2015 ANNUAL REPORT
ABOUT US
BUCKEYE PARTNERS, L.P. (NYSE: BPL)
is a publicly traded master limited partnership
and owns and operates a diversified network
of integrated assets providing midstream
logistic solutions, primarily consisting of the
transportation, storage, and marketing of liquid
petroleum products.
ORGANIZATIONAL OVERVIEW
DOMESTIC PIPELINES & TERMINALS
~6,000 miles of pipeline with ~110 delivery locations
Over 115 liquid petroleum product terminals
~55 million barrels of liquid petroleum product storage capacity
Stable fee-based cash flows derived from throughput volumes, tariffs and
terminalling and storage fees
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
Seven liquid petroleum product terminals in: the Caribbean, including
The Bahamas, St. Lucia and Puerto Rico; New York Harbor, including
Perth Amboy, Port Reading, Raritan Bay; and South Texas
~63 million barrels of liquid petroleum product storage capacity
Deep water capability to handle ULCCs and VLCCs in The Bahamas and
St. Lucia
Ship, barge, truck rack, rail and pipeline transportation in the New York
Harbor
Condensate splitters and connectivity through truck rack, pipeline, and
marine handling capabilities in South Texas
Revenue supported by take or pay contracts
In February 2016, Buckeye Partners
was announced as the winner of
the 2016 Alerian MLP Award, or
Ammy, for the Highest Total Return
for 2015 among its Large Cap MLP
peers included in the Alerian Master
Limited Partnership (MLP) Index.
This was the inaugural year for the
Ammys, which were launched by
Alerian to celebrate the people and
companies that have contributed
to the emergence and understanding
of MLPs.
Cover photo: Construction crew
inside late 19th century wooden
petroleum storage tank
MERCHANT SERVICES
Markets liquid petroleum products in areas served by Domestic Pipelines &
Terminals and Global Marine Terminals
DEAR UNITHOLDERS:
2015 WAS AN EXCEPTIONAL YEAR
for Buckeye Partners, both operationally and financially,
as we generated record earnings and cash flows and
increased distributions to our unitholders. Once again,
we proved our ability to follow through on our strategic
growth initiatives, which delivered incremental cash flows.
Our outstanding financial results enabled Buckeye’s total
unitholder return for the year to outperform our peers and
further demonstrated the benefits of our diversification
strategy and the strength of our position in the industry
despite volatility in both the commodity and stock markets.
Clark C. Smith
Chairman, President and
Chief Executive Officer
These stellar results would not have been possible without the hard work of Buckeye’s employees. Over the
past year, we have continued to strengthen our organization with additional talented members. We believe we
have a deeper talent base today than ever before at Buckeye, and the drive and commitment of our dedicated
team members have enabled us to continue to produce outstanding operational and financial results, driving
total unitholder returns.
Safety is at the Forefront of Our Culture
In 2015, we implemented a company-wide safety training initiative involving all our Buckeye field employees,
our senior leadership team, and our board members. The program included extensive occupational and safety
training as well as live drills. As a result of the successful program, we saw improvements across the board
in our safety and operational incident metrics. For 2016, we are continuing to expand our safety emphasis
internally and externally through regional contractor safety training schools, qualification guidelines for third-party
inspectors, and further improving our contractor orientation processes. Going forward, Buckeye will continue
its leadership commitment to a “safety first” philosophy in all of our businesses.
Buckeye Segments Delivered Positive 2015 Contributions
I am pleased to report that all three of our business segments posted solid results for 2015. Our Global Marine
Terminals and Merchant Services segments drove substantial incremental contributions, and we were able
to capitalize on the strong demand in the market to increase utilization of our storage assets to 96 percent for
the year, while successfully re-contracting anchor tenants at our largest facilities. Our Domestic Pipelines &
Terminals segment also delivered solid performance, despite the substantial decline in commodity prices,
A N N U A L R E P O R T 2 0 1 5 1
as we were able to drive increased throughput
volumes in both our pipelines and terminals.
Capital Projects Drive Our Growth
Over the past year, we have made additional
progress on our initiative to expand Buckeye
Partners’ geographic footprint as we continue to
build out our four strategically-located Buckeye
hubs in Chicago, New York Harbor, the Caribbean,
and the Gulf Coast.
Since the September 2014 formation of Buckeye
Texas Partners, our partnership with Trafigura
Trading LLC, we have substantially completed
phase one of the planned expansion of those
assets. This includes the addition of 1.1 million
barrels of refrigerated liquid petroleum gas, or
“LPG,” storage and the commissioning in late
2015 of a 50,000 barrel per day condensate splitter
facility. These newly completed assets, along with
Newly commissioned condensate splitter at Buckeye Texas Partners’ facility
all of the assets in South Texas, are in commercial service under long-term take-or-pay tolling and storage
agreements. Through our 80 percent ownership interest in the partnership, we have invested nearly $1.2 billion
in capital to create a world-class midstream global marine hub providing extensive connectivity to worldwide
markets. We expect to benefit as these investments contribute substantial incremental cash flow in 2016.
Our partnership with Trafigura has been built on principles of integrity, strategic vision, core values, a steadfast
work ethic, and an unwavering commitment to safety. Working together, we have developed a mutual respect and
trust in each other’s capabilities and business acumen, leveraging our individual strengths while forging a solid
alliance committed to the achievement of our goals. Buckeye Texas Partners provides substantial logistics,
processing and handling capabilities as an unparalleled midstream platform in the Gulf Coast. Working with
Trafigura, we are confident that Buckeye Texas Partners will play a critical role in the liquid petroleum products
logistics value chain, and we look forward to building on our successful partnership for many years to come.
Looking beyond South Texas, we identified and capitalized on numerous additional opportunities to effectively
deploy capital during 2015. Early in the year, we acquired a small but strategic terminal and pipeline in New
England. We also transported our first shipment of processed condensate from our newly completed rail offloading
2 B U C K E Y E P A R T N E R S , L . P.
OUR OUTSTANDING
FINANCIAL RESULTS
FOR THE YEAR
ENABLED BUCKEYE’S
TOTAL UNITHOLDER
RETURN FOR THE YEAR
TO OUTPERFORM OUR
PEERS AND FURTHER
DEMONSTRATED
THE BENEFITS OF
OUR DIVERSIFICATION
STRATEGY.
facility at Perth Amboy in the New York Harbor. In addition,
we successfully secured binding shipper commitments related
to our Chicago-based Cross Town Pipeline project. This project
will provide additional pipeline capacity from our strategic
Chicago Complex to various delivery locations in the greater
Chicago market.
Throughout 2015, we continued to make progress on our
Michigan/Ohio pipeline and terminal expansion project, and
we successfully executed take-or-pay transportation service
agreements with 10-year terms with all committed shippers for
the project. Once the project is completed in late 2016, the
expansion will allow Buckeye to offer enhanced transportation
service of refined petroleum products to destination points in
eastern Ohio and western Pennsylvania, expanding the supply
orbits for the advantaged Midwestern refineries.
FERC Approved Settlement with Airlines
In the third quarter of 2015, we were pleased
to receive approval from the Federal Energy
Regulatory Commission (FERC) on the settlement
of our three-year dispute with several airlines
that were challenging Buckeye’s rates for
transportation of jet fuel from New Jersey to the
New York City area airports. This settlement
resolved all FERC complaints filed by the parties.
We continue to work with these airlines on
improvements to enhance the utilization of our
pipeline systems to the New York City airports.
Our Financial Performance Outpaces
the Industry
We have strategically built our organization to
better withstand fluctuations in both commodity
markets and the economy in general. Our
diversified portfolio of quality assets generates
A N N U A L R E P O R T 2 0 1 5 3
Crude and kerosene product storage tanks at
Buckeye Texas Partners’ facility
consistent, predictable, fee-based cash flow, and in fact, 95 percent of our 2015 adjusted EBITDA was
fee-based. Our strong operational and financial performance continues to surpass that of the majority of our
peers. We have limited commodity exposure and limited counterparty risk, as most of our customers are
large, fiscally sound enterprises. Our domestic system is primarily demand-pull, limiting the impact of supply
disruptions on our business.
Our balance sheet is healthy, with sufficient liquidity to fund our growth projects. For 2016, we expect to invest
$325 to $375 million in growth capital while maintaining distribution growth of $0.0125 per quarter and also
improving our coverage ratio, which was 1.02x at year end.
Buckeye Has Multiple Avenues for Growth
Looking forward, we see numerous growth opportunities for Buckeye Partners, and we are excited to continue
to expand our market presence as we evaluate additional growth projects and acquisitions that we believe will
generate long-term value for our unitholders. For example, we are exploring opportunities to utilize our footprint
to provide producers with logistics solutions for condensates and natural gas liquids, and we are evaluating the
best way to expand our butane blending capabilities.
As we celebrate our 130-year anniversary, I want to
thank our board of directors, our employees, our
unitholders, our customers and the communities that
we serve for their ongoing support of the Buckeye
organization. I want to reiterate how proud I am of
our entire team and what they have accomplished
over the past year. We understand that focusing
on operational excellence, safety and continued
execution on our growth capital projects are the
keys to building long-term value for our unitholders.
We intend to maintain our focus on these important
initiatives going forward to ensure the continued
success of Buckeye Partners.
Clark C. Smith
Chairman, President and Chief Executive Officer
4 B U C K E Y E P A R T N E R S , L . P.
Buckeye construction crew utilizing crawler tractors for pipeline
construction in the early 20th century
2015 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, 2015
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, 2015, the aggregate market value of the registrant’s limited partner units held by non-affiliates was $9.4 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 19, 2016, there were 129,723,002 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 2016 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 3.
Item 4.
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 12.
Item 13.
Item 14.
Page
1
17
30
30
31
34
35
37
38
53
56
118
118
118
118
118
119
119
119
Item 15.
Exhibits, Financial Statement Schedules....................................................................................................
119
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; and (x) our
ability to successfully complete our organic growth projects and to realize the anticipated financial benefits. These factors are
not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our
forward-looking statements. Other known or unpredictable factors could also have material adverse effects on future results.
Consequently, all of the forward-looking statements made in this document are qualified by these cautionary statements, and we
cannot assure you that actual results or developments that we anticipate will be realized or, even if substantially realized, will
have the expected consequences to or effect on us or our business or operations. Also note that we provide additional
cautionary discussion of risks and uncertainties under the captions “Risk Factors” and in “Management’s Discussion and
Analysis of Financial Condition and Results of Operations” and elsewhere in this Report.
The forward-looking statements contained in this Report speak only as of the date hereof. Although the expectations in the
forward-looking statements are based on our current beliefs and expectations, caution should be taken not to place undue
reliance on any such forward-looking statements because such statements speak only as of the date hereof. Except as required
by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements,
whether as a result of new information, future events or any other reason. All forward-looking statements attributable to us or
any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in
this Report and in our future periodic reports filed with the U.S. Securities and Exchange Commission (“SEC”). In light of
these risks, uncertainties and assumptions, the forward-looking events discussed in this Report may not occur.
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 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 110 million barrels across our portfolio of pipelines, inland terminals
and marine terminals located primarily in the East Coast 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, 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 recent expansion into the Gulf Coast
has added another regional hub with world-class marine terminalling, storage and processing capabilities. We are also a
wholesale distributor of refined petroleum products in areas served by our pipelines and terminals.
In December 2015, we realigned our reportable segments into three reportable segments as a result of changes in our
organizational structure and renamed one of our reportable segments. Our three reportable segments are: Domestic Pipelines &
Terminals (formerly known as Pipelines & Terminals), Global Marine Terminals and Merchant Services. We merged our
previously reported Development & Logistics segment into the Domestic Pipelines & Terminals segment. See Note 25 in the
Notes to Consolidated Financial Statements for a more detailed discussion of our business segments. We have adjusted our
prior period segment information to conform to current year presentation.
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
2015 Transactions
Credit Facility
In December 2015, 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, modified the $1.5 billion revolving credit facility with SunTrust Bank, as
administrative agent, and other lenders (the “Credit Facility”) to extend the maturity date of the Credit Facility by one year to
September 30, 2020, with an option to extend the term for one additional year and a $500.0 million accordion option to increase
the commitments with the consent of the lenders. 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 modification and
extension of the Credit Facility. At December 31, 2015, Buckeye and BMSC collectively had $472.5 million outstanding under
the Credit Facility, of which $111.5 million, attributable to BMSC, was classified as current liabilities in our consolidated
balance sheet, as related funds were used to finance current working capital needs.
At-the-Market Offering Program
During the years ended December 31, 2015 and 2014, we sold 2.2 million and 1.0 million LP Units in aggregate under the
equity distribution agreements entered into in May 2013 with each of Wells Fargo Securities, LLC, Barclays Capital Inc.,
SunTrust Robinson Humphrey, Inc. and UBS Securities LLC (each an “Equity Distribution Agreement” and collectively the
“Equity Distribution Agreements”), received $161.5 million and $74.5 million in net proceeds after deducting commissions and
other related expenses, and paid $1.6 million and $0.8 million of compensation in aggregate to the agents under the Equity
Distribution Agreements, respectively.
2
Business Activities
The following discussion describes the business activities of our business segments, which include Domestic Pipelines &
Terminals, Global Marine Terminals and Merchant Services.
The Domestic Pipelines & Terminals, Global Marine 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):
2015
2014
2013
Revenue
Percent
Revenue
Percent
Revenue
Percent
Year Ended December 31,
Domestic Pipelines & Terminals.... $
Global Marine Terminals................
Merchant Services (1) ....................
Intersegment ...................................
966,749
514,301
2,037,664
(65,280)
Total ............................................. $ 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
844,832
14.2 % $
6.0 %
252,270
80.9 % 3,990,575
(33,576)
(1.1)%
100.0 % $ 5,054,101
16.7 %
5.0 %
79.0 %
(0.7)%
100.0 %
____________________________________
(1) The decrease in revenue for the year ended December 31, 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 supply 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 117 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.
3
The following table presents product volumes and percentage of products transported by the pipelines in the Domestic
Pipelines & Terminals segment for the periods indicated (barrels per day (“bpd”) in thousands):
2015
2014
2013
Year Ended December 31,
Pipelines:
Gasoline ..................................
Jet fuel .....................................
Middle distillates (1) ...............
Other products (2) ...................
Total pipelines throughput.........
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%
717.8
334.4
345.7
28.5
1,426.4
50.3%
23.5%
24.2%
2.0%
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 two refineries, 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 our operating subsidiary
Laurel Pipe Line Company, L.P. (“Laurel”) pipeline 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.
Our operating subsidiary Buckeye Pipe Line Transportation LLC (“BPL Transportation”) pipeline system 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.
4
Our operating subsidiary Wood River Pipe Lines LLC (“Wood River”) owns liquid petroleum products pipelines with
aggregate mileage of approximately 1,250 miles located in the Midwestern United States. Liquid petroleum products are
received from the Wood River refinery in the East St. Louis, Illinois area and transported to the Chicago area (the “Chicago
Complex”), to our terminal in the St. Louis, Missouri area and to the Lambert-St. Louis Airport, to delivery points across
Illinois and Indiana and to our pipeline in Lima, Ohio, and from the Chicago Complex to the Kankakee, Illinois area.
Other Liquid Petroleum Products Pipelines. BPLC serves Connecticut and Massachusetts through an approximately
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.
5
The following table sets forth the total average daily throughput for terminals and storage caverns within the Domestic
Pipelines & Terminals segment for the periods indicated (volume of bpd in thousands):
Year Ended December 31,
2015
2014
2013
Products throughput (1) ..................................................................................
1,215.4
1,147.5
985.7
____________________________
(1) Amounts include throughput at the five 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 previously
reported in our Development & Logistics segment. We have adjusted prior period throughput volumes to conform to
current year presentation.
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
14
11
4
1
4
4
117
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
4,003
2,536
2,191
328
1,805
1,228
55,639
____________________________
(1) This table includes five 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 17.0 million barrels of storage capacity with the remaining capacity used for throughput.
6
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
650-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.
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.
7
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
4,624
15,653
10,261
5,981
62,632
_____________________________
(1) This table represents total storage capacity as of December 31, 2015, of which approximately 8.8 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 Partners LLC (“Buckeye Texas”), which is 80% owned
by us.
BORCO Facility
BORCO 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 BORCO
facilitate customer activities within the tank farm and at the jetties.
BORCO’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 BORCO’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 BORCO terminalling facility is located. BORCO 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. BORCO 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 44 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 BORCO facility, enabling our
customers to take advantage of BORCO’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 51 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 61 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 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,
approximately 6.0 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 five 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..................................................................................................
1,215.0
2015
2014
2,009.0
2013
1,371.5
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, 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, in New York
Harbor and in 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, 2015, 2014 and 2013, no customer contributed 10% or more of our consolidated
revenue. In the Global Marine Terminals segment, storage revenue represented approximately 77% of BORCO’s total revenue
for the year ended December 31, 2015. Currently, BORCO has a limited number of long-term storage customers, consisting of
major oil companies, energy companies, physical traders and one national oil company. For the year ended December 31, 2015,
approximately 26% and 61% of BORCO’s storage revenue was derived from the top one and the top three customers,
respectively. We expect BORCO to continue to derive substantially all of its total revenue from a small number of customers in
the future.
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.
The Global Marine Terminals segment’s mix and volume of products stored does not vary significantly by season.
12
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, 2015, Services Company had approximately 1,490 employees, approximately 310 of whom were represented
by labor unions. Additionally, at December 31, 2015, certain of our wholly owned subsidiaries had approximately 275
employees, approximately 160 of whom are employed at our BORCO 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.
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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 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,” governs 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 and 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 BORCO 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”) and its agency, the
Pipeline and Hazardous Materials Safety Administration (“PHMSA”), under the Pipeline Safety Act (“PSA”). The PSA and
PHMSA implement regulations to 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 other
things, these programs include: integrity management requirements for pipelines located in high consequence areas, operator
qualification program requirements, control room management plan, public awareness plan, and drug & alcohol plan
requirements. 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 compatible 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 Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (“PSA 2011”) was signed into law on January 3,
2012. PHMSA has completed certain of the studies and rulemaking mandated by PSA 2011. A number of mandates remain
outstanding, however, that will either directly or potentially impact the oil and gas industry. These include studies and rules
regarding, among other things, expansion of integrity management requirements, leak detection, automatic and remote shut off
valves, incident notification, maximum operating pressure verification, and public awareness. PHMSA proposed rules
regarding expansion of integrity management requirements and leak detection to liquid pipelines and incident notification,
among other things, which would impact both gas (49 CFR Part 192) and liquid (49 CFR Part 195) regulations. Those rules are
not yet final. PSA 2011 was up for reauthorization by Congress in late 2015 but such reauthorization is not yet final.
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, 2016.
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 BORCO, 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.
Recent increases in 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.
Generally, pipelines are the lowest cost method for long-haul overland movement of liquid petroleum products. Therefore,
the most significant competitors for large volume shipments in our Domestic Pipelines & Terminals segment are other existing
pipelines, some of which are owned or controlled by major integrated oil and gas companies. In addition, new pipelines
(including pipeline segments that connect with existing pipeline systems) could be built to effectively compete with us in
particular locations.
Our 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 the New York
City area, the Pittsburgh area, Connecticut and locations on the Ohio River such as Cincinnati, Ohio and locations on the
Mississippi River, such as St. Louis, Missouri. Additionally, our South Portland and Bangor, Maine terminals are mainly
supplied by overseas ships from Canada and Europe.
Trucks competitively deliver liquid petroleum products in a number of areas that we serve. While their costs may not be
competitive for longer hauls or large volume shipments, trucks compete effectively for incremental and marginal volumes in
many areas that we serve. The availability of truck transportation places a significant competitive constraint on our ability to
increase our tariff rates.
Privately arranged exchanges of liquid petroleum products between marketers in different locations are another form of
competition for our Domestic Pipelines & Terminals segment. Generally, these exchanges reduce both parties’ costs by
eliminating or reducing transportation charges. In addition, consolidation among refiners and marketers, which has accelerated
in recent years, has altered distribution patterns, reducing demand for transportation services in some markets and increasing
them in other markets.
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 delivering liquid petroleum products to end-users such as retail
gasoline stations.
Our Global Marine Terminals segment primarily competes with other marine terminals in the Caribbean, in New York
Harbor and in the Gulf Coast. Many competitive terminals are owned by major energy companies, refiners and master limited
partnerships. Although the Global Marine Terminals segment’s storage fees are not regulated, the segment is subject to price
competition from competitive terminals. Our Global Marine Terminals segment also competes with alternatives to terminal
storage of crude oil and refined petroleum products, such as floating storage and lightering, which could reduce demand for our
Caribbean terminalling services.
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.
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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.
Approval from the Central Bank of The Bahamas will be required before BORCO can make distributions to us. 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.
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.
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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.
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.
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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 “greenhouse gases” (“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.
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:
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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.
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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 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 BORCO and St. Lucia operations may be adversely affected by economic, political and regulatory developments.
BORCO’s terminalling facility and the St. Lucia terminal are located in The Bahamas and St. Lucia, respectively. 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, as well as changes in the policies of the United States
affecting trade, taxation and investment in other countries. Any such developments or changes could have a material adverse
effect on our business, results of operations and cash flow.
Compliance with laws and regulations that apply to our Caribbean 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 in the Caribbean and could
have a material adverse effect on our business, financial results and cash flow.
We may not be able to fully implement or capitalize upon planned organic growth projects.
We have a number of organic growth projects that involve the construction, expansion or modification of existing assets.
Many of these projects involve numerous regulatory, environmental, commercial, economic, weather-related, political and legal
uncertainties that are beyond our control, including the following:
• As these projects are undertaken, required approvals, permits and licenses may not be obtained, may be delayed or
may be obtained with conditions that materially alter the expected return associated with the underlying projects;
• A depressed crude oil price environment may make it more difficult for producers and other customers to commit to
long-term contracts that provide commercial support for certain organic growth projects.
• Despite the fact that we will expend significant amounts of capital during the construction phase of these projects,
revenues associated with these organic growth projects will not materialize until the projects have been completed and
placed into commercial service, and the amount of revenue generated from these projects could be significantly lower
than anticipated for a variety of reasons;
• We may not be able to secure, or we may be significantly delayed in obtaining, all of the rights of way or other real
property interests we need to complete such projects, or the costs we incur in order to obtain such rights of way or
other interests may be greater than we anticipated;
• We may construct pipelines, facilities or other assets in anticipation of market demand that dissipates or market growth
that never materializes;
• Due to unavailability or costs of materials, supplies, power, labor or equipment, the cost of completing these projects
could turn out to be significantly higher than we budgeted and the time it takes to complete construction of these
projects and place them into commercial service could be significantly longer than planned; and
• The completion or success of our projects may depend on the completion or success of third-party facilities over which
we have no control.
As a result of these uncertainties, the anticipated benefits associated with our capital projects may not be achieved. In turn,
this could negatively impact our cash flow and our ability to make or increase cash distributions to our unitholders.
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Our results could be adversely affected by volatility in the price of refined petroleum products.
The Merchant Services segment buys and sells refined petroleum products in connection with its marketing activities.
If the values of refined petroleum products change in a direction or manner that we do not anticipate, we could experience
financial losses from these activities. Furthermore, when refined petroleum product prices decrease rapidly, we may be unable
to promptly pass our additional costs to our customers, resulting in lower margins for us which could adversely affect our
results of operations. Factors that could cause significant increases or decreases in commodity prices include changes in supply
due to production constraints, weather, governmental regulations, and changes in consumer demand. It is our practice to
maintain a position that is substantially balanced between commodity purchases, on the one hand, and expected commodity
sales or future delivery obligations, on the other hand. Through these transactions, we seek to establish a margin for the
commodity purchased by selling the same commodity for physical delivery to third-party users, such as wholesalers or retailers.
While our hedging policies are designed to minimize commodity price risk, some degree of exposure to unforeseen fluctuations
in market conditions remains. For example, any event that disrupts our anticipated physical supply could expose us to risk of
loss resulting from price changes if we are required to obtain alternative supplies to cover these sales transactions. In addition,
we are also exposed to basis risk which is created when a commodity of a certain grade or location is purchased, sold, or
exchanged for a like commodity at a different time or location. For example, we use NYMEX traded products, which deliver in
New York Harbor, to hedge our commodity risk associated with physical transactions that will be delivered at other locations,
such as Macungie, Pennsylvania. We are also susceptible to basis risk in our hedging activities that arises when a commodity,
such as the purchase of heating oil at one location must be hedged against the New York Harbor ultra low sulfur diesel futures
contract as a result of limitations within the financial markets for derivative products.
A substantial amount of the petroleum products handled by BORCO are exported from Venezuela, which exposes us to
political risks.
A substantial portion of BORCO’s revenue relates to petroleum products exported from Venezuela. This involvement with
products exported from Venezuela exposes BORCO to significant risks, including potential political and economic instability
and trade restrictions and economic embargoes imposed by the United States and other countries.
BORCO depends on a limited number of customers for substantially all of its revenue, and the loss of any of them could
adversely affect our results of operations and cash flow.
Storage revenue represented 77% of BORCO’s total revenue for the year ended December 31, 2015. Currently, BORCO
has a limited number of long-term storage customers, consisting of major oil companies, energy companies, physical traders
and one national oil company. For the year ended December 31, 2015, 26% and 61% of BORCO’s storage revenue was derived
from the top one and the top three customers, in the aggregate, respectively. We expect BORCO to continue to derive
substantially all of its total revenue from a small number of customers in the future. BORCO may be unsuccessful in renewing
its storage contracts with its customers, and those customers may discontinue or reduce contracted storage from BORCO. If
any of BORCO’s customers, in particular its top three customers, significantly reduces its contracted storage with BORCO and
if BORCO is unable to find other storage customers on terms substantially similar to the terms under BORCO’s existing storage
contracts, our business, results of operations and cash flow could be adversely affected.
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.
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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. Cyber security attacks in particular 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 lead to financial losses from remedial actions, business
interruptions, and loss of business or potential liability.
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, 2015, 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 in the future may have an adverse effect on our ability to do so.
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The rulemaking process under the Dodd-Frank Act has not been completed, so 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.
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.
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Unitholders may not have limited liability in some circumstances.
The limitations on the liability of holders of limited partnership interests for the obligations of a limited partnership have
not been clearly established in some states. If it were determined that we had been conducting business in any state without
compliance with the applicable limited partnership statute, or that the unitholders as a group took any action pursuant to our
partnership agreement that constituted participation in the “control” of our business, then the unitholders could be held liable
under some circumstances for our obligations to the same extent as a general partner.
Under applicable state law, our general partner has unlimited liability for our obligations, including our debts and
environmental liabilities, if any, except for our contractual obligations that are expressly made without recourse to the general
partner.
In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that under some
circumstances a unitholder may be liable to us for the amount of distributions paid to the unitholder for a period of three years
from the date of the distribution.
Tax Risks to Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being
subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (“IRS”) were to
treat us as a corporation for federal income tax purposes, or we become subject to entity-level taxation for state tax
purposes, our cash available for distribution to you would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our LP Units depends largely on our being treated as a
partnership for federal income tax purposes.
Despite the fact that we are organized as a limited partnership under Delaware law, we will be treated as a corporation for
U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations and
the private letter rulings we have received with respect to certain aspects of our business, we believe we satisfy the qualifying
income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated
as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation.
If we were treated as a corporation for federal income tax purposes, we would pay U.S. federal income tax on our taxable
income at the corporate tax rate, which 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.
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. For example,
the Obama administration’s budget proposal for fiscal year 2017 recommended that certain publicly traded partnerships earning
income from activities related to fossil fuels be taxed as corporations beginning in 2022. From time to time, members of
Congress propose and consider similar substantive changes to the existing federal income tax laws that affect publicly traded
partnerships. If successful, such proposals could eliminate 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.
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In addition, the Internal Revenue Service, on May 5, 2015, issued proposed regulations concerning which activities give
rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code. We do not believe the proposed
regulations affect our ability to qualify as a publicly traded partnership. However, finalized regulations could modify the
amount of our gross income that we are able to treat as qualifying income for the purposes of the qualifying income
requirement and modify or revoke existing private letter rulings, including ours.
Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or
impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal
income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted.
Any such changes could negatively impact the value of an investment in our LP Units.
If the IRS were to contest the federal income tax positions we take, it may adversely impact the market for our LP Units,
and the costs of any such contest would reduce cash available for distribution to you. Recently enacted legislation alters the
procedures for assessing and collecting taxes due for taxable years beginning after December 31, 2017, in a manner that
could substantially 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.
Recently enacted legislation, applicable to us for taxable years beginning after December 31, 2017, alters the procedures
for auditing large partnerships and also alters the procedures for assessing and collecting taxes due (including applicable
penalties and interest) as a result of an audit. Under the new rules, unless we are eligible to, and do, elect to issue a revised
Schedule K-1 to each of our partners with respect to an audited and adjusted return, the IRS may assess and collect taxes
(including any applicable penalties and interest) directly from us in the year in which the audit is completed. If we are required
to pay taxes, penalties and interest as the result of audit adjustments, cash available for distribution to our unitholders may be
substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed,
unitholders during that taxable year would bear the expense of the adjustment even if they were not unitholders during the
audited taxable year.
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.
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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.
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 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 U.S. Department of the Treasury recently adopted final Treasury Regulations allowing a similar monthly
simplifying convention for taxable years beginning on or after August 3, 2015. However, such regulations do not specifically
authorize the use of the proration method we have adopted for our 2015 taxable year and may not specifically authorize all
aspects of our proration method thereafter. 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.
29
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.
You will likely be subject to state and local taxes and income tax return filing requirements in jurisdictions where you
do not live as a result of investing in our LP Units.
In addition to U.S. federal income taxes, you may be subject to other taxes, including non-U.S., 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 you do not live in any of those jurisdictions. You will likely
be required to file non-U.S., state and local income tax returns and pay state and local income taxes in some or all of these
various jurisdictions. Further, you 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 own property and conduct business in Puerto Rico, The Bahamas and in
St. Lucia. Under current law, you are not required to file a tax return or pay taxes in Puerto Rico, The Bahamas and in
St. Lucia. 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.
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.
30
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.
Pennsauken Allisions. Our terminal located in Pennsauken, New Jersey suffered two allisions in the second half of 2014.
The first occurred on August 5, 2014, when a vessel allided with our terminal’s “Ship Dock.” We immediately “arrested” the
vessel and commenced litigation against its owner. Security for our claim was provided by the vessel owner’s insurers, in the
amount of $19.0 million, reserving all of their defenses. The vessel owners soon stipulated to liability, so the only issue in
dispute is the amount of Buckeye’s damages, which is now the subject of discovery. Reconstruction of the Ship Dock was
completed in July 2015 and service has since resumed. The aggregate cost to reconstruct the dock was approximately
$8.0 million. The second incident occurred on October 5, 2014, when a tug and barge struck and damaged the Pennsauken
terminal’s “Barge Dock.” The tug and barge owners have commenced proceedings to limit their liability to $1.0 million and
$5.0 million, respectively. We have filed claims in the limitation proceedings for the reconstruction of the Barge Dock and
response costs, together amounting to approximately $7.0 million. We have suffered and continue to suffer loss-of-use damages
as a result of the above allisions, as the two incidents together impacted the ability of vessels of a certain size and/or carrying
certain products to call at the terminal. In order to mitigate these business losses, we made modifications to two other berths at
a cost of $1.4 million. Recovery for both the mitigation costs and business losses is being sought jointly from all of the
respective responsible parties. We are insured for loss of use, subject to a 30 day deductible. Our insurers have been involved
in the recovery efforts. In 2015, we received insurance recoveries of $5.1 million related to the loss of use of our terminal,
which we have recognized within “Transportation, storage and other services” in our consolidated statement of operations.
BORCO Jetty. On May 25, 2012, a ship, Cape Bari, allided with a jetty at our BORCO facility while berthing, causing
damage to portions of the jetty. Buckeye has insurance to cover this loss, subject to a $5.0 million deductible. On
May 26, 2012, we commenced legal proceedings in The Bahamas against the vessel’s owner and the vessel to obtain security
for the cost of repairs and other losses incurred as a result of the incident. Full security for our claim has been provided by the
vessel owner’s insurers, reserving all of their defenses. We also have notified the customer on whose behalf the vessel was at
the BORCO facility that we intend to hold them responsible for all damages and losses resulting from the incident pursuant to
the terms of an agreement between the parties. Any disputes between us and our customer on this matter are subject to
arbitration in New York, New York, and arbitration has commenced.
The vessel owner has claimed that it is entitled to limit its liability to $17.0 million, but we are contesting the right of the
vessel owner to such limitation. The Bahamas court of first instance denied the vessel owner the right to limit its liability for
the incident, leaving the vessel owner responsible for all provable damages. The vessel owner appealed, and The Bahamas
Court of Appeals reversed, holding that the vessel owner may limit its liability. Our application for leave to appeal the Court of
Appeals’ decision to the Privy Council was granted, the hearing occurred on February 23, 2016 and we await that decision. We
can express no view on whether The Bahamas Court of Appeals decision ultimately will be affirmed or reversed.
We experienced no material interruption of service at the BORCO facility as a result of the incident, and the repairs and
reconstruction of the damaged sections are complete.
31
The aggregate cost to repair and reconstruct the damaged portions of the jetty and pursue recovery in court has been
$23.0 million. We recorded a loss on disposal due to the assets destroyed in the incident and other related costs incurred;
however, since we believe recovery of our losses is probable, we recorded a corresponding receivable. As of December 31,
2015, we had a $6.4 million receivable included in “Other non-current assets” in our consolidated balance sheet, representing
claims for reimbursement of the deductible and other third-party expenses. Additionally, we have received insurance
reimbursements of $16.0 million, and to the extent the aggregate proceeds from the recovery of our losses is in excess of the
carrying value of the destroyed assets or other costs incurred, we will recognize a gain when such proceeds are received and are
not refundable. Our insurers have paid most of the claim and are now parties in The Bahamas litigation. As of December 31,
2015, no gain had been recognized; however, we recorded a $14.1 million deferred gain in “Accrued and other current
liabilities” in our consolidated balance sheet, representing excess proceeds received over the loss on disposal and other costs
incurred.
On May 12, 2014, the vessel owner filed a third-party complaint against BORCO and a BORCO subsidiary, Borco Towing
Company Limited, alleging negligence by the pilots and tugs that assisted the Cape Bari berthing. We have investigated these
allegations and believe that we have defenses and intend to defend ourselves and pursue our claims against the vessel owner.
BORCO and Borco Towing Company Limited are insured for the alleged liability, subject to an applicable deductible, and the
liability insurers are participating in the defense. The main proceeding and third-party actions have been consolidated and are
expected to go to trial in May 2016.
Buckeye Texas Partners Contractor Dispute. Buckeye Texas Processing LLC, a wholly owned subsidiary of Buckeye
Texas, is party to a contract with Ventech Engineers USA, LLC (“Ventech”). The contract required Ventech to design, supply,
fabricate, and install two condensate splitters in Corpus Christi, Texas (the “Splitter Project”). Ventech’s primary subcontractor
on the Splitter Project was Bay, Ltd. (“Bay”). Certain disputes arose on the Splitter Project relating to payment, delays, cost
overruns, defective work, and other issues. On October 14, 2015, Bay filed a lawsuit in Harris County District Court against us
and Ventech, claiming breach of contract, fraud, and other causes of action primarily premised on alleged non-payment of
amounts due on the Splitter Project. We also believe that, if the matter is not resolved, Ventech may claim that it is also owed
additional money for its work on the Splitter Project. We disagree with assertions that we owe Ventech and Bay additional
amounts and, if resolution cannot be reached, we intend to pursue claims against Ventech and Bay relating to the delays, cost
overruns, defective work, and other issues on the Splitter Project. In addition, Ventech provided a bond on the Splitter Project
that may help to satisfy some of our losses. Our damages may exceed the damages claimed by Ventech and Bay. The parties
have agreed to mediate to seek to resolve the disputes between them, and settlement discussions are ongoing.
FERC Proceedings
FERC Docket No. OR12-28-000 — Airlines Complaint against BPLC New York City Jet Fuel Rates. On September 20,
2012, a complaint was filed with FERC by Delta Air Lines, JetBlue Airways, United/Continental Air Lines, and US Airways
challenging BPLC’s rates for transportation of jet fuel from New Jersey to three New York City airports. The complaint was not
directed at BPLC’s rates for service to other destinations and did not involve pipeline systems and terminals owned by
Buckeye’s other operating subsidiaries. The complaint challenges these jet fuel transportation rates as generating revenues in
excess of costs and thus being “unjust and unreasonable” under the Interstate Commerce Act. On February 22, 2013, FERC
issued an order setting the airline complaint in Docket (“Dkt.”) No. OR12-28-000 for hearing, but holding the hearing in
abeyance and setting the dispute for settlement procedures before a settlement judge. On March 8, 2013, an order was issued
consolidating, for settlement purposes, this complaint proceeding with the proceeding regarding BPLC’s application for market-
based rates in the New York City market in Dkt. No. OR13-3-000 (discussed below), and settlement discussions under the
supervision of the FERC settlement judge continued until April 1, 2014 when the FERC settlement judge reported that the
parties had been unable to reach a settlement. As a result, the matter proceeded to hearing, which was concluded on April 1,
2015. As a result of developments in ongoing settlement talks regarding Dkt. Nos. OR12-28-000, OR13-3-000 (discussed
below) and OR 14-41-000 (discussed below), we recorded an accrual and a corresponding reduction in revenue in the amount
of $40.0 million in the year ended December 31, 2014 in our Domestic Pipelines & Terminals segment.
32
In parallel with the hearing in the OR12-28-000 proceeding, BPLC and the airlines continued to pursue settlement. On
June 19, 2015, BPLC and the airlines submitted an Offer of Settlement at the FERC (the “Settlement”) to resolve the
complaints in Dkt. Nos. OR12-28-000, et al. and OR14-41-000, as well as BPLC’s application in Dkt. No. OR13-3-000. Under
the terms of the Settlement, BPLC agreed to reduce its jet fuel rates prospectively, to make settlement payments to the airlines,
to install facilities to increase the flexibility and capacity of its system in shipping jet fuel to John F. Kennedy International
Airport, and to resolve its application in Dkt. No. OR13-3-000 as described further below. As a result of submission of the
Settlement, we recorded an additional accrual and corresponding reduction in revenue in the amount of $15.2 million during the
year ended December 31, 2015 in our Domestic Pipelines & Terminals segment, which, together with the previously recorded
$40.0 million reduction in revenue, represented anticipated settlement payments and other expenses associated with the
Settlement. On September 29, 2015, the FERC approved the Settlement without modification. On October 1, 2015, BPLC filed
a tariff to implement the terms of the Settlement, including the agreed-upon reductions in jet fuel rates effective November 1,
2015 (the “Settlement Tariff”) in Dkt. No. IS16-7-000. On October 16, 2015, a jet fuel marketer and three airlines not parties to
the Settlement protested the tariff, alleging that certain provisions of an incentive rate program provided for in the Settlement
are unduly discriminatory (the “Protest”). On October 30, 2015, the FERC rejected the Protest on the merits and accepted the
Settlement Tariff, permitting the reduced rates to go into effect on November 1, 2015. On October 29, 2015, the same jet fuel
marketer and airlines sought late intervention and rehearing at the FERC to challenge FERC’s approval of the Settlement
alleging, on a basis similar to the Protest, that certain provisions of the Settlement’s incentive rate program are unduly
discriminatory. BPLC and the settling airlines responded that the Protest’s claims were invalid and untimely. On December 2,
2015, the FERC denied the late intervention request, which had the effect of barring the rehearing request. During the quarter
ended December 31, 2015, we made payments of $52.8 million related to the Settlement.
FERC Docket No. OR14-41-000 — American Airlines Complaint against BPLC New York City Jet Fuel Rates. On
September 17, 2014, a complaint was filed with FERC by American Airlines raising claims similar to the Dkt. No.
OR12-28-000 complaint (see above). As noted above, the Settlement to resolve this complaint was approved by the FERC on
September 29, 2015.
FERC Docket No. OR13-3-000 — BPLC’s Market-Based Rate Application. On October 15, 2012, BPLC filed an
application with FERC seeking authority to charge market-based rates for deliveries of liquid petroleum products to the New
York City-area market (the “Application”). In the Application, BPLC sought to charge market-based rates from its three origin
points in northeastern New Jersey to its five destinations on its Long Island System, including deliveries of jet fuel to the
Newark, LaGuardia, and JFK airports. On December 14, 2012, Delta Air Lines, JetBlue Airways, United/Continental Air
Lines, and US Airways filed a joint intervention and protest challenging the Application and requesting its rejection. Following
further pleadings, on February 28, 2013, FERC set the Application for hearing but held the hearing in abeyance and set the
dispute for settlement procedures before a settlement judge. After unsuccessful settlement talks, litigation as to the Application
proceeded separately from the complaint proceeding. Prior to the hearing, the airlines and BPLC reached an agreement in
principle, and as noted above, submitted an Offer of Settlement to the FERC to resolve the airlines’ objections to the
Application. Under the terms of the Settlement, BPLC agreed, inter alia, to withdraw the portions of the Application addressing
transportation of jet fuel within the New York City market, including transportation of jet fuel to the three airports, while
remaining free to pursue market-based rates for transportation of other refined petroleum products to other destinations within
the New York City market. As noted above, the Settlement was approved by the FERC on September 29, 2015, and on October
5, 2015, BPLC filed a notice withdrawing the Application except as to the transportation of other refined petroleum products
from Linden, New Jersey to Inwood and Long Island City, New York. On February 11, 2016, BPLC submitted a joint motion
with the support of FERC Trial Staff requesting that FERC waive the issuance of an initial decision, and instead issue an order
addressing the revised application of BPLC, based on evidence submitted by Commission Trial Staff and BPLC, both of whose
additional evidence found that BPLC lacked significant market power over the transportation of other refined petroleum
products from Linden, New Jersey to Inwood and Long Island City, New York. FERC has not yet issued an order in response
to the filing submitted on February 11, 2016.
Environmental Proceedings
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, intends to seek a reduction in the amount of the proposed penalty in 2016. 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.
33
On December 16, 2015, PHMSA issued to Buckeye a notice of probable violation (NOPV 1-2015-2021) relating to a July
2013 inspection of the Malvern, Booth and Macungie area pipelines. The NOPV includes 5 probable violations related to
Buckeye’s Corrosion Control program inspections and implementation. Four of the five violations included proposed civil
penalties totaling $0.3 million. Buckeye is currently reviewing the alleged violations.
In December 2014, Buckeye received a penalty from the Indiana Department of Environmental Management (“IDEM”)
primarily in connection with air emissions control device operations outside of the parameters of the permit at our terminal in
Hammond, Indiana. IDEM issued a final agreed order, and Buckeye paid $0.2 million in connection therewith in October 2015.
In November 2014, Buckeye received a notice of probable violation from the PHMSA in connection with certain
recordkeeping and procedural issues related to our assets in the Linden, New Jersey area. Buckeye responded contesting
certain of the violations and requesting a reduced penalty. PHMSA granted a slight penalty reduction, and in December 2015,
Buckeye paid a penalty of approximately $0.2 million.
Item 4. Mine Safety Disclosures
Not applicable.
34
PART II
Item 5. Market for the Registrant’s Units, Related Unitholder Matters, and Issuer Purchases of 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, 2015 and 2014, as reported in the NYSE Composite Transactions, were as follows:
Quarter
First ....................................................................................
Second................................................................................
Third...................................................................................
Fourth.................................................................................
2015
2014
High
Low
High
Low
$
78.30
$
69.52
$
75.83
$
82.98
76.56
72.43
73.93
52.91
52.04
83.72
84.91
85.14
69.19
74.50
75.26
63.77
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, 2010
and that all distributions or dividends were reinvested on a quarterly basis.
12/31/2010
12/31/2011
12/31/2012
12/31/2013
12/31/2014
12/31/2015
Buckeye Partners, L.P... $
S&P 500 .......................
Alerian MLP Index.......
100.00
$
102.05
$
77.67
$
130.96
$
147.76
$
100.00
100.00
102.11
113.88
118.45
119.34
156.82
152.26
178.28
159.57
137.31
180.75
107.57
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 142,000 at December 31, 2015.
35
Cash distributions paid to unitholders for the periods indicated were as follows:
Record Date
February 19, 2013................................... February 28, 2013
May 16, 2013 .......................................... May 31, 2013
August 12, 2013...................................... August 20, 2013
November 12, 2013 ................................ November 19, 2013
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
Amount Per
LP Unit
$1.0375
$1.0500
$1.0625
$1.0750
$1.0875
$1.1000
$1.1125
$1.1250
$1.1375
$1.1500
$1.1625
$1.1750
On February 12, 2016, we announced a quarterly distribution of $1.1875 per LP Unit that will be paid on March 1, 2016, to
unitholders of record on February 23, 2016. Based on the LP Units outstanding as of December 31, 2015, cash distributed to
unitholders on March 1, 2016 will total $154.4 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.
36
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):
2015
2014
2013
2012
2011
Year Ended December 31,
Income Statement Data:
Revenue (1) ............................................................... $ 3,453,434
604,116
Operating income (1) (2) ...........................................
438,391
Income from continuing operations (1) (2) ...............
Earnings per unit - diluted from continuing
operations .................................................................. $
Cash distributions per LP Unit - declared ................. $
3.41
4.68
$ 6,620,247
495,347
334,498
$ 5,054,101
478,041
351,599
$ 4,285,903
344,536
235,879
$ 4,693,620
365,845
291,827
$
$
2.78
4.48
$
$
3.23
4.28
$
$
2.37
4.15
$
$
3.15
4.08
2015
2014
2013
2012
2011
December 31,
Balance Sheet Data:
Total assets (3) (4) ..................................................... $ 8,369,281
Long-term debt (4) ....................................................
3,732,824
Total Buckeye Partners, L.P. capital..........................
3,735,389
$ 8,065,720
$ 6,988,024
$ 5,972,910
$ 5,560,717
3,368,618
3,075,172
2,727,145
2,383,915
3,702,628
3,065,665
2,372,313
2,303,169
____________________________
(1) The decrease in revenue for the year ended December 31, 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 supply 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 (see Note 5 in
the Notes to the Consolidated Financial Statements).
(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 (see
Note 2 in the Notes to Consolidated Financial Statements for further discussion), we reclassified $20.4 million,
$17.5 million, $8.1 million and $9.7 million of debt issuance costs originally included in “Other non-current assets” as of
each respective year ending December 31, 2014 through 2011 to “Long-term debt” as a direct deduction from the carrying
amount of debt liability, consistent with debt discounts.
37
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 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 110 million barrels across our portfolio of pipelines, inland terminals
and marine terminals located primarily in the East Coast 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, 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 recent expansion into the Gulf Coast has added another regional hub with world-class marine
terminalling, storage and processing capabilities. We are also a wholesale distributor of refined petroleum products in areas
served by our pipelines and terminals.
In December 2015, we realigned our reportable segments into three reportable segments as a result of changes in our
organizational structure and renamed one of our reportable segments. Our three reportable segments are: Domestic Pipelines &
Terminals (formerly known as Pipelines & Terminals), Global Marine Terminals and Merchant Services. We merged our
previously reported Development & Logistics segment into the Domestic Pipelines & Terminals segment. See Note 25 in the
Notes to Consolidated Financial Statements for a more detailed discussion of our business segments. We have adjusted our
prior period segment information to conform to current year presentation.
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 $437.2 million for the year ended December 31, 2015, which was an
increase of $164.3 million, or 60.2%, from $273.0 million for the corresponding period in 2014. Operating income was
$604.1 million for the year ended December 31, 2015, which is an increase of $108.8 million, or 22.0%, from $495.3 million
the corresponding period in 2014. Our operating income results for the year ended December 31, 2015 include year-over-year
improvement in each of our three segments despite mixed business conditions in a declining price environment.
Our Global Marine Terminals segment benefited from continued improvement in capacity utilization and higher rates on
contract renewals. Our continued efforts to provide new service offerings and enhance our marine asset portfolio capabilities
resulted in strong demand for our services. Internal growth capital investments also yielded additional capacity that our
commercial teams were able to successfully contract. The development of structure in the crude oil and refined petroleum
products markets additionally assisted in the year-over-year success in this segment. Our interest in Buckeye Texas acquired in
September 2014 was also a key driver for the increase over prior year. In the fourth quarter of 2015, we completed the
commissioning and start-up of our condensate splitters and liquid petroleum gas refrigerated storage, which are in service under
long-term agreements with Trafigura Trading LLC (“Trafigura”). These increases in net income were partially offset by an
increase in depreciation and amortization expense due to the Buckeye Texas assets.
Our Merchant Services segment benefited from the elimination of certain commercial strategies from 2014 and more
effective supply management. In 2015, the contribution from rack sales was lower as a result of competition from local
refineries and our focused efforts to reduce volumes due to our improved inventory management process. This segment
continues to drive increased utilization of our pipeline and terminal assets.
38
Our Domestic Pipelines & Terminals segment benefited from higher terminalling throughput volumes, particularly in
refined petroleum products, and higher storage revenue from new contracts. Our investment in organic growth capital projects
continues to drive customer activity to our terminals as we have enhanced our service offerings across our system. In 2015,
pipeline transportation revenues increased year-over-year as a result of higher gasoline and jet fuel volumes, as well as the
lower FERC litigation accruals recorded as a reduction of revenue. These increases were partially offset by lower product
recoveries from our terminalling throughput activities, a decrease in average pipeline tariff rates, lower butane blending margins
and increased operating expenses.
See the “Results of Operations” section below for further discussion and analysis of our operating segments.
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,
2015
2014
2013
3,453,434
2,849,318
604,116
6,381
(171,330)
98
439,265
(874)
438,391
(857)
437,534
(311)
437,223
$
$
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
$
$
5,054,101
4,576,060
478,041
5,243
(130,920)
295
352,659
(1,060)
351,599
(187,174)
164,425
(4,152)
160,273
Continuing operations................................................................................... $
Discontinued operations ............................................................................... $
$
3.41
(0.01) $
$
2.78
(0.50) $
3.23
(1.74)
_____________________________
(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 is the primary measure used by our senior management, including our Chief Executive Officer, 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. Distributable cash flow is another measure used by our senior management to
provide a clearer picture of cash available for distribution to our unitholders. Adjusted EBITDA and distributable cash flow
eliminate: (i) non-cash expenses, including but not limited to, depreciation and amortization expense resulting from the
significant capital investments we make in our businesses and from intangible assets recognized in business combinations;
(ii) charges for obligations expected to be settled with the issuance of equity instruments; and (iii) items that are not indicative
of our core operating performance results and business outlook.
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.
39
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 generally accepted accounting principles (“GAAP”), to Adjusted EBITDA and distributable cash flow for the
periods indicated (in thousands):
Year Ended December 31,
2015
2014
2013
Adjusted EBITDA from continuing operations:
Domestic Pipelines & Terminals .................................................................. $
Global Marine Terminals..............................................................................
Merchant Services ........................................................................................
323,840
22,026
Adjusted EBITDA from continuing operations....................................... $
868,062
$
522,196
$
532,071
$
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) ......................................................
Less: Amortization of unfavorable storage contracts (4)..............................
Adjusted EBITDA from continuing operations............................................
Less: Interest and debt expense, excluding amortization of deferred
financing costs, debt discounts and other........................................................
Income tax expense, excluding non-cash taxes...................................
Maintenance capital expenditures (5) .................................................
Distributable cash flow from continuing operations .................................... $
$
438,391
(311)
438,080
171,330
874
221,278
29,215
3,127
15,229
(11,071)
868,062
486,458
149,740
12,616
$
648,814
$
351,599
(4,152)
347,447
130,920
1,060
147,591
21,013
11,806
—
(11,023)
648,814
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)
763,568
(154,469)
(1,536)
(99,617)
612,440
$
(156,728)
(675)
(79,388)
526,777
$
(122,471)
(717)
(71,476)
454,150
____________________________
(1) Includes 100% of the depreciation and amortization expense of $49.3 million and $12.3 million for Buckeye Texas for the
years ended December 31, 2015 and 2014, respectively.
(2) Acquisition and transition expense consists of transaction costs, costs for transitional employees, and other employee and
third-party costs related to the integration of the acquired assets that are non-recurring in nature.
(3) Represents reductions in revenue related to settlement of a FERC proceeding. See Note 6 in the Notes to Consolidated
Financial Statements for further discussion.
(4) Represents the amortization of the negative fair values allocated to certain unfavorable storage contracts acquired in
connection with the BORCO acquisition.
(5) Represents expenditures that maintain the operating, safety and/or earnings capacity of our existing assets.
40
The following table presents product volumes and average tariff rates for the Domestic Pipelines & Terminals segment in
barrels per day (“bpd”), percent of capacity utilization for the Global Marine Terminals segment and total volumes sold in
gallons for the Merchant Services segment for the periods indicated:
Year Ended December 31,
2015
2014
2013
Domestic Pipelines & Terminals (average bpd in thousands):
Pipelines:
Gasoline ...................................................................................................
Jet fuel......................................................................................................
Middle distillates (1) ................................................................................
Other products (2) ....................................................................................
Total pipelines throughput...................................................................
735.9
358.9
337.4
28.5
702.8
336.0
354.9
36.6
717.8
334.4
345.7
28.5
1,460.7
1,430.3
1,426.4
Terminals:
Products throughput (3) ......................................................................
1,215.4
1,147.5
Pipeline Average Tariff (cents/bbl)...............................................................
83.7
85.2
985.7
82.2
Global Marine Terminals (percent of capacity):
Average capacity utilization rate (4).............................................................
96%
85%
92%
Merchant Services (in millions of gallons):
Sales volumes ...............................................................................................
1,215.0
2,009.0
1,371.5
_____________________________
(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 previously reported in our Development & Logistics
segment. We have adjusted our prior period throughput volumes to conform to current year presentation.
(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 85%, 74% and 88% for the years ended
December 31, 2015, 2014 and 2013, respectively.
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014
Consolidated
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 supply 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.
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.
41
Operating income was $604.1 million for the year ended December 31, 2015, which is an increase of $108.8 million, or
22.0%, from $495.3 million for the corresponding period in 2014. The increase in operating income 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 supply management in our
Merchant Services segment. The increase in operating income 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.
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.
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, 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 supply management. The elimination of certain commercial strategies included
liquidating our physical positions in markets less liquid than our core markets.
Adjusted EBITDA was 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.
42
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).
Year Ended December 31, 2014 Compared to Year Ended December 31, 2013
Consolidated
Adjusted EBITDA was $763.6 million for the year ended December 31, 2014, which is an increase of $114.8 million, or
17.7%, from $648.8 million for the corresponding period in 2013. The increase in Adjusted EBITDA was primarily related to
positive contribution from the assets acquired from Hess in December 2013 in the Global Marine Terminals and Domestic
Pipelines & Terminals segments and benefit from growth capital spending in the Domestic Pipelines & Terminals segment.
These increases in Adjusted EBITDA were partially offset by the loss in the Merchant Services segment as a result of weaker
business conditions in the various refined petroleum markets in which we serve, and unfavorable results from implementing
strategies in that segment during the second quarter of 2014 intended to increase the utilization of our physical assets, grow our
marketing business and mitigate risk. These losses were attributed to: (i) costs associated with entering into new markets to
grow our marketing business and support the optimization of our underlying physical assets; (ii) losses on the liquidation of
physical positions in markets less liquid than in our core markets; (iii) losses resulting from the timing of activity intended to
mitigate risk on gasoline and distillates for the summer driving season and upcoming heating season; and (iv) a significant
decline in the value of ethanol which is carried in inventory to support our gasoline business.
Revenue was $6,620.2 million for the year ended December 31, 2014, which is an increase of $1,566.1 million, or 31.0%,
from $5,054.1 million for the corresponding period in 2013. The increase in revenue was primarily related to increased product
sales volumes in our Merchant Services segment, as well as the benefit of the terminals acquired from Hess in December 2013
in both our Domestic Pipelines & Terminals and Global Marine Terminals segments. These increases were partially offset by a
litigation contingency accrual, recorded as a reduction in revenue, associated with FERC proceedings in our Domestic
Pipelines & Terminals segment.
Operating income was $495.3 million for the year ended December 31, 2014, which is an increase of $17.3 million, or
3.6%, from $478.0 million in the corresponding period in 2013. The increase in operating income was primarily related to the
benefit of the terminals acquired from Hess in December 2013 in both our Global Marine Terminals and Domestic Pipelines &
Terminals segments. These increases were partially offset by the increase in depreciation and amortization expense primarily
due to the assets acquired from Hess in December 2013, assets acquired in the Buckeye Texas Partners Transaction in
September 2014, the loss in the Merchant Services segment discussed above, as well as the litigation contingency accrual,
recorded as a reduction in revenue, associated with FERC proceedings in our Domestic Pipelines & Terminals segment.
Distributable cash flow was $526.8 million for the year ended December 31, 2014, which is an increase of $72.6 million,
or 16.0%, from $454.2 million for the corresponding period in 2013. The increase in distributable cash flow was primarily
related to an increase of $114.8 million in Adjusted EBITDA as described above, partially offset by a $34.3 million increase in
interest expense, excluding amortization of deferred financing costs, debt discounts and other, primarily resulting from the
long-term debt issuances in 2013, including the debt issued to partially fund the assets acquired from Hess in December 2013
and a $7.9 million increase in maintenance capital expenditures.
Adjusted EBITDA by Segment
Domestic Pipelines & Terminals. Adjusted EBITDA from the Domestic Pipelines & Terminals segment was $532.1
million for the year ended December 31, 2014, which was an increase of $45.6 million, or 9.4%, from $486.5 million for the
corresponding period in 2013. The positive factors impacting Adjusted EBITDA were related to a $68.4 million increase in
revenue resulting from an increase in terminalling throughput and storage contracts, including those associated with the assets
acquired from Hess in December 2013, $33.4 million of incremental revenue from capital investments in internal growth and
diversification initiatives, including butane blending capabilities, crude oil handling services and storage and throughput of
other hydrocarbons, a $14.6 million increase in revenue due to increases in average pipeline tariff rates and longer-haul
shipments, a $10.8 million increase in other revenue, including a favorable settlement related to certain pipeline transportation
services, a $6.0 million increase in earnings from equity investments primarily due to a decrease in maintenance expense and a
$2.4 million increase resulting from higher pipeline volumes.
43
The negative factors impacting Adjusted EBITDA were an $81.6 million increase in operating expenses, primarily related
to incremental costs necessary to operate the terminals acquired from Hess in December 2013 and outside services for asset-
maintenance activities, and $8.4 million in less favorable settlement experience primarily related to high volumetric gains
experienced in 2013 as well as, to a lesser extent, falling commodity prices in 2014.
Pipeline volumes slightly increased despite weaker gasoline shipments resulting from extreme weather conditions in early
2014. Overall terminalling volumes increased by 16.5% due to effective commercialization and integration of the terminals
acquired from Hess in December 2013. Legacy terminalling volumes increased by 4.4% due to higher demand for gasoline,
distillates and jet fuel and new customer contracts and service offerings at select locations, including the benefit of
contributions from growth capital spending.
Global Marine Terminals. Adjusted EBITDA from the Global Marine Terminals segment was $239.6 million for the year
ended December 31, 2014, which was an increase of $89.8 million, or 60.0%, from $149.7 million for the corresponding period
in 2013. The positive factors impacting Adjusted EBITDA were a $103.5 million increase in storage and terminalling revenue
primarily as a result of the assets acquired from Hess in December 2013 and a $32.8 million increase in revenue from ancillary
services. Ancillary services include the berthing of ships at our jetties, heating services and settlement gains/losses. The
increase in revenue was partially offset by a $46.5 million increase in operating expenses primarily related to incremental costs
necessary to operate the assets acquired from Hess in December 2013.
Merchant Services. Adjusted EBITDA from the Merchant Services segment was a loss of $8.1 million for the year ended
December 31, 2014, which was a decrease of $20.7 million from earnings of $12.6 million for the corresponding period in
2013. The loss experienced during the period is primarily attributed to losses in the second quarter described above, partially
offset by strong domestic rack margins.
Adjusted EBITDA was positively impacted by a $1,368.0 million increase in revenue, which included a $1,854.9 million
increase due to 46.5% of higher volumes sold, partially offset by a $486.9 million decrease in refined petroleum product sales
due to a price decrease of $0.24 per gallon (average sales prices per gallon were $2.67 and $2.91 for the 2014 and 2013 periods,
respectively).
Adjusted EBITDA was negatively impacted by a $1,383.0 million increase in cost of product sales, which included a
$1,843.3 million increase due to 46.5% of higher volumes sold, offset by a $460.3 million decrease in refined petroleum
product cost due to a price decrease of $0.23 per gallon (average cost prices per gallon were $2.66 and $2.89 for the 2014 and
2013 periods, respectively) and a $5.7 million increase in operating expenses.
General Outlook for 2016
We expect our year-over-year performance to improve in 2016 as a result of progress made in 2015 on the construction of
our Buckeye Texas facility, additional capital investments made across our portfolio of assets and continued high utilization and
increased rates for our storage capacity.
At Buckeye Texas, we completed the commissioning of our refrigerated and compressed LPG storage complex late in the
third quarter of 2015 and brought our two condensate splitters into service late in the fourth quarter of 2015. These assets,
combined with additional storage and dock capacity expected to be completed in the first quarter of 2016, are expected to
generate incremental cash flows compared to 2015.
In addition, we invested in bringing new storage capacity on-line across our system, including the conversion of over
2 million barrels of fuel oil tanks into flexible service at our BORCO facility, the return to commercial service of 1.5 million
barrels of capacity at our St. Lucia facility, and expansion of storage capacity at our Chicago Complex through the completion
of a bi-directional pipeline connecting this important Midwestern hub to an additional terminal that had been previously
underutilized. We also expanded our service capabilities in the New York Harbor by increasing gasoline blending capacity. We
expect these investments to generate incremental cash flows in 2016 as we benefit from the full year impact.
We have begun construction on our Michigan-Ohio pipeline and terminal expansion project, which will allow us to offer
expanded transportation service of refined petroleum products from points in Michigan and western Ohio to destinations in
eastern Ohio and western Pennsylvania. We expect this project to be in operation in the fourth quarter of 2016, although the
full run-rate will not be realized until 2017.
44
Volumes across our pipeline systems are expected to be impacted by the strength in aviation fuel and gasoline, partially
offset by weakness in distillates. Until the completion of our Michigan-Ohio expansion project, we expect to see downward
pressure from the impact of changing product flows, primarily on our Central Pennsylvania system. Throughput volumes
across our domestic terminals are expected to increase moderately from the completion of growth capital initiatives in the
Midwest and increased customer demand in the Southeast.
Our Merchant Services segment continues to benefit from inventory risk management activities and asset optimization. We
expect that our inventory risk management strategy will drive more stable results and allow us to seize opportunities to lock in
contango value, when presented, in 2016.
Our results in 2015 reflect the benefit of our diversified asset base with limited exposure to commodity prices. The impact
of lower commodity prices in 2016 could negatively impact the value we realize on our settlement revenues and butane
blending margins; however, our storage assets could benefit from the strong demand for storage as liquid petroleum product
inventories are at elevated levels. Overall, we believe our diversified portfolio of assets is well positioned for the current
market environment.
We believe that we have sufficient liquidity available on our $1.5 billion revolving Credit Facility, as well as the ability to
utilize our at-the-market equity issuance program to meet our expected capital needs for 2016. Under current market
conditions, we believe that we could raise additional capital in both the debt and equity markets on acceptable terms to fund
appropriate asset or business acquisitions.
We will continue to evaluate opportunities throughout 2016 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 2016” 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 2016” may not occur.
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, 2015, we had $47.2 million of working capital and $1,027.5 million of availability under our Credit
Facility. We are limited to $933.1 million of additional borrowing capacity by the financial covenants under our Credit Facility,
except for borrowings that are used to refinance other debt.
45
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 under
which we may issue equity securities with a value, as of December 31, 2015, not to exceed $836.5 million. 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.
Debt
At December 31, 2015, 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......................................................................................................................
6.750% Notes due August 15, 2033 .......................................................................................................................
5.850% Notes due November 15, 2043..................................................................................................................
5.600% Notes due October 15, 2044......................................................................................................................
Credit Facility due September 30, 2020.................................................................................................................
Total debt ............................................................................................................................................................. $
125,000
300,000
400,000
275,000
650,000
500,000
300,000
150,000
400,000
300,000
472,488
3,872,488
In December 2015, Buckeye and its indirect wholly-owned subsidiaries, BMSC, as borrowers, exercised their option to
extend our existing Credit Facility by one year to September 30, 2020, resulting in a remaining option to extend the term for
one additional year. At December 31, 2015, Buckeye and BMSC collectively had $472.5 million outstanding under the Credit
Facility, of which $111.5 million, attributable to BMSC, was classified as current liabilities in our consolidated balance sheet, as
related funds were used to finance current working capital needs. See Note 14 in the Notes to Consolidated Financial
Statements for additional information.
Equity
During the year ended December 31, 2015, we sold 2.2 million LP Units in aggregate under the Equity Distribution
Agreements, received $161.5 million in net proceeds after deducting commissions and other related expenses, and paid
$1.6 million of compensation in aggregate to the agents under the Equity Distribution Agreements.
46
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,
2015
2014
2013
Operating activities....................................................................................... $
Investing activities ........................................................................................
Financing activities.......................................................................................
$
710,192
(614,894)
(98,625)
599,642
(1,191,497)
595,113
$
385,494
(1,204,678)
817,358
Operating Activities
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, $53.7 million in other non-cash items
and a $56.8 million decrease in working capital, partially offset by $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, 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.
2013. Net cash provided by operating activities was $385.5 million for the year ended December 31, 2013, primarily
related to $164.4 million of net income and $155.2 million of depreciation and amortization, partially offset by a $62.0 million
settlement to terminate the interest rate swap agreements related to the 4.150% Notes, a $69.7 million increase in accounts
receivables and an increase in interest and debt expense.
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
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, $21.4 million in escrow deposits, 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, partially offset by $103.4 million cash proceeds from the sale of our Natural Gas Storage disposal group.
2013. Net cash used in investing activities of $1,204.7 million for the year ended December 31, 2013 primarily related to
$361.4 million of capital expenditures and $856.4 million related to the Hess Terminals Acquisition.
See below for a discussion of capital spending. For further discussion on our acquisitions, see Note 3 in the Notes to
Consolidated Financial Statements.
47
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) (3) ..............................................................
Total capital expenditures, net...................................................................... $
Year Ended December 31,
2015
2014
2013
99,617
494,903
594,520
$
$
80,141
392,008
472,149
$
$
71,595
289,850
361,445
_____________________________
(1) Includes maintenance capital expenditures related to the Natural Gas Storage disposal group of $0.8 million and
$0.1 million for the years ended December 31, 2014 and 2013, respectively.
(2) Includes expansion and cost reduction capital expenditures related to the Natural Gas Storage disposal group of
$0.1 million for the year ended December 31, 2013.
(3) Amounts exclude accruals for capital expenditures. Expansion and cost reduction amounts including accruals for capital
expenditures were $516.5 million and $340.5 million for the year ended December 31, 2015 and 2014, respectively.
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.
Capital expenditures increased for the year ended December 31, 2014, as compared to the corresponding period in 2013
primarily due to increases in expansion and cost reduction capital expenditures. Our expansion and cost reduction capital
expenditures were $392.0 million for the year ended December 31, 2014, which is an increase of $102.2 million, or 35.2%,
from $289.9 million for the corresponding period in 2013. 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, 2014 included cost reduction and revenue generating projects
related to storage tank enhancements across our portfolio of terminalling assets, butane blending capabilities, completion of rail
unloading facilities, crude oil storage/transportation and a pipeline integrity enhancement program that improved the
operational efficiencies in our pipeline systems. Our maintenance capital expenditures were $80.1 million for the year ended
December 31, 2014, which is an increase of $8.5 million, or 11.9%, from $71.6 million for the corresponding period in 2013.
Year-to-year fluctuations in our maintenance capital expenditures are primarily driven by the timing and cost of pipeline
integrity and similar projects. Our most significant maintenance capital expenditures for the year ended December 31, 2014
included truck rack infrastructure 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.
48
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 Partners related capital expenditures.
2016
Low
High
75,000
185,000
260,000
25,000
140,000
165,000
100,000
325,000
425,000
$
$
$
$
$
$
85,000
215,000
300,000
35,000
160,000
195,000
120,000
375,000
495,000
Estimated maintenance capital expenditures include replacement of tank floors and tank roofs, pipeline integrity, marine
dock structure upgrades and upgrades to station and terminalling equipment, field instrumentation and cathodic protection
systems. Estimated major expansion and cost reduction expenditures include the capacity expansion of our pipeline system and
terminalling capacity in the Midwest, LPG storage/loading facility in Western Pennsylvania, various tank construction and
conversion projects in our Global Marine Terminals and Domestic Pipelines & Terminals segments, as well as an expansion
between facilities in the New York Harbor.
Financing Activities
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.
2013. Net cash flows provided by financing activities of $817.4 million for the year ended December 31, 2013 primarily
related to $1.3 billion of proceeds from the issuance of the 4.150%, 2.650% and 5.850% Notes due July 1, 2023, November 15,
2018 and November 15, 2043, respectively, $903.0 million of net proceeds from the issuance of an aggregate 16.0 million LP
Units, partially offset by $616.2 million of net repayments under the Credit Facility, $428.8 million of cash distributions paid to
our unitholders ($4.225 per LP Unit) and $300.0 million related to the repayment of the 4.625% Notes.
For further discussion on our equity offerings, see Note 22 in the Notes to Consolidated Financial Statements.
49
Contractual Obligations
The following table summarizes our contractual obligations as of December 31, 2015 (in thousands):
Long-term debt (1)................................... $
Interest payments (2)................................
Operating leases:
Office space and other ...........................
Equipment (3)........................................
Land leases (4).......................................
Purchase obligations (5)...........................
Payments Due by Period
Total
Less than 1
year
1-3 years
3-5 years
More than 5
years
3,761,000
$
— $
825,000
$
636,000
$
2,300,000
1,934,988
177,899
327,344
262,571
1,167,174
20,340
4,996
101,855
161,600
3,885
4,010
2,398
161,600
7,116
986
4,796
—
5,935
—
4,796
—
3,404
—
89,865
—
Total contractual obligations ................. $
5,984,779
$
349,792
$
1,165,242
$
909,302
$
3,560,443
_____________________________
(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, 2016, our rights-of-way payments are expected to be $7.2 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, 2015 and 2014, we had no off-balance sheet debt or arrangements.
50
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 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.
In February 2015, the FASB issued guidance changing the criteria for reporting entities that are required to evaluate
whether they should consolidate certain legal entities. All legal entities are subject to reevaluation under the revised
consolidation model. Specifically, the amendments modify the evaluation of whether limited partnerships and similar legal
entities are variable interest entities or voting interest entities, while also eliminating the presumption that a general partner
should consolidate a limited partnership. We adopted this guidance on January 1, 2015. Our adoption did not have a material
impact on our consolidated financial statements as there were no changes to the entities consolidated as a result of the adoption
of this guidance.
Upon adoption of this guidance, we concluded that Buckeye Texas and Sabina Pipeline are VIEs of which we are the
primary beneficiary. In making this conclusion, we evaluated the legal form of the VIEs and the activities that significantly
impact the economics of the VIEs, including our role to perform all services reasonably required to operate and maintain the
assets of the VIEs.
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 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 carrying value. In the fourth quarter of 2015, we changed the date of our annual
goodwill impairment test for all reporting units from January 1st to October 31st. The change is preferable as it better aligns our
goodwill impairment testing procedures with our annual budget process and alleviates resource constraints in connection with
the year-end closing and financial reporting process. Due to significant judgments and estimates that are utilized in a goodwill
impairment analysis, we determined it was impracticable to objectively determine operating and valuation estimates as of each
October 31st for periods prior to October 31, 2015. As a result, we prospectively applied the change in the annual impairment
test date to October 31, 2015. The change in accounting principle does not delay, accelerate, or avoid an impairment charge.
51
For our annual goodwill impairment test as of October 31, 2015, 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, 2015, 2014 or 2013.
Valuation of Long-Lived Assets and Equity Method Investments
We assess the recoverability of our long-lived assets whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable. If events or circumstances are identified, the carrying amount of the asset
is compared to the estimated discounted future cash flows to determine if an impairment exists. Estimates of undiscounted
future cash flows include: (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating
expenses; (ii) long-term growth rates; and (iii) estimates of useful lives of the assets. The identification of impairment
indicators and the estimates of future undiscounted cash flows are highly subjective and are based on numerous assumptions
about future operations and market conditions.
In December 2013, the Board 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. The estimated fair value less costs to sell was determined to be less than its carrying value, which resulted in
the recognition of a non-cash asset impairment charge of $169.0 million, which included the write-down of long-lived assets.
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 and the completed sale
in December 2014, we recorded additional 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 years ended December 31, 2014 and 2013, respectively. 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, 2015, 2014 or 2013.
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.
52
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 Domestic Pipelines & Terminals segment uses exchange-traded refined petroleum contracts to hedge certain
expected future transactions which we 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. Our Merchant
Services segment entered into these contracts on behalf of our Domestic Pipelines & Terminals segment. In both cases, 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. 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 New York Mercantile Exchange. 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.
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.
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.
53
The following is a summary of changes in fair value of our derivative instruments for the periods indicated (in thousands):
Fair value of contracts outstanding at January 1, 2015 .......................................................................................... $
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, 2015 .................................................................................... $
67,686
(108,227)
10,188
108,605
(123)
78,129
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. During 2015,
our Merchant Services segment entered into exchange-traded refined petroleum product futures contracts on behalf of our
Domestic Pipelines & Terminals 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, 2015, 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
Fair Value
Asset
Asset
Asset
$
$
$
252,618
259,936
245,300
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 July 2009 and May 2010, the Board authorized us to enter into certain
transactions, such as 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.
See Note 17 in the Notes to Consolidated Financial Statements for additional discussion related to derivative instruments
and hedging activities.
At December 31, 2015, we had total fixed-rate debt obligations under various public notes at an aggregate carrying value
of $3,372 million. Based on a hypothetical 1% movement in the underlying interest rates at December 31, 2015, 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
3,057.9
$
2,893.8
$
3,242.1
$
54
At December 31, 2015, our variable-rate obligations were $472.5 million under the Credit Facility. Based on the balance
outstanding at December 31, 2015, we estimate that a 1% increase or decrease in interest rates would increase or decrease
annual interest expense by $4.7 million.
Foreign Currency Risk
Puerto Rico is a commonwealth country under the U.S., and thus uses the U.S. dollar as its official currency. BORCO’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, 2015, 2014 and 2013.
55
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, 2015, 2014 and 2013 .....................
.......................................................................................................................................................................................
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2015, 2014 and 2013
.......................................................................................................................................................................................
Consolidated Balance Sheets as of December 31, 2015 and 2014 ...........................................................................
.......................................................................................................................................................................................
Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013.....................
Consolidated Statements of Partners’ Capital for the Years Ended December 31, 2015, 2014 and 2013...........
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) ..................................................................................................................
Page
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61
62
63
65
66
66
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82
83
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87
87
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89
90
91
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94
94
94
98
99
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107
107
111
112
112
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116
56
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, 2015. 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, 2015, 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 25, 2016
/s/ KEITH E. ST.CLAIR
Keith E. St.Clair
Executive Vice President and
Chief Financial Officer
57
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, 2015, 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, 2015, 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, 2015 of Buckeye and our report dated February 25,
2016 expressed an unqualified opinion on those consolidated financial statements.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 25, 2016
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 accompanying consolidated balance sheets of Buckeye Partners, L.P. and subsidiaries (“Buckeye”) as of
December 31, 2015 and 2014, 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, 2015. 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, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the
period ended December 31, 2015, 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, 2015, 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 25, 2016 expressed an unqualified opinion on Buckeye’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 25, 2016
59
BUCKEYE PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
Year Ended December 31,
2015
2014
2013
Revenue:
Product sales ................................................................................................... $
Transportation, storage and other services......................................................
Total revenue............................................................................................
2,028,323
$
5,348,532
$
3,966,247
1,425,111
3,453,434
1,271,715
6,620,247
1,087,854
5,054,101
Costs and expenses:
Cost of product sales .......................................................................................
Operating expenses .........................................................................................
Depreciation and amortization ........................................................................
General and administrative .............................................................................
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..................................................................................................... $
1,965,844
5,311,552
3,944,448
573,368
221,278
88,828
2,849,318
604,116
537,705
196,443
79,200
6,124,900
495,347
413,577
147,591
70,444
4,576,060
478,041
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
$
$
$
$
$
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
$
$
$
$
$
5,243
(130,920)
295
(125,382)
352,659
(1,060)
351,599
(187,174)
164,425
(4,152)
160,273
3.25
(1.75)
1.50
3.23
(1.74)
1.49
Weighted average units outstanding:
Basic.........................................................................................................
Diluted......................................................................................................
128,084
128,617
119,323
119,899
107,202
107,677
See Notes to Consolidated Financial Statements
60
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,
2015
2014
2013
437,534
$
274,857
$
164,425
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
$
37,718
4,881
1,574
11,054
55,227
219,652
(4,152)
215,500
See Notes to Consolidated Financial Statements
61
BUCKEYE PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands, except unit amounts)
December 31,
2015
2014
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 .........................................................................................................
Property, plant and equipment, net...........................................................................................
Equity investments ...................................................................................................................
Goodwill...................................................................................................................................
Intangible assets, net ................................................................................................................
Other non-current assets...........................................................................................................
Total assets...................................................................................................................... $
4,881
213,830
13,491
192,992
78,285
48,071
551,550
6,202,081
84,128
998,748
491,372
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....................................................................................................
111,488
82,691
510
309,620
504,309
$
$
$
8,208
265,830
20,542
243,475
69,189
25,055
632,299
5,735,787
82,849
993,375
553,924
67,486
8,065,720
166,000
159,129
1,802
295,024
621,955
Long-term debt .........................................................................................................................
Other non-current liabilities .....................................................................................................
Total liabilities ................................................................................................................
3,732,824
115,407
4,352,540
3,368,618
134,551
4,125,124
Commitments and contingent liabilities (Note 6).......................................................................
—
—
Partners’ capital:
Buckeye Partners, L.P. capital:
Limited Partners (129,523,703 and 127,043,317 units outstanding as of
December 31, 2015 and 2014, respectively) .......................................................................
Accumulated other comprehensive loss ..............................................................................
Total Buckeye Partners, L.P. capital...............................................................................
Noncontrolling interests ......................................................................................................
Total partners’ capital......................................................................................................
Total liabilities and partners’ capital............................................................................... $
3,833,230
(97,841)
3,735,389
281,352
4,016,741
8,369,281
$
3,817,916
(115,288)
3,702,628
237,968
3,940,596
8,065,720
See Notes to Consolidated Financial Statements
62
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......................................................................
Litigation contingency accrual .....................................................................
Litigation settlement .....................................................................................
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 ............................................
Net cash used in investing activities ........................................................
Cash flows from financing activities:
Net proceeds from issuance of LP Units ......................................................
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 .......................................................................................
Borrowings under BPL Credit Facility.........................................................
63
Year Ended December 31,
2015
2014
2013
437,534
$
274,857
$
164,425
—
221,278
15,229
(52,839)
—
(9,177)
—
(11,071)
(6,381)
5,108
53,669
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)
161,474
215
(7,700)
—
—
(1,115)
1,627,450
(51,469)
196,443
40,000
—
23,365
(77,901)
3,637
(11,071)
(11,265)
470
35,481
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
—
(62,009)
155,183
—
—
169,002
1,776
3,770
(11,023)
(5,243)
1,312
42,196
(69,661)
(10,057)
(45,344)
32,106
11,311
33,516
626
(26,392)
385,494
(361,445)
—
(856,377)
12,650
494
—
103,407
(1,191,497)
—
(1,204,678)
899,710
849
(6,234)
599,103
(275,000)
(7,414)
1,856,031
902,976
1,277
(5,034)
1,292,666
(300,000)
(11,921)
1,651,500
Repayments under BPL Credit Facility........................................................
Net (repayments) borrowings under BMSC Credit Facility.........................
Acquisition of additional interest in Buckeye Memphis ..............................
Contributions from noncontrolling interests.................................................
Distributions paid to noncontrolling interests...............................................
Distributions paid to unitholders ..................................................................
Net cash (used in) provided by financing activities.................................
Net (decrease) increase in cash and cash equivalents .....................................
Cash and cash equivalents — Beginning of year............................................
Cash and cash equivalents — End of year ...................................................... $
(1,266,450)
(54,512)
(10,044)
57,000
(13,972)
(590,971)
(98,625)
(3,327)
8,208
(1,885,031)
(60,000)
(9,510)
16,400
(6,593)
(527,198)
595,113
3,258
4,950
(2,287,500)
19,800
(9,727)
—
(7,850)
(428,829)
817,358
(1,826)
6,776
4,881
$
8,208
$
4,950
See Notes to Consolidated Financial Statements
64
BUCKEYE PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(In thousands)
Partners’ capital - January 1, 2013 .................................. $
2,117,788
$
413,304
$
(158,779) $
16,527
$
2,388,840
Limited
Partners
Class B
Units
Accumulated
Other
Comprehensive
Loss
Noncontrolling
Interests
Total
Net income ...........................................................................
Acquisition of additional interest in Buckeye Memphis......
Distributions paid to unitholders..........................................
Conversion of Class B Units to LP Units ............................
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 ....................................................................................
143,554
(8,232)
(432,508)
430,023
902,976
21,781
1,277
(5,034)
—
—
(2,250)
(158)
Partners' capital - December 31, 2013 .............................
3,169,217
Net income ...........................................................................
Acquisition of additional interest in Buckeye Memphis......
Noncontrolling interest in acquisition (Note 3) ...................
272,954
(7,933)
—
Distributions paid to unitholders..........................................
(530,376)
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 ....................................................................................
—
899,710
21,499
849
(6,234)
—
—
(1,619)
(151)
Partners' capital - December 31, 2014 .............................
3,817,916
Net income ...........................................................................
Acquisition of additional interest in Buckeye Memphis......
Adjusted value of noncontrolling interest in acquisition
(Note 3) ................................................................................
437,223
(8,276)
—
Distributions paid to unitholders..........................................
(594,132)
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 ....................................................................................
—
161,474
29,332
215
(7,700)
—
—
(3,085)
263
16,719
—
—
(430,023)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
55,227
—
—
(103,552)
—
—
—
—
—
—
—
—
—
—
(11,736)
—
—
4,152
(1,495)
3,679
—
—
—
—
—
(7,850)
—
—
158
15,171
1,903
(1,577)
208,998
3,178
16,400
—
—
—
—
(6,593)
—
—
488
164,425
(9,727)
(428,829)
—
902,976
21,781
1,277
(5,034)
(7,850)
55,227
(2,250)
—
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
(115,288)
237,968
3,940,596
—
—
—
—
—
—
—
—
—
—
17,447
—
—
311
(1,768)
(1,220)
3,161
57,000
—
—
—
—
(13,972)
—
—
(128)
437,534
(10,044)
(1,220)
(590,971)
57,000
161,474
29,332
215
(7,700)
(13,972)
17,447
(3,085)
135
Partners' capital - December 31, 2015 ............................. $
3,833,230
$
— $
(97,841) $
281,352
$
4,016,741
See Notes to Consolidated Financial Statements
65
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 (“NYSE”) 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 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 110 million barrels across
our portfolio of pipelines, inland terminals and marine terminals located primarily in the East Coast 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, 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 recent expansion into the Gulf Coast has added another regional hub with world-class marine terminalling, storage and
processing capabilities. We are also a wholesale distributor of refined petroleum products in areas served by our pipelines and
terminals.
In December 2015, we realigned our reportable segments into three reportable segments as a result of changes in our
organizational structure and renamed one of our reportable segments. Our three reportable segments are: Domestic Pipelines &
Terminals (formerly known as Pipelines & Terminals), Global Marine Terminals and Merchant Services. We merged our
previously reported Development & Logistics segment into the Domestic Pipelines & Terminals segment. See Note 25 in the
Notes to Consolidated Financial Statements for a more detailed discussion of our business segments. We have adjusted our
prior period segment information to conform to current year presentation.
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 U.S. generally accepted
accounting principles (“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.
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 discussed
below in “Recent Accounting Developments”, we reclassified $20.4 million of debt issuance costs originally included in “Other
non-current assets” as of December 31, 2014 to “Long-term debt” as a direct deduction from the carrying amount of debt
liability, consistent with debt discounts. Such reclassifications had no impact on our results of operations.
66
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Asset Retirement Obligations
We regularly assess our legal obligations with respect to estimated retirements of certain of our long-lived assets to
determine if an asset retirement obligation (“ARO”) exists. The fair value of a liability related to the retirement of long-lived
assets is recorded at the time a regulatory or contractual obligation is incurred, including obligations to perform an asset
retirement activity in which the timing or method of settlement are conditional on a future event that may or may not be within
the control of the entity. If an ARO is identified and a liability is recorded, a corresponding asset is recorded concurrently and is
depreciated over the remaining useful life of the asset. After the initial measurement, the liability is periodically adjusted for
costs incurred or settled, accretion expense, and any revisions made to the assumptions related to the retirement costs.
Generally, the fair value of the liability is determined based on estimates and assumptions related to: (i) future retirement costs;
(ii) future inflation rates; and (iii) credit-adjusted risk-free interest rates.
Our assets generally consist of terminals that we own and underground liquid petroleum products pipelines installed along
rights-of-way acquired from land owners and related above-ground facilities. The significant majority of our rights-of-way
agreements do not require the dismantling and removal of the pipelines and reclamation of the rights-of-way upon permanent
removal of the pipelines from service. In addition, we assume substantially all of our common carrier properties operate
indefinitely, as these assets generally serve in high-population and high-demand markets. Accordingly, other than with respect
to facilities that are expected to be taken out of service, we have recorded no liabilities, or corresponding assets because the
future dismantlement and removal dates 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, 2014.................................................................................................................. $
Decrease in ARO liability (1)...............................................................................................................................
ARO settlements ..................................................................................................................................................
ARO liability balance, December 31, 2014 (2) ......................................................................................................
Increase in ARO liability (3) ................................................................................................................................
ARO settlements ..................................................................................................................................................
ARO liability balance, December 31, 2015 (2) ...................................................................................................... $
10,917
(3,798)
(3,456)
3,663
4,200
(1,040)
6,823
____________________________
(1) In 2014, we recorded a $3.8 million reduction to our ARO related to the abandonment of a portion of our NORCO pipeline
system. See Note 5 for further information.
(2) Amount includes $1.4 million and $1.1 million within “Accrued and other current liabilities” and $5.4 million and
$2.6 million within “Other non-current liabilities” in the accompanying consolidated balance sheets as of December 31,
2015 and 2014, respectively.
(3) 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.
67
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
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, 2015, 2014 and 2013 was $21.3 million, $9.9 million and
$7.0 million, respectively. The weighted average rates used to capitalize interest on borrowed funds was 4.8%, 4.9% and 4.7%
for the years ended December 31, 2015, 2014 and 2013, 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 $199.5 million and $255.0 million as of December 31, 2015 and 2014, 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.
68
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 .................................................................................. $
5,784
$
2,019
$
2,983
(387)
8,380
$
3,985
(220)
5,784
$
3,425
6
(1,412)
2,019
December 31,
2015
2014
2013
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.
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 credit facility with SunTrust Bank, as administrative agent, and other
lenders dated September 30, 2014, are reported in “Other non-current assets”. Debt issuance costs related to our outstanding
notes 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.
69
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We recognize these transactions on our consolidated balance sheets as assets and liabilities based on the instrument’s fair
value. Changes in fair value of derivative instrument contracts are recognized in 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. In both cases, 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 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.
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 and Class B Units (as defined in Note 22), 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.
70
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
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, 2015, 2014 or 2013.
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.
71
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial
statements based on the observability of inputs used to estimate such fair values. The characteristics of fair value amounts
classified within each level of the hierarchy are described as follows:
• Level 1 inputs — unadjusted quoted prices which are available in active markets for identical, unrestricted assets or
liabilities as of the reporting date;
• Level 2 inputs — quoted market prices in markets that are not considered to be active or financial instruments for
which all significant inputs are observable, either directly or indirectly; and
• Level 3 inputs — prices or valuations that require inputs that are both significant to the fair value measurement and
unobservable. These inputs are typically used in connection with internally developed valuation methodologies where
management makes its best estimate of an instrument’s fair value.
We categorize our financial assets and liabilities using this hierarchy at each balance sheet reporting date.
Foreign Currency
Puerto Rico is a commonwealth country under the U.S., and thus uses the U.S. dollar as its official currency.
The functional currency of our operations in BORCO 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, 2015, 2014 and 2013.
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 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. In the fourth quarter of 2015, we changed the date of our annual
goodwill impairment test for all of our reporting units from January 1st to October 31st. The change is preferable because it
better aligns our goodwill impairment testing procedures with our annual budget process and alleviates resource constraints in
connection with the year-end and financial reporting process. Due to significant judgments and estimates that are utilized in a
goodwill impairment analysis, we determined it was impracticable to objectively determine operating and valuation estimates
as of each October 31st for periods prior to October 31, 2015. As a result, we prospectively applied the change in the annual
impairment test date as of October 31, 2015. The change in accounting principle does not delay, accelerate, or avoid an
impairment charge.
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 Partners LLC
(“Buckeye Texas”).
72
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
In addition, outside the continental U.S., our operations at BORCO and St. Lucia are exempt from income taxes. Our
operations at BORCO are tax exempt by the Bahamian government pursuant to concessions granted under the Hawksbill Creek
Agreement between the Government of The Bahamas and the Grand Bahama Port Authority. These concessions have been
extended through May 2016, and whether, and on what terms, to further extend those concessions is currently under review by
the Bahamian Government. 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 $1.6 million and ($0.7) million, respectively, for the year ended
December 31, 2015, $0.7 million and $(0.2) million, respectively, for the year ended December 31, 2014 and $0.7 million and
$0.4 million, respectively, for the year ended December 31, 2013. We have no unrecognized tax benefits related to uncertain
tax positions.
73
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
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 previously allocated the net income attributable to Buckeye to the LP Unitholders and Class B Unitholders based on the
weighted average LP Units and Class B Units (as defined in Note 22) outstanding during the period. Following the conversion
of all Class B Units into LP Units effective September 1, 2013, the net income attributable to Buckeye is allocated entirely to
the LP Unitholders.
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.
74
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 heath 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, storage, terminalling 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.
Recent Accounting Developments
Financial Instruments. In January 2016, the Financial Accounting Standards Board (“FASB”) issued guidance that
enhances the reporting model for financial instruments, which includes amendments to address aspects of recognition,
measurement, presentation, and disclosure. The guidance is effective for annual reporting periods beginning after December 15
2017, and interim periods within those annual periods, with early adoption permitted for certain amendments. We are currently
evaluating the impact the adoption of this guidance will have on our consolidated financial statements.
Income Taxes. In November 2015, the FASB issued guidance to simplify the presentation of deferred taxes in the
statement of financial position. The amendment requires that deferred tax assets and liabilities be classified as non-current in
the balance sheet. The guidance can be applied retrospectively or prospectively and is effective for annual reporting periods
beginning after December 15, 2016, and interim periods within those annual periods, with early adoption permitted. We expect
to adopt this guidance on January 1, 2016. We do not believe our adoption will have a material impact on our consolidated
financial statements or on our disclosures.
Business Combinations. In September 2015, the FASB issued guidance to simplify the accounting for adjustments made to
provisional amounts recognized in a business combination. The amendments require that an acquirer recognize adjustments to
provisional amounts identified during the measurement period in the reporting period in which the adjustment amounts are
determined. This eliminates the requirement to retrospectively account for such adjustments. The guidance is effective
prospectively for annual reporting periods beginning after December 15, 2015, and interim periods within those annual periods,
with early adoption permitted. We adopted this guidance in the fourth quarter of 2015, which did not have a material impact on
our consolidated financial statements or on our disclosures.
75
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Inventory. In July 2015, the FASB issued guidance to simplify the measurement of inventory. The amendments require
inventory to be measured at the lower of cost or net realizable value. 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.
The guidance is effective prospectively for annual reporting periods beginning after December 15, 2016, and interim periods
within those annual periods, with early adoption permitted. We adopted this guidance in the fourth quarter of 2015, which did
not have a material impact on our consolidated financial statements or on our disclosures.
Revenue from Contracts with Customers. In July 2015, the FASB deferred the effective date of guidance that was
originally issued in May 2014 to clarify principles used to recognize revenue for all entities. The guidance is now 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. The standard’s core principle is that an entity will recognize revenue 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. In doing so, entities will need to use more judgment and make more estimates than under
current guidance. These may include identifying performance obligations in the contract, estimating the amount of variable
consideration included in the transaction price and/or allocating the transaction price to each separate performance obligation.
We expect to adopt this guidance on January 1, 2018, and we are currently evaluating the impact the adoption of this guidance
will have on our consolidated financial statements.
Debt Issuance Costs. In April 2015, the FASB issued guidance to simplify the presentation of debt issuance costs.
The amendments require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a
direct deduction from the carrying amount of that debt liability, consistent with debt discounts. In August 2015, the FASB
issued clarifying guidance allowing entities to present debt issuance costs related to line-of-credit arrangements as an asset,
which must be subsequently amortized ratably over the term of the arrangement. The guidance is effective for annual reporting
periods beginning after December 15, 2015, and interim periods within those annual periods, with early adoption permitted.
We adopted this guidance in the fourth quarter of 2015, which resulted in the retrospective adjustment to our prior period
consolidated balance sheet. See “Basis of Presentation and Principles of Consolidation” and “Debt Issuance Costs” above for
additional information.
Consolidations. In February 2015, the FASB issued guidance changing the criteria for reporting entities that are required
to evaluate whether they should consolidate certain legal entities. All legal entities are subject to reevaluation under the revised
consolidation model. Specifically, the amendments modify the evaluation of whether limited partnerships and similar legal
entities are variable interest entities or voting interest entities, while also eliminating the presumption that a general partner
should consolidate a limited partnership. These provisions are effective prospectively for annual reporting periods beginning
after December 15, 2015, and interim periods within those annual periods, with early adoption permitted. We adopted this
guidance on January 1, 2015. Our adoption did not have a material impact on our consolidated financial statements as there
were no changes to the entities consolidated as a result of the adoption of this guidance.
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.
76
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
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. Revenue from transactions commonly called buy/sell contracts, in which the purchase
and sale of inventory with the same counterparty physically settle on the same day and location, are combined and reported net.
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 variable interest entities 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, 2015.
77
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Upon adoption of the new accounting guidance in 2015 (as discussed above in “Recent Accounting Developments”), we
concluded that 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.
3. ACQUISITIONS AND DISPOSITION
Business Combinations
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 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, 2015 are subject to change pending final valuation analysis. 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 ..................................................................................................................................... $
5,287
2,372
(2,372)
5,287
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 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 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. The estimates of fair value reflected as of December 31, 2015 are subject to change
pending final valuation analysis. 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 ...................................................................................................................................... $
3,951
8,254
(4,200)
(293)
7,712
78
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
2014 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, approximately 6.0 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 recently 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
79
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 recently 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.
2013 Transaction
In December 2013, we acquired certain wholesale distribution contracts and 20 liquid petroleum products terminals with
total storage capacity of approximately 39 million barrels from Hess Corporation (“Hess”) for $856.4 million, net of cash
acquired (the “Hess Terminals Acquisition”). The 19 domestic terminals are located primarily in major metropolitan locations
along the U.S. East Coast and have approximately 29 million barrels of aggregate liquid petroleum products storage capacity,
including approximately 15 million barrels of capacity strategically located in New York Harbor. These terminals have access
to products supplied by marine vessels and barges as well as pipelines. Excluding the Port Reading and Raritan Bay terminals,
which are reported as part of our Global Marine Terminals segment, the operations of these domestic terminals acquired from
Hess are reported in our Domestic Pipelines & Terminals segment. The terminal on St. Lucia in the Caribbean has
approximately 10 million barrels of crude oil and refined petroleum products storage capacity with deep-water access, and its
operations are reported in our Global Marine Terminals segment. The operations relating to the wholesale distribution contracts
are reported in our Merchant Services segment. We allocated $6.0 million of goodwill resulting from the Hess Terminals
Acquisition to the Domestic Pipelines & Terminals reporting unit due to expected growth opportunities from one of the
domestic terminals with high throughput volumes. The remaining $3.4 million of goodwill was allocated to the Merchant
Services reporting unit as it relates to the wholesale distribution contracts, which will enhance our wholesale distribution and
rack marketing business. Concurrent with this acquisition, we entered into multi-year storage and throughput commitments
with Hess.
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 our operations from the Hess Terminals Acquisition 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 ....................................................................................................................................................
Environmental liabilities.........................................................................................................................................
Allocated purchase price ...................................................................................................................................... $
16,533
802,101
30,520
9,375
(882)
(1,270)
856,377
80
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Unaudited Pro forma Financial Results for Hess Terminals Acquisition
Our consolidated statements of operations do not include earnings from the terminals acquired from Hess (the “Hess
Terminals”) prior to December 11, 2013, the effective date of the Hess Terminals Acquisition. The preparation of unaudited pro
forma financial information for the Hess Terminals Acquisition is impracticable due to the fact that Hess historically operated
the domestic terminals primarily as part of its integrated distribution network and therefore, meaningful historical revenue
information is not available. The following table summarizes revenue and net income related to the assets acquired from Hess
included in our consolidated statements of operations for the year ended December 31, 2013 (in thousands):
Revenue .................................................................................................................................................................. $
Net income (1) ........................................................................................................................................................
8,734
(7,657)
____________________________
(1) Includes transition expenses of $11.8 million.
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%, and in April 2013, BPH had purchased
an additional 10% ownership interest in Buckeye Memphis for $9.7 million, increasing our ownership interest in Buckeye
Memphis from 70% to 80%. 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.
81
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 years ended December 31, 2014 and 2013. We recorded asset impairment charges of
$23.4 million and $169.0 million within “Loss from discontinued operations” on our consolidated statements of operations for
the years ended December 31, 2014 and 2013, respectively. See Note 5 and Note 18 for further discussion.
The following table summarizes the results from discontinued operations (in thousands):
Revenue ........................................................................................................... $
Depreciation and amortization ........................................................................
Loss from discontinued operations..................................................................
Year Ended December 31,
2015
2014
— $
—
(857)
$
25,862
—
(59,641)
2013
55,757
7,608
(187,174)
5. ASSET IMPAIRMENTS
Natural Gas Storage Disposal Group
In connection with the classification of our Natural Gas Storage disposal group as held for sale in December 2013 we
performed a valuation to measure the disposal group at fair value less costs to sell (see Note 18 for more information).
The estimated fair value less costs to sell was determined to be less than its carrying value, which resulted in the recognition of
a non-cash asset impairment charge of $169.0 million in the fourth quarter of 2013, which included the write-down of long-
lived assets. 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 additional 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 years ended
December 31, 2014 and 2013, respectively. Refer to Note 18 for further discussion.
NORCO Pipeline System
During the third and fourth quarters of 2012, management performed extensive integrity tests on a portion of our NORCO
pipeline system, consisting of approximately 169 miles of liquid petroleum products pipelines and related assets in Indiana and
Illinois. Upon completion of the integrity tests in the fourth quarter of 2012, management determined that projected integrity
costs, which included work required to maintain the line to our integrity standards, were in excess of the amounts that would be
recoverable through operation of the line and proposed the abandonment of this portion of our NORCO pipeline system.
On December 13, 2012, the Board approved management’s plan. Based on the determination to abandon this pipeline, we were
able to estimate the settlement date for the asset retirement obligation and therefore recorded a liability of $12.1 million as of
December 31, 2012 for our estimated costs of abandonment, which we began incurring in 2013. We also compared the
undiscounted future cash flows to the carrying value of the assets, including the asset retirement cost associated with the
removal and decommissioning of the pipeline. Since the carrying value exceeded the undiscounted cash flows, we estimated
the fair value of the assets using the expected present value of future cash flows to be minimal and recorded a $60.0 million
non-cash asset impairment charge in December 2012 in our Domestic Pipelines & Terminals segment. In January 2013, we
ceased operations on the affected portion of the system. In 2014, we recorded a $3.8 million reduction in our ARO due to
revised estimated costs of abandonment. The ARO represents our best estimate of the costs to be incurred with information
currently available and is based on certain assumptions, including assumptions about methods of abandonment to be employed
and our requirements in applicable rights-of-way agreements.
82
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
Pennsauken Allisions. Our terminal located in Pennsauken, New Jersey suffered two allisions in the second half of 2014.
The first occurred on August 5, 2014, when a vessel allided with our terminal’s “Ship Dock.” We immediately “arrested” the
vessel and commenced litigation against its owner. Security for our claim was provided by the vessel owner’s insurers, in the
amount of $19.0 million, reserving all of their defenses. The vessel owners soon stipulated to liability, so the only issue in
dispute is the amount of Buckeye’s damages, which is now the subject of discovery. Reconstruction of the Ship Dock was
completed in July 2015 and service has since resumed. The aggregate cost to reconstruct the dock was approximately
$8.0 million. The second incident occurred on October 5, 2014, when a tug and barge struck and damaged the Pennsauken
terminal's “Barge Dock.” The tug and barge owners have commenced proceedings to limit their liability to $1.0 million and
$5.0 million, respectively. We have filed claims in the limitation proceedings for the reconstruction of the Barge Dock and
response costs, together amounting to approximately $7.0 million. We have suffered and continue to suffer loss-of-use damages
as a result of the above allisions, as the two incidents together impacted the ability of vessels of a certain size and/or carrying
certain products to call at the terminal. In order to mitigate these business losses, we made modifications to two other berths at a
cost of $1.4 million. Recovery for both the mitigation costs and business losses is being sought jointly from all of the respective
responsible parties. We are insured for loss of use, subject to a 30 day deductible. Our insurers have been involved in the
recovery efforts. In 2015, we received insurance recoveries of $5.1 million related to the loss of use of our terminal, which we
have recognized within “Transportation, storage and other services” in our consolidated statement of operations.
BORCO Jetty. On May 25, 2012, a ship, Cape Bari, allided with a jetty at our BORCO facility while berthing, causing
damage to portions of the jetty. Buckeye has insurance to cover this loss, subject to a $5.0 million deductible. On
May 26, 2012, we commenced legal proceedings in The Bahamas against the vessel’s owner and the vessel to obtain security
for the cost of repairs and other losses incurred as a result of the incident. Full security for our claim has been provided by the
vessel owner’s insurers, reserving all of their defenses. We also have notified the customer on whose behalf the vessel was at
the BORCO facility that we intend to hold them responsible for all damages and losses resulting from the incident pursuant to
the terms of an agreement between the parties. Any disputes between us and our customer on this matter are subject to
arbitration in New York, New York, and arbitration has commenced.
The vessel owner has claimed that it is entitled to limit its liability to $17.0 million, but we are contesting the right of the
vessel owner to such limitation. The Bahamas court of first instance denied the vessel owner the right to limit its liability for
the incident, leaving the vessel owner responsible for all provable damages. The vessel owner appealed, and The Bahamas
Court of Appeals reversed, holding that the vessel owner may limit its liability. Our application for leave to appeal the Court of
Appeals’ decision to the Privy Council was granted, the hearing occurred on February 23, 2016 and we await that decision. We
can express no view on whether The Bahamas Court of Appeals decision ultimately will be affirmed or reversed.
We experienced no material interruption of service at the BORCO facility as a result of the incident, and the repairs and
reconstruction of the damaged sections are complete.
83
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The aggregate cost to repair and reconstruct the damaged portions of the jetty and pursue recovery in court has been
$23.0 million. We recorded a loss on disposal due to the assets destroyed in the incident and other related costs incurred;
however, since we believe recovery of our losses is probable, we recorded a corresponding receivable. As of December 31,
2015, we had a $6.4 million receivable included in “Other non-current assets” in our consolidated balance sheet, representing
claims for reimbursement of the deductible and other third-party expenses. Additionally, we have received insurance
reimbursements of $16.0 million, and to the extent the aggregate proceeds from the recovery of our losses is in excess of the
carrying value of the destroyed assets or other costs incurred, we will recognize a gain when such proceeds are received and are
not refundable. Our insurers have paid most of the claim and are now parties in The Bahamas litigation. As of December 31,
2015, no gain had been recognized; however, we recorded a $14.1 million deferred gain in “Accrued and other current
liabilities” in our consolidated balance sheet, representing excess proceeds received over the loss on disposal and other costs
incurred.
On May 12, 2014, the vessel owner filed a third-party complaint against BORCO and a BORCO subsidiary, Borco Towing
Company Limited, alleging negligence by the pilots and tugs that assisted the Cape Bari berthing. We have investigated these
allegations and believe that we have defenses and intend to defend ourselves and pursue our claims against the vessel owner.
BORCO and Borco Towing Company Limited are insured for the alleged liability, subject to an applicable deductible, and the
liability insurers are participating in the defense. The main proceeding and third-party actions have been consolidated and are
expected to go to trial in May 2016.
Buckeye Texas Partners Contractor Dispute. Buckeye Texas Processing LLC, a wholly owned subsidiary of Buckeye
Texas, is party to a contract with Ventech Engineers USA, LLC (“Ventech”). The contract required Ventech to design, supply,
fabricate, and install two condensate splitters in Corpus Christi, Texas (the “Splitter Project”). Ventech’s primary subcontractor
on the Splitter Project was Bay, Ltd. (“Bay”). Certain disputes arose on the Splitter Project relating to payment, delays, cost
overruns, defective work, and other issues. On October 14, 2015, Bay filed a lawsuit in Harris County District Court against us
and Ventech, claiming breach of contract, fraud, and other causes of action primarily premised on alleged non-payment of
amounts due on the Splitter Project. We also believe that, if the matter is not resolved, Ventech may claim that it is also owed
additional money for its work on the Splitter Project. We disagree with assertions that we owe Ventech and Bay additional
amounts and, if resolution cannot be reached, we intend to pursue claims against Ventech and Bay relating to the delays, cost
overruns, defective work, and other issues on the Splitter Project. In addition, Ventech provided a bond on the Splitter Project
that may help to satisfy some of our losses. Our damages may exceed the damages claimed by Ventech and Bay. The parties
have agreed to mediate to seek to resolve the disputes between them, and settlement discussions are ongoing.
Federal Energy Regulatory Commission (“FERC”) Proceedings
FERC Docket No. OR12-28-000 — Airlines Complaint against Buckeye Pipe Line Company, L.P. (“BPLC”) New York City
Jet Fuel Rates. On September 20, 2012, a complaint was filed with FERC by Delta Air Lines, JetBlue Airways, United/
Continental Air Lines, and US Airways challenging BPLC’s rates for transportation of jet fuel from New Jersey to three New
York City airports. The complaint was not directed at BPLC’s rates for service to other destinations and did not involve
pipeline systems and terminals owned by Buckeye’s other operating subsidiaries. The complaint challenged these jet fuel
transportation rates as generating revenues in excess of costs and thus being “unjust and unreasonable” under the Interstate
Commerce Act. On February 22, 2013, FERC issued an order setting the airline complaint in Docket (“Dkt.”) No.
OR12-28-000 for hearing, but holding the hearing in abeyance and setting the dispute for settlement procedures before a
settlement judge. On March 8, 2013, an order was issued consolidating, for settlement purposes, this complaint proceeding with
the proceeding regarding BPLC’s application for market-based rates in the New York City market in Dkt. No. OR13-3-000
(discussed below), and settlement discussions under the supervision of the FERC settlement judge continued until April 1,
2014, when it was reported that the parties had been unable to reach a settlement. As a result, the matter proceeded to hearing,
which was concluded on April 1, 2015. As a result of developments in ongoing settlement talks regarding Dkt. Nos.
OR12-28-000, OR13-3-000 (discussed below) and OR 14-41-000 (discussed below), we recorded an accrual and a
corresponding reduction in revenue in the amount of $40.0 million for the year ended December 31, 2014 in our Domestic
Pipelines & Terminals segment based upon a settlement offer made by BPLC to satisfy the claims for alleged past excessive
charges through December 31, 2014.
84
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In parallel with the hearing in the OR12-28-000 proceeding, BPLC and the airlines continued to pursue settlement.
On June 19, 2015, BPLC and the airlines submitted an Offer of Settlement at the FERC (the “Settlement”) to resolve the
complaints in Dkt. Nos. OR12-28-000, et al. and OR14-41-000, as well as BPLC’s application in Dkt. No. OR13-3-000. Under
the terms of the Settlement, BPLC agreed to reduce its jet fuel rates prospectively, to make settlement payments to the airlines,
to install facilities to increase the flexibility and capacity of its system in shipping jet fuel to John F. Kennedy International
Airport, and to resolve its application in Dkt. No. OR13-3-000 as described further below. As a result of submission of the
Settlement, we recorded an additional accrual and corresponding reduction in revenue in the amount of $15.2 million during the
year ended December 31, 2015 in our Domestic Pipelines & Terminals segment, which, together with the previously recorded
$40.0 million reduction in revenue, represented anticipated settlement payments and other expenses associated with the
Settlement. On September 29, 2015, the FERC approved the Settlement without modification. On October 1, 2015, BPLC filed
a tariff to implement the terms of the Settlement, including the agreed-upon reductions in jet fuel rates effective November 1,
2015 (the “Settlement Tariff”) in Dkt. No. IS16-7-000. On October 16, 2015, a jet fuel marketer and three airlines not parties to
the Settlement protested the tariff, alleging that certain provisions of an incentive rate program provided for in the Settlement
are unduly discriminatory (the “Protest”). On October 30, 2015, the FERC rejected the Protest on the merits and accepted the
Settlement Tariff, permitting the reduced rates to go into effect on November 1, 2015. On October 29, 2015, the same jet fuel
marketer and airlines sought late intervention and rehearing at the FERC to challenge the FERC’s approval of the Settlement,
alleging, on a basis similar to the Protest, that certain provisions of the Settlement’s incentive rate program are unduly
discriminatory. BPLC and the settling airlines responded that the Protest's claims were invalid and untimely. On December 2,
2015, the FERC denied the late intervention request, which had the effect of barring the rehearing request. During the quarter
ended December 31, 2015, we made payments of $52.8 million related to the Settlement.
FERC Docket No. OR14-41-000 — American Airlines Complaint against BPLC New York City Jet Fuel Rates.
On September 17, 2014, a complaint was filed with FERC by American Airlines, raising claims similar to the Dkt. No.
OR12-28-000 complaint (see above). As noted above, the Settlement to resolve this complaint was approved by the FERC on
September 29, 2015.
FERC Docket No. OR13-3-000 — BPLC’s Market-Based Rate Application. On October 15, 2012, BPLC filed an
application with FERC seeking authority to charge market-based rates for deliveries of liquid petroleum products to the New
York City-area market (the “Application”). In the Application, BPLC sought to charge market-based rates from its three origin
points in northeastern New Jersey to its five destinations on its Long Island System, including deliveries of jet fuel to the
Newark, LaGuardia, and JFK airports. On December 14, 2012, Delta Air Lines, JetBlue Airways, United/Continental Air Lines,
and US Airways filed a joint intervention and protest challenging the Application and requesting its rejection. Following
further pleadings, on February 28, 2013, FERC set the Application for hearing but held the hearing in abeyance and set the
dispute for settlement procedures before a settlement judge.
After unsuccessful settlement talks, litigation as to the Application proceeded separately from the complaint proceeding.
Prior to the hearing, the airlines and BPLC reached an agreement in principle, and as noted above, submitted an Offer of
Settlement to the FERC to resolve the airlines’ objections to the Application. Under the terms of the Settlement, BPLC agreed,
inter alia, to withdraw the portions of the Application addressing transportation of jet fuel within the New York City market,
including transportation of jet fuel to the three airports, while remaining free to pursue market-based rates for transportation of
other refined petroleum products to other destinations within the New York City market. As noted above, the Settlement was
approved by the FERC on September 29, 2015, and on October 5, 2015, BPLC filed a notice withdrawing the Application
except as to the transportation of other refined petroleum products from Linden, New Jersey to Inwood and Long Island City,
New York. On February 11, 2016, BPLC submitted a joint motion with the support of FERC Trial Staff requesting that FERC
waive the issuance of an initial decision, and instead issue an order addressing the revised application of BPLC, based on
evidence submitted by Commission Trial Staff and BPLC, both of whose additional evidence found that BPLC lacked
significant market power over the transportation of other refined petroleum products from Linden, New Jersey to Inwood and
Long Island City, New York. FERC has not yet issued an order in response to the filing submitted on February 11, 2016.
85
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Environmental Contingencies
We recorded operating expenses, net of recoveries, of $6.2 million, $3.0 million and $3.5 million during the years ended
December 31, 2015, 2014 and 2013, respectively, related to environmental remediation liabilities unrelated to claims and legal
proceedings. As of December 31, 2015 and 2014, we recorded environmental remediation liabilities of $48.0 million and
$52.3 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,
2015 and 2014, we had $10.9 million and $13.6 million, respectively, of receivables related to these environmental remediation
liabilities covered by insurance or third-party claims.
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, 2015, 2014 and 2013 was $31.0 million,
$26.9 million and $24.9 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
Equipment (1)
Land
Leases (2)
Total
2016...................................................................................... $
2017......................................................................................
2018......................................................................................
2019......................................................................................
2020......................................................................................
Thereafter.............................................................................
Total................................................................................... $
3,885
3,984
3,132
2,927
3,008
3,404
20,340
$
$
4,010
986
—
—
—
—
4,996
$
$
2,398
2,398
2,398
2,398
2,398
89,865
101,855
$
$
10,293
7,368
5,530
5,325
5,406
93,269
127,191
____________________________
(1) Includes BORCO 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, 2015, 2014 and 2013 were $7.0 million,
$6.5 million and $6.1 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 ....................................................................................................................... $
174,232
18,760
192,992
$
$
226,898
16,577
243,475
____________________________
(1) Ending inventory was 153.3 million and 140.3 million gallons of liquid petroleum products at December 31, 2015 and
2014, respectively.
December 31,
2015
2014
86
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
At December 31, 2015 and 2014, approximately 89% and 90% 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.
8. PREPAID AND OTHER CURRENT ASSETS
Prepaid and other current assets consist of the following at the dates indicated (in thousands):
December 31,
2015
2014
Prepaid insurance ........................................................................................................................ $
Unbilled revenue .........................................................................................................................
Prepaid taxes ...............................................................................................................................
Escrow deposits...........................................................................................................................
Other............................................................................................................................................
Total prepaid and other current assets ...................................................................................... $
12,779
4,047
4,842
21,360
5,043
48,071
$
$
9,918
3,556
2,492
—
9,089
25,055
9. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consist of the following at the dates indicated (in thousands):
Estimated
Useful
Lives (Years)
December 31,
2015
2014
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.......................................................
N/A
(1)
13-50
20-50
25-50
7-50
3-20
30-50
N/A
____________________________
(1) Rights-of-way assets are depreciated over the useful life of the related pipeline assets.
$
669,130
$
107,293
235,872
629,677
2,349
655,847
104,754
364,704
485,523
2,229
4,616,080
4,306,472
117,494
557,853
141,153
103,253
—
445,165
7,076,901
(874,820)
6,202,081
$
6,467,947
(732,160)
5,735,787
$
Depreciation expense was $158.7 million, $148.4 million and $122.7 million for the years ended December 31, 2015, 2014
and 2013, respectively.
87
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):
Ownership
2015
2014
December 31,
West Shore Pipe Line Company......................................................................
Muskegon Pipeline LLC..................................................................................
Transport4, LLC ..............................................................................................
South Portland Terminal LLC .........................................................................
Total equity investments ...............................................................................
34.6%
40.0%
25.0%
50.0%
$
$
60,441
13,599
459
9,629
84,128
$
$
57,123
16,175
503
9,048
82,849
The following table presents earnings from equity investments for the periods indicated (in thousands):
Year Ended December 31,
2015
2014
2013
West Shore Pipe Line Company...................................................................... $
Muskegon Pipeline LLC..................................................................................
Transport4, LLC ..............................................................................................
South Portland Terminal LLC .........................................................................
Total earnings from equity investments........................................................ $
7,070
(2,876)
606
1,581
6,381
$
$
8,621
1,059
470
1,115
11,265
$
$
4,176
(77)
361
783
5,243
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,
2015
2014
26,910
126,456
153,366
11,474
43,344
98,548
153,366
$
$
$
$
62,437
109,347
171,784
28,242
50,598
92,944
171,784
INCOME STATEMENT DATA:
Revenue......................................................................................................... $
Costs and expenses........................................................................................
Non-operating expense .................................................................................
Net income .................................................................................................... $
92,501
(56,906)
(15,903)
19,692
$
$
88,417
(48,563)
(13,826)
26,028
$
$
79,266
(58,697)
(6,808)
13,761
Year Ended December 31,
2014
2013
2015
88
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):
Domestic
Pipelines
& Terminals
Global
Marine
Terminals
Merchant
Services
Total
January 1, 2014 .................................................................................... $
Acquisition (1)...................................................................................
Purchase price adjustments (2)..........................................................
December 31, 2014 ..............................................................................
Acquisition (1)...................................................................................
Purchase price adjustments (2)..........................................................
December 31, 2015 .............................................................................. $
279,615
$
537,894
$
3,991
$
821,500
—
(335)
279,280
10,626
—
289,906
$
172,632
(930)
709,596
—
(5,253)
704,343
—
508
4,499
—
—
$
4,499
$
172,632
(757)
993,375
10,626
(5,253)
998,748
____________________________
(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 2014, we recorded adjustments to the purchase price allocations for the Perth
Amboy facility and Hess Terminals acquisitions. During 2015, we recorded adjustments to the purchase price allocations
for the Buckeye Texas Partners Transaction. See Note 3 for discussion of our acquisitions.
For our annual goodwill impairment test as of October 31, 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. Prior to the current year change in our goodwill annual impairment test date, our annual goodwill impairment
tests were performed as of January 1st. For our January 1, 2015 goodwill impairment test, we performed a qualitative
assessment to determine whether the fair value of the Domestic Pipelines & Terminals reporting unit was more likely than not
less than the carrying value. Based on economic conditions and industry and market considerations, we determined the fair
value of the reporting unit exceeded the carrying value; therefore, the quantitative impairment test was not required.
Additionally, we performed quantitative assessments to determine the fair value of each of the remaining 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, 2015 and 2014. See Note 2 for further discussion of the change of our
annual impairment test date.
89
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Intangible Assets
Intangible assets consist of the following at the dates indicated (in thousands):
December 31,
2015
2014
Customer relationships................................................................................................................ $
Accumulated amortization ..........................................................................................................
Net carrying amount .................................................................................................................
$
231,620
(70,349)
161,271
Customer contracts......................................................................................................................
Accumulated amortization ..........................................................................................................
Net carrying amount .................................................................................................................
Total intangible assets, net................................................................................................... $
395,690
(65,589)
330,101
491,372
$
231,620
(57,246)
174,374
446,233
(66,683)
379,550
553,924
For the years ended December 31, 2015, 2014 and 2013, amortization expense related to intangible assets was
$62.6 million, $47.4 million and $24.4 million, respectively. Amortization expense related to intangible assets is expected to be
$68.0 million for 2016, $66.6 million for 2017, $65.7 million for 2018, $64.9 million for 2019 and $64.9 million for 2020.
12. OTHER NON-CURRENT ASSETS
Other non-current assets consist of the following at the dates indicated (in thousands):
December 31,
2015
2014
Debt issuance costs, net .............................................................................................................. $
Insurance receivables related to environmental remediation reserves........................................
Indemnification asset ..................................................................................................................
BORCO jetty insurance receivable (see Note 6).........................................................................
Pennsauken allision third party receivable (see Note 6) .............................................................
Derivative assets .........................................................................................................................
Other............................................................................................................................................
Total other non-current assets................................................................................................... $
4,150
4,554
—
6,433
—
1,057
25,208
41,402
$
$
4,540
8,111
17,720
6,178
2,769
2,919
25,249
67,486
90
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
13. ACCRUED AND OTHER CURRENT LIABILITIES
Accrued and other current liabilities consist of the following at the dates indicated (in thousands):
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)..............................................................................................
Other ...........................................................................................................................................
Total accrued and other current liabilities................................................................................ $
December 31,
2015
2014
28,183
6,710
9,164
56,066
27,365
28,942
79,060
36,108
5,979
1,360
2,390
28,293
309,620
$
$
19,619
4,528
12,315
57,958
23,329
24,087
31,178
14,077
11,071
1,067
40,000
55,795
295,024
____________________________
(1) Amounts relate to the unfavorable storage contracts acquired in connection with the BORCO acquisition in 2011.
We recognized $11.1 million of revenue during the years ended December 31, 2015 and 2014. Revenue to be recognized
related to these unfavorable storage contracts is expected to be $6.0 million for 2016.
(2) Amount relates to a contingent liability associated with the FERC litigation accrual. See Note 6 for further information.
91
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):
December 31,
2015
2014
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).....................................................................................
6.750% Notes due August 15, 2033 (1) ......................................................................................
5.850% Notes due November 15, 2043 (1).................................................................................
5.600% Notes due October 15, 2044 (1).....................................................................................
Credit Facility due September 30, 2020......................................................................................
Unamortized discounts and debt issuance costs .........................................................................
Total debt ..................................................................................................................................
Less: Current portion of line of credit (2) ...................................................................................
Total long-term debt ................................................................................................................. $
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
$
$
125,000
300,000
400,000
275,000
650,000
500,000
300,000
150,000
400,000
300,000
166,000
(31,382)
3,534,618
(166,000)
3,368,618
____________________________
(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):
Years Ending
December 31,
2016 ........................................................................................................................................................................ $
2017 ........................................................................................................................................................................
2018 ........................................................................................................................................................................
2019 ........................................................................................................................................................................
2020 ........................................................................................................................................................................
Thereafter................................................................................................................................................................
Total...................................................................................................................................................................... $
111,488
125,000
700,000
275,000
361,000
2,300,000
3,872,488
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 (the “Credit Facility”) 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. At September 2014, we had
$2.7 million of remaining unamortized deferred financing costs, and we incurred additional debt issuance costs of $2.1 million
in connection with the modification and extension of the Credit Facility.
92
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In December 2015, Buckeye and BMSC exercised their option to extend our existing Credit Facility 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. 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, 2015, Buckeye and BMSC collectively had $472.5 million outstanding under the Credit Facility, of
which $111.5 million, attributable to BMSC, was classified as current liabilities in our consolidated balance sheet, as related
funds were used to finance current working capital needs. The weighted average interest rate for borrowings under the Credit
Facility was 1.7% at December 31, 2015. The Credit Facility includes covenants limiting, as of the last day of each fiscal
quarter, the ratio of consolidated funded debt (“Funded Debt Ratio”) to consolidated EBITDA, 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, depletion and
amortization determined on a consolidated basis. At December 31, 2015, our Funded Debt Ratio was 4.01 to 1.00.
At December 31, 2015, we were in compliance with the covenants under our Credit Facility.
At December 31, 2015 and 2014, we had committed $1.2 million and $0.8 million, respectively, in support of letters of
credit. The obligations for letters of credit are not reflected as debt on our consolidated balance sheets.
Note Offerings
In September 2014, we issued an aggregate of $600.0 million of senior unsecured notes in an underwritten public offering,
including the $300.0 million of 4.350% Notes due on October 15, 2024 (the “4.350% Notes”) and the $300.0 million of 5.600%
Notes due on October 15, 2044 (the “5.600% Notes”), at 99.825% and 99.876%, respectively, of their principal amounts.
Total proceeds from this offering, after underwriting fees, expenses and debt issuance costs of $5.3 million, were $593.8
million. We used the net proceeds from this offering to fund a portion of the Buckeye Texas Partners Transaction (see Note 3),
to settle all interest rate swaps relating to the forecasted refinancing of the 5.300% Notes for $51.5 million (see Note 17) and for
general partnership purposes. We also used the net proceeds to reduce the indebtedness outstanding under our Credit Facility.
Extinguishment of Debt
In October 2014, we repaid in full the $275.0 million principal amount outstanding under the 5.300% Notes due on
October 15, 2014 (the “5.300% Notes”) and $7.3 million of related accrued interest using funds available under our Credit
Facility.
93
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
15. OTHER NON-CURRENT LIABILITIES
Other non-current liabilities consist of the following at the dates indicated (in thousands):
December 31,
2015
2014
Accrued employee benefit liabilities........................................................................................... $
Accrued environmental remediation liabilities ...........................................................................
Deferred consideration ................................................................................................................
Liability related to investment tax credit ....................................................................................
Unfavorable storage contracts (1) ...............................................................................................
ARO ............................................................................................................................................
Derivative liabilities ....................................................................................................................
Other............................................................................................................................................
Total other non-current liabilities ............................................................................................. $
42,643
38,832
23,392
—
—
5,463
703
4,374
115,407
$
$
44,364
39,993
16,131
17,720
5,979
2,596
2,620
5,148
134,551
____________________________
(1) Amounts relate to the unfavorable storage contracts acquired in connection with the BORCO acquisition in 2011. See Note
13 for further discussion.
16. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Accumulated other comprehensive income (loss) consists of the following at the dates indicated (in thousands):
December 31,
2015
2014
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 ........................................................................... $
$
1,266
(92,014)
(7,093)
(97,841) $
—
(104,165)
(11,123)
(115,288)
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.
We entered into six forward-starting interest rate swaps with a total aggregate notional amount of $300.0 million, which we
entered into in anticipation of the issuance of debt on or before July 15, 2013, and six forward-starting interest rate swaps with a
total aggregate notional amount of $275.0 million, which we entered into in anticipation of the issuance of debt on or before
October 15, 2014.
94
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In September 2014, we issued $300.0 million of senior unsecured notes (see Note 14 for further discussion) and also settled
the related six forward-starting interest rate swaps 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 the related six forward-starting interest rate swaps 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, 2014 unrealized loss of $21.4 million was recorded in AOCI to reflect the change in
the fair values of the forward-starting interest rate swaps. Over the next twelve months, we expect to reclassify $12.2 million of
net losses from accumulated other comprehensive loss to interest and debt expense. The loss consists primarily of the
amortization of our settled 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 Domestic Pipelines & Terminals segment uses exchange-traded refined petroleum contracts to hedge certain
expected future transactions which we 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.
Our Merchant Services segment entered into these contracts on behalf of our Domestic Pipelines & Terminals segment. In both
cases, 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. Physical forward contracts and futures contracts that have
not been designated in a hedge relationship are marked-to-market.
The following table summarizes our commodity derivative instruments outstanding at December 31, 2015 (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:
Futures contracts for refined petroleum products.....................................
Futures contracts for refined petroleum products.....................................
____________________________
(1) Volume represents absolute value of net notional volume position.
Volume (1)
Current
Long-Term
Accounting
Treatment
13,741
69,457
13,587
136,458
8,400
1,659 Mark-to-market
— Mark-to-market
2,562 Mark-to-market
— Fair Value Hedge
— Cash Flow Hedge
95
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table sets forth the fair value of each classification of derivative instruments and the locations of the
derivative instruments on our consolidated balance sheets at the dates indicated (in thousands):
December 31, 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.
December 31, 2014
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......................
Physical fixed price derivative contracts .............
Futures contracts for refined products .................
Total non-current derivative liabilities ..............
Net derivative assets ............................................ $
42,005
112
150,352
192,469
2,919
2,919
(1,502)
(371)
(153,911)
(155,784)
(5)
(2,615)
(2,620)
36,984
Derivatives
Designated
as Hedging
Instruments
$
Derivative
Carrying
Value
42,005
112
181,054
223,171
2,919
2,919
(1,502)
(371)
(153,911)
(155,784)
(5)
(2,615)
(2,620)
67,686
— $
—
30,702
30,702
—
—
—
—
—
—
—
—
—
30,702
$
$
$
Netting
Balance
Sheet
Adjustment (1)
$
(12) $
(59)
(153,911)
(153,982)
—
—
12
59
153,911
153,982
—
—
—
— $
Total
41,993
53
27,143
69,189
2,919
2,919
(1,490)
(312)
—
(1,802)
(5)
(2,615)
(2,620)
67,686
____________________________
(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.
96
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Our futures contracts designated as fair value hedges related to our inventory portfolio extend to the third quarter of 2016
and our futures contracts designated as cash flow hedges related to refined petroleum products extend to the first quarter of
2016. The majority of the unrealized gain at December 31, 2015, for fair value hedges of inventory and cash flow hedges
related to refined petroleum products represented by futures contracts of $33.7 million and $1.3 million, respectively, will be
realized by the first quarter of 2016. At December 31, 2015, open refined petroleum product derivative contracts (represented
by the physical fixed-price contracts, physical index contracts, and futures contracts for fixed-price sales contracts noted above)
varied in duration in the overall portfolio, but did not extend beyond April 2018. In addition, at December 31, 2015, 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,
2015
2014
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 loss in income ........................................................................
$
$
$
$
$
35,667
(268)
12,489
101
(6,559)
50,293
(73)
4,352
(849)
(14,151)
$
75,974
(83,703)
117,283
(144,142)
$
2,162
(9,891)
(7,729) $
40
(26,899)
(26,859)
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 ...............................................................................................................
$
Gain (Loss) Recognized
in OCI on Derivatives for the
Year Ended December 31,
2015
2014
— $
1,266
1,266
$
(21,424)
—
(21,424)
Loss Reclassified
From AOCI to Income for the
Year Ended December 31,
Location
2015
2014
Derivatives designated as cash flow hedging instruments:
Interest rate contracts.................................................................... Interest and debt expense
$
(12,151) $
(9,753)
The unrealized gain at December 31, 2015 for refined petroleum products designated as cash flow hedges of $1.3 million
will be realized and reclassified from AOCI to product sales by the first quarter of 2016, at the end of the butane blending
season. The ineffective portion of the change in fair value of cash flow hedges was not material for the year ended
December 31, 2015.
97
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 2015
December 31, 2014
Level 1
Level 2
Level 1
Level 2
Financial assets:
Physical fixed price derivative contracts ............................. $
Physical index derivative contracts......................................
Futures contracts for refined products .................................
— $
—
51,641
27,676
25
—
Financial liabilities:
Physical fixed price derivative contracts .............................
Physical index derivative contracts......................................
Futures contracts for refined products .................................
Fair value ........................................................................... $
—
—
(703)
50,938
$
(456)
(54)
—
27,191
$
$
— $
—
27,143
44,912
53
—
—
—
(2,615)
24,528
$
(1,495)
(312)
—
43,158
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 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 fixed price derivative assets are net of credit value adjustments (“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 Level 2 fixed price derivative assets
of $27.7 million and $44.9 million as of December 31, 2015 and 2014, respectively, are net of CVA of ($0.2) million and
($0.1) million as of December 31, 2015 and 2014, respectively. As of December 31, 2015, the Merchant Services segment did
not hold any net liability derivative position containing credit contingent features.
Financial instruments included in current assets and current liabilities are reported in the consolidated balance sheets at
amounts which approximate fair value due to the relatively short period to maturity of these financial instruments. The fair
values of our fixed-rate debt were estimated by observing market trading prices and by comparing the 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):
December 31, 2015
December 31, 2014
Carrying
Amount
Fair Value
Carrying
Amount
Fair Value
Fixed-rate debt ..................................................................... $
Variable-rate debt.................................................................
Total debt........................................................................... $
3,371,824
472,488
3,844,312
$
$
3,057,945
472,488
3,530,433
$
$
3,368,618
166,000
3,534,618
$
$
3,465,973
166,000
3,631,973
98
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 2015 and 2014.
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.
During the year ended December 31, 2013, we recorded a non-cash asset impairment charge of $169.0 million based on
Level 3 inputs related to our Natural Gas Storage disposal group. We believed the combination of a repurposed natural gas and
compressed air energy storage was the highest-and-best use of this facility and as such our fair value estimate less cost to sell
was based on the disposal group operating as such. We applied the income approach due to the lack of recent comparable
transactions in the marketplace and estimated the fair value using a present value of expected future cash flows valuation
method. The present value of the expected future cash flows was determined using multiple pricing inputs, including, where
applicable, commodity prices (power ancillary service charges, energy prices, capacity fees, and natural gas storage), discount
rates, historical contract terms, and operational capabilities of the natural gas storage facility. Valuation adjustments were
considered to factor in liquidity risk and model uncertainty. Unobservable pricing inputs were developed based on an
evaluation of relevant empirical market data and historical pricing and operating cash flows. In addition, we engaged a third-
party natural gas storage valuation specialist to assist with our internally developed fair value estimate.
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 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.
99
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 loss (gain) ..........................................................
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,
2015
2014
2015
2014
17,988
11
551
—
346
(469)
(1,022)
17,405
6,743
(373)
—
665
(469)
(1,022)
5,544
$
$
$
$
17,180
94
553
—
770
—
(609)
17,988
6,003
152
—
1,197
—
(609)
6,743
$
$
$
$
36,117
365
1,334
510
(3,573)
—
(1,023)
33,730
$
$
— $
—
510
513
—
(1,023)
— $
35,149
345
1,420
456
(188)
—
(1,065)
36,117
—
—
456
609
—
(1,065)
—
Funded status at end of year ............................................. $
(11,861) $
(11,245) $
(33,730) $
(36,117)
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,
2015
2014
2015
2014
Accrued employee benefit liabilities - current .................. $
Accrued employee benefit liabilities - noncurrent ............
Total.............................................................................. $
— $
(11,861)
(11,861) $
— $
(11,245)
(11,245) $
(2,948) $
(30,782)
(33,730) $
(2,998)
(33,119)
(36,117)
AOCI:
Net actuarial loss ............................................................... $
Total.............................................................................. $
5,804
5,804
$
$
6,062
6,062
$
$
1,289
1,289
$
$
5,061
5,061
100
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,
2015
2014
Projected benefit obligation ........................................................................................................ $
Accumulated benefit obligation (1) ............................................................................................
Fair value of plan assets ..............................................................................................................
17,405
$
13,357
5,544
17,988
13,602
6,743
____________________________
(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,
2015
2014
2013
2015
2014
2013
Discount rate.........................................
Expected return on plan assets..............
Rate of compensation increase .............
3.3%
5.8%
3.0%
3.5%
5.8%
3.0%
2.7%
5.8%
3.0%
3.9%
N/A
3.0%
4.4%
N/A
3.0%
3.6%
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,
2015
2014
2015
2014
Discount rate ........................................................................
Rate of compensation increase.............................................
3.5%
3.0%
3.3%
3.0%
4.1%
3.0%
3.9%
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, 2015, 2014, and 2013, 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, 2015 in the
Retiree Medical Plan was 6.0% for 2016, 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, 2015 results (in thousands):
Effect on total service cost and interest cost components........................................................... $
Effect on postretirement benefit obligation.................................................................................
$
56
778
(50)
(700)
1%
Increase
1%
(Decrease)
101
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,
2015
2014
2013
2015
2014
2013
Components of net periodic benefit
cost:
Service cost ........................................ $
Interest cost ........................................
Expected return on plan assets ...........
Amortization of prior service credit ...
Actuarial loss due to settlements ........
Amortization of unrecognized loss ....
551
(334)
—
469
842
Net periodic benefit cost................ $
1,539
$
Other changes in plan assets and
benefit obligations recognized in
OCI:
Net actuarial loss (gain)...................... $
Amortization of unrecognized loss ....
Actuarial loss due to settlements ........
Amortization of prior service credit ...
1,053
$
(842)
(469)
—
Total recognized in OCI ................ $
(258) $
553
(333)
—
—
667
981
951
(667)
—
—
284
Total recognized in net period benefit
cost and OCI ......................................... $
1,281
$
1,265
11
$
94
$
217
$
365
$
345
$
538
(393)
—
773
1,232
1,334
1,420
—
—
—
199
—
—
—
31
$
2,367
$
1,898
$
1,796
$
431
1,409
—
(1,624)
—
1,193
1,409
$
$
$
(3,298) $
(1,232)
(773)
—
(5,303) $
(3,573) $
(199)
—
—
(3,772) $
(188)
(31)
—
—
(219) $
(7,756)
(1,193)
—
1,624
(7,325)
(2,936) $
(1,874) $
1,577
$
(5,916)
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, 2016 (in thousands):
Amortization of unrecognized loss ............................................................................................. $
923
$
—
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
2016............................................................................................................................................. $
2017.............................................................................................................................................
2018.............................................................................................................................................
2019.............................................................................................................................................
2020.............................................................................................................................................
Thereafter ....................................................................................................................................
RIGP
1,827
$
2,147
1,825
1,871
1,681
5,922
Retiree
Medical
Plan
3,009
2,946
2,912
2,893
2,801
11,500
102
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We expect to contribute $4.0 million to our benefit plans in 2016. Funding requirements for subsequent years are uncertain
and will depend on whether there are any changes in the actuarial assumptions used to calculate plan funding levels, the actual
return on plan assets and any legislative or regulatory changes affecting plan funding requirements. For tax planning, financial
planning, cash flow management or cost reduction purposes, we may increase, accelerate, decrease or delay contributions to the
plan to the extent permitted by law.
We do not fund the Retiree Medical Plan and, accordingly, no assets are invested in the plan. A summary of investments in
the RIGP are as follows at the dates indicated (in thousands):
Mutual fund - fixed-income securities................................. $
Mutual fund - money market ...............................................
Coal lease .............................................................................
Fair value of plan assets .................................................... $
2,759
465
—
3,224
$
$
— $
—
2,320
2,320
$
3,107
660
—
3,767
$
$
—
—
2,976
2,976
December 31, 2015
December 31, 2014
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,
2015
2014
Beginning balance, January 1 ..................................................................................................... $
Lease payments received .....................................................................................................
Unrealized loss.....................................................................................................................
Transfers out of Level 3.......................................................................................................
Ending balance, December 31 .................................................................................................. $
2,976
393
(656)
(393)
2,320
$
$
3,303
307
(327)
(307)
2,976
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 $15.2 million, $14.0 million and $10.7 million during the years ended December 31,
2015, 2014 and 2013, respectively.
103
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, $1.0 million and $0.6 million during the years
ended December 31, 2015, 2014 and 2013, 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 BORCO, were $1.4 million, $1.4 million and $1.2 million during the years
ended December 31, 2015, 2014 and 2013, respectively.
Employee Stock Ownership Plan
Services Company provides the ESOP to the majority of its employees hired before September 16, 2004. Employees hired
by Services Company after September 15, 2004 and certain employees covered by a union 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, 2015, 2014, and 2013.
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 $29.3 million, $21.5 million and $21.8 million for the years ended December 31, 2015, 2014 and 2013, 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.
104
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
After giving effect to the issuance or forfeiture of phantom unit and performance unit awards through the year end, awards
representing a total of 2,610,765 LP Units were available for issuance under the LTIP as of December 31, 2015.
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, 2015, 2014 and
2013, eligible employees were allowed to defer up to 50% of their 2015, 2014, and 2013 compensation award 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, 2015, $3.1 million of 2015 compensation awards had been deferred, for
which phantom units will be granted in 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. At December 31, 2013,
$2.7 million of 2013 compensation awards had been deferred, for which 75,870 phantom units (including matching units) were
granted during 2014. These grants are included as granted in the LTIP activity table below.
Awards under the LTIP
During the year ended December 31, 2015, the Compensation Committee granted 202,176 phantom units to employees
(including the 54,592 phantom units granted pursuant to the Deferral Plan discussed above), 22,001 phantom units to
independent directors of Buckeye GP and 210,494 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 $2.6 million and
$2.0 million for the years ended December 31, 2015 and 2014, 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.
105
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table sets forth the LTIP activity for the periods indicated (in thousands, except per unit amounts):
Unvested at January 1, 2014 .......................................................................................................
Granted .....................................................................................................................................
Vested........................................................................................................................................
Forfeited....................................................................................................................................
Unvested at December 31, 2014 .................................................................................................
Granted .....................................................................................................................................
Vested........................................................................................................................................
Forfeited....................................................................................................................................
Unvested at December 31, 2015 .................................................................................................
Number of
LP Units
813
409
(231)
(85)
906
435
(312)
(18)
1,011
Weighted
Average
Grant Date
Fair Value
per LP Unit (1)
59.36
$
71.79
63.27
63.92
63.56
73.45
62.08
67.32
68.20
$
$
____________________________
(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, 2015, we expect to recognize $28.9 million of compensation expense related to the LTIP over a weighted
average period of 1.7 years.
Unit Option and Distribution Equivalent Plan
We also sponsor the Option Plan pursuant to which we historically granted options to employees to purchase LP Units at
the market price of our LP Units on the date of grant. Generally, the options vest three years from the date of grant and expire
ten years from the date of grant. As unit options are exercised, we issue new LP Units to the holder. We have not historically
repurchased, and do not expect to repurchase in 2016, any of our LP Units. Following the adoption of the 2009 Plan effective
March 20, 2009, we ceased making additional grants under the Option Plan.
The following is a summary of the changes in the options outstanding (all of which are vested) under the Option Plan for
the periods indicated (in thousands, except per unit amounts):
Weighted-
Average
Strike Price
($/LP Unit)
Weighted-
Average
Remaining
Contractual
Term (in years)
Aggregate
Intrinsic
Value (1)
Number of
LP Units
Outstanding at January 1, 2014............................................
Exercised ...........................................................................
Forfeited, cancelled or expired ..........................................
Outstanding at December 31, 2014......................................
Exercised ...........................................................................
Forfeited, cancelled or expired ..........................................
Outstanding at December 31, 2015......................................
Exercisable at December 31, 2015.......................................
$
46
(18)
(2) $
26
(5)
(4)
17
17
$
$
$
47.32
46.62
42.10
48.18
47.38
46.65
48.71
48.71
2.4
$
1,080
1.6
$
703
0.9
0.9
$
$
300
300
____________________________
(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 2015 and the exercise price,
multiplied by the number of exercisable, in-the-money options.
106
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The total intrinsic value of options exercised during the years ended December 31, 2015, 2014 and 2013 was $0.1 million,
$0.5 million and $0.6 million, respectively. At December 31, 2015 and 2014, there was no unrecognized compensation cost
related to unvested options, as all options were vested as of November 24, 2011. At December 31, 2015, 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, 2015, 2014 and 2013, 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 0.7 million of our LP Units (0.5% of our LP Units outstanding) as of
December 31, 2015. 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 $3.2 million,
$3.2 million and $3.7 million for the years ended December 31, 2015, 2014 and 2013, 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.
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.
Class B Units
From January 2011 to September 2013, we had issued and outstanding Class B Units representing a separate class of our
limited partnership interests. The Class B Units shared equally with the LP Units: (i) with respect to the payment of
distributions and (ii) in the event of our liquidation. Our partnership agreement provided the option to pay distributions on the
Class B Units with cash or by issuing additional Class B Units, with the number of Class B Units issued based upon the
volume-weighted average price of the LP Units for the 10 trading days immediately preceding the date the distributions were
declared, less a discount of 15%. From January 2011 to September 2013, we paid distributions on the Class B Units by issuing
such additional Class B Units.
In September 2013, 8.5 million Class B Units, which represented all of our Class B Units outstanding as of September 1,
2013, converted into LP Units on a one-for-one basis. The conversion was required by our partnership agreement and was
triggered in connection with over 4 million barrels of incremental storage capacity being placed in service since acquisition at
our BORCO facility effective September 1, 2013. No Class B Units have been issued subsequent to that date, and as a result,
there were no Class B Units outstanding at December 31, 2015.
107
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
At-the-Market Offering Program
In May 2013, we entered into four separate equity distribution agreements (each an “Equity Distribution Agreement” and
collectively the “Equity Distribution Agreements”) with each of Wells Fargo Securities, LLC, Barclays Capital Inc., SunTrust
Robinson Humphrey, Inc. and UBS Securities LLC. Under the terms of the Equity Distribution Agreements, we may offer and
sell up to $300 million in aggregate gross sales proceeds of LP Units from time to time through such firms, acting as agents of
the Partnership or as principals, subject in each case to the terms and conditions set forth in the applicable Equity Distribution
Agreement. Sales of LP Units, if any, may be made by means of ordinary brokers’ transactions on the New York Stock
Exchange or otherwise at market prices prevailing at the time of sale, at prices related to prevailing market prices or at
negotiated prices or as otherwise agreed with any of such firms. During the years ended December 31, 2015, 2014 and 2013,
we sold 2.2 million, 1.0 million and 0.5 million LP Units in aggregate under the Equity Distribution Agreements, received
$161.5 million, $74.5 million and $33.1 million in net proceeds after deducting commissions and other related expenses, and
paid $1.6 million, $0.8 million and $0.4 million of compensation in aggregate to the agents under the Equity Distribution
Agreements, respectively.
Equity Offerings
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 underwriting fees and
estimated 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, through which the underwriters also exercised an option to purchase 0.4 million additional LP Units. The offering
priced at $76.60 per unit, resulting in total gross proceeds of $229.0 million before deducting underwriting fees and estimated
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.
In October 2013, we completed a public offering of 7.5 million LP Units pursuant to an effective shelf registration
statement, which priced at $62.61 per unit. The underwriters also exercised an option to purchase 1.1 million additional LP
Units, resulting in total gross proceeds of $540.0 million before deducting underwriting fees and offering expenses of
$19.3 million. We used the net proceeds from this offering to reduce the indebtedness outstanding under our Credit Facility and
to indirectly fund a portion of the purchase price for the Hess Terminals Acquisition.
In January 2013, we completed a public offering of 6.0 million LP Units pursuant to an effective shelf registration
statement, which priced at $52.54 per unit. The underwriters also exercised an option to purchase 0.9 million additional LP
Units, resulting in total gross proceeds of $362.5 million before deducting underwriting fees and offering expenses of
$13.3 million. We used the net proceeds from this offering to reduce the indebtedness outstanding under our Credit Facility.
108
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):
Limited
Partners
Class B
Units
Total
Units outstanding at January 1, 2013 ..............................................................
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.............................
Issuance of Class B Units in lieu of quarterly cash distribution......................
Conversion of Class B Units into LP Units.....................................................
Units outstanding at December 31, 2013 ......................................................
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 ......................................................
____________________________
(1) The number of units issued represents issuance net of tax withholding.
90,371
27
182
15,526
489
—
8,469
115,064
18
198
10,752
1,011
127,043
5
229
2,247
129,524
7,975
98,346
—
—
—
—
494
(8,469)
—
—
—
—
—
—
—
—
—
—
27
182
15,526
489
494
—
115,064
18
198
10,752
1,011
127,043
5
229
2,247
129,524
109
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):
Record Date
Payment Date
February 19, 2013.................. February 28, 2013
May 16, 2013......................... May 31, 2013
August 12, 2013..................... August 20, 2013
November 12, 2013 ............... November 19, 2013
Total.....................................
February 18, 2014.................. February 25, 2014
May 12, 2014......................... May 19, 2014
August 18, 2014..................... August 25, 2014
November 18, 2014 ............... November 25, 2014
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
Total.....................................
In-kind Distributions
$
$
$
Amount Per
LP Unit
Total Cash
Distributions
$
1.0375
1.0500
1.0625
1.0750
$
$
$
$
$
1.0875
1.1000
1.1125
1.1250
1.1375
1.1500
1.1625
1.1750
101,475
102,689
104,293
124,051
432,508
125,806
128,042
133,142
143,386
530,376
145,382
147,085
149,490
152,175
594,132
In-kind distributions paid to Class B unitholders of Buckeye for the periods indicated were as follows (in thousands):
Record Date
February 19, 2013................................... February 28, 2013
May 16, 2013 .......................................... May 31, 2013
August 12, 2013...................................... August 20, 2013
Payment Date
Total......................................................
Units
186
163
145
494
On February 12, 2016, we announced a quarterly distribution of $1.1875 per LP Unit that will be paid on March 1, 2016, to
unitholders of record on February 23, 2016. Based on the LP Units outstanding as of December 31, 2015, cash distributed to
LP unitholders on March 1, 2016 will total $154.4 million.
110
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
23. INCOME TAXES
As of December 31, 2015 and 2014, we had net deferred tax assets of $1.2 million and $1.3 million, respectively, for BDL.
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, 2014, 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 and 2014, we had net deferred tax assets of $42.3 million and $43.4 million related to Buckeye
Caribbean. As of December 31, 2015, $18.2 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, 2015 and 2014, 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 $1.3 million and $1.8 million of these deferred tax assets, respectively, at December 31,
2015 and 2014.
The tax effects of significant items comprising our net deferred tax assets and liabilities at December 31, 2015 and 2014 are
as follows (in thousands):
Deferred tax asset:
December 31,
2015
2014
Net operating loss carryforward ............................................................................................... $
Property, plant and equipment - refinery..................................................................................
Other .........................................................................................................................................
Total deferred tax asset................................................................................................................ $
18,236
23,447
3,016
44,699
Deferred tax liability:
Property, plant and equipment - terminals................................................................................ $
Other .........................................................................................................................................
Total deferred tax liability...........................................................................................................
Net deferred tax asset ..................................................................................................................
Less: Valuation allowance........................................................................................................
Deferred taxes, net ...................................................................................................................... $
1,189
—
1,189
43,510
(41,056)
2,454
$
$
$
$
21,652
22,333
2,879
46,864
2,124
55
2,179
44,685
(42,893)
1,792
We are currently not under any income tax audits or examinations. As of December 31, 2015, BDL’s tax years from 2012
to 2015 and Buckeye Caribbean’s tax years from 2009 through 2015 were open to examination by the Internal Revenue Service
and Puerto Rico Treasury Department, respectively.
111
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
24. EARNINGS PER UNIT
Basic and diluted earnings per unit (includes LP Units and Class B Units in 2013) is calculated by dividing net income,
after deducting the amount allocated to noncontrolling interests, by the weighted-average number of LP Units and Class B
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,
2015
2014
2013
Net income attributable to Buckeye Partners, L.P........................................... $
Basic:
437,223
$
272,954
$
160,273
Weighted average units outstanding - basic .............................................
Earnings per unit - basic .................................................................................. $
128,084
3.41
$
119,323
2.29
$
107,202
1.50
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 ............................................................................... $
128,084
533
128,617
3.40
$
119,323
576
119,899
2.28
$
107,202
475
107,677
1.49
25. BUSINESS SEGMENTS
We operate and report in three business segments: (i) Domestic Pipelines & Terminals (formerly known as Pipelines &
Terminals); (ii) Global Marine Terminals; and (iii) Merchant Services. In December 2015, we realigned our reportable
segments as a result of changes in our organizational structure. We merged our previously reported Development & Logistics
segment into the Domestic Pipelines & Terminals segment. We have adjusted our prior period segment information to conform
to the current year presentation.
Domestic Pipelines & Terminals
The Domestic Pipelines & Terminals segment receives liquid petroleum products from refineries, connecting pipelines,
vessels, and bulk and marine terminals and 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 five 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 and the New York Harbor and Corpus Christi, Texas in the United States.
112
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, approximately 6.0 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. See Note 3 for further discussion.
Merchant Services
The Merchant Services segment is a wholesale distributor of 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 five
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, 2015, 2014 and 2013. See Note 4 and Note 5 for further information.
Adjusted EBITDA
Adjusted EBITDA is the primary measure used by our senior management, including our Chief Executive Officer, 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. Adjusted EBITDA eliminates: (i) non-cash expenses, including but not limited to
depreciation and amortization expense resulting from the significant capital investments we make in our businesses and from
intangible assets recognized in business combinations; (ii) charges for obligations expected to be settled with the issuance of
equity instruments; and (iii) items that are not indicative of our core operating performance results and business outlook.
We believe that investors benefit from having access to the same financial measures that we use and that these measures
are useful to investors because they aid in comparing our operating performance with that of other companies with similar
operations. The Adjusted EBITDA data presented by us may not be comparable to similarly titled measures at other companies
because these items may be defined differently by other companies.
The following tables summarize our financial information by each segment for the periods indicated (in thousands):
Year Ended December 31,
2015
2014
2013
Revenue:
Domestic Pipelines & Terminals................................................................... $
Global Marine Terminals ..............................................................................
Merchant Services.........................................................................................
Intersegment..................................................................................................
Total revenue............................................................................................ $
966,749
514,301
2,037,664
(65,280)
3,453,434
$
$
938,036
395,306
5,358,626
(71,721)
6,620,247
$
$
844,832
252,270
3,990,575
(33,576)
5,054,101
For the years ended December 31, 2015, 2014 and 2013, no customer contributed 10% or more of consolidated revenue.
113
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Year Ended December 31,
2015
2014
2013
Capital additions, net: (1)
Domestic Pipelines & Terminals................................................................... $
Global Marine Terminals ..............................................................................
Merchant Services.........................................................................................
Total segment capital additions, net .........................................................
Natural Gas Storage disposal group (2) ........................................................
Total capital additions, net........................................................................ $
218,283
375,267
970
594,520
—
594,520
$
$
221,850
248,905
614
471,369
780
472,149
$
$
154,667
206,472
113
361,252
193
361,445
____________________________
(1) Amounts represent cash paid for capital expenditures and exclude $27.5 million, $(49.8) million and $23.3 million of non-
cash changes in accounts payable and accruals for capital expenditures for the years ended December 31, 2015, 2014 and
2013, respectively. See Note 26 for supplemental cash flow information.
(2) Assets related to the Natural Gas Storage disposal group were classified as “Assets held for sale” as of the year ended
December 31, 2013. In December 2014, we sold our Natural Gas Storage segment and its related assets. See Note 4 for
further information.
December 31,
2015
2014
Total Assets:
Domestic Pipelines & Terminals (1)......................................................................................... $
Global Marine Terminals (2) ....................................................................................................
Merchant Services ....................................................................................................................
Total assets........................................................................................................................... $
3,498,883
4,500,705
369,693
8,369,281
$
$
3,357,410
4,239,792
468,518
8,065,720
____________________________
(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
$1,506.2 million and $1,520.8 million for the years ended December 31, 2015 and 2014, respectively.
The following tables summarize our financial information for continuing operations, by major geographic area, for the
periods indicated (in thousands):
Year Ended December 31,
2015
2014
2013
Revenue:
United States ................................................................................................. $
International ..................................................................................................
Total revenue............................................................................................ $
3,115,450
337,984
3,453,434
$
$
6,279,142
341,105
6,620,247
$
$
4,834,991
219,110
5,054,101
114
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following tables present Adjusted EBITDA 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,
2015
2014
2013
Adjusted EBITDA from continuing operations:
Domestic Pipelines & Terminals................................................................... $
Global Marine Terminals ..............................................................................
Merchant Services.........................................................................................
Adjusted EBITDA from continuing operations ....................................... $
522,196
323,840
22,026
868,062
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).......................................................
Less: Amortization of unfavorable storage contracts (4) ..............................
Adjusted EBITDA from continuing operations ....................................... $
438,391
(311)
438,080
171,330
874
221,278
29,215
3,127
15,229
(11,071)
868,062
$
$
$
$
532,071
239,556
(8,059)
763,568
$
$
486,458
149,740
12,616
648,814
334,498
(1,903)
332,595
171,235
451
196,443
20,867
13,048
40,000
(11,071)
763,568
$
$
351,599
(4,152)
347,447
130,920
1,060
147,591
21,013
11,806
—
(11,023)
648,814
____________________________
(1) Includes 100% of the depreciation and amortization expense of $49.3 million and $12.3 million for Buckeye Texas for the
years ended December 31, 2015 and 2014, respectively.
(2) Acquisition and transition expense consists of transaction costs, costs for transitional employees, and other employee and
third-party costs related to the integration of the acquired assets that are non-recurring in nature.
(3) Represents reductions in revenue related to settlement of a FERC proceeding. See Note 6 for further discussion.
(4) Represents the amortization of the negative fair values allocated to certain unfavorable storage contracts acquired in
connection with the BORCO acquisition.
26. SUPPLEMENTAL CASH FLOW INFORMATION
Supplemental cash flows and non-cash transactions were as follows for the periods indicated (in thousands):
Year Ended December 31,
2015
2014
2013
Cash paid for interest (net of capitalized interest) .......................................... $
Cash paid for income taxes .............................................................................
Capitalized interest..........................................................................................
$
156,654
1,705
21,257
$
152,201
663
9,903
115,006
510
7,007
Non-cash financing activities:
Issuance of Class B Units in lieu of quarterly cash distribution...................
—
—
25,687
We recorded liabilities related to capital expenditures of $87.9 million, $60.4 million, and $110.2 million at December 31,
2015, 2014, and 2013, respectively. Such amounts are not included under “Capital expenditures” on the consolidated statement
of cash flows.
115
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.
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.............................................. $
2014
Revenue (1)............................................ $
Operating income (1) .............................
Income from continuing operations (1) .
Loss from discontinued operations (2) ..
Net income (1) (2)..................................
Net income attributable to Buckeye
Partners, L.P. (1) (2)...............................
Earnings (loss) per unit - basic
Continuing operations ....................... $
Discontinued operations....................
Total.............................................. $
Earnings (loss) per unit - diluted
Continuing operations ....................... $
Discontinued operations....................
Total.............................................. $
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
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
1,991,829
$
1,808,951
$
1,573,473
$
1,245,994
$
6,620,247
141,273
101,539
(10,042)
91,497
102,166
61,939
(38,186)
23,753
148,941
107,008
(3,280)
103,728
102,967
64,012
(8,133)
55,879
495,347
334,498
(59,641)
274,857
90,468
23,020
102,943
56,523
272,954
0.87
(0.09)
0.78
0.87
(0.09)
0.78
$
$
$
$
0.53
(0.33)
0.20
0.53
(0.33)
0.20
$
$
$
$
0.90
(0.03)
0.87
0.89
(0.03)
0.86
$
$
$
$
0.51
(0.06)
0.45
0.50
(0.06)
0.44
$
$
$
$
2.79
(0.50)
2.29
2.78
(0.50)
2.28
____________________________
(1) During the fourth quarter of 2014, second quarter of 2015 and third quarter of 2015, we recorded reductions in revenue of
$40.0 million, $13.5 million and $1.7 million, respectively, related to settlement of a FERC proceeding (see Note 6).
116
BUCKEYE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(2) During the second quarter of 2014, we recorded a $26.3 million asset impairment charge related to the Natural Gas Storage
disposal group. During the third quarter of 2014, we reduced the asset impairment charge by $5.4 million due to changes
in the carrying value of the net assets of the Natural Gas Storage disposal group. In December 2014, we recorded an
additional $2.5 million asset impairment charge due to the completion of the sale. We reported the final working capital
adjustments as discontinued operations in the first quarter of 2015 (see Note 4).
117
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 2015, that have materially affected, or are
reasonably likely to materially affect, our internal controls over financial reporting.
Item 9B. Other Information
None.
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 2016
Annual Meeting of unitholders (the “2016 Proxy Statement”), which will be filed with the SEC within 120 days after the end of
the fiscal year ended December 31, 2015, 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 2016 Proxy Statement, which will be filed with the SEC
within 120 days after the end of the fiscal year ended December 31, 2015, 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.
118
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 2016 Proxy Statement, which will be filed with the SEC
within 120 days after the end of the fiscal year ended December 31, 2015, 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 2016 Proxy Statement, which will be filed with the SEC
within 120 days after the end of the fiscal year ended December 31, 2015, 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 2016 Proxy Statement, which will be filed with the SEC
within 120 days after the end of the fiscal year ended December 31, 2015, 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.
119
Exhibit
Number
Description
2.1
2.2
3.1
3.2
3.3
3.4
3.5
3.6
3.7
3.8
3.9
4.1
4.2
Purchase and Sale Agreement, dated July 25, 2014, between Buckeye Gas Storage LLC and BIF II CalGas
(Delaware) LLC (Incorporated by reference to Exhibit 2.1 to Buckeye Partners, L.P.’s Current Report on
Form 8-K filed on July 29, 2014).
Contribution Agreement, dated as of September 2, 2014, by and between Trafigura Corpus Christi Holdings
Inc. 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 September 2, 2014).
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).
First Supplemental Indenture dated as of July 10, 2003, between Buckeye Partners, L.P. and SunTrust Bank,
as Trustee (Incorporated by reference to Exhibit 4.2 of Buckeye Partners, L.P.’s Registration Statement on
Form S-4 filed September 19, 2003).
120
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
4.11
10.1
10.2
10.3
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).
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).
Buckeye Partners, L.P. Unit Deferral and Incentive Plan, as amended and restated effective February 4,
2015 (Incorporated by reference to Exhibit 10.1 of Buckeye Partners, L.P.'s Annual Report on Form 10-K
for the year ended December 31, 2014).
Second Amended and Restated Agreement of Limited Partnership of Buckeye GP Holdings L.P., dated as of
November 19, 2010 (Incorporated by reference to Exhibit 10.1 of Buckeye Partners, L.P.’s Current Report
on Form 8-K filed on November 22, 2010).
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).
*10.4
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).
121
*10.5
*10.6
*10.7
*10.8
*10.9
*10.10
10.11
10.12
10.13
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).
Buckeye Partners, L.P. 2013 Long-Term Incentive Plan (Incorporated by reference to Exhibit A of Buckeye
Partners, L.P.’s Definitive Proxy Statement filed April 19, 2013).
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).
Form of Equity Distribution Agreement, dated May 21, 2013, among Buckeye Partners, L.P., Buckeye GP
LLC and each of Wells Fargo Securities, LLC, Barclays Capital Inc., SunTrust Robinson Humphrey, Inc.
and UBS Securities LLC (Incorporated by reference to Exhibit 1.1 to Buckeye Partners, L.P.’s Current
Report on Form 8-K filed on May 21, 2013).
Form of Amendment No. 1 to Equity Distribution Agreement, dated March 2, 2015, among Buckeye
Partners, L.P., Buckeye GP LLC and each of Wells Fargo Securities, LLC, Barclays Capital Inc., SunTrust
Robinson Humphrey, Inc. and UBS Securities LLC (Incorporated by reference to Exhibit 1.2 to Buckeye
Partners, L.P.’s Current Report on Form 8-K filed on March 3, 2015).
* **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.
122
**23.1
Consent of Deloitte & Touche LLP.
**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.
123
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 25, 2016
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.
124
Dated: February 25, 2016
By:
/s/
Dated: February 25, 2016
By:
/s/
Dated: February 25, 2016
By:
/s/
Dated: February 25, 2016
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 25, 2016
By:
/s/ MARK C. MCKINLEY
Mark C. McKinley
Director
Dated: February 25, 2016
By:
/s/
Dated: February 25, 2016
By:
/s/
Dated: February 25, 2016
By:
/s/
Dated: February 25, 2016
By:
/s/
Dated: February 25, 2016
By:
/s/
DONALD W. NIEMIEC
Donald W. Niemiec
Director
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
125
Dated: February 25, 2016
By:
/s/
KEITH E. ST.CLAIR
Keith E. St.Clair
Executive Vice President and Chief Financial
Officer
(Principal Financial Officer)
Dated: February 25, 2016
By:
/s/ MARTIN A. WHITE
Martin A. White
Director
Dated: February 25, 2016
By:
/s/
PATRICK L. PELTON
Patrick L. Pelton
Vice President and Controller
(Principal Accounting Officer)
126
PRINCIPAL EXECUTIVE OFFICE
Buckeye Partners, L.P.
One Greenway Plaza, Suite 600
Houston, TX 77046
832-615-8600
TRANSFER AGENT AND REGISTRAR
American Stock Transfer & Trust Company, LLC
6201 15th Avenue
Brooklyn, NY 11219
877-724-6457
www.amstock.com
UNITHOLDER TAX INFORMATION
PricewaterhouseCoopers, LLP
K-1 Support
P.O. Box 799060
Dallas, TX 75379
800-230-7224
INVESTOR INFORMATION
For more information about
Buckeye Partners, L.P. please contact:
Investor Relations
800-422-2825
irelations@buckeye.com
or visit the Investor Center pages at our website:
www.buckeye.com
INFORMATION
AUDIT COMMITTEE:
Barbara J. Duganier (Chair)
Barbara M. Baumann
Donald W. Niemiec
Larry C. Payne
Frank S. Sowinski
COMPENSATION COMMITTEE:
Oliver G. “Rick” Richard, III (Chair)
Barbara M. Baumann
Barbara J. Duganier
Joseph A. LaSala, Jr.
Mark C. McKinley
NOMINATING & CORPORATE GOVERNANCE
COMMITTEE:
Frank S. Sowinski (Chair)
Pieter Bakker
Joseph A. LaSala, Jr.
Oliver G. “Rick” Richard, III
Martin A. White
HEALTH, SAFETY, SECURITY &
ENVIRONMENTAL COMMITTEE:
Martin A. White (Chair)
Pieter Bakker
Mark C. McKinley
Donald W. Niemiec
Larry C. Payne
EQUAL OPPORTUNITY
Buckeye Partners, L.P. provides equal opportunity
in all aspects of employment without regard
to race, color, creed, religion, ancestry, national
origin, gender, age, disability, veteran, or
marital status.
BOARD OF DIRECTORS & SENIOR EXECUTIVES
BOARD OF DIRECTORS
SENIOR EXECUTIVES
Front row: Frank S. Sowinski, Clark C. Smith, Pieter Bakker, Donald W. Niemiec
Second row: Joseph A. LaSala, Jr., Barbara J. Duganier, Martin A. White, Larry C. Payne,
Barbara M. Baumann, Mark C. McKinley, Oliver G. “Rick” Richard, III
Front row: Todd J. Russo, Clark C. Smith, Khalid A. Muslih
Second row: Robert A. Malecky, William J. Hollis, Joseph M. Sauger, Mark S. Esselman,
Keith E. St.Clair
Clark C. Smith
Chairman, President and Chief Executive Officer
Clark C. Smith
Chairman, President and Chief Executive Officer
Keith E. St.Clair
Executive Vice President and Chief Financial Officer
Mark S. Esselman
Senior Vice President of Global Human Resources
William J. Hollis
Senior Vice President and President of Buckeye Services
Robert A. Malecky
Senior Vice President and President of Domestic Pipelines &
Terminals
Khalid A. Muslih
Senior Vice President and President of Global Marine Terminals
Patrick L. Pelton
Vice President, Controller and Principal Accounting Officer
Todd J. Russo
Senior Vice President, General Counsel and Secretary
Joseph M. Sauger
Senior Vice President, Engineering and Compliance Services
Frank S. Sowinski
Lead Independent Director
Management Affiliate of MidOcean Partners
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
Donald W. Niemiec
President of WR Energy, LLC and former Vice
President of Union Pacific Resources Group, Inc.
Larry C. Payne
President and Chief Executive Officer
of LESA & Associates, LLC
Oliver G. “Rick” Richard, III
Chairman of Cleanfuel USA, President of Empire of
the Seed LLC, and former Chairman, President and
Chief Executive Officer of Columbia Energy Group
Martin A. White
Former President and Chief Executive Officer of
MDU Resources Group, Inc.
One Greenway Plaza
Suite 600
Houston, TX 77046
www.buckeye.com