10-K 1 bpl201710-k.htm 10-K 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, 2017
Or
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 and posted on its corporate website, if any, every Interactive Date File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes ý   No 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):
Large accelerated filer x
 
Accelerated filer o
 
Non-accelerated filer o
 
Smaller reporting company o
(Do not check if a smaller reporting company)
Emerging growth company o
 
 
 
 
 
 
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, 2017, the aggregate market value of the registrant’s limited partner units held by non-affiliates was $9.0 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 16, 2018, there were 146,931,979 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 2018 Annual Meeting of Limited Partners are incorporated by reference in Part III of this Form 10-K.



TABLE OF CONTENTS
 
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 



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 integrate acquired assets with our existing assets and to realize anticipated cost savings and other efficiencies and benefits; and (x) our ability to successfully complete our organic growth projects and to realize the anticipated financial 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.




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, or own a significant interest in, a diversified global network of integrated assets providing midstream logistic solutions, primarily consisting of the transportation, storage, processing and marketing of liquid petroleum products.  We are one of the largest independent liquid petroleum products pipeline operators in the United States in terms of volumes delivered, with approximately 6,000 miles of pipeline. We also use our service expertise to operate and/or maintain third-party pipelines and perform certain engineering and construction services for our customers. Our global terminal network, including through our interest in VTTI B.V. (“VTTI”), comprises more than 135 liquid petroleum products terminals with aggregate tank capacity of over 176 million barrels across our portfolio of pipelines, inland terminals and marine terminals located primarily in the East Coast, Midwest and Gulf Coast regions of the United States as well as in the Caribbean, Northwest Europe, the Middle East and Southeast Asia.  Our global network of marine terminals enables us to facilitate global flows of crude oil and refined petroleum products, offering our customers connectivity between supply areas and market centers through some of the world’s most important bulk storage and blending hubs.  Our flagship marine terminal in The Bahamas, Buckeye Bahamas Hub Limited (“BBH”), is one of the largest marine crude oil and refined petroleum products storage facilities in the world and provides an array of logistics and blending services for the global flow of petroleum products.  Our Gulf Coast regional hub, Buckeye Texas Partners LLC (“Buckeye Texas”), offers world-class marine terminalling, storage and processing capabilities. Through our 50% equity interest in VTTI, our global terminal network offers premier storage and marine terminalling services for petroleum product logistics in key international energy hubs. We are also a wholesale distributor of refined petroleum products in certain areas served by our pipelines and terminals.

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

1


We intend to achieve our strategy by:

Acquiring, building and operating high quality, strategically-located assets;
Maintaining and enhancing the integrity of our pipelines, terminals and storage assets;
Pursuing strategic cash flow-accretive acquisitions that:
Complement our existing footprint;
Provide geographic, product and/or asset class diversity; and
Leverage existing management capabilities and infrastructure;
Seeking to acquire or develop other energy-related assets that enable us to leverage our asset base, knowledge base and skill sets;
Valuing the effort, teamwork and innovation of our employees; and
Providing superior customer service.

Recent Developments

Notes Offerings and Repayments
 
In January 2018, we issued $400.0 million of junior subordinated notes (“Junior Notes”) maturing on January 22, 2078, which are redeemable at Buckeye’s option, in whole or in part, on or after January 22, 2023. The Junior Notes bear interest at a fixed rate of 6.375% per year up to, but not including, January 22, 2023. From January 22, 2023, the Junior Notes will bear interest at a floating rate based on the Three-Month London Interbank Offered Rate (“LIBOR”) plus 4.02%, reset quarterly. Total proceeds from this offering, after underwriting fees, expenses and debt issuance costs, were $394.9 million. We used the net proceeds from this offering for general partnership purposes and to reduce the indebtedness outstanding under our $1.5 billion revolving Credit Facility with SunTrust Bank (the “Credit Facility”).

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

In 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.

VTTI Acquisition

In January 2017, we acquired an indirect 50% equity interest in VTTI for cash consideration of $1.15 billion (the “VTTI Acquisition”). We own VTTI jointly with Vitol S.A. (“Vitol”). VTTI is one of the largest independent global marine terminal businesses which, through its subsidiaries and partnership interests, owns and operates approximately 58 million barrels of petroleum products tank capacity across 15 terminals located on 5 continents. These marine terminals are predominately located in key global energy hubs, including Northwest Europe, the Middle East and Southeast Asia, and offer world-class storage and marine terminalling services for liquid petroleum products. We and VIP Terminals Finance B.V., a subsidiary of Vitol, have equal board representation and voting rights in the VTTI joint venture.

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

At-the-Market Offering Program
 
In 2017, we sold approximately 6.2 million LP Units, including a block sale of 3.8 million units, under our equity distribution agreement (the “Equity Distribution Agreement”) with J.P. Morgan Securities LLC, BB&T Capital Markets, a division of BB&T Securities, LLC, BNP Paribas Securities Corp., Deutsche Bank Securities Inc., Jefferies LLC, Morgan Stanley & Co. LLC, RBC Capital Markets, LLC, and SMBC Nikko Securities America, Inc. (collectively, the “ATM Underwriters”). We received $345.8 million in net proceeds after deducting commissions and other related expenses. We used the net proceeds from the block sale to reduce the indebtedness outstanding under our Credit Facility and for general partnership purposes.

2



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 fuel oil to third parties at various locations in the Caribbean.  Additional financial information regarding revenue, profits and total assets of each segment and major geographic area can be found in Note 24 in the Notes to Consolidated Financial Statements.  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,
 
2017
 
2016
 
2015
 
Revenue
 
Percent
 
Revenue
 
Percent
 
Revenue
 
Percent
Domestic Pipelines & Terminals
$
1,035,663

 
28.4
 %
 
$
1,011,696

 
31.1
 %
 
$
966,749

 
28.0
 %
Global Marine Terminals
634,749

 
17.4
 %
 
671,465

 
20.7
 %
 
514,301

 
14.9
 %
Merchant Services (1)
2,038,221

 
55.9
 %
 
1,621,915

 
49.9
 %
 
2,037,664

 
59.0
 %
Intersegment
(60,488
)
 
(1.7
)%
 
(56,700
)
 
(1.7
)%
 
(65,280
)
 
(1.9
)%
Total
$
3,648,145

 
100.0
 %
 
$
3,248,376

 
100.0
 %
 
$
3,453,434

 
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 approximately 110 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 115 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 56 million barrels.  In addition, certain terminals provide rail loading/unloading services for a variety of petroleum products.  Of our terminals in the Domestic Pipelines & Terminals segment, over half 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.
 
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.
 

3


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,
 
2017
 
2016
 
2015
Pipelines:
 

 
 

 
 

 
 

 
 

 
 

Gasoline
756.3

 
51.8
%
 
759.6

 
53.2
%
 
735.9

 
50.4
%
Jet fuel
373.8

 
25.6
%
 
361.1

 
25.3
%
 
358.9

 
24.5
%
Middle distillates (1)
309.7

 
21.2
%
 
289.4

 
20.3
%
 
337.4

 
23.1
%
Other products (2)
19.1

 
1.4
%
 
16.9

 
1.2
%
 
28.5

 
2.0
%
Total pipelines throughput
1,458.9

 
100.0
%
 
1,427.0

 
100.0
%
 
1,460.7

 
100.0
%
_____________________________
(1)
Includes diesel fuel and heating oil.
(2)
Includes liquefied petroleum gas (“LPG”), intermediate petroleum products and crude oil.
 
We provide pipeline transportation services in the following states: California, Connecticut, Florida, Illinois, Indiana, Iowa, Maine, Massachusetts, Michigan, Missouri, Nevada, New Jersey, New York, Ohio, Pennsylvania and Tennessee.  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.  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.

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.
 

4


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.
 
Our operating subsidiary, Everglades Pipe Line Company, L.P. (“Everglades”), transports primarily jet fuel through an approximately 40-mile pipeline from Port Everglades, Florida to Ft. Lauderdale-Hollywood International Airport and Miami International Airport. 
 
Our operating subsidiary, Buckeye Aviation (Reno) LLC (“Buckeye Reno”), owns an approximately 3-mile pipeline serving the Reno/Tahoe International Airport.  Our operating subsidiary, Buckeye Aviation (San Diego) LLC (“Buckeye San Diego”), owns an approximately 4-mile pipeline serving the San Diego International Airport.  Buckeye Aviation (Memphis) LLC (“Buckeye Memphis”), formerly known as WesPac Pipelines - Memphis LLC, owns an approximately 14-mile pipeline and a related terminalling facility that primarily serves Federal Express Corporation at the Memphis International Airport.  Buckeye Reno, Buckeye San Diego and Buckeye Memphis, collectively, have terminalling facilities with aggregate storage capacity of 0.5 million barrels.

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.  The terminals also derive revenue from recovering and selling vapors captured during truck loading.  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,
 
2017
 
2016
 
2015
Products throughput (1)
1,251.5

 
1,238.4

 
1,215.4

 ____________________________
(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.


5


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

California
3

 
530

Connecticut
2

 
1,212

Florida
4

 
1,951

Iowa
5

 
1,302

Illinois
7

 
2,772

Indiana
11

 
9,846

Kentucky
1

 
214

Louisiana
1

 
304

Maine
1

 
140

Maryland
1

 
3,232

Massachusetts
2

 
433

Michigan
14

 
5,467

Missouri
3

 
1,767

Nevada
1

 
50

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

Tennessee
1

 
328

Virginia
4

 
1,805

Wisconsin
4

 
1,228

Total
115

 
56,583

 ____________________________
(1)
This table includes three terminals in Pennsylvania with aggregate tank 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 20.3 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 and energy assets across the United States. We also operate and/or maintain third-party pipelines under agreements with major oil and gas, petrochemical and chemical companies, which are located primarily in Texas and Louisiana, 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. 
 

6


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.

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, including through our interest in VTTI, 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, Northwest Europe, the Middle East, and Southeast Asia.  The segment owns and operates, or owns a significant interest in, 22 liquid petroleum product terminals, located in these key domestic and international energy hubs.
 
The following table sets forth the capacity utilization percentage within the Global Marine Terminals segment:

 
Year Ended December 31,
 
2017
 
2016
 
2015
Average capacity utilization rate (1)
92
%
 
99
%
 
96
%
___________________________
(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 88%, 92% and 85% for the years ended December 31, 2017, 2016 and 2015, respectively.
 


7


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)
1

 
6,668

Total Global Marine Terminals (2)
7

 
62,150

 
 
 
 
VTTI:
 
 
 
Northwest Europe
 
 
 
     Amsterdam, Netherlands
1

 
8,605

     Rotterdam, Netherlands
1

 
7,032

     Antwerp, Belgium
1

 
5,994

Middle East
 
 
 
     Fujairah, United Arab Emirates
1

 
10,121

Southeast Asia
 
 
 
   Johore, Malaysia
1

 
7,296

Other Regions
 
 
 
   Ventspils, Latvia
1

 
7,517

   Vasiliko, Cyprus
1

 
3,428

   Kaliningrad, Russia
1

 
308

   Ploce, Croatia
1

 
315

   Cape Canaveral, Florida
1

 
2,856

   Buenos Aires, Argentina
1

 
1,371

   Panama City, Panama
1

 
1,447

   Mombasa, Kenya
1

 
698

   Lagos, Nigeria
1

 
101

   Cape Town, South Africa
1

 
767

Total VTTI (3)
15

 
57,856

 
 
 
 
    Total
22

 
120,006

_____________________________
(1)
Represents the terminalling facility owned by Buckeye Texas, which is 80% owned by us.
(2)
This total represents total tank capacity as of December 31, 2017, of which approximately 8.3 million barrels are unavailable for contracting to third parties due to being out of service for maintenance, capital enhancements or used for internal purposes.
(3)
This total represents the terminalling facilities owned and operated by VTTI, which is 50% owned by us.








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The following descriptions set forth additional information about our and certain of VTTI’s 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.
 
BBH’s terminalling facility includes more than 80 aboveground 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. 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.
 

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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 — six miles from our Linden, New Jersey complex — and has water, pipeline, rail and truck access.  In 2014, we completed a high capacity pipeline connection between Perth Amboy and our Linden hub.  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 69 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 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. Buckeye is currently constructing a 16” bi-directional pipeline between our Perth Amboy and Raritan Bay terminals, which will allow for customer product movements between the facilities and access to the Linden hub. It is expected to be completed in the spring of 2018.
 
U.S. Gulf Coast
 
Corpus Christi Facilities
 
Buckeye Texas owns storage, petroleum processing and marine terminalling facilities that sit on approximately 730 acres along the Corpus Christi Ship Channel in Texas.  The Corpus Christi facilities have five vessel berths, including three deep-water docks, two 25,000 barrels per day condensate splitters and approximately 6.7 million barrels of liquid petroleum products storage capacity, including a refrigerated and compressed LPG storage complex, along with rail and truck loading/unloading capabilities. The platform also comprises three field gathering facilities with associated storage in the Eagle Ford play and pipeline connectivity that allows Buckeye Texas to move Eagle Ford play 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.

Northwest Europe

VTTI’s Amsterdam, Rotterdam and Antwerp terminals offer over 21 million aggregate barrels of storage capacity for liquid petroleum products. The Amsterdam terminal offers complex blending services, connections to truck and rail and a large number of berths that accommodate a broad range of vessel types. The Rotterdam terminal primarily stores fuel oil and middle distillate products and offers connections to vessels, including very large crude carriers, truck, rail, and the North Atlantic Treaty Organization (“NATO”) pipeline system. The Antwerp terminal is connected to an extensive pipeline network and harbor infrastructure, offering connections to the NATO pipeline system, vessels, truck and rail. The Antwerp terminal is also adjacent to the largest dedicated bitumen processing plant in Europe with a capacity of approximately 24,000 barrels per day, which is also owned by VTTI.

Middle East

VTTI’s Fujairah terminal offers approximately 10.1 million barrels of storage capacity for crude oil and refined petroleum products. The terminal is located in the United Arab Emirates on the gateway between the Indian Ocean and the Persian Gulf and strategically sits in one of the major bunker markets in the world. The terminal offers connections to any size or type of vessel, as well as to truck and pipelines. The terminal is also connected to the Fujairah Refinery Limited refinery, which is able to process a combination of condensate and heavy crude oil at a rate of up to 80,000 barrels per day.


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Southeast Asia

VTTI’s Johore terminal offers approximately 7.3 million barrels of storage capacity for refined petroleum products. The terminal is located in Malaysia next to the Asian hub of Singapore, one of the largest bunkering hubs in the world, and can receive all tanker sizes including partially-laden very large crude carriers.

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, propane, ethanol, biodiesel and petroleum distillates such as heating oil, diesel fuel and kerosene.  The segment also provides fuel oil supply 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,
 
2017
 
2016
 
2015
Sales volumes
1,214.8

 
1,179.7

 
1,215.0

 
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 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 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.


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Discontinuation of Natural Gas Storage Segment
 
In December 2013, the Board of Directors of Buckeye GP (“the Board”) approved a plan to divest the natural gas storage facility and related assets that our former subsidiary, Lodi Gas Storage, L.L.C. (“Lodi”), owned and operated in Northern California.  We refer to this group of assets as our Natural Gas Storage disposal group.  We reported the results of operations as discontinued operations for all periods presented in these financial statements.  In December 2014, we completed the sale of our Natural Gas Storage disposal group for $102.6 million in cash, net of expenses and working capital adjustments of $2.4 million.  We reported the final working capital adjustments as discontinued operations in the first quarter of 2015. For additional information, see Note 4 in the Notes to Consolidated Financial Statements.
 
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.
 
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.
 

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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, 2017, 2016 and 2015, 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 38% of total revenue in the segment for the year ended December 31, 2017.

In addition, BBH’s storage revenue accounted for approximately 23% of total revenue in the Global Marine Terminals segment for the year ended December 31, 2017.  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, 2017, approximately 40% and 59% of BBH’s storage revenue was derived from the top one and the top three customers, respectively.  We expect BBH to continue to derive a substantial portion of its total revenue from a small number of customers in the future. Similarly, a majority of VTTI’s 2017 revenue was derived from its primary customer, Vitol.
 
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.
 

13


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, 2017, Services Company had approximately 1,600 employees, approximately 400 of whom were represented by labor unions.  Additionally, at December 31, 2017, certain of our wholly owned subsidiaries had approximately 270 employees, approximately 150 of whom are 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 and resulting 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 Pipe Line Company LLC (“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.   
 
The indexing methodology is used to establish rates on the pipelines owned by Wood River, BPL Transportation and NORCO, and for certain rates charged by 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.
 

14


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.  See “Item 3, Legal Proceedings.”  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 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.


15


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. VTTI is subject to environmental regulatory regimes in the locations in which it operates, including the European Union and the United States. In the European Union, many of these laws and regulations are becoming increasingly stringent, and VTTI could be required to make additional capital expenditures to meet 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.


16


We believe that we currently comply in all material respects with the pipeline safety laws and regulations. However, the industry, including us, will incur additional pipeline and tank integrity expenditures in the future, and we are likely to incur increased operating costs based on these 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 2018. 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.

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, 2018.
 
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 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, 2018.


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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 ten oil spill cooperatives or mutual aid groups, and we maintain more than 50 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 over 100 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.


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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 refinery feedstock 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.
 

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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.
 
Mergers among our customers and competitors could result in lower volumes being shipped on our pipelines and stored in our terminals, thereby reducing the amount of cash we generate.
 
Mergers between existing customers could provide strong economic incentives for the combined entities to utilize their existing pipeline and terminal systems instead of ours.  As a result, we could lose some or all of the volumes and associated revenues from these customers, and we could experience difficulty in replacing those lost volumes and revenues.  Because most of our operating costs are fixed, a reduction in volumes would result in not only a reduction of revenues, but also a decline in Adjusted EBITDA (see “Non-GAAP Financial Measures” in Item 7 for a discussion of Adjusted EBITDA, which is our primary measure of performance), net income and cash flow of a similar magnitude, which would reduce our ability to meet our financial obligations and pay cash distributions.
 
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.


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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.
 
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 acquisitionWe 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.

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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.
 
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 the pipelines owned by Wood River, BPL Transportation and NORCO, and for certain rates charged by 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 Wood River, BPL Transportation and NORCO, and certain rates charged by 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 greenhouse gases 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 GHG.  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.

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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 filed.
 
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, particularly California, 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 or new DOT pipeline safety regulations may affect our operations.
 

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Our international operations may be adversely affected by economic, political and regulatory developments.
 
BBH’s terminalling facility and the St. Lucia terminal are located in The Bahamas and St. Lucia, respectively.  VTTI’s operations span the globe, with key locations predominantly located in Northwest Europe, the Middle East and Southeast Asia. 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 the policies of the United States affecting trade, taxation and investment in other countries.  Any such developments or changes 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 approvals, permits and licenses may not be obtained, may 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.
 

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Our results 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.
 

The loss of one or more key customers in our Global Marine Terminals segment could adversely affect our results of operations and cash flow.
 
BBH’s storage revenue accounted for approximately 23% of total revenue in the Global Marine Terminals segment for the year ended December 31, 2017. 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, 2017, 40% and 59% of BBH’s storage revenue was derived from the top one and the top three customers, in the aggregate, respectively.  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.  If any of BBH’s customers, in particular its top three customers, 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.

Additionally, revenue from Buckeye Texas, which is contracted predominantly to one customer under long-term take-or-pay arrangements, accounted for approximately 38% of total revenue in the Global Marine Terminals segment for the year ended December 31, 2017. 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.

Similarly, a majority of VTTI’s 2017 revenue was derived from its primary customer, Vitol. If a significant portion of VTTI’s contractual arrangements with Vitol is terminated and VTTI is unable to secure comparable alternative arrangements with one or more third parties, VTTI may not be able to generate sufficient additional revenue to fully replace that generated by the current customer, which may have a significant adverse effect on its ability to pay distributions to us.

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.


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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.

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. Failures of our information technology systems 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.

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 TSA 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.

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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.

Additionally, if VTTI, or its or officers, directors, employees or agents, were determined to be in violation of anti-corruption laws, including the FCPA and the U.K. Bribery Act, VTTI could become subject to substantial fines, sanctions, civil and/or criminal penalties, or curtailment of VTTI’s operations in certain jurisdictions, which could adversely affect its business, results of operations or financial condition. Any such adverse effects could, in turn, adversely affect VTTI’s ability to make cash distributions to us.

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, 2017, 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.
 

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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 are lower at settlement than when we entered into these futures contracts, then we will be required to make payments upon the settlement thereof.  Ordinarily, this settlement payment is offset by the payment received from the customer pursuant to the associated fixed-price contract.  We are, however, required to make the settlement payment 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.
 

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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.

VTTI is subject to many of the same operational and business risks to which our wholly owned operations are subject and we have less control over the way VTTI manages these risks.

VTTI is subject to many of the risks described above, including risks related to shifts in supply and demand, competition, environmental risks, environmental and other regulations, the need to attract and retain customers, credit risks, and terrorism and natural disaster risks. Because we do not control VTTI, we may not be able to mitigate or protect against these risks as we would with our wholly owned assets and business. If VTTI’s business were to be negatively impacted by any of these risks, its results of operations, financial position and cash flows, as well as its ability to pay cash distributions to us could be adversely affected.

We have limited ability to influence significant business decisions affecting VTTI without also receiving the consent of Vitol.

Differences in views among the owners of VTTI could result in delayed decisions or in failures to agree on significant matters, potentially adversely affecting the business and results of operations or prospects of VTTI and, in turn, the amount of cash from operations distributed to us.

In addition, we do not control the day-to-day operations of the VTTI Entities. Our lack of control over the VTTI Entities’ day-to-day operations and the associated costs of such operations could result in our receiving lower cash distributions than we anticipate, which could have an adverse effect on our financial condition or cash flows.


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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.
 
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 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 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 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 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.
 

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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 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, on January 24, 2017, final regulations (the “Final Regulations”) regarding which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code of 1986, as amended (the “Code”) were published in the Federal Register. We do not believe the Final Regulations affect our ability to be treated as a partnership for U.S. federal income tax purposes.

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.
 
If the IRS were to contest the 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 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.


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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 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.

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, however, we have not yet determined the impact the limitation could have on our unitholders’ ability to deduct the interest expense we derive from VTTI.  
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. Further, with respect to taxable years beginning after December 31, 2017, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours that is engaged in one or more unrelated trade or business) 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.

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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.
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 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.
 

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Taxable income from our non-U.S. businesses is not eligible for the 20% deduction for qualified publicly traded partnership income.
Pursuant to the Tax Act, a unitholder is generally allowed a deduction equal to 20% of our “qualified publicly traded partnership income” that is allocated to such unitholder.   For purposes of the deduction, the term qualified publicly traded 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 and the VTTI 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.
Our gross income with respect to the VTTI business may not be qualifying income, and we may cause all or a portion of our interest in such business to be held in an entity treated as a corporation for U.S. federal income tax purposes, which could substantially reduce cash available for distribution.
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 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. 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. 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 or operations. 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.
If these income inclusion amounts are expected to exceed our anticipated tolerance for gross income with respect to which our counsel is unable to opine and we are unable to receive a favorable IRS ruling in a timely manner, it may be necessary for us to hold some or all of our interests in the VTTI business through a taxable U.S. corporate subsidiary. In such case, this corporate subsidiary would be subject to corporate-level tax on its taxable income up to the maximum U.S. federal corporate income tax rate, which is currently 21%, as well as any applicable state and local income tax rates. Imposition of a corporate level income tax would significantly reduce the anticipated cash available for distribution from the VTTI business to us and, in turn, would reduce our cash available for distribution to our unitholders. Moreover, if the IRS were to successfully assert that this corporation had more tax liability than we currently anticipate or legislation was enacted that increased the corporate tax rate, our cash available for distribution to our unitholders would be further reduced.
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 and a portion of the VTTI 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.


34


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.
  
We have subsidiaries that are treated as corporations for federal income tax purposes and subject to corporate-level income taxes.
 
We conduct a portion of our operations through subsidiaries that are corporations for 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.

Item 1B.    Unresolved Staff Comments
 
None.
 

35


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, leases, 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.


36


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 high and low sales prices of our LP Units during the years ended December 31, 2017 and 2016, as reported in the NYSE Composite Transactions, were as follows:
 
 
2017
 
2016
Quarter
 
High
 
Low
 
High
 
Low
First
 
$
72.00

 
$
64.50

 
$
70.84

 
$
47.07

Second
 
69.95

 
60.70

 
74.35

 
62.29

Third
 
65.34

 
55.16

 
75.10

 
67.11

Fourth
 
59.25

 
45.24

 
71.79

 
61.37

 
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, 2012 and that all distributions or dividends were reinvested on a quarterly basis.
marketforunitholdersgraph21.jpg
 
12/31/2012
 
12/31/2013
 
12/31/2014
 
12/31/2015
 
12/31/2016
 
12/31/2017
Buckeye Partners, L.P.
$
100.00

 
$
167.09

 
$
188.52

 
$
175.18

 
$
188.99

 
$
153.65

S&P 500
100.00

 
132.39

 
150.51

 
152.59

 
170.84

 
208.14

Alerian MLP Index
100.00

 
127.58

 
133.71

 
90.13

 
106.63

 
99.68


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 159,500 at December 31, 2017.
 

37


Cash distributions paid to unitholders for the periods indicated were as follows:
 
 
 
 
Amount Per
Record Date
 
Payment Date
 
LP Unit
February 17, 2015
 
February 24, 2015
 

$1.1375

May 11, 2015
 
May 18, 2015
 

$1.1500

August 10, 2015
 
August 17, 2015
 

$1.1625

November 9, 2015
 
November 17, 2015
 

$1.1750

 
 
 
 
 

February 23, 2016
 
March 1, 2016
 

$1.1875

May 16, 2016
 
May 23, 2016
 

$1.2000

August 15, 2016
 
August 22, 2016
 

$1.2125

November 15, 2016
 
November 22, 2016
 

$1.2250

 
 
 
 
 

February 21, 2017
 
February 28, 2017
 

$1.2375

May 15, 2017
 
May 22, 2017
 

$1.2500

August 14, 2017
 
August 21, 2017
 

$1.2625

November 13, 2017
 
November 20, 2017
 

$1.2625

 
On February 9, 2018, we announced a quarterly distribution of $1.2625 per LP Unit that will be paid on February 27, 2018, to unitholders of record on February 20, 2018.  Based on the LP Units and distribution equivalent rights with respect to certain unit-based compensation awards outstanding as of December 31, 2017, cash expected to be distributed to unitholders on February 27, 2018 is estimated to be approximately $186.2 million.
 
We generally make quarterly cash distributions of substantially all of our available cash, generally defined as consolidated cash receipts less consolidated cash expenditures and such retentions for working capital, anticipated cash expenditures and contingencies as Buckeye GP deems appropriate.
 
Buckeye Partners, L.P. is a publicly traded MLP, and is not subject to federal income tax.  Instead, unitholders are required to report their allocable share of our income, gain, loss and deduction, regardless of whether we make distributions.  We have made quarterly distribution payments since May 1987.
 
Recent Sales of Unregistered Securities
 
None.
 
Issuer Purchases of Equity Securities
 
None.


38


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 of this Report (in thousands, except per unit amounts):
 
Year Ended December 31,
 
2017
 
2016
 
2015
 
2014
 
2013
Income Statement Data:
 

 
 

 
 

 
 

 
 

Revenue (1)
$
3,648,145

 
$
3,248,376

 
$
3,453,434

 
$
6,620,247

 
$
5,054,101

Operating income
683,904

 
733,342

 
604,116

 
495,347

 
478,041

Income from continuing operations
493,665

 
548,675

 
438,391

 
334,498

 
351,599

Earnings per unit - diluted from continuing operations
$
3.32

 
$
4.03

 
$
3.41

 
$
2.78

 
$
3.23

Cash distributions per LP Unit - declared for the period
$
5.04

 
$
4.88

 
$
4.68

 
$
4.48

 
$
4.28

Diluted weighted average units outstanding
143,144

 
132,927

 
128,617

 
119,899

 
107,677

 
 
December 31,
 
2017
 
2016
 
2015
 
2014
 
2013
Balance Sheet Data:
 

 
 

 
 

 
 

 
 

Total assets (2) (3)
$
10,304,659

 
$
9,421,103

 
$
8,369,281

 
$
8,065,720

 
$
6,988,024

Long-term debt (3)
4,658,321

 
4,217,695

 
3,732,824

 
3,368,618

 
3,075,172

Total Buckeye Partners, L.P. capital
4,590,937

 
4,411,723

 
3,735,389

 
3,702,628

 
3,065,665

____________________________
(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 impact of $181.7 million of assets held for sale as of December 31, 2013 relating to the Natural Gas Storage disposal group sold in December 2014. See Note 4 in the Notes to Consolidated Financial Statements for further discussion.
(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, and $17.5 million of debt issuance costs originally included in “Other non-current assets” as of each respective year ending December 31, 2014 and 2013 to “Long-term debt” as a direct deduction from the carrying amount of debt liabilities, consistent with debt discounts.


39


Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
The following discussion should be read in conjunction with our consolidated financial statements and our accompanying notes thereto included in Item 8 of this Report.
 
Business Overview
 
We own and operate, or own a significant interest in, a diversified global network of integrated assets providing midstream logistic solutions, primarily consisting of the transportation, storage, processing and marketing of liquid petroleum products.  We are one of the largest independent liquid petroleum products pipeline operators in the United States in terms of volumes delivered, with approximately 6,000 miles of pipeline. We also use our service expertise to operate and/or maintain third-party pipelines and perform certain engineering and construction services for our customers. Our global terminal network, including through our interest in VTTI, comprises more than 135 liquid petroleum products terminals with aggregate tank capacity of over 176 million barrels across our portfolio of pipelines, inland terminals and marine terminals located primarily in the East Coast, Midwest and Gulf Coast regions of the United States, as well as in the Caribbean, Northwest Europe, the Middle East and Southeast Asia.  Our global network of marine terminals enables us to facilitate global flows of crude oil and refined petroleum products, offering our customers connectivity between supply areas and market centers through some of the world’s most important bulk liquid storage and blending hubs.  Our flagship marine terminal in The Bahamas, 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, offers world-class marine terminalling, storage and processing capabilities. Through our 50% equity interest in VTTI, our global terminal network offers premier storage and marine terminalling services for petroleum product logistics in key international energy hubs. We are also a wholesale distributor of refined petroleum products in certain areas served by our pipelines and terminals. 

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

40


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,
 
2017
 
2016
 
2015
Revenue
$
3,648,145

 
$
3,248,376

 
$
3,453,434

Costs and expenses
2,964,241

 
2,515,034

 
2,849,318

Operating income
683,904

 
733,342

 
604,116

Earnings from equity investments
36,005

 
11,536

 
6,381

Interest and debt expense
(225,583
)
 
(194,922
)
 
(171,330
)
Other income
211

 
179

 
98

Income from continuing operations before taxes
494,537

 
550,135

 
439,265

Income tax expense
(872
)
 
(1,460
)
 
(874
)
Income from continuing operations
493,665

 
548,675

 
438,391

Loss from discontinued operations (1)

 

 
(857
)
Net income
493,665

 
548,675

 
437,534

Less: Net income attributable to noncontrolling interests
(14,863
)
 
(13,067
)
 
(311
)
Net income attributable to Buckeye Partners, L.P.
$
478,802

 
$
535,608

 
$
437,223

Diluted earnings (loss) per unit attributable to Buckeye Partners, L.P.
 

 
 

 
 

Continuing operations
$
3.32

 
$
4.03

 
$
3.41

Discontinued operations
$

 
$

 
$
(0.01
)
_____________________________
(1)
Represents loss from the operations of our Natural Gas Storage disposal group.  See Note 4 in the Notes to Consolidated Financial Statements for more information.
 

41


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 from continuing operations before interest expense, income taxes, depreciation and amortization, further adjusted to exclude certain non-cash items, such as non-cash compensation expense; transaction, transition, and integration costs associated with acquisitions; certain unrealized gains and losses on foreign currency transactions and foreign currency derivative financial instruments, as applicable; and certain other operating expense or income items, reflected in net income, that we do not believe are indicative of our core operating performance results and business outlook, such as hurricane-related costs, gains and losses on property damage recoveries, and gains and losses on asset sales. We define distributable cash flow as Adjusted EBITDA less cash interest expense, cash income tax expense, and maintenance capital expenditures incurred to maintain the operating, safety, and/or earnings capacity of our existing assets, plus or minus realized gains or losses on certain foreign currency derivative financial instruments, as applicable. These definitions of Adjusted EBITDA and distributable cash flow are also applied to our proportionate share in the Adjusted EBITDA and distributable cash flow of significant equity method investments, such as that in VTTI, and are not applied to our less significant equity method investments. The calculation of our proportionate share of the reconciling items used to derive these VTTI performance metrics is based upon our 50% equity interest in VTTI, prior to adjustments related to noncontrolling interests in several of its subsidiaries and partnerships, which are immaterial. These adjustments include gains and losses on foreign currency derivative financial instruments used to hedge VTTI’s United States dollar denominated distributions which are excluded from Adjusted EBITDA and included in distributable cash flow when realized. Adjusted EBITDA and distributable cash flow are non-GAAP financial measures that are used by our senior management, including our Chief Executive Officer, to assess the operating performance of our business and optimize resource allocation. We use Adjusted EBITDA as a primary measure to: (i) evaluate our consolidated operating performance and the operating performance of our business segments; (ii) allocate resources and capital to business segments; (iii) evaluate the viability of proposed projects; and (iv) determine overall rates of return on alternative investment opportunities.  We use distributable cash flow as a performance metric to compare 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.


42


The following table presents income from continuing operations on a consolidated basis and a reconciliation of income from continuing operations, 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,
 
 
2017
 
2016
 
2015
Reconciliation of Income from continuing operations to
Adjusted EBITDA and Distributable cash flow:
 

 
 

 
 

Income from continuing operations
$
493,665

 
$
548,675

 
$
438,391

Less:
Net income attributable to noncontrolling interests
(14,863
)
 
(13,067
)
 
(311
)
Income from continuing operations attributable to Buckeye Partners, L.P.
478,802

 
535,608

 
438,080

Add:       
Interest and debt expense
225,583

 
194,922

 
171,330

 
Income tax expense
872

 
1,460

 
874

 
Depreciation and amortization (1)
269,243

 
254,659

 
221,278

 
Non-cash unit-based compensation expense
30,302

 
33,344

 
29,215

 
Acquisition and transition expense (2)
4,226

 
8,196

 
3,127

 
Litigation contingency accrual (3)

 

 
15,229

 
Hurricane-related costs, net of recoveries (4)
5,780

 
16,795

 

 
Proportionate share of Adjusted EBITDA for the equity method investment in VTTI (5)
126,642

 

 

Less:           
Amortization of unfavorable storage contracts (6)

 
(5,979
)
 
(11,071
)
 
Gains on property damage recoveries (7)
(4,621
)
 
(5,700
)
 

 
Gain on sale of ammonia pipeline

 
(5,299
)
 

 
Earnings from the equity method investment in VTTI (5)
(22,910
)
 

 

Adjusted EBITDA
$
1,113,919

 
$
1,028,006

 
$
868,062

Less:         
Interest and debt expense, excluding amortization of deferred financing costs, debt discounts and other
(208,380
)
 
(177,996
)
 
(154,469
)
 
Income tax (expense) benefit, excluding non-cash taxes
(297
)
 
276

 
(1,536
)
 
Maintenance capital expenditures
(144,046
)
 
(129,691
)
 
(99,617
)
 
Proportionate share of VTTI’s interest expense, current income tax expense, realized foreign currency derivative gains and losses, and maintenance capital expenditures (5)
(43,855
)
 

 

Add:
Hurricane-related maintenance capital expenditures
14,577

 
6,054

 

Distributable cash flow
$
731,918

 
$
726,649

 
$
612,440

 
 
 
 
 
 
 
Adjusted EBITDA by segment:
 

 
 

 
 

Domestic Pipelines & Terminals
$
573,021

 
$
568,405

 
$
522,196

Global Marine Terminals
512,821

 
427,229

 
323,840

Merchant Services
28,077

 
32,372

 
22,026

Adjusted EBITDA
$
1,113,919

 
$
1,028,006

 
$
868,062

____________________________
(1)
Includes 100% of the depreciation and amortization expense of $72.4 million, $71.7 million and $49.3 million for Buckeye Texas for the years ended December 31, 2017, 2016 and 2015, respectively.
(2)
Represents transaction, internal and third-party costs related to asset acquisition and integration.
(3)
Represents reductions in revenue related to settlement of a FERC proceeding.
(4)
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 Harvey, Irma, and Maria, which occurred in August and September 2017, as well as Hurricane Matthew, which occurred in October 2016, consisting of operating expenses and write-offs of damaged long-lived assets, net of insurance recoveries.

43


(5)
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.
(6)
Represents fair value adjustment amortization related to certain storage contracts acquired in the BBH acquisition. These contracts were fully amortized by December 31, 2016.
(7)
Represents gains on recoveries of property damages caused by third parties, primarily related to an allision with a ship dock at our terminal located in Pennsauken, New Jersey.

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,
 
2017
 
2016
 
2015
Domestic Pipelines & Terminals (average bpd in thousands):
 

 
 

 
 

Pipelines:
 

 
 

 
 

Gasoline
756.3


759.6

 
735.9

Jet fuel
373.8


361.1

 
358.9

Middle distillates (1)
309.7


289.4

 
337.4

Other products (2)
19.1


16.9

 
28.5

Total throughput
1,458.9


1,427.0

 
1,460.7

Terminals:
 


 

 
 

Throughput (3)
1,251.5


1,238.4

 
1,215.4

 
 
 
 
 
 
Pipeline average tariff (cents/bbl)
89.7


85.9

 
83.7

 
 
 
 
 
 
Global Marine Terminals (percent of capacity):
 
 
 
 
 
Average capacity utilization rate (4)
92
%

99
%
 
96
%
 
 
 
 
 
 
Merchant Services (in millions of gallons):
 

 
 

 
 

Sales volumes
1,214.8


1,179.7

 
1,215.0

_____________________________
(1)
Includes diesel fuel and heating oil.
(2)
Includes LPG, intermediate petroleum products and crude oil.
(3)
Includes throughput of two underground propane storage caverns.
(4)
Represents the ratio of contracted capacity to capacity available to be contracted. Based on total capacity (i.e., including out of service capacity), average capacity utilization rates are approximately 88%, 92% and 85% for the years ended December 31, 2017, 2016 and 2015, respectively.
 

44


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.


45


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.

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
 
Consolidated Overview

Income from continuing operations was $548.7 million for the year ended December 31, 2016, an increase of $110.3 million, or 25.2%, from $438.4 million in 2015.  The increase reflected stronger results from all segments, as discussed below in the section covering segment results, as well as $11.0 million in gains from property damage recoveries and the sale of an ammonia pipeline in Texas; partially offset by the following factors: (i) a $33.4 million increase in depreciation and amortization related to assets placed in service during the period, as well as a full year of operation of the Buckeye Texas assets which were commissioned in the fourth quarter of 2015; (ii) a $23.6 million increase in interest and debt expense, due to lower capitalization of interest, as a result of the placement in service of the Buckeye Texas assets during the fourth quarter of 2015, and long-term debt issued in the fourth quarter of 2016 to partially fund the VTTI Acquisition; and (iii) $5.1 million of incremental acquisition and transition expenses.
 
Total Adjusted EBITDA was $1,028.0 million for the year ended December 31, 2016, an increase of $159.9 million, or 18.4%, from $868.1 million in 2015.  The increase in Adjusted EBITDA was primarily related to increases in segment Adjusted EBITDA of $103.4 million, $46.2 million, and $10.4 million, respectively in Global Marine Terminals, Domestic Pipelines & Terminals, and Merchant Services segments, as further explained within the discussion of Adjusted EBITDA by segment below.

Distributable cash flow was $726.6 million for the year ended December 31, 2016, an increase of $114.2 million, or 18.6%, from $612.4 million in 2015.  The increase in distributable cash flow was primarily related to an increase of $159.9 million in Adjusted EBITDA as described above. This increase was partially offset by a $24.0 million increase in maintenance capital expenditures, excluding hurricane-related maintenance capital expenditures, primarily resulting from increased tank integrity project costs, marine dock structure upgrades, and upgrades to station and terminalling equipment, as well as a $23.5 million increase in interest and debt expense, excluding amortization of deferred financing costs, debt discounts and other, reflecting the factors discussed above.
 

46


Adjusted EBITDA by Segment

Domestic Pipelines & Terminals. Adjusted EBITDA from the Domestic Pipelines & Terminals segment was $568.4 million for the year ended December 31, 2016, an increase of $46.2 million, or 8.8%, from $522.2 million for the corresponding period in 2015.  The increase in Adjusted EBITDA was primarily due to a $37.1 million net increase in revenue, a $5.2 million increase in earnings from equity investments and a $3.9 million decrease in operating expenses. The increase in revenue was due to a $40.1 million increase in terminalling throughput revenue and product recovery revenue, reflecting new terminalling-services contracts and $14 million in proceeds from the exercise by a customer of an early buy-out provision in a crude-by-rail contract at our Albany, New York terminal, as well as a $23.4 million increase in storage revenue, primarily due to storage capacity brought back into service, internal growth capital investments, and new storage contracts. These increases were partially offset by a $13.6 million decrease in certain blending activities, a $7.2 million decrease in project management revenues, and $5.6 million decrease in other revenues. The decrease in project management revenues was due to a decrease in project activity. The decrease in operating expenses was primarily due to favorable power and utilities, a decrease in reimbursable expenses within our project management business due to a decrease in project activity, and lower general and administrative expenses; partially offset by higher payroll and benefits, reflecting merit increases and incremental property taxes.
  
Pipeline volumes decreased by 2.3% due to a decline in distillate volumes, reflecting lower industrial activity and warmer weather, which was partially offset by higher gasoline volumes due to increased customer demand. Terminalling throughput volumes increased by 1.9% due to higher gasoline volumes, reflecting increased customer demand, partially offset by absence of throughput activity and subsequent termination of a crude-by-rail contract at our Albany, New York terminal.

Global Marine Terminals.  Adjusted EBITDA from the Global Marine Terminals segment was $427.2 million for the year ended December 31, 2016, an increase of $103.4 million, or 31.9%, from $323.8 million for the corresponding period in 2015.  The increase in Adjusted EBITDA was primarily due to a $135.0 million net increase in revenue, partially offset by a $31.6 million increase in operating expenses. The increase in revenue was due to a $138.5 million increase in revenue from storage and terminalling services, reflecting increased contributions from our joint venture interest in Buckeye Texas, as a result of assets commissioned during the fourth quarter of 2015. Our internal growth capital investments since the second quarter of 2015 increased available storage capacity and diversified our asset capabilities at Buckeye Texas and other marine storage terminals. In addition, such capital investments enabled us to achieve an increase in storage and terminalling services revenue in 2016. The average capacity utilization of our marine storage assets was 99% for the year ended December 31, 2016, which was an increase from 96% in the corresponding period in 2015. These increases in revenue were partially offset by a $3.5 million decrease in ancillary revenues, which was principally due to lower berthing activity and other related ancillary services. Operating expenses increased by $31.6 million, primarily due to the operation of the Buckeye Texas assets.

Merchant Services.  Adjusted EBITDA from the Merchant Services segment was $32.4 million for the year ended December 31, 2016, an increase of $10.4 million, or 47.3%, from $22.0 million for the corresponding period in 2015.  Adjusted EBITDA was positively impacted by continued effective inventory management and a decrease in operating expenses.

Adjusted EBITDA was negatively impacted by a $415.8 million decrease in revenue, which included a $59.2 million decrease due to 2.9% lower volumes sold and a $356.6 million decrease in refined petroleum product sales due to lower commodity prices (average sales prices per gallon were $1.37 and $1.68 for the 2016 and 2015 periods, respectively).

Adjusted EBITDA was positively impacted by a $423.8 million decrease in cost of product sales, which included a $58.1 million decrease due to 2.9% lower volumes sold and a $365.7 million decrease in refined petroleum product cost due to lower commodity prices (average prices per gallon were $1.34 and $1.65 for the 2016 and 2015 periods, respectively) and a $2.4 million decrease in operating expenses.

47


General Outlook for 2018

We expect to see solid performance across our reporting segments for 2018 as we benefit from improving market conditions, particularly around our Domestic Pipeline & Terminal segment’s assets. We expect to see incremental returns associated with growth capital investments made across our global portfolio, including the VTTI Merger. Offsetting this growth, we expect to see continued storage market challenges that may impact contract renewal rates and capacity utilization in our segregated storage business.

Domestic Pipelines & Terminals Segment Business Outlook and Growth Projects

In 2018, we expect tariff increases on our market-based and FERC index-based tariff pipelines to drive a part of our pipeline revenue growth. Pipeline throughput volumes are projected to remain relatively flat as strength in distillate volumes is partially offset by the impact of expected refinery turnarounds and other minor system fluctuations. Throughput volumes across our domestic terminals are expected to increase moderately from the completion of growth capital initiatives across our system and expansion of market share, primarily in the Southeast and Northeast United States. Throughput revenues are anticipated to be impacted by the expiration of a crude-by-rail contract at our Chicago Complex in early 2018 that we do not expect to be renewed. Our butane blending and settlement revenues, including revenues associated with the operation of our vapor recovery equipment, are expected to generate incremental benefits compared to the prior year.

We expect to see the benefit, in 2018, from a number of growth projects currently underway. We continue to advance through the regulatory approval process on 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 the planned partial reversal of our Laurel pipeline. While we await final regulatory approval, which is expected in mid-2018, our teams continue to advance engineering and construction planning efforts to meet our expected in-service date of late 2018.

We expect to sign a long-term agreement for an expansion of our Chicago Complex to provide additional services to a major Midwestern-area refinery. This project includes the construction of additional product tankage, for which we have already received necessary air permits, as well as the significant expansion of an existing truck rack on our site. We expect this project to be completed in 2019.

We have completed or are advancing a number of smaller projects that require moderate capital investments and have attractive return profiles that we expect to contribute to our 2018 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. We have made investments across our terminalling asset footprint to upgrade our vapor recovery unit equipment, improving the contribution from recovery of truck rack vapors while benefiting the environment by reducing our emissions. We expect to benefit in 2018 from these and other projects completed in 2017 or projected to be completed in 2018.

Buckeye Texas Partners Joint Venture Opportunities

Our operations teams at our Buckeye Texas Partners joint venture remain focused on improving the operational capabilities of our assets in South Texas, and we expect to see improved throughput rates on our condensate splitters. We are working with our partner and customer on various projects intended to debottleneck and improve the throughput capabilities of our facilities. These projects include expanding dock capabilities, adding storage capacity and increasing pipeline connectivity, in advance of an anticipated increase in throughput volumes due to our customer’s increased supply commitments on pipelines from the Permian into Corpus Christi.







48


VTTI Strategic Rationale and Take Private Transaction

Our equity investment in VTTI represents a significant interest in a global network with substantial breadth and scale. Our combined marine storage terminal footprint is situated across major global logistics hubs, including the U.S. Gulf Coast, New York Harbor, Northwest Europe, the Caribbean, the Middle East and Southeast Asia, as well as key terminalling locations in emerging markets. These facilities include state-of-the-art, world class marine terminals designed with a focus on providing superior customer optionality, most with multi-modal capabilities to receive and deliver a wide array of petroleum products. This platform represents a broad set of organic and expansion opportunities capitalizing on a number of emerging market trends at attractive expected investment multiples.

In September 2017, VTTI successfully completed the VTTI Merger, which simplified VTTI’s structure and further enhanced the expected accretion to Buckeye’s distributable cash flow.

Global Marine Terminals Segment Storage Business Outlook and Growth Projects

We continue to be impacted by evolving market conditions that are anticipated to be less favorable for segregated storage demand. Our commercial teams, however, have historically been able to maintain high levels of utilization of available storage capacity through varying market cycles. We believe we are well-positioned to manage through these current market conditions as we continue to be proactive in leveraging our diversified portfolio of assets to meet our customers’ needs, although we may see pressure on storage rates. We are converting certain of our storage capacity in the Caribbean to handle a wider spectrum of products, as well as further enhancing some of our service offerings to accommodate new business lines. In the New York Harbor, we are currently constructing a 16” bi-directional pipeline between our Perth Amboy and Raritan Bay terminals, which will provide enhanced connectivity and is expected to drive improved utilization across our storage assets in the area.  The project is expected to be completed in the spring of 2018.

Merchant Services Segment Business Outlook

Our Merchant Services segment continues to focus on optimizing its position across our portfolio of domestic assets to drive higher utilization and incremental value to Buckeye. We believe this segment’s disciplined supply management efforts will deliver stable results in 2018.

Capital Market and Financing Activities

We have $400 million of long-term debt maturing in November 2018. We believe that we have sufficient liquidity available on our $1.5 billion revolving Credit Facility to satisfy this maturity, although we do plan to access the debt capital market in late 2018. We have executed approximately $500 million of forward starting interest rate hedges that mature in late 2018 to partially mitigate the risk of rising interest rates on our expected issuance. During 2017, issuances of LP Units under our at-the-market (“ATM”) offering program aggregated to approximately $346 million. We expect the LP Unit issuances made under our ATM offering program in 2017 to be sufficient to fund the equity portion of our growth capital projects in the near term. Our ATM offering program expired in January 2018 concurrent with the expiration of our traditional shelf registration statement and Equity Distribution Agreement. Our new traditional shelf registration statement became effective in December 2017, and we intend to enter into a new equity distribution agreement in connection with our ATM offering program in 2018. Under current market conditions, we believe that we could raise additional capital in both the debt and equity capital markets on acceptable terms to fund appropriate asset or business acquisitions.

We will continue to evaluate opportunities throughout 2018 to acquire or construct assets that are strategically positioned to support our long-term growth strategy and will determine the appropriate financing structure on acceptable terms for any opportunity we pursue.

The forward-looking statements contained in this “General Outlook for 2018” 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 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 2018” may not occur.

49


Liquidity and Capital Resources
 
            General
 
                        Our primary cash requirements, in addition to normal operating expenses and debt service, are for working capital, capital expenditures, business acquisitions and distributions to unitholders.  Our principal sources of liquidity are cash from operations, borrowings under our $1.5 billion revolving Credit Facility and proceeds from the issuance of our LP Units.  We will, from time to time, issue debt securities to refinance amounts borrowed under our Credit Facility.  Buckeye Energy Services LLC, Buckeye West Indies Holdings LP, and Buckeye Caribbean Terminals LLC (collectively the Buckeye Merchant Service Companies or “BMSC”) fund their working capital needs principally from their own operations and their portion of our Credit Facility.  Our financial policy is to fund maintenance capital expenditures with cash from continuing operations.  Expansion and cost reduction capital expenditures, along with acquisitions, have typically been funded from external sources including our Credit Facility, as well as debt and equity offerings.  Our goal has been to fund at least half of these expenditures with proceeds from equity offerings in order to maintain an appropriate leverage ratio and our investment-grade credit rating.  Based on current market conditions, we believe our borrowing capacity under our Credit Facility, cash flows from continuing operations and access to debt and equity markets, if necessary, will be sufficient to fund our primary cash requirements, including our expansion plans over the next 12 months.
 
            Current Liquidity
 
As of December 31, 2017, we had a $28.8 million working capital deficit and $1.1 billion of availability under our Credit Facility.
 
Capital Structuring Transactions
 
As part of our ongoing efforts to maintain a capital structure that is closely aligned with the cash-generating potential of our asset-based business, we may explore additional sources of external liquidity, including public or private debt or equity issuances.  Matters to be considered will include cash interest expense and maturity profile, all to be balanced with maintaining adequate liquidity.  We have a universal shelf registration statement that does not place any dollar limits on the amount of debt and equity securities that we may issue thereunder and a traditional shelf registration statement on file with the SEC that allows us to issue up to an aggregate of $1 billion in equity securities. From time to time, we enter into equity distribution agreements in connection with our ATM offering program pursuant to which we may issue and sell LP Units registered under our traditional shelf registration statement. All issuances of equity securities under the Equity Distribution Agreement in 2017 were issued pursuant to a traditional shelf registration statement that expired, along with the Equity Distribution Agreement, on January 15, 2018. We filed a new traditional shelf registration statement with the SEC, under which we had $1 billion of unsold securities available as of December 31, 2017. We intend to enter into a new equity distribution agreement in connection with our ATM offering program in 2018. 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.
 
In addition, we periodically evaluate engaging in strategic transactions as a source of capital or may consider divesting non-strategic assets where our evaluation suggests such a transaction is in the best interest of our business.

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

50


Debt
 
At December 31, 2017, we had the following debt obligations (in thousands):
6.050% Notes due January 15, 2018
$
300,000

2.650% Notes due November 15, 2018
400,000

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

Term Loan due September 30, 2019
250,000

Credit Facility due September 30, 2021
418,904

Unamortized discounts & debt issuance costs
(33,379
)
Total debt
$
4,910,525

 
At December 31, 2017, the aggregate principal amount outstanding of our various long-term debt obligations (including current maturities) was $4,943.9 million. At December 31, 2017, we were in compliance with the covenants under our Credit Facility and our $250.0 million variable-rate term loan due September 30, 2019 (the “Term Loan”). As of December 31, 2017, we have $1.1 billion of availability under our Credit Facility. For more information regarding our debt-related transactions, see Note 13 in the Notes to Consolidated Financial Statements for additional information.

In January 2018, we issued $400.0 million of Junior Notes maturing on January 22, 2078, which are redeemable at Buckeye’s option, in whole or in part, on or after January 22, 2023. The Junior Notes bear interest at a fixed rate of 6.375% per year up to, but not including, January 22, 2023. From January 22, 2023, the Junior Notes will bear interest at a floating rate based on the Three-Month LIBOR Rate plus 4.02%, reset quarterly. Total proceeds from this offering, after underwriting fees, expenses, and debt issuance costs, were $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.

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

In 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.

Equity
 
During the year ended December 31, 2017, we sold 6.2 million LP Units in aggregate under the Equity Distribution Agreement, received $345.8 million in net proceeds after deducting commissions and other related expenses. See Note 21 in the Notes to Consolidated Financial Statements for additional information.

Buckeye expects the LP Unit issuances made under the Equity Distribution Agreement in 2017 to be sufficient to fund the equity portion of its growth capital projects in the near term.
 

51


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,
 
2017
 
2016
 
2015
Cash provided by (used in):
 

 
 

 
 

Operating activities
$
888,402

 
$
717,917

 
$
710,192

Investing activities
(1,809,988
)
 
(481,702
)
 
(614,894
)
Financing activities
283,426

 
399,244

 
(98,625
)
 
            Operating Activities
 
                        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 derivatives assets.
 
                        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 a $162.3 million increase in inventory, primarily driven by an increase in commodity prices.
 
                        2015.  Net cash provided by operating activities was $710.2 million for the year ended December 31, 2015, primarily related to $437.5 million of net income, $221.3 million of depreciation and amortization, a $56.8 million decrease in working capital, $29.2 million of non-cash unit-based compensation expense and $12.2 million of amortization of losses on terminated interest rate swaps, which were partially offset by $52.8 million in litigation settlement payments.

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
 
                        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 terminalling facility, which were partially offset by $19.9 million in refunded escrow deposits.

                        2015.  Net cash used in investing activities of $614.9 million for the year ended December 31, 2015 primarily related to $594.5 million of capital expenditures and $21.4 million in escrow deposits, which were partially offset by $10.3 million of proceeds from the sale and disposition of assets, primarily due to the disposition of an ammonia pipeline in Texas.

                        See below for a discussion of capital spending.  For further discussion on our acquisitions, see Note 3 in the Notes to Consolidated Financial Statements.
 

52


                        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,
 
2017
 
2016
 
2015
Maintenance capital expenditures (1)
$
144,046

 
$
129,691

 
$
99,617

Expansion and cost reduction
289,289

 
356,625

 
494,903

Total capital expenditures(2)
$
433,335

 
$
486,316

 
$
594,520

_____________________________
(1)
Includes maintenance capital expenditures of $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, 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 $436.9 million, $457.4 million and $616.1 million for the years ended December 31, 2017, 2016 and 2015, respectively.
 
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.

Total capital expenditures decreased for the year ended December 31, 2016, as compared to the corresponding period in 2015 primarily due to decreases in expansion and cost reduction capital expenditures. Our expansion and cost reduction capital expenditures were $356.6 million for the year ended December 31, 2016, which is a decrease of $138.3 million, or 27.9%, from $494.9 million for the corresponding period in 2015. Year-to-year fluctuations in our expansion and cost reduction capital expenditures were primarily driven by the completion of major organic growth capital projects associated with the initial build- out of our facilities at Buckeye Texas, including the significant completion of a deep-water marine terminal, two condensate splitters, an LPG storage complex and three crude oil and condensate gathering facilities in 2015. Our most significant organic growth capital expenditures for the year ended December 31, 2016 included cost reduction and revenue generating projects related to enhancements across our portfolio of terminalling assets, butane blending capabilities, completion of rail unloading facilities, crude oil storage/transportation/processing and a pipeline integrity enhancement program that improved the operational efficiencies in our pipeline systems. Our maintenance capital expenditures were $129.7 million for the year ended December 31, 2016, which is an increase of $30.1 million, or 30.2%, from $99.6 million for the corresponding period in 2015. 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, 2016 included tank integrity work necessary to maintain operating capacity, replacements at our BBH facility as a result of Hurricane Matthew, marine dock structure improvements and upgrades to station and terminalling equipment.

 

53


We estimate our capital expenditures for the period indicated as follows (in thousands):
 
2018
 
Low
 
High
Domestic Pipelines & Terminals:
 

 
 

Maintenance capital expenditures
$
70,000

 
$
80,000

Expansion and cost reduction
219,000

 
249,000

Total capital expenditures
$
289,000

 
$
329,000

 
 
 
 
Global Marine Terminals:
 

 
 

Maintenance capital expenditures
$
40,000

 
$
50,000

Expansion and cost reduction
56,000

 
76,000

Total capital expenditures (1)
$
96,000

 
$
126,000

 
 
 
 
Overall:
 

 
 

Maintenance capital expenditures
$
110,000

 
$
130,000

Expansion and cost reduction
275,000

 
325,000

Total capital expenditures
$
385,000

 
$
455,000

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

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

Financing Activities
 
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.
 
2015.  Net cash flows used in financing activities of $98.6 million for the year ended December 31, 2015 primarily related to $591.0 million of cash distributions paid to unitholders ($4.625 per LP Unit), partially offset by $306.5 million of net borrowings under the Credit Facility and $161.5 million of net proceeds from the issuance of 2.2 million LP Units under equity distribution agreements in connection with our ATM offering program.
 
For further discussion on our equity offerings, see Note 21 in the Notes to Consolidated Financial Statements.
 

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Contractual Obligations
 
The following table summarizes our contractual obligations as of December 31, 2017 (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)
$
4,691,700

 
700,000

 
525,000

 
816,700

 
2,650,000

Interest payments (2)
2,007,926

 
201,244

 
355,772

 
280,682

 
1,170,228

Operating leases:
 

 
 
 
 
 
 
 
 
Office space and other
14,781

 
3,031

 
5,708

 
3,182

 
2,860

Equipment (3)
85,042

 
11,133

 
18,078

 
18,911

 
36,920

Land leases (4)
99,863

 
2,659

 
5,318

 
5,318

 
86,568

Purchase obligations (5)
167,379

 
167,379

 

 

 

Total contractual obligations
$
7,066,691

 
$
1,085,446

 
$
909,876

 
$
1,124,793

 
$
3,946,576

_____________________________
(1)
Includes long-term debt portion borrowed under our Credit Facility.  See Note 13 in the Notes to Consolidated Financial Statements for additional information 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.
(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, 2018, our rights-of-way payments are expected to be $7.6 million, which include an estimated amount for annual escalation.

In addition, our obligations related to our pension and postretirement benefit plans are discussed in Note 18 in the Notes to Consolidated Financial Statements.

Employee Stock Ownership Plan
 
Services Company provides the Employee Stock Ownership Plan (“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.
 
The ESOP was frozen with respect to benefits effective March 27, 2011 (the “Freeze Date”).  No Services Company contributions have been or will be made on behalf of current participants in the ESOP on and after the Freeze Date.  Even though contributions under the ESOP are no longer being made, each eligible participant’s ESOP account will continue to be credited with its share of any stock dividends or other stock distributions associated with Services Company stock.
 
All Services Company stock has been allocated to ESOP participants.  See Note 18 in the Notes to Consolidated Financial Statements for further information.

Off-Balance Sheet Arrangements
 
At December 31, 2017 and 2016, we had no off-balance sheet debt or arrangements.


55


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 in the Notes to Consolidated Financial Statements for our significant accounting policies. The following describes significant estimates and assumptions affecting the application of these policies:
 
Basis of Presentation and Principles of Consolidation
 
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, which include Buckeye Texas, Services Company and Sabina Pipeline, on an ongoing basis to determine whether we continue to be the primary beneficiary.  Third party or affiliate ownership interests in our consolidated VIEs are presented as noncontrolling interests.  All intercompany transactions are eliminated in consolidation.

Business Combinations and Investments
 
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. 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. With respect to equity method investments, we make similar determinations in relation to any basis difference between our investment and our interest in the underlying net assets of the investee.
 
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.
 
For our annual goodwill impairment evaluations as of October 31, 2017, we performed qualitative assessments 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 qualitative assessment, if we determine the fair value of a reporting unit is more likely than not to be less than its carrying amount, we are required to perform a quantitative test in which the fair value of a reporting unit will be compared with its carrying amount. If the reporting unit’s carrying value exceeds its fair value, an impairment charge will be recognized to the extent that the carrying value of goodwill exceeds its fair value. Based on our qualitative assessment, we determined that it is not more likely than not that the fair value of each reporting unit is lower than its carrying value; therefore, the quantitative impairment test was not required. We did not recognize any goodwill impairment during the years ended December 31, 2017, 2016 or 2015.
 

56


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 discounted 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.

In December 2013, the Board of Directors approved a plan to divest the natural gas storage facility and related assets that our former subsidiary, Lodi, owned and operated in Northern California.  We refer to this group of assets as our Natural Gas Storage disposal group.  In July 2014, we signed a purchase and sale agreement to sell our Natural Gas Storage disposal group and completed the sale in December 2014.  See Note 4 in the Notes to Consolidated Financial Statements for further discussion.
 
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.  There were no impairments of our equity investments during the years ended December 31, 2017, 2016 or 2015.
 
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.
 
Valuation of Derivatives
 
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 these risks.
 
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.

Futures contracts are valued using quoted market prices obtained from the NYMEX. Physical derivative contracts are valued 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, and are net of credit value adjustments (“CVAs”).


57


The fixed-price and index purchase contracts are typically executed with credit worthy counterparties and are short-term in nature, thus evaluated for credit risk in the same manner as the fixed-price sales contracts.  However, because the fixed-price sales contracts are privately negotiated with customers of the Merchant Services segment who are generally smaller, private companies that may not have established credit ratings, the determination of an adjustment to fair value to reflect counterparty credit risk (a “credit valuation adjustment”) requires management judgment.
 
Each customer is evaluated for performance under the terms and conditions of their contracts; therefore, we evaluate: (i) the historical payment patterns of the customer; (ii) the current outstanding receivables balances for each customer and contract; and (iii) the level of performance of each customer with respect to volumes called for in the contract.  We then evaluated the specific risks and expected outcomes of nonpayment or nonperformance by each customer and contract.  We continue to monitor and evaluate performance and collections with respect to these fixed-price contracts.

Additionally, we utilize forward-starting interest rate swaps to manage interest rate risk related to forecasted interest payments on anticipated debt issuances. 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 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. The fair value of the swap instruments are calculated by discounting the future cash flows of both the fixed rate and variable rate interest payments using appropriate discount rates with consideration given to our non-performance risk.

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.

58


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, 2017
$
(28,801
)
 
$
62,609

 
$
33,808

Cash settlements during the period
34,964

 
(20,018
)
 
14,946

Change in fair value attributable to new deals during the period
1,318

 

 
1,318

Change in fair value attributable to existing deals at January 1st
(11,688
)
 
(10,597
)
 
(22,285
)
Fair value of contracts outstanding at December 31, 2017
$
(4,207
)
 
$
31,994

 
$
27,787

  
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, 2017, 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
 
$
240,658

Fair value assuming 10% increase in underlying commodity prices
 
Asset
 
$
253,628

Fair value assuming 10% decrease in underlying commodity prices
 
Asset
 
$
227,688


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.  In addition, in August 2016, the Board authorized us to enter into forward-starting interest rate swaps to manage our interest rate and cash flow risks related to certain expected debt issuances associated with the maturity of existing debt obligations. Based on a hypothetical 10% movement in the underlying interest rates at December 31, 2017, the estimated fair value of the interest rate derivative contracts would be as follows (in thousands):
Scenario
 
Resulting
Classification
 
Fair Value
Fair value assuming no change in underlying interest rates (as is)
 
Asset
 
$
31,994

Fair value assuming 10% increase in underlying interest rates
 
Asset
 
$
28,795

Fair value assuming 10% decrease in underlying interest rates
 
Asset
 
$
35,193


See Note 16 in the Notes to Consolidated Financial Statements for additional discussion related to derivative instruments and hedging activities.

59


 
At December 31, 2017, we had total fixed-rate debt obligations under various public notes at an aggregate carrying value of $4.2 billion.  Based on a hypothetical 1% movement in the underlying interest rates at December 31, 2017, 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)
 
$
4,420

Fair value assuming 1% increase in underlying interest rates
 
$
4,170

Fair value assuming 1% decrease in underlying interest rates
 
$
4,704

 
At December 31, 2017, our variable-rate obligations were $668.9 million. Based on the balance outstanding at December 31, 2017, we estimate that a 1% increase or decrease in underlying interest rates would increase or decrease annual interest expense by $6.7 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 income (expense)” within our consolidated statements of operations.  The effects of foreign currency transactions were not considered to be material for the years ended December 31, 2017, 2016 and 2015.

Our equity method investment in VTTI indirectly exposes us to foreign currency risk, primarily with respect to the Euro, Malaysian Ringgit and United Arab Emirates Dirham. VTTI manages its exposure to foreign currency risk with foreign exchange hedging strategies. Our proportionate share of VTTI’s foreign currency transaction, hedging and translation gains and losses is included in our earnings from equity investments and accumulated other comprehensive income, as applicable. We recognized our proportionate share of $49.6 million of VTTI’s other comprehensive income, primarily comprised of foreign currency translation adjustments in other comprehensive income for the year ended December 31, 2017.


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Item 8. Financial Statements and Supplementary Data
 
 
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