LaSala, Jr.
			Director

Dated: February 15, 2019	By:	/s/	MARK C. MCKINLEY
			Mark C. McKinley
			Director

Dated: February 15, 2019	By:	/s/	LARRY C. PAYNE
			Larry C. Payne
			Director

Dated: February 15, 2019	By:	/s/	OLIVER G. “RICK” RICHARD, III
			Oliver “Rick” G. Richard, III
			Director

Dated: February 15, 2019	By:	/s/	FRANK S. SOWINSKI
			Frank S. Sowinski
			Lead Independent Director

Dated: February 15, 2019	By:	/s/	MARTIN A. WHITE
			Martin A. White
			Director

124