2016 ANNUAL REPORT
EXPANDED
GLOBAL
PRESENCE
ABOUT US
BUCKEYE PARTNERS, L.P. (NYSE: BPL) is a publicly traded
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of integrated assets providing midstream logistic solutions, primarily
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petroleum products.
ORGANIZATIONAL OVERVIEW
DOMESTIC PIPELINES & TERMINALS
~6,000 miles of pipeline with ~110 delivery locations
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Primarily demand-pull system; limiting impact of supply disruptions
Operates and/or maintains third-party pipelines and performs certain engineering and construction management
services for its customers
GLOBAL MARINE TERMINALS
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MERCHANT SERVICES
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Vessel dock at the Buckeye Perth Amboy
facility in New Jersey
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I AM PLEASED TO REPORT THAT 2016
WAS AN EXCEPTIONAL YEAR for Buckeye and
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Safely Through the Storm
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communities in which we operate. Our employees were able to demonstrate
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aftermath of the storm were nothing short of outstanding.
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operations were secure and that our facilities were fully prepared for its impact.
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Clark C. Smith
Chairman, President and
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Rail unloading rack at the Buckeye
Port Reading facility in New Jersey
2 0 1 6 A N N U A L R E P O R T 1
demonstrated that this advanced preparation allows us to withstand incidents with minimal impact. Most
importantly, we are happy and thankful to report that all of our employees and their families in Matthew’s
path survived the storm with no injuries.
Financial and Operational Excellence
2016 was an outstanding year for Buckeye as we grew Adjusted EBITDA1 by almost 20 percent to a record
$1.03 billion. This strong performance allowed us to continue to grow distributions to our unitholders
as we declared distributions of $4.875 for the year, representing over four percent growth from the prior year.
All three of our business segments contributed to this record performance. Our Domestic Pipelines &
Terminals segment has grown consistently through the contribution from numerous capital projects that our
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from strong storage demand driving higher utilization and storage rates as well as new capital projects that
brought storage capacity back in service. In addition, we completed the build out and are now operating all
2016 WAS AN OUTSTANDING
YEAR FOR BUCKEYE AS
WE GREW ADJUSTED
EBITDA BY ALMOST 20
PERCENT TO A RECORD
$1.03 BILLION.
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management and favorable business conditions. This segment
also contributed a record level of revenues to the Buckeye
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pipeline and terminal assets.
Business Strategy for Growth and Diversification
Buckeye has continually emphasized our goal of diversifying
our business across new products and services as well
as new geographic locations. We have achieved great success
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our portfolio of domestic terminals. We also entered into the marine terminal business while meeting our
objective of increasing our geographic scale by acquiring terminals in the Caribbean, Corpus Christi, and
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this strategy, minimizing investment risk where possible with long-term contracts. We managed our balance
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this strategy in 2010. At the same time, we have also improved our coverage and strengthened our
balance sheet, maintaining our investment grade credit rating while continuing to grow distributions to our
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the past 18 to 24 months.
2 B U C K E Y E P A R T N E R S , L . P.
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that improve coverage and strengthen our balance sheet.
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continue to contribute to our success.
Investing Globally
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of crude and petroleum products.
VTTI terminal located in Johor, Malaysia
near the Port of Singapore
2 0 1 6 A N N U A L R E P O R T 3
Capitalizing on Opportunities
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Midwestern supply sources eastward to the Pittsburgh and other Western Pennsylvania markets. This
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continue to ramp up in early 2017 with the full run-rate contribution being achieved in the second quarter.
We also announced the successful completion of an open season for the second phase of this project. The
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approval and permitting process for this project, which we currently plan to complete in late 2018.
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terminals. We also increased our butane blending and vapor recovery capabilities and completed a number
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us in 2017 and beyond.
Opportunity Set Remains Vast
As we look forward to 2017, we continue to see numerous opportunities as well as business challenges
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among our New York Harbor terminals. We are assessing further opportunities to invest in our Chicago
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and development teams are making on these very important initiatives.
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to continue to deliver outstanding results.
Clark C. Smith
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1(cid:58)(cid:76)(cid:76)(cid:3)(cid:75)(cid:76)(cid:196)(cid:85)(cid:80)(cid:91)(cid:80)(cid:86)(cid:85)(cid:3)(cid:86)(cid:77)(cid:3)(cid:53)(cid:86)(cid:85)(cid:20)(cid:46)(cid:40)(cid:40)(cid:55)(cid:3)(cid:84)(cid:76)(cid:72)(cid:90)(cid:92)(cid:89)(cid:76)(cid:90)(cid:3)(cid:72)(cid:85)(cid:75)(cid:3)(cid:89)(cid:76)(cid:74)(cid:86)(cid:85)(cid:74)(cid:80)(cid:83)(cid:80)(cid:72)(cid:91)(cid:80)(cid:86)(cid:85)(cid:90)(cid:3)(cid:91)(cid:86)(cid:3)(cid:53)(cid:86)(cid:85)(cid:20)(cid:46)(cid:40)(cid:40)(cid:55)(cid:3)(cid:84)(cid:76)(cid:72)(cid:90)(cid:92)(cid:89)(cid:76)(cid:90)(cid:3)(cid:72)(cid:91)(cid:3)(cid:91)(cid:79)(cid:76)(cid:3)(cid:76)(cid:85)(cid:75)(cid:3)(cid:86)(cid:77)(cid:3)(cid:91)(cid:79)(cid:80)(cid:90)(cid:3)(cid:89)(cid:76)(cid:87)(cid:86)(cid:89)(cid:91)(cid:21)
4 B U C K E Y E P A R T N E R S , L . P.
2016
FORM 10-K
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
______________________________________________________
(Mark One)
FORM 10-K
______________________________________________________
Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2016
Or
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
(State or other jurisdiction of incorporation or organization)
One Greenway Plaza
Suite 600
Houston, TX
(Address of principal executive offices)
23-2432497
(IRS Employer Identification number)
77046
(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
Limited partner units representing limited partnership interests
Name of each exchange on which registered
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
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
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
No
No
No
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
No
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.
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
Accelerated filer
Non-accelerated filer
Smaller reporting company
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes
At June 30, 2016, the aggregate market value of the registrant’s limited partner units held by non-affiliates was $9.1 billion. The
No
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 17, 2017, there were 140,462,347 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 2017 Annual Meeting of
Limited Partners are incorporated by reference in Part III of this Form 10-K.
TABLE OF CONTENTS
PART I
Item 1.
Business ........................................................................................................................................................
Item 1A. Risk Factors..................................................................................................................................................
Item 1B. Unresolved Staff Comments.........................................................................................................................
Properties......................................................................................................................................................
Item 2.
Legal Proceedings ........................................................................................................................................
Mine Safety Disclosures...............................................................................................................................
Item 4.
Item 3.
PART II
Item 6.
Item 5.
Market for the Registrant’s LP Units, Related Unitholder Matters, and Issuer Purchases of LP Units..
Selected Financial Data ...............................................................................................................................
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations ..................
Item 7A. Quantitative and Qualitative Disclosures About Market Risk....................................................................
Financial Statements and Supplementary Data .........................................................................................
Item 8.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure .................
Item 9A. Controls and Procedures..............................................................................................................................
Item 9B. Other Information ........................................................................................................................................
PART III
Item 10. Directors, Executive Officers and Corporate Governance .........................................................................
Executive Compensation..............................................................................................................................
Item 11.
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters .
Certain Relationships and Related Transactions and Director Independence..........................................
Principal Accounting Fees and Services.....................................................................................................
Item 14.
Item 12.
Item 13.
Page
1
17
32
33
33
33
34
36
37
54
57
115
115
115
116
116
116
116
116
Item 15.
Exhibits, Financial Statement Schedules....................................................................................................
116
PART IV
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; (x) our
ability to realize the expected benefits of our investment in VTTI; and (xi) 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.
Item 1. Business
Introduction
PART I
The original Buckeye Pipe Line Company was founded in 1886 as part of the Standard Oil Company (“Standard Oil”) and
became a publicly owned, independent company after the dissolution of Standard Oil in 1911. Expansion into petroleum
products transportation after World War II and subsequent acquisitions thereafter ultimately led to Buckeye Pipe Line Company
becoming a leading independent common carrier pipeline. In 1964, Buckeye Pipe Line Company was acquired by a subsidiary
of the Pennsylvania Railroad, which later became the Penn Central Corporation. In 1986, Buckeye Pipe Line Company was
reorganized into a master limited partnership (“MLP”), Buckeye Partners, L.P. We are a publicly traded Delaware master
limited partnership, and our limited partnership units representing limited partner interests (“LP Units”) are listed on the New
York Stock Exchange (“NYSE”) under the ticker symbol “BPL.” Buckeye GP LLC (“Buckeye GP”) is our general partner.
Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” or “Buckeye” are intended to mean the
business and operations of Buckeye Partners, L.P. and its consolidated subsidiaries.
We own and operate a diversified 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. Additionally, we are one of the largest independent terminalling and storage
operators in the United States in terms of capacity available for service. Our terminal network comprises more than 120 liquid
petroleum products terminals with aggregate storage capacity of over 115 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
and in the Caribbean. Our 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”), formerly known as Bahamas Oil Refining Company International Limited (“BORCO”), is one of the largest marine
crude oil and refined petroleum products storage facilities in the world and provides an array of logistics and blending services
for 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. Our recent acquisition of an indirect 50% equity
interest in VTTI B.V. (“VTTI”) expands our international presence with premier storage and marine terminalling services for
petroleum products predominantly located in key global energy hubs, including Northwest Europe, the United Arab Emirates
and Singapore. We are also a wholesale distributor of refined petroleum products in 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 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;
•
• Leverage existing management capabilities and infrastructure;
Provide geographic, product and/or asset class diversity; and
•
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
VTTI Acquisition
In January 2017, we acquired an indirect 50% equity interest in VTTI for cash consideration of $1.15 billion (the “VTTI
Acquisition”). VTTI will be owned jointly with Vitol S.A. (“Vitol”). VTTI is one of the largest independent global marine
terminal businesses that, through its subsidiaries and partnership interests, owns and operates approximately 57 million
barrels of petroleum products storage across 14 terminals located on five continents. These marine terminals are predominately
located in key global energy hubs, including Northwest Europe, the United Arab Emirates and Singapore, and offer world-class
storage and marine terminalling services for refined petroleum products, liquid petroleum gas and crude oil. We and VIP
Terminals Finance B.V., a subsidiary of Vitol, have equal board representation and voting rights in the VTTI joint venture.
Hurricane Matthew
In October 2016, Hurricane Matthew made landfall in the Bahamas and the southeastern United States. Our domestic
operations experienced no property damage or product releases as a result of the storm. Our BBH terminalling facility, which is
located along the Northwest Providence Channel of Grand Bahama Island, experienced property damage but no material
interruption of services or product releases. During 2016, we incurred operating expenses of $11.0 million and maintenance
capital expenditures of $6.1 million and recorded a $5.8 million write-off of damaged long-lived assets as a result of the storm.
We estimate the range of total costs expected to be incurred as a result of Hurricane Matthew to be between $20 million to
$30 million, comprised of both operating and capital expenditures, including the amounts incurred to-date. We intend to seek
recovery from our insurers for property damage incurred above our self-insured retentions; however, no assurances can be
given relative to the timing or amount of such recoveries.
Equity Offering
In October 2016, we completed a public offering of 7.75 million LP Units pursuant to an effective shelf registration
statement, which priced at $66.05 per unit. The underwriters also exercised an option to purchase 1.16 million additional
LP Units, resulting in total gross proceeds of $588.7 million before deducting underwriting fees and other related expenses of
$8.0 million. We used the net proceeds from the offering to initially reduce the indebtedness outstanding under our existing
$1.5 billion revolving Credit Facility with SunTrust Bank (the “Credit Facility”) and for general partnership purposes, as well
as to subsequently fund a portion of the purchase price for the VTTI Acquisition in January 2017.
Notes Offering
In November 2016, we issued $600.0 million of senior unsecured 3.950% notes maturing on December 1, 2026 (the
“3.950% Notes”) in an underwritten public offering at 99.644% of their principal amount. Total proceeds from this offering,
after underwriting fees, expenses and debt issuance costs of $5.2 million, were $592.7 million. In January 2017, we used the
net proceeds from this offering to fund a portion of the purchase price for the VTTI Acquisition.
2
Credit Facility
In September 2016, Buckeye and its indirect wholly-owned subsidiaries, Buckeye Energy Services LLC (“BES”), Buckeye
West Indies Holdings LP (“BWI”) and Buckeye Caribbean Terminals LLC (“BCT”), collectively the Buckeye Merchant
Service Companies (“BMSC”), as borrowers, exercised their remaining option with consenting lenders to extend $1.4 billion of
our Credit Facility by one year to September 30, 2021. At the time of the transaction, we had $3.4 million of remaining
unamortized deferred financing costs, and we incurred additional debt issuance costs of $0.7 million in connection with the
extension of the Credit Facility. At December 31, 2016, Buckeye and BMSC collectively had no outstanding balance under the
Credit Facility.
Term Loan
In September 2016, we entered into a credit agreement with SunTrust Bank, as administrative agent, and other lenders for a
$250.0 million variable-rate term loan due September 30, 2019 (the “Term Loan”), with an option to extend the term with
consenting lenders for up to two one-year periods. We incurred debt issuance costs of $0.5 million related to the Term Loan.
We used the proceeds from the Term Loan to reduce the indebtedness outstanding under our Credit Facility.
At-the-Market Offering Program
In March 2016, we entered into an equity distribution agreement (the “Equity Distribution Agreement”) with J.P. Morgan
Securities LLC, BB&T Capital Markets, a division of BB&T Securities, LLC, BNP Paribas Securities Corp., Deutsche Bank
Securities Inc., Jefferies LLC, Morgan Stanley & Co. LLC, RBC Capital Markets, LLC, and SMBC Nikko Securities
America, Inc. (collectively, the “ATM Underwriters”). Under the terms of the Equity Distribution Agreement, we may offer
and sell up to $500.0 million in aggregate gross sales proceeds of LP Units from time to time through the ATM Underwriters,
acting as agents of Buckeye or as principals, subject in each case to the terms and conditions set forth in the Equity Distribution
Agreement. This agreement replaced our prior four separate equity distribution agreements with each of Wells Fargo
Securities, LLC, Barclays Capital Inc., SunTrust Robinson Humphrey, Inc. and UBS Securities LLC, which we entered into in
May 2013 and, under the terms of which, we could sell up to $300.0 million in aggregate gross sales proceeds of LP Units from
time to time.
During the year ended December 31, 2016, we sold 1.6 million LP Units in aggregate under the Equity Distribution
Agreement and received $108.4 million in net proceeds after deducting commissions and other related expenses, including
$1.1 million of compensation paid in aggregate to the agents under the Equity Distribution Agreement.
3
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 operations and assets are conducted and 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. Detailed financial information
regarding revenue, profits and total assets of each segment and major geographic area can be found in Note 25 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):
2016
2015
2014
Revenue
Percent
Revenue
Percent
Revenue
Percent
Year Ended December 31,
Domestic Pipelines & Terminals.... $ 1,011,696
Global Marine Terminals................
671,465
1,621,915
Merchant Services (1) ....................
(56,700)
Intersegment ...................................
Total ............................................. $ 3,248,376
966,749
31.1 % $
20.7 %
514,301
49.9 % 2,037,664
(65,280)
(1.7)%
100.0 % $ 3,453,434
938,036
28.0 % $
14.9 %
395,306
59.0 % 5,358,626
(71,721)
(1.9)%
100.0 % $ 6,620,247
14.2 %
6.0 %
80.9 %
(1.1)%
100.0 %
____________________________________
(1) The decrease in revenue for the years ended December 31, 2016 and 2015 compared to the year ended December 31, 2014
was primarily related to a decrease in sales volume and a decline of refined petroleum products prices. The decrease in
sales volume was primarily related to more effective inventory management. 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 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 liquid petroleum products, including gasoline, jet fuel, diesel fuel, heating oil and kerosene, from major
supply sources to terminals and airports located within end-use markets. The pipelines within this segment also transport other
refined petroleum products, such as propane and butane, refinery feedstock and blending components, as well as crude oil. 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 storage capacity of over 55 million barrels. In addition,
three of our terminals provide crude oil services, including train loading/unloading, storage and throughput. 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. In addition, our pipelines generally operate as a common carrier, providing transportation services at
posted tariffs and without long-term contracts. 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.
4
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):
2016
2015
2014
Year Ended December 31,
Pipelines:
Gasoline ..................................
Jet fuel .....................................
Middle distillates (1) ...............
Other products (2) ...................
Total pipelines throughput.........
759.6
361.1
289.4
16.9
1,427.0
53.2%
25.3%
20.3%
1.2%
100.0%
735.9
358.9
337.4
28.5
1,460.7
50.4%
24.5%
23.1%
2.0%
100.0%
702.8
336.0
354.9
36.6
1,430.3
49.1%
23.5%
24.8%
2.6%
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, including one refinery, six connecting
pipelines and nine storage and terminalling facilities. Products are then transported through two lines from Linden, New Jersey
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 (serving Reading, Harrisburg,
Altoona/Johnstown, Greensburg and Pittsburgh, Pennsylvania) and north through eastern Pennsylvania into New York (serving
Scranton/Wilkes-Barre, Pennsylvania and Binghamton, Syracuse, Utica, Rochester and, via a connecting carrier, Buffalo, 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 through one line to Newark Airport and through two
additional lines to JFK Airport and LaGuardia Airport and to commercial liquid petroleum products terminals at Long Island
City and Inwood, New York. These pipelines supply JFK Airport, LaGuardia Airport and Newark Airport with substantially all
of each airport’s jet fuel requirements.
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 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 Reading,
Harrisburg, Altoona/Johnstown, Greensburg and Pittsburgh, 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.
5
Other Liquid Petroleum Products Pipelines. BPLC serves Connecticut and Massachusetts through an approximately
100-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. Everglades supplies Miami International Airport with substantially all of its jet fuel requirements.
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 16-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. Buckeye Reno, Buckeye San Diego and Buckeye Memphis were originally created as joint
ventures between BPH and Kealine LLC, but in April 2015, BPH purchased the remaining 10% ownership interest in Buckeye
Memphis from Kealine LLC, increasing our ownership interest in Buckeye Memphis to 100%. As such, BPH currently owns
100% of Buckeye Reno, Buckeye San Diego and Buckeye Memphis. Each of these entities is consolidated into our financial
statements.
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 railroads, 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 that include the
injection of various additives. Typically, the Domestic Pipelines & Terminals segment’s terminalling facilities consist of
multiple storage tanks and are equipped with automated truck loading equipment that is 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 emitted during truck loading. Finally, the terminals derive service fees
and blending margins from butane blending activities during the winter months (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 in earnings. These derivative instruments consist primarily of futures contracts traded 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):
Products throughput (1) ..................................................................................
1,238.4
2016
2015
1,215.4
2014
1,147.5
____________________________
(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.
Year Ended December 31,
6
The following table sets forth the number of terminals and storage capacity in barrels by location for terminals reported in
the Domestic Pipelines & Terminals segment (barrels in thousands):
Location
Alabama......................................................................................................................................
California ....................................................................................................................................
Connecticut .................................................................................................................................
Florida.........................................................................................................................................
Iowa ............................................................................................................................................
Illinois .........................................................................................................................................
Indiana ........................................................................................................................................
Kentucky.....................................................................................................................................
Louisiana.....................................................................................................................................
Maine ..........................................................................................................................................
Maryland.....................................................................................................................................
Massachusetts .............................................................................................................................
Michigan .....................................................................................................................................
Missouri ......................................................................................................................................
Nevada ........................................................................................................................................
New Jersey..................................................................................................................................
New York....................................................................................................................................
North Carolina ............................................................................................................................
Ohio ............................................................................................................................................
Pennsylvania ...............................................................................................................................
South Carolina ............................................................................................................................
Tennessee....................................................................................................................................
Virginia .......................................................................................................................................
Wisconsin....................................................................................................................................
Total .......................................................................................................................................
Number of
Terminals (1)
Storage
Capacity (2)
2
3
2
4
5
8
11
1
1
1
1
2
14
3
1
3
16
1
13
10
4
1
4
4
115
605
530
1,212
1,951
1,302
2,977
9,439
214
304
140
3,232
433
5,467
1,767
50
4,903
8,450
572
3,861
3,027
2,191
328
1,805
1,228
55,988
____________________________
(1) This table includes three terminals in Pennsylvania with aggregate storage capacity of approximately 1 million barrels,
which are owned by the Merchant Services segment and operated by the Domestic Pipelines & Terminals segment (as
discussed below).
(2) This table includes approximately 19.5 million barrels of storage capacity with the remaining capacity 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.
Equity Investments
We own a 34.6% equity interest in West Shore Pipe Line Company (“West Shore”). West Shore owns an approximately
610-mile pipeline system that originates in the Chicago, Illinois area and extends north to Green Bay, Wisconsin and west and
then north to Madison, Wisconsin. The pipeline system transports refined petroleum and crude oil 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.
7
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.
Global Marine Terminals Segment
The Global Marine Terminals segment provides marine accessible bulk storage and blending services, rail and truck rack
loading/unloading, along with petroleum processing services in the East Coast and Gulf Coast regions of the United States and
in the Caribbean. The segment has seven liquid petroleum product terminals located in The Bahamas, Puerto Rico and St.
Lucia in the Caribbean and the New York Harbor and Corpus Christi, Texas in the United States.
The following table sets forth terminal locations and storage capacity in barrels for terminals reported in the Global Marine
Terminals segment (barrels in thousands):
Location
The Bahamas ..............................................................................................................................
Puerto Rico .................................................................................................................................
New York Harbor........................................................................................................................
St. Lucia......................................................................................................................................
Texas (2) .....................................................................................................................................
Total..........................................................................................................................................
Number of
Terminals
Storage
Capacity (1)
1
1
3
1
1
7
26,113
4,106
15,100
10,261
6,668
62,248
_____________________________
(1) This table represents total storage capacity as of December 31, 2016, of which approximately 6.0 million barrels are
unavailable for contracting to third parties due to being out of service for maintenance, capital enhancements or used for
internal purposes.
(2) This represents the terminalling facility owned by Buckeye Texas, which is 80% owned by us.
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 provided by BBH 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.
Yabucoa Terminal
The Yabucoa terminal sits on approximately 250 acres in the southeast of Puerto Rico and includes 40 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.
8
New York Harbor Terminals
The New York Harbor storage and marine terminals, which consist of our Perth Amboy, Port Reading and Raritan Bay
terminals, have the ability to provide a link between our inland pipelines and terminals 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.
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 storage capacity, has 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 the 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.
Corpus Christi Facilities
In September 2014, we acquired an 80% interest in Buckeye Texas, which 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.
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 third parties 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.
9
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):
Sales volumes..................................................................................................
1,179.7
2016
2015
1,215.0
2014
2,009.0
Year Ended December 31,
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.
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 Notes 4 and 5 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 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.
10
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.
The Domestic Pipelines & Terminals segment competes with marine transportation in some areas. Tankers and barges on
the Great Lakes account for some of the volume to certain Michigan, Ohio and upstate New York locations during the
approximately eight non-winter months of the year. Barges are presently a competitive factor for deliveries to and within the
New York City area, the Pittsburgh area and locations on the Ohio River, such as Cincinnati, Ohio and locations on the
Mississippi River, such as St. Louis, Missouri. Additionally, the South Portland and Bangor, Maine terminals, and the pipeline
connecting these terminals, compete with regional barge-supplied terminals.
Trucks competitively deliver liquid petroleum products in a number of areas that the Domestic Pipelines & Terminals
segment serves. While their costs may not be competitive for longer hauls or large volume shipments, trucks compete
effectively for smaller volumes in many local areas. The availability of truck transportation places a significant competitive
constraint on the ability of the Domestic Pipelines & Terminals segment to increase its tariff rates.
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 that has accelerated in recent years has altered 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. In particular, railroads competitively deliver biofuels to a
number of areas and, therefore, are a significant competitor of pipelines with respect to biofuels. 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.
Distribution of liquid petroleum products depends to a large extent upon the location and capacity of refineries. Because
the Domestic Pipelines & Terminals segment’s business is largely driven by the consumption of fuel in its delivery areas and
the Domestic Pipelines & Terminals segment’s pipelines have numerous source points, generally we do not believe that the
expansion or shutdown of any particular refinery is likely, in most instances, to have a material effect on the business of the
Domestic Pipelines & Terminals segment. As discussed in “Item 1A, Risk Factors”, however, a significant decline in
production at the Wood River refinery, Paulsboro refinery or Lima refinery, or a fundamental change in the primary sources or
supply of petroleum products to a region, could materially impact the business of the Domestic Pipelines & Terminals segment.
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.
We also compete with independent pipeline companies, engineering firms, major integrated oil and gas companies and
chemical companies to operate and maintain logistic assets for third-party owners. In addition, in some instances it can be
either more cost-effective or strategic for certain companies to operate and maintain their own pipelines as opposed to
contracting with the Domestic Pipelines & Terminals segment for such services. Numerous engineering and construction firms
compete with the Domestic Pipelines & Terminals segment for construction management business.
11
Global Marine Terminals Segment
Our Global Marine Terminals segment primarily competes with other marine terminals in the Caribbean, New York Harbor
and the Gulf Coast. Our terminalling facilities on Grand Bahama Island, The Bahamas and St. Lucia face competition from
multiple proprietary or third-party terminal operators located elsewhere in the Caribbean region. However, the geographical
locations, deep drafts, storage capacity and ancillary service capabilities of our facilities provide certain advantages to our
customers for handling and storing products for export to other locations within the Caribbean, North and South America,
Europe, and Asia. Internal transfer pricing of certain regional facilities and discounted incentive storage and handling rates at
independent third-party facilities supported by quasi national oil companies adds competition for handling of remaining product
demand in certain areas.
Our facility in Yabucoa, Puerto Rico faces competition for residual fuel oil storage as a result of the method by which the
local utility company, a significant fuel oil user, sources fuel for their power generation needs. Additionally, competition exists
for clean products storage and throughput because of other third-party terminals on the island that have geographical
advantages over the Yabucoa facility.
Our Perth Amboy, Port Reading, and Raritan Bay facilities, located in the New York Harbor, generally compete with
pipelines and terminals owned by major oil and gas companies and major pipeline and terminal operators in the same
geographic market as our Domestic Pipelines & Terminals segment (as discussed above).
Our Corpus Christi facility, owned by Buckeye Texas, does not currently compete for customers, as it is almost fully
contracted to one customer under long-term take-or-pay arrangements.
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, 2016, 2015 and 2014, no customer contributed 10% or more of our consolidated
revenue. In the Global Marine Terminals segment, storage revenue represented approximately 82% of BBH’s total revenue for
the year ended December 31, 2016, which accounted for approximately 29% of total revenue in the segment. 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, 2016, approximately 31% and 60% 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.
Revenue from Buckeye Texas, which is almost fully contracted to one customer under long-term take-or-pay arrangements,
accounted for approximately 33% of total revenue in the Global Marine Terminals segment for the year ended December 31,
2016.
Seasonality
The Domestic Pipelines & Terminals segment’s mix and volume of products transported and stored tends to vary
seasonally. Declines in demand for heating oil during the summer months are, to a certain extent, offset by increased demand
for gasoline and jet fuel. Overall, this segment’s business has been only moderately seasonal, with somewhat lower than
average volumes being transported and stored during March, April and May and somewhat higher than average volumes being
transported and stored in November, December and January.
The Merchant Services segment’s mix and volume of product sales tend to vary seasonally, with the fourth and first
quarters’ volumes generally being higher than the second and third quarters, primarily due to the increased demand for home
heating oil in the winter months.
The Domestic Pipelines & Terminals and Merchant Services segments both benefit from increased sales of heating oil and
butane blending activities at our terminals during the winter months. From mid-September through mid-March, we are able to
blend butane into various grades of gasoline.
12
The Global Marine Terminals segment’s mix and volume of products stored does not vary significantly by season.
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, 2016, Services Company had approximately 1,590 employees, approximately 310 of whom were represented
by labor unions. Additionally, at December 31, 2016, certain of our wholly owned subsidiaries had approximately 275
employees, approximately 160 of whom are employed at our BBH facility. We have never experienced any work stoppages or
other significant labor problems.
Regulation
General
We are 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 rules and regulations binding on the pipeline and
natural gas storage industries, related businesses, and individual participants. 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, Buckeye
Linden 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 the rates charged by Wood River, BPL
Transportation, Buckeye Linden and NORCO, and certain rates charged by BPLC, 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.
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.
13
Environmental Regulation
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 liabilities are inherent in pipeline, terminalling and processing operations, and we may incur material environmental
liabilities in the future. Moreover, 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.” 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.
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.
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.
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 a “hazardous substance,” 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.
The Clean Air Act, 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. EPA has promulgated greenhouse gas
(“GHG”) regulations and is otherwise increasing its scrutiny of the oil and gas industry. 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. 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.
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We are also subject to other environmental laws and regulations adopted by the various states, localities and territories in
which we operate. In certain instances, the regulatory standards adopted by the states and/or territories are more stringent than
applicable federal laws. In addition, our BBH terminal in The Bahamas and our St. Lucia terminal are subject to the
environmental regulatory programs applicable in those countries. While these regulatory programs are today less stringent than
in the United States, they have the potential to impose material liabilities on us, particularly in the event of a spill or other
release, and if they are made more stringent in the future, we could be required to make significant capital expenditures to meet
the new standards.
Pipeline and Terminal Maintenance and Safety Regulation
The pipelines we operate are subject to regulation by the U.S. Department of Transportation (“DOT”), its agency, the
Pipeline and Hazardous Materials Safety Administration (“PHMSA”), and state pipeline regulatory bodies as appropriate and
consistent with the federal Pipeline Safety Act (“PSA”). The PSA and PHMSA implementing regulations govern the design,
installation, testing, construction, operation, replacement and management of pipeline facilities and require any entity that owns
or operates pipeline facilities to comply with applicable safety standards, to establish and maintain plans for inspection and
maintenance and to comply with such plans and programs. Among others, these programs include: construction, operation and
maintenance, integrity management for pipelines located in high consequence areas, operator qualification, control room
management, public awareness, and drug and alcohol. Certain states in which we operate participate in oversight and
inspection of intrastate and interstate pipeline facilities through certifications and agreements with PHMSA. For intrastate
pipelines located in PHMSA certified states, the State may impose additional or more stringent pipeline safety regulations as
long as they are not inconsistent with minimum PHMSA standards.
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
become effective in March 2017. PHMSA issued a 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.
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 rule will continue to be subject to the regulatory freeze, or be allowed to
become effective.
We are also subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state
statutes. We believe that our operations comply in all material respects with 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.
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We are covered by site pollution incident 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 premises pollution 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, 2017.
In addition to the site pollution incident legal liability insurance policies, we maintain casualty insurance policies that
provide coverage for claims involving sudden and accidental releases with aggregate and per occurrence limits of $400 million.
Coverage under the casualty insurance is secondary to the site pollution incident legal liability policies for sudden and
accidental releases. The pollution coverage provided in the casualty insurance policies contains 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, 2017.
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 incident legal liability and casualty 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.
In 2013, we contracted 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 business would be particularly susceptible to adverse effects because we
operate without the benefit of either exclusive franchises from government entities or long-term contracts.
Strong demand for the services we provide in the Caribbean have been driven by increases in crude oil production from
Latin America, crude oil movements from South America to Asia, a forward market structure that incentivizes storage, and
Latin America demand for clean petroleum products from the United States and Europe. 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, or a
fundamental change in the primary 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, 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.
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.
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.
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.
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If a significant release or event occurred in the past at any of our acquired assets and we are responsible for all or a
significant portion of the liability associated with such release or event, it could adversely affect our business, financial
position, results of operations and cash flows. We could be liable for unknown obligations relating to any of our acquired
assets, for which indemnification or insurance is not available, which could materially adversely affect our business, financial
condition, results of operations or cash flow.
If we incorrectly predict the future results of acquired operations or assets, we may not realize all of the benefits we
expect from an acquisition. We may make dispositions on terms that are less favorable than we anticipated.
Part of our business strategy includes making acquisitions and, when appropriate, dispositions. In evaluating acquisitions
and dispositions, we prepare one or more financial cases based on a number of business, industry, economic, legal, regulatory,
and other assumptions applicable to the proposed transaction. Although we expect a reasonable basis will exist for those
assumptions, the assumptions typically involve current estimates of future conditions. Many assumptions are beyond our
control and may not materialize. Because of the uncertainty and risk of inaccuracy associated with these assumptions,
including financial projections, we may not realize the full benefits we anticipate from an acquisition, or we may encounter
unanticipated difficulties locating buyers and securing favorable terms for dispositions, each of which could materially
adversely affect our business, financial condition, results of operations or cash flow. Dispositions may also involve continued
financial involvement in the divested business, such as through continuing minority equity ownership, guarantees, indemnities
or other financial obligations. Under these arrangements, performance by the divested businesses or other conditions outside of
our control could adversely affect our future financial results.
Potential future acquisitions and organic growth projects, if any, may affect our business by substantially increasing the
level of our indebtedness and contingent liabilities and increasing the risks of our being unable to effectively complete and
integrate these new operations.
From time to time, we evaluate and acquire assets and businesses that we believe complement our existing assets and
businesses. If we consummate any future acquisitions, our capitalization and results of operations may change significantly.
We also routinely execute organic growth projects that complement our existing assets. Our decisions regarding new organic
growth projects rely on numerous estimates, including predictions of future demand for our services, future supply shifts, crude
oil and refined products production estimates, commodity price environments, economic conditions and potential changes in the
financial condition of our customers. Our predictions of such factors could cause us to forego certain investments or to lose
opportunities to competitors who make investments based on more aggressive predictions. Acquisitions and organic growth
projects, including the integration of assets into our existing businesses, may require substantial capital.
Acquisitions and organic growth projects involve numerous risks, including difficulties in the assimilation of the assets and
operations of the acquired businesses, inefficiencies and difficulties that arise because of unfamiliarity with new assets and the
businesses associated with them and new geographic areas and the diversion of management’s attention from other business
concerns. Further, we may experience unanticipated delays in realizing the benefits of an acquisition or project or we may be
unable to integrate certain assets to the extent such assets relate to a business for which we have no or limited experience. Our
failure to properly assess the levels of capital or time required to acquire or build and integrate these assets, or our failure to
accurately predict the returns from these assets could have an adverse effect on our business, financial condition, results of
operations or cash flows.
Debt securities we issue are, and will continue to be, junior to claims of our operating subsidiaries’ creditors.
Our outstanding debt securities are structurally subordinated to the claims of our operating subsidiaries’ creditors. In
addition, any debt securities we issue in the future will likewise be subordinated in the same manner. Holders of the debt
securities will not be creditors of our operating subsidiaries. Our claim to the assets of our operating subsidiaries derives from
our own ownership interests in those operating subsidiaries. Claims of our operating subsidiaries’ creditors will generally have
priority as to the assets of our operating subsidiaries over our own ownership interests and will therefore have priority over the
holders of our debt, including our debt securities.
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Limited access to the debt and equity markets 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. 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, Buckeye
Linden 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, Buckeye Linden 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. Where circumstances justify it, FERC permits pipelines to use one of three alternatives to
indexing—pipelines may seek to use market-based, cost-based, or settlement-based rates.
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.
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
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 response to
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 or any subsequent PSA reauthorization laws or new DOT pipeline safety
regulations may affect our operations.
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 United Arab Emirates and
Singapore. 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.
21
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.
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.
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A substantial amount of the petroleum products handled by BBH are exported from Venezuela, which exposes us to
political risks.
A substantial portion of BBH’s revenue relates to petroleum products exported from Venezuela. This involvement with
products exported from Venezuela exposes BBH to significant risks, including potential political and economic instability and
trade restrictions and economic embargoes imposed by the United States and other countries.
The loss of one or more key customers in our Global Marine Terminals segment could adversely affect our results of
operations and cash flow.
Storage revenue represented 82% of BBH’s total revenue for the year ended December 31, 2016, which accounted for
approximately 29% of total revenue in the Global Marine Terminals segment. 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, 2016, 31% and 60% 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 33% of total revenue in the Global Marine Terminals segment for the year
ended December 31, 2016. If any one or more of our long-term take-or-pay arrangements with this customer is 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.
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, 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.
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.
Cybersecurity breaches and other disruptions could compromise our information and expose us to liability, which could
cause our business and reputation to suffer.
Cyber security 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. 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, and loss of business.
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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 cyber security 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.
During 2007, the Department of Homeland Security promulgated the Chemical Facility Anti-Terrorism Standards
(“CFATS”) to regulate the security of facilities that handle certain chemicals. We have submitted 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 initially tiered as “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. The Department of Homeland Security began a concerted effort to enforce and further
define the CFATS program in 2013, which we expect to continue. 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
other components of the Department of Homeland Security and the Department of Transportation, 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.
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 and similar international
laws and regulations prohibit improper payments to foreign officials for the purpose of obtaining or retaining business. The
scope and enforcement of anti-corruption laws and regulations may vary.
We operate in parts of the world that have experienced governmental corruption to some degree, and in certain
circumstances, strict compliance with anti-bribery laws may conflict with local customs and practices. Our compliance
programs and internal control policies and procedures may not always protect us from reckless or negligent acts committed by
our employees or agents. Violations of these laws, or allegations of such violations, could disrupt our business and result in a
material adverse effect on our business and operations.
Derivative reform mandated by the Dodd-Frank Act and rules and regulations under the Dodd-Frank Act may have an
adverse effect on our ability to use certain derivative instruments to reduce the effect of commodity price, interest rate and
other risks associated with our business.
Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) in 2010.
Among other things, the Dodd-Frank Act mandated significant changes to the over-the-counter derivative market and requires
the Commodities Futures Trading Commission and the SEC and other regulators to promulgate rules and regulations
establishing federal oversight and regulation of the over-the-counter derivative market. Although as of December 31, 2016, 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 (including rules and regulations mandated by the Dodd-Frank Act that have not yet been promulgated) may have an
adverse effect on our ability to do so in the future.
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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.
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.
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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.
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.
Our investment in VTTI involves risks associated with the integration of acquired businesses, including the potential
exposure to significant liabilities, and the intended benefits of our investment in VTTI may not be realized.
Our investment in VTTI involves risks associated with the integration of acquired businesses, including, among other
things:
diversion of management’s attention from other business concerns;
•
• managing regulatory compliance and corporate governance matters;
•
ensuring the VTTI Entities have appropriate internal controls and maintaining an effective system of internal controls
at Buckeye related to the VTTI Entities;
failure of the VTTI Entities to perform as well as we anticipate;
incurrence of significant unknown and contingent liabilities for which we have limited or no contractual remedies or
insurance coverage; and
potential environmental or other regulatory compliance matters or liabilities and/or title issues, including certain
liabilities arising from the operation of the VTTI Entities prior to the closing of the VTTI Acquisition.
•
•
•
26
Further, unexpected costs and challenges may arise whenever businesses undergo a change in ownership and management,
and we may experience unanticipated delays in realizing the benefits of our investment in VTTI. If such risks or other
anticipated or unanticipated liabilities were to materialize, any desired benefits of our investment in VTTI may not be fully
realized, if at all, and our future financial performance may be negatively impacted.
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 VTTI and its subsidiaries (collectively, 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.
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.
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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 is currently a maximum of 35%. Distributions to you would generally be taxed again as
corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be
imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore,
treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to holders
of our LP Units, likely causing a substantial reduction in the value of our LP Units.
Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that
subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for U.S. federal, state, local or foreign
income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect
the impact of that law or interpretation on us. At the state level, several states have been evaluating ways to subject
partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state
were to impose a tax upon us as an entity, the cash available for distribution to you would be reduced and the value of our LP
Units could be negatively impacted.
The tax treatment of publicly traded partnerships or an investment in our LP Units could be subject to potential
legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our LP
Units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to
time, members of Congress propose and consider substantive changes to the existing 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.
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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.
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. These rules are not applicable for tax years beginning on or
prior to December 31, 2017.
Even if you do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable
income.
You will be required to pay 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.
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Tax-exempt entities and non-U.S. persons face unique tax issues from owning our LP Units that may result in adverse
tax consequences to them.
Investment in LP Units by tax-exempt entities, such as employee benefit plans and individual retirement accounts
(“IRAs”), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to
organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business
taxable income and will be taxable to them. Distributions to non-U.S. persons will be subject to withholding taxes imposed at
the highest effective tax rate applicable to such non-U.S. persons, and each non-U.S. person will be required to file United
States federal tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person,
you should consult your 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.
30
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in
the termination of our partnership for federal income tax purposes.
We will be considered to have terminated for U.S. federal income tax purposes if there is a sale or exchange of 50% or
more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things,
result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one calendar year
and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a
unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than
twelve months of our taxable income or loss being includable in taxable income for the unitholder’s taxable year that includes
our termination. Our termination would not affect our classification as a partnership for federal income tax purposes, but it
would result in our being treated as a new partnership for U.S. federal income tax purposes following the termination. If we
were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were
unable to determine that a termination occurred. The IRS has announced a relief procedure whereby if a publicly traded
partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may
be permitted to provide only a single Schedule K-1 to unitholders for the two short tax periods included in the year in which the
termination occurs.
We may in the future cause all or a portion of our interest in the acquired VTTI business to be held in an entity treated as
a corporation for U.S. federal income tax purposes, which would reduce cash available for distribution from the acquired
VTTI business.
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 LPG, crude oil and refined petroleum products in part
through direct or indirect non-U.S. subsidiaries of VTTI, including VTTI Energy Partners LP, 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, 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 exceed or are expected to exceed our currently 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 acquired 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 at the
applicable U.S. federal corporate income tax rate of 35% as well as any applicable state income tax rates. Imposition of a
corporate level federal income tax would significantly reduce the anticipated cash available for distribution from the acquired
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 significantly 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.
31
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 a subsidiary that is treated as a corporation for federal income tax purposes and subject to corporate-level
income taxes.
We conduct a portion of our operations through a subsidiary that is a corporation for federal income tax purposes. We may
elect to conduct additional operations in corporate form in the future. The corporate subsidiary 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.
32
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.
In June 2016, Buckeye Pipe Line Company, L.P. (“BPLC”), as the operator of the West Shore pipeline system, received a
penalty from PHMSA totaling $0.1 million in connection with certain procedural issues related to an inspection. We
determined not to contest the penalty and paid it in full. West Shore indemnified BPLC for all costs associated with the penalty.
On January 19, 2016, Buckeye received a letter from the Environmental Enforcement Section of the Department of Justice
discussing a possible consent decree in connection with pipeline releases of West Shore that occurred on December 14, 2010
near Lockport, Illinois and on August 27, 2012 near Palos Park, Illinois. The letter proposes a civil penalty of $2.3 million.
Buckeye, as operator of West Shore, is seeking a reduction in the amount of the proposed penalty. Buckeye is entitled to certain
indemnifications by West Shore pursuant to an agreement between BPLC and West Shore, which we believe would result in
West Shore indemnifying us for any penalties.
In December 2015, PHMSA issued to Buckeye a notice of probable violation (NOPV 1-2015-5021) relating to a July 2013
inspection of the Malvern, Booth and Macungie area pipelines. Buckeye responded contesting certain of the alleged violations
and requesting a reduced penalty. PHMSA granted a slight penalty reduction, and in December 2016, Buckeye paid a penalty
of approximately $0.2 million.
Item 4. Mine Safety Disclosures
Not applicable.
33
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, 2016 and 2015, as reported in the NYSE Composite Transactions, were as follows:
Quarter
First ....................................................................................
Second................................................................................
Third...................................................................................
Fourth.................................................................................
2016
2015
High
Low
High
Low
$
70.84
$
47.07
$
78.30
$
74.35
75.10
71.79
62.29
67.11
61.37
82.98
76.56
72.43
69.52
73.93
52.91
52.04
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, 2011
and that all distributions or dividends were reinvested on a quarterly basis.
12/31/2011
12/31/2012
12/31/2013
12/31/2014
12/31/2015
12/31/2016
Buckeye Partners, L.P... $
S&P 500 .......................
Alerian MLP Index.......
100.00
$
76.80
$
128.32
$
144.79
$
134.54
$
100.00
100.00
116.00
104.80
153.57
133.70
174.60
140.13
177.01
94.46
145.14
198.18
111.75
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 152,500 at December 31, 2016.
34
Cash distributions paid to unitholders for the periods indicated were as follows:
Record Date
Payment Date
February 18, 2014................................... February 25, 2014...................................
May 12, 2014 .......................................... May 19, 2014 ..........................................
August 18, 2014...................................... August 25, 2014......................................
November 18, 2014 ................................ November 25, 2014 ................................
February 17, 2015................................... February 24, 2015...................................
May 11, 2015 .......................................... May 18, 2015 ..........................................
August 10, 2015...................................... August 17, 2015......................................
November 9, 2015 .................................. November 17, 2015 ................................
February 23, 2016................................... March 1, 2016.........................................
May 16, 2016 .......................................... May 23, 2016 ..........................................
August 15, 2016...................................... August 22, 2016......................................
November 15, 2016 ................................ November 22, 2016 ................................
Amount Per
LP Unit
$1.0875
$1.1000
$1.1125
$1.1250
$1.1375
$1.1500
$1.1625
$1.1750
$1.1875
$1.2000
$1.2125
$1.2250
On February 10, 2017, we announced a quarterly distribution of $1.2375 per LP Unit that will be paid on February 28,
2017, to unitholders of record on February 21, 2017. Based on the LP Units outstanding as of December 31, 2016, cash
distributed to unitholders on February 28, 2017 will total $174.4 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.
We are a publicly traded MLP and are 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.
35
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):
2016
2015
2014
2013
2012
Year Ended December 31,
Income Statement Data:
Revenue (1) ............................................................... $ 3,248,376
733,342
Operating income (1) (2) ...........................................
Income from continuing operations (1) (2) ...............
548,675
Earnings per unit - diluted from continuing
operations .................................................................. $
Cash distributions per LP Unit - declared ................. $
4.03
4.88
$ 3,453,434
604,116
438,391
$ 6,620,247
495,347
334,498
$ 5,054,101
478,041
351,599
$ 4,285,903
344,536
235,879
$
$
3.41
4.68
$
$
2.78
4.48
$
$
3.23
4.28
$
$
2.37
4.15
2016
2015
2014
2013
2012
December 31,
Balance Sheet Data:
Total assets (3) (4) ..................................................... $ 9,421,103
Long-term debt (4) ....................................................
4,217,695
Total Buckeye Partners, L.P. capital..........................
4,411,723
$ 8,369,281
$ 8,065,720
$ 6,988,024
$ 5,972,910
3,732,824
3,368,618
3,075,172
2,727,145
3,735,389
3,702,628
3,065,665
2,372,313
____________________________
(1) The decrease in revenue for the years ended December 31, 2016 and 2015 compared to the year ended December 31, 2014
was primarily related to a decrease in sales volume and a decline of refined petroleum products prices in our Merchant
Services segment. The decrease in sales volume was primarily related to more effective inventory management. See
“Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations” for further discussion.
(2) During 2012, we recorded a $60.0 million asset impairment in our Domestic Pipelines & Terminals segment related to the
abandonment of a portion of our NORCO pipeline system.
(3) Includes $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.
(4) 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 guidance for debt issuance costs, we
reclassified $20.4 million, $17.5 million and $8.1 million of debt issuance costs originally included in “Other non-current
assets” as of each respective year ending December 31, 2014 through 2012 to “Long-term debt” as a direct deduction from
the carrying amount of debt liabilities, consistent with debt discounts.
36
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 a diversified 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. Additionally, we are one of the largest independent terminalling and storage
operators in the United States in terms of capacity available for service. Our terminal network comprises more than 120 liquid
petroleum products terminals with aggregate storage capacity of over 115 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
and in the Caribbean. Our 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, 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. Our recent acquisition of an indirect 50% equity interest in VTTI expands our
international presence with premier storage and marine terminalling services for petroleum products predominantly located in
key global energy hubs, including Northwest Europe, the United Arab Emirates and Singapore. We are also a wholesale
distributor of refined petroleum products in 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.
Overview of Operating Results
Net income attributable to our unitholders was $535.6 million for the year ended December 31, 2016, which was an
increase of $98.4 million, or 22.5%, from $437.2 million for the corresponding period in 2015. Operating income was
$733.3 million for the year ended December 31, 2016, which is an increase of $129.2 million, or 21.4%, from $604.1 million
for the corresponding period in 2015.
The increase in net income attributable to our unitholders was the result of increased contributions from each of our
business segments. Our Global Marine Terminals segment benefited from higher asset utilization due to strong customer
demand for our storage, throughput and terminalling services over the prior year, as well as increased available storage capacity
as a result of capital investments, including the commissioning of the Buckeye Texas assets during the fourth quarter of 2015.
In our Domestic Pipelines & Terminals segment, increases in terminalling storage and throughput revenue, pipeline
transportation revenue and product recoveries, as well as $14 million in proceeds from the exercise by a customer of an early
buy-out provision in a crude-by-rail contract, were the primary drivers for the increase over the prior year. Additionally, our
Merchant Services segment benefited from higher margins due to continued effective inventory management.
These increases in net income attributable to our unitholders were partially offset by increases in depreciation and
amortization expense due to the commissioning of the Buckeye Texas assets in our Global Marine Terminals segment during
the fourth quarter of 2015 and expansion capital projects placed into service during 2015. In addition, an increase in interest
and debt expense, due to lower capitalization of interest as a result of the placement in service of significant asset infrastructure
at Buckeye Texas during the fourth quarter of 2015 and interest expense related to the long-term debt issued in the fourth
quarter of 2016 to partially fund the VTTI Acquisition, also partially offset the increases to net income attributable to our
unitholders.
See the “Results of Operations” section below for further discussion and analysis of our operating segments.
37
Results of Operations
Consolidated Summary
Our summary operating results were as follows for the periods indicated (in thousands, except per unit amounts):
Revenue........................................................................................................... $
Costs and expenses..........................................................................................
Operating income ............................................................................................
Earnings from equity investments...................................................................
Interest and debt expense ................................................................................
Other income (expense) ..................................................................................
Income from continuing operations before taxes............................................
Income tax expense .........................................................................................
Income from continuing operations ................................................................
Loss from discontinued operations (1)............................................................
Net income ......................................................................................................
Less: Net income attributable to noncontrolling interests ............................
Net income attributable to Buckeye Partners, L.P. ......................................... $
Diluted earnings (loss) per unit attributable to Buckeye Partners, L.P...........
Year Ended December 31,
2016
3,248,376
2,515,034
733,342
11,536
(194,922)
179
550,135
(1,460)
548,675
—
548,675
(13,067)
535,608
$
$
2015
3,453,434
2,849,318
604,116
6,381
(171,330)
98
439,265
(874)
438,391
(857)
437,534
(311)
437,223
$
$
2014
6,620,247
6,124,900
495,347
11,265
(171,235)
(428)
334,949
(451)
334,498
(59,641)
274,857
(1,903)
272,954
Continuing operations................................................................................... $
Discontinued operations ............................................................................... $
4.03
$
— $
3.41
$
(0.01) $
2.78
(0.50)
_____________________________
(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.
Non-GAAP Financial Measures
Adjusted EBITDA and distributable cash flow are measures not defined by accounting principles generally accepted in the
United States of America (“GAAP”). We define Adjusted EBITDA as earnings before interest expense, income taxes,
depreciation and amortization, further adjusted to exclude certain non-cash items, such as non-cash compensation expense;
transaction and transitions costs associated with acquisitions; 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. We define
distributable cash flow as Adjusted EBITDA less cash interest expense, cash income tax expense, and maintenance capital
expenditures. 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 that we use and that these measures
are useful to investors because they aid in comparing our operating performance with that of other companies with similar
operations. The Adjusted EBITDA and distributable cash flow data presented by us may not be comparable to similarly titled
measures at other companies because these items may be defined differently by other companies.
38
239,556
(8,059)
763,568
334,498
(1,903)
332,595
171,235
451
196,443
20,867
13,048
40,000
—
(11,071)
—
—
The following table presents Adjusted EBITDA from continuing operations by segment and on a consolidated basis,
distributable cash flow and a reconciliation of income from continuing operations, which is the most comparable financial
measure under GAAP, to Adjusted EBITDA and distributable cash flow for the periods indicated (in thousands):
Adjusted EBITDA from continuing operations:
Domestic Pipelines & Terminals .................................................................. $
Global Marine Terminals..............................................................................
Merchant Services ........................................................................................
Year Ended December 31,
2016
2015
2014
568,405
$
522,196
$
532,071
427,229
32,372
323,840
22,026
Adjusted EBITDA from continuing operations....................................... $
1,028,006
$
868,062
$
Reconciliation of Income from continuing operations to
Adjusted EBITDA from continuing operations and Distributable cash flow:
Income from continuing operations ................................................................ $
Less: Net income attributable to noncontrolling interests............................
Income from continuing operations attributable to Buckeye Partners, L.P.....
Add: Interest and debt expense....................................................................
Income tax expense.............................................................................
Depreciation and amortization (1) ......................................................
Non-cash unit-based compensation expense ......................................
Acquisition and transition expense (2) ...............................................
Litigation contingency accrual (3)......................................................
Hurricane-related costs (4) .................................................................
Less: Amortization of unfavorable storage contracts (5).............................
Gains on property damage recoveries (6)...........................................
Gain on sale of ammonia pipeline ......................................................
Adjusted EBITDA from continuing operations .............................................. $
Less: Interest and debt expense, excluding amortization of deferred
financing costs, debt discounts and other ...........................................
Income tax benefit (expense), excluding non-cash taxes ...................
Maintenance capital expenditures (7).................................................
Add: Hurricane-related maintenance capital expenditures (8) ....................
Distributable cash flow from continuing operations....................................... $
548,675
(13,067)
535,608
194,922
1,460
254,659
33,344
8,196
—
16,795
(5,979)
(5,700)
(5,299)
1,028,006
(177,996)
276
(129,691)
6,054
$
$
438,391
(311)
438,080
171,330
874
221,278
29,215
3,127
15,229
—
(11,071)
—
—
$
868,062
$
763,568
(154,469)
(1,536)
(99,617)
—
(156,728)
(675)
(79,388)
—
726,649
$
612,440
$
526,777
____________________________
(1) Includes 100% of the depreciation and amortization expense of $71.7 million, $49.3 million and $12.3 million for Buckeye
Texas for the years ended December 31, 2016, 2015 and 2014, 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 as a result of Hurricane Matthew, which occurred in October 2016, consisting
of $11.0 million of operating expenses and a $5.8 million write-off of damaged long-lived assets for the year ended
December 31, 2016.
(5) Represents amortization of negative fair value allocated to certain unfavorable storage contracts acquired in connection
with the BBH acquisition.
(6) Represents 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.
(7) Represents expenditures that maintain the operating, safety and/or earnings capacity of our existing assets, including
hurricane-related expenditures.
(8) Represents expenditures to repair or replace long-lived assets damaged as a result of Hurricane Matthew.
39
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, percent of capacity utilization for our Global Marine Terminals segment and total
volumes sold in gallons for the Merchant Services segment for the periods indicated:
Year Ended December 31,
2016
2015
2014
Domestic Pipelines & Terminals (average bpd in thousands):
Pipelines:
Gasoline ...................................................................................................
Jet fuel......................................................................................................
Middle distillates (1) ................................................................................
Other products (2) ....................................................................................
Total throughput..................................................................................
759.6
361.1
289.4
16.9
735.9
358.9
337.4
28.5
702.8
336.0
354.9
36.6
1,427.0
1,460.7
1,430.3
Terminals:
Throughput (3) ....................................................................................
1,238.4
1,215.4
1,147.5
Pipeline average tariff (cents/bbl).................................................................
85.9
83.7
85.2
Global Marine Terminals (percent of capacity):
Average capacity utilization rate (4) ..........................................................
99%
96%
85%
Merchant Services (in millions of gallons):
Sales volumes.............................................................................................
1,179.7
1,215.0
2,009.0
_____________________________
(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 92%, 85% and 74% for the years ended
December 31, 2016, 2015 and 2014, respectively.
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
Consolidated
Income from continuing operations was $548.7 million for the year ended December 31, 2016, which was an increase of
$110.3 million, or 25.2%, from $438.4 million for the corresponding period in 2015. The increase in income from continuing
operations was primarily due to higher storage revenues, reflecting increased capacity utilization, internal growth capital
investments and new storage contracts; higher pipeline transportation and terminalling throughput revenues; favorable product
recoveries; higher contributions from the Buckeye Texas assets; $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; and continued effective inventory
management in our Merchant Services segment. The increase in income from continuing operations was partially offset by an
increase in depreciation and amortization expense primarily due to the Buckeye Texas assets which were commissioned in the
fourth quarter of 2015 and expansion capital projects placed into service during 2015 and 2016, as well as an increase in
interest and debt expense due to lower capitalization of interest as a result of the placement in service of significant asset
infrastructure at Buckeye Texas during the fourth quarter of 2015 and interest expense related to the long-term debt issued in
the fourth quarter of 2016 to partially fund the VTTI Acquisition.
Revenue was $3,248.4 million for the year ended December 31, 2016, which is a decrease of $205.0 million, or 5.9%, from
$3,453.4 million for the corresponding period in 2015. The decrease in revenue was primarily related to a decline of refined
petroleum product prices and a decrease in sales volume in our Merchant Services segment. This decrease in revenue was
partially offset by higher storage revenues, reflecting increased capacity utilization, internal growth capital investments, and
new storage contracts; higher pipeline transportation and terminalling throughput revenues; favorable product recoveries; and
higher contributions from the Buckeye Texas assets.
40
Adjusted EBITDA was $1,028.0 million for the year ended December 31, 2016, which is an increase of $159.9 million, or
18.4%, from $868.1 million for the corresponding period in 2015. The increase in Adjusted EBITDA was primarily related to
increased contributions from our joint venture interest in Buckeye Texas and higher storage revenues, reflecting increased
capacity utilization, internal growth capital investments, and new storage contracts; higher pipeline transportation and
terminalling throughput revenues; favorable product recoveries; as well as continued effective inventory management in our
Merchant Services segment.
Distributable cash flow was $726.6 million for the year ended December 31, 2016, which is an increase of $114.2 million,
or 18.6%, from $612.4 million for the corresponding period 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 and a $23.5 million increase in interest and debt expense, excluding amortization of deferred financing
costs, debt discounts and other. This increase was due to lower capitalization of interest as a result of the placement in service
of significant asset infrastructure at Buckeye Texas during the fourth quarter of 2015 and interest expense related to the long-
term debt issued in the fourth quarter of 2016 to partially fund the VTTI Acquisition.
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, which is 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 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.
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 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, which was 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, which was 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.
41
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 by $0.31 per gallon (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.
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 by $0.31 per gallon (average sales prices per gallon were $1.37 and $1.68 for the 2016 and 2015 periods,
respectively).
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014
Consolidated
Income from continuing operations was $438.4 million for the year ended December 31, 2015, which is an increase of
$103.9 million, or 31.1%, from $334.5 million for the corresponding period in 2014. The increase in income from continuing
operations was primarily related to increased storage revenue due to higher storage utilization and rates at our terminalling
facilities in the Global Marine Terminals segment and elimination of certain commercial strategies from 2014 and more
effective inventory management in our Merchant Services segment. The increase in income from continuing operations was
partially offset by the decrease in revenue related to settlements and butane blending margins in our Domestic Pipelines &
Terminals segment, as well as an increase in depreciation and amortization expense primarily due to the Buckeye Texas assets
in our Global Marine Terminals segment.
Revenue was $3,453.4 million for the year ended December 31, 2015, which is a decrease of $3,166.8 million, or 47.8%,
from $6,620.2 million for the corresponding period in 2014. The decrease in revenue was primarily related to the decrease in
sales volume and a decline of refined petroleum product prices in our Merchant Services segment, as well as lower product
recoveries from our terminalling throughput activities in our Domestic Pipelines & Terminals segment. The decrease in
revenue was partially offset by the revenue increase in our Global Marine Terminals segment primarily due to higher storage
utilization and rates at our terminalling facilities and lower FERC litigation accruals recorded as a reduction in revenue in our
Domestic Pipelines & Terminals segment.
Adjusted EBITDA was $868.1 million for the year ended December 31, 2015, which is an increase of $104.5 million, or
13.7%, from $763.6 million for the corresponding period in 2014. The increase in Adjusted EBITDA was primarily related to
increased storage revenue due to higher storage utilization and rates at our terminalling facilities and positive contributions
from the Buckeye Texas assets in our Global Marine Terminals segment and elimination of certain commercial strategies from
2014 and more effective inventory management in our Merchant Services segment. The increase in Adjusted EBITDA was
partially offset by a decrease in revenue related to settlements and butane blending margins in our Domestic Pipelines &
Terminals segment. Settlement revenues decreased in our Domestic Pipelines & Terminals segment due to lower product
recoveries from our terminalling throughput activities and prior year volumetric pipeline settlement gains. In addition, butane
blending activities in our Domestic Pipelines & Terminals segment were negatively impacted due to the narrowed spread
between butane and gasoline prices.
Distributable cash flow was $612.4 million for the year ended December 31, 2015, which is an increase of $85.7 million,
or 16.3%, from $526.8 million as compared to the corresponding period in 2014. The increase in distributable cash flow was
primarily related to an increase of $104.5 million in Adjusted EBITDA as described above, partially offset by a $20.2 million
increase in maintenance capital expenditures primarily resulting from increased tank integrity projects.
42
Adjusted EBITDA by Segment
Domestic Pipelines & Terminals. Adjusted EBITDA from the Domestic Pipelines & Terminals segment was
$522.2 million for the year ended December 31, 2015, which is a decrease of $9.9 million, or 1.9%, from $532.1 million for the
corresponding period in 2014. The decrease in Adjusted EBITDA is due to a $19.2 million increase in operating expenses,
which include higher payroll expense and legal fees related to certain FERC matters, and a $4.9 million decrease in earnings
from equity investments primarily due to an increase in integrity spending, which were partially offset by a $14.2 million
increase in revenues, excluding the accrual related to certain FERC litigation that was recorded as a reduction in revenue. The
increase in revenues is comprised of a $26.3 million increase resulting from higher terminalling throughput volumes and higher
storage revenue from new contracts, a $13.2 million increase in revenue from capital investments in internal growth and
diversification initiatives, including diluent and crude oil handling services and a $9.5 million increase in revenue resulting
from higher pipeline volumes. These increases were partially offset by a $26.8 million decrease in revenue related to lower
product recoveries from our terminalling throughput activities, as well as the narrowed spread between butane and gasoline
prices, and an $8.0 million decrease in revenue resulting from lower average pipeline tariff rates primarily due to a shift
between intra-state and inter-state shipments.
Pipeline volumes increased by 2.1% due to stronger demand for jet fuel and gasoline resulting from growth capital projects
placed into service mid-year 2014. Terminalling volumes increased by 5.9% due to higher demand for gasoline, distillates and
jet fuel, new customer contracts and service offerings at select locations, including contributions from growth capital spending,
which were partially offset by a decrease in crude-by-rail volumes.
Global Marine Terminals. Adjusted EBITDA from the Global Marine Terminals segment was $323.8 million for the year
ended December 31, 2015, which is an increase of $84.2 million, or 35.1%, from $239.6 million for the corresponding period in
2014. The increase in Adjusted EBITDA is primarily due to a $58.4 million increase in storage and terminalling revenue as a
result of greater customer utilization and higher service rates and a $39.7 million increase in the contribution from our joint
venture interest in Buckeye Texas. The average capacity utilization of our marine storage assets was 96% for the year ended
December 31, 2015, which is an increase from 85% in the corresponding period in 2014. The increase in storage revenue
resulted from internal growth capital investments which increased available storage capacity and diversified our asset
capabilities, as well as improved market conditions which were the result of the development of structure in the crude oil and
refined petroleum products markets. This increase in Adjusted EBITDA is partially offset by a $7.5 million increase in
operating expenses related to outside services for asset maintenance activities and incremental costs necessary to support the
higher utilization of our facilities, as well as a $6.4 million decrease in ancillary revenues primarily due to higher product
settlement gains in the prior year.
Merchant Services. Adjusted EBITDA from the Merchant Services segment was $22.0 million for the year ended
December 31, 2015, which is an improvement of $30.1 million from a loss of $8.1 million for the corresponding period in
2014. The positive factors impacting Adjusted EBITDA were primarily related to the elimination of certain commercial
strategies from 2014 and more effective inventory management. The elimination of certain commercial strategies included
liquidating our physical positions in markets less liquid than our core markets.
Adjusted EBITDA was also positively impacted by a $3,349.9 million decrease in cost of product sales, which included a
$2,113.9 million decrease due to 39.5% of lower volumes sold and a $1,236.0 million decrease in refined petroleum product
cost due to a price decrease of $1.01 per gallon (average prices per gallon were $1.65 and $2.66 for the 2015 and 2014 periods,
respectively) and a $1.1 million decrease in operating expenses, which primarily related to overhead and administrative costs.
Adjusted EBITDA was negatively impacted by a $3,320.9 million decrease in revenue, which included a $2,117.8 million
decrease due to 39.5% of lower volumes sold and a $1,203.1 million decrease in refined petroleum product sales due to a price
decrease of $0.99 per gallon (average sales prices per gallon were $1.68 and $2.67 for the 2015 and 2014 periods, respectively).
43
General Outlook for 2017
We expect our year-over-year performance to improve in 2017 based on the strength of our underlying asset portfolio
combined with our growth capital investment opportunities. Our acquisition of an indirect 50% equity interest in VTTI, which
we closed in early January 2017, is expected to be a key contributor to that improvement. In addition, we expect our successful
growth capital projects executed during 2016 across our portfolio of assets to generate incremental cash flow.
The full-year contribution from our equity interest in VTTI is expected to drive improvement in our year-over-year
performance. VTTI, one of the largest independent global marine terminal businesses in the world, owns and operates
approximately 55 million barrels of crude and petroleum products storage across 14 terminals located on five continents. This
transaction expands our world-wide presence and furthers our strategy for diversification to new geographic locations. We
expect VTTI to be a key growth engine for Buckeye, as further demonstrated by VTTI's announcement of recent acquisitions
and growth initiatives. Importantly, we expect this investment to be immediately accretive in 2017.
We achieved the mechanical completion of the first phase of our Michigan-Ohio pipeline and terminal expansion project in
late 2016 and we expect our customers to ramp up throughput volumes in the first quarter of 2017. This project allows us to
offer expanded transportation service of refined petroleum products from supply sources in Michigan and western Ohio to
destinations in eastern Ohio and western Pennsylvania. Our customers, including Midwestern refiners, have signed up for
multi-year commitments to move refined products eastward. This project provides our customers with increased access to these
eastern markets to allow them to deliver into arbitrage opportunities between higher East Coast and lower Midwestern refined
product market prices.
In late 2016, we successfully completed an open season on a second phase of the Michigan/Ohio project that will further
expand Buckeye’s capabilities to move more refined product barrels from Midwestern refineries to Pittsburgh as well as to
destinations in central Pennsylvania. This is a significant multi-year project that includes the partial reversal of our existing
Laurel pipeline. We are now moving forward with engineering and permitting work, including seeking necessary regulatory
approvals, and we currently expect to bring this project on-line in the second half of 2018.
We also continue to make progress on our infrastructure upgrades across our New York Harbor terminals as we work to
create an interconnected complex similar to our very successful Chicago Complex. The initiatives are expected to enhance our
competitive position through improved interconnectivity, marine handling, blending and pipeline takeaway capabilities. The
completion of these various facility improvements is scheduled for late 2017 into early 2018. We also expect to invest further
in our Chicago Complex to support the growing needs of major Midwestern refinery customers. We are assessing opportunities
to further expand storage capacity, throughput capacity and service capabilities at this key hub.
In addition, we expect to benefit from a full-year contribution of a number of capital investment projects that were
completed in 2016. We completed the refurbishment or construction of approximately 5 million barrels of additional storage
capacity across our domestic and international terminals. We also increased our butane blending and vapor recovery
capabilities and completed a number of additional improvements and debottlenecks across our system in 2016, and we expect a
full-year contribution from those projects in 2017.
We expect tariff increases, primarily on our market-based tariff pipelines, to drive throughput revenue growth, although
current pricing index projections do not indicate a significant change in FERC index-based tariffs in July 2017. We expect
volumes to be positively impacted from projects coming on-line, including the first phase of our Michigan/Ohio project as well
as the full-year impact from a pipeline reversal completed in late 2016 that provides Philadelphia-area refiners access to
markets in upstate New York and New York Harbor. We expect modest impacts to throughput volumes from continued strength
in gasoline and jet fuel demand in the markets we serve. Throughput volumes across our domestic terminals are expected to
increase moderately from the completion of growth capital initiatives across our system and customer growth primarily in the
Southeast. Additionally, a customer terminated a crude-by-rail contract at our Albany facility during 2016 and, although we are
working to secure replacement volumes by introducing new services offerings, we expect a year-over-year decline in
contribution from this facility.
44
Our results in 2016 reflect the benefit of our diversified asset base and limited exposure to commodity price cycles. If we
experience higher commodity prices in 2017, we would expect to see improved butane blending and settlement revenues as a
result. We anticipate continued tightening of the supply and demand balances to have an impact on the shape of the forward
curve and market structure, which could pressure recontracting rates for storage. However, we believe our market position and
continually improving asset capabilities positions us well to serve our customers as supply and demand patterns evolve and
market structure changes. We believe the geographic and product diversification as well as the service capabilities of our
pipeline, terminal, processing and marketing assets are well positioned for success despite potential continued volatility in
product prices.
Our Merchant Services segment will continue to focus on driving higher utilization across our system while capturing
incremental value when opportunities in the market are present. We expect this approach along with our continued inventory
and inventory management efforts to drive stable results in 2017.
We have $125 million of long-term debt maturing in mid-2017. We believe that we have sufficient liquidity available on
our $1.5 billion revolving Credit Facility to satisfy this maturity. We plan to access the debt capital market in late 2017 in
advance of a $300 million long-term debt maturity in January 2018. We have executed approximately $350 million of forward
starting interest rate hedges that mature in late 2017 to partially mitigate the risk of rising interest rates on our expected
issuance. We believe our Credit Facility and our ability to utilize our at-the-market equity issuance program will be sufficient
to meet our remaining expected capital needs for 2017. 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 2017 to acquire or construct assets that are complementary to our
businesses and 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 2017” 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 2017” may not occur.
45
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 permanently finance amounts borrowed under our Credit Facility. The BMSC entities fund their
working capital needs principally from their own operations and their portion of our Credit Facility. Our financial policy has
been 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 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, 2016, we had $919.3 million of working capital and $1.5 billion of availability under our Credit
Facility. However, in early January 2017 we paid $1.15 billion of cash consideration for the VTTI Acquisition, which was
partially funded through 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. In March 2016, we entered into an Equity Distribution
Agreement, under which we may offer to sell up to $500.0 million in aggregate gross sales proceeds of LP Units from time to
time through the ATM Underwriters, acting as agents of the Partnership or as principals, subject in each case to the terms and
conditions set forth in the Equity Distribution Agreement. All issuances of equity securities under the Equity Distribution
Agreement have been issued pursuant to the traditional shelf registration statement. At December 31, 2016, we had
$890.0 million of unsold securities available under the traditional shelf registration statement.
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-core 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.
46
Debt
At December 31, 2016, we had the following debt obligations (in thousands):
5.125% Notes due July 1, 2017.............................................................................................................................. $
6.050% Notes due January 15, 2018 ......................................................................................................................
2.650% Notes due November 15, 2018..................................................................................................................
5.500% Notes due August 15, 2019 .......................................................................................................................
4.875% Notes due February 1, 2021 ......................................................................................................................
4.150% Notes due July 1, 2023..............................................................................................................................
4.350% Notes due October 15, 2024......................................................................................................................
3.950% Notes due December 1, 2026 ....................................................................................................................
6.750% Notes due August 15, 2033 .......................................................................................................................
5.850% Notes due November 15, 2043..................................................................................................................
5.600% Notes due October 15, 2044......................................................................................................................
Term Loan due September 30, 2019 ......................................................................................................................
Total debt ............................................................................................................................................................. $
125,000
300,000
400,000
275,000
650,000
500,000
300,000
600,000
150,000
400,000
300,000
250,000
4,250,000
In November 2016, we issued the 3.950% Notes in an underwritten public offering at 99.644% of their principal amount.
Total proceeds from this offering, after underwriting fees, expenses and debt issuance costs of $5.2 million, were
$592.7 million. In January 2017, we used the net proceeds from this offering to fund a portion of the purchase price for the
VTTI Acquisition.
In September 2016, we entered into our $250.0 million Term Loan due September 30, 2019, with an option to extend the
term with consenting lenders for up to two one-year periods. We used the proceeds from the Term Loan to reduce the
indebtedness outstanding under our Credit Facility. See Note 14 in the Notes to Consolidated Financial Statements for
additional information.
In September 2016, Buckeye and its indirect wholly-owned subsidiaries, BMSC, as borrowers, exercised their remaining
option with consenting lenders to extend $1.4 billion of our existing $1.5 billion revolving Credit Facility by one year to
September 30, 2021. At December 31, 2016, Buckeye and BMSC collectively had no outstanding balance under the Credit
Facility.
Equity
In October 2016, we completed a public offering of 7.75 million LP Units pursuant to an effective shelf registration
statement, which priced at $66.05 per unit. The underwriters also exercised an option to purchase 1.16 million additional
LP Units, resulting in total gross proceeds of $588.7 million before deducting underwriting fees and other related expenses of
$8.0 million. We used the net proceeds from this offering to initially reduce the indebtedness outstanding under our Credit
Facility and for general partnership purposes, as well as to subsequently fund a portion of the purchase price for the VTTI
Acquisition in January 2017.
During the year ended December 31, 2016, we sold 1.6 million LP Units in aggregate under the Equity Distribution
Agreement, received $108.4 million in net proceeds after deducting commissions and other related expenses, including
$1.1 million of compensation paid in aggregate to the agents under the Equity Distribution Agreement. See Note 22 in the
Notes to Consolidated Financial Statements for additional information.
47
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):
Cash provided by (used in):
Year Ended December 31,
2016
2015
2014
Operating activities....................................................................................... $
Investing activities ........................................................................................
Financing activities.......................................................................................
$
717,917
(481,702)
399,244
$
710,192
(614,894)
(98,625)
599,642
(1,191,497)
595,113
Operating Activities
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 the
change 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 a $52.8 million in litigation settlement payments.
2014. Net cash provided by operating activities was $599.6 million for the year ended December 31, 2014, primarily
related to $274.9 million of net income and $196.4 million of depreciation and amortization, a $71.3 million decrease in
accounts receivables, and a $70.1 million decrease in inventory, which were partially offset by a $51.5 million settlement to
terminate the interest rate swap agreements related to the forecasted refinancing of the $5.300% Notes.
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
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.
2014. Net cash used in investing activities of $1,191.5 million for the year ended December 31, 2014 primarily related to
$472.1 million of capital expenditures and $824.7 million of acquisition costs, primarily related to the Buckeye Texas Partners
Transaction, which were partially offset by $103.4 million cash proceeds from the sale of our Natural Gas Storage disposal
group.
See below for a discussion of capital spending. For further discussion on our acquisitions, see Note 3 in the Notes to
Consolidated Financial Statements.
48
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):
Maintenance capital expenditures (1) ............................................................. $
Expansion and cost reduction (2)....................................................................
Total capital expenditures, net...................................................................... $
Year Ended December 31,
2016
129,691
356,625
486,316
$
$
2015
2014
99,617
494,903
594,520
$
$
80,141
392,008
472,149
_____________________________
(1) Includes maintenance capital expenditures of $6.1 million related to the BBH facility as a result of Hurricane Matthew for
the year ended December 31, 2016 and $0.8 million related to the Natural Gas Storage disposal group for the year ended
December 31, 2014.
(2) Amounts exclude accruals for capital expenditures. Expansion and cost reduction amounts including accruals for capital
expenditures were $327.7 million, $516.5 million and $340.5 million for the years ended December 31, 2016, 2015 and
2014, respectively.
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 the 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, repairs to our BBH facility as a result of Hurricane
Matthew, marine dock structure upgrades and upgrades to station and terminalling equipment.
Capital expenditures increased for the year ended December 31, 2015, as compared to the corresponding period in 2014
primarily due to increases in expansion and cost reduction capital expenditures. Our expansion and cost reduction capital
expenditures were $494.9 million for the year ended December 31, 2015, which is an increase of $102.9 million, or 26.2%,
from $392.0 million for the corresponding period in 2014. Year-to-year fluctuations in our expansion and cost reduction capital
expenditures are primarily driven by spending on our major organic growth capital projects. Our most significant organic
growth capital expenditures for the year ended December 31, 2015 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, and 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 South Texas. The build-
out of the facilities in South Texas was funded through additional partnership contributions by us and Trafigura based on our
respective ownership interests in Buckeye Texas. Our maintenance capital expenditures were $99.6 million for the year ended
December 31, 2015, which is an increase of $19.5 million, or 24.3%, from $80.1 million for the corresponding period in 2014.
Year-to-year fluctuations in our maintenance capital expenditures are primarily driven by the timing and cost of asset integrity
and facility infrastructure projects. Our most significant maintenance capital expenditures for the year ended December 31,
2015 included truck rack upgrades, pump replacements and pipeline and tank integrity work necessary to maintain the
operating capacity and equipment reliability of our existing infrastructure, as well as to address environmental regulations.
49
We estimate our capital expenditures for the period indicated as follows (in thousands):
Domestic Pipelines & Terminals:
Maintenance capital expenditures ............................................................................................ $
Expansion and cost reduction...................................................................................................
Total capital expenditures.................................................................................................... $
Global Marine Terminals:
Maintenance capital expenditures ............................................................................................ $
Expansion and cost reduction...................................................................................................
Total capital expenditures (1).............................................................................................. $
Overall:
Maintenance capital expenditures ............................................................................................ $
Expansion and cost reduction...................................................................................................
Total capital expenditures.................................................................................................... $
_____________________________
(1) Includes 100% of Buckeye Texas’ capital expenditures.
2017
Low
High
70,000
190,000
260,000
40,000
90,000
130,000
110,000
280,000
390,000
$
$
$
$
$
$
80,000
220,000
300,000
50,000
110,000
160,000
130,000
330,000
460,000
Estimated maintenance capital expenditures include tank refurbishments and upgrades to station and terminalling
equipment, pipeline integrity, field instrumentation and cathodic protection systems and exclude capital expenditures expected
to be incurred in response to Hurricane Matthew. Estimated major expansion and cost reduction expenditures include the
capacity expansion of our pipeline system and terminalling capacity in the Midwest, various tank construction and conversion
projects in our Global Marine Terminals and Domestic Pipelines & Terminals segments, as well as an expansion of facilities in
the New York Harbor.
Financing Activities
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 the
Equity Distribution Agreements.
2014. Net cash flows provided by financing activities of $595.1 million for the year ended December 31, 2014 primarily
related to $899.7 million of net proceeds from the issuance of an aggregate 11.8 million LP Units, and $599.1 million of
proceeds from the issuance of the 4.350% and 5.600% Notes due October 15, 2024 and October 15, 2044, respectively, partially
offset by $527.2 million of cash distributions paid to our unitholders ($4.425 per LP Unit), $275.0 million related to the
repayment of the 5.300% Notes and $89.0 million of net repayments under the Credit Facility.
For further discussion on our equity offerings, see Note 22 in the Notes to Consolidated Financial Statements.
50
Contractual Obligations
The following table summarizes our contractual obligations as of December 31, 2016 (in thousands):
Long-term debt (1)................................... $
Interest payments (2)................................
Operating leases:
Office space and other ...........................
Equipment (3)........................................
Land leases (4).......................................
Purchase obligations (5)...........................
Total
4,250,000
1,960,007
16,173
92,855
99,247
113,505
Payments Due by Period
Less than 1
year
125,000
$
1-3 years
1,225,000
$
3-5 years
$
650,000
$
More than 5
years
2,250,000
191,321
321,747
250,029
1,196,910
3,930
9,919
2,648
113,505
5,944
17,970
5,296
—
5,543
18,474
4,796
—
756
46,492
86,507
—
Total contractual obligations ................. $
6,531,787
$
446,323
$
1,575,957
$
928,842
$
3,580,665
_____________________________
(1) Includes long-term debt portion borrowed under our Credit Facility. See Note 14 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, 2017, our rights-of-way payments are expected to be $7.3 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 19 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 multiemployer 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 19 in the Notes to Consolidated Financial
Statements for further information.
Off-Balance Sheet Arrangements
At December 31, 2016 and 2015, we had no off-balance sheet debt or arrangements.
51
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 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
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.
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 test as of October 31, 2016, we performed quantitative assessments to determine the
fair value of each of our reporting units. The estimate of the fair value of the reporting unit is determined using a combination
of an expected present value of future cash flows and a market multiple valuation method. The present value of future cash
flows is estimated using: (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating
expenses; (ii) long-term growth rates; and (iii) an appropriate discount rate. The market multiple valuation method uses
appropriate market multiples from comparable companies on the reporting unit’s earnings before interest, tax, depreciation and
amortization. We evaluate industry and market conditions for purposes of weighting the income and market valuation
approach. Based on such calculations, each reporting unit’s fair value was in excess of its carrying value. We did not record
any goodwill impairment charges during the years ended December 31, 2016, 2015 or 2014.
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.
52
In December 2013, the Board 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. As a
result of the execution of the purchase and sale agreement, subsequent changes in the carrying value of the net assets of our
Natural Gas Storage disposal group, and the completed sale in December 2014, we recorded non-cash asset impairment charges
of $23.4 million during the year ended December 31, 2014. We recorded these asset impairment charges within “Loss from
discontinued operations” on our consolidated statements of operations for the year ended December 31, 2014. See Notes 4 and
5 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, 2016, 2015 or 2014.
Reserves for Environmental Matters
We record environmental liabilities at 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, or current facts and circumstances. The estimates
related to environmental matters are uncertain because: (i) estimated future expenditures are subject to cost fluctuations and
change in 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 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 narrowing 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.
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 significant management judgment.
53
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.
54
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, 2016................................... $
Items recognized or settled during the period...............................................
Fair value attributable to new deals ..............................................................
Change in fair value attributable to price movements ..................................
Change in fair value attributable to non-performance risk...........................
Fair value of contracts outstanding at December 31, 2016............................. $
$
78,129
(51,658)
(16,249)
(39,269)
246
(28,801) $
— $
—
62,609
—
—
62,609
$
78,129
(51,658)
46,360
(39,269)
246
33,808
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 derivative contracts. 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. 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 narrowing gasoline-to-butane pricing spreads associated 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 and observable market data from third-party pricing publications for physical derivative contracts related
to designated hedged refined petroleum products inventories outstanding and physical derivative contracts at December 31,
2016, the estimated fair value would be as follows (in thousands):
Scenario
Fair value assuming no change in underlying commodity prices (as is) ..................................
Fair value assuming 10% increase in underlying commodity prices........................................
Fair value assuming 10% decrease in underlying commodity prices .......................................
Resulting
Classification
Asset
Asset
Asset
Fair Value
$
$
$
308,622
314,092
303,152
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,
2016, the estimated fair value of the interest rate derivative contracts would be as follows (in thousands):
Scenario
Fair value assuming no change in underlying interest rates (as is)...........................................
Fair value assuming 10% increase in underlying interest rates ................................................
Fair value assuming 10% decrease in underlying interest rates................................................
Resulting
Classification
Asset
Asset
Asset
Fair Value
$
$
$
62,609
56,348
68,870
See Note 17 in the Notes to Consolidated Financial Statements for additional discussion related to derivative instruments
and hedging activities.
55
At December 31, 2016, we had total fixed-rate debt obligations under various public notes at an aggregate carrying value
of $4.0 billion. Based on a hypothetical 1% movement in the underlying interest rates at December 31, 2016, the estimated fair
value of these debt obligations would be as follows (in millions):
Scenario
Fair value assuming no change in underlying interest rates (as is) ......................................................................
Fair value assuming 1% increase in underlying interest rates .............................................................................
Fair value assuming 1% decrease in underlying interest rates.............................................................................
Fair Value of
Fixed-Rate Debt
4,083.5
$
3,848.1
$
4,350.7
$
At December 31, 2016, our variable-rate obligations were $250.0 million. Based on the balance outstanding at
December 31, 2016, we estimate that a 1% increase or decrease in underlying interest rates would increase or decrease annual
interest expense by $2.5 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, 2016, 2015 and 2014.
56
Item 8. Financial Statements and Supplementary Data
Management’s Report On Internal Control Over Financial Reporting ................................................................
Reports of Independent Registered Public Accounting Firm .................................................................................
Consolidated Statements of Operations for the Years Ended December 31, 2016, 2015 and 2014 .....................
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2016, 2015 and 2014
Consolidated Balance Sheets as of December 31, 2016 and 2015 ...........................................................................
Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014.....................
Consolidated Statements of Partners’ Capital for the Years Ended December 31, 2016, 2015 and 2014...........
Notes to Consolidated Financial Statements:
1. Organization ...........................................................................................................................................................
2. Summary of Significant Accounting Policies.........................................................................................................
3. Acquisitions and Disposition ..................................................................................................................................
4. Discontinued Operations ........................................................................................................................................
5. Asset Impairments ..................................................................................................................................................
6. Commitments and Contingencies ...........................................................................................................................
7. Inventories ..............................................................................................................................................................
8. Prepaid and Other Current Assets...........................................................................................................................
9. Property, Plant and Equipment ...............................................................................................................................
10. Equity Investments ...............................................................................................................................................
11. Goodwill and Intangible Assets ............................................................................................................................
12. Other Non-Current Assets.....................................................................................................................................
13. Accrued and Other Current Liabilities..................................................................................................................
14. Long-Term Debt ...................................................................................................................................................
15. Other Non-Current Liabilities...............................................................................................................................
16. Accumulated Other Comprehensive Income (Loss).............................................................................................
17. Derivative Instruments and Hedging Activities....................................................................................................
18. Fair Value Measurements .....................................................................................................................................
19. Pensions and Other Postretirement Benefits.........................................................................................................
20. Unit-Based Compensation Plans ..........................................................................................................................
21. Related Party Transactions ...................................................................................................................................
22. Partners’ Capital and Distributions .......................................................................................................................
23. Income Taxes ........................................................................................................................................................
24. Earnings Per Unit..................................................................................................................................................
25. Business Segments................................................................................................................................................
26. Supplemental Cash Flow Information ..................................................................................................................
27. Quarterly Financial Data (Unaudited) ..................................................................................................................
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57
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of Buckeye GP LLC, as general partner of Buckeye Partners, L.P. (“Buckeye”), is responsible for establishing and
maintaining adequate internal control over financial reporting of Buckeye. Internal control over financial reporting is a process
designed to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with accounting principles generally accepted in the United States of
America. A company’s internal control over financial reporting includes those policies and procedures that pertain to the
maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of
the company; provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial
statements in accordance with accounting principles generally accepted in the United States of America (“GAAP”), and that
receipts and expenditures of the company are being made only in accordance with authorizations of management and directors
of the company; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management evaluated the internal control over financial reporting of Buckeye as of December 31, 2016. In making this
assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway
Commission in Internal Control—Integrated Framework (2013) (“COSO”). As a result of this assessment and based on the
criteria in the COSO framework, management has concluded that, as of December 31, 2016, the internal control over financial
reporting of Buckeye was effective.
Buckeye’s independent registered public accounting firm, Deloitte & Touche LLP, has audited the internal control over
financial reporting of Buckeye. Their opinion on the effectiveness of internal control over financial reporting of Buckeye
appears herein.
/s/ CLARK C. SMITH
Clark C. Smith
Chief Executive Officer, President and
Chairman of the Board
February 24, 2017
/s/ KEITH E. ST.CLAIR
Keith E. St.Clair
Executive Vice President and
Chief Financial Officer
58
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Buckeye GP LLC and the
Partners of Buckeye Partners, L.P.
We have audited the internal control over financial reporting of Buckeye Partners, L.P. and subsidiaries (“Buckeye”) as of
December 31, 2016, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee
of Sponsoring Organizations of the Treadway Commission. Buckeye’s management is responsible for maintaining effective
internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting,
included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to
express an opinion on Buckeye’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal
control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and
operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered
necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s
principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s
board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting
principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the
maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of
the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that
could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper
management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely
basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods
are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
In our opinion, Buckeye maintained, in all material respects, effective internal control over financial reporting as of
December 31, 2016, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the
Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the
consolidated financial statements as of and for the year ended December 31, 2016 of Buckeye and our report dated February 24,
2017 expressed an unqualified opinion on those consolidated financial statements.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 24, 2017
59
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Buckeye GP LLC and the
Partners of Buckeye Partners, L.P.
We have audited the accompanying consolidated balance sheets of Buckeye Partners, L.P. and subsidiaries (“Buckeye”) as of
December 31, 2016 and 2015, and the related consolidated statements of operations, comprehensive income, cash flows, and
partners’ capital for each of the three years in the period ended December 31, 2016. These financial statements are the
responsibility of Buckeye’s management. Our responsibility is to express an opinion on the financial statements based on our
audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts
and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Buckeye
as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the
period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),
Buckeye’s internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal
Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission
and our report dated February 24, 2017 expressed an unqualified opinion on Buckeye’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 24, 2017
60
BUCKEYE PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
Year Ended December 31,
2016
2015
2014
Revenue:
Product sales ................................................................................................... $
Transportation, storage and other services......................................................
Total revenue............................................................................................
1,594,240
$
2,028,323
$
5,348,532
1,654,136
3,248,376
1,425,111
3,453,434
1,271,715
6,620,247
Costs and expenses:
Cost of product sales .......................................................................................
Operating expenses .........................................................................................
Depreciation and amortization ........................................................................
General and administrative .............................................................................
Other operating income, net............................................................................
Total costs and expenses..........................................................................
Operating income ............................................................................................
Other income (expense):
Earnings from equity investments...................................................................
Interest and debt expense ................................................................................
Other income (expense) ..................................................................................
Total other expense, net................................................................................
Income from continuing operations before taxes............................................
Income tax expense .........................................................................................
Income from continuing operations ................................................................
Loss from discontinued operations (Note 4)...................................................
Net income ......................................................................................................
Less: Net income attributable to noncontrolling interests ..........................
Net income attributable to Buckeye Partners, L.P..................................... $
Basic earnings (loss) per unit attributable to Buckeye Partners, L.P.:
Continuing operations.............................................................................. $
Discontinued operations...........................................................................
Total..................................................................................................... $
Diluted earnings (loss) per unit attributable to Buckeye Partners, L.P.:
Continuing operations.............................................................................. $
Discontinued operations...........................................................................
Total..................................................................................................... $
1,549,522
1,965,844
5,311,552
629,942
254,659
86,098
(5,187)
2,515,034
733,342
11,536
(194,922)
179
(183,207)
550,135
(1,460)
548,675
—
548,675
(13,067)
535,608
4.05
—
4.05
4.03
—
4.03
$
$
$
$
$
573,368
221,278
88,828
—
2,849,318
604,116
6,381
(171,330)
98
(164,851)
439,265
(874)
438,391
(857)
437,534
(311)
437,223
3.42
(0.01)
3.41
3.41
(0.01)
3.40
$
$
$
$
$
537,705
196,443
79,200
—
6,124,900
495,347
11,265
(171,235)
(428)
(160,398)
334,949
(451)
334,498
(59,641)
274,857
(1,903)
272,954
2.79
(0.50)
2.29
2.78
(0.50)
2.28
Weighted average units outstanding:
Basic.........................................................................................................
Diluted......................................................................................................
132,242
132,927
128,084
128,617
119,323
119,899
See Notes to Consolidated Financial Statements
61
BUCKEYE PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
Net income ....................................................................................................... $
Other comprehensive income (loss):
Unrealized gains (losses) on derivative instruments ......................................
Reclassification of derivative losses to net income........................................
Recognition of costs related to benefit plans to net income...........................
Adjustments to recognize the funded status of benefit plans .........................
Total other comprehensive income (loss)..................................................
Comprehensive income ....................................................................................
Less: Comprehensive income attributable to noncontrolling interests ..........
Comprehensive income attributable to Buckeye Partners, L.P......................... $
Year Ended December 31,
2016
548,675
$
2015
437,534
$
2014
274,857
60,281
10,884
1,886
(803)
72,248
620,923
(13,067)
607,856
$
1,266
12,151
1,510
2,520
17,447
454,981
(311)
454,670
$
(21,424)
9,753
698
(763)
(11,736)
263,121
(1,903)
261,218
See Notes to Consolidated Financial Statements
62
BUCKEYE PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands, except unit amounts)
December 31,
2016
2015
Assets:
Current assets:
Cash and cash equivalents................................................................................................................... $
Accounts receivable, net .....................................................................................................................
Construction and pipeline relocation receivables................................................................................
Inventories...........................................................................................................................................
Derivative assets..................................................................................................................................
Prepaid and other current assets ..........................................................................................................
Total current assets.........................................................................................................................
$
640,340
236,416
17,276
356,803
1,526
66,536
1,318,897
Property, plant and equipment..................................................................................................................
Less: Accumulated depreciation.........................................................................................................
Property, plant and equipment, net ................................................................................................
7,523,774
(1,040,492)
6,483,282
Equity investments ...................................................................................................................................
Goodwill ...................................................................................................................................................
89,564
1,004,545
Intangible assets........................................................................................................................................
Less: Accumulated amortization........................................................................................................
Intangible assets, net ......................................................................................................................
616,286
(192,983)
423,303
4,881
213,830
13,491
192,992
78,285
48,071
551,550
7,076,901
(874,820)
6,202,081
84,128
998,748
627,310
(135,938)
491,372
Other non-current assets ...........................................................................................................................
Total assets..................................................................................................................................... $
101,512
9,421,103
$
41,402
8,369,281
Liabilities and partners’ capital:
Current liabilities:
Line of credit ....................................................................................................................................... $
Accounts payable ................................................................................................................................
Derivative liabilities ............................................................................................................................
Accrued and other current liabilities ...................................................................................................
Total current liabilities...................................................................................................................
Long-term debt .........................................................................................................................................
Other non-current liabilities......................................................................................................................
Total liabilities ...............................................................................................................................
— $
107,383
26,272
265,893
399,548
4,217,695
105,437
4,722,680
111,488
82,691
510
309,620
504,309
3,732,824
115,407
4,352,540
Commitments and contingent liabilities (Note 6) .......................................................................................
—
—
Partners’ capital:
Buckeye Partners, L.P. capital:
Limited Partners (140,263,787 and 129,523,703 units outstanding as of December 31, 2016 and
2015, respectively) ..............................................................................................................................
Accumulated other comprehensive loss..............................................................................................
Total Buckeye Partners, L.P. capital..............................................................................................
Noncontrolling interests ......................................................................................................................
Total partners’ capital.....................................................................................................................
Total liabilities and partners’ capital.............................................................................................. $
4,437,316
(25,593)
4,411,723
286,700
4,698,423
9,421,103
$
3,833,230
(97,841)
3,735,389
281,352
4,016,741
8,369,281
See Notes to Consolidated Financial Statements
63
BUCKEYE PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Cash flows from operating activities:
Net income ...................................................................................................... $
Adjustments to reconcile net income to net cash provided by (used in)
operating activities:
Settlement of terminated interest rate swap agreements...............................
Depreciation and amortization......................................................................
Amortization of debt issuance costs and discounts ......................................
Amortization of losses on terminated interest rate swaps ............................
Non-cash unit-based compensation expense ................................................
Litigation contingency accrual .....................................................................
Litigation settlement .....................................................................................
Gains on property damage recoveries...........................................................
Hurricane-related damaged asset write-off...................................................
Gain on sale of ammonia pipeline ................................................................
Impairment of assets of discontinued operations..........................................
Net changes in fair value of derivatives .......................................................
Non-cash deferred lease expense..................................................................
Amortization of unfavorable storage contracts.............................................
Earnings from equity investments ................................................................
Distributions from equity investments..........................................................
Other non-cash items ....................................................................................
Change in assets and liabilities, net of amounts related to acquisitions:
Accounts receivable......................................................................................
Construction and pipeline relocation receivables .........................................
Inventories ....................................................................................................
Prepaid and other current assets ...................................................................
Accounts payable..........................................................................................
Accrued and other current liabilities.............................................................
Other non-current assets ...............................................................................
Other non-current liabilities..........................................................................
Net cash provided by operating activities................................................
Cash flows from investing activities:
Capital expenditures .....................................................................................
Contribution to equity investments...............................................................
Acquisitions, net of working capital settlements..........................................
Net proceeds from insurance settlement.......................................................
Proceeds from sale and disposition of assets................................................
Escrow deposits ............................................................................................
Proceeds from sale of discontinued operations ............................................
Recoveries on property damages ..................................................................
Distributions from equity investments..........................................................
Net cash used in investing activities ........................................................
64
Year Ended December 31,
2016
2015
2014
548,675
$
437,534
$
274,857
—
254,659
4,776
12,150
33,482
—
—
(5,700)
5,812
(5,299)
—
103,336
—
(5,979)
(11,536)
3,280
7,162
(23,646)
(4,961)
(162,257)
(41,224)
25,983
(7,347)
32
(13,481)
717,917
(486,316)
—
(26,025)
—
2,563
19,850
—
5,700
2,526
(481,702)
—
221,278
4,710
12,151
29,215
15,229
(52,839)
—
—
—
—
(9,177)
—
(11,071)
(6,381)
5,108
7,593
48,006
7,051
52,775
(3,523)
(65,239)
16,759
22,423
(21,410)
710,192
(594,520)
(300)
(8,118)
—
10,261
(21,360)
(857)
—
—
(614,894)
(51,469)
196,443
4,754
9,753
20,867
40,000
—
—
—
—
23,365
(77,901)
3,637
(11,071)
(11,265)
470
107
71,299
(5,424)
70,068
34,956
27,860
3,119
(19,706)
(5,077)
599,642
(472,149)
—
(824,719)
737
1,227
—
103,407
—
—
(1,191,497)
Cash flows from financing activities:
Net proceeds from issuance of LP Units ......................................................
689,128
161,474
Net proceeds from exercise of Unit options .................................................
Payment of tax withholding on issuance of LTIP awards.............................
Issuance of long-term debt............................................................................
Repayment of long term-debt .......................................................................
Debt issuance costs .......................................................................................
300
(6,711)
597,864
—
(6,413)
215
(7,700)
—
—
(1,115)
899,710
849
(6,234)
599,103
(275,000)
(7,414)
Borrowings under BPL Credit Facility.........................................................
1,007,200
1,627,450
1,856,031
Repayments under BPL Credit Facility........................................................
(1,368,200)
(1,266,450)
(1,885,031)
Net repayments under BMSC Credit Facility...............................................
(111,488)
Acquisition of additional interest in Buckeye Memphis ..............................
Borrowings under Term Loan.......................................................................
Contributions from noncontrolling interests.................................................
Distributions paid to noncontrolling interests...............................................
Distributions paid to unitholders ..................................................................
Net cash provided by (used in) financing activities.................................
Net increase (decrease) in cash and cash equivalents .....................................
Cash and cash equivalents — Beginning of year............................................
Cash and cash equivalents — End of year ...................................................... $
—
250,000
5,000
(15,750)
(641,686)
399,244
635,459
4,881
(54,512)
(10,044)
—
57,000
(13,972)
(60,000)
(9,510)
—
16,400
(6,593)
(590,971)
(527,198)
(98,625)
(3,327)
8,208
595,113
3,258
4,950
8,208
640,340
$
4,881
$
See Notes to Consolidated Financial Statements
65
BUCKEYE PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(In thousands)
Limited
Partners
Accumulated
Other
Comprehensive
Loss
Noncontrolling
Interests
Total
Partners' capital - January 1, 2014 ......................................... $
Net income .................................................................................
Acquisition of additional interest in Buckeye Memphis ............
Noncontrolling equity in acquisition (Note 3) ...........................
Distributions paid to unitholders ................................................
Contributions from noncontrolling interests (Note 3) ................
Net proceeds from issuance of LP Units ....................................
Amortization of unit-based compensation awards .....................
Net proceeds from exercise of Unit options ...............................
Payment of tax withholding on issuance of LTIP awards ..........
Distributions paid to noncontrolling interests ............................
Other comprehensive loss ..........................................................
Noncash accrual for distribution equivalent rights.....................
Other ..........................................................................................
Partners' capital - December 31, 2014 ....................................
Net income .................................................................................
Acquisition of additional interest in Buckeye Memphis ............
Adjusted value of noncontrolling interest in acquisition
(Note 3) .....................................................................................
Distributions paid to unitholders ................................................
Contributions from noncontrolling interests (Note 3) ................
Net proceeds from issuance of LP Units ....................................
Amortization of unit-based compensation awards .....................
Net proceeds from exercise of Unit options ...............................
Payment of tax withholding on issuance of LTIP awards ..........
Distributions paid to noncontrolling interests ............................
Other comprehensive income ....................................................
Noncash accrual for distribution equivalent rights.....................
Other ..........................................................................................
Partners' capital - December 31, 2015 ....................................
Net income .................................................................................
Distributions paid to unitholders ................................................
Net proceeds from issuance of LP Units ....................................
Amortization of unit-based compensation awards .....................
Net proceeds from exercise of Unit options ...............................
Payment of tax withholding on issuance of LTIP awards ..........
Distributions paid to noncontrolling interests ............................
Contributions from noncontrolling interests (Note 3) ................
Other comprehensive income ....................................................
Noncash accrual for distribution equivalent rights.....................
Other ..........................................................................................
Partners' capital - December 31, 2016 .................................... $
3,169,217
$
(103,552) $
15,171
$
272,954
(7,933)
—
(530,376)
—
899,710
21,499
849
(6,234)
—
—
(1,619)
(151)
3,817,916
437,223
(8,276)
—
(594,132)
—
161,474
29,332
215
(7,700)
—
—
(3,085)
263
3,833,230
535,608
(644,729)
689,128
33,482
300
(6,711)
—
—
—
(3,004)
12
—
—
—
—
—
—
—
—
—
—
(11,736)
—
—
(115,288)
—
—
—
—
—
—
—
—
—
—
17,447
—
—
(97,841)
—
—
—
—
—
—
—
—
72,248
—
—
1,903
(1,577)
208,998
3,178
16,400
—
—
—
—
(6,593)
—
—
488
237,968
311
(1,768)
(1,220)
3,161
57,000
—
—
—
—
(13,972)
—
—
(128)
281,352
13,067
3,043
—
—
—
—
(15,750)
5,000
—
—
(12)
3,080,836
274,857
(9,510)
208,998
(527,198)
16,400
899,710
21,499
849
(6,234)
(6,593)
(11,736)
(1,619)
337
3,940,596
437,534
(10,044)
(1,220)
(590,971)
57,000
161,474
29,332
215
(7,700)
(13,972)
17,447
(3,085)
135
4,016,741
548,675
(641,686)
689,128
33,482
300
(6,711)
(15,750)
5,000
72,248
(3,004)
—
4,437,316
$
(25,593) $
286,700
$
4,698,423
See Notes to Consolidated Financial Statements
66
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION
Buckeye Partners, L.P. is a publicly traded Delaware master limited partnership (“MLP”), and its limited partnership units
representing limited partner interests (“LP Units”) are listed on the New York Stock Exchange under the ticker symbol “BPL.”
Buckeye GP LLC (“Buckeye GP”) is our general partner. As used in these Notes to Consolidated Financial Statements, “we,”
“us,” “our” and “Buckeye” mean Buckeye Partners, L.P. and, where the context requires, includes our subsidiaries.
We were formed in 1986 and own and operate a diversified 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. Additionally, we are one of the largest
independent terminalling and storage operators in the United States in terms of capacity available for service. Our terminal
network comprises more than 120 liquid petroleum products terminals with aggregate storage capacity of over 115 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 and in the Caribbean. Our 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”), formerly known as Bahamas Oil Refining Company International Limited
(“BORCO”), is one of the largest marine crude oil and refined petroleum products storage facilities in the world and provides
an array of logistics and blending services for 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. Our recent
acquisition of an indirect 50% equity interest in VTTI B.V. (“VTTI”) expands our international presence with premier storage
and marine terminalling services for petroleum products predominantly located in key global energy hubs, including Northwest
Europe, the United Arab Emirates and Singapore. We are also a wholesale distributor of refined petroleum products in areas
served by our pipelines and terminals.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
We adhere to the following significant accounting policies in the preparation of our consolidated financial statements:
Basis of Presentation and Principles of Consolidation
The consolidated financial statements and the accompanying notes are prepared in accordance with accounting principles
generally accepted in the United States of America (“GAAP”) and the rules of the U.S. Securities and Exchange Commission
(“SEC”). The consolidated financial statements include the accounts of our subsidiaries controlled by us and variable interest
entities (“VIEs”) of which we are the primary beneficiary. A VIE is required to be consolidated by its primary beneficiary
which is generally defined as the party who has (i) the power to direct the activities of a VIE that most significantly impact the
VIE’s economic performance and (ii) the obligation to absorb losses of the VIE or the right to receive benefits that could
potentially be significant to the VIE. We evaluate our relationships with our VIEs on an ongoing basis to determine whether we
continue to be the primary beneficiary. Third party or affiliate ownership interests in our subsidiaries and consolidated VIEs are
presented as noncontrolling interests. All intercompany transactions are eliminated in consolidation.
Asset Retirement Obligations
We regularly assess our legal obligations with respect to estimated retirements of certain of our long-lived assets to
determine if an asset retirement obligation (“ARO”) exists. The fair value of a liability related to the retirement of long-lived
assets is recorded at the time a regulatory or contractual obligation is incurred, including obligations to perform an asset
retirement activity in which the timing or method of settlement are conditional on a future event that may or may not be within
the control of the entity. If an ARO is identified and a liability is recorded, a corresponding asset is recorded concurrently and
is depreciated over the remaining useful life of the asset. After the initial measurement, the liability is periodically adjusted for
costs incurred or settled, accretion expense, and any revisions made to the assumptions related to the retirement costs.
Generally, the fair value of the liability is determined based on estimates and assumptions related to: (i) future retirement costs;
(ii) future inflation rates; and (iii) credit-adjusted risk-free interest rates.
67
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Our assets generally consist of terminals that we own and underground liquid petroleum products pipelines installed along
rights-of-way acquired from land owners and related above-ground facilities. The significant majority of our rights-of-way
agreements do not require the dismantling and removal of the pipelines and reclamation of the rights-of-way upon permanent
removal of the pipelines from service. In addition, we assume substantially all of our common carrier properties operate
indefinitely, as these assets generally serve in high-population and high-demand markets. Accordingly, other than with respect
to facilities that are expected to be taken out of service, we have recorded no liabilities, or corresponding assets because the
future dismantlement and removal dates of the majority of our assets, and the amount of any associated costs, are
indeterminable. The ARO liability represents our best estimate of the costs to be incurred with information currently available
and is based on certain assumptions, including: (i) timing of retirement of assets; (ii) methods of abandonment to be employed;
and (iii) if applicable, our requirements under right-of-way agreements; therefore, it is likely that the ultimate costs to settle this
liability will be different and such differences could be material.
The following table presents information regarding our AROs (in thousands):
ARO liability balance, January 1, 2015.................................................................................................................. $
Increase in ARO liability (1) ................................................................................................................................
ARO settlements ..................................................................................................................................................
ARO liability balance, December 31, 2015 (2) ......................................................................................................
Decrease in ARO liability (3)...............................................................................................................................
ARO settlements ..................................................................................................................................................
ARO liability balance, December 31, 2016 (2) ...................................................................................................... $
3,663
4,200
(1,040)
6,823
(117)
(723)
5,983
____________________________
(1) In 2015, we recorded an ARO of $4.2 million in connection with the acquisition of a pipeline in Springfield,
Massachusetts. See Note 3 for further information.
(2) Amount includes $2.6 million and $1.4 million within “Accrued and other current liabilities” and $3.4 million and
$5.4 million within “Other non-current liabilities” in the accompanying consolidated balance sheets as of December 31,
2016 and 2015, respectively.
(3) Amount includes the net impact of revised estimated costs of abandonment for our Springfield and NORCO pipeline
systems, as well as an ARO of $1.1 million recorded in connection with the removal of previously idled lines that run
under the Delaware River.
Business Combinations
We allocate the total purchase price of a business combination to the assets acquired and the liabilities assumed based on
their estimated fair values at the acquisition date, with the excess purchase price recorded as goodwill. For all material
acquisitions, we engage an independent valuation specialist to assist us in determining the fair value of the assets acquired and
liabilities assumed, including goodwill, based on recognized business valuation methodology. If the initial accounting for the
business combination is incomplete by the end of the reporting period in which the acquisition occurs, an estimate will be
recorded. Subsequent to the acquisition, and not later than one year from the acquisition date, we will record any material
adjustments to the initial estimate in the reporting period in which the adjustment amounts are determined based on new
information obtained about facts and circumstances that existed as of the acquisition date. 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. Also, we
expense any acquisition-related costs as incurred in connection with each business combination.
Business Segments
We operate and report in three business segments: (i) Domestic Pipelines & Terminals; (ii) Global Marine Terminals; and
(iii) Merchant Services. See Note 25 for discussion of our business segments.
68
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Capitalization of Interest
Interest on borrowed funds is capitalized on projects during construction based on the approximate average interest rate of
our debt. Interest capitalized for the years ended December 31, 2016, 2015 and 2014 was $4.4 million, $21.3 million and
$9.9 million, respectively. The weighted average rates used to capitalize interest on borrowed funds was 4.6%, 4.8% and 4.9%
for the years ended December 31, 2016, 2015 and 2014, respectively.
Cash and Cash Equivalents
Cash equivalents represent all highly marketable securities with original maturities of three months or less. The carrying
value of cash equivalents approximates fair value because of the short-term nature of these investments.
Comprehensive Income
Our comprehensive income is determined based on net income adjusted for unrealized gains and losses on derivative
instruments for our cash flow hedging transactions, reclassification of derivative gains and losses to net income, recognition of
costs related to our pension and post-retirement benefit plans and adjustments to the funded status of our pension and post-
retirement benefit plans.
Concentration of Credit Risk and Trade Receivables
Trade receivables of $228.5 million and $199.5 million as of December 31, 2016 and 2015, respectively, are primarily due
from major oil and natural gas companies, national oil companies, refiners, marketing and trading companies, and commercial
airlines. These concentrations of customers may affect our overall credit risk as these customers may be similarly affected by
changes in economic, regulatory or other factors. We extend credit to customers and manage our credit risks through credit
analysis and monitoring procedures, including credit approvals, credit limits and right of offset. Also, we manage our risk using
collateral, such as letters of credit, prepayments, liens on customer assets and guarantees.
Trade receivables represent valid claims against non-affiliated customers and are recognized when products are sold or
services are rendered. We record an allowance for doubtful accounts for estimated losses resulting from the inability of our
customers to make required payments. We review the adequacy of the allowance for doubtful accounts monthly by making
judgments regarding future events and trends based on the: (i) customers’ historical relationship with us; (ii) customers’ current
financial condition; and (iii) current and projected economic conditions.
The following table presents activity in the allowance for doubtful accounts at the dates indicated (in thousands):
Balance at beginning of period........................................................................ $
Charged to expense..........................................................................................
Write-offs, net of recoveries............................................................................
Balance at end of period .................................................................................. $
8,380
$
5,784
$
2,143
(2,563)
7,960
$
2,983
(387)
8,380
$
2,019
3,985
(220)
5,784
December 31,
2016
2015
2014
Construction and Pipeline Relocation Receivables
Construction and pipeline relocation receivables represent valid claims against non-affiliated customers for services
rendered in constructing or relocating pipelines and are recognized when services are rendered.
69
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Contingencies
Certain conditions may exist as of the date our consolidated financial statements are issued that may result in a loss to us,
but which will only be resolved when one or more future events occur or fail to occur. Our management, with input from legal
counsel, assesses such contingent liabilities, and such assessment inherently involves judgment. In assessing loss contingencies
related to legal proceedings that are pending against us or unasserted claims that may result in proceedings, our management,
with input from legal counsel, evaluates the perceived merits of any legal proceedings or unasserted claims as well as the
perceived merits of the amount of relief sought or expected to be sought therein.
If the assessment of a contingency indicates that it is probable that a loss has been incurred and the amount of liability can
be estimated, then the estimated liability is accrued in our consolidated financial statements. If the assessment indicates that a
potentially material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the
nature of the contingent liability, together with an estimate of the range of possible loss if determinable and material, is
disclosed. Actual results could vary from these estimates and judgments.
Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the
guarantees would be disclosed.
Cost of Product Sales
Cost of product sales relates to sales of refined petroleum products, consisting primarily of gasoline, propane, ethanol,
biodiesel and middle distillates, such as heating oil, diesel fuel and kerosene, and fuel oil, as well as the effects of hedges of
refined petroleum product acquisition costs and hedges of fixed-price contracts.
Debt Issuance Costs
Costs incurred upon the issuance of our debt instruments are capitalized and amortized over the life of the associated debt
instrument on a straight-line basis, which approximates the effective interest method. If the debt instrument is retired before its
scheduled maturity date, any remaining issuance costs associated with that debt instrument are expensed in the same period.
Debt issuance costs related to our existing $1.5 billion revolving credit facility with SunTrust Bank, as administrative agent,
and other lenders dated September 30, 2014 (the “Credit Facility”), are reported in “Other non-current assets”. Debt issuance
costs related to our outstanding notes and our $250.0 million variable-rate term loan with SunTrust Bank, as administrative
agent, and other lenders due September 30, 2019 (the “Term Loan”) are reported in “Long-term debt” as a direct deduction
from the carrying amount of our outstanding notes.
Derivative Instruments
Derivatives are financial and physical instruments whose fair value is determined by changes in a specified benchmark
such as interest rates or commodity prices. We use derivative instruments such as forwards, futures, swaps and other contracts
to manage market price risks associated with inventories, firm commitments, interest rates and certain forecasted transactions.
We do not engage in speculative trading activities.
We recognize these transactions on our consolidated balance sheets as assets and liabilities based on the instrument’s fair
value. Changes in fair value of derivative instrument contracts are recognized in the current period in earnings unless specific
hedge accounting criteria are met. If the derivative instrument is designated as a hedging instrument in a fair value hedge, gains
and losses incurred on the instrument will be recorded in earnings to offset corresponding losses and gains on the hedged item.
If the derivative instrument is designated as a hedging instrument in a cash flow hedge, gains and losses incurred on the
instrument are recorded in other comprehensive income. Any gains or losses incurred on the derivative instrument that are not
effective in offsetting changes in fair value or cash flows of the hedged item are recognized immediately in earnings. Gains and
losses on cash flow hedges are reclassified from accumulated other comprehensive income (“AOCI”) to earnings when the
forecasted transaction occurs and affects net income or, as appropriate, over the economic life of the underlying asset or
liability. Gains and losses related to a derivative instrument designated as a hedge of a forecasted transaction that is no longer
likely to occur is immediately recognized in earnings. Physical forward contracts and futures contracts that have not been
designated in a hedge relationship are marked-to-market.
70
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
To qualify as a hedge, the item to be hedged must expose us to risk and we must have an expectation that the related
hedging instrument will be effective at reducing or mitigating that exposure. In accordance with the hedging requirements, we
document all hedging relationships at inception and include a description of the risk management objective and strategy for
undertaking the hedge, identification of the hedging instrument, the hedged item, the nature of the risk being hedged, the
method for assessing effectiveness of the hedging instrument in offsetting the hedged risk and the method of measuring any
ineffectiveness. We link all derivative instruments that are designated as fair value or cash flow hedges to specific assets and
liabilities on our consolidated balance sheets or to specific firm commitments or forecasted transactions. When an event or
transaction occurs, such as the sale of hedged fuel inventory or the expiration of derivative contracts, we discontinue hedge
accounting. We also formally assess, both at the hedge’s inception and on an ongoing basis, whether the derivative instruments
that are used in designated hedging relationships are highly effective in offsetting changes in fair values or cash flows of hedged
items. If it is determined that a derivative instrument is not highly effective as a hedge or that it has ceased to be a highly
effective hedge, we discontinue hedge accounting prospectively. We measure ineffectiveness by comparing the change in fair
value of the hedge instrument to the change in fair value of the hedged item. The time value component is excluded from our
hedge assessment and reported directly in earnings.
Discontinued Operations
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. The results of operations for our Natural
Gas Storage disposal group have been segregated and presented as discontinued operations for all periods presented in these
financial statements. On December 31, 2014, we completed the sale of our Natural Gas Storage disposal group and have
reported the final working capital adjustments as discontinued operations in the first quarter of 2015. See Note 4 and Note 5 for
additional information.
Earnings per Unit
Basic earnings per unit from continuing operations, which includes LP Units, is determined by dividing our income from
continuing operations, after deducting the amount allocated to noncontrolling interests, by the weighted average units
outstanding for the period. Diluted earnings per unit from continuing operations is calculated using the same methodology,
except the weighted average units outstanding includes any dilutive effect of LP Unit option grants or grants under the 2013
Long-Term Incentive Plan of Buckeye Partners, L.P. (the “LTIP”). A similar calculation is performed for basic and diluted
earnings per unit from discontinued operations, except loss from discontinued operations is divided by the weighted average
units outstanding for the period.
Environmental Expenditures
We are subject to federal, state and local laws and regulations relating to the protection of the environment, which require
us to remove or remedy the effect of the disposal or release of specified substances at our operating sites. We record
environmental liabilities at a specific site when environmental assessments indicate remediation efforts are probable, and costs
can be reasonably estimated based upon past experience, discussions with operating personnel, advice of outside engineering
and consulting firms, discussion with legal counsel or current facts and circumstances. The estimates related to environmental
matters are uncertain because: (i) estimated future expenditures are subject to cost fluctuations and change in estimated
remediation period; (ii) unanticipated liabilities may arise; and (iii) changes in federal, state and local environmental laws and
regulations may significantly change the extent of remediation.
Our estimated environmental remediation liabilities are not discounted to present value since the ultimate amount and
timing of cash payments for such liabilities are not readily determinable. Expenditures to mitigate or prevent future
environmental contamination are capitalized. We monitor the environmental liabilities regularly and record adjustments to our
initial estimates, from time to time, to reflect changing circumstances and estimates based upon additional developments or
information obtained in subsequent periods. We maintain insurance which may cover certain environmental expenditures.
Recoveries of environmental remediation expenses from other parties are recorded when their receipt is deemed probable.
71
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Equity Investments
We account for investments in entities in which we do not exercise control, but have significant influence, using the equity
method of accounting. Under this method, an investment is recorded at acquisition cost plus our equity in undistributed
earnings or losses since acquisition, reduced by distributions received and amortization of excess net investment.
Excess investment is the amount by which the total investment exceeds the proportionate share of the book value of the net
assets of the investment. Such excess investment not related to any specific accounts of the investee are treated as goodwill and
not amortized. Amounts associated with specific accounts of the investee are amortized. We evaluate equity method
investments for impairment whenever events or changes in circumstances indicate that there is an “other than temporary” loss
in value of the investment. In the event that the loss in value of an investment is “other than temporary”, we record a charge to
earnings to adjust the carrying value to fair value. Estimates of future cash flows that would be used to determine fair value
include: (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses; (ii) long-
term growth rates; and (iii) probabilities assigned to different cash flow scenarios. A significant change in these underlying
assumptions could result in an impairment charge. There were no impairments of our equity investments for the years ended
December 31, 2016, 2015 or 2014.
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.
Fair Value Measurements
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly
transaction between market participants at a specified measurement date. Our fair value estimates are based on either: (i) actual
market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of
risk. Recognized valuation techniques employ inputs such as product prices, operating costs, discount factors and business
growth rates. These inputs may be either readily observable, corroborated by market data or generally unobservable.
In developing our estimates of fair value, we endeavor to utilize the best information available and apply market-based data to
the extent possible. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the
use of unobservable inputs.
A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial
statements based on the observability of inputs used to estimate such fair values. The characteristics of fair value amounts
classified within each level of the hierarchy are described as follows:
• Level 1 inputs — unadjusted quoted prices which are available in active markets for identical, unrestricted assets or
liabilities as of the reporting date;
• Level 2 inputs — quoted market prices in markets that are not considered to be active or financial instruments for
which all significant inputs are observable, either directly or indirectly; and
• Level 3 inputs — prices or valuations that require inputs that are both significant to the fair value measurement and
unobservable. These inputs are typically used in connection with internally developed valuation methodologies where
management makes its best estimate of an instrument’s fair value.
We categorize our financial assets and liabilities using this hierarchy at each balance sheet reporting date.
72
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Foreign Currency
Puerto Rico is a commonwealth country under the U.S., and thus uses the U.S. dollar as its official currency.
The functional currency of our operations in BBH and St. Lucia is the U.S. dollar. Foreign exchange gains and losses arising
from transactions denominated in a currency other than the U.S. dollar relate to a nominal amount of supply purchases and are
included in “Other income (expense)” within the consolidated statements of operations. The effects of foreign currency
transactions were not considered to be material for the years ended December 31, 2016, 2015 and 2014.
Goodwill
Goodwill represents the excess of purchase price over fair value of net assets acquired. Our goodwill amounts are assessed
for impairment: (i) on an annual basis on October 31st each year or (ii) on an interim basis if circumstances indicate it is more
likely than not the fair value of a reporting unit is less than its fair value.
Goodwill is tested for impairment at a level of reporting referred to as a reporting unit. A reporting unit is a business
segment or one level below a business segment for which discrete financial information is available and regularly reviewed by
segment management. Our reporting units are our business segments, with the exception of our Global Marine Terminals
segment. Our reporting units to which goodwill has been allocated in our Global Marine Terminals segment consist of the
following: (i) our operations in the Caribbean and New York Harbor; and (ii) our operations in Buckeye Texas.
We may perform a qualitative assessment to determine whether the fair value of our reporting units are more likely than not
less than the carrying amount. If we believe the fair value is less than the carrying amount, we will perform step one of the
two-step goodwill impairment test. The first step of the goodwill impairment test determines whether an impairment exists by
comparing the fair value of a reporting unit with its carrying amount, including goodwill. If the estimated fair value of the
reporting unit exceeds its carrying amount, no impairment is indicated. If the carrying amount of a reporting unit exceeds its
estimated fair value, an impairment is indicated and the second step of the test is performed to measure the amount of
impairment by comparing the implied fair value of the reporting unit goodwill to the carrying amount of that goodwill. The fair
value of the reporting unit is allocated to all of the assets and liabilities of that unit as if the reporting unit had been acquired in
a business combination. The excess of the fair value of the reporting unit over the amounts assigned to its assets and liabilities
is the implied fair value of goodwill. The estimate of the fair value of the reporting unit is determined using a combination of
an expected present value of future cash flows and a market multiple valuation method. The present value of future cash flows
is estimated using: (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses;
(ii) long-term growth rates; and (iii) appropriate discount rates. The market multiple valuation method uses appropriate market
multiples from comparable companies on the reporting unit’s earnings before interest, tax, depreciation and amortization.
We evaluate industry and market conditions for purposes of weighting the income and market valuation approach.
Income Taxes
For U.S. federal income tax purposes, we and each of our subsidiaries, except for Buckeye Development & Logistics I
LLC (“BDL”), are not taxable entities. Accordingly, our taxable income, except for BDL, is generally includable in the U.S.
federal income tax returns of our individual partners and may differ significantly from taxable income reportable to our
unitholders as a result of differences between the tax basis and financial reporting basis of certain assets and liabilities and other
factors. In certain states in which we operate, our operating subsidiaries directly incur income-based state taxes, which are
subject to examination by state taxing authorities.
73
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In addition, outside the continental U.S., our operations at BBH and St. Lucia are exempt from income taxes. Our
operations at BBH are tax exempt by the Bahamian government pursuant to concessions granted under the Hawksbill Creek
Agreement between the Government of The Bahamas and the Grand Bahama Port Authority. These concessions expired in
May 2016 but have been extended through May 2036 by the Grand Bahama Investment Incentives Act, subject to an
application process that must be completed by March 2017. Our operations in St. Lucia are exempt from income taxes and
duties pursuant to concessions granted under the terms of a tax concession agreement effective in 2007 and in effect for a
minimum of 50 years. Our operations at the Yabucoa terminal are subject to income taxes within the Commonwealth of Puerto
Rico. Buckeye Caribbean Terminals LLC (“Buckeye Caribbean”) files annual income tax returns with the Puerto Rico
Treasury Department and in 2002, was granted partial exemption under the Tax Incentives Act of 1998 (the “Act”). Under the
current terms of the grant, Buckeye Caribbean is subject to an income tax rate of 4% to 7% on industrial development income.
The grant also provides additional exemptions as follows: (i) 90% exempt from real and personal property taxes; (ii) 60%
exempt from municipal taxes on industrial development income; and (iii) 100% exempt from excise taxes imposed under
Subtitle C of the Puerto Rico Internal Revenue Code, to the extent provided in Section 6(c) of the Act. This favorable tax rate
is scheduled to expire in 2022.
We recognize deferred tax assets and liabilities for temporary differences between the amounts of assets and liabilities
measured for financial reporting purposes and federal income tax purposes. Changes in tax legislation are included in the
relevant computations in the period in which such changes are effective. We evaluate the need for a valuation allowance and
consider all available positive and negative evidence, including projected operating income or losses for the foreseeable future,
to determine the likelihood of realizing the benefits of deferred tax assets. If the value of the deferred tax assets exceeds the
estimated future benefit, we record a valuation allowance to reduce our deferred tax assets to the amount of future benefit that is
more likely than not to be realized. In the future, if the realization of the deferred tax assets should occur, a reduction to the
valuation allowance related to the deferred tax assets would increase net income in the period such determination is made.
Our current and deferred income tax expense (benefit) was $(0.2) million and $1.7 million, respectively, for the year ended
December 31, 2016, $1.6 million and $(0.7) million, respectively, for the year ended December 31, 2015 and $0.7 million and
($0.2) million, respectively, for the year ended December 31, 2014. We have no unrecognized tax benefits related to uncertain
tax positions.
Intangible Assets
Intangible assets with finite useful lives are reviewed for impairment when events or changes in circumstances indicate that
the carrying amount of such assets may not be recoverable. Intangible assets that have finite useful lives are amortized over
their useful lives. Intangible assets include contracts and customer relationships. The fair values of these intangibles are based
on the present value of cash flows attributable to the customer relationship or contract, which includes management’s estimates
of revenue and operating expenses and costs relating to utilization of other assets to fulfill such contracts. The customer
contracts are being amortized over their contractual lives with a range of 1 to 10 years. For the customer relationships, we
determine the recovery period based on historical customer attrition rates and management’s assumptions on future events,
including customer demand, contract renewal, useful lives of related assets and market conditions. The customer relationships
are being amortized over the estimated recovery period of 12 to 20 years. When necessary, intangible assets’ useful lives are
revised and the impact on amortization is reflected on a prospective basis.
Inventories
We generally maintain two types of inventory. Our Merchant Services segment principally maintains refined petroleum
products inventory, consisting of gasoline, propane, ethanol, biodiesel and middle distillates, such as heating oil, diesel fuel and
kerosene. Inventory is valued at the lower of weighted average cost or net realizable value, unless such inventories are
hedged. Net realizable value is defined as the estimated selling price in the ordinary course of business, less reasonably
predictable costs of completion, disposal and transportation. Hedged inventory is adjusted for the effects of applying fair value
hedge accounting.
We also maintain, principally within our Domestic Pipelines & Terminals segment, an inventory of materials and supplies
such as pipes, valves, pumps, electrical/electronic components, drag reducing agent and other miscellaneous items that are
valued at the lower of weighted average cost or net realizable value.
74
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Long-Lived Assets
We assess the recoverability of our long-lived assets whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable. We determine the estimated undiscounted future cash flows expected to
result from the use of the asset and its eventual disposal. If the sum of the estimated undiscounted future cash flows exceeds
the carrying amount, no impairment is necessary. If the carrying amount exceeds the sum of the undiscounted cash flows, an
impairment charge is recognized based on the amount by which the carrying amount of the assets exceeds the estimated fair
value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or estimated fair value less costs
to sell. Estimates of undiscounted future cash flows include: (i) discrete financial forecasts, which rely on management’s
estimates of revenue and operating expenses; (ii) long-term growth rates; and (iii) estimates of useful lives of the assets. Such
estimates of future undiscounted net cash flows are highly subjective and are based on numerous assumptions about future
operations and market conditions.
Net Income Allocation
We allocate the net income attributable to Buckeye to the LP Unitholders based on the weighted average LP Units
outstanding during the period.
Noncontrolling Interests
The consolidated balance sheets and statements of operations include noncontrolling interests that relate primarily to
Buckeye Texas, Buckeye Pipe Line Services Company (“Services Company”) and the Sabina crude butadiene pipeline (the
“Sabina Pipeline”) that are not owned by Buckeye. In April 2015, our operating subsidiary, Buckeye Pipe Line Holdings, L.P.
(“BPH”), purchased from Kealine LLC the remaining 10% ownership interest in Buckeye Aviation (Memphis) LLC, formerly
known as WesPac Pipelines - Memphis LLC. As a result of the acquisition, we now own 100% of Buckeye Aviation
(Memphis) LLC. See Note 3 for further information.
Pensions and Postretirement Benefits
Services Company sponsors a defined contribution plan, a defined benefit plan and the Employee Stock Ownership Plan
(“ESOP”) that provide retirement benefits to certain regular full-time employees. Services Company also sponsors an unfunded
post-retirement plan that provides health care and life insurance benefits for certain of its retirees. We develop pension and
postretirement health care and life insurance benefits costs from actuarial valuations. The measurement of expenses and
liabilities related to these plans is based on management’s assumptions related to future events, including discount rate,
expected return on plan assets, rate of compensation increase, and health care cost trend rates. The actuarial assumptions that
we use may differ from actual results due to changing market rates or other factors. These differences could affect the amount
of pension and postretirement health care and life insurance benefit expense we have recorded or may record.
Property, Plant and Equipment
We record property, plant and equipment at its original acquisition cost. Property, plant and equipment consist primarily of
pipelines, terminals, storage and processing facilities, jetties, subsea pipelines and docks, and pumping and station equipment.
Generally, we depreciate property, plant and equipment based on the straight-line method over the estimated useful lives, except
for land. See Note 9 for the depreciation life of our assets.
Additions to property, plant and equipment, including maintenance and expansion and cost reduction capital expenditures,
are recorded at cost. Maintenance capital expenditures maintain and enhance the safety and integrity of our pipelines,
terminals, storage and processing facilities, and related assets, and expansion and cost reduction capital expenditures expand the
reach or capacity of those assets, to improve the efficiency of our operations and to pursue new business opportunities. We
charge repairs to expense in the period incurred. The cost of property, plant and equipment sold or retired and the related
depreciation, except for certain pipeline system assets, are removed from our consolidated balance sheet in the period of sale or
disposition, and any resulting gain or loss is included in earnings. For our pipeline system assets, we generally charge the
original cost of property sold or retired to accumulated depreciation and amortization, net of salvage and cost of removal.
When a separately identifiable group of assets, such as a stand-alone pipeline system is sold, we will recognize a gain or loss in
our consolidated statements of operations for the difference between the cash received and the net book value of the assets sold.
75
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Recent Accounting Developments
Goodwill Impairment. In January 2017, the Financial Accounting Standards Board (“FASB”) issued guidance simplifying
the test for goodwill impairment. The guidance eliminates Step 2 from the goodwill impairment test, which required entities to
calculate the implied fair value of a reporting unit's goodwill by assigning the fair value of a reporting unit to all of its assets
and liabilities as if that reporting unit had been acquired in a business combination. Under the new guidance, entities will
recognize an impairment charge for the amount by which the fair value of a reporting unit exceeds its carrying amount. The
guidance must be applied using a prospective approach and is effective for interim and annual goodwill impairment tests in
fiscal years beginning after December 15, 2019, with early adoption permitted. We do not believe our adoption of this guidance
will have a material impact on our consolidated financial statements or on our disclosures.
Business Combinations. In January 2017, the FASB issued guidance clarifying the definition of a business in order to
assist entities with evaluating whether transactions should be accounted for as acquisitions/disposals of assets or businesses.
The guidance provides a screen to help entities determine when an integrated set of assets and activities is not a business. The
screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a
single identifiable asset or a group of similar identifiable assets, the set of assets is not a business. If the threshold of the screen
is not met, the guidance further clarifies that the set of assets is not a business unless it includes an input and a substantive
process that together significantly contribute to the ability to create output. The guidance must be applied using a prospective
approach and is effective for annual reporting periods beginning after December 15, 2017 and interim periods within those
annual periods, with early adoption permitted for specific transactions. We are currently evaluating the impact the adoption of
this guidance will have on our consolidated financial statements.
Statement of Cash Flows. In August 2016, the FASB issued guidance to address how certain cash receipts and cash
payments are presented and classified in the statement of cash flows, with the objective of reducing existing diversity in
practice with respect to these items. The guidance must be applied retrospectively, and it is effective for annual reporting
periods beginning after December 15, 2017 and interim periods within those annual periods, with early adoption permitted. We
are currently evaluating the impact the adoption of this guidance will have on our consolidated financial statements.
Equity-Based Compensation. In March 2016, the FASB issued guidance to simplify several aspects of the accounting for
employee equity-based payment transactions, including the accounting for income taxes, forfeitures and statutory tax
withholding requirements, as well as classification in the statement of cash flows and classification of awards as liabilities or
equity. The guidance is effective for annual reporting periods beginning after December 15, 2016 and interim periods within
those annual periods, with early adoption permitted. Amendments related to the timing of when excess tax benefits are
recognized, statutory withholding requirements and forfeitures should be applied using a modified retrospective transition
method by means of a cumulative-effect adjustment to equity as of the beginning of the period in which the guidance is
adopted. Amendments related to the presentation of employee taxes paid on the statement of cash flows should be applied
retrospectively. Amendments requiring recognition of excess tax benefits and tax deficiencies in the income statement should
be applied prospectively. Amendments related to the presentation of excess tax benefits on the statement of cash flows may be
applied using either a prospective transition method or a retrospective transition method. We do not believe our adoption of this
guidance will have a material impact on our consolidated financial statements or on our disclosures.
Leases. In February 2016, the FASB issued guidance requiring lessees to recognize assets and liabilities for leases with
lease terms greater than twelve months in the statement of financial position. This update also requires enhanced disclosures
regarding the amount, timing and uncertainty of cash flows arising from leases. The guidance must be applied using a modified
retrospective approach and is effective for annual reporting periods beginning after December 15, 2018 and interim periods
within those annual periods, with early adoption permitted. We are currently evaluating the impact the adoption of this
guidance will have on our consolidated financial statements.
76
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Revenue from Contracts with Customers. In May 2014, the FASB issued Accounting Standards Update No. 2014-09,
“Revenue from Contracts with Customers (Topic 606)” (“ASU 2014-09”), which amended existing accounting standards for
revenue recognition, including industry-specific requirements, and provides entities with a single revenue recognition model for
recognizing revenue from contracts with customers. The core principle of ASU 2014-09 is that an entity should recognize
revenue from contracts with customers when it transfers promised goods or services to customers in an amount that reflects the
consideration to which the entity expects to be entitled in exchange for those goods or services. Furthermore, additional
disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows arising from
customer contracts. The two permitted transition methods under ASU 2014-09 are the full retrospective method, which would
be applied to each prior reporting period presented and the cumulative effect of applying the standard would be recognized at
the earliest period shown, or the modified retrospective method, in which the cumulative effect of applying the standard would
be recognized at the date of initial application. In July 2015, the FASB deferred the effective date of ASU 2014-09 and is
effective for annual and interim periods beginning after December 15, 2017, with early adoption permitted for annual and
interim periods beginning after December 15, 2016. In 2016, the FASB issued accounting standards updates that amended
several aspects of ASU 2014-09. We are currently evaluating the provisions of the standard and have formed an
implementation work team consisting of representatives from across all of our business segments to evaluate and implement
changes to business processes, systems and controls. In addition, we have implemented training on the new standard's revenue
recognition model and are continuing our contract review and documentation. We expect to adopt this guidance on January 1,
2018, and we are currently evaluating the impact and the transition alternatives it will have on our consolidated financial
statements.
Revenue Recognition
Domestic Pipelines & Terminals segment. Revenue from pipeline operations is comprised of tariffs and fees associated
with the transportation of liquid petroleum products or crude oil at published tariffs as well as revenue associated with line
leases for committed capacity on a particular system. Tariff revenue is recognized either at the point of delivery or at the point
of receipt, pursuant to specifications outlined in the respective tariffs. Revenue associated with line leases is recognized ratably
over the respective lease terms, regardless of whether the capacity is actually utilized, and is subject to take-or-pay
arrangements. All pipeline tariff and fee revenue is based upon actual volumes and rates. As is common in the industry, our
tariffs incorporate loss allocation or loss allowance factors that are intended to, among other things, offset losses due to
evaporation, measurement and other product losses in transit. We value the variance of allowance volumes to actual losses at
the estimated net realizable value at the time the variance occurred, and the result is recorded as either an increase or decrease
to transportation and other service revenue. In addition, we have certain agreements that require counterparties to ship a
minimum volume over an agreed-upon period. Revenue pursuant to such agreements is recognized at the earlier of when the
volume is shipped or when the counterparty’s ability to meet the minimum volume commitment has expired.
Revenue from terminalling and storage operations is recognized as services are performed. Storage and terminalling
revenue include storage fees, which are generated when we provide storage capacity, and terminalling or throughput fees,
which are generated when we receive liquid petroleum products from one connecting pipeline and redeliver such products to
another connecting carrier or to customers through a truck-loading rack. We generate revenue through a combination of month-
to-month and multi-year storage capacity and terminalling service arrangements. Storage fees resulting from short-term and
long-term contracts are typically recognized in revenue ratably over the term of the contract, regardless of the actual storage
capacity utilized. Terminalling fees are recognized as the refined petroleum product or crude oil exits the terminal and is
delivered to a connecting carrier, third-party terminal or a customer through a truck-loading rack. In addition, we have certain
agreements that require counterparties to throughput a minimum volume over an agreed-upon period. Revenue pursuant to
such agreements is recognized at the earlier of when the volume exits the terminal or when the counterparty’s ability to meet the
minimum volume commitment has expired. Butane blending revenues are recognized as blending activities are completed and
include the change in the fair value of financial derivative instruments used to manage the commodity price risk associated with
narrowing gasoline-to-butane pricing spreads.
Revenue from contract operation and construction services of facilities and pipelines not directly owned by us is
recognized as the services are performed. Contract and construction services revenue typically includes costs to be reimbursed
by the customer plus an operator fee.
77
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Global Marine Terminals segment. Revenue from terminalling and storage operations is recognized as the services are
performed. Storage and terminalling revenue includes storage fees, which are generated when we provide storage capacity, and
terminalling or throughput fees, which are generated when we receive liquid petroleum products from sea going vessels,
pipelines, trucks, or rail and redeliver such products to customers through marine applications, truck-loading racks, and
pipelines. We generate revenue through a combination of storage capacity, terminalling and tolling service arrangements.
Storage fees resulting from short-term and long-term contracts are typically recognized in revenue ratably over the term of the
contract, regardless of the actual storage capacity utilized. Terminalling fees are recognized as the liquid petroleum product
exits the terminal and is delivered to a connecting carrier, third-party terminal or a customer through a truck-loading rack or
vessel. Tolling agreement fees are recognized ratably over the term of the contract and are based on minimum volume and
product specification requirements. In addition, we have agreements that require counterparties to throughput a minimum
volume over an agreed-upon period. Revenue pursuant to such agreements is recognized at the earlier of when the volume exits
the terminal or when the counterparty’s ability to meet the minimum volume has expired. Revenue from other ancillary
services is recognized in the accounting period in which the services are rendered.
Merchant Services segment. Revenue from the sale of petroleum products, including fuel oil, which are sold on a
wholesale basis, is recognized at the time title to the product sold transfers to the purchaser, which occurs upon delivery of the
product to the purchaser or its designee. We enter into exchange contracts and matching buy/sell arrangements whereby we
agree to deliver a particular quantity and quality of crude oil or refined products at a specified location and date to a particular
counterparty and to receive from the same counterparty the same or similar commodity at a specified location on the same or
another specified date. The exchange receipts and deliveries are nonmonetary transactions, with the exception of associated
grade or location differentials that are settled in cash. The matching buy/sell purchase and sale transactions are settled in cash.
Both exchange and matching buy/sell transactions are accounted for as exchanges of inventory, and pricing differentials are
recorded in “Product sales” revenues. The exchange transactions are recognized at the carrying amount of the inventory
transferred.
Unit-Based Compensation
We award unit-based compensation to employees and directors primarily under the LTIP. All unit-based payments to
employees under the LTIP, including grants of phantom units and performance units, are recognized in our consolidated
statements of operations based on their fair values. The fair values of both the performance unit and phantom unit grants are
based on the average market price of our LP Units on the date of grant as adjusted for certain market-based conditions.
Compensation expense equal to the fair value of those performance unit and phantom unit awards that are expected to vest is
estimated and recorded over the period the grants are earned, which is the vesting period. Compensation expense estimates are
updated periodically. The vesting of the performance unit awards is also contingent upon the attainment of predetermined
performance goals. Depending on the estimated probability of attainment of those performance goals, the compensation
expense recognized related to the awards could increase or decrease over the remaining vesting period.
Variable Interest Entities
We evaluate our financial interests in business enterprises to determine if they represent VIEs of which we are the primary
beneficiary. If such criteria are met (as discussed above in “Basis of Presentation and Principles of Consolidation”), we reflect
these entities as consolidated subsidiaries. There were no changes to the entities consolidated for the year ended December 31,
2016.
Buckeye Texas and Sabina Pipeline are VIEs of which we are the primary beneficiary. We own an 80% interest in Buckeye
Texas (see Note 3 for more information) and also own a 63% interest in Sabina Pipeline. Third party or affiliate ownership
interests in our consolidated VIEs are presented as noncontrolling interests.
78
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3. ACQUISITIONS AND DISPOSITION
Business Combinations
2016 Transaction
Indianola terminalling facility acquisition
In August 2016, we acquired a liquid petroleum products terminalling facility in Indianola, Pennsylvania from Kinder
Morgan Transmix Company, LLC for $26.0 million. The operations of these assets are reported in our Domestic Pipelines &
Terminals segment. The acquisition cost has been allocated on a preliminary basis to assets acquired based on estimated fair
values at the acquisition date, with amounts exceeding the fair value recorded as goodwill, which represent expected synergies
from combining the acquired assets with our existing operations. Fair values have been developed using recognized business
valuation techniques. The estimates of fair value reflected as of December 31, 2016 are subject to change pending final
valuation analysis. The purchase price has been allocated to tangible and intangible assets acquired as follows (in thousands):
Inventories .............................................................................................................................................................. $
Property, plant and equipment................................................................................................................................
Goodwill .................................................................................................................................................................
Allocated purchase price ...................................................................................................................................... $
1,554
16,713
7,758
26,025
Adjustments to the preliminary purchase price allocation during the fourth quarter of 2016 resulted in a decrease to
property, plant and equipment of $3.5 million, an increase to inventories of $0.3 million, an increase to goodwill of
$3.4 million, and an increase to the overall purchase price of $0.1 million. These adjustments resulted in a $0.2 million
increase to operating expenses as well as a nominal decrease to depreciation expense and accumulated depreciation.
Unaudited Pro forma Financial Results for the Indianola terminalling facility acquisition
Our consolidated statements of operations do not include earnings from the terminalling facility prior to August 4, 2016,
the effective acquisition date of these assets. The preparation of unaudited pro forma financial information for the terminalling
facility is impracticable due to the fact that meaningful historical revenue information is not available. The revenues and
earnings impact of this acquisition was not significant to our financial results for the year ended December 31, 2016.
79
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2015 Transactions
Pennsauken pipeline acquisition
In December 2015, we acquired a pipeline and associated tanks and other infrastructure in Pennsauken, New Jersey for
$5.3 million. The operations of these assets are reported in our Domestic Pipelines & Terminals segment. The acquisition cost
has been allocated to assets acquired and liabilities assumed based on estimated fair values at the acquisition date, with amounts
exceeding the fair value recorded as goodwill, which represent expected synergies from combining the acquired assets with our
existing operations. Fair values have been developed using recognized business valuation techniques. The purchase price has
been allocated to tangible and intangible assets acquired and liabilities assumed as follows (in thousands):
Property, plant and equipment...............................................................................................................................
Goodwill ................................................................................................................................................................
Environmental liabilities .......................................................................................................................................
Allocated purchase price ..................................................................................................................................... $
7,159
500
(2,372)
5,287
We finalized the purchase price allocation during the third quarter of 2016. Adjustments to the preliminary purchase price
allocation resulted in an increase to property, plant and equipment of $1.9 million, with a corresponding decrease to goodwill.
The change to the preliminary amount resulted in a nominal increase to depreciation expense and accumulated depreciation.
Unaudited Pro forma Financial Results for the Pennsauken pipeline acquisition
Our consolidated statements of operations do not include earnings from the pipeline and associated tanks and other
infrastructure prior to December 10, 2015, the effective acquisition date of these assets. The preparation of unaudited pro forma
financial information for the pipeline and associated tanks and other infrastructure is impracticable due to the fact that
meaningful historical revenue information is not available. The revenues and earnings impact of this acquisition was not
significant to our financial results for the year ended December 31, 2015.
Springfield pipeline and terminal acquisitions
In March and May 2015, we acquired a terminal and pipeline in Springfield, Massachusetts from ExxonMobil Oil
Corporation (“ExxonMobil”) for an aggregate $7.7 million. The operations of these assets are reported in our Domestic
Pipelines & Terminals segment. The acquisition cost has been allocated to assets acquired and liabilities assumed based on
estimated fair values at the acquisition date, with amounts exceeding the fair value recorded as goodwill, which represents both
expected synergies from combining the acquired assets with our existing operations and the economic value attributable to
optimizing, modernizing and commercializing the asset from this acquisition. Fair values have been developed using
recognized business valuation techniques. We finalized the purchase price allocation during the first quarter of 2016. The
purchase price has been allocated to tangible and intangible assets acquired and liabilities assumed as follows (in thousands):
Property, plant and equipment................................................................................................................................ $
Goodwill .................................................................................................................................................................
Asset retirement obligation.....................................................................................................................................
Environmental liabilities.........................................................................................................................................
Allocated purchase price ...................................................................................................................................... $
4,040
8,165
(4,200)
(293)
7,712
Unaudited Pro forma Financial Results for the Springfield pipeline and terminal acquisition
Our consolidated statements of operations do not include earnings from the pipeline and terminal acquired from
ExxonMobil prior to March 31, 2015 and May 5, 2015, the effective acquisition dates of the terminal and pipeline acquired
from ExxonMobil, respectively. The preparation of unaudited pro forma financial information for the terminal and pipeline
acquired from ExxonMobil is impracticable due to the fact that ExxonMobil historically operated the assets as part of its
integrated distribution network and, therefore, meaningful historical revenue information is not available. The revenues and
earnings impact of this acquisition was not significant to our financial results for the year ended December 31, 2015.
80
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2014 Transaction
Buckeye Texas Partners Transaction
In September 2014, we acquired an 80% interest in Buckeye Texas, a newly-formed entity, for $816.1 million, net of cash
acquired of $15.0 million and working capital and capital expenditure adjustments of $4.9 million required by the contribution
agreement with Trafigura Corpus Christi Holdings Inc. (the “Buckeye Texas Partners Transaction”). Buckeye Texas and its
subsidiaries, which are owned jointly with Trafigura Trading LLC, formerly known as Trafigura AG (“Trafigura”), own and
operate a vertically integrated system of midstream assets, which include 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 liquefied petroleum gas (“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 allow 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. At the time of
acquisition most of the significant assets mentioned were under construction. Construction of the significant assets and
commissioning activities were completed in late November 2015. The initial build-out of these facilities was funded through
additional partnership contributions by us and Trafigura based on our respective ownership interests. Concurrent with this
acquisition, we entered into multi-year storage and throughput commitments with Trafigura that support substantially all the
capacity and cash flows expected from these assets. At the time of acquisition, we concluded Buckeye Texas is a VIE of which
we are the primary beneficiary. In making this conclusion, we evaluated the activities that significantly impact the economics
of the VIE, including our role to perform all services reasonably required to construct, operate and maintain the assets.
We consolidated Buckeye Texas due to our conclusion that Buckeye Texas is a VIE of which we are the primary beneficiary.
The operations of these assets are reported in the Global Marine Terminals segment.
The acquisition cost has been allocated to assets acquired and liabilities assumed based on estimated fair values at the
acquisition date, with amounts exceeding the fair value recorded as goodwill, which represents both expected synergies from
combining the Buckeye Texas operations with our existing operations and the economic value attributable to future expansion
projects resulting from this acquisition. Fair values have been developed using recognized business valuation techniques.
The purchase price has been allocated to tangible and intangible assets acquired and liabilities assumed as follows (in
thousands):
Current assets.......................................................................................................................................................... $
Property, plant and equipment................................................................................................................................
Intangible assets......................................................................................................................................................
Goodwill .................................................................................................................................................................
Current liabilities ....................................................................................................................................................
Noncontrolling interests..........................................................................................................................................
Allocated purchase price ...................................................................................................................................... $
23,061
527,390
376,000
167,379
(54,943)
(207,778)
831,109
81
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Unaudited Pro forma Financial Results for the Buckeye Texas Partners Transaction
Our consolidated statements of operations do not include earnings from the assets acquired from Trafigura prior to
September 16, 2014, the effective acquisition date of the Buckeye Texas Partners Transaction. The preparation of unaudited pro
forma financial information for the Buckeye Texas Partners Transaction is impracticable due to the fact that the construction of
significant assets and commissioning activities were completed in late November 2015, therefore, meaningful historical
revenue information is not available. The revenues and earnings impact of this acquisition was not significant to our financial
results for the year ended December 31, 2014, as significant assets were still under construction.
Equity Transactions
VTTI Acquisition
In January 2017, we acquired an indirect 50% equity interest in VTTI for cash consideration of $1.15 billion (the “VTTI
Acquisition”). VTTI will be owned jointly with Vitol S.A. (“Vitol”). VTTI is one of the largest independent global marine
terminal businesses that, through its subsidiaries and partnership interests, owns and operates approximately 57 million
barrels of petroleum products storage across 14 terminals located on five continents. These marine terminals are predominately
located in key global energy hubs, including Northwest Europe, the United Arab Emirates and Singapore, and offer world-class
storage and marine terminalling services for refined petroleum products, liquid petroleum gas and crude oil. We and VIP
Terminals Finance B.V., a subsidiary of Vitol, have equal board representation and voting rights in the VTTI joint venture.
Acquisition of Remaining Interest in WesPac Pipelines - Memphis LLC
In April 2015, our operating subsidiary, BPH, purchased from Kealine LLC for $10.0 million the remaining 10%
ownership interest in Buckeye Aviation (Memphis) LLC, formerly known as WesPac Pipelines - Memphis LLC (“Buckeye
Memphis”), which was accounted for as an equity transaction. As a result of the acquisition, we now own 100% of Buckeye
Memphis. Previously, in April 2014, BPH had purchased an additional 10% ownership interest in Buckeye Memphis for
$9.5 million, increasing our ownership interest in Buckeye Memphis from 80% to 90%. The acquisitions were accounted for as
equity transactions since BPH retained controlling interest in Buckeye Memphis.
Disposition
In December 2014, we completed the sale of all of the outstanding limited liability company interests in Lodi, our Natural
Gas Storage business, to Brookfield Infrastructure and its institutional partners (“Brookfield”) for $102.6 million in cash, net of
expenses and working capital adjustments of $2.4 million. Refer to Note 4 and Note 5 for further information.
82
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. DISCONTINUED OPERATIONS
In December 2013, the Board approved a plan to divest our Natural Gas Storage disposal group. 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 recorded in the first quarter of 2015 as
discontinued operations for the year ended December 31, 2015 and we have reported the results of operations for the disposal
group as discontinued operations for the year ended December 31, 2014. We recorded asset impairment charges of
$23.4 million within “Loss from discontinued operations” on our consolidated statements of operations for the year ended
December 31, 2014. See Note 5 and Note 18 for further discussion.
The following table summarizes the results from discontinued operations (in thousands):
Revenue....................................................................................................................................... $
Loss from discontinued operations .............................................................................................
— $
(857)
25,862
(59,641)
Year Ended December 31,
2015
2014
5. ASSET IMPAIRMENTS
Natural Gas Storage Disposal Group
In July 2014, we signed a purchase and sale agreement to sell our Natural Gas Storage disposal group. As a result of the
execution of the purchase and sale agreement, subsequent changes in the carrying value of the net assets of our Natural Gas
Storage disposal group, and the completed sale in December 2014 (as discussed in Note 4), we recorded non-cash asset
impairment charges of $23.4 million during the year ended December 31, 2014. We recorded these asset impairment charges
within “Loss from discontinued operations” on our consolidated statements of operations for the year ended December 31,
2014. Refer to Note 18 for further discussion.
6. COMMITMENTS AND CONTINGENCIES
Claims and Legal Proceedings
In the ordinary course of business, we are involved in various claims and legal proceedings, some of which are covered by
insurance. We are generally unable to predict the timing or outcome of these claims and proceedings. Based upon our
evaluation of existing claims and proceedings and the probability of losses relating to such contingencies, we have accrued
certain amounts relating to such claims and proceedings, none of which are considered material.
Environmental Contingencies
We recorded operating expenses, net of recoveries, of $8.2 million, $6.2 million and $3.0 million during the years ended
December 31, 2016, 2015 and 2014, respectively, related to environmental remediation liabilities unrelated to claims and legal
proceedings. As of December 31, 2016 and 2015, we recorded environmental remediation liabilities of $44.3 million and
$48.0 million, respectively. See Notes 13 and 15 for further information. Costs ultimately incurred may be in excess of our
estimates, which may have a material impact on our financial condition, results of operations or cash flows. At December 31,
2016 and 2015, we had $7.2 million and $10.9 million, respectively, of receivables related to these environmental remediation
liabilities covered by insurance or third-party claims.
83
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Leases —Where We are Lessee
We lease certain property, plant and equipment under noncancelable and cancelable operating leases. Rental expense is
charged to operating expenses on a straight-line basis over the period of expected benefit. Contingent rental payments are
expensed as incurred. Total rental expense for the years ended December 31, 2016, 2015 and 2014 was $32.8 million,
$31.0 million and $26.9 million, respectively. The following table presents minimum lease payment obligations under our
operating leases with terms in excess of one year for the years ending December 31st (in thousands):
Office Space
and Other
2017...................................................................................... $
2018......................................................................................
2019......................................................................................
2020......................................................................................
2021......................................................................................
Thereafter.............................................................................
Total................................................................................... $
3,930
3,075
2,869
2,947
2,596
756
16,173
Equipment (1)
9,919
$
9,027
8,943
9,135
9,339
46,492
92,855
$
$
$
Land
Leases (2)
2,648
2,648
2,648
2,398
2,398
86,507
99,247
$
$
Total
16,497
14,750
14,460
14,480
14,333
133,755
208,275
____________________________
(1) Includes BBH facility leases for tugboats and a barge in our Global Marine Terminals segment.
(2) Includes leases for properties in connection with both the jetty and inland dock operations in the Global Marine Terminals
segment.
Additionally, our rights-of-way payments for the years ended December 31, 2016, 2015 and 2014 were $7.1 million,
$7.0 million and $6.5 million, respectively; and are subject to an annual escalation for the remaining life of all pipelines and
terminals.
7. INVENTORIES
Our inventory amounts were as follows at the dates indicated (in thousands):
Liquid petroleum products (1) .................................................................................................... $
Materials and supplies.................................................................................................................
Total inventories ....................................................................................................................... $
December 31,
2016
337,424
19,379
356,803
$
$
2015
174,232
18,760
192,992
____________________________
(1) Ending inventory was 198.2 million and 153.3 million gallons of liquid petroleum products at December 31, 2016 and
2015, respectively.
At December 31, 2016 and 2015, approximately 88% and 89% of our liquid petroleum products inventory volumes were
designated in a fair value hedge relationship, respectively. Because we generally designate inventory as a hedged item upon
purchase, hedged inventory is valued at current market prices with the change in value of the inventory reflected in our
consolidated statements of operations. Our inventory volumes that are not designated as the hedged item in a fair value hedge
relationship are economically hedged to reduce our commodity price exposure. Inventory not accounted for as a fair value
hedge is accounted for at the lower of weighted average cost method or net realizable value.
84
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
8. PREPAID AND OTHER CURRENT ASSETS
Prepaid and other current assets consist of the following at the dates indicated (in thousands):
December 31,
2016
2015
Prepaid insurance ........................................................................................................................ $
Margin deposits...........................................................................................................................
Unbilled revenue .........................................................................................................................
Prepaid taxes ...............................................................................................................................
Vendor prepayments....................................................................................................................
Escrow deposits...........................................................................................................................
Other............................................................................................................................................
Total prepaid and other current assets ...................................................................................... $
7,609
43,912
1,615
7,357
1,863
10
4,170
66,536
$
$
12,779
—
4,047
4,842
97
21,360
4,946
48,071
9. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consist of the following at the dates indicated (in thousands):
Land.................................................................................................................
Rights-of-way ..................................................................................................
Buildings and leasehold improvements...........................................................
Jetties, subsea pipeline and docks ...................................................................
Gas storage facility ..........................................................................................
Pipelines and terminals....................................................................................
Vehicles, equipment and office furnishings.....................................................
Processing facilities .........................................................................................
Construction in progress..................................................................................
Total property, plant and equipment..............................................................
Less: Accumulated depreciation......................................................................
Total property, plant and equipment, net.......................................................
Estimated
Useful
Lives (Years)
N/A
December 31,
2016
670,437
$
2015
669,130
$
(1)
13-50
20-50
25-50
7-50
3-20
30-50
N/A
107,448
254,421
629,316
2,349
107,293
235,872
629,677
2,349
4,968,574
4,616,080
130,247
598,837
162,145
117,494
557,853
141,153
7,523,774
(1,040,492)
6,483,282
$
7,076,901
(874,820)
6,202,081
$
____________________________
(1) Rights-of-way assets are depreciated over the useful life of the related pipeline assets.
Depreciation expense was $186.6 million, $158.7 million and $148.4 million for the years ended December 31, 2016, 2015
and 2014, respectively.
85
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
10. EQUITY INVESTMENTS
The following table presents our equity investments, all included within the Domestic Pipelines & Terminals segment, at
the dates indicated (in thousands):
West Shore Pipe Line Company......................................................................
Muskegon Pipeline LLC..................................................................................
Transport4, LLC ..............................................................................................
South Portland Terminal LLC .........................................................................
Total equity investments ...............................................................................
Ownership
34.6%
40.0%
25.0%
50.0%
$
$
December 31,
2016
2015
66,065
13,523
474
9,502
89,564
$
$
60,441
13,599
459
9,629
84,128
The following table presents earnings from equity investments for the periods indicated (in thousands):
West Shore Pipe Line Company...................................................................... $
Muskegon Pipeline LLC..................................................................................
Transport4, LLC ..............................................................................................
South Portland Terminal LLC .........................................................................
Total earnings from equity investments........................................................ $
7,647
2,002
765
1,122
11,536
$
$
7,070
(2,876)
606
1,581
6,381
$
$
8,621
1,059
470
1,115
11,265
Year Ended December 31,
2016
2015
2014
Summarized combined financial information for our equity method investments are as follows for the periods indicated
(amounts represent 100% of investee financial information in thousands):
BALANCE SHEET DATA:
Current assets............................................................................................................................ $
Noncurrent assets......................................................................................................................
Total assets........................................................................................................................... $
Current liabilities ...................................................................................................................... $
Other liabilities .........................................................................................................................
Combined equity.......................................................................................................................
Total liabilities and combined equity................................................................................... $
December 31,
2016
2015
39,214
134,937
174,151
15,790
44,224
114,137
174,151
$
$
$
$
26,910
126,456
153,366
11,474
43,344
98,548
153,366
INCOME STATEMENT DATA:
Revenue......................................................................................................... $
Costs and expenses........................................................................................
Non-operating expense .................................................................................
Net income .................................................................................................... $
87,434
(41,502)
(14,990)
30,942
$
$
92,501
(56,906)
(15,903)
19,692
$
$
88,417
(48,563)
(13,826)
26,028
Year Ended December 31,
2016
2015
2014
86
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. GOODWILL AND INTANGIBLE ASSETS
Goodwill
The changes in the carrying amount of goodwill by segment are as follows at the dates indicated (in thousands):
January 1, 2015 .................................................................................... $
Acquisition (1)...................................................................................
Purchase price adjustments (2)..........................................................
December 31, 2015 ..............................................................................
Acquisition (1)...................................................................................
Purchase price adjustments (2)..........................................................
December 31, 2016 .............................................................................. $
Domestic
Pipelines
& Terminals
279,280
Global
Marine
Terminals
Merchant
Services
$
709,596
$
4,499
$
10,626
—
289,906
7,758
(1,961)
295,703
—
(5,253)
704,343
—
—
—
—
4,499
—
—
$
704,343
$
4,499
Total
993,375
10,626
(5,253)
998,748
7,758
(1,961)
$ 1,004,545
____________________________
(1) See Note 3 for discussion of our acquisitions.
(2) Goodwill is recorded at the acquisition date based on preliminary fair value information. Subsequent to the acquisition but
not to exceed one year from the acquisition date, we record any material adjustments to the initial estimate in the reporting
period in which the adjustment amounts are determined based on new information obtained about facts and circumstances
that existed as of the acquisition date. During 2015, we recorded adjustments to the purchase price allocations for the
Buckeye Texas Partners Transaction. During 2016, we recorded adjustments to the purchase price allocations for the
Pennsauken pipeline acquisition and Springfield pipeline and terminal acquisitions. See Note 3 for discussion of our
acquisitions.
For our annual goodwill impairment tests as of October 31, 2016 and 2015, we performed quantitative assessments to
determine the fair value of each of our reporting units. Based on such calculations, each reporting unit’s fair value was in
excess of its carrying value. Therefore, we did not record any goodwill impairment for the years ended December 31, 2016 or
2015.
Intangible Assets
Intangible assets consist of the following at the dates indicated (in thousands):
Customer relationships................................................................................................................ $
Accumulated amortization ..........................................................................................................
Net carrying amount .................................................................................................................
Customer contracts......................................................................................................................
Accumulated amortization ..........................................................................................................
Net carrying amount .................................................................................................................
Total intangible assets, net................................................................................................... $
December 31,
2016
231,620
(83,187)
148,433
384,666
(109,796)
274,870
423,303
$
$
2015
231,620
(70,349)
161,271
395,690
(65,589)
330,101
491,372
For the years ended December 31, 2016, 2015 and 2014, amortization expense related to intangible assets was
$68.1 million, $62.6 million and $47.4 million, respectively. Amortization expense related to intangible assets is expected to be
$66.3 million for 2017, $65.4 million for 2018, $64.6 million for 2019, $64.9 million for 2020 and $61.1 million for 2021.
87
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
12. OTHER NON-CURRENT ASSETS
Other non-current assets consist of the following at the dates indicated (in thousands):
Debt issuance costs, net .............................................................................................................. $
Insurance receivables related to environmental remediation reserves........................................
BBH jetty insurance receivable...................................................................................................
Derivative assets .........................................................................................................................
Other............................................................................................................................................
Total other non-current assets................................................................................................... $
3,794
3,635
6,827
62,768
24,488
101,512
$
$
4,150
4,554
6,433
1,057
25,208
41,402
December 31,
2016
2015
13. ACCRUED AND OTHER CURRENT LIABILITIES
Accrued and other current liabilities consist of the following at the dates indicated (in thousands):
December 31,
2016
2015
Taxes - other than income........................................................................................................... $
Accrued employee benefit liabilities ..........................................................................................
Accrued environmental remediation liabilities...........................................................................
Interest payable...........................................................................................................................
Unearned revenue .......................................................................................................................
Compensation and vacation........................................................................................................
Accrued capital expenditures......................................................................................................
Margin deposits ..........................................................................................................................
Unfavorable storage contracts (1)...............................................................................................
ARO............................................................................................................................................
Litigation contingency accrual (2)..............................................................................................
Expense accruals - other .............................................................................................................
Other ...........................................................................................................................................
Total accrued and other current liabilities................................................................................ $
34,052
6,849
8,410
59,508
32,183
31,693
45,664
—
—
2,543
858
20,764
23,369
265,893
$
$
28,183
6,710
9,164
56,066
27,365
28,942
79,060
36,108
5,979
1,360
2,390
7,429
20,864
309,620
____________________________
(1) Amounts relate to the unfavorable storage contracts acquired in connection with the BBH acquisition in 2011.
We recognized $6.0 million and $11.1 million of revenue during the years ended December 31, 2016 and 2015,
respectively.
(2) Amount relates to a contingent liability associated with the Federal Energy Regulatory Commission (“FERC”) litigation
accrual.
88
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
14. LONG-TERM DEBT
Long-term debt consists of the following at the dates indicated (in thousands):
5.125% Notes due July 1, 2017 (1) ............................................................................................. $
6.050% Notes due January 15, 2018 (1) .....................................................................................
2.650% Notes due November 15, 2018 (1).................................................................................
5.500% Notes due August 15, 2019 (1) ......................................................................................
4.875% Notes due February 1, 2021 (1) .....................................................................................
4.150% Notes due July 1, 2023 (1) .............................................................................................
4.350% Notes due October 15, 2024 (1).....................................................................................
3.950% Notes due December 1, 2026 (1) ...................................................................................
6.750% Notes due August 15, 2033 (1) ......................................................................................
5.850% Notes due November 15, 2043 (1).................................................................................
5.600% Notes due October 15, 2044 (1).....................................................................................
Term Loan due September 30, 2019 ...........................................................................................
Credit Facility due September 30, 2021......................................................................................
Unamortized discounts and debt issuance costs .........................................................................
Total debt ..................................................................................................................................
Less: Current portion of line of credit (2) ...................................................................................
Total long-term debt ................................................................................................................. $
December 31,
2016
125,000
300,000
400,000
275,000
650,000
500,000
300,000
600,000
150,000
400,000
300,000
250,000
—
(32,305)
4,217,695
—
4,217,695
$
$
2015
125,000
300,000
400,000
275,000
650,000
500,000
300,000
—
150,000
400,000
300,000
—
472,488
(28,176)
3,844,312
(111,488)
3,732,824
____________________________
(1) We make semi-annual interest payments on these notes based on the rates noted above with the principal balances
outstanding to be paid on or before the due dates as shown above.
(2) The line of credit is classified as a current liability in our consolidated balance sheets as related funds are used to finance
the Buckeye Merchant Service Companies’ current working capital needs.
The following table presents the scheduled maturities of principal amounts of our debt obligations for the next five years
and in total thereafter (in thousands):
2017 ........................................................................................................................................................................ $
2018 ........................................................................................................................................................................
2019 ........................................................................................................................................................................
2020 ........................................................................................................................................................................
2021 ........................................................................................................................................................................
Thereafter................................................................................................................................................................
Total...................................................................................................................................................................... $
Years Ending
December 31,
125,000
700,000
525,000
—
650,000
2,250,000
4,250,000
89
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Credit Facility
In September 2014, Buckeye and its indirect wholly-owned subsidiaries, Buckeye Energy Services LLC (“BES”), Buckeye
West Indies Holdings LP (“BWI”) and Buckeye Caribbean Terminals LLC (“BCT”), as borrowers, modified and extended
(through a new credit agreement) our existing revolving Credit Facility with SunTrust Bank, as administrative agent, and other
lenders to provide a total borrowing capacity of $1.5 billion, dated September 30, 2014 of which BES, BWI and BCT,
collectively the Buckeye Merchant Service Companies (“BMSC”), share a sublimit of $500.0 million. The Credit Facility's
maturity date was September 30, 2019, with an option to extend the term for up to two one-year periods and a $500.0 million
accordion option to increase the commitments, with the consent of the lenders.
In December 2015, the Credit Facility's maturity date was extended by one year to September 30, 2020, resulting in a
remaining option to extend the term for one additional year. At the time of the transaction, we had $3.4 million of remaining
unamortized deferred financing costs, and we incurred additional debt issuance costs of $0.8 million in connection with the
extension of the Credit Facility.
In September 2016, Buckeye and BMSC exercised their remaining option with consenting lenders to extend $1.4 billion of
our existing $1.5 billion revolving credit facility with SunTrust Bank by one year to September 30, 2021. At the time of the
transaction, we had $3.4 million of remaining unamortized deferred financing costs, and we incurred additional debt issuance
costs of $0.7 million in connection with the extension of the Credit Facility. These amounts are included in “Other non-current
assets” and are being amortized over the revised term of the agreement.
Under the Credit Facility, interest accrues on advances at the London Interbank Offered Rate (“LIBOR”) rate or a base rate
plus an applicable margin based on the election of the applicable borrower for each interest period. The issuing fees for all
letters of credit are also based on an applicable margin. The applicable margin used in connection with interest rates and fees is
based on the credit ratings assigned to our senior unsecured long-term debt securities. The applicable margin for LIBOR rate
loans, swing line loans, and letter of credit fees ranges from 1.0% to 1.75% and the applicable margin for base rate loans ranges
from 0% to 0.75%. Buckeye and BMSC will also pay a fee based on our credit ratings on the actual daily unused amount of the
aggregate commitments.
At December 31, 2016, Buckeye and BMSC collectively had no outstanding balance under the Credit Facility. In October
2016, we completed a public equity offering and used a portion of the net proceeds from the offering to reduce the indebtedness
outstanding under our Credit Facility. See Note 22 for additional information. The weighted average interest rate for
borrowings under the Credit Facility was 2.0% at December 31, 2016. The Credit Facility includes covenants limiting, as of
the last day of each fiscal quarter, the ratio of consolidated funded debt to consolidated EBITDA (“Funded Debt Ratio”), as
defined in the Credit Facility, measured for the preceding twelve months, to not more than 5.0 to 1.0. This requirement is
subject to a provision for increases to 5.5 to 1.0 in connection with certain future acquisitions. The Funded Debt Ratio is
calculated by dividing consolidated debt by annualized EBITDA, which is defined in the Credit Facility as earnings before
interest, taxes, depreciation, and amortization determined on a consolidated basis. At December 31, 2016, our Funded Debt
Ratio was 3.55 to 1.00. At December 31, 2016, we were in compliance with the covenants under our Credit Facility.
At both December 31, 2016 and 2015, we had committed $1.2 million in support of letters of credit. The obligations for
letters of credit are not reflected as debt on our consolidated balance sheets.
Term Loan
In September 2016, we entered into our $250.0 million Term Loan due September 30, 2019, with an option to extend the
term with consenting lenders for up to two one-year periods. At the time of the transaction, we incurred debt issuance costs of
$0.5 million related to the Term Loan. We used the proceeds from the Term Loan to reduce the indebtedness outstanding under
our Credit Facility. Under the Term Loan, interest accrues at the LIBOR rate or a base rate plus an applicable margin based on
the election of the borrower. The applicable margin used in connection with interest rates and fees is based on the credit ratings
assigned to our senior unsecured long-term debt securities. The applicable margin for LIBOR rate loans ranges from 1.0% to
1.6% and the applicable margin for base rate loans ranges from 0% to 0.6%.
90
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Term Loan includes covenants limiting the Funded Debt Ratio, as defined in the Term Loan, measured for the
preceding twelve months, to not more than 5.0 to 1.0 as of the last day of each fiscal quarter. This requirement is subject to a
provision for increases to 5.5 to 1.0 in connection with certain future acquisitions. The Funded Debt Ratio is calculated by
dividing consolidated debt by annualized EBITDA, which is defined in the Term Loan as earnings before interest, taxes,
depreciation, and amortization determined on a consolidated basis. At December 31, 2016, we were in compliance with the
covenants under the Term Loan.
Note Offering
In November 2016, we issued $600.0 million of senior unsecured 3.950% notes maturing on December 1, 2026 in an
underwritten public offering at 99.644% of their principal amount. Total proceeds from this offering, after underwriting fees,
expenses and debt issuance costs of $5.2 million, were $592.7 million. In January 2017, we used the net proceeds from this
offering to fund a portion of the purchase price for the VTTI Acquisition (see Note 3).
Current Maturities Expected to be Refinanced
It is our intent to refinance the $125.0 million of 5.125% Notes maturing on July 1, 2017 using our Credit Facility. At
December 31, 2016, we had $1.5 billion of availability under our Credit Facility. Therefore, we have classified these notes as
long-term debt in the consolidated balance sheet at December 31, 2016.
15. OTHER NON-CURRENT LIABILITIES
Other non-current liabilities consist of the following at the dates indicated (in thousands):
Accrued employee benefit liabilities........................................................................................... $
Accrued environmental remediation liabilities ...........................................................................
Deferred consideration ................................................................................................................
ARO ............................................................................................................................................
Derivative liabilities ....................................................................................................................
Other............................................................................................................................................
Total other non-current liabilities ............................................................................................. $
37,795
35,878
19,126
3,439
4,214
4,985
105,437
$
$
42,643
38,832
23,392
5,463
703
4,374
115,407
December 31,
2016
2015
16. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Accumulated other comprehensive income (loss) consists of the following at the dates indicated (in thousands):
Unrealized gains on derivative instruments ................................................................................ $
Net loss on settlement of interest rate swaps, net of amortization ..............................................
Adjustments to funded status of benefit plans ............................................................................
Total accumulated other comprehensive loss ........................................................................... $
December 31,
2016
2015
$
60,281
(79,864)
(6,010)
(25,593) $
1,266
(92,014)
(7,093)
(97,841)
91
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
17. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
We are exposed to financial market risks, including changes in interest rates and commodity prices, in the course of our
normal business operations. We use derivative instruments to manage risks.
Interest Rate Derivatives
From time to time, we utilize forward-starting interest rate swaps to hedge the variability of the forecasted interest
payments on anticipated debt issuances that may result from changes in the benchmark interest rate until the expected debt is
issued. When entering into interest rate swap transactions, we become exposed to both credit risk and market risk. We are
subject to credit risk when the change in fair value of the swap instrument is positive and the counterparty may fail to perform
under the terms of the contract. We are subject to market risk with respect to changes in the underlying benchmark interest rate
that impacts the fair value of the swaps. We manage our credit risk by entering into swap transactions only with major financial
institutions with investment-grade credit ratings. We manage our market risk by aligning the swap instrument with the existing
underlying debt obligation or a specified expected debt issuance, generally associated with the maturity of an existing debt
obligation. We designate the swap agreements as cash flow hedges at inception and expect the changes in values to be highly
correlated with the changes in value of the underlying borrowings.
During 2016, we entered into seven forward-starting interest rate swaps with a total aggregate notional amount of
$350.0 million, which we entered into in anticipation of the issuance of debt on or before January 15, 2018, and eleven forward-
starting interest rate swaps with a total aggregate notional amount of $500.0 million, which we entered into in anticipation of
the issuance of debt on or before November 15, 2018. We expect to issue new fixed-rate debt on or before January 15, 2018 to
repay the $300.0 million of 6.050% Notes that are due on January 15, 2018, and on or before November 15, 2018 to repay the
$400.0 million of 2.650% Notes that are due on November 15, 2018, as well as to fund capital expenditures and other general
partnership purposes, although no assurances can be given that the issuance of fixed-rate debt will be possible on acceptable
terms.
In September 2014, we issued $300.0 million of senior unsecured notes and also settled six related forward-starting interest
rate swaps with a total aggregate notional amount of $300.0 million for $51.5 million. As a result of the interest rate swap
settlement, we recognized $1.1 million hedge ineffectiveness in interest and debt expense attributable to the timing difference
between when the swaps were settled and when they were forecasted to settle.
In June 2013, we issued $500.0 million of the 4.150% Notes and also settled six related forward-starting interest rate swaps
with a total aggregate notional amount of $275.0 million for $62.0 million. As a result of the interest rate swap settlement, we
recognized $0.9 million hedge ineffectiveness in interest and debt expense attributable to the timing difference between when
the swaps were settled and when they were forecasted to settle.
During the year ended December 31, 2016, unrealized gains of $62.6 million were recorded in AOCI to reflect the change
in the fair values of the forward-starting interest rate swaps.
Commodity Derivatives
Our Merchant Services segment primarily uses exchange-traded refined petroleum product futures contracts to manage the
risk of market price volatility on its refined petroleum product inventories and its physical derivative contracts, which we
designated as fair value hedges, with changes in fair value of both the futures contracts and physical inventory reflected in
earnings. Our Merchant Services segment also uses exchange-traded refined petroleum contracts to hedge expected future
transactions related to certain gasoline inventory that we manage on behalf of a third party, which are designated as cash flow
hedges, with the effective portion of the hedge reported in other comprehensive income (“OCI”) and reclassified into earnings
when the expected future transaction affects earnings. Any gains or losses incurred on the derivative instruments that are not
effective in offsetting changes in fair value or cash flows of the hedged item are recognized immediately in earnings.
Additionally, our Merchant Services segment enters into exchange-traded refined petroleum product futures contracts on
behalf of our Domestic Pipelines & Terminals segment to manage the risk of market price volatility on the narrowing 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.
92
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes our commodity derivative instruments outstanding at December 31, 2016 (amounts in
thousands of gallons):
Derivative Purpose
Derivatives NOT designated as hedging instruments:
Physical fixed price derivative contracts ..................................................
Physical index derivative contracts ..........................................................
Futures contracts for refined petroleum products.....................................
Derivatives designated as hedging instruments:
Physical fixed price derivative contracts ..................................................
Futures contracts for refined petroleum products.....................................
____________________________
(1) Volume represents absolute value of net notional volume position.
Volume (1)
Current
Long-Term
Accounting
Treatment
2,335
24,012
2,055
174,006
9,828
1,453 Mark-to-market
16,507 Mark-to-market
2,142 Mark-to-market
— Fair Value Hedge
— Cash Flow Hedge
93
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table sets forth the fair value of each classification of derivative instruments and the locations of the
derivative instruments on our consolidated balance sheets at the dates indicated (in thousands):
Physical fixed price derivative contracts ............. $
Physical index derivative contracts......................
Futures contracts for refined products .................
Total current derivative assets ...........................
Physical fixed price derivative contracts .............
Futures contracts for refined products .................
Interest rates derivatives ......................................
Total non-current derivative assets....................
Physical fixed price derivative contracts .............
Physical index derivative contracts......................
Futures contracts for refined products .................
Total current derivative liabilities......................
Physical fixed price derivative contracts .............
Futures contracts for refined products .................
Total non-current derivative liabilities ..............
Net derivative (liabilities) assets................... $
Derivatives
NOT Designated
as Hedging
Instruments
Derivatives
Designated
as Hedging
Instruments
$
December 31, 2016
Derivative
Carrying
Value
— $
—
21
21
—
—
62,609
62,609
—
—
(15,685)
(15,685)
—
—
—
46,945
$
1,499
334
51,452
53,285
164
226
62,609
62,999
(4,517)
(1)
(73,513)
(78,031)
(61)
(4,384)
(4,445)
33,808
Netting
Balance
Sheet
Adjustment (1)
$
(306) $
(1)
(51,452)
(51,759)
(5)
(226)
—
(231)
306
1
51,452
51,759
5
226
231
$
— $
Total
1,193
333
—
1,526
159
—
62,609
62,768
(4,211)
—
(22,061)
(26,272)
(56)
(4,158)
(4,214)
33,808
1,499
334
51,431
53,264
164
226
—
390
(4,517)
(1)
(57,828)
(62,346)
(61)
(4,384)
(4,445)
(13,137) $
____________________________
(1) Amounts represent the netting of physical fixed and index contracts’ assets and liabilities when a legal right of offset exists.
Futures contracts are subject to settlement through margin requirements and are additionally presented on a net basis.
December 31, 2015
Derivatives
NOT Designated
as Hedging
Instruments
Physical fixed price derivative contracts ............. $
Physical index derivative contracts......................
Futures contracts for refined products .................
Total current derivative assets ...........................
Physical fixed price derivative contracts .............
Total non-current derivative assets....................
Physical fixed price derivative contracts .............
Physical index derivative contracts......................
Futures contracts for refined products .................
Total current derivative liabilities......................
Futures contracts for refined products .................
Total non-current derivative liabilities ..............
Net derivative assets ..................................... $
26,698
87
136,131
162,916
1,057
1,057
(535)
(116)
(119,506)
(120,157)
(703)
(703)
43,113
Derivatives
Designated
as Hedging
Instruments
$
Derivative
Carrying
Value
26,698
87
172,965
199,750
1,057
1,057
(535)
(116)
(121,324)
(121,975)
(703)
(703)
78,129
— $
—
36,834
36,834
—
—
—
—
(1,818)
(1,818)
—
—
35,016
$
$
$
Netting
Balance
Sheet
Adjustment (1)
$
(79) $
(62)
(121,324)
(121,465)
—
—
79
62
121,324
121,465
—
—
— $
Total
26,619
25
51,641
78,285
1,057
1,057
(456)
(54)
—
(510)
(703)
(703)
78,129
____________________________
(1) Amounts represent the netting of physical fixed and index contracts’ assets and liabilities when a legal right of offset exists.
Futures contracts are subject to settlement through margin requirements and are additionally presented on a net basis.
94
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Our futures contracts designated as fair value hedges related to our inventory portfolio and our futures contracts designated
as cash flow hedges related to refined petroleum products extend to the second quarter of 2017. The unrealized loss at
December 31, 2016 for fair value hedges of inventory and cash flow hedges related to refined petroleum products represented
by futures contracts of $13.4 million and $2.3 million, respectively, will be realized by the second quarter of 2017.
At December 31, 2016, open refined petroleum product derivative contracts (represented by the physical fixed-price contracts,
physical index contracts, and futures contracts for refined products contracts noted above) varied in duration in the overall
portfolio, but did not extend beyond December 2018. In addition, at December 31, 2016, we had refined petroleum product
inventories that we intend to use to satisfy a portion of the physical derivative contracts.
The gains and losses on our derivative instruments recognized in income were as follows for the periods indicated (in
thousands):
Location
Year Ended December 31,
2016
2015
Derivatives NOT designated as hedging instruments:
Physical fixed price derivative contracts ...................................... Product sales.....................
Physical index derivative contracts .............................................. Product sales.....................
Physical fixed price derivative contracts ...................................... Cost of product sales ........
Physical index derivative contracts .............................................. Cost of product sales ........
Futures contracts for refined products .......................................... Cost of product sales ........
Derivatives designated as fair value hedging instruments:
Futures contracts for refined products .......................................... Cost of product sales ........
Physical inventory - hedged items................................................ Cost of product sales ........
Ineffectiveness excluding the time value component on fair
value hedging instruments:
Fair value hedge ineffectiveness (excluding time value).............. Cost of product sales ........
Time value excluded from hedge assessment............................... Cost of product sales ........
Net gain (loss) in income...........................................................................................................
$
$
$
$
(11,161) $
349
8,790
308
4,463
35,667
(268)
12,489
101
(6,559)
(55,693) $
77,555
75,974
(83,703)
(1,410) $
23,272
21,862
$
2,162
(9,891)
(7,729)
The change in value recognized in OCI and the losses reclassified from AOCI to income attributable to our derivative
instruments designated as cash flow hedges were as follows for the periods indicated (in thousands):
Derivatives designated as cash flow hedging instruments:
Interest rate contracts .................................................................................................................. $
Commodity derivatives ...............................................................................................................
Derivatives designated as cash flow hedging instruments:
Interest rate contracts.................................................................... Interest and debt expense .
Commodity derivatives................................................................. Product sales.....................
Location
95
$
$
$
Gain Recognized
in OCI on Derivatives for the
Year Ended December 31,
2016
2015
62,609
(2,328)
60,281
$
$
—
1,266
1,266
Loss Reclassified
From AOCI to Income for the
Year Ended December 31,
2016
2015
(12,150) $
1,266
(10,884) $
(12,151)
—
(12,151)
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Over the next twelve months, we expect to reclassify $11.9 million of net losses attributable to interest rate derivatives
from AOCI to earnings as an increase to interest and debt expense. The net losses consist of $12.2 million of amortization of
hedge losses related to our settled forward-starting interest rate swaps and $0.3 million of estimated amortization of forecasted
hedge gains on our forward-starting interest rate swaps that we expect to settle in late 2017. Additionally, the unrealized losses
at December 31, 2016 for refined petroleum products designated as cash flow hedges of $2.3 million will be realized and
reclassified from AOCI to product sales during 2017. The ineffective portion of the change in fair value of cash flow hedges
was not material for the year ended December 31, 2016 or 2015.
18. FAIR VALUE MEASUREMENTS
We categorize our financial assets and liabilities using the three-tier hierarchy as follows:
Recurring
The following table sets forth financial assets and liabilities, measured at fair value on a recurring basis, as of the
measurement dates indicated, and the basis for that measurement, by level within the fair value hierarchy (in thousands):
December 31, 2016
December 31, 2015
Level 1
Level 2
Level 1
Level 2
Financial assets:
Physical fixed price derivative contracts ............................. $
Physical index derivative contracts......................................
Futures contracts for refined products .................................
Interest rate derivatives ........................................................
— $
—
—
—
Financial liabilities:
Physical fixed price derivative contracts .............................
Physical index derivative contracts......................................
Futures contracts for refined products .................................
Fair value ........................................................................... $
—
—
(26,219)
(26,219) $
1,352
333
—
62,609
(4,267)
—
—
60,027
$
$
— $
—
51,641
—
—
—
(703)
50,938
$
27,676
25
—
—
(456)
(54)
—
27,191
The values of the Level 1 derivative assets and liabilities were based on quoted market prices obtained from the New York
Mercantile Exchange.
The values of the Level 2 interest rate derivatives were determined using fair value estimates obtained from our
counterparties, which are verified using other available market data, including cash flow models which incorporate market
inputs including the implied forward LIBOR yield curve for the same period as the future interest rate swap settlements.
Credit value adjustments (“CVAs”), which are used to reflect the potential nonperformance risk of our
counterparties, are considered in the fair value assessment of interest rate derivatives. We determined that the
impact of CVAs is not significant to the overall valuation of interest rate derivatives.
The values of the Level 2 commodity derivative contracts were calculated using market approaches based on observable
market data inputs, including published commodity pricing data, which is verified against other available market data, and
market interest rate and volatility data. Level 2 physical fixed price derivative assets are net of CVAs determined using an
expected cash flow model, which incorporates assumptions about the credit risk of the derivative contracts based on the
historical and expected payment history of each customer, the amount of product contracted for under the agreement and the
customer’s historical and expected purchase performance under each contract. The Merchant Services segment determined
CVAs are appropriate because few of the Merchant Services segment’s customers entering into these derivative contracts are
large organizations with nationally recognized credit ratings. The CVAs were nominal as of December 31, 2016 and 2015. As
of December 31, 2016 and 2015, the Merchant Services segment did not hold any net liability derivative position containing
credit contingent features.
96
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Financial instruments included in current assets and current liabilities are reported in the consolidated balance sheets at
amounts which approximate fair value due to the relatively short period to maturity of these financial instruments. The fair
values of our fixed-rate debt were estimated by observing market trading prices and by comparing the historic market prices of
our publicly issued debt with the market prices of the publicly issued debt of other MLP’s with similar credit ratings and terms.
The fair values of our variable-rate debt are their carrying amounts, as the carrying amount reasonably approximates fair value
due to the variability of the interest rates. The carrying value and fair value, using Level 2 input values, of our debt were as
follows at the dates indicated (in thousands):
Fixed-rate debt ..................................................................... $
Variable-rate debt.................................................................
Total debt........................................................................... $
December 31, 2016
December 31, 2015
Carrying
Amount
3,967,695
250,000
4,217,695
Fair Value
$
$
4,083,488
250,000
4,333,488
$
$
Carrying
Amount
3,371,824
472,488
3,844,312
Fair Value
$
$
3,057,945
472,488
3,530,433
In addition, our pension plan assets are measured at fair value on a recurring basis, based on Level 1 and Level 3 inputs.
See Note 19 for additional information.
We recognize transfers between levels within the fair value hierarchy as of the beginning of the reporting period. We did
not have any transfers between Level 1 and Level 2 during the years ended December 31, 2016 and 2015.
Non-Recurring
Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value
adjustments in certain circumstances, such as when there is evidence of impairment. During the year ended December 31,
2014, we recorded a net non-cash asset impairment charge of $23.4 million related to our Natural Gas Storage disposal group as
a result of the execution of a purchase and sale agreement in July 2014 to sell the business, subsequent changes in the carrying
value of the net assets of the business and the completed sale in December 2014. See Note 4 and Note 5 for additional
information.
19. PENSIONS AND OTHER POSTRETIREMENT BENEFITS
RIGP and Retiree Medical Plan
Services Company, which employs the majority of our workforce, sponsors a Retirement Income Guarantee Plan
(“RIGP”), which is a defined benefit plan that generally guarantees employees hired before January 1, 1986 a retirement benefit
based on years of service and the employee’s highest compensation for any consecutive 5-year period during the last 10 years
of service or other compensation measures as defined under the respective plan provisions. The retirement benefit is subject to
reduction at varying percentages for certain offsetting amounts, including benefits payable under a retirement and savings plan
discussed further below. Services Company funds this benefit plan through contributions to pension trust assets, generally
subject to minimum funding requirements as provided by applicable law.
Services Company also sponsors an unfunded post-retirement benefit plan (the “Retiree Medical Plan”), which provides
health care and life insurance benefits to certain of its retirees. To be eligible for the health care benefits, an employee must
have been hired prior to January 1, 1991 and meet certain age and service requirements. To be eligible for the life insurance
benefits, an employee must have been hired prior to January 1, 2002 and meet certain service requirements.
97
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The components of projected benefit obligations and plan assets, and the funded status of the RIGP and the Retiree
Medical Plan (“the Plans”) were as follows for the periods indicated (in thousands):
Change in benefit obligation:
Benefit obligation at beginning of year ............................. $
Service cost........................................................................
Interest cost........................................................................
Plan participants’ contributions.........................................
Actuarial (gain) loss ..........................................................
Plan curtailment.................................................................
Settlements ........................................................................
Benefit payments ...............................................................
Benefit obligation at end of year ....................................... $
Change in plan assets:
Fair value of plan assets at beginning of year ................... $
Actual return on plan assets...............................................
Plan participants’ contributions.........................................
Employer contributions .....................................................
Settlements ........................................................................
Benefit payments ...............................................................
Fair value of plan assets at end of year.............................. $
RIGP
Retiree Medical Plan
Year Ended December 31,
Year Ended December 31,
2016
2015
2016
2015
17,405
(34)
421
—
(555)
(1,513)
(598)
(1,948)
13,178
5,544
256
—
1,270
(598)
(1,948)
4,524
$
$
$
$
17,988
11
551
—
346
—
(469)
(1,022)
17,405
6,743
(373)
—
665
(469)
(1,022)
5,544
$
$
$
$
33,730
323
1,309
474
2,871
—
—
(6,749)
31,958
$
$
— $
—
474
6,275
—
(6,749)
— $
36,117
365
1,334
510
(3,573)
—
—
(1,023)
33,730
—
—
510
513
—
(1,023)
—
Funded status at end of year ............................................. $
(8,654) $
(11,861) $
(31,958) $
(33,730)
Amounts recognized in our consolidated balance sheets for the Plans consist of the following at the dates indicated below
(in thousands):
Liabilities:
RIGP
December 31,
Retiree Medical Plan
December 31,
2016
2015
2016
2015
Accrued employee benefit liabilities - current .................. $
Accrued employee benefit liabilities - noncurrent ............
Total.............................................................................. $
— $
(8,654)
(8,654) $
— $
(11,861)
(11,861) $
(2,817) $
(29,141)
(31,958) $
(2,948)
(30,782)
(33,730)
AOCI:
Net actuarial loss ............................................................... $
Total.............................................................................. $
2,616
2,616
$
$
5,804
5,804
$
$
3,394
3,394
$
$
1,289
1,289
98
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Information regarding the accumulated benefit obligation in excess of plan assets for the RIGP is as follows at the dates
indicated (in thousands):
RIGP
December 31,
2016
2015
Projected benefit obligation ........................................................................................................ $
Accumulated benefit obligation (1) ............................................................................................
Fair value of plan assets ..............................................................................................................
13,178
$
11,590
4,524
17,405
13,357
5,544
____________________________
(1) The accumulated benefit obligation does not include an assumption for future compensation increases.
The weighted average assumptions used in determining net periodic benefit cost for the Plans were as follows for the
periods indicated:
RIGP
Year Ended December 31,
Retiree Medical Plan
Year Ended December 31,
2016
2015
2014
2016
2015
2014
Discount rate.........................................
Expected return on plan assets..............
Rate of compensation increase .............
3.0%
5.8%
3.0%
3.3%
5.8%
3.0%
3.5%
5.8%
3.0%
4.1%
N/A
3.0%
3.9%
N/A
3.0%
4.4%
N/A
3.0%
The assumptions used in determining benefit obligations for the Plans were as follows at the dates indicated:
RIGP
December 31,
Retiree Medical Plan
December 31,
2016
2015
2016
2015
Discount rate ........................................................................
Rate of compensation increase.............................................
3.3%
3.0%
3.5%
3.0%
4.0%
3.0%
4.1%
3.0%
The discount rate reflects the rate at which benefits could be effectively settled on the measurement date. For the years
ended December 31, 2016, 2015, and 2014, the discount rate was determined based on a projection of expected cash flows from
the Plans using relevant economic benchmarks available as of each year end. The expected return on plan assets was
determined based on projected long-term market returns for each asset class in which the Plans are invested, weighted by the
target asset class allocations. The rate of compensation increase represents the long-term assumption for future increases to
salaries.
The assumed annual rate of increase in the per capita cost of covered health care benefits as of December 31, 2016 in the
Retiree Medical Plan was 5.5% for 2017, grading down to 4.5% in 2021, and thereafter. The assumed health care cost trend
rates may have a significant effect on the amounts reported for the Retiree Medical Plan. Based on a hypothetical 1%
movement in the assumed health care cost trend rates, the change in costs would have had the following effects on the
December 31, 2016 results (in thousands):
Effect on total service cost and interest cost components........................................................... $
Effect on postretirement benefit obligation.................................................................................
$
49
679
(44)
(614)
1%
Increase
1%
(Decrease)
99
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The components of the net periodic benefit cost and other changes recognized in OCI for the Plans were as follows for the
periods indicated (in thousands):
RIGP
Year Ended December 31,
Retiree Medical Plan
Year Ended December 31,
2016
2015
2014
2016
2015
2014
(34) $
11
$
94
$
323
$
365
$
Components of net periodic benefit
cost:
Service cost ........................................ $
Interest cost ........................................
Expected return on plan assets ...........
Actuarial loss due to settlements........
Amortization of unrecognized loss ....
421
(256)
598
522
551
(334)
469
842
Net periodic benefit cost................ $
1,251
$
1,539
$
Other changes in plan assets and
benefit obligations recognized in
OCI:
Net actuarial (gain) loss...................... $
Amortization of unrecognized loss ....
Actuarial loss due to settlements........
(2,068) $
(522)
(598)
Total recognized in OCI ................ $
(3,188) $
$
1,053
(842)
(469)
(258) $
Total recognized in net period benefit
cost and OCI ......................................... $
(1,937) $
1,281
$
1,265
553
(333)
—
667
981
951
(667)
—
284
1,309
1,334
—
—
766
—
—
199
345
1,420
—
—
31
$
2,398
$
1,898
$
1,796
$
$
$
2,871
(766)
—
2,105
4,503
$
$
$
(3,573)
(199)
—
(3,772) $
(188)
(31)
—
(219)
(1,874) $
1,577
We expect that the following amounts, currently included in OCI, for the Plans will be recognized in our consolidated
statement of operations during the year ending December 31, 2017 (in thousands):
Amortization of unrecognized loss ............................................................................................. $
351
$
32
We estimate the following benefit payments, which reflect expected future service, as appropriate, will be paid for the
Plans in the years indicated below as such (in thousands):
RIGP
Retiree
Medical
Plan
2017............................................................................................................................................. $
2018.............................................................................................................................................
2019.............................................................................................................................................
2020.............................................................................................................................................
2021.............................................................................................................................................
Thereafter ....................................................................................................................................
RIGP
1,920
$
1,486
1,373
1,336
1,307
3,631
Retiree
Medical
Plan
2,874
2,848
2,806
2,729
2,628
10,946
We expect to contribute $4.1 million to our benefit plans in 2017. Funding requirements for subsequent years are uncertain
and will depend on whether there are any changes in the actuarial assumptions used to calculate plan funding levels, the actual
return on plan assets and any legislative or regulatory changes affecting plan funding requirements. For tax planning, financial
planning, cash flow management or cost reduction purposes, we may increase, accelerate, decrease or delay contributions to the
plan to the extent permitted by law.
100
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We do not fund the Retiree Medical Plan and, accordingly, no assets are invested in the plan. A summary of investments in
the RIGP are as follows at the dates indicated (in thousands):
Mutual fund - fixed-income securities................................. $
Mutual fund - money market ...............................................
Coal lease .............................................................................
Fair value of plan assets .................................................... $
2,305
212
—
2,517
$
$
— $
—
2,007
2,007
$
2,759
465
—
3,224
$
$
—
—
2,320
2,320
December 31, 2016
December 31, 2015
Level 1
Level 3
Level 1
Level 3
The values of the Level 1 mutual funds were based on quoted market prices in active markets for identical assets. The
mutual fund — fixed-income securities generally seeks long-term growth of capital and income and invests in a portfolio
consisting primarily of fixed-income securities.
The values of the Level 3 coal lease were determined using an expected present value of future cash flows valuation model.
This investment relates to a 20.8% interest in a coal lease, which derives value from specified minimum royalty payments
received from CONSOL Energy Inc. related to coal reserves mined from two Pennsylvania mines owned by the lessor.
The coal lease extends through 2023.
The following table summarizes the activity in our Level 3 pension assets for the periods indicated (in thousands):
Year Ended
December 31,
2016
2015
Beginning balance, January 1 ..................................................................................................... $
Lease payments received .....................................................................................................
Unrealized loss.....................................................................................................................
Transfers out of Level 3.......................................................................................................
Ending balance, December 31 .................................................................................................. $
2,320
369
(313)
(369)
2,007
$
$
2,976
393
(656)
(393)
2,320
The RIGP investment policy does not target specific asset classes, but seeks to balance the preservation and growth of
capital in the plan’s mutual funds with the income derived with proceeds from the coal lease. While no significant changes in
the asset class allocation of the plan are expected during the upcoming year, Services Company may make changes at any time.
Retirement and Savings Plans
Services Company also sponsors the Retirement and Savings Plan (“RASP”) through which it provides retirement benefits
for substantially all of its regular full-time employees located in the continental United States, except those covered by certain
labor contracts. The RASP consists of two components. Under the first component, Services Company contributes 5% of each
eligible employee’s covered salary to an employee’s separate account maintained in the RASP. Under the second component,
Services Company makes a matching contribution into the employee’s separate account for 100% of an employee’s
contribution to the RASP up to 5% (or 6% if an employee has over 20 years of service) of an employee’s eligible covered
salary. Total costs of the RASP were $16.4 million, $15.2 million and $14 million during the years ended December 31, 2016,
2015 and 2014, respectively.
Services Company also participates in a multi-employer retirement income plan and a multi-employer postretirement
benefit plan, both of which provide retirement and health care and life insurance benefits to employees covered by certain labor
contracts. We do not administer these plans and contribute to them in accordance with the provisions of negotiated labor
contracts. The costs of providing these benefits, in aggregate, were $1.4 million, $1.4 million and $1.0 million during the years
ended December 31, 2016, 2015 and 2014, respectively.
Additionally, certain of our wholly owned subsidiaries provide a savings and retirement plan to employees. The costs of
providing these benefits, which primarily relates to BBH, were $1.4 million for all years ended December 31, 2016, 2015 and
2014.
101
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Employee Stock Ownership Plan
Services Company provides the ESOP to the majority of its employees hired before September 16, 2004. Employees hired
by Services Company after September 15, 2004 and certain employees covered by a union multiemployer pension plan do not
participate in the ESOP. The ESOP owns all of the outstanding common stock of Services Company. Buckeye, as primary
beneficiary, consolidates Services Company.
The ESOP was frozen with respect to benefits effective March 27, 2011 (the “Freeze Date”). No Services Company
contributions (other than dividend equivalent payments) have been made on behalf of current participants in the Plan after the
Freeze Date. Even though contributions under the ESOP are no longer being made, each eligible participant’s ESOP account
continues to be credited with its share of any stock dividends or other stock distributions associated with Services Company
stock.
Individual employees were allocated shares based upon the ratio of their eligible compensation to total eligible
compensation. Eligible compensation generally included base salary, overtime payments and certain bonuses. All Services
Company stock has been released to ESOP participants. Total ESOP related costs charged to earnings were nominal for each of
the years ended December 31, 2016, 2015, and 2014.
20. UNIT-BASED COMPENSATION PLANS
We award unit-based compensation to employees and directors primarily under the LTIP, which was approved by the
Partnership’s unitholders in June 2013. The LTIP replaced the 2009 Long-Term Incentive Plan (the “2009 Plan”), which was
merged with and into the LTIP, and no further grants will be made under the 2009 Plan. We formerly awarded options to
acquire LP Units to employees pursuant to the Buckeye Partners, L.P. Unit Option and Distribution Equivalent Plan (the
“Option Plan”).
We recognized compensation expense related to the LTIP, which includes awards under the 2009 Plan, and the Option Plan
of $33.5 million, $29.3 million and $21.5 million for the years ended December 31, 2016, 2015 and 2014, respectively.
LTIP
The LTIP, which is overseen by the Compensation Committee of the Board of Directors of Buckeye GP (the
“Compensation Committee”), provides for the grant of phantom units, performance units and in certain cases, distribution
equivalent rights (“DERs”), which provide the participant a right to receive payments based on distributions we make on our LP
Units. Phantom units are notional LP Units whose vesting is subject to service-based restrictions or other conditions
established by the Compensation Committee in its discretion. Phantom units entitle a participant to receive an LP Unit without
payment of an exercise price upon vesting. Performance units are notional LP Units whose vesting is subject to the attainment
of one or more performance goals, and which entitle a participant to receive LP Units without payment of an exercise price
upon vesting. DERs are rights to receive a cash payment per phantom unit or performance unit, as applicable, equal to the per
unit cash distribution we pay on our LP Units. The number of LP Units that may be granted to any one individual in a calendar
year will not exceed 100,000. If awards are forfeited, terminated or otherwise not paid in full, the LP Units underlying such
awards will again be available for purposes of the LTIP. Persons eligible to receive grants under the LTIP are (i) officers and
employees of Buckeye GP and any of our affiliates who provide services to us and (ii) independent members of the Board of
Directors of Buckeye GP. Phantom units or performance units may be granted to participants at any time as determined by the
Compensation Committee.
After giving effect to the issuance or forfeiture of phantom unit and performance unit awards through the year end, awards
representing a total of 2,071,509 LP Units were available for issuance under the LTIP as of December 31, 2016.
102
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Deferral Plan under the LTIP
On December 16, 2009, the Compensation Committee approved the terms of the Buckeye Partners, L.P. Unit Deferral and
Incentive Plan (“Deferral Plan”). The Compensation Committee is expressly authorized to adopt the Deferral Plan under the
terms of the LTIP, which grants the Compensation Committee the authority to establish a program pursuant to which our
phantom units may be awarded in lieu of cash compensation at the election of the employee. At December 31, 2016, 2015 and
2014, eligible employees were allowed to defer up to 50% of their 2016, 2015 and 2014 compensation awards under our
Annual Incentive Compensation Plan or other discretionary bonus program in exchange for grants of phantom units equal in
value to the amount of their cash award deferral (each such unit, a “Deferral Unit”). Participants also receive one matching
phantom unit for each Deferral Unit. Deferral Units and their matching phantom units vest on December 15 of the second year
after the year in which such units are granted. At December 31, 2016, $4.4 million of 2016 compensation awards had been
deferred, for which phantom units will be granted in 2017. At December 31, 2015, $3.1 million of 2015 compensation awards
had been deferred, for which 139,526 phantom units (including matching units) were granted during 2016. At December 31,
2014, $1.7 million of 2014 compensation awards had been deferred, for which 54,592 phantom units (including matching units)
were granted during 2015. These grants are included as granted in the LTIP activity table below.
Awards under the LTIP
During the year ended December 31, 2016, the Compensation Committee granted 342,572 phantom units to employees
(including the 139,526 phantom units granted pursuant to the Deferral Plan discussed above), 20,000 phantom units to
independent directors of Buckeye GP and 274,896 performance units to employees. The vesting criteria for the performance
units are the attainment of certain performance goals during the third year of a three-year period and remaining employed by us
throughout such three-year period.
Phantom unit grantees will be paid quarterly distributions on DERs associated with phantom units over their respective
vesting periods of one-year or three-years in the same amounts per phantom unit as distributions paid on our LP Units over
those same one-year or three-year periods. The amount paid with respect to phantom unit distributions was $3.6 million and
$2.6 million for the years ended December 31, 2016 and 2015, respectively. Distributions may be paid on performance units at
the end of the three-year vesting period. In such case, DERs will be paid on the number of LP Units for which the performance
units will be settled. Quarterly distributions related to DERs associated with phantom and performance units are recorded as a
reduction of our Limited Partners’ Capital on our consolidated balance sheets.
The following table sets forth the LTIP activity for the periods indicated (in thousands, except per unit amounts):
Unvested at January 1, 2015 .......................................................................................................
Granted .....................................................................................................................................
Vested........................................................................................................................................
Forfeited....................................................................................................................................
Unvested at December 31, 2015 .................................................................................................
Granted .....................................................................................................................................
Vested........................................................................................................................................
Forfeited....................................................................................................................................
Unvested at December 31, 2016 .................................................................................................
Number of
LP Units
906
435
(312)
(18)
1,011
637
(333)
(19)
1,296
Weighted
Average
Grant Date
Fair Value
per LP Unit (1)
63.56
$
73.45
62.08
67.32
68.20
53.47
58.89
60.76
63.54
$
$
____________________________
(1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. The weighted-
average grant date fair value per LP Unit for forfeited and vested awards is determined before an allowance for forfeitures.
At December 31, 2016, we expect to recognize $31.1 million of compensation expense related to the LTIP over a weighted
average period of 1.7 years.
103
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Unit Option and Distribution Equivalent Plan
We also sponsor the Option Plan pursuant to which we historically granted options to employees to purchase LP Units at
the market price of our LP Units on the date of grant. Generally, the options vest three years from the date of grant and expire
ten years from the date of grant. As unit options are exercised, we issue new LP Units to the holder. We have not historically
repurchased, and do not expect to repurchase in 2017, any of our LP Units. Following the adoption of the 2009 Plan effective
March 20, 2009, we ceased making additional grants under the Option Plan.
The following is a summary of the changes in the options outstanding (all of which are vested) under the Option Plan for
the periods indicated (in thousands, except per unit amounts):
Outstanding at January 1, 2015............................................
Exercised ...........................................................................
Forfeited, cancelled or expired ..........................................
Outstanding at December 31, 2015......................................
Exercised ...........................................................................
Forfeited, cancelled or expired ..........................................
Outstanding at December 31, 2016......................................
Exercisable at December 31, 2016.......................................
Number of
LP Units
Weighted-
Average
Strike Price
($/LP Unit)
$
26
(5)
(4) $
17
(6)
(1)
10
10
$
$
$
48.18
47.38
46.65
48.71
47.17
44.73
50.36
50.36
Weighted-
Average
Remaining
Contractual
Term (in years)
1.6
Aggregate
Intrinsic
Value (1)
$
703
0.9
$
300
0.1
0.1
$
$
151
151
____________________________
(1) Aggregate intrinsic value reflects fully vested LP Unit options at the date indicated. Intrinsic value is determined by
calculating the difference between our closing LP Unit price on the last trading day in 2016 and the exercise price,
multiplied by the number of exercisable, in-the-money options.
The total intrinsic value of options exercised during the years ended December 31, 2016, 2015 and 2014 was $0.1 million,
$0.1 million and $0.5 million, respectively. At December 31, 2016 and 2015, there was no unrecognized compensation cost
related to unvested options, as all options were vested as of November 24, 2011. At December 31, 2016, 333,000 LP Units
were available for grant in connection with the Option Plan. The fair value of options vested was zero for each of the years
ended December 31, 2016, 2015 and 2014, respectively.
21. RELATED PARTY TRANSACTIONS
We are managed by Buckeye GP, our general partner. Services Company is considered a related party with respect to us.
Services Company employees provide services to the majority of our operating subsidiaries. Pursuant to a services agreement
entered into in December 2004, our operating subsidiaries reimburse Services Company for the costs of the services provided
by Services Company. As Services Company is consolidated, these amounts eliminate in consolidation. Services Company,
which is beneficially owned by the ESOP, owned 0.6 million of our LP Units (0.4% of our LP Units outstanding) as of
December 31, 2016. Distributions received by Services Company from us on such LP Units are distributed to ESOP
participants for investment pursuant to the terms of the ESOP. Distributions paid to Services Company totaled $3.0 million,
$3.2 million and $3.2 million for the years ended December 31, 2016, 2015 and 2014, respectively. Total distributions paid to
Services Company decrease over time as Services Company sells LP Units to fund benefits payable to ESOP participants who
exit the ESOP or otherwise choose to diversify their holdings.
104
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
22. PARTNERS’ CAPITAL AND DISTRIBUTIONS
Our LP Units represent limited partner interests, which give the holders thereof the right to participate in distributions and
to exercise the other rights and privileges available to them under our partnership agreement. The partnership agreement
provides that, without prior approval of our limited partners holding an aggregate of at least two-thirds of the outstanding LP
Units, we cannot issue any LP Units of a class or series having preferences or other special or senior rights over the LP Units.
At-the-Market Offering Program
In March 2016, we entered into an equity distribution agreement (the “Equity Distribution Agreement”) with J.P. Morgan
Securities LLC, BB&T Capital Markets, a division of BB&T Securities, LLC, BNP Paribas Securities Corp., Deutsche Bank
Securities Inc., Jefferies LLC, Morgan Stanley & Co. LLC, RBC Capital Markets, LLC, and SMBC Nikko Securities
America, Inc. (collectively, the “ATM Underwriters”). Under the terms of the Equity Distribution Agreement, we may offer
and sell up to $500.0 million in aggregate gross sales proceeds of LP Units from time to time through the ATM Underwriters,
acting as agents of Buckeye or as principals, subject in each case to the terms and conditions set forth in the Equity Distribution
Agreement. This agreement replaced our prior four separate equity distribution agreements with each of Wells Fargo
Securities, LLC, Barclays Capital Inc., SunTrust Robinson Humphrey, Inc. and UBS Securities LLC, which we entered into in
May 2013 and, under the terms of which, we could sell up to $300.0 million in aggregate gross sales proceeds of LP Units from
time to time. Sales of LP Units, if any, may be made by means of ordinary brokers’ transactions on the New York Stock
Exchange or otherwise at market prices prevailing at the time of sale, at prices related to prevailing market prices or at
negotiated prices or as otherwise agreed with any of such firms. During the years ended December 31, 2016, 2015 and 2014,
we sold 1.6 million, 2.2 million and 1.0 million LP Units in aggregate under their active equity distribution agreements and
received $108.4 million, $161.5 million and $74.5 million in net proceeds after deducting commissions and other related
expenses, including $1.1 million, $1.6 million and $0.8 million of compensation paid in aggregate to the agents under their
active equity distribution agreements, respectively.
Equity Offerings
In October 2016, we completed a public offering of 7.75 million LP Units pursuant to an effective shelf registration
statement, which priced at $66.05 per unit. The underwriters also exercised an option to purchase 1.16 million additional
LP Units, resulting in total gross proceeds of $588.7 million before deducting underwriting fees and other related expenses of
$8.0 million. We used the net proceeds from this offering to initially reduce the indebtedness outstanding under our Credit
Facility and for general partnership purposes, as well as to subsequently fund a portion of the purchase price for the VTTI
Acquisition in January 2017.
In September 2014, we completed a public offering of 6.75 million LP Units pursuant to an effective shelf registration
statement, which priced at $80.00 per unit. In October 2014, the underwriters exercised an option to purchase up to an
additional 1.0 million LP Units, resulting in total gross proceeds of $621.0 million before deducting estimated underwriting fees
and offering expenses of $22.0 million. We used the net proceeds from this offering to reduce the indebtedness outstanding
under our Credit Facility, to fund a portion of the Buckeye Texas Partners Transaction and for general partnership purposes.
In August 2014, we completed a public offering of 2.6 million LP Units pursuant to an effective shelf registration
statement, which priced at $76.60 per unit. The underwriters also exercised an option to purchase 0.4 million additional
LP Units, resulting in total gross proceeds of $229.0 million before deducting estimated underwriting fees and offering
expenses of $2.4 million. We used the net proceeds from this offering to reduce the indebtedness outstanding under our Credit
Facility and for general partnership purposes.
105
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Summary of Changes in Outstanding Units
The following is a summary of changes in Buckeye’s outstanding units for the periods indicated (in thousands):
Units outstanding at January 1, 2014 .......................................................................................................................
LP Units issued pursuant to the Option Plan (1)......................................................................................................
LP Units issued pursuant to the LTIP (1).................................................................................................................
Issuance of units to institutional investors ...............................................................................................................
Issuance of units through equity distribution agreements........................................................................................
Units outstanding at December 31, 2014...............................................................................................................
LP Units issued pursuant to the Option Plan (1)......................................................................................................
LP Units issued pursuant to the LTIP (1).................................................................................................................
Issuance of units through equity distribution agreements........................................................................................
Units outstanding at December 31, 2015...............................................................................................................
LP Units issued pursuant to the Option Plan (1)......................................................................................................
LP Units issued pursuant to the LTIP (1).................................................................................................................
Issuance of units to institutional investors ...............................................................................................................
Issuance of units through Equity Distribution Agreement.......................................................................................
Units outstanding at December 31, 2016...............................................................................................................
____________________________
(1) The number of units issued represents issuance net of tax withholding.
Limited
Partners
115,064
18
198
10,752
1,011
127,043
5
229
2,247
129,524
6
254
8,913
1,567
140,264
106
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Cash Distributions
We generally make quarterly cash distributions to unitholders of substantially all of our available cash, generally defined in
our partnership agreement as consolidated cash receipts less consolidated cash expenditures and such retentions for working
capital, anticipated cash expenditures and contingencies as our general partner deems appropriate. Cash distributions paid to
unitholders of Buckeye for the periods indicated were as follows (in thousands, except per unit amounts):
Amount Per
LP Unit
Total Cash
Distributions
Payment Date
Record Date
February 18, 2014.................. February 25, 2014..................
May 12, 2014......................... May 19, 2014.........................
August 18, 2014..................... August 25, 2014.....................
November 18, 2014 ............... November 25, 2014 ...............
1.0875
1.1000
1.1125
1.1250
Total............................................................................................................................................
$
February 17, 2015.................. February 24, 2015..................
May 11, 2015......................... May 18, 2015.........................
August 10, 2015..................... August 17, 2015.....................
November 9, 2015 ................. November 17, 2015 ...............
1.1375
1.1500
1.1625
1.1750
Total............................................................................................................................................
$
February 23, 2016.................. March 1, 2016........................
May 16, 2016......................... May 23, 2016.........................
August 15, 2016..................... August 22, 2016.....................
November 15, 2016 ............... November 22, 2016 ...............
1.1875
1.2000
1.2125
1.2250
Total............................................................................................................................................
$
$
$
$
$
$
$
125,806
128,042
133,142
143,386
530,376
145,382
147,085
149,490
152,175
594,132
154,928
157,247
159,881
172,673
644,729
On February 10, 2017, we announced a quarterly distribution of $1.2375 per LP Unit that will be paid on February 28,
2017, to unitholders of record on February 21, 2017. Based on the LP Units outstanding as of December 31, 2016, cash
distributed to LP unitholders on February 28, 2017 will total $174.4 million.
23. INCOME TAXES
As of December 31, 2016 and 2015, we had net deferred tax assets of $0.4 million and $1.2 million, respectively, for BDL.
As of December 31, 2016, we had provided a full valuation allowance against the net deferred tax assets based on the available
evidence of projected future operating losses. As of December 31, 2015, BDL’s net operating loss carryforwards had been fully
utilized, primarily due to taxable income generated by the disposition of an ammonia pipeline in Texas, and therefore, we
released the valuation allowance against the net deferred tax assets based on our assessment of projected future book and
taxable income.
As of December 31, 2016 and 2015, we had net deferred tax assets of $42.1 million and $42.3 million related to Buckeye
Caribbean. As of December 31, 2016, $18.1 million of the deferred tax assets related to net operating loss carryforwards, and
unless utilized, the tax benefits of the net operating loss carryforwards will expire between 2020 and 2022. Based on available
evidence, we had recorded a full valuation allowance against the net deferred tax assets upon our acquisition of Buckeye
Caribbean during the year ended December 31, 2010. However, based on our assessment at December 31, 2016 and 2015, we
concluded that sufficient positive evidence exists, including the realization of book and taxable income and a forecast of future
book and taxable income, to realize $1.5 million and $1.3 million of these deferred tax assets, respectively, at December 31,
2016 and 2015.
107
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The tax effects of significant items comprising our net deferred tax assets and liabilities at December 31, 2016 and 2015 are
as follows (in thousands):
Deferred tax asset:
December 31,
2016
2015
Net operating loss carryforward ............................................................................................... $
Property, plant and equipment - refinery..................................................................................
Other .........................................................................................................................................
Total deferred tax asset................................................................................................................ $
18,909
22,333
2,608
43,850
Deferred tax liability:
Property, plant and equipment - terminals................................................................................ $
Other .........................................................................................................................................
Total deferred tax liability...........................................................................................................
Net deferred tax asset ..................................................................................................................
Less: Valuation allowance........................................................................................................
Deferred taxes, net ...................................................................................................................... $
1,224
123
1,347
42,503
(40,972)
1,531
$
$
$
$
18,236
23,447
3,016
44,699
1,189
—
1,189
43,510
(41,056)
2,454
We are currently not under any income tax audits or examinations. As of December 31, 2016, BDL’s tax years from 2013
to 2016 and Buckeye Caribbean’s tax years from 2012 through 2016 were open to examination by the Internal Revenue Service
and Puerto Rico Treasury Department, respectively.
108
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
24. EARNINGS PER UNIT
Basic and diluted earnings per LP Unit is calculated by dividing net income, after deducting the amount allocated to
noncontrolling interests, by the weighted-average number of LP Units outstanding during the period.
The following table is a reconciliation of the weighted average units outstanding used in computing the basic and diluted
earnings per unit for the periods indicated (in thousands, except per unit amounts):
Year Ended December 31,
Net income attributable to Buckeye Partners, L.P........................................... $
Basic:
2016
535,608
Weighted average units outstanding - basic .............................................
Earnings per unit - basic .................................................................................. $
132,242
4.05
Diluted:
Weighted average units outstanding - basic..................................................
Dilutive effect of LP Unit options and LTIP awards granted........................
Weighted average units outstanding - diluted ..........................................
Earnings per unit - diluted ............................................................................... $
132,242
685
132,927
4.03
2015
437,223
128,084
3.41
128,084
533
128,617
3.40
$
$
$
2014
272,954
119,323
2.29
119,323
576
119,899
2.28
$
$
$
25. BUSINESS SEGMENTS
We operate and report in three business segments: (i) Domestic Pipelines & Terminals; (ii) Global Marine Terminals; and
(iii) Merchant Services. Each segment uses the same accounting policies as those used in the preparation of our consolidated
financial statements. All inter-segment revenues, operating income and assets have been eliminated.
Domestic Pipelines & Terminals
The Domestic Pipelines & Terminals segment receives liquid petroleum products from refineries, connecting pipelines,
vessels, and bulk and marine terminals, transports those products to other locations for a fee, and provides bulk storage and
terminal throughput services. The segment also has butane blending capabilities and provides crude oil services, including train
loading/unloading, storage and throughput. This segment owns and operates pipeline systems and liquid petroleum products
terminals in the continental United States, including three terminals owned by the Merchant Services segment but operated by
the Domestic Pipelines & Terminals segment, and two underground propane storage caverns. Additionally, this segment
provides turn-key operations and maintenance of third-party pipelines and performs pipeline construction management services
typically for cost plus a fixed fee.
Global Marine Terminals
The Global Marine Terminals segment provides marine accessible bulk storage and blending services, rail and truck rack
loading/unloading along with petroleum processing services in the East Coast and Gulf Coast regions of the United States and
in the Caribbean. The segment has seven liquid petroleum product terminals located in The Bahamas, Puerto Rico and
St. Lucia in the Caribbean, as well as the New York Harbor and Corpus Christi, Texas in the United States.
Buckeye Texas owns storage and marine terminalling facilities that sit 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 facilities have 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.
109
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Merchant Services
The Merchant Services segment is a wholesale distributor of refined petroleum products in the United States and in the
Caribbean. This segment recognizes revenues when products are delivered. The segment’s products include gasoline, natural
gas liquids, ethanol, biodiesel and petroleum distillates such as heating oil, diesel fuel, kerosene and fuel oil. The segment
owns three terminals, which are operated by the Domestic Pipelines & Terminals segment. The segment’s customers consist
principally of product wholesalers as well as major commercial users of these refined petroleum products.
Natural Gas Storage Disposal Group
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. We have reported the results of operations for the disposal group as discontinued
operations for the years ended December 31, 2014. See Note 4 and Note 5 for further information.
Financial Information by Segment
The following tables summarize our financial information by each segment for the periods indicated (in thousands):
Revenue:
Domestic Pipelines & Terminals................................................................... $
Global Marine Terminals ..............................................................................
Merchant Services.........................................................................................
Intersegment..................................................................................................
Total revenue............................................................................................ $
1,011,696
671,465
1,621,915
(56,700)
3,248,376
$
$
966,749
514,301
2,037,664
(65,280)
3,453,434
$
$
938,036
395,306
5,358,626
(71,721)
6,620,247
Year Ended December 31,
2016
2015
2014
For the years ended December 31, 2016, 2015 and 2014, no customer contributed 10% or more of consolidated revenue.
Year Ended December 31,
2016
2015
2014
Capital expenditures, net: (1)
Domestic Pipelines & Terminals................................................................... $
Global Marine Terminals ..............................................................................
Merchant Services.........................................................................................
Total segment capital expenditures, net ...................................................
Natural Gas Storage disposal group (2) ........................................................
Total capital expenditures, net.................................................................. $
294,849
191,422
45
486,316
—
486,316
$
$
218,283
375,267
970
594,520
—
594,520
$
$
221,850
248,905
614
471,369
780
472,149
____________________________
(1) Amounts exclude the impact of accruals. See Note 26 for supplemental cash flow information.
(2) In December 2014, we sold our Natural Gas Storage segment and its related assets. See Note 4 for further information.
110
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31,
2016
2015
Total Assets:
Domestic Pipelines & Terminals (1)......................................................................................... $
Global Marine Terminals (2) ....................................................................................................
Merchant Services ....................................................................................................................
Total assets........................................................................................................................... $
4,412,464
4,494,995
513,644
9,421,103
$
$
3,498,883
4,500,705
369,693
8,369,281
____________________________
(1) All equity investments are included in the assets of the Domestic Pipelines & Terminals segment.
(2) The Global Marine Terminals segment’s long-lived assets consist of property, plant and equipment, goodwill, intangible
assets and other non-current assets. Total tangible long-lived assets located in our international locations were $1.5 billion
for both years ended December 31, 2016 and 2015.
The following tables summarize our financial information for continuing operations, by major geographic area, for the
periods indicated (in thousands):
Revenue:
United States ................................................................................................. $
International ..................................................................................................
Total revenue............................................................................................ $
2,915,619
332,757
3,248,376
$
$
3,115,450
337,984
3,453,434
$
$
6,279,142
341,105
6,620,247
Year Ended December 31,
2016
2015
2014
Adjusted EBITDA
Adjusted EBITDA is a measure not defined by GAAP. We define Adjusted EBITDA as earnings before interest expense,
income taxes, depreciation and amortization, further adjusted to exclude certain non-cash items, such as non-cash compensation
expense; transaction and transitions costs associated with acquisitions; 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.
We define distributable cash flow as Adjusted EBITDA less cash interest expense, cash income tax expense, and maintenance
capital expenditures. 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 that we use and that these measures
are useful to investors because they aid in comparing our operating performance with that of other companies with similar
operations. The Adjusted EBITDA data presented by us may not be comparable to similarly titled measures at other companies
because these items may be defined differently by other companies.
111
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following tables present Adjusted EBITDA from continuing operations by segment and on a consolidated basis and a
reconciliation of income from continuing operations to Adjusted EBITDA for the periods indicated (in thousands):
Year Ended December 31,
2016
2015
2014
Adjusted EBITDA from continuing operations:
Domestic Pipelines & Terminals................................................................... $
Global Marine Terminals ..............................................................................
Merchant Services.........................................................................................
Adjusted EBITDA from continuing operations ....................................... $
568,405
427,229
32,372
1,028,006
Reconciliation of Income from continuing operations to
Adjusted EBITDA from continuing operations:
Income from continuing operations................................................................. $
Less: Net income attributable to noncontrolling interests ..........................
Income from continuing operations attributable to Buckeye Partners, L.P.....
Add: Interest and debt expense...................................................................
Income tax expense ...........................................................................
Depreciation and amortization (1).....................................................
Non-cash unit-based compensation expense .....................................
Acquisition and transition expense (2) ..............................................
Litigation contingency accrual (3).....................................................
Hurricane-related costs (4) ................................................................
Less: Amortization of unfavorable storage contracts (5)............................
Gains on property damage recoveries (6)..........................................
Gain on sale of ammonia pipeline .....................................................
Adjusted EBITDA from continuing operations............................................... $
548,675
(13,067)
535,608
194,922
1,460
254,659
33,344
8,196
—
16,795
(5,979)
(5,700)
(5,299)
1,028,006
$
$
$
$
$
$
522,196
323,840
22,026
868,062
438,391
(311)
438,080
171,330
874
221,278
29,215
3,127
15,229
—
(11,071)
—
—
532,071
239,556
(8,059)
763,568
334,498
(1,903)
332,595
171,235
451
196,443
20,867
13,048
40,000
—
(11,071)
—
—
$
868,062
$
763,568
____________________________
(1) Includes 100% of the depreciation and amortization expense of $71.7 million, $49.3 million and $12.3 million for Buckeye
Texas for the years ended December 31, 2016, 2015 and 2014, 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 as a result of Hurricane Matthew, which occurred in October 2016, consisting
of $11.0 million of operating expenses and a $5.8 million write-off of damaged long-lived assets for the year ended
December 31, 2016.
(5) Represents amortization of negative fair value allocated to certain unfavorable storage contracts acquired in connection
with the BBH acquisition.
(6) Represents 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.
112
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
26. SUPPLEMENTAL CASH FLOW INFORMATION
Supplemental cash flows and non-cash transactions were as follows for the periods indicated (in thousands):
Cash paid for interest (net of capitalized interest) .......................................... $
Cash paid for income taxes .............................................................................
Capitalized interest..........................................................................................
Year Ended December 31,
$
2016
174,555
812
4,371
$
2015
156,654
1,705
21,257
2014
152,201
663
9,903
Liabilities related to capital projects outstanding at December 31, 2016, 2015, and 2014 of $59.1 million, $87.9 million,
and $60.4 million, respectively, are not included under “Capital expenditures” within the consolidated statement of cash flows.
113
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
27. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data for the periods indicated is set forth below (in thousands, except per unit amounts).
Quarterly results were influenced by seasonal and other factors inherent in our business. The results of operations of the
Natural Gas Storage disposal group have been reported as discontinued operations for all periods presented.
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
Total
2016
Revenue.................................................. $
Operating income...................................
Net income .............................................
Net income attributable to Buckeye
Partners, L.P...........................................
780,594
$
777,122
$
766,605
$
924,055
$
3,248,376
180,207
134,977
189,944
144,499
206,227
160,270
156,964
108,929
733,342
548,675
131,113
140,456
156,374
107,665
535,608
Earnings per unit - basic ........................ $
Earnings per unit - diluted...................... $
1.01
1.01
$
$
1.08
1.07
$
$
1.19
1.19
$
$
0.78
0.78
$
$
4.05
4.03
2015
Revenue (1)............................................ $
Operating income (1) .............................
Income from continuing operations (1) .
Loss from discontinued operations (2) ..
Net income (1) .......................................
Net income attributable to Buckeye
Partners, L.P. (1).....................................
Earnings (loss) per unit - basic
Continuing operations ....................... $
Discontinued operations....................
Total.............................................. $
Earnings (loss) per unit - diluted
Continuing operations ....................... $
Discontinued operations....................
Total.............................................. $
1,088,100
$
796,783
$
728,384
$
840,167
$
3,453,434
151,802
112,021
(857)
111,164
131,019
91,326
—
91,326
143,560
99,947
—
99,947
177,735
135,097
—
135,097
604,116
438,391
(857)
437,534
111,611
91,580
100,040
133,992
437,223
0.89
(0.01)
0.88
0.88
(0.01)
0.87
$
$
$
$
0.72
—
0.72
0.71
—
0.71
$
$
$
$
0.78
—
0.78
0.78
—
0.78
$
$
$
$
1.04
—
1.04
1.03
—
1.03
$
$
$
$
3.42
(0.01)
3.41
3.41
(0.01)
3.40
____________________________
(1) During the second quarter of 2015 and third quarter of 2015, we recorded reductions in revenue of $13.5 million and
$1.7 million, respectively, related to settlement of a FERC proceeding.
(2) We reported the final working capital adjustments related to the December 2014 completed sale of our Natural Gas Storage
disposal group as discontinued operations in the first quarter of 2015 (see Note 4).
114
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Our management, with the participation of our Chief Executive Officer (the “CEO”) and Chief Financial Officer (the
“CFO”), evaluated the design and effectiveness of our disclosure controls and procedures as of the end of the period covered by
this Report. Based on that evaluation, the CEO and CFO concluded that our disclosure controls and procedures as of the end of
the period covered by this Report are designed and operating effectively to provide reasonable assurance that the information
required to be disclosed by us in reports filed under the Securities Exchange Act of 1934, as amended, is: (i) recorded,
processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (ii) accumulated and
communicated to management, including the CEO and CFO, as appropriate to allow timely decisions regarding disclosure.
A controls system cannot provide absolute assurance, however, that the objectives of the controls system are met, and no
evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a company
have been detected.
Management’s Report on Internal Control Over Financial Reporting
Management’s report on internal control over financial reporting is set forth in Item 8 of this Report and is incorporated by
reference herein.
Attestation Report of the Registered Public Accounting Firm
The attestation report of our registered public accounting firm with respect to internal controls over financial reporting is
set forth in Item 8 of this Report and is incorporated by reference herein.
Change in Internal Control Over Financial Reporting
There have been no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the
Securities Exchange Act of 1934) or in other factors during the fourth quarter of 2016, that have materially affected, or are
reasonably likely to materially affect, our internal controls over financial reporting.
Item 9B. Other Information
Effective February 23, 2017, the responsibilities of Principal Accounting Officer were assigned to Keith E. St.Clair. Mr.
St.Clair is Executive Vice President and CFO of Buckeye GP LLC. Mr. St.Clair, 60, was named Executive Vice President and
CFO of Buckeye GP LLC in January 2012. He served as Senior Vice President and CFO of Buckeye GP LLC from November
2008 to January 2012. Mr. St.Clair has assumed these responsibilities from Patrick L. Pelton, who is no longer in the role of
Principal Accounting Officer but remains employed with the Partnership. The change in Principal Accounting Officer is not as a
result of any dispute or disagreement with Mr. Pelton over the Partnership’s accounting principles or practices, financial
statement disclosures, the Partnership's Business Code of Conduct or Code of Ethics, or other policy of the Partnership.
115
Item 10. Directors, Executive Officers and Corporate Governance
PART III
The information required by this item will be included in our definitive Proxy Statement in connection with our 2017
Annual Meeting of unitholders (the “2017 Proxy Statement”), which will be filed with the SEC within 120 days after the end of
the fiscal year ended December 31, 2016, under the headings “Proposal One: Election of Directors,” “Executive Officers” and
“Section 16(a) Beneficial Ownership Reporting Compliance” and is incorporated herein by reference.
Item 11. Executive Compensation
The information required by this item will be set forth in our 2017 Proxy Statement, which will be filed with the SEC
within 120 days after the end of the fiscal year ended December 31, 2016, under the headings “Compensation of Directors,”
“Compensation Discussion and Analysis,” “Executive Compensation” and “Compensation Committee Interlocks and Insider
Participation” and is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
The information required by this item will be set forth in our 2017 Proxy Statement, which will be filed with the SEC
within 120 days after the end of the fiscal year ended December 31, 2016, under the headings “Security Ownership of
Management and Certain Beneficial Owners” and “Equity Compensation Plans” and is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this item will be set forth in our 2017 Proxy Statement, which will be filed with the SEC
within 120 days after the end of the fiscal year ended December 31, 2016, under the headings “Independence of Directors” and
“Related Person Transactions and Procedures” and is incorporated herein by reference.
Item 14. Principal Accounting Fees and Services
The information required by this item will be included in our 2017 Proxy Statement, which will be filed with the SEC
within 120 days after the end of the fiscal year ended December 31, 2016, under the heading “Fees Paid to Deloitte & Touche
LLP” and is incorporated herein by reference.
PART IV
Item 15. Exhibits, Financial Statement Schedules
(a) The following documents are filed as a part of this Report:
(1) Financial Statements — See Item 8 of this Report.
(2) Financial Statement Schedules — None.
(3) Exhibits — The following is a list of exhibits filed as part of this Report including those incorporated by
reference.
116
Exhibit
Number
Description
2.1
3.1
3.2
3.3
3.4
3.5
3.6
3.7
3.8
3.9
4.1
4.2
4.3
Share Purchase Agreement, dated as of October 24, 2016, by and between VIP Terminals Finance B.V. and
Buckeye Partners, L.P. (Incorporated by reference to Exhibit 2.1 of Buckeye Partners, L.P.’s Current Report
on Form 8-K filed on October 24, 2016).
Amended and Restated Certificate of Limited Partnership of Buckeye Partners, L.P., dated as of February 4,
1998 (Incorporated by reference to Exhibit 3.2 of Buckeye Partners, L.P.’s Annual Report on Form 10-K for
the year ended December 31, 1997).
Certificate of Amendment to Amended and Restated Certificate of Limited Partnership of Buckeye Partners,
L.P., dated as of April 26, 2002 (Incorporated by reference to Exhibit 3.2 of Buckeye Partners, L.P.’s
Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2002).
Certificate of Amendment to Amended and Restated Certificate of Limited Partnership of Buckeye Partners,
L.P., dated as of June 1, 2004, effective as of June 3, 2004 (Incorporated by reference to Exhibit 3.3 of the
Buckeye Partners, L.P.’s Registration Statement on Form S-3 filed June 16, 2004).
Certificate of Amendment to Amended and Restated Certificate of Limited Partnership of Buckeye Partners,
L.P., dated as of December 15, 2004 (Incorporated by reference to Exhibit 3.5 of Buckeye Partners, L.P.’s
Annual Report on Form 10-K for the year ended December 31, 2004).
Amended and Restated Agreement of Limited Partnership of Buckeye Partners, L.P., dated as of
November 19, 2010 (Incorporated by reference to Exhibit 3.1 of Buckeye Partners, L.P.’s Current Report on
Form 8-K filed November 22, 2010).
Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Buckeye Partners, L.P.,
dated as of January 18, 2011 (Incorporated by reference to Exhibit 3.1 of Buckeye Partners, L.P.’s Current
Report on Form 8-K filed on January 20, 2011).
Amendment No. 2 to Amended and Restated Agreement of Limited Partnership of Buckeye Partners, L.P.,
dated as of February 21, 2013 (Incorporated by reference to Exhibit 3.1 of Buckeye Partners, L.P.’s Current
Report on Form 8-K filed on February 25, 2013).
Amendment No. 3 to Amended and Restated Agreement of Limited Partnership of Buckeye Partners, L.P.,
dated as of October 1, 2013, (Incorporated by reference to Exhibit 3.1 of Buckeye Partners, L.P.’s Current
Report on Form 8-K filed on October 7, 2013).
Amendment No. 4 to Amended and Restated Agreement of Limited Partnership of Buckeye Partners, L.P.,
dated as of September 29, 2014, (Incorporated by reference to Exhibit 3.1 of Buckeye Partners, L.P.’s
Current Report on Form 8-K filed on September 29, 2014).
Indenture dated as of July 10, 2003, between Buckeye Partners, L.P. and SunTrust Bank, as Trustee
(Incorporated by reference to Exhibit 4.1 of Buckeye Partners, L.P.’s Registration Statement on Form S-4
filed September 19, 2003).
Second Supplemental Indenture dated as of August 19, 2003, between Buckeye Partners, L.P. and SunTrust
Bank, as Trustee (Incorporated by reference to Exhibit 4.3 of Buckeye Partners, L.P.’s Registration
Statement on Form S-4 filed September 19, 2003).
Third Supplemental Indenture dated as of October 12, 2004, between Buckeye Partners, L.P. and SunTrust
Bank, as Trustee (Incorporated by reference to Exhibit 4.1 of Buckeye Partners, L.P.’s Current Report on
Form 8-K filed on October 14, 2004).
117
4.4
4.5
4.6
4.7
4.8
4.9
4.10
4.11
10.1
10.2
*10.3
*10.4
Fourth Supplemental Indenture dated as of June 30, 2005, between Buckeye Partners, L.P. and SunTrust
Bank, as Trustee (Incorporated by reference to Exhibit 4.1 of Buckeye Partners, L.P.’s Current Report on
Form 8-K filed on June 30, 2005).
Fifth Supplemental Indenture dated as of January 11, 2008, between Buckeye Partners, L.P. and U.S. Bank
National Association (successor to SunTrust Bank), as Trustee (Incorporated by reference to Exhibit 4.1 of
Buckeye Partners, L.P.’s Current Report on Form 8-K filed on January 11, 2008).
Sixth Supplemental Indenture dated as of August 18, 2009, between Buckeye Partners, L.P. and U.S. Bank
National Association (successor-in-interest to SunTrust Bank), as Trustee (Incorporated by reference to
Exhibit 4.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on August 24, 2009).
Seventh Supplemental Indenture dated as of January 13, 2011, between Buckeye Partners, L.P. and U.S.
Bank National Association (successor-in-interest to SunTrust Bank), as Trustee (Incorporated by reference
to Exhibit 4.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on January 20, 2011).
Eighth Supplemental Indenture dated as of June 10, 2013, between Buckeye Partners, L.P. and U.S. Bank
National Association (successor-in-interest to SunTrust Bank), as Trustee (Incorporated by reference to
Exhibit 4.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on June 12, 2013).
Ninth Supplemental Indenture dated as of November 14, 2013, between Buckeye Partners, L.P. and U.S.
Bank National Association (successor-in-interest to SunTrust Bank), as Trustee (Incorporated by reference
to Exhibit 4.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on November 19, 2013).
Tenth Supplemental Indenture, dated September 12, 2014, between Buckeye Partners, L.P. and U.S. Bank
National Association (successor-in-interest to SunTrust Bank), as trustee (Incorporated by reference to
Exhibit 4.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on September 12, 2014).
Eleventh Supplemental Indenture, dated November 7, 2016, between Buckeye Partners, L.P. and U.S. Bank
National Association (successor-in-interest to SunTrust Bank), as trustee (Incorporated by reference to
Exhibit 4.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on November 7, 2016).
Buckeye Partners, L.P. Unit Deferral and Incentive Plan, as amended and restated effective January 1, 2017
(Incorporated by reference to Exhibit 10.1 of Buckeye Partners, L.P.'s Current Report on Form 8-K filed on
December 19, 2016).
Services Agreement dated as of February 21, 2013, among Buckeye Partners, L.P., certain operating
subsidiaries of Buckeye Partners, L.P. and Services Company (Incorporated by reference to Exhibit 10.2 of
Buckeye Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2013).
Form of Severance Agreement for each Named Executive Officer (Incorporated by reference to Exhibit 10.1
of Buckeye Partners, L.P.’s Quarterly Report on Form 10-Q for the quarterly period ended September 30,
2015).
Amended and Restated Unit Option and Distribution Equivalent Plan of Buckeye Partners, L.P., dated as of
April 1, 2005 (Incorporated by reference to Exhibit 10.1 of Buckeye Partners, L.P.’s Current Report on
Form 8-K filed on April 4, 2005).
* **10.5
Buckeye Partners, L.P. 2013 Long-Term Incentive Plan, as amended and restated, effective February 1,
2017.
118
*10.6
*10.7
*10.8
*10.9
10.10
10.11
10.12
10.13
Buckeye Partners, L.P. Annual Incentive Compensation Plan ( as amended and restated, effective January 1,
2012) (Incorporated by reference to Exhibit 10.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K
filed on April 2, 2012).
Buckeye Partners, L.P. Non-Employee Director Deferred Compensation Plan, effective as of January 1,
2013 (Incorporated by reference to Exhibit 10.8 of Buckeye Partners, L.P.’s Annual Report on Form 10-K
for the year ended December 31, 2013).
Buckeye Pipe Line Company Benefit Equalization Plan, effective as of January 1, 2012 (Incorporated by
reference to Exhibit 10.9 of Buckeye Partners, L.P.’s Annual Report on Form 10-K for the year ended
December 31, 2013).
Revolving Credit Agreement, dated September 30, 2014, by and among Buckeye Partners, L.P., Buckeye
Energy Services LLC, Buckeye Caribbean Terminals LLC, Buckeye West Indies Holdings LP, SunTrust
Bank and other lenders party thereto (Incorporated by reference to Exhibit 10.1 to Buckeye Partners, L.P.’s
Current Report on Form 8-K filed on October 6, 2014).
First Amendment to Revolving Credit Agreement dated as of December 16, 2015, by and among Buckeye
Partners, L.P., Buckeye Energy Services LLC, Buckeye Caribbean Terminals LLC and Buckeye West Indies
Holdings LP, as borrowers, the lenders party thereto and SunTrust Bank, as administrative agent
(Incorporated by reference to Exhibit 10.1 to Buckeye Partners, L.P.’s Current Report on Form 8-K filed on
December 18, 2015).
Second Amendment to Revolving Credit Agreement dated as of September 30, 2016, by and among
Buckeye Partners, L.P., Buckeye Energy Services LLC, Buckeye Caribbean Terminals LLC and Buckeye
West Indies Holdings LP, as borrowers, the lenders party thereto and SunTrust Bank, as administrative agent
(Incorporated by reference to Exhibit 10.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on
October 3, 2016).
Term Loan Agreement dated as of September 30, 2016, by and among Buckeye Partners, L.P., as borrower,
the lenders party thereto and SunTrust Bank, as administrative agent (Incorporated by reference to Exhibit
10.2 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on October 3, 2016).
Distribution Agreement, dated March 9, 2016, among Buckeye Partners, L.P., Buckeye GP LLC and 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. (Incorporated by reference to Exhibit 1.1 to
Buckeye Partners, L.P.’s Current Report on Form 8-K filed on March 9, 2016).
* **10.14
Form of Phantom Unit Grant Agreement (Employee)
* **10.15
Form of Phantom Unit Grant Agreement (UDIP - Employee)
* **10.16
Form of Phantom Unit Grant Agreement (Director)
* **10.17
Form of Performance Unit Grant Agreement (Employee)
**12.1
Computation of Ratio of Earnings to Fixed Charges.
**21.1
List of Subsidiaries of Buckeye Partners, L.P.
**23.1
Consent of Deloitte & Touche LLP.
119
**31.1
**31.2
Certification of Chief Executive Officer pursuant to Rule 13a-14 (a) under the Securities Exchange Act of
1934.
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of
1934.
**32.1
Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350.
**32.2
Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350.
**101.INS
XBRL Instance Document.
**101.SCH
XBRL Taxonomy Extension Schema Document.
**101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document.
**101.LAB
XBRL Taxonomy Extension Label Linkbase Document.
**101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document.
**101.DEF
XBRL Taxonomy Extension Definition Linkbase Document.
____________________________
* Represents management contract or compensatory plan or arrangement.
** Filed herewith.
† Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. Buckeye agrees to furnish supplementally a
copy of the omitted schedules to the SEC upon request.
(a) Exhibits — See Item 15(a)(3) above.
120
Pursuant to the requirements of Section 13 of 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SIGNATURES
BUCKEYE PARTNERS, L.P.
(Registrant)
By:
Buckeye GP LLC,
as General Partner
Dated: February 24, 2017
By:
/s/ CLARK C. SMITH
Clark C. Smith
Chief Executive Officer, President and
Chairman of the Board
(Principal Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities and on the dates indicated.
121
Dated: February 24, 2017
By:
/s/
Dated: February 24, 2017
By:
/s/
Dated: February 24, 2017
By:
/s/
Dated: February 24, 2017
By:
/s/
PIETER BAKKER
Pieter Bakker
Director
BARBARA M. BAUMANN
Barbara M. Baumann
Director
BARBARA J. DUGANIER
Barbara J. Duganier
Director
JOSEPH A. LASALA, JR.
Joseph A. LaSala, Jr.
Director
Dated: February 24, 2017
By:
/s/ MARK C. MCKINLEY
Mark C. McKinley
Director
Dated: February 24, 2017
By:
/s/
Dated: February 24, 2017
By:
/s/
Dated: February 24, 2017
By:
/s/
Dated: February 24, 2017
By:
/s/
Dated: February 24, 2017
By:
/s/
LARRY C. PAYNE
Larry C. Payne
Director
OLIVER G. “RICK” RICHARD, III
Oliver “Rick” G. Richard, III
Director
CLARK C. SMITH
Clark C. Smith
Chief Executive Officer, President and Chairman
of the Board
(Principal Executive Officer)
FRANK S. SOWINSKI
Frank S. Sowinski
Lead Independent Director
KEITH E. ST.CLAIR
Keith E. St.Clair
Executive Vice President and Chief Financial
Officer
(Principal Financial Officer and Principal
Accounting Officer)
Dated: February 24, 2017
By:
/s/ MARTIN A. WHITE
Martin A. White
Director
122
INFORMATION
AUDIT COMMITTEE:
Barbara J. Duganier (Chair)
Barbara M. Baumann
(cid:51)(cid:72)(cid:89)(cid:89)(cid:96)(cid:3)(cid:42)(cid:21)(cid:3)(cid:55)(cid:72)(cid:96)(cid:85)(cid:76)
Frank S. Sowinski
COMPENSATION COMMITTEE:
(cid:54)(cid:83)(cid:80)(cid:93)(cid:76)(cid:89)(cid:3)(cid:46)(cid:21)(cid:3)(cid:184)(cid:57)(cid:80)(cid:74)(cid:82)(cid:185)(cid:3)(cid:57)(cid:80)(cid:74)(cid:79)(cid:72)(cid:89)(cid:75)(cid:19)(cid:3)(cid:48)(cid:48)(cid:48)(cid:3)(Chair)
Barbara M. Baumann
Barbara J. Duganier
(cid:49)(cid:86)(cid:90)(cid:76)(cid:87)(cid:79)(cid:3)(cid:40)(cid:21)(cid:3)(cid:51)(cid:72)(cid:58)(cid:72)(cid:83)(cid:72)(cid:19)(cid:3)(cid:49)(cid:89)(cid:21)
Mark C. McKinley
NOMINATING & CORPORATE GOVERNANCE
COMMITTEE:
Frank S. Sowinski (Chair)
Pieter Bakker
(cid:49)(cid:86)(cid:90)(cid:76)(cid:87)(cid:79)(cid:3)(cid:40)(cid:21)(cid:3)(cid:51)(cid:72)(cid:58)(cid:72)(cid:83)(cid:72)(cid:19)(cid:3)(cid:49)(cid:89)(cid:21)
(cid:54)(cid:83)(cid:80)(cid:93)(cid:76)(cid:89)(cid:3)(cid:46)(cid:21)(cid:3)(cid:184)(cid:57)(cid:80)(cid:74)(cid:82)(cid:185)(cid:3)(cid:57)(cid:80)(cid:74)(cid:79)(cid:72)(cid:89)(cid:75)(cid:19)(cid:3)(cid:48)(cid:48)(cid:48)
Martin A. White
HEALTH, SAFETY, SECURITY &
ENVIRONMENTAL COMMITTEE:
Martin A. White (Chair)
Pieter Bakker
Mark C. McKinley
(cid:51)(cid:72)(cid:89)(cid:89)(cid:96)(cid:3)(cid:42)(cid:21)(cid:3)(cid:55)(cid:72)(cid:96)(cid:85)(cid:76)
EQUAL OPPORTUNITY
(cid:41)(cid:92)(cid:74)(cid:82)(cid:76)(cid:96)(cid:76)(cid:3)(cid:55)(cid:72)(cid:89)(cid:91)(cid:85)(cid:76)(cid:89)(cid:90)(cid:19)(cid:3)(cid:51)(cid:21)(cid:55)(cid:21)(cid:3)(cid:87)(cid:89)(cid:86)(cid:93)(cid:80)(cid:75)(cid:76)(cid:90)(cid:3)(cid:76)(cid:88)(cid:92)(cid:72)(cid:83)(cid:3)(cid:86)(cid:87)(cid:87)(cid:86)(cid:89)(cid:91)(cid:92)(cid:85)(cid:80)(cid:91)(cid:96)(cid:3)
in all aspects of employment without regard
to race, color, creed, religion, ancestry, national
origin, gender, age, disability, veteran, or
marital status.
PRINCIPAL EXECUTIVE OFFICE
(cid:41)(cid:92)(cid:74)(cid:82)(cid:76)(cid:96)(cid:76)(cid:3)(cid:55)(cid:72)(cid:89)(cid:91)(cid:85)(cid:76)(cid:89)(cid:90)(cid:19)(cid:3)(cid:51)(cid:21)(cid:55)(cid:21)
One Greenway Plaza, Suite 600
Houston, TX 77046
832-615-8600
TRANSFER AGENT AND REGISTRAR
(cid:40)(cid:84)(cid:76)(cid:89)(cid:80)(cid:74)(cid:72)(cid:85)(cid:3)(cid:58)(cid:91)(cid:86)(cid:74)(cid:82)(cid:3)(cid:59)(cid:89)(cid:72)(cid:85)(cid:90)(cid:77)(cid:76)(cid:89)(cid:3)(cid:13)(cid:3)(cid:59)(cid:89)(cid:92)(cid:90)(cid:91)(cid:3)(cid:42)(cid:86)(cid:84)(cid:87)(cid:72)(cid:85)(cid:96)(cid:19)(cid:3)(cid:51)(cid:51)(cid:42)
6201 15th Avenue
Brooklyn, NY 11219
877-724-6457
www.amstock.com
UNITHOLDER TAX INFORMATION
(cid:55)(cid:89)(cid:80)(cid:74)(cid:76)(cid:94)(cid:72)(cid:91)(cid:76)(cid:89)(cid:79)(cid:86)(cid:92)(cid:90)(cid:76)(cid:42)(cid:86)(cid:86)(cid:87)(cid:76)(cid:89)(cid:90)(cid:19)(cid:3)(cid:51)(cid:51)(cid:55)
K-1 Support
(cid:55)(cid:21)(cid:54)(cid:21)(cid:3)(cid:41)(cid:86)(cid:95)(cid:3)(cid:30)(cid:32)(cid:32)(cid:23)(cid:29)(cid:23)
Dallas, TX 75379
800-230-7224
INVESTOR INFORMATION
For more information about
(cid:41)(cid:92)(cid:74)(cid:82)(cid:76)(cid:96)(cid:76)(cid:3)(cid:55)(cid:72)(cid:89)(cid:91)(cid:85)(cid:76)(cid:89)(cid:90)(cid:19)(cid:3)(cid:51)(cid:21)(cid:55)(cid:21)(cid:3)(cid:87)(cid:83)(cid:76)(cid:72)(cid:90)(cid:76)(cid:3)(cid:74)(cid:86)(cid:85)(cid:91)(cid:72)(cid:74)(cid:91)(cid:33)
Investor Relations
800-422-2825
irelations@buckeye.com
(cid:86)(cid:89)(cid:3)(cid:93)(cid:80)(cid:90)(cid:80)(cid:91)(cid:3)(cid:91)(cid:79)(cid:76)(cid:3)(cid:48)(cid:85)(cid:93)(cid:76)(cid:90)(cid:91)(cid:86)(cid:89)(cid:3)(cid:42)(cid:76)(cid:85)(cid:91)(cid:76)(cid:89)(cid:3)(cid:87)(cid:72)(cid:78)(cid:76)(cid:90)(cid:3)(cid:72)(cid:91)(cid:3)(cid:86)(cid:92)(cid:89)(cid:3)(cid:94)(cid:76)(cid:73)(cid:90)(cid:80)(cid:91)(cid:76)(cid:33)
www.buckeye.com
BOARD OF DIRECTORS & SENIOR EXECUTIVES
BOARD OF DIRECTORS
SENIOR EXECUTIVES
Front row: (cid:45)(cid:89)(cid:72)(cid:85)(cid:82)(cid:3)(cid:58)(cid:21)(cid:3)(cid:58)(cid:86)(cid:94)(cid:80)(cid:85)(cid:90)(cid:82)(cid:80)(cid:19)(cid:3)(cid:42)(cid:83)(cid:72)(cid:89)(cid:82)(cid:3)(cid:42)(cid:21)(cid:3)(cid:58)(cid:84)(cid:80)(cid:91)(cid:79)(cid:19)(cid:3)(cid:55)(cid:80)(cid:76)(cid:91)(cid:76)(cid:89)(cid:3)(cid:41)(cid:72)(cid:82)(cid:82)(cid:76)(cid:89)(cid:19)(cid:3)(cid:54)(cid:83)(cid:80)(cid:93)(cid:76)(cid:89)(cid:3)(cid:46)(cid:21)(cid:3)(cid:184)(cid:57)(cid:80)(cid:74)(cid:82)(cid:185)(cid:3)(cid:57)(cid:80)(cid:74)(cid:79)(cid:72)(cid:89)(cid:75)(cid:19)(cid:3)(cid:48)(cid:48)(cid:48)
Second row:(cid:3)(cid:49)(cid:86)(cid:90)(cid:76)(cid:87)(cid:79)(cid:3)(cid:40)(cid:21)(cid:3)(cid:51)(cid:72)(cid:58)(cid:72)(cid:83)(cid:72)(cid:19)(cid:3)(cid:49)(cid:89)(cid:21)(cid:19)(cid:3)(cid:41)(cid:72)(cid:89)(cid:73)(cid:72)(cid:89)(cid:72)(cid:3)(cid:49)(cid:21)(cid:3)(cid:43)(cid:92)(cid:78)(cid:72)(cid:85)(cid:80)(cid:76)(cid:89)(cid:19)(cid:3)(cid:52)(cid:72)(cid:89)(cid:91)(cid:80)(cid:85)(cid:3)(cid:40)(cid:21)(cid:3)(cid:62)(cid:79)(cid:80)(cid:91)(cid:76)(cid:19)(cid:3)(cid:51)(cid:72)(cid:89)(cid:89)(cid:96)(cid:3)(cid:42)(cid:21)(cid:3)(cid:55)(cid:72)(cid:96)(cid:85)(cid:76)(cid:19)(cid:3)
Barbara M. Baumann, Mark C. McKinley
Front row: Keith E. St.Clair, Clark C. Smith, Khalid A. Muslih
Second row: Robert A. Malecky, William J. Hollis, Mark S. Esselman, Joseph M. Sauger,
Todd J. Russo
Clark C. Smith
(cid:42)(cid:79)(cid:72)(cid:80)(cid:89)(cid:84)(cid:72)(cid:85)(cid:19)(cid:3)(cid:55)(cid:89)(cid:76)(cid:90)(cid:80)(cid:75)(cid:76)(cid:85)(cid:91)(cid:3)(cid:72)(cid:85)(cid:75)(cid:3)(cid:42)(cid:79)(cid:80)(cid:76)(cid:77)(cid:3)(cid:44)(cid:95)(cid:76)(cid:74)(cid:92)(cid:91)(cid:80)(cid:93)(cid:76)(cid:3)(cid:54)(cid:1117)(cid:74)(cid:76)(cid:89)
Clark C. Smith
(cid:55)(cid:89)(cid:76)(cid:90)(cid:80)(cid:75)(cid:76)(cid:85)(cid:91)(cid:3)(cid:72)(cid:85)(cid:75)(cid:3)(cid:42)(cid:79)(cid:80)(cid:76)(cid:77)(cid:3)(cid:44)(cid:95)(cid:76)(cid:74)(cid:92)(cid:91)(cid:80)(cid:93)(cid:76)(cid:3)(cid:54)(cid:1117)(cid:74)(cid:76)(cid:89)
Mark S. Esselman
Senior Vice President, Global Human Resources
William J. Hollis
Senior Vice President and President, Buckeye Services
Robert A. Malecky
Executive Vice President and President, Domestic Pipelines and
Terminals
Khalid A. Muslih
Executive Vice President and President, Global Marine Terminals
Todd J. Russo
Senior Vice President, General Counsel and Secretary
Joseph M. Sauger
Senior Vice President, Global Marine Terminals Operations and
Engineering
Keith E. St.Clair
(cid:44)(cid:95)(cid:76)(cid:74)(cid:92)(cid:91)(cid:80)(cid:93)(cid:76)(cid:3)(cid:61)(cid:80)(cid:74)(cid:76)(cid:3)(cid:55)(cid:89)(cid:76)(cid:90)(cid:80)(cid:75)(cid:76)(cid:85)(cid:91)(cid:3)(cid:72)(cid:85)(cid:75)(cid:3)(cid:42)(cid:79)(cid:80)(cid:76)(cid:77)(cid:3)(cid:45)(cid:80)(cid:85)(cid:72)(cid:85)(cid:74)(cid:80)(cid:72)(cid:83)(cid:3)(cid:54)(cid:1117)(cid:74)(cid:76)(cid:89)
Frank S. Sowinski
Lead Independent Director
(cid:52)(cid:72)(cid:85)(cid:72)(cid:78)(cid:76)(cid:84)(cid:76)(cid:85)(cid:91)(cid:3)(cid:40)(cid:1117)(cid:83)(cid:80)(cid:72)(cid:91)(cid:76)(cid:3)(cid:86)(cid:77)(cid:3)(cid:52)(cid:80)(cid:75)(cid:54)(cid:74)(cid:76)(cid:72)(cid:85)(cid:3)(cid:55)(cid:72)(cid:89)(cid:91)(cid:85)(cid:76)(cid:89)(cid:90)
Pieter Bakker
Chairman of First Reserve Tank Terminals Houston
Barbara M. Baumann
President of Cross Creek Energy Corporation
Barbara J. Duganier
Former Managing Director, Accenture
Joseph A. LaSala, Jr.
General Counsel, Publicis Groupe
Mark C. McKinley
Managing Partner of MK Resources
Larry C. Payne
(cid:55)(cid:89)(cid:76)(cid:90)(cid:80)(cid:75)(cid:76)(cid:85)(cid:91)(cid:3)(cid:72)(cid:85)(cid:75)(cid:3)(cid:42)(cid:79)(cid:80)(cid:76)(cid:77)(cid:3)(cid:44)(cid:95)(cid:76)(cid:74)(cid:92)(cid:91)(cid:80)(cid:93)(cid:76)(cid:3)(cid:54)(cid:1117)(cid:74)(cid:76)(cid:89)(cid:3)(cid:86)(cid:77)(cid:3)
(cid:51)(cid:44)(cid:58)(cid:40)(cid:3)(cid:13)(cid:3)(cid:40)(cid:90)(cid:90)(cid:86)(cid:74)(cid:80)(cid:72)(cid:91)(cid:76)(cid:90)(cid:19)(cid:3)(cid:51)(cid:51)(cid:42)
Oliver G. “Rick” Richard, III
Chairman of Cleanfuel USA, President of Empire of
(cid:91)(cid:79)(cid:76)(cid:3)(cid:58)(cid:76)(cid:76)(cid:75)(cid:3)(cid:51)(cid:51)(cid:42)(cid:19)(cid:3)(cid:72)(cid:85)(cid:75)(cid:3)(cid:77)(cid:86)(cid:89)(cid:84)(cid:76)(cid:89)(cid:3)(cid:42)(cid:79)(cid:72)(cid:80)(cid:89)(cid:84)(cid:72)(cid:85)(cid:19)(cid:3)(cid:55)(cid:89)(cid:76)(cid:90)(cid:80)(cid:75)(cid:76)(cid:85)(cid:91)(cid:3)(cid:72)(cid:85)(cid:75)(cid:3)
(cid:42)(cid:79)(cid:80)(cid:76)(cid:77)(cid:3)(cid:44)(cid:95)(cid:76)(cid:74)(cid:92)(cid:91)(cid:80)(cid:93)(cid:76)(cid:3)(cid:54)(cid:1117)(cid:74)(cid:76)(cid:89)(cid:3)(cid:86)(cid:77)(cid:3)(cid:42)(cid:86)(cid:83)(cid:92)(cid:84)(cid:73)(cid:80)(cid:72)(cid:3)(cid:44)(cid:85)(cid:76)(cid:89)(cid:78)(cid:96)(cid:3)(cid:46)(cid:89)(cid:86)(cid:92)(cid:87)
Martin A. White
(cid:45)(cid:86)(cid:89)(cid:84)(cid:76)(cid:89)(cid:3)(cid:55)(cid:89)(cid:76)(cid:90)(cid:80)(cid:75)(cid:76)(cid:85)(cid:91)(cid:3)(cid:72)(cid:85)(cid:75)(cid:3)(cid:42)(cid:79)(cid:80)(cid:76)(cid:77)(cid:3)(cid:44)(cid:95)(cid:76)(cid:74)(cid:92)(cid:91)(cid:80)(cid:93)(cid:76)(cid:3)(cid:54)(cid:1117)(cid:74)(cid:76)(cid:89)(cid:3)(cid:86)(cid:77)(cid:3)
MDU Resources Group, Inc.
One Greenway Plaza
Suite 600
Houston, TX 77046
www.buckeye.com