Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


 

FORM 10-K

 


 

(Mark One)

 

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

 

For the fiscal year ended December 31, 2013

 

OR

 

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

 

For the transition period from                             to                            

 

Commission file number 1-9356

 


 

Buckeye Partners, L.P.

(Exact name of registrant as specified in its charter)

 


 

Delaware

 

23-2432497

(State or other jurisdiction of

 

(IRS Employer

incorporation or organization)

 

Identification number)

 

One Greenway Plaza

 

 

Suite 600

 

 

Houston, TX

 

77046

(Address of principal executive offices)

 

(Zip Code)

 

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

 

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

 

Title of each class

 

Name of each exchange on
which registered

Limited partner units representing limited partnership interests

 

New York Stock Exchange

 

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

 

None

 

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

 

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

 

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 x  No o

 

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

 

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

 

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

 

Large accelerated filer

x

 

Accelerated filer

o

Non-accelerated filer

o

 

Smaller reporting company

o

(Do not check if a smaller reporting company)

 

 

 

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

 

At June 30, 2013, the aggregate market value of the registrant’s limited partner units and Class B units held by non-affiliates was $7.4 billion. The calculation of such market value should not be construed as an admission or conclusion by the registrant that any person is in fact an affiliate of the registrant.

 

As of February 18, 2014, there were 115,222,148 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 2014 Annual Meeting of Limited Partners are incorporated by reference in Part III of this Form 10-K.

 

 

 



Table of Contents

 

TABLE OF CONTENTS

 

 

 

Page

 

 

 

PART I

Item 1.

Business

1

Item 1A.

Risk Factors

18

Item 1B.

Unresolved Staff Comments

33

Item 2.

Properties

33

Item 3.

Legal Proceedings

34

Item 4.

Mine Safety Disclosures

36

 

 

 

PART II

Item 5.

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

37

Item 6.

Selected Financial Data

39

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

40

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

58

Item 8.

Financial Statements and Supplementary Data

62

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

127

Item 9A.

Controls and Procedures

127

Item 9B.

Other Information

127

 

 

 

PART III

Item 10.

Directors, Executive Officers and Corporate Governance

128

Item 11.

Executive Compensation

128

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

128

Item 13.

Certain Relationships and Related Transactions and Director Independence

128

Item 14.

Principal Accounting Fees and Services

128

 

 

 

PART IV

Item 15.

Exhibits, Financial Statement Schedules

129

 



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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, adverse weather conditions, including hurricanes, environmental releases and natural disasters, (iii) changes in the marketplace for our products or services, such as increased competition, 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, terminal, and storage 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 refined petroleum products and the value of natural gas storage services, (viii) nonpayment or nonperformance by our customers, (ix) our ability to integrate acquired assets with our existing assets and to realize anticipated cost savings and other efficiencies and benefits, (x) our ability to successfully complete our organic growth projects and to realize the anticipated financial benefits, and (xi) an unfavorable outcome with respect to the proceedings pending before the Federal Energy Regulatory Commission (“FERC”) regarding Buckeye Pipe Line Company, L.P.’s transportation of jet fuel to the New York City airports.  These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements.  Other known or unpredictable factors could also have material adverse effects on future results.  Consequently, all of the forward-looking statements made in this document are qualified by these cautionary statements, and we cannot assure you that actual results or developments that we anticipate will be realized or, even if substantially realized, will have the expected consequences to or effect on us or our business or operations.  Also note that we provide additional cautionary discussion of risks and uncertainties under the captions “Risk Factors” and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Report.

 

The forward-looking statements contained in this Report speak only as of the date hereof.  Although the expectations in the forward-looking statements are based on our current beliefs and expectations, caution should be taken not to place undue reliance on any such forward-looking statements because such statements speak only as of the date hereof.  Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason.  All forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this Report and in our future periodic reports filed with the U.S. Securities and Exchange Commission (“SEC”).  In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this Report may not occur.

 



Table of Contents

 

PART I

 

Item 1.                     Business

 

Introduction

 

The original Buckeye Pipe Line Company was founded in 1886 as part of the Standard Oil Company 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 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 and is a wholly owned subsidiary of Buckeye GP Holdings L.P. (“BGH”), a Delaware limited partnership that was previously publicly traded on the NYSE prior to Buckeye’s merger with BGH (see Item 6 of this Report for further information).  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 one of the largest independent liquid petroleum products pipeline systems in the United States in terms of volumes delivered, with approximately 6,000 miles of pipeline.  Buckeye also owns more than 120 liquid petroleum products terminals with aggregate storage capacity of over 110 million barrels.  In addition, we operate and/or maintain third-party pipelines under agreements with major oil and gas, petrochemical and chemical companies, and perform certain engineering and construction management services for third parties.  We also are a wholesale distributor of refined petroleum products in the United States in areas also served by our pipelines and terminals.  Beginning in late 2012, we began to provide fuel oil supply and distribution services to third parties in the Caribbean.  Our flagship marine terminal in The Bahamas, Bahamas Oil Refining Company International Limited (“BORCO”), is one of the largest marine crude oil and petroleum products storage facilities in the world, serving the international markets as a global logistics hub.

 

In December 2013, our Board of Directors approved a plan to divest the natural gas storage facility and related assets that our operating subsidiary, Lodi Gas Storage, L.L.C. (“Lodi Gas”), owns and operates in Northern California as we no longer believe this business is aligned with our long-term business strategy.  In this report, we refer to this group of assets as our Natural Gas Storage disposal group.  Accordingly, we have classified the disposal group as “Assets held for sale” and “Liabilities held for sale” in our consolidated balance sheet as of December 31, 2013 and reported the results of operations as discontinued operations for all periods presented in this report.  For additional information, see Note 4 in the Notes to Consolidated Financial Statements.

 

Business Strategy

 

Our primary business objective is to provide stable and sustainable cash distributions to our LP 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.

 

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;

 

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·                  Pursuing strategic cash flow-accretive acquisitions that:

·                  Complement our existing footprint;

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

·                  Leverage existing management capabilities and infrastructure;

·                  Pursuing other energy-related assets that enable us to leverage our asset base, knowledge base and skill sets; and

·                  Providing superior customer service.

 

Recent Developments

 

2013 Transactions

 

Acquisitions

 

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.  The terminal on St. Lucia in the Caribbean has approximately 10 million barrels of crude oil and refined petroleum products storage capacity and has deep-water accessThis acquisition increases Buckeye’s total liquid petroleum storage capacity by approximately 53 percent to over 110 million barrels.  Concurrent with this acquisition, we entered into multi-year storage and throughput commitments with Hess.

 

In April 2013, our operating subsidiary, Buckeye Pipe Line Holdings, L.P. (“BPH”), purchased an additional 10% ownership interest in WesPac Pipelines — Memphis LLC (“WesPac Memphis”) from Kealine LLC for $9.7 million and, as a result of the acquisition, our ownership interest in WesPac Memphis increased from 70% to 80%.  Since BPH retains controlling interest in WesPac Memphis, this acquisition was accounted for as an equity transaction.

 

Notes Offerings

 

In November 2013, we issued an aggregate of $800 million of senior unsecured notes in an underwritten public offering, including $400 million of 2.650% Notes due November 15, 2018 (the “2.650% Notes”) and $400 million of 5.850% Notes due November 15, 2043 (the “5.850% Notes”), at 99.823% and 98.581%, respectively, of their principal amounts.  Total proceeds from this offering, after underwriting fees, expenses and debt issuance costs of $5.9 million, were $787.7 million.  We used the net proceeds from this offering to fund a portion of the Hess Terminals Acquisition and for general partnership purposes.

 

In June 2013, we issued $500 million of senior unsecured 4.150% Notes due July 1, 2023 (the “4.150% Notes”) in an underwritten public offering at 99.81% of their principal amount.  Total proceeds from this offering, after underwriting fees, expenses and debt issuance costs of $3.3 million, were $495.8 million.  We used the net proceeds from this offering for general partnership purposes and to repay amounts due under our $1.25 billion revolving credit facility dated September 26, 2011 (the “Credit Facility”) with SunTrust Bank, a portion of which was subsequently reborrowed in July 2013 in order to repay in full the $300 million principal amount outstanding under the 4.625% Notes due on July 15, 2013 (the “4.625% Notes) and $6.9 million of related accrued interest.  We also settled all interest rate swaps relating to the 4.150% Notes for $62 million during June 2013.

 

Equity Offerings

 

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 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.

 

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In January 2013, we completed a public offering of 6 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.

 

Conversion of Class B Units

 

In September 2013, 8.5 million Class B Units representing limited partner interests in Buckeye, 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, 2013.

 

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 year ended December 31, 2013, we sold 0.5 million LP Units in aggregate under the Equity Distribution Agreements, received $33.1 million in net proceeds after deducting commissions and other related expenses, and paid $0.4 million of compensation in aggregate to the agents under the Equity Distribution Agreements.

 

Business Activities

 

The following discussion describes the business activities of our business segments, which include Pipelines & Terminals, Global Marine Terminals, Merchant Services, Development & Logistics and the discontinuation of the Natural Gas Storage segment.  In December 2013, we realigned our business segments to support the way our management views our business in light of recent growth through acquisitions.  We eliminated our previously reported International Operations and Energy Services segments and created the Global Marine Terminals and Merchant Services segments.  The new Global Marine Terminals segment includes our marine facilities that primarily facilitate global logistic product flows and feature segregated tankage, serve a similar international customer base and offer similar services, such as bulk storage and blending.  This segment includes our BORCO facility and Yabucoa terminal, the St. Lucia terminal acquired from Hess, and the New York Harbor storage and marine terminals, which consist of our legacy Perth Amboy terminal and the Port Reading and Raritan Bay terminals acquired from Hess.  Our Merchant Services segment centralizes all existing and new merchant activities to leverage common mid- and back-office support.  This segment includes the legacy Energy Services segment, the Caribbean fuel oil supply and distribution business and new merchant activities supporting the terminals recently acquired from Hess.  Our Development & Logistics segment remains unchanged.  Our Pipelines & Terminals segment remains unchanged, other than the removal of the Perth Amboy terminal.  Finally, we also eliminated the Natural Gas Storage segment because it has been classified as a discontinued operation.  We have adjusted our prior period segment information to conform to the current alignment of our continuing business and discontinued operations.

 

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The Pipelines & Terminals segment and the Merchant Services segment derive a nominal amount of their revenue from U.S. governmental agencies.  Otherwise, none of our business segments have contracts or subcontracts with the U.S. government.  All of our continuing 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 sells fuel oil to third parties at various locations in the Caribbean.  Detailed financial information regarding revenue and total assets of each segment and major geographic area can be found in Note 26 in the Notes to Consolidated Financial Statements.  The following table shows our consolidated revenue and each segment’s revenue and percentage of consolidated revenue for the periods indicated (revenue in thousands):

 

 

 

Year Ended December 31,

 

 

 

2013

 

2012

 

2011

 

 

 

Revenue

 

Percent

 

Revenue

 

Percent

 

Revenue

 

Percent

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pipelines & Terminals

 

$

786,759

 

15.6

%

$

709,341

 

16.6

%

$

631,289

 

13.4

%

Global Marine Terminals

 

252,270

 

5.0

%

218,180

 

5.1

%

193,960

 

4.1

%

Merchant Services(1)

 

3,990,575

 

79.0

%

3,339,241

 

77.9

%

3,888,961

 

82.9

%

Development & Logistics

 

59,247

 

1.2

%

50,211

 

1.2

%

43,068

 

0.9

%

Intersegment

 

(34,750

)

(0.8

)%

(31,070

)

(0.8

)%

(63,658

)

(1.3

)%

Total

 

$

5,054,101

 

100.0

%

$

4,285,903

 

100.0

%

$

4,693,620

 

100.0

%

 


(1)         Amounts for 2013 and 2012 include sales related to the fuel oil supply and distribution services in the Caribbean.

 

Pipelines & Terminals Segment

 

The 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 approximately 115 active terminals that provide bulk storage and throughput services with respect to liquid petroleum products and renewable fuels, including ethanol, and have an aggregate storage capacity of over 55 million barrels.  In addition, three of our terminals provide crude oil services, including train off-loading, storage and throughput.  Of our terminals in the Pipelines & Terminals segment, over half are connected to our pipelines.  We generally own the property on which the terminals are located with the exception of our terminal located in Albany, New York, which is primarily located on leased property.  The segment’s geographical diversity, connections to multiple sources of supply and extensive delivery system help create a stable base business.

 

Pipelines

 

The Pipelines & Terminals segment’s pipelines conduct business without the benefit of exclusive franchises from government entities.  In addition, the Pipelines & Terminals segment generally operates as a common carrier, providing transportation services at posted tariffs and without long-term contracts.  Demand for the services provided by the Pipelines & Terminals segment 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.  Demand for the services provided by the Pipelines & Terminals segment is, therefore, subject to a variety of factors 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.

 

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

 

 

 

Year Ended December 31,

 

 

 

2013

 

2012

 

2011

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pipelines:

 

 

 

 

 

 

 

 

 

 

 

 

 

Gasoline

 

717.8

 

50.3

%

701.9

 

50.6

%

668.1

 

49.2

%

Jet fuel

 

334.4

 

23.5

%

339.2

 

24.5

%

340.6

 

25.1

%

Middle distillates (1)

 

345.7

 

24.2

%

318.6

 

23.0

%

327.0

 

24.1

%

Other products (2)

 

28.5

 

2.0

%

25.9

 

1.9

%

22.4

 

1.6

%

Total pipelines throughput

 

1,426.4

 

100.0

%

1,385.6

 

100.0

%

1,358.1

 

100.0

%

 


(1)         Includes diesel fuel and heating oil.

(2)         Includes liquefied petroleum gas, 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 JerseyOur operating subsidiary Buckeye Pipe Line Company, L.P. (“Buckeye Pipe Line”) serves major population centers in Pennsylvania, New York and New Jersey through approximately 925 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 oil 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 500 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, while another segment delivers products to central Pennsylvania.  Two shorter pipeline segments connect the Paulsboro refinery to the Colonial pipeline system and the Philadelphia International Airport, via a connecting carrier, respectively.

 

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—OhioBuckeye Pipe Line, 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 2,100 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.

 

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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 PipelinesBuckeye Pipe Line 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 Transporation 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 WesPac Pipelines — Reno LLC (“WesPac Reno”) owns an approximately 3-mile pipeline serving the Reno/Tahoe International Airport.  Our operating subsidiary WesPac Pipelines — San Diego LLC (“WesPac San Diego”) owns an approximately 4-mile pipeline serving the San Diego International Airport.  WesPac Pipelines — Memphis LLC (“WesPac Memphis”) owns an approximately 16-mile pipeline and a related terminal facility that primarily serves Federal Express Corporation at the Memphis International Airport.  WesPac Reno, WesPac San Diego and WesPac Memphis, collectively, have terminal facilities with aggregate storage capacity of 0.5 million barrels.  Each of WesPac Reno, WesPac San Diego and WesPac Memphis was originally created as a joint venture between BPH and Kealine LLC (“Kealine”).  BPH currently owns 100% of WesPac Reno and WesPac San Diego.  In September 2012 and April 2013, BPH purchased additional 20% and 10% ownership interests, respectively, in WesPac Memphis from Kealine, increasing our ownership interest in WesPac Memphis from 50% to 80%.  Each of these entities has been consolidated into our financial statements.

 

Terminals

 

The 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 Pipelines & Terminals segment’s terminal facilities consist of multiple storage tanks and are equipped with automated truck loading equipment that is available 24 hours a day.

 

The 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 leasing 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.

 

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

 

 

 

Year Ended December 31,

 

 

 

2013

 

2012

 

2011

 

Products throughput (1)

 

975.1

 

916.7

 

756.0

 

 


(1)         Amounts for 2013, 2012 and 2011 include post-acquisition throughput volumes at terminals acquired from Hess, BP Products North America Inc. (“BP”) and ExxonMobil Corporation (“ExxonMobil”) on December 11, 2013, June 1, 2011 and July 19, 2011, respectively.  The table also includes throughput at the five terminals owned by the Merchant Services segment and operated by the Pipelines & Terminals segment (as discussed below).

 

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

 

 

 

Number of

 

Storage

 

Location 

 

Terminals (1)

 

Capacity

 

Alabama

 

2

 

605

 

California

 

3

 

530

 

Connecticut

 

2

 

1,212

 

Florida

 

4

 

1,951

 

Iowa

 

5

 

1,302

 

Illinois

 

8

 

2,977

 

Indiana

 

11

 

9,439

 

Kentucky

 

1

 

214

 

Louisiana

 

1

 

304

 

Maine

 

1

 

140

 

Maryland

 

1

 

3,232

 

Massachusetts

 

1

 

106

 

Michigan

 

13

 

5,370

 

Missouri

 

3

 

1,767

 

Nevada

 

1

 

50

 

New Jersey

 

4

 

6,161

 

New York

 

15

 

6,988

 

North Carolina

 

1

 

572

 

Ohio

 

14

 

4,003

 

Pennsylvania

 

11

 

2,536

 

South Carolina

 

4

 

2,191

 

Tennessee (2) 

 

1

 

328

 

Virginia

 

4

 

1,805

 

Wisconsin

 

4

 

1,228

 

 

 

115

 

55,011

 

 


(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 Pipelines & Terminals segment (as discussed below).

(2)         This represents the terminal facility owned by WesPac Memphis, which is 80% owned by BPH.

 

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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 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 terminal throughput services, marine bulk storage and other related services through six liquid petroleum product terminals located in The Bahamas, Puerto Rico and St. Lucia in the Caribbean and the New York Harbor in the continental United States.

 

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

 

 

 

Number of

 

Storage

 

Location

 

Terminals

 

Capacity

 

Bahamas

 

1

 

26,113

 

Puerto Rico

 

1

 

4,624

 

New York Harbor

 

3

 

15,653

 

St. Lucia

 

1

 

10,261

 

Total

 

6

 

56,651

 

 

BORCO Facility

 

BORCO owns a terminal 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 and ancillary services including, but not limited to, berthing, heating, transshipment, blending, treating and bunkering.  Ancillary services provided by BORCO facilitate customer activities within the tank farm and at the jetties.

 

BORCO’s terminal 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 terminal 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.  Certain of these jetties are capable of handling both very large crude carriers (“VLCCs”) and ultra large crude carriers (“ULCCs”).

 

We own the 500 acres of property on which the BORCO terminal 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.

 

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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 8-bay truck rack.

 

New York Harbor Terminals

 

The New York Harbor storage and marine terminals, which consist of our legacy Perth Amboy terminal and the Port Reading and Raritan Bay terminals acquired from Hess, 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.  The Perth Amboy terminal includes 51 storage tanks and a dock of maximum 850-foot vessel length and three operational berths, each with articulated loading arms, allowing both ship and barge berthing.  The Port Reading and Raritan Bay terminals acquired as part of the Hess Terminals Acquisition have approximately 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.  The Port Reading terminal is located on 211 acres in Port Reading, New Jersey and includes 61 storage tanks, a deep-water dock of maximum 900-foot vessel length, and five operational berths, allowing for both ship and barge berthing.  In addition, the facility has bi-directional pipeline access, rail off-loading 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 of maximum 550-foot vessel length, 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 New York Mercantile Exchange (“NYMEX”) delivery locations for both gasoline and ultra low sulfur diesel.

 

St. Lucia Terminal

 

The St. Lucia terminal sits on approximately 700 acres on Cul de Sac Bay.  It has approximately 10 million barrels of crude oil and refined petroleum products storage capacity, has deep-water access and improves our capabilities in the Caribbean storage market with more geographically diverse service offerings to allow us to accommodate a larger portion of the growing Latin American crude oil production volumes.

 

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 terminal 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 began to provide fuel oil supply and distribution services to third parties in the Caribbean beginning in late 2012.

 

The Merchant Services segment owns five terminals in Pennsylvania with aggregate storage capacity of approximately 1 million barrels, which are operated by the 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.

 

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

 

 

 

Year Ended December 31,

 

 

 

2013

 

2012

 

2011

 

Sales volumes (1)

 

1,371.5

 

1,125.9

 

1,337.8

 

 


(1)         Amounts for 2013 and 2012 include volumes related to fuel oil supply and distribution services which began in late 2012.

 

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 ship 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 sheet, 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 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.

 

Development & Logistics Segment

 

The Development & Logistics segment provides turn-key operations and maintenance, asset development and construction services for third-party pipeline and energy assets across the United States. This segment operates and/or maintains third-party pipelines under agreements with major oil and gas, petrochemical and chemical companies, which are located primarily in Texas and Louisiana.  This segment also performs 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.  The Development & Logistics segment includes our ownership and operation of two underground propane storage caverns in Huntington, Indiana and Tuscola, Illinois, with approximately 800,000 barrels of throughput and storage capability.  Additionally, this segment owns an approximate 63% interest in the Sabina crude butadiene pipeline, owns and operates a 30-mile ammonia pipeline and owns and operates approximately 25 miles of pipeline, which it leases to third parties, all located in Texas.

 

Third-party operations and construction management services are a key area of focus for the Development & Logistics segment.  The segment also operates as an asset and business development service provider for many of its operation and maintenance service customers.

 

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Discontinuation of Natural Gas Storage Segment

 

In December 2013, our Board of Directors approved a plan to divest our natural gas storage facility and related assets that our subsidiary, Lodi Gas, owns and operates in Northern California, as we no longer believe this business is aligned with our long-term business strategy.  The natural gas facility currently has approximately 30 billion cubic feet of working natural gas storage and is connected to Pacific Gas and Electric’s intrastate gas pipeline system that services natural gas demand in the San Francisco and Sacramento, California areas.  We classified the Natural Gas Storage disposal group as “Assets held for sale” and “Liabilities held for sale” in our consolidated balance sheet as of December 31, 2013 and reported the results of operations as discontinued operations for all periods presented in this report.  For additional information, see Note 4 in the Notes to Consolidated Financial Statements.

 

Competition and Customers

 

Competitive Strengths

 

We believe that we have the following competitive strengths:

 

·                  We operate in a safe 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.

 

Pipelines & Terminals Segment

 

Generally, pipelines are the lowest cost method for long-haul overland movement of liquid petroleum products.  Therefore, the 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 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 Pipelines & Terminals segment in particular locations.

 

The 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 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 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, if such biofuels can be transported through our pipeline, and additional blending opportunities within the segment, although that potential cannot be quantified at present.

 

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Distribution of liquid petroleum products depends to a large extent upon the location and capacity of refineries.  However, because the Pipelines & Terminals segment’s business is largely driven by the consumption of fuel in its delivery areas and the Pipelines & Terminals segment’s pipelines have numerous source points, 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 Pipelines & Terminals segment.  As discussed in “Item 1A., Risk Factors”, 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 Pipelines & Terminals segment.

 

The 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 Pipelines & Terminals segment’s terminals.  While the Pipelines & Terminals segment’s terminal throughput fees are not regulated, they are subject to price competition from competitive terminals and alternate modes of transporting liquid petroleum products to end-users such as retail gasoline stations.

 

Global Marine Terminals Segment

 

Our Global Marine Terminals segment primarily competes with other marine terminals in the Caribbean, terminals in New York Harbor, and to a lesser extent, terminals on the Gulf Coast.  Many competitive terminals are owned by major integrated oil and gas companies, refiners and master limited partnerships.  Our terminal facilities on Grand Bahama Island, 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 the Buckeye 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 Pipelines & Terminals segment (as discussed above).

 

Merchant Services Segment

 

The Merchant Services segment competes with major integrated oil and gas 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 petroleum products.

 

Development & Logistics Segment

 

The Development & Logistics segment competes 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 Development & Logistics segment to complete these tasks.  Numerous engineering and construction firms compete with the Development & Logistics segment for construction management business.

 

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Customers

 

For the years ended December 31, 2013, 2012 and 2011, no customer contributed 10% or more of our consolidated revenue.  In the Global Marine Terminals segment, storage revenue represented approximately 76% of BORCO’s total revenue for the year ended December 31, 2013.  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, 2013, approximately 38% and 69% 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 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 Global Marine Terminals segment’s mix and volume of products stored does not vary significantly by season.

 

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 Pipelines & Terminals and Merchant Services segments both benefit from 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.

 

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, 2013, Services Company had approximately 1,270 employees, approximately 310 of whom were represented by labor unions.  Additionally, at December 31, 2013, certain of our wholly owned subsidiaries had approximately 350 employees, approximately 180 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.

 

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Following is a discussion of certain laws and regulations affecting us.  However, you should not rely on such discussion as an exhaustive review of all regulatory considerations affecting our business and operations.

 

Rate Regulation

 

OverviewBuckeye Pipe Line, Wood River, BPL Transportation and NORCO operate pipelines subject to the regulatory jurisdiction of 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 FERC believes reflects cost changes appropriate for application to pipeline rates.  In December 2010, FERC amended its regulations to change the index to the Producer Price Index — finished goods (“PPI-FG”) plus 2.65% effective July 1, 2011.  Under FERC’s rules, as one alternative to indexed rates, a pipeline is also allowed to charge market-based rates if the pipeline establishes that it does not possess significant market power in a particular market.

 

The tariff rates of Wood River, BPL Transportation and NORCO are governed by the generic FERC index methodology, and therefore are subject to change annually according to the index.  If the index is negative in a future period, then Wood River, BPL Transportation and NORCO could be required to reduce their rates if they exceed the new maximum allowable rate.  Shippers may file protests against the application of the index to the rates of an individual pipeline and may also file complaints against indexed rates as being unjust and unreasonable, subject to the FERC’s standards.

 

Buckeye Pipe Line’s rates were historically governed by an exception to the rules discussed above, pursuant to a specific FERC authorization, although, as discussed below in detail, as a result of a FERC order issued in February 2013, Buckeye Pipe Line’s rates in markets that are not subject to market-based rate authority are now subject to the index rules discussed above that apply to all of the rates for Wood River, BPL Transportation and NORCO; Buckeye’s rates in markets subject to market-based rate authority can be set according to market forces rather than indexing.

 

BackgroundBuckeye Pipe Line’s market-based rate regulation program was initially approved by FERC in March 1991 and was subsequently extended in 1994.  Under this program, in markets where Buckeye Pipe Line did not have significant market power, individual rate increases: (a) would not exceed a real (i.e., exclusive of inflation) increase of 15% over any two-year period, and (b) would be allowed to become effective without suspension or investigation if they did not exceed a “trigger” equal to the change in the Gross Domestic Product implicit price deflator since the date on which the individual rate was last increased, plus 2%.  Individual rate decreases would be presumptively valid upon a showing that the proposed rate exceeds marginal costs.  In markets where Buckeye Pipe Line was found to have significant market power and in certain markets where no market power finding was made: (i) individual rate increases could not exceed the volume-weighted average rate increase in markets where Buckeye Pipe Line did not have significant market power since the date on which the individual rate was last increased, and (ii) any volume-weighted average rate decrease in markets where Buckeye Pipe Line did not have significant market power must have been accompanied by a corresponding decrease in all of Buckeye Pipe Line’s rates in markets where it did have significant market power.  Shippers retained the right to file complaints or protests following notice of a rate increase, but were required to show that the proposed rates would violate or were not adequately justified under the market-based rate regulation program, that the proposed rates were unduly discriminatory, or that Buckeye Pipe Line had acquired significant market power in markets previously found to be competitive.

 

Order Returning Buckeye Pipe Line Company to the Standard FERC Ratemaking Options.  The Buckeye Pipe Line program was subject to review by FERC in 2000 when FERC reviewed the index selected in the generic oil pipeline regulations.  FERC decided to continue the generic oil pipeline regulations with no material changes and did not modify or discontinue Buckeye Pipe Line’s program.  By order issued on March 30, 2012 in FERC Docket (“Dkt.”) No. IS12-185-000, FERC required Buckeye Pipe Line to show cause why its program should not be discontinued and other changes made to its rates and system of regulation.  On February 22, 2013, FERC issued an order in Dkt. No. IS12-185-000 et al. discontinuing the program, and affirming on rehearing its rejection of all rate increases filed in March 2012 (“Ratemaking Methodology Order”).  The Ratemaking Methodology Order permitted Buckeye to retain its currently-filed rates in place, to make future rate changes under market-based ratemaking authority in markets previously found to be competitive by FERC, and to make future changes in rates in other markets pursuant to the generic FERC ratemaking methods, which would include indexing.  No requests for rehearing or petitions for judicial review were filed with respect to the Ratemaking Methodology Order.  Subsequently, on March 28, 2013, Buckeye Pipe Line Company filed rate increases for services in the markets previously found to be competitive, and on May 30, 2013, Buckeye Pipe Line Company filed rate increases for most transportation services in the markets not previously found to be competitive; both sets of tariff filings became effective and are not subject to any FERC proceedings.

 

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

 

Environmental Regulation

 

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 and terminal 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 and terminalling industry. Our pipelines cross, and certain terminals are located proximal to, 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 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 and terminal 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.  Releases of a hazardous substance, whether on or off-site, may subject the generator of that substance to joint and several liabilities under CERCLA for the costs of clean-up and other remedial action.  Pipeline and terminal maintenance and other activities in the ordinary course of business generate “hazardous substances.”  As a result, to the extent a hazardous substance generated by us or our predecessors may have been released or disposed of in the past, we may in the future be required to remediate 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 adjacent to or in the immediate vicinity of Superfund and other hazardous waste sites, we may be responsible under CERCLA for all or part of the costs required to cleanup such sites, which could be material.

 

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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.  EPA has recently begun promulgating greenhouse gas (“GHG”) regulations and 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 add controls separate from or in conjunction with federal programs.

 

We are also subject to environmental laws and regulations adopted by the various states 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”).  In promulgating the PSA in 1994, Congress combined and re-codified, without substantial modification, the provisions of the two existing pipeline safety statutes: the Natural Gas Pipeline Safety Act of 1968 and the Hazardous Liquid Pipeline Safety Act of 1979.  Since the passage of these safety statutes, the resulting DOT regulations have been modified and strengthened by various Congressional actions including the Pipeline Safety Reauthorization Act of 1988, the Pipeline Safety Act of 1992, the Accountable Pipeline Safety and Partnership Act of 1996, the Pipeline Safety Improvement Act of 2002, the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 and the most recent Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011.  These Acts and the resulting DOT regulations govern the design, installation, testing, construction, operation, replacement and management of pipeline facilities and require any entity that owns or operates pipeline facilities to comply with applicable safety standards, to establish and maintain plans for inspection and maintenance and to comply with such plans and programs.  Also governed by the Acts and related regulations are requirements for an integrity management program that among other things, requires the determination of pipeline integrity risk and periodic assessments of pipeline segments in High Consequent Areas (“HCAs”), a drug and alcohol testing program, an Operator Qualification program that ensures that persons performing tasks covered by the pipeline safety rules are qualified, a public education program for residents, public officials, emergency responders and contractors and a control room management plan that prescribes safety requirements for controllers, control rooms and the computer systems used to monitor and control pipeline operations.

 

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.  This law has a number of provisions that will either directly or potentially impact the oil and gas industry.  Among other things, PSA 2011 requires that PHMSA conduct a number of evaluations and studies and, based on the results, promulgate regulations to address possible expansion of the integrity management requirements to areas outside of HCAs; methods or processes to verify maximum operating pressure (MOP); changes to operators’ public education programs to increase outreach to the affected public; the technical limitations and practicality of requiring the use of leak detection systems and the standards relating thereto; and incidents that may have been caused by lack of adequate depth of cover at water crossings of 100 feet or more.  PSA 2011 also specifically requires PHMSA to establish time limits for reporting incidents to the National Response Center as well as coordination of notifications to state/local first responders and issue regulations to improve the current administrative enforcement process for pipeline operators.  PSA 2011 increases penalties for non-compliance with PHMSA regulations from a $100,000 to a $200,000 maximum for a single violation, and from a $1.0 million to a $2.0 million maximum for a series of violations.

 

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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 petroleum product spills and other releases.  If any of these should occur, we could incur legal defense costs and environmental remediation costs, and could be required to pay amounts due to injury, loss of life, damage or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations.

 

We are covered by site pollution incident legal liability insurance policies with per incident and aggregate limits of $100.0 million, subject to a maximum self-insured retention of $4.5 million.  The policies include coverage for sudden and accidental or gradual releases at our listed sites. The policies also include a contractor’s pollution coverage endorsement.  The insurance policies expire on September 30, 2014.  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.

 

In addition to the site pollution incident legal liability insurance policies, we maintain casualty insurance policies with aggregate and per occurrence limits of $400 million.  The policies provide coverage for claims involving sudden and accidental releases up to $400 million.  Coverage under the casualty insurance is secondary to the site pollution incident legal liability policies for sudden and accidental releases.  The insurance policies expire on April 1, 2014.  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.

 

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 companies 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.

 

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We have written plans for responding to emergencies along our pipeline system and at our terminal 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 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. We maintain more than 50 contract relationships with United States Coast Guard certified oil spill response organizations, spill response contractors and remediation management consultants.  In 2013, we have 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 BORCO, Yabucoa and St. Lucia Terminals.  This service contract provides access to over 100 additional local United States Coast Guard certified oil 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.

 

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 has been driven by increases in crude oil production from Latin America, crude oil movements from South America to Asia, 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.

 

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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 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 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 our pipelines and terminals service 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.

 

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 Pipelines & Terminals segment are other existing pipelines, some of which are owned or controlled by major integrated oil 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 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.

 

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Privately arranged exchanges of liquid petroleum products between marketers in different locations are another form of competition for our 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 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 Pipelines & Terminals segment’s terminals.  While the 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, terminals in New York Harbor, and to a lesser extent, terminals on the Gulf Coast.  Many competitive terminals are owned by major integrated oil and gas 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 terminal services.

 

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

 

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

 

Mergers among our customers and competitors could result in lower volumes being shipped on our pipelines and stored in our terminals, thereby reducing the amount of cash we generate.

 

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

 

We are a holding company and depend entirely on our operating subsidiaries’ distributions to service our debt obligations and pay cash distributions to our unitholders.

 

We are a holding company with no material operations.  If we do not receive cash distributions 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.

 

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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 performed a certain level of diligence in connection with our acquisitions and attempted 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 is not available, which could materially adversely affect our business, financial condition, results of operations or cash flow.

 

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

 

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

 

Potential future acquisitions and expansions, 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 integrate these new operations.

 

From time to time, we evaluate and acquire assets and businesses that we believe complement our existing assets and businesses.  Acquisitions, including the integration of acquired assets into our existing business, may require substantial capital or the incurrence of substantial indebtedness. If we consummate any future acquisitions, our capitalization and results of operations may change significantly.

 

Acquisitions and business expansions 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 we may be unable to integrate certain assets we acquire as part of a larger acquisition to the extent such assets relate to a business for which we have no or limited experience.  Following an acquisition, we may discover previously unknown liabilities associated with the acquired business for which we have no recourse under applicable indemnification provisions.

 

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

 

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

 

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

 

Buckeye Pipe Line, Wood River, BPL Transportation 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.  In the alternative, 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.  A pipeline may also charge rates based on the agreement of all shippers receiving a service, which are referred to as settlement-based rates.

 

The indexing methodology has been and continues to be used to establish rates on the pipelines owned by Wood River, BPL Transportation and NORCO.  In December 2010, FERC amended its regulations to change the index to the Producer Price Index (“PPI”) — finished goods plus 2.65% effective July 1, 2011.  If the index were to be negative, we would be required to reduce the rates charged by Wood River, BPL Transportation and NORCO 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.

 

Until February 2013, Buckeye Pipe Line was authorized to charge rates under an exception to the rules generally applicable to oil pipelines.  In 1991, Buckeye Pipe Line sought and received FERC permission to determine rate changes on Buckeye Pipe Line’s pipeline system (the “Buckeye System”) using a unique methodology that constrained rates based on competitive pressures in markets that FERC found to be competitive, as well as certain other limits on rate increases in other markets on the Buckeye System (the “Buckeye Methodology”). FERC permitted the continuation of the Buckeye Methodology for the Buckeye System in 1994, subject to FERC’s authority to cause Buckeye Pipe Line to terminate the Buckeye Methodology in the future.  The Buckeye Methodology was an exception to the generic oil pipeline regulations that FERC issued under the Energy Policy Act of 1992 (the “FERC Rules”), which rely primarily on the indexing methodology described above.

 

On March 1, 2012, Buckeye Pipe Line filed to increase its rates under the Buckeye Methodology.  On March 30, 2012, in response to a shipper protest, FERC issued an order (the “Show Cause Order”) in Docket No. IS 12-185-000 rejecting the rate increase and stating that FERC will review the continued efficacy of the Buckeye Methodology.  The Show Cause Order, among other things, stated that FERC would review the continued efficacy of the unique program and directed Buckeye Pipe Line to show cause why it should not be required to discontinue the program on the Buckeye System and avail itself of the generic ratemaking methodologies used by other oil pipelines.  The Show Cause Order did not impact any of the pipeline systems or terminals owned by Buckeye’s other operating subsidiaries.  On February 22, 2013, FERC issued an order in Docket (“Dkt.”) No. IS12-185-000 et al. discontinuing the Buckeye Methodology, and affirming on rehearing its rejection of all rate increases filed in March 2012 (“Ratemaking Methodology Order”).  The Ratemaking Methodology Order permitted Buckeye to retain its currently-filed rates in place, to make future rate changes under market-based ratemaking authority in markets previously found to be competitive by FERC, and to make future rate changes in other markets pursuant to the generic FERC ratemaking methods, which would include indexing.  Subsequently, on March 28, 2013, Buckeye Pipe Line filed rate increases for services in the markets previously found to be competitive, and on May 30, 2013, Buckeye Pipe Line filed rate increases for most transportation services in the markets not previously found to be competitive; both sets of tariff filings became effective and are not subject to any FERC proceedings.

 

On September 20, 2012, five airlines jointly filed a complaint in FERC Dkt. No. OR12-28-000 alleging that Buckeye Pipe Line’s rates for the transportation of jet fuel to the three major New York City area airports were unreasonable and should be reduced and should be subject to reparations for past shipments, and that the Buckeye Methodology should end with respect to that transportation; on October 10, 2012, Buckeye Pipe Line filed a motion to dismiss and answer opposing the complaint and its relief, and subsequent pleadings were filed by both the airlines and by Buckeye Pipe Line.  On October 15, 2012, Buckeye Pipe Line filed an application in FERC Dkt. No. OR13-3-000 for authority to charge market-based rates for transportation to destinations in the New York City-area markets (the “Application”), because Buckeye Pipe Line lacked significant market power.  On December 14, 2012, five airlines intervened and filed comments in opposition to the application in Dkt. No. OR13-3-000.  On February 22, 2013, FERC issued an order setting the airline complaint in Dkt. No. OR12-28-000 for hearing, but holding the hearing in abeyance and setting the dispute for settlement procedures before a settlement judge.  If FERC were to find these challenged rates to be in excess of costs and not otherwise protected by law, it could order Buckeye Pipe Line to reduce these rates prospectively and could order repayment to the complaining airlines of any past charges found to be in excess of just and reasonable levels for up to two years prior to the filing date of the complaint.  On February 28, 2013, FERC also issued an order setting the Application for hearing, holding the hearing in abeyance and setting the dispute for settlement procedures before a settlement judge.  If FERC were to approve the Application, Buckeye Pipe Line would be permitted prospectively to set these rates in response to competitive forces, and the basis for the airlines’ claim for relief in their OR12-28-000 complaint as to Buckeye Pipe Line’s future rates would be irrelevant prospectively.  On March 8, 2013, an order was issued consolidating, for settlement purposes, the complaint proceeding in Dkt. No. OR12-28-000 with the proceeding regarding the Application for market-based rates in the New York City market in Dkt. No. OR13-3-000 and settlement discussions under the supervision of the FERC settlement judge are ongoing.  The timing or outcome of final resolution of this matter cannot reasonably be determined at this time.

 

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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.  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, natural gas 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 these 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, natural gas and other hydrocarbon products that we transport, store or otherwise handle in connection with our business. A significant decrease in demand for petroleum products would have a material adverse effect on our business, financial condition, results of operations or cash flows.

 

Environmental regulation may impose significant costs and liabilities on us.

 

We are subject to federal, state and local laws and regulations relating to the protection of the environment. Risks of substantial environmental liabilities are inherent in our operations, and we cannot assure you that we will not incur material environmental liabilities.  Additionally, our costs could increase significantly, and we could face substantial liabilities, if, among other developments:

 

·                  environmental laws, regulations and enforcement policies become more rigorous; or

·                  claims for property damage or personal injury resulting from our operations are filed.

 

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

 

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

 

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

 

Our pipeline operations and natural gas storage 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 may affect our operations.

 

Our BORCO and St. Lucia operations may be adversely affected by economic, political and regulatory developments.

 

BORCO’s terminal 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 terminal 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.

 

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 increase rapidly and dramatically, 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 risks in our hedging activities that arise when a commodity, such as ultra low sulfur diesel, is purchased at one pricing index but must be hedged against another commodity type, such as heating oil, because of limitations in the markets for derivative products.  We are also susceptible to basis risk created when we enter into financial hedges that are priced at a certain location, such as New York Harbor, but the sales or exchanges of the underlying commodity are at another location, such as Macungie, Pennsylvania, where prices and price changes might differ from the prices and price changes at the location upon which the hedging instrument is based.

 

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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 76% of BORCO’s total revenue for the year ended December 31, 2013. 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, 2013, 38% and 69% of BORCO’s storage revenue was derived from the top one and the top three customers, in 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 terrors attacks, we face various other security threats, including cyber security threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the safety of our employees; threats to the security of our facilities, such as terminals and pipelines, and infrastructure or third-party facilities and infrastructure.  These developments have subjected our operations to increased risks.

 

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

 

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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.  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 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.

 

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”) and the rules and regulations promulgated and to be promulgated under the 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.  The Act mandates significant changes to the over-the-counter derivative market.  Among other changes, the Act and the regulations under the Act will:

 

·                    require the clearing and exchange trading of certain derivatives;

·                    require dealers and major participants to register with the Commodity Futures Trading Commission or the Securities Exchange Commission or both, and require them to comply with capital, business conduct, reporting and recordkeeping requirements;

·                    subject certain derivative transactions to margin requirements;

·                    establish position limits for certain derivatives; and

·                    require certain financial institutions to spin-off portions of their derivatives business.

 

The rulemaking process under the Act has not been completed, and the timeframes for compliance with rules under the Act that are effective remains uncertain.  Consequently, it is not possible at this time to determine the full effect that the Act and the rules and regulations adopted under the Act will have on our ability to continue to use the derivative products we currently utilize.  As a result of the imposition of capital, clearing and exchange-trading requirements, the Act and the rules and regulations under the Act may limit the availability of certain derivative products and/or may increase the costs of such products.  Additionally, the margin requirements applicable to certain derivative products may increase, resulting in such products becoming more expensive or uneconomical for us to use in our business.  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.  To the extent that our dealer counterparties are required to spin-off their derivatives activities to a separate entity, that new entity may not be as creditworthy as the current dealer counterparty and, as a result, we may have to increase our exposure to less creditworthy counterparties or curtail our dealings with that counterparty.  The effects of the Act and the rules and regulations under the Act may also reduce our ability to monetize or restructure our existing derivative contracts.  If, as a result of the Act and the rules and regulations under the Act, 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.  Any of these consequences could have a material adverse effect on us, our financial condition, and our results of operations.  To the extent that we currently utilize exchange traded futures in our business, we do not anticipate that those products will be affected by the provisions of the Act and the rules and regulations under the Act described above.

 

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

 

Our businesses are subject to the risks of nonpayment and nonperformance by our customers.  We manage our exposure to credit risk through credit analysis and monitoring procedures, and sometimes use letters of credit, prepayments 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. 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.

 

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, hazardous materials releases and other events beyond our control.  These events might result in a loss of equipment or life, injury, or extensive property 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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Hurricanes and other severe weather conditions, which may become more frequent as a result of climactic changes, could damage our facilities or disrupt our marine terminals or the operations of their customers, which could have a material adverse effect on our business, financial results and cash flow.

 

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

 

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

 

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

 

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

 

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

 

Our Merchant Services segment 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.

 

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.  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.

 

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

 

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

 

Unitholders may not have limited liability in some circumstances.

 

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

 

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

 

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

 

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Tax Risks to Unitholders

 

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

 

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

 

Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement.  Based upon our current operations, 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 or differing interpretations, possibly applied 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, from time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. One such legislative proposal would have eliminated our ability to be treated as a partnership for U.S. federal income tax purposes based on the qualifying income requirement. We are unable to predict whether any of these changes, or other proposals, will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our LP Units. Any modification to U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the qualifying income requirement to be treated as a partnership for U.S. federal income tax purposes.

 

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

 

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

 

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

 

You will be required to pay federal income taxes and, in some cases, state and local income taxes, on your share of our taxable income, whether or not you receive cash distributions from us. 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 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.

 

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 use of this proration method may not be permitted under existing U.S. Treasury Regulations.  The U.S. Treasury Department has issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders.  Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted.  If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

 

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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.

 

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 recently 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 these jurisdictions.  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.

 

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Our operations in The Bahamas and St. Lucia are currently exempt from taxation.  In addition, our operations in Puerto Rico are currently partially exempt from taxation.  If our tax status in these non-U.S. jurisdictions were to change, such that we have more tax liability than we anticipate, our cash flow could be materially adversely affected.

 

BORCO is currently exempt from income and property tax in The Bahamas pursuant to concessions granted under the Hawksbill Creek Agreement between the Government of the Bahamas and the Grand Bahama Port Authority.  BORCO’s exemption from Bahamian taxation pursuant to the Hawksbill Creek Agreement is scheduled to expire in 2015.  While we anticipate that the Bahamian governmental authorities will extend the concessions under the Hawksbill Creek Agreement, if the Bahamian governmental authorities do not extend the concessions or BORCO’s tax status in The Bahamas were to otherwise change, such that BORCO has more tax liability than we anticipate, our cash flow could be materially adversely affected.

 

We are currently exempt from income taxes and duties in St. Lucia pursuant to concessions granted under the terms of our Tax Concession Agreement effective in 2007 and in effect for a minimum of 50 years.  If our tax status in St. Lucia were to change, such that our operations have more tax liability than we anticipate, our cash flow could be materially adversely affected.

 

We are subject to income taxes within the Commonwealth of Puerto Rico and in 2002, we were granted partial exemption under the Tax Incentives Act of 1998 (the “Act”).  Under the current terms of the grant, we are 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.  If our exemptions under the Act are not extended upon expiration or our tax status in Puerto Rico were to otherwise change, such that our operations have more tax liability than we anticipate, our cash flow could be materially adversely affected.

 

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 64,000 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, pumping stations and terminal facilities are located on land that we own.  BORCO currently leases the seabed on which the jetties are located and the inland dock under long-term agreements through 2057 and 2067, respectively.

 

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

 

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

 

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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.

 

On May 25, 2012, a ship 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 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 Houston, Texas.  The vessel owner has claimed that it is entitled to limit its liability to approximately $17 million, but we are contesting the right of the vessel owner to such limitation.  A hearing in the Bahamas court on the vessel owner’s right to limit its liability was held on July 23, 2013, and the 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 interests have appealed that decision and the appeal is scheduled to be heard March 27, 2014.  We experienced no material interruption of service at the BORCO facility as a result of the incident, and the repairs of the damaged sections are complete.  The aggregate cost to repair and reconstruct the damaged portions of the jetty was approximately $25 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, 2013, we had a $5 million receivable included in “Other non-current assets” in our consolidated balance sheet, representing reimbursement of the deductible.  Additionally, we have received cash proceeds of $15.3 million related to insurance reimbursements as of December 31, 2013, 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.  As of December 31, 2013, no gain had been recognized; however, we recorded a $12.7 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 December 3, 2012, a complaint was filed in the Circuit Court for Washington County, Wisconsin by Chad Altschafl, et al., as plaintiffs, naming Buckeye, Buckeye Pipe Line Services Company (“Services Company”), BPH, Buckeye Pipe Line, West Shore, and Zurich American Insurance Co. as defendants, which complaint was amended by the plaintiffs on April 18, 2013, August 1, 2013 and again on September 23, 2013.  The plaintiffs are owners of 216 properties located in and around Jackson, Wisconsin.  The complaint attempts to allege various emotional distress and property damage claims under Wisconsin law arising out of a release of gasoline from a pipeline owned by West Shore in the Town of Jackson, Wisconsin on July 17, 2012.  On January 21, 2013, we filed an answer to the complaint, denying plaintiffs claims and asserting affirmative defenses.  No dollar amount of damages is stated in the complaint, but the plaintiffs seek damages to reimburse them for, among other things, alleged costs of restoring their properties, of installing a permanent supply of potable water, and the alleged diminution in value of their properties.  The plaintiffs also seek punitive damages.  Pursuant to the scheduling order entered in the case, a trial is scheduled to begin in August 2015, but the timing or outcome of final resolution of this matter cannot reasonably be determined at this time.  Buckeye, Services Company, BPH and Buckeye Pipe Line are entitled to certain indemnifications by West Shore pursuant to an agreement between Buckeye Pipe Line and West Shore, which we believe would result in West Shore indemnifying us for any losses stemming from this litigation.  In addition, West Shore has insurance that we believe should cover such losses, subject to a $3.0 million deductible.  West Shore is pursuing that insurance coverage.

 

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Federal Energy Regulatory Commission (“FERC”) Proceedings

 

FERC Docket No. OR12-28-000 — Airlines Complaint against Buckeye Pipe Line 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 Buckeye Pipe Line’s rates for transportation of jet fuel from New Jersey to three New York City airports.  The complaint was not directed at Buckeye Pipe Line’s rates for service to other destinations, and does 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 October 10, 2012, Buckeye Pipe Line filed its answer to the complaint, contending that the airlines’ allegations are based on inappropriate adjustments to the pipeline’s costs and revenues, and that, in any event, any revenue recovery by Buckeye Pipe Line in excess of costs would be irrelevant because Buckeye Pipe Line’s rates are set under a FERC-approved program that ties rates to competitive levels.  Buckeye Pipe Line also sought dismissal of the complaint to the extent it seeks to challenge the portion of Buckeye Pipe Line’s rates that were deemed just and reasonable, or “grandfathered,” under Section 1803 of the Energy Policy Act of 1992.  Buckeye Pipe Line further contested the airlines’ ability to seek relief as to past charges where the rates are lawful under Buckeye Pipe Line’s FERC-approved rate program.  On October 25, 2012, the complainants filed their answer to Buckeye Pipe Line’s motion to dismiss and answer.  On November 9, 2012, Buckeye Pipe Line filed a response addressing newly raised arguments in the complainants’ October 25th answer.  On February 22, 2013, FERC issued an order setting the airline complaint in Dkt. No. OR12-28-000 for hearing, but holding the hearing in abeyance and setting the dispute for settlement procedures before a settlement judge.  If FERC were to find these challenged rates to be in excess of costs and not otherwise protected by law, it could order Buckeye Pipe Line to reduce these rates prospectively and could order repayment to the complaining airlines of any past charges found to be in excess of just and reasonable levels for up to two years prior to the filing date of the complaint. Buckeye Pipe Line intends to vigorously defend its rates.  On March 8, 2013, an order was issued consolidating, for settlement purposes, this complaint proceeding with the proceeding regarding Buckeye Pipe Line’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 are ongoing.  The timing or outcome of final resolution of this matter cannot reasonably be determined at this time.

 

FERC Docket No. OR13-3-000 — Buckeye Pipe Line’s Market-Based Rate Application. On October 15, 2012, Buckeye Pipe Line 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, Buckeye Pipe Line seeks 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.  The jet fuel rates were also the subject of the airlines’ OR12-28-000 complaint discussed above.  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.  On January 14, 2013, Buckeye Pipe Line filed its answer to the protest and requested summary disposition as to those non-jet-fuel rates that were not challenged in the protest.  On January 29, 2013, the protestants responded to Buckeye Pipe Line’s answer, and on February 13, 2013, Buckeye Pipe Line filed a further answer to the protestants’ January 29, 2013 pleading.  On February 28, 2013, FERC issued an order setting the Application for hearing, holding the hearing in abeyance and setting the dispute for settlement procedures before a settlement judge.  As discussed above, the Application has been consolidated with the complaint proceeding in Dkt. No. OR12-28-000 for settlement purposes and settlement discussions under the supervision of the FERC settlement judge are ongoing.  If FERC were to approve the Application, Buckeye Pipe Line would be permitted prospectively to set these rates in response to competitive forces, and the basis for the airlines’ claim for relief in their OR12-28-000 complaint as to Buckeye Pipe Line’s future rates would be irrelevant prospectively.  The timing or outcome of FERC’s review of the Application cannot reasonably be determined at this time.

 

Environmental Proceedings

 

In May 2013, the Pennsylvania Department of Environmental Protection (“PADEP”) issued a proposed Consent Assessment of Civil Penalty related to a March 2011 release of diesel fuel that occurred in Shippingport Borough, Pennsylvania, which included a $0.2 million proposed penalty.  We are in discussions with PADEP regarding the circumstances of the release and the appropriate amount of the penalty.  The timing or outcome of this matter cannot reasonably be determined at this time.

 

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In May 2013, the Pipeline Hazardous Materials Safety Administration issued a proposed penalty totaling $0.4 million in connection with a product release that occurred in Linden, New Jersey in May 2010. We contested portions of the proposed penalty and in early February 2014 PHMSA issued a final order agreeing in part and required that we pay a reduced penalty amount of $0.3 million.

 

In September 2012, the Attorney General of the State of Illinois filed a complaint under the caption the People of the State of Illinois, et al v. Buckeye Pipe Line Company, L.P. (“BPLC”), et al. in connection with an alleged release of jet fuel on or about August 27, 2012, from a pipeline owned by West Shore Pipe Line Company and operated by BPLC in Palos Park, Illinois. In December 2013, the consent order was entered by the Circuit Court of Cook County, Illinois with the aggregate penalty amount for both West Shore and BPLC marginally exceeding $0.1 million.

 

Item 4.                     Mine Safety Disclosures

 

Not applicable.

 

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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, 2013 and 2012, as reported in the NYSE Composite Transactions, were as follows:

 

 

 

2013

 

2012

 

Quarter

 

High

 

Low

 

High

 

Low

 

First

 

$

61.32

 

$

45.72

 

$

64.95

 

$

58.50

 

Second

 

70.50

 

58.33

 

61.37

 

44.55

 

Third

 

73.44

 

64.19

 

54.68

 

47.06

 

Fourth

 

72.47

 

62.00

 

50.91

 

44.37

 

 

The following graph compares the total unitholder return performance of our LP Units with the performance of (i) the Standard & Poor’s 500 Stock Index (“S&P 500”) and (ii) the Alerian MLP index.  The Alerian MLP Index is a composite of the 50 most prominent energy master limited partnerships that provides investors with a comprehensive benchmark for this asset class.  The graph assumes that $100 was invested in our LP Units and each comparison index beginning on December 31, 2008 and that all distributions or dividends were reinvested on a quarterly basis.

 

 

 

 

12/31/2008

 

12/31/2009

 

12/31/2010

 

12/31/2011

 

12/31/2012

 

12/31/2013

 

Buckeye Partners, L.P.

 

$

100.00

 

$

183.29

 

$

239.43

 

$

244.35

 

$

187.66

 

$

313.56

 

S&P 500

 

100.00

 

126.46

 

145.51

 

148.59

 

172.37

 

228.19

 

Alerian MLP Index

 

100.00

 

176.41

 

239.66

 

272.92

 

286.01

 

364.90

 

 

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We have gathered tax information from our known unitholders and from brokers/nominees and, based on the information collected, we estimate our number of beneficial unitholders to be approximately 159,538 at December 31, 2013.

 

Cash distributions paid to LP Unitholders for the periods indicated were as follows:

 

Record Date

 

Payment Date

 

Amount Per
LP Unit

 

February 21, 2011

 

February 28, 2011

 

$

0.9875

 

May 16, 2011

 

May 31, 2011

 

1.0000

 

August 15, 2011

 

August 31, 2011

 

1.0125

 

November 14, 2011

 

November 30, 2011

 

1.0250

 

 

 

 

 

 

 

February 21, 2012

 

February 29, 2012

 

$

1.0375

 

May 14, 2012

 

May 31, 2012

 

1.0375

 

August 15, 2012

 

August 31, 2012

 

1.0375

 

November 12, 2012

 

November 30, 2012

 

1.0375

 

 

 

 

 

 

 

February 19, 2013

 

February 28, 2013

 

$

1.0375

 

May 16, 2013

 

May 31, 2013

 

1.0500

 

August 12, 2013

 

August 20, 2013

 

1.0625

 

November 12, 2013

 

November 19, 2013

 

1.0750

 

 

On February 7, 2014, we announced a quarterly distribution of $1.0875 per LP Unit that will be paid on February 25, 2014, to unitholders of record on February 18, 2014.  Based on the LP Units outstanding as of December 31, 2013, cash distributed to LP unitholders on February 25, 2014 will total $125.5 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.

 

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Item 6.                     Selected Financial Data

 

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

 

 

 

Year Ended December 31,

 

 

 

2013

 

2012

 

2011

 

2010 (1)

 

2009 (1)

 

Income Statement Data:

 

 

 

 

 

 

 

 

 

 

 

Revenue

 

$

5,054,101

 

$

4,285,903

 

$

4,693,620

 

$

3,055,931

 

$

1,671,209

 

Operating income (2)

 

478,041

 

344,536

 

365,845

 

262,513

 

172,883

 

Income from continuing operations (2)

 

351,599

 

235,879

 

291,827

 

182,642

 

110,876

 

Earnings per unit - diluted from continuing operations (3)

 

$

3.23

 

$

2.37

 

$

3.15

 

$

0.95

 

$

0.94

 

Cash distributions per LP Unit - declared

 

$

4.23

 

$

4.15

 

$

4.03

 

$

3.83

 

$

3.63

 

 

 

 

December 31,

 

 

 

2013

 

2012

 

2011

 

2010

 

2009

 

Balance Sheet Data:

 

 

 

 

 

 

 

 

 

 

 

Total assets (4)

 

$

7,005,563

 

$

5,981,009

 

$

5,570,376

 

$

3,574,216

 

$

3,486,571

 

Long-term debt

 

3,092,711

 

2,735,244

 

2,393,574

 

1,519,393

 

1,500,495

 

Total Buckeye Partners, L.P. capital (5)

 

3,065,665

 

2,372,313

 

2,303,169

 

1,392,405

 

242,334

 

 


(1)         On November 19, 2010, we consummated a transaction pursuant to a plan and agreement of merger (the “Merger Agreement”) with our general partner, BGH, BGH’s general partner and Grand Ohio, LLC (“Merger Sub”), our subsidiary.  The exchange of BGH’s units for our LP Units was accounted for as a BGH equity issuance, and pursuant to the Merger Agreement, Merger Sub was merged into BGH, with BGH as the surviving entity (the “Merger”) for accounting purposes.  The financial information for the periods prior to the effective date of the Merger is that of BGH. Although Buckeye is the surviving entity for legal purposes, BGH is the surviving entity for accounting purposes. Because BGH controlled Buckeye prior to the Merger, Buckeye’s financial statements were consolidated into BGH.

(2)         During 2012 and 2010, we recorded a $60 million asset impairment in our Pipelines & Terminals segment (see Note 5 in the Notes to the Consolidated Financial Statements) and a $21.1 million modification of an equity compensation plan, respectively.

(3)         In connection with the Merger, the incentive compensation agreement (also referred to as the incentive distribution rights) held by our general partner was cancelled, and the general partner units held by our general partner (representing an approximate 0.5% general partner interest in us) were converted to a non-economic general partner interest.  Additionally, pursuant to the Merger, BGH’s unitholders received a total of approximately 20 million of Buckeye’s LP Units in exchange for all outstanding BGH common units and management units.  As a result, the number of Buckeye’s LP Units outstanding increased from 51.6 million to 71.4 million.  However, for historical reporting purposes, the impact of this change was accounted for as a reverse split of BGH’s units of 0.705 to 1.0, together with the addition of Buckeye’s existing LP Units.

(4)         Includes $181.7 million of assets held for sale as of December 31, 2013 relating to the Natural Gas Storage disposal group (see Note 4 in the Notes to Consolidated Financial Statements for further discussion).

(5)         Prior to the Merger, BGH’s noncontrolling interests primarily related to equity interests of Buckeye that were not owned by BGH.  In connection with the Merger, total Buckeye capital substantially increased with the elimination of such noncontrolling interests.

 

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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 one of the largest independent liquid petroleum products pipeline systems in the United States in terms of volumes delivered, miles of pipeline, and active product terminals.  In addition, we operate and/or maintain third-party pipelines under agreements with major oil and gas, petrochemical and chemical companies, and perform certain engineering and construction management services for third parties.  Furthermore, we are a wholesale distributor of refined petroleum products in the United States in areas also served by our pipelines and terminals.  Beginning in late 2012, we began to provide fuel oil supply and distribution services to third parties in the Caribbean.  Our flagship marine terminal in The Bahamas, BORCO, is one of the largest marine crude oil and petroleum products storage facilities in the world, serving the international markets as a global logistics hub.

 

We also own and operate a natural gas storage facility in Northern California.  In December 2013, our Board of Directors approved a plan to divest our Natural Gas Storage segment and its related assets as we no longer believe this business is aligned with our long-term business strategy.  In this report, we refer to this group of assets as our Natural Gas Storage disposal group.  Accordingly, we have classified the disposal group as “Assets held for sale” and “Liabilities held for sale” in our consolidated balance sheet as of December 31, 2013 and reported the results of operations as discontinued operations for all periods presented in this report.  Furthermore, we have excluded the disposal group’s financial results from our business segment disclosures for the periods presented in this report.  For additional information, see Note 4 in the Notes to Consolidated Financial Statements.

 

Additionally, in December 2013, we changed our organizational structure to align our strategic business units into four reportable segments: Pipelines & Terminals, Global Marine Terminals, Merchant Services and Development & Logistics.  See Note 26 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 the current alignment of our continuing business and discontinued operations.

 

Our primary business objective is to provide stable and sustainable cash distributions to our LP 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; 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 $160.3 million for the year ended December 31, 2013, which was a decrease of $66.1 million, or 29% from $226.4 million for the corresponding period in 2012. Operating income was $478.0 million for the year ended December 31, 2013, which is an increase of $133.5 million, or 38.7%%, from $344.5 million the corresponding period in 2012.  Our results for the year ended December 31, 2013 includes year-over-year improvement in each of our operating segments.  Continued excess supply of natural gas, minimal volatility in natural gas prices and compressed seasonal spreads resulted in a decision by our Board of Directors to approve a plan to divest our Natural Gas Storage business.  In the fourth quarter of 2013, we recorded a non-cash asset impairment charge of $169 million.

 

Revenues for our Pipelines & Terminals segment grew significantly in 2013, primarily from the impact of capital investments in internal growth and diversification initiatives, including expanded butane blending capabilities, crude-handling services, as well as storage and throughput of other hydrocarbons.  Pipeline transportation and terminalling throughput volumes increased year-over-year driven by changes in regional production and supply, commodity pricing arbitrage favoring East and Gulf Coast over Midwest supply and an increase in distillate volumes, primarily due to a colder than usual winter in 2013 resulting in higher heating oil movements.  The change over prior year was additionally impacted by a non-cash asset impairment charge in the fourth quarter of 2012 of $60 million related to the idling of a portion of Buckeye’s NORCO pipeline system.

 

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Our Global Marine Terminals segment benefited from year-over-year contribution driven by the 4.7 million barrels of expansion capacity at BORCO put in operation since mid-2012.  In addition to the storage revenue contribution from the expansion capacity, increased customer utilization of our facilities and the changing product mix at our BORCO facility generated higher ancillary revenues for the period.  In 2013, the Global Marine Terminals segment was adversely impacted by certain tankage taken out of service to facilitate projects intended to improve our ability to handle heavy crude volumes sourced from South America and potentially from Canada.  We continued to explore the diversification opportunities with our assets and to take advantage of the flexibility of our terminals to offer additional services such as butanization and other crude initiatives.  Integration of the terminals acquired from Hess in December 2013 is expected to allow further product diversification for Buckeye, as we will be able to leverage our existing assets to provide a broader array of services to the customers at these new terminals.

 

Additionally, our Merchant Services segment continued to see benefits from our risk mitigation strategy initiated in 2012, which includes focusing on fewer, more strategic locations in which to transact business, better managing our inventories and reducing the cost structure of the business.  Sales volumes increased as we executed this strategy.  Furthermore, we benefited from improved rack margins, largely the result of renewable identification number (“RIN”) sales.  Our Merchant Services segment generates RINs through its ethanol blending and bio-blended diesel activities.  The market for RINs, which are legislatively required to be purchased by refiners, experienced a substantial increase in value during the first half of the year.  In the latter half of 2013, the value of RINs declined as the U.S. Environmental Protection Agency lowered the required blend volumes for renewable fuels.  Although RIN values have declined considerably since their elevated levels in the first half of the year, RIN sales still made a positive contribution to our Merchant Services segment.  Our marketing operations remain a catalyst for incremental utilization of our Pipelines & Terminals assets as the contribution from Merchant Services has been greater than its standalone reported results. Segment revenue also increased as a result of the launch of our fuel oil marketing business in the Caribbean.  We supply fuel oil and hedge it in a highly correlated market.

 

Key contributors to growth for our Development & Logistics segment include our third-party engineering and operations business, which benefited from improved margins and new contract operations opportunities.  In addition, contributions from the liquefied petroleum gas (“LPG”) storage caverns continue to increase due to the return of recent capital investments and rail capabilities at these facilities.

 

In 2013, the discontinued operations of our natural gas storage facility declined over 2012 results due to a non-cash asset impairment charge, unfavorable market conditions, including low natural gas prices, compressed seasonal spreads and low volatility.

 

See the “Results of Operations” section below for further discussion and analysis of our operating segments.

 

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Results of Operations

 

            Consolidated Summary

 

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

 

 

 

Year Ended December 31,

 

 

 

2013

 

2012

 

2011

 

Revenue

 

$

5,054,101

 

$

4,285,903

 

$

4,693,620

 

Costs and expenses

 

4,576,060

 

3,941,367

 

4,327,775

 

Operating income

 

478,041

 

344,536

 

365,845

 

Earnings from equity investments

 

5,243

 

6,100

 

10,434

 

Gain on sale of equity investment

 

 

 

34,727

 

Interest and debt expense

 

(130,920

)

(114,980

)

(119,561

)

Other income (expense)

 

295

 

(452

)

190

 

Income from continuing operations, before taxes

 

352,659

 

235,204

 

291,635

 

Income tax (expense) benefit

 

(1,060

)

675

 

192

 

Income from continuing operations

 

351,599

 

235,879

 

291,827

 

Loss from discontinued operations (1)

 

(187,174

)

(5,328

)

(177,163

)

Net income

 

164,425

 

230,551

 

114,664

 

Less: Net income attributable to noncontrolling interests

 

(4,152

)

(4,134

)

(6,163

)

Net income attributable to Buckeye Partners, L.P.

 

$

160,273

 

$

226,417

 

$

108,501

 

Earnings (loss) per unit - diluted

 

 

 

 

 

 

 

Continuing operations

 

$

3.23

 

$

2.37

 

$

3.15

 

Discontinued operations

 

$

(1.74

)

$

(0.05

)

$

(1.95

)

 


(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 its 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.

 

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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,

 

 

 

2013

 

2012

 

2011

 

Adjusted EBITDA from continuing operations:

 

 

 

 

 

 

 

Pipelines & Terminals

 

$

471,091

 

$

409,541

 

$

361,018

 

Global Marine Terminals

 

149,740

 

128,581

 

112,996

 

Merchant Services

 

12,616

 

1,144

 

1,797

 

Development & Logistics

 

15,367

 

13,174

 

7,932

 

Adjusted EBITDA from continuing operations

 

$

648,814

 

$

552,440

 

$

483,743

 

 

 

 

 

 

 

 

 

Reconciliation of Income from continuing operations to Adjusted EBITDA and Distributable Cash Flow:

 

 

 

 

 

 

 

Income from continuing operations

 

$

351,599

 

$

235,879

 

$

291,827

 

Less: Net income attributable to non-controlling interests

 

(4,152

)

(4,134

)

(6,163

)

Income from continuing operations attributable to Buckeye Partners, L.P.

 

347,447

 

231,745

 

285,664

 

Add: Interest and debt expense

 

130,920

 

114,980

 

119,561

 

Income tax expense (benefit)

 

1,060

 

(675

)

(192

)

Depreciation and amortization

 

147,591

 

138,857

 

112,398

 

Non-cash unit-based compensation expense

 

21,013

 

18,577

 

8,601

 

Asset impairment expense

 

 

59,950

 

 

Hess acquisition and transition expense

 

11,806

 

 

 

Less: Amortization of unfavorable storage contracts (1)

 

(11,023

)

(10,994

)

(7,562

)

Gain on sale of equity investment

 

 

 

(34,727

)

Adjusted EBITDA from continuing operations

 

648,814

 

552,440

 

483,743

 

Less: Interest and debt expense, excluding amortization of deferred financing costs, debt discounts and other

 

(122,471

)

(111,511

)

(111,941

)

Income tax expense, excluding non-cash taxes

 

(717

)

(1,095

)

(6

)

Maintenance capital expenditures

 

(71,476

)

(54,070

)

(57,251

)

Distributable cash flow from continuing operations

 

$

454,150

 

$

385,764

 

$

314,545

 

 


(1)         Represents the amortization of the negative fair values allocated to certain unfavorable storage contracts acquired in connection with the BORCO acquisition.

 

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The following table presents product volumes transported and average daily throughput for the Pipelines & Terminals segment and total volumes sold for the Merchant Services segment for the periods indicated:

 

 

 

Year Ended December 31,

 

 

 

2013

 

2012

 

2011

 

Pipelines & Terminals (average bpd in thousands):

 

 

 

 

 

 

 

Pipelines:

 

 

 

 

 

 

 

Gasoline

 

717.8

 

701.9

 

668.1

 

Jet fuel

 

334.4

 

339.2

 

340.6

 

Middle distillates (1)

 

345.7

 

318.6

 

327.0

 

Other products (2)

 

28.5

 

25.9

 

22.4

 

Total pipelines throughput

 

1,426.4

 

1,385.6

 

1,358.1

 

Terminals:

 

 

 

 

 

 

 

Products throughput (3)

 

975.1

 

916.7

 

756.0

 

 

 

 

 

 

 

 

 

Merchant Services (in millions of gallons):

 

 

 

 

 

 

 

Sales volumes (4)

 

1,371.5

 

1,125.9

 

1,337.8

 

 


(1)         Includes diesel fuel and heating oil.

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

(3)         Amounts for 2013, 2012 and 2011 include throughput volumes at terminals acquired from Hess, BP and ExxonMobil on December 11, 2013, June 1, 2011 and July 19, 2011, respectively.

(4)         Amounts for 2013 and 2012 include volumes related to fuel oil supply and distribution services which began in late 2012.

 

            Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

 

Consolidated

 

Adjusted EBITDA was $648.8 million for the year ended December 31, 2013, which is an increase of $96.4 million, or 17.4%, from $552.4 million for the corresponding period in 2012.  The increase in Adjusted EBITDA was primarily related to positive contributions from increased pipeline and terminalling volumes directly attributable to growth capital spending and higher blending capabilities, particularly butane blending, in the Pipelines & Terminals segment and increased storage capacity at and customer utilization of our BORCO facility in the Global Marine Terminals segment.  In addition, higher margins in the Merchant Services segment were primarily due to lower product costs resulting from risk management activities and the generation of RINs.

 

Revenue was $5,054.1 million for the year ended December 31, 2013, which is an increase of $768.2 million, or 17.9%, from $4,285.9 million for the corresponding period in 2012.  The increase in revenue was primarily related to new fuel oil supply and distribution services in the Caribbean and increased product sales volumes in our Merchant Services segment.  In addition, revenue in our Pipelines & Terminals segment increased as a result of increased pipeline and terminalling volumes directly attributable to our growth capital spending and higher butane blending capabilities.  Our Global Marine Terminals segment benefitted from incremental storage capacity brought online at our BORCO facility.

 

Operating income was $478.0 million for the year ended December 31, 2013, which is an increase of $133.5 million, or 38.7%%, from $344.5 million the corresponding period in 2012.  The increase in operating income was primarily related to increased pipeline and terminalling volumes directly attributable to our growth capital spending and diversification initiatives, as well as a non-cash asset impairment charge in 2012 in the Pipelines & Terminals segment. In addition, higher margins and lower operating costs in our Merchant Services segment contributed to our overall increase in operating income.  These increases in operating income were offset by increased operating and depreciation expense largely attributable to the capacity expansion completed and brought online in the Global Marine Terminals segment.

 

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Distributable cash flow was $454.2 million for the year ended December 31, 2013, which is an increase of $68.4 million, or 17.7%, from $385.8 million for the corresponding period in 2012.  The increase in distributable cash flow was primarily related to an increase of $96.4 million in Adjusted EBITDA as described above, partially offset by an increase in maintenance capital expenditures of $17.4 million and increase in interest expense of $11.0 million related to long-term debt issuances in 2013, including the debt issued in the fourth quarter of 2013 to partially fund the Hess Terminals acquisition.

 

Adjusted EBITDA by Segment

 

Pipelines & Terminals.  Adjusted EBITDA from the Pipelines & Terminals segment was $471.1 million for the year ended December 31, 2013, which was an increase of $61.6 million, or 15.0%, from $409.5 million for the corresponding period in 2012.  The positive factors impacting Adjusted EBITDA were related to $49.6 million of incremental revenue from capital investments in internal growth and diversification initiatives, including expanded butane blending capabilities, crude-handling services, as well as storage and throughput of other hydrocarbons, a $17.8 million increase in revenue due to higher pipeline and terminalling volumes on our legacy assets, $6.9 million increase in revenue resulting from an increase in pipeline capacity rentals, terminalling storage contracts and throughput and storage revenue at the terminals acquired from Hess in December 2013, $5.6 million more of favorable settlement experience despite the successful resolution of a $10.6 million product settlement allocation matter in 2012 and a $0.7 million increase in earnings due to the purchase of an additional ownership interest in WesPac Memphis in the second quarter of 2013.

 

The negative factors impacting Adjusted EBITDA were a $16.9 million increase in operating expenses, primarily related to higher operating costs due to internal growth and pipeline integrity costs, a $1.2 million decrease in revenue due to lower average pipeline tariff rates resulting from shorter-haul shipments and a $0.9 million decrease in earnings from equity investments due to higher maintenance costs.

 

Pipeline volumes increased by 2.9% due to stronger demand for gasoline and middle distillates resulting from changes in regional production and supply, partially offset by the idling of a portion of our NORCO pipeline system in early 2013.  Terminalling volumes increased by 6.4% due to higher demand for gasoline, distillates and other hydrocarbons, resulting from new customer contracts and service offerings at select locations, effective commercialization of acquired assets, continued positive contribution from our recently completed internal growth projects and favorable market conditions.

 

Global Marine Terminals.  Adjusted EBITDA from the Global Marine Terminals segment was $149.7 million for the year ended December 31, 2013, which was an increase of $21.1 million, or 16.4%, from $128.6 million for the corresponding period in 2012.  The positive factors impacting Adjusted EBITDA were a $28.9 million increase in storage revenue primarily as a result of incremental storage capacity brought online at our BORCO facility and assets acquired from Hess in December 2013 and a $5.3 million increase in revenues from ancillary services due to increased customer utilization of our facilities.  Ancillary services include the berthing of ships at our jetties and heating services.

 

The increase in revenue was offset by a $13.1 million increase in operating expenses primarily due to increased costs necessary to operate the expanded capabilities of the BORCO facility, one-time costs related to certain organizational changes in the second quarter of 2013 and costs associated with taking certain tankage out of service for maintenance activities and project work to improve the capabilities for handling anticipated heavy crude volumes.

 

Merchant Services.  Adjusted EBITDA from the Merchant Services segment was $12.6 million for the year ended December 31, 2013, which was an increase of $11.5 million from $1.1 million for the corresponding period in 2012.  In 2012, we developed and executed a strategy to mitigate basis risk that included the reduction of refined petroleum product inventories in the Midwest.  In 2013, we continued to benefit from the execution of our strategy, which included focusing on fewer, more strategic locations in which to transact business, better managing our inventories and reducing the cost structure of the business.  Sales volumes increased as we executed this strategy.  In addition, beginning in late 2012, the segment began to provide fuel oil supply and distribution services to third parties in the Caribbean.  This activity has also contributed to our increase in sales volumes for the period.  Furthermore, we benefited from improved rack margins, largely the result of risk management activities to lower product costs, and the generation of RINs, which are tradable “credits” generated by blending biofuels into finished gasoline or diesel products.

 

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The increase in Adjusted EBITDA was primarily related to a $651.4 million increase in revenue, which included a $728.4 million increase due to 21.8% of higher sales volumes, offset by a $77.0 million decrease as a result of a $0.06 per gallon decrease in refined petroleum product sales price (average sales prices per gallon were $2.91 and $2.97 for the 2013 and 2012 periods, respectively) and a $0.8 million decrease in operating expenses primarily related to overhead costs.

 

The increase in revenue was partially offset by a $640.7 million increase in cost of product sales, which included a $725.3 million increase due to 21.8% of higher sales volumes, offset by a $84.6 million decrease as a result of a $0.06 per gallon decrease in refined petroleum product cost price (average cost prices per gallon were $2.89 and $2.95 for the 2013 and 2012 periods, respectively).

 

Development & Logistics.  Adjusted EBITDA from the Development & Logistics segment was $15.4 million for the year ended December 31, 2013, which was an increase of $2.2 million, or 16.6%, from $13.2 million for the corresponding period in 2012.  The increase in Adjusted EBITDA was primarily due to an $8.1 million increase in third-party engineering and operations revenue as a result of new contracts and higher fees and a $0.9 million increase in revenue related to the LPG storage caverns, partially offset by a $6.0 million increase in third-party engineering and operations expense and a $0.8 million increase in operating expenses, which primarily related to overhead costs.

 

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

 

Consolidated

 

Adjusted EBITDA was $552.4 million for the year ended December 31, 2012, which is an increase of $68.7 million, or 14.2%, from $483.7 million for the corresponding period in 2011. The increase in Adjusted EBITDA was primarily related to positive contribution as a result of a full period of operating activities for 2011 acquisitions, the benefit of contributions from growth capital spending and higher blending capabilities, particularly butane blending, in the Pipelines & Terminals segment, as well as increased storage capacity and customer utilization of our BORCO facility in the Global Marine Terminals segment.

 

Revenue was $4,285.9 million for the year ended December 31, 2012, which is a decrease of $407.7 million, or 8.7%, from $4,693.6 million for the corresponding period in 2011. The decrease in revenue was primarily related to a net decrease in revenue in the Merchant Services segment, which was partially offset by the revenue generated due to a full period of operations for the 2011 acquisitions in the Pipelines & Terminals segment, as well as increased storage revenue as a result of 1.9 million barrels of incremental storage capacity brought online, the Perth Amboy Facility acquisition in 2012 and new service offerings providing fuel oil supply and distribution services in the Global Marine Terminals segment.

 

Operating income was $344.5 million for the year ended December 31, 2012, which is a decrease of $21.3 million, or 5.8%, from $365.8 million the corresponding period in 2011. The decrease in operating income was primarily related to a non-cash asset impairment charge in 2012 and an increase in depreciation and amortization due to the assets acquired in 2011 in the Pipelines & Terminals segment and the upgrades and expansions of the jetty structure in the Global Marine Terminals segment.  These decreases were partially offset by positive contribution as a result of a full period of operating activities for 2011 acquisitions in the Pipelines & Terminals segment.

 

Distributable cash flow was $385.8 million for the year ended December 31, 2012, which is an increase of $71.2 million, or 22.6%, from $314.5 million for the corresponding period in 2011. The increase in distributable cash flow was primarily related to an increase of $68.7 million in Adjusted EBITDA as described above.

 

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Adjusted EBITDA by Segment

 

Pipelines & Terminals. Adjusted EBITDA from the Pipelines & Terminals segment was $409.5 million for the year ended December 31, 2012, which was an increase of $48.5 million, or 13.4%, from $361.0 million for the corresponding period in 2011. The positive factors impacting Adjusted EBITDA were related to a $34.4 million increase in revenue due to a full period of operations for the assets acquired in 2011, a $31.7 million increase in revenue due to higher average pipeline tariff rates, resulting from tariff increases and long-haul shipments, and terminalling contract rate escalations on our legacy assets, $11.1 million of favorable settlement experience, a $7.9 million increase in revenue due to higher blending capabilities in the Northeast, particularly butane blending, and a $1.6 million increase in revenue due to higher terminalling volumes. The favorable settlement experience primarily related to the successful resolution of a $10.6 million product settlement allocation matter related to certain pipeline transportation-related services provided by Buckeye over a period of several years, of which $7.8 million related to services rendered in prior years but, for accounting purposes, was not recognized in revenue until the current period.

 

The negative factors impacting Adjusted EBITDA were a $12.1 million increase in operating expenses related to a full period of operations of the assets acquired in 2011, which included acquisition and transition expenses, a $8.5 million decrease in other revenue, resulting from a decrease in terminalling storage contracts primarily due to market backwardation of refined petroleum products, a $4.3 million decrease in earnings from equity investments primarily due to higher environmental remediation costs at West Shore and the sale of our interest in West Texas LPG Pipeline Limited Partnership in 2011, a $4.3 million increase in operating expenses, which included integrity program expenditures, payroll costs, operating power and utilities, insurance and environmental remediation expenses, $3.8 million in fees related to the FERC proceedings, $3.7 million increase in expenses related to the relocation of certain operations and administrative support functions to our Houston, Texas headquarters, and $1.5 million of fees related to the temporary suspension of ethanol offloading capabilities at our Albany facility.

 

Overall pipeline and terminalling volumes increased by 2.0% and 21.3%, respectively, primarily as a result of the assets acquired in 2011. Legacy pipeline volumes declined marginally as a result of seasonal fluctuations in heating oil, a temporary shut-down of one of our pipelines for emergency maintenance, and business interruptions caused by Hurricane Sandy, offset by higher demand for gasoline. Legacy terminalling volumes increased by 1.6% due to higher demand for gasoline and distillates, new customer contracts and service offerings at select locations, including crude oil services and the benefit of contributions from growth capital spending.

 

Global Marine Terminals. Adjusted EBITDA from the Global Marine Terminals segment was $128.6 million for the year ended December 31, 2012, which was an increase of $15.6 million, or 13.8%, from $113.0 million for the corresponding period in 2011. The positive factors impacting Adjusted EBITDA were primarily related to a $9.8 million increase in revenue due to the Perth Amboy Facility acquired in 2012, a $7.9 million decrease in acquisition and transition expenses, a $6.0 million increase in storage revenue as a result of 1.9 million barrels of incremental storage capacity brought online, a $5.0 million increase in ancillary revenues, including berthing, which represents ships that utilize the jetties, and heating services due to increased customer utilization of our facilities and $1.7 million decrease in income allocated to non-controlling interests related to the remaining 20% ownership interest in BORCO not acquired by us until February 16, 2011.

 

The increase in revenue was partially offset by a $14.8 million increase in operating expenses primarily as a result of increased customer utilization of our facilities, increased costs necessary to operate the expanded facilities and the Perth Amboy Facility acquired in 2012.

 

Merchant Services. Adjusted EBITDA from the Merchant Services segment was $1.1 million for the year ended December 31, 2012, which was a decrease of $0.7 million, or 36.3%, from $1.8 million for the corresponding period in 2011. In early 2012, we developed and executed a strategy to mitigate basis risk, which included the reduction of refined petroleum product inventories in the Midwest. As a result, losses generated from the execution of our strategy contributed to the decrease in Adjusted EBITDA. During the period, we continued to aggressively manage our inventory levels and reduce our exposure to market backwardation, despite sustained adverse market conditions. In addition, we had a $2.2 million decrease in biodiesel tax credits, which are recorded as a reduction of cost of sales. In early 2013, legislative changes resulted in retroactive recognition of biodiesel tax credits for year 2012.

 

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The decrease in Adjusted EBITDA was primarily related to a $549.7 million decrease in revenue, which included a $616 million decrease due to 15.8% of lower sales volumes, offset by a $66.3 million increase as a result of a $0.06 per gallon increase in refined petroleum product sales price (average sales prices per gallon were $2.97 and $2.91 for the 2012 and 2011 periods, respectively).

 

The decrease in revenue was partially offset by a $546.6 million decrease in cost of product sales, which included a $613.2 million decrease due to 15.8% of lower sales volumes, offset by $66.6 million increase as a result of a $0.06 per gallon increase in refined petroleum product cost price (average cost prices per gallon were $2.95 and $2.89 for the 2012 and 2011 periods, respectively) and a $2.4 million decrease in operating expenses primarily related to overhead costs.

 

Development & Logistics. Adjusted EBITDA from the Development & Logistics segment was $13.2 million for the year ended December 31, 2012, which was an increase of $5.2 million, or 66.1%, from $7.9 million for the corresponding period in 2011. The increase in Adjusted EBITDA was primarily due to a $4.5 million increase in revenue related to the LPG storage caverns acquired in November 2011, a $2.6 million increase in third-party engineering and operations revenue as a result of new contracts and higher fees, partially offset by a $0.8 million increase in third-party engineering and operations expense, a $0.6 million increase in operating expenses for the LPG storage caverns and a $0.5 million increase in operating expenses, which primarily related to overhead costs.

 

General Outlook for 2014

 

Overall, we continue to expect growth capital investments in our businesses to drive meaningful improvement in year-over-year performance.  There are numerous projects currently underway that we expect to be completed in 2014 and contribute incremental cash flow.  Our Perth Amboy transformation efforts continue.  We expect the pipeline connection from our Perth Amboy and Port Reading marine terminals to our Linden facility, which throughputs over 0.5 million barrels per day to Buckeye’s eastern system and serves Western Pennsylvania and Upstate New York, to be operational early in the second quarter.  In addition, the crude rail loading and unloading facility is expected to be completed in mid-2014.  This facility will provide customers with the optionality to unload crude rail cars and deliver product via truck, barge, ship or pipeline.  In addition, various storage tank and manifold improvements are expected to be completed at the facility to service Chevron and other customers and to drive incremental revenues.

 

At our Chicago Complex, which is our Midwestern hub, we are constructing 1.1 million barrels of crude storage for a large customer to provide flexibility in supply for a refinery.  We expect this storage to be operational in the second half of 2014.  We are also expanding the pipeline connectivity at the Chicago Complex to allow greater transshipment capability, which will allow us to meet peak demand and provide more product diversification capabilities for our customers.  In addition, this increased connectivity will allow us to offer additional refined products storage capacity at the Complex.

 

Expansion of our butane blending capabilities across our system is also planned for 2014.  We intend to increase the number of locations with the ability to blend butane domestically, including certain of the newly acquired Hess terminals, and internationally at our BORCO facility.  We expect butane to continue to be a strong earnings contributor for Buckeye as we do not foresee any significant disruptions in the margin opportunities for butane.

 

Integration of the 20 terminals acquired from Hess remains a top priority for Buckeye into 2014.  We are pleased with the early results from these assets and remain confident we will be able to meet our integration plan.

 

We expect our Merchant Services segment to play an important role in driving higher utilization across our system.  This segment will be an important catalyst as we look to optimize waterborne supply for the new marine terminals acquired from Hess.   In addition, we are exploring additional opportunities for this business to serve our other Pipelines & Terminals and Global Marine Terminals assets.

 

We do not expect any significant change in macro-economic demand for petroleum products in the markets we serve absent a significant change in the economy.  Volumes on our pipeline systems and terminals are expected to experience moderate growth, primarily the result of capital projects.  Tariffs growth is expected on both our market-based and index-based system.  Tariffs on our pipelines serving the New York City airports remain subject to the ongoing FERC matter.

 

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We continue to look for ways to provide new solutions for our customers by leveraging our existing asset footprint.  Ultimately, our ability to increase transportation and storage revenues is largely dependent on the strength of the overall economy in the markets we serve.

 

We believe that, under current market conditions, we could raise additional capital in both the debt and equity markets on acceptable terms.  This could include utilizing the at-the-market equity issuance program, which is the most cost-efficient means to raise equity if necessary.

 

We will continue to evaluate opportunities throughout 2014 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 for any opportunity we pursue.

 

We expect to divest our non-core Natural Gas Storage business during 2014 and will reflect the financial results of this business as discontinued operations.

 

The forward-looking statements contained in this “General Outlook for 2014” 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 2014” 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 partners.  Our principal sources of liquidity are cash from continuing operations, borrowings under our Credit Facility and proceeds from the issuance of our units.  We will, from time to time, issue debt securities to permanently finance amounts borrowed under our Credit Facility.  Buckeye Energy Services LLC (“BES”) funds its working capital needs principally from its operations and its portion of the Credit Facility.  Our fuel oil supply and distribution services in the Caribbean are additionally funded principally from their own operations and the 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, 2013, we had $216.0 million of working capital (including net assets held for sale of $143.9 million) and $995 million of availability under our Credit Facility but, except for borrowings that are used to refinance other debt, we are limited to $961.9 million of additional borrowing capacity by the financial covenants under our Credit Facility.

 

Capital Structuring Transactions

 

As part of our ongoing efforts to maintain a capital structure that is closely aligned with the cash-generating potential of our asset-based business, we may explore additional sources of external liquidity, including public or private debt or equity issuances.  Matters to be considered will include cash interest expense and maturity profile, all to be balanced with maintaining adequate liquidity.  We have a universal shelf registration statement that does not place any dollar limits on the amount of debt and equity securities that we may issue thereunder and a traditional shelf registration statement on file with the SEC under which we may issue equity securities with a value, as of December 31, 2013, not to exceed $716.5 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.

 

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

 

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 to Buckeye.  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, 2013, we had the following debt obligations (in thousands):

 

5.300% Notes due October 15, 2014

 

275,000

 

5.125% Notes due July 1, 2017

 

125,000

 

6.050% Notes due January 15, 2018

 

300,000

 

2.650% Notes due November 15, 2018

 

400,000

 

5.500% Notes due August 15, 2019

 

275,000

 

4.875% Notes due February 1, 2021

 

650,000

 

4.150% Notes due July 1, 2023

 

500,000

 

6.750% Notes due August 15, 2033

 

150,000

 

5.850% Notes due November 15, 2043

 

400,000

 

BPL Credit Facility due September 26, 2017

 

255,000

 

Total debt

 

$

3,330,000

 

 

It is our intent to refinance the 5.300% Notes in 2014.  If necessary, the $275 million of 5.300% Notes maturing on October 15, 2014 could be refinanced using our Credit Facility.  At December 31, 2013, we had $995 million of availability under our Credit Facility but, except for borrowings that are used to refinance other debt, we are limited to $961.9 million of additional borrowing capacity by the financial covenants under our Credit Facility.  Additionally, we expect to pay to settle interest rate swaps with a fair value as of December 31, 2013 of $30 million relating to the refinancing of the 5.300% Notes on or before October 15, 2014.

 

In November 2013, we issued an aggregate of $800 million of senior unsecured notes, including $400 million of 2.650% Notes due November 15, 2018 and $400 million of 5.850% Notes due November 15, 2043, at 99.823% and 98.581% of their principal amounts, respectively.  Total proceeds from this offering, after underwriting fees, expenses and debt issuance costs of $5.9 million, were $787.7 million. We used the net proceeds from this offering to fund the Hess Terminals Acquisition and for general partnership purposes.

 

In August 2013, we extended the maturity date of our Credit Facility by one year to September 26, 2017, which we may further extend for up to one additional year.

 

In June 2013, we issued $500 million of senior unsecured 4.150% Notes due July 1, 2023 in an underwritten public offering at 99.81% of their principal amount.  Total proceeds from this offering, after underwriting fees, expenses and debt issuance costs of $3.3 million, were $495.8 million.  We used the net proceeds from this offering for general partnership purposes and to repay amounts due under our Credit Facility, a portion of which was subsequently reborrowed in July 2013 in order to repay in full the 4.625% Notes and related accrued interest.  We also settled all interest rate swaps relating to the 4.150% Notes for $62 million during June 2013.

 

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Equity

 

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 million before deducting underwriting fees and estimated 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 May 2013, we entered into four separate equity distribution agreements under which 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.  See related discussion in “Recent Developments” for additional information.  During the year ended December 31, 2013, we sold 0.5 million LP Units in aggregate under the Equity Distribution Agreements, received $33.1 million in net proceeds after deducting commissions and other related expenses, and paid $0.4 million of compensation in aggregate to the agents under the Equity Distribution Agreements.

 

In January 2013, we completed a public offering of 6 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.

 

Cash Flows from Operating, Investing and Financing Activities

 

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

 

 

 

Year Ended December 31,

 

 

 

2013

 

2012

 

2011

 

Cash provided by (used in):

 

 

 

 

 

 

 

Operating activities

 

$

385,494

 

$

441,636

 

$

403,892

 

Investing activities

 

(1,204,678

)

(590,322

)

(1,310,279

)

Financing activities

 

817,358

 

142,476

 

905,747

 

 

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Operating Activities

 

2013Net 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 million settlement to terminate the interest rate swap agreements related to the 4.150% Notes, a $60.8 million increase in trade receivables and an increase in interest and debt expense.

 

2012. Net cash provided by operating activities was $441.6 million for the year ended December 31, 2012, primarily related to $230.6 million of net income, $146.4 million of depreciation and amortization and $39.1 million associated with a reduction in inventory, partially offset by an increase of $53.5 million in trade receivables.  In 2012, we developed and executed a strategy to mitigate our basis risk that included the reduction of refined petroleum product inventories in the Midwest.

 

2011.  Net cash provided by operating activities was $403.9 million for the year ended December 31, 2011, primarily related to $114.7 million of net income, $119.5 million of depreciation and amortization and $102.5 million associated with a reduction in inventory, partially offset by an increase of $29.7 million in trade receivables.

 

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

 

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.

 

2012.  Net cash used in investing activities of $590.3 million for the year ended December 31, 2012 primarily related to $331.3 million of capital expenditures and a $260.3 million acquisition of the Perth Amboy Facility.

 

2011Net cash used in investing activities of $1,310.3 million for the year ended December 31, 2011 primarily related to a $1.4 billion acquisition of BORCO, of which $893.7 million was paid in cash, net of cash acquired and the remaining consideration in issuance of LP Units and Class B Units, a $166 million acquisition of pipeline and terminal assets and $305.3 million of capital expenditures, which were partially offset by $85 million of cash proceeds from the sale of our 20% interest in West Texas LPG Pipeline Limited Partnership.

 

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

 

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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 facilities and related assets, and “expansion and cost reduction capital expenditures” to expand the reach or capacity of those assets, to improve the efficiency of our operations and to pursue new business opportunities.  Capital expenditures, excluding non-cash changes in accruals for capital expenditures, were as follows for the periods indicated (in thousands):

 

 

 

Year Ended December 31,

 

 

 

2013

 

2012

 

2011

 

Maintenance capital expenditures (1)

 

$

71,595

 

$

54,425

 

$

57,467

 

Expansion and cost reduction (2)

 

289,850

 

276,913

 

247,857

 

Total capital expenditures, net

 

$

361,445

 

$

331,338

 

$

305,324

 

 


(1)         Includes maintenance capital expenditures related to the Natural Gas Storage disposal group of $0.1 million, $0.4 million and $0.2 million, respectively, for the years ended December 31, 2013, 2012 and 2011.

(2)         Includes expansion and cost reduction capital expenditures related to the Natural Gas Storage disposal group of $0.1 million, $2 million and $9.9 million, respectively, for the years ended December 31, 2013, 2012 and 2011.

 

In 2013, maintenance capital expenditures included pump replacements and truck rack infrastructure upgrades, as well as pipeline and tank integrity work.  Expansion and cost reduction capital expenditures included significant investments in storage tank expansion at BORCO and Perth Amboy, butane blending, rail offloading facilities, crude storage/transportation and various other cost reduction and revenue generating projects.

 

In 2012, maintenance capital expenditures included terminal pump replacements and truck rack infrastructure upgrades, as well as pipeline and tank integrity work, and expansion and cost reduction projects included initiation of a significant storage tank expansion project as well as upgrades and expansion of a jetty structure and inland dock at BORCO, terminal ethanol and butane blending, new pipeline connections, transformation of our Albany marine terminal to handle crude services via rail and ship, new natural gas storage wells, continued progress on a new pipeline and terminal billing system as well as various other operating infrastructure projects.

 

In 2011, maintenance capital expenditures included pipeline and tank integrity work, and expansion and cost reduction projects included terminal ethanol and butane blending, new pipeline connections, natural gas storage well recompletions, continued progress on a new pipeline and terminal billing system as well as various other operating infrastructure projects, Kirby Hills Phase II expansion project, the construction of three additional tanks with capacity of 0.4 million barrels in Linden, New Jersey and various other pipeline and terminal operating infrastructure projects.

 

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

 

 

 

2014

 

 

 

Low

 

High

 

Pipelines & Terminals:

 

 

 

 

 

Maintenance capital expenditures

 

$

60,000

 

$

70,000

 

Expansion and cost reduction

 

250,000

 

270,000

 

Total capital expenditures

 

$

310,000

 

$

340,000

 

 

 

 

 

 

 

Global Marine Terminals:

 

 

 

 

 

Maintenance capital expenditures

 

$

20,000

 

$

30,000

 

Expansion and cost reduction

 

30,000

 

40,000

 

Total capital expenditures

 

$

50,000

 

$

70,000

 

 

 

 

 

 

 

Overall:

 

 

 

 

 

Maintenance capital expenditures

 

$

80,000

 

$

100,000

 

Expansion and cost reduction

 

280,000

 

310,000

 

Total capital expenditures

 

$

360,000

 

$

410,000

 

 

Estimated maintenance capital expenditures include tank floor and roof upgrades, cathodic protection upgrades, pipeline replacements, prover and meter upgrades, electrical infrastructure upgrades, terminal and station upgrades, dock upgrades and instrumentation and controls upgrades.  Estimated major expansion and cost reduction expenditures include: completion of additional storage tanks and truck loading rack upgrades; rail offloading facilities and the refurbishment of storage tanks across our system; continued installation of vapor recovery units throughout our system of terminals; and various upgrades and expansions of our butane blending business.  In connection with our Perth Amboy Facility, our estimated expansion and cost reduction expenditures include completion of a new crude rail offloading system; completion of a bi-directional pipeline; conversion of tanks for distillate and gasoline storage; completion of a multi-product blend and transfer piping manifold; and completion of a new 16-inch pipeline allowing direct access to our existing pipeline infrastructure.  Also, estimated expansion and cost reduction expenditures include costs for the terminals acquired in the Hess Terminals Acquisition.

 

Financing Activities

 

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 million of net proceeds from the issuance of an aggregate 16 million LP Units, partially offset by $655.8 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 million related to the repayment of the 4.625% Notes.

 

2012.  Net cash flows provided by financing activities of $142.5 million for the year ended December 31, 2012 primarily related to $296 million of net borrowings under the Credit Facility and $246.8 million of net proceeds from the issuance of 4.3 million LP Units, partially offset by $371.2 million ($4.15 per LP Unit) of cash distributions paid to our unitholders.

 

2011Net cash flows provided by financing activities of $905.7 million for the year ended December 31, 2011 primarily related to $736.9 million of net proceeds from the issuance of 11.3 million LP Units and 1.3 million Class B Units, $647.5 million from the issuance of the 4.875% Notes, and $192.9 million of net borrowings under the Credit Facility, partially offset by $335.7 million ($4.025 per LP Unit) of cash distributions paid to our unitholders and $318.2 million repayment of debt assumed and settlement of interest rate derivative instruments relating to the BORCO acquisition.

 

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For further discussion on our equity offerings, see Note 23 in the Notes to Consolidated Financial Statements.

 

Contractual Obligations

 

The following table summarizes our contractual obligations as of December 31, 2013 (in thousands):

 

 

 

Payments Due by Period

 

 

 

 

 

Less than 1

 

 

 

 

 

More than 5

 

 

 

Total

 

year

 

1-3 years

 

3-5 years

 

years

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term debt (1)

 

$

3,104,000

 

$

275,000

 

$

 

$

854,000

 

$

1,975,000

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest payments (2) (3)

 

1,579,589

 

151,988

 

281,056

 

247,179

 

899,366

 

Operating leases:

 

 

 

 

 

 

 

 

 

 

 

Office space and other

 

26,392

 

3,551

 

7,395

 

6,819

 

8,627

 

Equipment (4) 

 

3,314

 

3,314

 

 

 

 

Land leases (5) (7)

 

127,634

 

2,863

 

5,700

 

5,700

 

113,371

 

Purchase obligations (6) (7)

 

132,851

 

132,851

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total contractual obligations

 

$

4,973,780

 

$

569,567

 

$

294,151

 

$

1,113,698

 

$

2,996,364

 

 


(1)         Includes long-term debt portion borrowed by Buckeye 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)         Excludes estimates of the effect of our interest rate swap related to forecasted interest payments, which as of December 31, 2013, had a fair value of $30 million. We expect to settle this swap on or about October 15, 2014.

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

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

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

(7)         Excludes land leases and short-term purchase and payment obligations related to our Natural Gas Storage disposal group.

 

For the year ended 2014, our rights-of-way payments are expected to be $6.3 million, which includes 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.

 

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All Services Company stock has been allocated to ESOP participants.  See Note 21 in the Notes to Consolidated Financial Statements for further information.

 

Off-Balance Sheet Arrangements

 

At December 31, 2013 and 2012, we had no off-balance sheet debt or arrangements.

 

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 the Partnership’s 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:

 

Business Combinations

 

We allocate the total purchase price of a business combination to the assets acquired and the liabilities assumed based on their estimated fair values at the acquisition date, with the excess purchase price recorded as goodwill. An income, market or cost valuation method may be utilized to estimate the fair value of the assets acquired or liabilities assumed in a business combination.  The income valuation method represents the present value of future cash flows over the life of the asset using (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses, (ii) long-term growth rates and (iii) appropriate discount rates.  The market valuation method uses prices paid for a reasonably similar asset by other purchasers in the market, with adjustments relating to any differences between the assets.  The cost valuation method is based on the replacement cost of a comparable asset at prices at the time of the acquisition reduced for depreciation of the asset.

 

Valuation of Goodwill

 

Goodwill represents the excess of purchase price over fair value of net assets acquired. Our goodwill amounts are assessed for impairment (i) on an annual basis on January 1 of 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.

 

For our annual goodwill impairment test as of January 1, 2014, we performed a qualitative assessment to determine whether the fair value of the Pipelines & Terminals reporting unit was more likely than not less than the carrying value.  Based on our assessment, the Pipelines & Terminals reporting unit had (i) a substantial excess of fair value over carrying value in its latest quantitative assessment, (ii) continued positive performance in Adjusted EBITDA over prior year, (iii) projected increases in Adjusted EBITDA primarily as a result of contributions from internal capital projects and accretive acquisitions, and (iv) positive industry and market factors.  We determined that the fair value of the reporting unit exceeded the carrying amount; therefore, the two-step impairment test was not required.

 

Additionally, we performed quantitative assessments to determine the fair value of each of the remaining 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, 2013 and 2012.  During the year ended December 31, 2011, we recorded a non-cash goodwill impairment charge of $169.6 million in our former Natural Gas Storage segment.

 

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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.  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 cash flows are highly subjective and are based on numerous assumptions about future operations and market conditions.

 

During the fourth quarter of 2013, our Board of Directors approved a plan to divest our Natural Gas Storage segment and its related assets as we no longer believe this business is aligned with our long-term business strategy.  In connection with this strategic divestiture, we recorded a $169 million non-cash asset impairment charge included in our loss on discontinued operations on our consolidated statement of operations for the year ended December 31, 2013.

 

Our current marketing initiative and fair value estimate are based on the Natural Gas Storage disposal group operating as a combined natural gas and compressed air energy storage facility, as geological evidence indicates that the formation and deliverability of the facility are capable of providing both services.  We believe the combined services are more valuable to market participants (i.e. load-serving entities) that are subject to the California Public Utility Commissions’ requirement to own specific amounts of energy storage by 2024, in accordance with state law Assembly Bill 2514.  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.  Sensitivity to changes in commodity prices and discount rates could have a material impact on our fair value estimate.

 

During the fourth quarter of 2012, we recorded a $60 million non-cash asset impairment charge in the Pipelines & Terminals segment relating to a portion of Buckeye’s NORCO pipeline system.  During 2011, we considered the goodwill impairment in our former Natural Gas Storage segment an indicator of impairment related to the long-lived assets associated with the Natural Gas Storage reporting unit.  Accordingly, we evaluated the former Natural Gas Storage assets for impairment and concluded that no impairment of the long-lived assets existed at that time.  See Note 5 and 11 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, 2013, 2012 or 2011.

 

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.

 

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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.  The futures contracts used to hedge refined petroleum product inventories are designated as fair value hedges with changes in fair value of both the futures contracts and physical inventory reflected in earnings.  Physical contracts and futures contracts that have not been designated in a hedge relationship are marked-to-market.

 

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.

 

Additionally, we utilize forward-starting interest rate swaps to manage interest rate risk related to forecasted interest payments on anticipated debt issuances.  When entering into interest rate swap transactions, we are exposed to both credit risk and market risk.  We manage our credit risk by entering into swap transactions only with major financial institutions with investment-grade credit ratings.  We manage our market risk by aligning the swap instrument with the existing underlying debt obligation or a specified expected debt issuance generally associated with the maturity of an existing debt obligation.  The fair value of the swap instruments are calculated by discounting the future cash flows of both the fixed rate and variable rate interest payments using appropriate discount rates with consideration given to our non-performance risk.

 

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk

 

Market Risk — Trading Instruments

 

We have no trading derivative instruments.

 

Market Risk — Non-Trading Instruments

 

We are exposed to financial market risks, including changes in commodity prices and interest rates.  The primary factors affecting our market risk and the fair value of our derivative portfolio at any point in time are the volume of open derivative positions, changing refined petroleum commodity prices, and prevailing interest rates for our interest rate swaps.  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.

 

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

 

 

 

Commodity

 

Interest

 

 

 

 

 

Instruments

 

Rate Swaps

 

Total

 

 

 

 

 

 

 

 

 

Fair value of contracts outstanding at January 1, 2013

 

$

(8,439

)

$

(130,636

)

$

(139,075

)

Items recognized or settled during the period

 

(4,304

)

62,873

 

58,569

 

Fair value attributable to new deals

 

(6,485

)

 

(6,485

)

Change in fair value attributable to price movements

 

8,999

 

37,718

 

46,717

 

Change in fair value attributable to non-performance risk

 

14

 

 

14

 

Fair value of contracts outstanding at December 31, 2013

 

$

(10,215

)

$

(30,045

)

$

(40,260

)

 

Commodity Price Risk

 

Merchant Services

 

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.  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, 2013, the estimated fair value would be as follows (in thousands):

 

 

 

Resulting

 

 

 

Scenario

 

Classification

 

Fair Value

 

Fair value assuming no change in underlying commodity prices (as is)

 

Asset

 

$

280,502

 

Fair value assuming 10% increase in underlying commodity prices

 

Asset

 

284,166

 

Fair value assuming 10% decrease in underlying commodity prices

 

Asset

 

276,838

 

 

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Interest Rate Risk

 

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

 

Our practice with respect to derivative transactions related to interest rate risk has been to have each transaction in connection with non-routine borrowings authorized by the Board of Directors of Buckeye GP.  In February 2009, Buckeye GP’s Board of Directors 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, Buckeye GP’s Board of Directors 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.

 

Based on a hypothetical 10% movement in the underlying interest rates at December 31, 2013, the estimated fair value of the interest rate derivative contracts would be as follows (in thousands):

 

 

 

Resulting

 

 

 

Scenario

 

Classification

 

Fair Value

 

Fair value assuming no change in underlying interest rates (as is)

 

Liability

 

$

(30,045

)

Fair value assuming 10% increase in underlying interest rates

 

Liability

 

(21,350

)

Fair value assuming 10% decrease in underlying interest rates

 

Liability

 

(38,760

)

 

See Note 17 in the Notes to Consolidated Financial Statements for additional discussion related to derivative instruments and hedging activities.

 

At December 31, 2013, we had total fixed-rate debt obligations under our Credit Facility at carrying value of $3,063.7 million.  Based on a hypothetical 1% movement in the underlying interest rates at December 31, 2013, the estimated fair value of our debt obligations would be as follows (in millions):

 

 

 

 

 

 

 

 

 

Fair Value of

 

 

 

Scenario

 

Fixed-Rate Debt

 

 

 

Fair value assuming no change in underlying interest rates (as is)

 

$

3,148.6

 

 

 

Fair value assuming 1% increase in underlying interest rates

 

2,961.6

 

 

 

Fair value assuming 1% decrease in underlying interest rates

 

3,358.9

 

 

 

 

At December 31, 2013, our variable-rate obligations were $255 million under the Credit Facility.  Based on the balance outstanding at December 31, 2013, we estimate that a 1% increase or decrease in interest rates would increase or decrease annual interest expense by $2.6 million.

 

 

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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 the consolidated statements of operations.  The effects of foreign currency transactions were not considered to be material for the years ended December 31, 2013, 2012 and 2011.

 

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Item  8.      Financial Statements and Supplementary Data

 

 

Page

 

 

 Management’s Report On Internal Control Over Financial Reporting

63

 

 

 Reports of Independent Registered Public Accounting Firm

64

 

 

 Consolidated Statements of Operations for the Years Ended December 31, 2013, 2012 and 2011

66

 

 

 Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2013, 2012 and 2011

67

 

 

 Consolidated Balance Sheets as of December 31, 2013 and 2012

68

 

 

 Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011

69

 

 

 Consolidated Statements of Partners’ Capital for the Years Ended December 31, 2013, 2012 and 2011

70

 

 

 Notes to Consolidated Financial Statements:

 

 1. Organization

71

 2. Summary of Significant Accounting Policies

71

 3. Acquisitions and Dispositions

82

 4. Discontinued Operations

86

 5. Asset Impairments

87

 6. Commitments and Contingencies

88

 7. Inventories

90

 8. Prepaid and Other Current Assets

91

 9. Property, Plant and Equipment

91

 10. Equity Investments

92

 11. Goodwill and Intangible Assets

94

 12. Other Non-Current Assets

95

 13. Accrued and Other Current Liabilities

96

 14. Long-Term Debt

97

 15. Other Non-Current Liabilities

100

 16. Accumulated Other Comprehensive Income (Loss)

100

 17. Derivative Instruments and Hedging Activities

100

 18. Fair Value Measurements

104

 19. Pensions and Other Postretirement Benefits

106

 20. Unit-Based Compensation Plans

111

 21. Employee Stock Ownership Plan

114

 22. Related Party Transactions

115

 23. Partners’ Capital and Distributions

115

 24. Income Taxes

119

 25. Earnings Per Unit

120

 26. Business Segments

121

 27. Supplemental Cash Flow Information

125

 28. Quarterly Financial Data (Unaudited)

126

 

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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 (“GAAP”) in the United States of America, 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, 2013.  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 (1992) (“COSO”).  As a result of this assessment and based on the criteria in the COSO framework, management has concluded that, as of December 31, 2013, the internal control over financial reporting of Buckeye was effective.

 

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

 

 

/s/ CLARK C. SMITH

 

/s/ KEITH E. ST.CLAIR

 

Clark C. Smith

 

Keith E. St.Clair

 

Chief Executive Officer, President and Director

Executive Vice President and Chief Financial Officer

 

 

 

 

February 26, 2014

 

 

 

 

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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, 2013, based on criteria established in Internal Control — Integrated Framework (1992) 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