10-K 1 d451347d10k.htm FORM 10-K Form 10-K
Table of Contents
Index to Financial Statements

 

 

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, 2012

OR

 

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

For the transition period from             to            

Commission file number 1-9356

 

 

Buckeye Partners, L.P.

(Exact name of registrant as specified in its charter)

 

Delaware   23-2432497

(State or other jurisdiction of

incorporation or organization)

 

(IRS Employer

Identification number)

One Greenway Plaza

Suite 600

Houston, TX

  77046
(Address of principal executive offices)   (Zip Code)

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

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

 

Title of each class

 

Name of each exchange on which registered

Limited partner units representing limited partnership interests   New York Stock Exchange

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

None

 

 

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

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  ¨    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  ¨

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  ¨

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

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

 

Large accelerated filer   x    Accelerated filer   ¨
Non-accelerated filer   ¨  (Do not check if a smaller reporting company)    Smaller reporting company   ¨

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

At June 30, 2012, the aggregate market value of the registrant’s limited partner units and Class B units held by non-affiliates was $5.0 billion. The calculation of such market value should not be construed as an admission or conclusion by the registrant that any person is in fact an affiliate of the registrant.

Limited partner units and Class B units outstanding as of February 19, 2013: 97,322,040 and 7,974,750, respectively.

 

 

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Proxy Statement being prepared for the solicitation of proxies in connection with the 2013 Annual Meeting of Limited Partners are incorporated by reference in Part III of this Form 10-K.

 

 

 


Table of Contents
Index to Financial Statements

TABLE OF CONTENTS

          Page  
   PART I   
Item 1.    Business      3   

Item 1A.

   Risk Factors      19   

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      57   

Item 8.

   Financial Statements and Supplementary Data      60   

Item 9.

   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure      122   

Item 9A.

   Controls and Procedures      122   

Item 9B.

   Other Information      122   
   PART III   

Item 10.

   Directors, Executive Officers and Corporate Governance      123   

Item 11.

   Executive Compensation      123   

Item 12.

   Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters      123   

Item 13.

   Certain Relationships and Related Transactions and Director Independence      123   

Item 14.

   Principal Accounting Fees and Services      123   
   PART IV   

Item 15.

   Exhibits, Financial Statement Schedules      124   


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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 tariff rates. 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.

 

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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 refined petroleum products pipeline systems in the United States in terms of volumes delivered, with approximately 6,000 miles of pipeline and over 100 active products terminals that provide aggregate storage capacity of over 70 million barrels. We also 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 own and operate a natural gas storage facility in Northern California, and are a wholesale distributor of refined petroleum products in the United States in areas also served by our pipelines and terminals. 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.

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:

 

   

Maximize utilization of our assets at the lowest cost per unit;

 

  Maintain stable long-term customer relationships;

 

  Operate in a safe and environmentally responsible manner;

 

  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;

 

  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.

 

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Recent Developments

2013 Transaction

Equity Offering

In January 2013, we completed a public offering of 6,000,000 LP Units pursuant to an effective shelf registration statement, which priced at $52.54 per unit. The underwriters also exercised an option to purchase 900,000 additional LP Units, resulting in total gross proceeds of approximately $362.5 million before deducting underwriting fees and estimated offering expenses. We used the net proceeds from this offering to reduce the indebtedness outstanding under our revolving credit facility.

2012 Transactions

Acquisitions

In July 2012, we acquired a marine terminal facility for liquid petroleum products in New York Harbor (the “Perth Amboy Facility”) from Chevron U.S.A. Inc. (“Chevron”) for $260.3 million in cash. The facility, which sits on approximately 250 acres on the Arthur Kill tidal strait in Perth Amboy, New Jersey, has over 4.0 million barrels of tankage, four docks, and significant undeveloped land available for potential expansion. The Perth Amboy Facility has water, pipeline, rail, and truck access, and is located six miles from our Linden, New Jersey complex. The facility provides a link between our inland pipelines and terminals and our BORCO facility in The Bahamas and opportunities for improved service offerings to our customers. Concurrent with the acquisition, we entered into multi-year storage, blending, and throughput commitments with Chevron.

In September 2012, our operating subsidiary, Buckeye Pipe Line Holdings, L.P. (“BPH”), purchased an additional 20% ownership interest in WesPac Pipelines – Memphis LLC (“WesPac Memphis”) from Kealine LLC for $17.3 million and, as a result of the acquisition, our ownership interest in WesPac Memphis increased from 50% to 70%. Since BPH retains controlling interest in WesPac Memphis, this acquisition was accounted for as an equity transaction.

Equity Offering

In February 2012, we issued 4,262,575 LP Units to institutional investors in a registered direct offering for aggregate consideration of approximately $250.0 million at a price of $58.65 per LP Unit, before deducting placement agents’ fees and estimated offering expenses. We used the majority of the net proceeds from this offering to reduce the indebtedness outstanding under our Revolving Credit Agreement dated September 26, 2011 (the “Credit Facility”) with SunTrust Bank and to indirectly fund a portion of the Perth Amboy Facility acquisition as well as certain other growth capital expenditures.

 

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Business Activities

The following discussion describes the business activities of our business segments, which include Pipelines & Terminals, International Operations, Natural Gas Storage, Energy Services and Development & Logistics. The Pipelines & Terminals segment and the Energy 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 operations and assets are conducted and located in the continental United States, except for our terminals located in Puerto Rico and The Bahamas and, from time to time, our International Operations segment sells fuel oil to third parties at various locations in the Caribbean. Detailed financial information regarding revenue and total assets of each segment can be found in Note 24 in the Notes to Consolidated Financial Statements. The following table shows our consolidated revenue and each segment’s revenue and percentage of consolidated revenue for the periods indicated (revenue in thousands):

 

     Year Ended December 31,  
     2012     2011     2010  
     Revenue     Percent     Revenue     Percent     Revenue     Percent  

Pipelines & Terminals

   $ 719,126       16.5   $ 631,289       13.2   $ 574,990       18.3

International Operations (1)

     254,362       5.8     193,960       4.1     936       0.0

Natural Gas Storage

     71,339       1.6     65,990       1.4     95,337       3.0

Energy Services

     3,293,274       75.6     3,888,961       81.7     2,481,566       78.7

Development & Logistics

     50,211       1.2     43,068       0.9     37,696       1.2

Intersegment

     (31,070     (0.7 )%      (63,658     (1.3 )%      (39,257     (1.2 )% 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

   $ 4,357,242       100.0   $ 4,759,610       100.0   $ 3,151,268       100.0
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) Amounts for 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 refined 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 100 active terminals that provide bulk storage and throughput services with respect to refined petroleum products and renewable fuels, including ethanol, and have an aggregate storage capacity of over 40.0 million barrels. In addition, two 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 refined 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 refined 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 refined petroleum

 

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products from refineries, connecting pipelines, and bulk and marine terminals and transports those products to other locations for a fee.

The following table presents product volumes 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,  
     2012     2011     2010  

Pipelines:

               

Gasoline

     701.9        50.6     668.1        49.2     653.5        49.6

Jet fuel

     339.2        24.5     340.6        25.1     338.5        25.7

Middle distillates (1)

     322.3        23.3     327.2        24.1     303.4        23.1

Other products (2)

     22.2        1.6     22.2        1.6     21.0        1.6
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total pipelines throughput

     1,385.6        100.0     1,358.1        100.0     1,316.4        100.0
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

 

(1) Includes diesel fuel, heating oil and kerosene.
(2) Includes liquefied petroleum gas (“LPG”).

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

Pennsylvania—New York—New Jersey. Our operating subsidiary Buckeye Pipe Line Company, L.P. (“Buckeye Pipe Line”) serves major population centers in Pennsylvania, New York and New Jersey through approximately 925 miles of pipeline. Refined 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 refined 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 refined petroleum products from a refinery located in Paulsboro, New Jersey to destinations in New Jersey, Pennsylvania and New York. A portion of the pipeline system extends from Paulsboro, New Jersey to Malvern, Pennsylvania. From Malvern, a pipeline segment delivers refined 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 refined petroleum products through a 350-mile pipeline extending westward from three refineries, a marine terminal and a connection to the Colonial pipeline system in the Philadelphia area to Reading, Harrisburg, Altoona/Johnstown, Greensburg and Pittsburgh, Pennsylvania.

Illinois—Indiana—Michigan—Missouri—Ohio. Buckeye 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 refined 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,

 

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Michigan. Refined petroleum products are received at refineries and other pipeline connection points near Toledo and Lima, Ohio; Detroit, Michigan; and East Chicago, Indiana. Major market areas served include Huntington/Fort Wayne, Indianapolis and South Bend, Indiana; Bay City, Detroit and Flint, Michigan; Cleveland, Columbus, Lima, Warren and Toledo, Ohio; and Pittsburgh, Pennsylvania.

Our operating subsidiary Wood River Pipe Lines LLC (“Wood River”) owns refined petroleum products pipelines with aggregate mileage of approximately 1,250 miles located in the Midwestern United States. Refined 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 Refined Petroleum Products Pipelines. Buckeye Pipe Line serves Connecticut and Massachusetts through an approximately 100-mile pipeline that carries refined 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 a 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 a 124-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 15-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, BPH purchased an additional 20% ownership interest in WesPac Memphis from Kealine, increasing our ownership interest in WesPac Memphis from 50% to 70%. 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,  
     2012      2011      2010  

Products throughput (1)

     897.3        730.9        562.5  
  

 

 

    

 

 

    

 

 

 

 

(1) Amounts for 2012 and 2011 include throughput volumes at terminals acquired from BP and ExxonMobil Corporation (“ExxonMobil”) on June 1, 2011 and July 19, 2011, respectively. The table does not include throughput at the five terminals owned by the Energy Services segment, 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

     1        345  

Florida

     1        456  

Iowa

     5        1,302  

Illinois

     9        3,161  

Indiana

     11        9,175  

Kentucky

     1        214  

Louisiana

     1        135  

Maine

     1        141  

Massachusetts

     1        106  

Michigan

     13        5,370  

Missouri

     3        1,767  

Nevada

     1        50  

New Jersey (2)

     1        4,530  

New York

     10        4,111  

Ohio

     14        4,003  

Pennsylvania

     11        2,536  

South Carolina

     3        1,022  

Tennessee (3)

     1        328  

Virginia

     3        781  

Wisconsin

     4        1,228  
  

 

 

    

 

 

 

Total

     100        41,896  
  

 

 

    

 

 

 

 

(1) This table includes five terminals, which are owned by the Energy Services segment (as discussed below), in Pennsylvania with aggregate storage capacity of approximately 1.0 million barrels. This table does not include the Yabucoa terminal or the BORCO facility that are included in the International Operations segment for reporting purposes (as discussed below) with an aggregate storage capacity of approximately 30.0 million barrels.
(2) In July 2012, we acquired a marine terminal facility for liquid petroleum products in Perth Amboy, New Jersey.
(3) This represents the terminal facility owned by WesPac Memphis, which is 70% 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.

International Operations Segment

The International Operations segment provides marine terminal throughput services, marine bulk storage and other related services through two petroleum product terminals located on Grand Bahama Island, in The Bahamas and in Puerto Rico.

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

 

Location

   Storage
Capacity
 

Bahamas

     24,946  

Puerto Rico

     4,623  
  

 

 

 

Total

     29,569  
  

 

 

 

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 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 property on which the BORCO terminal facility is located. BORCO leases 330 acres of seabed on which the deep water jetties are located and has a long-term agreement through 2057 with the Bahamas Government. BORCO also leases the land on which the inland dock is located and has a long-term agreement through 2067 with the Freeport Harbour Company.

 

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Yabucoa Terminal

The Yabucoa terminal includes 44 storage tanks, which store gasoline, jet fuel, diesel, fuel oil and crude oil. Access to the Yabucoa terminal is provided through one ship dock, which is leased from the Puerto Rico Ports Authority, two barge docks as well as an 8-bay truck rack. Additionally, we provide fuel oil supply and distribution services to utility companies in the Caribbean.

Natural Gas Storage Segment

Our operating subsidiary Buckeye Gas Storage LLC, through its subsidiary Lodi Gas Storage, L.L.C. (“Lodi Gas”) owns a natural gas facility in Northern California. The natural gas facility currently has approximately 30.0 billion cubic feet (“Bcf”) of working natural gas storage and is connected to Pacific Gas and Electric’s (“PG&E”) intrastate gas pipeline system that services natural gas demand in the San Francisco and Sacramento, California areas.

The original Lodi facility is located approximately 30 miles south of Sacramento, near Lodi, California, and has been in service since January 2002. The Kirby Hills facility is located approximately 30 miles west of Lodi in the Montezuma Hills, nine miles southeast of Fairfield, California. The Natural Gas Storage segment’s three storage facilities have daily maximum injection and withdrawal capability of 550 million cubic feet (“Mmcf”) per day and 750 Mmcf/day, respectively, utilizing over thirty wells. Thirty-one miles of pipeline link the original Lodi facility to an interconnect with PG&E just north of Antioch, California. Six miles of pipeline link the Kirby Hills facility to an interconnect with PG&E approximately six miles west of Rio Vista, California.

The Natural Gas Storage segment is regulated by the California Public Utilities Commission (“CPUC”). All services have been, and will continue to be, contracted under the Natural Gas Storage segment’s published CPUC tariff.

The Natural Gas Storage segment’s revenues primarily consist of lease and hub services revenues. Lease revenues are charges for the reservation of storage space for natural gas. Generally, customers inject natural gas in the fall and spring and withdraw it for winter and summer use. Title to the stored natural gas remains with the customer. Hub services revenue consists of a variety of other storage services under interruptible storage agreements. The Natural Gas Storage segment does not trade or market natural gas.

Energy Services Segment

The Energy Services segment is a wholesale distributor of refined petroleum products in the United States in certain areas served by our pipelines and terminals which allows us to increase the utilization of our existing pipeline and terminal assets by marketing refined petroleum products in the areas served by those assets. 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 Energy Services segment owns five terminals in Pennsylvania with aggregate storage capacity of approximately 1.0 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.

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

 

     Year Ended December 31,  
     2012      2011      2010  

Sales volumes

     1,106.3        1,337.8        1,139.1  
  

 

 

    

 

 

    

 

 

 

 

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

 

  Wholesale Rack – 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; and

 

  Branded Gasoline – the Energy Services segment delivers, through third-party carriers, gasoline and on-highway diesel fuel to independently owned retail gas stations under many leading gasoline brands.

The operations of the Energy 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 Energy Services segment uses consist primarily of futures contracts traded on the New York Mercantile Exchange (“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 Energy 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 Energy 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 and natural gas storage services.

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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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 refined 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 refined 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 refined 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.

Distribution of refined 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

 

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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 refined petroleum products to end-users such as retail gasoline stations.

International Operations Segment

Our facility on Grand Bahama Island, Bahamas faces competition with some proprietary and third-party independent terminal operators in the Caribbean region. The facility’s location and deep draft coupled with its storage and blending capability provide certain advantages to our customers for export of products 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 into 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, which is a significant fuel oil user, sources fuel for their power generation needs.

Natural Gas Storage Segment

The Natural Gas Storage segment competes with other storage providers, including local distribution companies (“LDCs”), utilities and affiliates of LDCs and other independent utilities in the Northern California natural gas storage market. Certain major pipeline companies have existing storage facilities connected to their systems that compete with the Natural Gas Storage segment’s facilities. Ongoing and proposed third-party construction of new capacity in Northern California could have an adverse impact on the Natural Gas Storage segment’s competitive position.

Energy Services Segment

The Energy Services segment competes with major integrated oil and gas companies, their marketing affiliates and independent gatherers, investment banks that have established trading platforms, and brokers and marketers of widely varying sizes, financial resources and experience. Some of these competitors have capital resources greater than the Energy Services segment, and control greater supplies of refined 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.

Customers

For the years ended December 31, 2012, 2011 and 2010, no customer contributed 10% or more of our consolidated revenue.

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

 

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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 International Operations segment’s mix and volume of products stored does not vary significantly.

The Natural Gas Storage segment typically has two injection and two withdrawal seasons during the year. Our natural gas storage facility is normally at capacity prior to the summer cooling season and prior to the winter heating season. Since our customers pay a demand fee, they are generally incentivized to maximize their use of the storage facility throughout the year.

The Energy 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 Energy 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, 2012, Services Company had approximately 1,020 employees, approximately 190 of whom were represented by labor unions. Additionally, at December 31, 2012, certain of our wholly owned subsidiaries had approximately 230 employees, approximately 170 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.

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

Buckeye 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

 

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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.

Until recently, Buckeye Pipe Line’s rates have been governed by an exception to the rules discussed above, pursuant to specific FERC authorization. Buckeye 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 was determined by FERC not to 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 determined by FERC 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 does 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 was determined by FERC not to have significant market power were required to be accompanied by a corresponding decrease in all of Buckeye Pipe Line’s rates in markets where it was found to have significant market power and in certain markets where no market power finding was made. Shippers retained the right to file complaints or protests following notice of a rate increase, but were required to show that the proposed rates violate or have not been 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.

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 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. Nos. IS12-185-000, et al., discontinuing the Buckeye Pipe Line program but permitting Buckeye Pipe Line to retain its filed rates, to make future rate changes in markets which were previously determined by FERC to be competitive under market-based ratemaking authority, and to make future changes in rates in other markets under the generic FERC ratemaking methods, which would include indexing. We cannot predict with certainty the impact of the discontinuance of Buckeye Pipe Line’s rate program on Buckeye Pipe Line’s operations. Independent of regulatory considerations, it is expected that tariff rates will continue to be constrained by competition and other market factors.

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 in intrastate service in Illinois, and tariff rates related to this pipeline are regulated by the Illinois Commerce Commission.

Lodi Gas owns and operates a natural gas storage facility in Northern California under a Certificate of Public Convenience and Necessity originally granted by the CPUC. Lodi Gas is not subject to FERC rate regulation, but is regulated by the CPUC and other state and local agencies in California. Consistent with California regulatory policy and its Certificate of Public Convenience and Necessity, however, Lodi Gas is authorized to charge market-based rates and is not otherwise subject to rate regulation.

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 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

 

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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 refined petroleum products sometimes occurs in the petroleum pipeline and terminalling industry. Our pipelines cross 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 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. Any changes in the 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 liability 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,” our property or right-of-way may be adjacent to or in the immediate vicinity of Superfund and other hazardous waste sites. Accordingly, we may be responsible under CERCLA for all or part of the costs required to cleanup such sites, which could be material.

The Clean Air Act, amended by the Clean Air Act Amendments of 1990 (the “Amendments”), imposes controls on the emission of pollutants into the air. The Amendments required states to develop facility-wide permitting programs to comply with new federal programs. Existing operating and air-emission requirements currently imposed on us are being reviewed by state agencies in connection with the new facility-wide permitting program. 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 (primarily California) and regions have considered 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 in which we operate. In certain instances, the regulatory standards adopted by the states are more stringent than applicable federal laws.

 

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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. PSA 2011 strengthens damage prevention regulations and provides authority to further strengthen such regulations with respect to HCAs in the future. Similarly, 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; 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.

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

 

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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, 2013. 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 depositing waste. 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 $400.0 million. The policies provide coverage for claims involving sudden and accidental releases. 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 September 30, 2013. 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 costs and losses 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.

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. This 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.

 

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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 refined 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.

At BORCO, recent increases in demand for the services we provide 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 at BORCO and the prices we can charge for those services.

In recent years, the federal government has enacted renewable fuel or energy efficiency statutory mandates that may have the impact over time of reducing the demand for refined petroleum products in certain markets, particularly with respect to gasoline. 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 refined 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,

 

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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 refined 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 refined petroleum products in a number of areas that we serve. While their costs may not be competitive for longer hauls or large volume shipments, trucks compete effectively for incremental and marginal volumes in many areas that we serve. The availability of truck transportation places a significant competitive constraint on our ability to increase our tariff rates.

Privately arranged exchanges of refined 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 refined petroleum products to end-users such as retail gasoline stations.

Our International Operations segment primarily competes with other marine terminals in the Caribbean, and to the 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 International Operations segment’s storage fees are not regulated, the segment is subject to price competition from competitive terminals. Our International Operations 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 Natural Gas Storage segment competes primarily with other storage facilities and pipelines in the storage of natural gas. Some of our competitors may have greater financial resources. Some of these competitors may expand or construct transportation and storage systems that would create additional competition for the services we provide to our customers. Increased competition could reduce the volumes of natural gas stored by us and could adversely affect our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows.

 

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Our Energy 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.

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.

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,

 

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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.

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 is 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 recently, Buckeye Pipe Line has been authorized to charge rates set by market forces, subject to limitations, rather than by reference to costs historically incurred by the pipeline, in 15 regions and metropolitan areas. 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 directed Buckeye Pipe Line to show cause why it should not be required to discontinue the Buckeye Methodology and avail itself of the generic ratemaking methodologies used by other oil pipeline companies. Pending FERC’s review of the program, the Order also disallowed proposed rate increases on the Buckeye System that would have become effective April 1, 2012. On September 20, 2012, five airlines jointly filed a complaint in FERC Docket 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, Buckeye Pipe Line filed an application in FERC Docket No. OR13-3-000 for authority to charge market-based rates for transportation to destinations in the New York City Market, including the New York City area airports, because Buckeye Pipe Line lacked significant market power. On December 14, 2012, five airlines intervened and filed comments in opposition to the application in Docket No. OR13-3-000. As of the end of 2012, FERC had not issued an order with

 

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respect to Docket Nos. IS12-185-000, OR12-28-000, or OR13-3-000. On February 22, 2013, FERC issued an order in Dkt. No. IS12-185-000, et al., discontinuing the Buckeye Pipe Line 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 in markets previously found to be competitive by FERC under market-based ratemaking authority, and to make future changes in rates in other markets pursuant to the generic FERC ratemaking methods, which would include indexing. Also 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. It is too early to predict the outcome of the proceedings in FERC Docket Nos. OR12-28-000 and OR 13-3-000, or to determine the impact of the Ratemaking Methodology Order’s requirement that Buckeye Pipe Line transition to ratemaking methodologies that differ from the Buckeye Methodology.

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. Following the Ratemaking Methodology Order, shippers would have the right to file such complaints regarding rates in Buckeye Pipe Line’s markets that are not subject to market-based-rate authority. 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 refined 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.

These currently effective regulations or any future laws or regulations that may be adopted to address GHG emissions could require us to incur 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 refined 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.

 

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Environmental regulation may impose significant costs and liabilities on us.

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

 

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

 

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

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

Changes made to governmental regulations governing the components of refined 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.

BORCO may be adversely affected by economic, political and regulatory developments.

BORCO’s terminal facility is located in The Bahamas. 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 BORCO 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 or under development, employees, contractors, or agents may violate the policies. Any such violations could include prohibitions on BORCO’s ability to offer its services 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 value of natural gas storage services, including hub services or a significant change in the production of natural gas.

The Natural Gas Storage segment stores natural gas for, and loans natural gas to, its customers for fixed periods of time. If the values of natural gas storage services change in a direction or manner that we do not anticipate, we could experience financial losses from these activities. Although the Natural Gas Storage segment does not purchase or sell natural gas, the value of natural gas storage services generally changes based on changes in the

 

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relative prices of natural gas over different delivery periods. In particular, the hub services portion of our Natural Gas Storage segment involves our entry into interruptible natural gas storage agreements with our customers. These agreements are entered into in order to maximize the daily utilization of the natural gas storage facility, while also attempting to capture value from seasonal price differences in the natural gas markets. To the extent that the seasonal price differences moderate, our business, financial condition, results of operations, or cash flows could be negatively impacted due to a lack of demand for storage capacity. In addition, a material change in the supply of, or demand for, natural gas could negatively impact the value of lease capacity and hub services activities, which could adversely affect our results of operations.

Our results could be adversely affected by volatility in the price of refined petroleum products.

The Energy 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.

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 approximately 76% of BORCO’s total revenue for the year ended December 31, 2012. 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, 2012, approximately 32% and 66% 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. 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.

 

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

Since the attacks of September 11, 2001, the United States government has issued warnings that energy assets, specifically our nation’s pipeline infrastructure, may be the future target of terrorist organizations. In addition to the threat of 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 data, and other electronic security breaches that could lead to disruptions in critical 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 additional scrutiny and enforcement of the CFATS requirements in 2010, which continued in 2011 and 2012 and is expected to continue. At this time, we do not believe that compliance with CFATS will have a material effect on our business, financial condition, results of operations or cash flows.

In addition to CFATS, our domestic operations are also subject to other laws and regulations promulgated and enforced by other components of the Department of Homeland Security and the Department of Transportation. Our operations in the Bahamas 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. 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.

 

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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.

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 Energy 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

 

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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.

The Natural Gas Storage segment offers interruptible storage services to customers, which allow customers to borrow gas from our storage facilities. In the event a customer does not repay its loan in-kind with physical natural gas, we would be required to enter the physical natural gas markets to procure the volumes borrowed from the facility in order to honor our commitments to our other storage customers. A customer’s nonperformance under an interruptible storage agreement or failure to keep us financially whole could have an adverse effect on our business, financial condition, results of operations, or cash flows.

Our natural gas storage business depends on third-party pipelines to transport natural gas.

We depend on PG&E’s intrastate gas pipelines to move our customers’ natural gas to and from our Lodi facility. Any interruption of service or decline in utilization on the pipelines or adverse change in the terms and conditions of service for the pipelines could have a material adverse effect on the ability of our customers to transport natural gas to and from the Lodi facility, and could have a corresponding material adverse effect on our storage revenues. In addition, the rates charged by the interconnected pipelines for transportation to and from our facilities could affect the utilization and value of our storage services.

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.

Hurricanes and other severe weather conditions 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. Any such occurrence could have a material adverse effect on our business, financial condition, results of operation or cash flows.

 

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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 Energy Services and Natural Gas Storage segments follow risk management practices that are designed to minimize commodity price risk, credit risk and operational risk for their respective business. 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.

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.

 

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

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

Tax Risks to Unitholders

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

The anticipated after-tax economic benefit of an investment in LP Units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this.

Despite the fact that we are a limited partnership under Delaware law, a publicly traded partnership such as us may be treated as a corporation for federal income tax purposes unless its gross income from its business activities satisfies a “qualifying income” requirement. “Qualifying income” includes income and gains derived from the transportation, storage, processing and marketing of natural resources, including crude oil, natural gas and products thereof. Based upon our current operations we believe that we are treated as a partnership rather than a corporation for such purposes; however, a change in our business could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay Texas franchise tax at a maximum effective rate of 0.7% of our gross income apportioned to Texas in the prior year. Imposition of such a tax on us by any other state will reduce the cash available for distribution to you.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to unitholders 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.

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

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common 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 federal income tax laws that affect publicly traded partnerships. For example, one such previously introduced legislative proposal would eliminate the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. 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 common units. Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult

 

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or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes.

If the IRS contests the federal income tax positions we take, the market for our LP Units may be adversely impacted and the cost of any IRS contest will reduce our 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 or certain other matters affecting us. 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. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

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

Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you receive no 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 liability that results from that income.

Tax gain or loss on the 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 you realize 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 our 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 reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons 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 actual LP Units 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.

 

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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. Recently, the U.S. Treasury Department 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. 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.

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 as having 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 may 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 as having 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 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 loan to a short seller 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 technically terminated for 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 (and our unitholders could receive two Schedules K-1) for one fiscal 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 fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in the unitholder’s taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has recently announced a relief program whereby a publicly traded partnership that technically terminates may be allowed to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.

As a result of investing in our LP Units, a unitholder may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire property.

In addition to federal income taxes, a unitholder will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if a unitholder does not live in any of those jurisdictions. A unitholder will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, a unitholder 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

 

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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 and The Bahamas. Under current law, you are not required to file a tax return or pay taxes in either of these jurisdictions. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. It is a unitholder’s responsibility to file all foreign, 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.

BORCO is currently exempt from Bahamian taxation. If BORCO’s tax status in The Bahamas were to change, such that BORCO has 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. If the Bahamian governmental authorities do not extend the concessions under the Hawksbill Creek Agreement 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.

 

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 56,000 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. We have leases for subsurface underground gas storage rights and surface rights in connection with our operations in the Natural Gas Storage segment. 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 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. The extent of the damage is being assessed and presently is estimated to range between $20.0 million and $30.0 million. We have insurance to cover this loss, subject to a $5.0 million deductible. On May 26, 2012, we commenced legal proceedings in The Bahamas against the vessel’s owner and the vessel to obtain security for the cost of repairs and other losses incurred as a result of the incident. Full security for our claim has been provided by the vessel owner’s insurers, reserving all of their defenses, but the vessel owner is claiming it is entitled to limit its liability to approximately $17.0 million. 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. At this time, we have not experienced any material interruption of service at the BORCO facility as a result of the incident and have commenced the process of repairing the jetty. We recorded a $4.2 million loss on disposal due to the assets destroyed in the incident and $3.5 million related to other costs incurred; however, since we believe recovery of our losses is probable, we recorded a corresponding receivable. To the extent the 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, 2012, no gain had been recognized.

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, BPH, Buckeye Pipe Line and West Shore, as defendants. The complaint in the Altschafl case attempts to allege various emotional distress and property damage claims under Wisconsin law arising out of a release of gasoline from a pipeline operated by West Shore in the Town of Jackson, Wisconsin on July 17, 2012. Owners of 148 properties in the area of Jackson, Wisconsin are the plaintiffs in the case. No dollar amount of damages is stated in the complaint, but the plaintiffs seek damages to reimburse them for, among other things, the costs of restoring their properties and of installing a permanent supply of potable water, the diminution in value of their properties, and the cost of a program of future medical monitoring. The plaintiffs also seek punitive damages. On January 21, 2013, we filed an answer to the complaint, denying its claims and asserting affirmative defenses, and a motion to dismiss the claims for emotional distress and for medical monitoring costs. No hearing on that motion has yet been held and the case is not presently scheduled for trial. 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.

Federal Energy Regulatory Commission (“FERC”) Proceedings

FERC Docket No. IS12-185 – Buckeye Pipe Line Show Cause Proceeding. On March 30, 2012, FERC issued an order (the “Show Cause Order”) regarding the market-based methodology used by Buckeye Pipe Line to set tariff rates on its pipeline system (the “Buckeye System”). In 1991, Buckeye Pipe Line sought and received FERC permission to determine rate changes on the Buckeye System using a unique methodology that constrained rates in markets not found to be competitive based on rate changes in markets that FERC found to be competitive, as well as certain other limits on rate increases. FERC ordered the continuation of this methodology for the Buckeye System in 1994, subject to FERC’s authority to cause Buckeye Pipe Line to terminate the program in the future. The Show Cause Order, among other things, stated that FERC would review the continued efficacy of Buckeye Pipe Line’s 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 also disallowed proposed rate increases on the Buckeye System that would have become effective April 1, 2012. The Show Cause Order did not impact any of the pipeline systems or terminals owned by Buckeye’s other operating subsidiaries. On April 23, 2012, Buckeye Pipe Line requested rehearing as to the disallowance of certain rates. On February 22, 2013, FERC issued an order in Dkt. No. IS12-185 discontinuing Buckeye Pipe Line’s unique program, and affirming on rehearing its rejection of all rate increases filed in March 2012 . The Ratemaking Methodology Order permitted Buckeye to retain its currently-filed rates in place, to make future rate changes in 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. Pending finality of this order, the timing or outcome of final resolution of this matter cannot reasonably be determined at this time.

 

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FERC Docket No. OR12-28 – 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 and its existing rate program. The timing or outcome of final resolution of this matter cannot reasonably be determined at this time.

FERC Docket No. OR13-3 – 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 refined 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 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. In addressing the Application, FERC will determine whether to approve the Application, deny it, or set it for further proceedings, including potentially an evidentiary hearing. 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 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 October 2011, PHMSA issued a proposed penalty totaling $0.1 million in connection with certain procedural and personnel qualification issues related to product release that occurred in Boothwyn, Pennsylvania in April 2008. We contested portions of the proposed penalty and in October 2012 we received a final order from PHMSA with respect to the matter and paid a penalty of $0.1 million.

 

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In April 2010, PHMSA proposed penalties totaling approximately $0.5 million in connection with a tank overfill incident that occurred at our facility in East Chicago, Indiana in May 2005 and other related personnel qualification issues raised as a result of PHMSA’s 2008 Integrity Inspection. We contested the proposed penalty and in November 2012 PHMSA issued a final order with a reduced penalty of approximately $0.4 million. We filed a petition for reconsideration appealing this order. The timing or outcome of this appeal cannot reasonably be determined at this time.

 

Item 4. Mine Safety Disclosures

Not applicable.

 

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Index to Financial Statements

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, 2012 and 2011, as reported in the NYSE Composite Transactions, were as follows:

 

     2012      2011  

Quarter

   High      Low      High      Low  

First

   $ 64.95      $ 58.50      $ 68.81      $ 58.45  

Second

     61.37        44.55        65.20        59.85  

Third

     54.68        47.06        65.24        54.51  

Fourth

     50.91        44.37        68.45        59.00  

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, 2007 and that all distributions or dividends were reinvested on a quarterly basis.

 

LOGO

 

     12/31/2007      12/31/2008      12/31/2009      12/31/2010      12/31/2011      12/31/2012  

Buckeye Partners, L.P.

   $ 100.00      $ 70.55      $ 128.99      $ 168.50      $ 171.74      $ 131.89  

S&P 500

     100.00        63.00        79.68        91.68        93.61        108.59  

Alerian MLP Index

     100.00        63.08        111.29        151.19        172.17        180.43  

 

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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 151,000 at December 31, 2012.

There is no established trading market for our Class B Units. As of December 31, 2012, our Class B Units were held by 9 holders of record.

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

 

          Amount Per  

Record Date

   Payment Date    LP Unit  

February 16, 2010

   February 26, 2010    $ 0.9375  

May 17, 2010

   May 28, 2010      0.9500  

August 16, 2010

   August 31, 2010      0.9625  

November 15, 2010

   November 30, 2010      0.9750  

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  

On February 8, 2013, we announced a quarterly distribution of $1.0375 per LP Unit that will be paid on February 28, 2013, to unitholders of record on February 19, 2013. Based on the LP Units outstanding as of December 31, 2012 and the 6.9 million LP units issued in connection with our January 2013 equity offering, cash distributed to LP unitholders on February 28, 2013 will total approximately $101.2 million. Based on Class B Units outstanding as of December 31, 2012, we also expect to issue approximately 186,000 Class B Units in lieu of cash distributions on February 28, 2013 to Class B unitholders of record on February 19, 2013.

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,  
     2012      2011 (1)      2010 (2)      2009 (2)      2008 (2)  

Income Statement Data:

              

Revenue

   $ 4,357,242      $ 4,759,610      $ 3,151,268      $ 1,770,372      $ 1,896,652  

Operating income (3)

     339,208        188,682        278,582        203,457        247,293  

Net income (3)

     230,551        114,664        201,008        141,637        180,623  

Net income attributable to Buckeye Partners, L.P. (3) (4)

     226,417        108,501        43,080        49,594        26,477  

Earnings per unit—diluted (5)

   $ 2.32      $ 1.20      $ 1.65      $ 2.49      $ 1.33  

Cash distributions per LP Unit—declared

   $ 4.15      $ 4.03      $ 3.83      $ 3.63      $ 3.43  
     December 31,  
     2012      2011      2010      2009      2008  

Balance Sheet Data:

              

Total assets

   $ 5,981,009      $ 5,570,376      $ 3,574,216      $ 3,486,571      $ 3,263,097  

Long-term debt

     2,735,244        2,393,574        1,519,393        1,500,495        1,445,722  

Total Buckeye Partners, L.P. capital (4)

     2,372,313        2,303,169        1,392,405        242,334        232,060  

 

(1) During the first quarter of 2011, we acquired a marine terminal in The Bahamas (see Note 3 in the Notes to Consolidated Financial Statements).
(2) 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.
(3) During 2012, 2011, 2010 and 2009, we recorded a $60.0 million asset impairment (see Note 7 in the Notes to Consolidated Financial Statements), a $169.6 million goodwill impairment (see Note 9 in the Notes to Consolidated Financial Statements), a $21.1 million modification of an equity compensation plan (see Note 18 in the Notes to Consolidated Financial Statements), and a $59.7 million asset impairment and $32.1 million reorganization expense, respectively.
(4) 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.
(5) 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 20.0 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

 

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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.

 

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 refined 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. We also own and operate a natural gas storage facility in Northern California, and are a wholesale distributor of refined petroleum products in the United States in areas also served by our pipelines and terminals. 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 operate and report in five business segments: (i) Pipelines & Terminals; (ii) International Operations; (iii) Natural Gas Storage; (iv) Energy Services; and (v) Development & Logistics. See Note 24 in the Notes to Consolidated Financial Statements for a more detailed discussion of our business segments.

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) maximize utilization of our assets at the lowest cost per unit; (ii) maintain stable long-term customer relationships; (iii) operate in a safe and environmentally responsible manner; (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 $226.4 million for the year ended December 31, 2012, which was an increase of $117.9 million, or 109% from $108.5 million for the corresponding period in 2011. Operating income was $339.2 million for the year ended December 31, 2012, which is an increase of $150.5 million, or 80% from $188.7 million for the corresponding period in 2011.

Revenues for our Pipelines & Terminals segment grew significantly in 2012, primarily from the impact of recent acquisitions, including the assets acquired from BP and ExxonMobil in mid-2011 and the Perth Amboy Facility acquired in the second half of 2012. Pipeline transportation volumes on assets owned prior to the 2011 and 2012 acquisitions (which we refer to as our “legacy assets”) declined marginally year-over-year driven by a decline in distillate volumes, primarily due to a warmer than usual winter in early 2012 resulting in lower heating oil movements. Throughput volumes for 2012 at terminals owned prior to the 2011 acquisitions (which we refer to as our “legacy terminals”) increased over 2011 as our Chicago Complex benefited from record output at Midwest refineries and as recent growth capital projects became operational, including the transformation of our Albany terminal to add the ability to provide crude oil service. In addition, we purchased an additional 20% interest in WesPac Memphis from Kealine LLC. In January 2013, we ceased operations on a portion of Buckeye’s NORCO pipeline system, consisting of approximately 169 miles of refined petroleum products pipelines and related assets in Indiana and Illinois. We recorded a non-cash impairment charge in the fourth quarter of 2012 of $60.0 million, which included $12.1 million of estimated costs associated with the removal and decommissioning of the pipeline.

Our International Operations segment benefited from the incremental contribution from the 1.9 million barrels of expansion capacity at BORCO that was completed in the second half of 2012. In addition to the storage revenue contribution from the expansion capacity, higher ancillary revenues, including berthing and heating revenues, were generated due to increased customer utilization of our facilities. Segment revenue also increased as a result of the launch of our fuel oil marketing business at the Yabucoa marine terminal, which is a low-margin business. We supply fuel oil under back-to-back arrangements that are intended to eliminate commodity and basis risks. In 2011,

 

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the International Operations segment was adversely impacted by lower than expected berthing revenue due to reductions in availability of fuel oil blending components as a result of operational issues at a refinery in the U.S. Virgin Islands (“Caribbean refinery”) and lower vessel traffic as inventory optimization opportunities were limited by market conditions. These market conditions continued into 2012, resulting in weakness in demand for product storage in early 2012.

In 2012, our Natural Gas Storage segment improved over 2011 results, but unfavorable market conditions, including low natural gas prices, compressed seasonal spreads and low volatility, continued to negatively impact the segment’s performance.

The Energy Services segment continued to be negatively impacted by extreme price volatility and basis risk, combined with market backwardation, in the markets it serves. We saw the benefits of the execution of our risk mitigation strategy, particularly in the second half of 2012, 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 declined as we executed this risk mitigation strategy. Our marketing operations remain a catalyst for incremental utilization of our Pipelines & Terminals assets as the contribution from Energy Services has been greater than its standalone reported results.

The liquefied petroleum gas (“LPG”) storage caverns acquired in 2011 were a key contributor to growth for our Development & Logistics segment. In addition, we benefited from improved margins and new contract operations opportunities for our third-party engineering and operations business.

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,  
     2012     2011     2010  

Revenue

   $ 4,357,242     $ 4,759,610     $ 3,151,268  

Costs and expenses

     4,018,034       4,570,928       2,872,686  
  

 

 

   

 

 

   

 

 

 

Operating income

     339,208       188,682       278,582  

Earnings from equity investments

     6,100       10,434       11,363  

Gain on sale of equity investment

     —         34,727       —    

Interest and debt expense

     (114,980     (119,561     (89,169

Other income (expense)

     (452     190       (687
  

 

 

   

 

 

   

 

 

 

Income before taxes

     229,876       114,472       200,089  

Income tax benefit

     (675     (192     (919
  

 

 

   

 

 

   

 

 

 

Net income

     230,551       114,664       201,008  

Less: Net income attributable to noncontrolling interests

     (4,134     (6,163     (157,928
  

 

 

   

 

 

   

 

 

 

Net income attributable to Buckeye Partners, L.P. (1)

   $ 226,417     $ 108,501     $ 43,080  
  

 

 

   

 

 

   

 

 

 

Earnings per unit—diluted (2)

   $ 2.32     $ 1.20     $ 1.65  
  

 

 

   

 

 

   

 

 

 

 

(1) 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 non-controlling interest.
(2) Pursuant to the Merger, BGH’s unitholders received a total of approximately 20.0 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.

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 by segment and on a consolidated basis, distributable cash flow and a reconciliation of net income, 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,  
     2012     2011     2010  

Adjusted EBITDA:

      

Pipelines & Terminals

   $ 409,055     $ 361,018     $ 346,447  

International Operations

     132,104       112,996       (4,655

Natural Gas Storage

     6,118       4,204       29,794  

Energy Services

     524       1,797       5,861  

Development & Logistics

     11,722       7,932       5,193  
  

 

 

   

 

 

   

 

 

 

Total Adjusted EBITDA

   $ 559,523     $ 487,947     $ 382,640  
  

 

 

   

 

 

   

 

 

 

Reconciliation of Net Income to Adjusted EBITDA and Distributable Cash Flow:

      

Net income

   $ 230,551     $ 114,664     $ 201,008  

Less: Net income attributable to non-controlling interests

     (4,134     (6,163     (157,928
  

 

 

   

 

 

   

 

 

 

Net income attributable to Buckeye Partners, L.P.

     226,417       108,501       43,080  

Add: Interest and debt expense

     114,980       119,561       89,169  

Income tax expense

     (675     (192     (919

Depreciation and amortization

     146,424       119,534       59,590  

Non-cash deferred lease expense

     3,901       4,122       4,235  

Non-cash unit-based compensation expense

     19,520       9,150       8,960  

Asset impairment expense

     59,950       —         —    

Goodwill impairment expense

     —         169,560       —    

Equity plan modification expense

     —         —         21,058  

Net income attributable to non-controlling interests affected by Merger (1)

     —         —         157,467  

Less: Amortization of unfavorable storage contracts (2)

     (10,994     (7,562     —    

Gain on sale of equity investment

     —         (34,727     —    
  

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

     559,523       487,947       382,640  
  

 

 

   

 

 

   

 

 

 

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

     (111,511     (111,941     (84,758

Income tax expense, excluding non-cash taxes

     (1,095     (6     —    

Maintenance capital expenditures

     (54,425     (57,467     (31,244
  

 

 

   

 

 

   

 

 

 

Distributable cash flow

   $ 392,492     $ 318,533     $ 266,638  
  

 

 

   

 

 

   

 

 

 

 

(1) Amounts represent portions of BGH’s non-controlling interests related to Buckeye that were eliminated as a result of the Merger. Amounts are excluded for the portion of 2010 prior to the Merger for comparability purposes.
(2) 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 Energy Services segment for the periods indicated:

 

     Year Ended December 31,  
     2012      2011      2010  

Pipelines & Terminals (average bpd in thousands):

        

Pipelines:

        

Gasoline

     701.9        668.1        653.5  

Jet fuel

     339.2        340.6        338.5  

Middle distillates (1)

     322.3        327.2        303.4  

Other products (2)

     22.2        22.2        21.0  
  

 

 

    

 

 

    

 

 

 

Total pipelines throughput

     1,385.6        1,358.1        1,316.4  
  

 

 

    

 

 

    

 

 

 

Terminals:

        

Products throughput (3)

     897.3        730.9        562.5  
  

 

 

    

 

 

    

 

 

 

Energy Services (in millions of gallons):

        

Sales volumes

     1,106.3        1,337.8        1,139.1  
  

 

 

    

 

 

    

 

 

 

 

(1) Includes diesel fuel, heating oil and kerosene.
(2) Includes liquefied petroleum gas.
(3) Amounts for 2012 and 2011 include throughput volumes at terminals acquired from BP and ExxonMobil Corporation on June 1, 2011 and July 19, 2011, respectively.

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

Consolidated

Adjusted EBITDA was $559.5 million for the year ended December 31, 2012, which is an increase of $71.6 million, or 14.7%, from $487.9 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 International Operations segment.

Revenue was $4,357.2 million for the year ended December 31, 2012, which is a decrease of $402.4 million, or 8.5%, from $4,759.6 million for the corresponding period in 2011. The decrease in revenue was primarily related to a net decrease in revenue in the Energy Services segment, which was partially offset by the revenue generated due to a full period of operations for the 2011 acquisitions and the Perth Amboy Facility acquisition in 2012 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 and new service offerings providing fuel oil supply and distribution services in the International Operations segment.

Operating income was $339.2 million for the year ended December 31, 2012, which is an increase of $150.5 million, or 80.0%, from $188.7 million the corresponding period in 2011. The increase in operating income was primarily related to a non-cash goodwill impairment charge in the Natural Gas Storage segment in 2011 and positive contribution as a result of a full period of operating activities for 2011 acquisitions in the Pipelines & Terminals segment. These increases were partially offset by 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 International Operations segment.

Distributable cash flow was $392.5 million for the year ended December 31, 2012, which is an increase of $74.0 million, or 23.2%, from $318.5 million for the corresponding period in 2011. The increase in distributable cash flow was primarily related to an increase of $71.6 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 $409.1 million for the year ended December 31, 2012, which was an increase of $48.1 million, or 13.3%, from $361.0 million for the corresponding period in 2011. The positive factors impacting Adjusted EBITDA were related to a $44.2 million increase in revenue due to a full period of operations for the assets acquired in 2011 and the Perth Amboy Facility acquired in 2012, 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 $17.1 million increase in operating expenses related to a full period of operations of the assets acquired in 2011 and the Perth Amboy Facility acquired in 2012, which included acquisition and transition expenses, a $9.5 million increase in operating expenses, which included integrity program expenditures, payroll costs, operating power and utilities, insurance and environmental remediation 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, $3.8 million in fees related to the FERC proceedings, $1.5 million of fees related to the temporary suspension of ethanol offloading capabilities at our Albany facility and a $3.7 million increase in expenses related to the relocation of certain operations and administrative support functions to our Houston, Texas headquarters.

Overall pipeline and terminalling volumes increased by 2.0% and 22.8%, 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.

International Operations. Adjusted EBITDA from the International Operations segment was $132.1 million for the year ended December 31, 2012, which was an increase of $19.1 million, or 16.9%, from $113.0 million for the corresponding period in 2011. The positive factors impacting Adjusted EBITDA were primarily related to a $46.0 million increase in revenue related to new service offerings providing fuel oil supply and distribution services in the Caribbean, 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 $45.5 million increase in cost of product sales related to new service offerings providing fuel oil supply and distribution services in the Caribbean and $2.0 million increase in operating expenses primarily as a result of increased customer utilization of our facilities.

Natural Gas Storage. Adjusted EBITDA from the Natural Gas Storage segment was $6.1 million for the year ended December 31, 2012, which was an increase of $1.9 million, or 45.5%, from $4.2 million for the corresponding period in 2011. The increase in Adjusted EBITDA was primarily the result of an $18.1 million increase in fees for hub service activities due to improved seasonal spreads and a $1.0 million decrease in operating expenses, which primarily related to a decline in the number of well workovers performed during 2012 as compared to the 2011 period. The increase in Adjusted EBITDA was partially offset by a $12.8 million decrease in lease revenue due to lower firm storage rates and a $4.4 million increase in costs of natural gas storage services, which includes hub services fees paid to customers for hub service activities. Lease revenue and hub services revenue are affected by

 

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the difference in natural gas commodity prices for the periods in which natural gas is injected and withdrawn from the storage facility (i.e., time spread).

Energy Services. Adjusted EBITDA from the Energy Services segment was $0.5 million for the year ended December 31, 2012, which was a decrease of $1.3 million, or 70.8%, 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.

The decrease in Adjusted EBITDA was primarily related to a $595.7 million net decrease in revenue, which included a $673.0 million decrease due to 17.3% of lower sales volumes, offset by a $77.3 million increase as a result of approximately $0.07 per gallon increase in refined petroleum product sales price (average sales prices per gallon were $2.98 and $2.91 for the 2012 and 2011 periods, respectively).

The decrease in revenue was partially offset by a $592.0 million net decrease in cost of product sales, which included a $670.0 million decrease due to 17.3% of lower sales volumes, offset by $78.0 million increase as a result of approximately $0.07 per gallon increase in refined petroleum product cost price (average cost prices per gallon were $2.96 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 $11.7 million for the year ended December 31, 2012, which was an increase of $3.8 million, or 47.8%, 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 $1.9 million increase in operating expenses, which primarily related to overhead costs, a $0.8 million increase in third-party engineering and operations expense and a $0.6 million increase in operating expenses for the LPG storage caverns.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Consolidated

Adjusted EBITDA was $487.9 million for the year ended December 31, 2011, which is an increase of $105.3 million, or 27.5%, from $382.6 million for the corresponding period in 2010. The increase in Adjusted EBITDA was primarily related to positive contribution as a result of the 2011 acquisitions in the Pipelines & Terminals segment and International Operations segment’s acquisition of the BORCO facility in 2011 and a full year of operations for the Yabucoa terminal, which was acquired in December 2010. These increases were partially offset by decreased earnings in the Natural Gas Storage segment as a result of low volatility in natural gas prices and compressed seasonal spreads in part due to system capacity constraints.

Revenue was $4,759.6 million for the year ended December 31, 2011, which was an increase of $1,608.3 million, or 51.0%, from $3,151.3 million for the corresponding period in 2010. The increase in revenue was primarily related to the increase in revenue in the Energy Services segment, as well as the increase in revenue as a result of the assets acquired in 2011 in the Pipelines & Terminals and International Operations segments. These increases in revenue were partially offset by the decrease in revenue in the Natural Gas Storage segment primarily related to a reduced level of hub services activities caused by the weakness in market fundamentals.

Operating income was $188.7 million for the year ended December 31, 2011, which was a decrease of $89.9 million, or 32.3%, from $278.6 million for the corresponding period in 2010. The decrease in operating income was primarily related to a non-cash goodwill impairment charge in the Natural Gas Storage segment and an increase in depreciation and amortization due to assets acquired in 2011 in the Pipelines & Terminals and International Operations segment, which was partially offset by positive contribution as a result of the assets acquired in 2011 in the Pipelines & Terminals segment and International Operations segment and a decrease in compensation expense as a result of the equity plan modification expense during 2010.

 

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Distributable cash flow was $318.5 million for the year ended December 31, 2011, which was an increase of $51.9 million, or 19.5%, from $266.6 million for the corresponding period in 2010. The increase in distributable cash flow was primarily related to an increase of $105.3 million in Adjusted EBITDA as described above, partially offset by a $26.2 million increase in maintenance capital expenditures relating to pipeline and tank integrity work performed in the Pipelines & Terminals and International Operations segments.

Adjusted EBITDA by Segment

Pipelines & Terminals. Adjusted EBITDA from the Pipelines & Terminals segment was $361.0 million for the year ended December 31, 2011, which was an increase of $14.6 million, or 4.2%, from $346.4 million for the corresponding period in 2010. The positive factors impacting Adjusted EBITDA were related to a $48.5 million increase in revenue due to pipeline and terminal acquisitions in 2011, $19.2 million due to higher pipeline tariff rates and terminalling contract rate escalations and a $9.0 million increase in other revenue.

These increases in Adjusted EBITDA were partially offset by a $25.7 million increase in operating costs relating to pipeline and terminal acquisitions in 2011, a $12.5 million decrease in revenue due to lower pipeline and terminalling volumes on legacy assets, a $8.8 million increase in acquisition and integration expenses, a $7.5 million increase in operating expenses, which included environmental remediation expenses, property taxes and payroll costs, $6.6 million in unfavorable settlement experience and a $1.0 million decrease in earnings from equity investments primarily due to the sale of our interest in WT LPG.

Overall pipeline and terminalling volumes increased by 3.3% and 32.1%, respectively, as a result of the acquisition of pipeline and terminal assets in 2011. Excluding the impact of the acquisitions, pipeline volumes decreased by 1.3% primarily due to lower gasoline volumes as a result of lower demand caused by high commodity prices and supply interruptions due to severe weather conditions and lower heating oil volumes due to lack of contango in the market and refinery closures. Terminalling volumes decreased by 5.8% primarily due to lower ethanol volumes as a result of competitive pressures and lower gasoline and distillate volumes as a result of lower demand caused by high commodity prices and supply interruptions due to severe weather conditions and refinery maintenance issues.

International Operations. Adjusted EBITDA from the International Operations segment was $113.0 million for the year ended December 31, 2011, which was an increase of $117.7 million from a loss of $4.7 million for the corresponding period in 2010. The positive factors impacting Adjusted EBITDA were primarily related to the BORCO acquisition in 2011 and a full year of operations for the Yabucoa terminal. The increase in Adjusted EBITDA was primarily due to a $151.0 million increase in storage revenue and $34.5 million in ancillary revenues, including berthing and heating services, partially offset by $62.9 million in operating costs, which included payroll costs, repair costs, insurance expenses, lease expenses and other costs, a $3.2 million increase in acquisition and integration expenses and $1.7 million increase in income allocated to non-controlling interests related to the remaining 20% ownership interest in BORCO not acquired by us until February 16, 2011.

Natural Gas Storage. Adjusted EBITDA from the Natural Gas Storage segment was $4.2 million for the year ended December 31, 2011, which was a decrease of $25.6 million, or 85.9%, from $29.8 million for the corresponding period in 2010. The decrease in Adjusted EBITDA was primarily the result of a $20.7 million and $8.6 million decrease in hub services activities and lease revenue, respectively, due to decreased storage prices relating to low volatility in natural gas prices and compressed seasonal spreads in part due to system capacity constraints as a result of unplanned maintenance on a pipeline combined with excess supply and weak domestic demand and $3.0 million of higher operating costs, partially offset by a $6.7 million decrease in cost of natural gas storage services.

Energy Services. Adjusted EBITDA from the Energy Services segment was $1.8 million for the year ended December 31, 2011, which was a decrease of $4.1 million, or 69.3%, from $5.9 million for the corresponding period in 2010. The decrease in Adjusted EBITDA was primarily due to declining basis, which had an adverse effect on the net value of our inventory portfolio. During the period, market dynamics impacted the flow of product along the supply chain and warmer weather conditions, which resulted in decreased consumer demand, created downward pressure on basis.

The decrease in Adjusted EBITDA was primarily related to a $1,413.2 million increase in cost of product sales, which included a $428.8 million increase due to 17.4% of higher sales volumes and a $984.4 million increase as a result of approximately $0.73 per gallon increase in refined petroleum product cost price (average cost prices per gallon were $2.89 and $2.16 for the 2011 and 2010 periods, respectively).

 

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The increase in cost of product sales was partially offset by a $1,407.4 million increase in revenue, which included a $432.9 million increase due to 17.4% of higher sales volumes and a $974.5 million increase as a result of approximately $0.73 per gallon increase in refined petroleum product sales price (average sales prices per gallon were $2.91 and $2.18 for the 2011 and 2010 periods, respectively) and a $1.7 million decrease in operating expenses primarily related to overhead costs.

Development & Logistics. Adjusted EBITDA from the Development & Logistics segment was $7.9 million for the year ended December 31, 2011, which was an increase of $2.7 million, or 52.7%, from $5.2 million for the corresponding period in 2010. The increase in Adjusted EBITDA was primarily due to a $5.5 million increase in third-party engineering and operations revenue as a result of new contracts and higher fees, $2.4 million in expenses associated with a customer bankruptcy in the 2010 period and $0.7 million of revenue relating to the LPG storage caverns acquired in November 2011, partially offset by a $3.7 million increase in third-party engineering and operations expenses, $1.3 million of higher operating and other costs and $0.9 million of net proceeds from the ammonia line fill sale in the 2010 period.

General Outlook for 2013

For our Pipelines & Terminals segment, we do not expect any significant change in macro-economic demand for petroleum products in the markets we serve in 2013 absent a significant change in the economy. We expect that throughput volumes on our pipeline systems will experience moderate growth, primarily as a result of what we expect to be a normal winter in terms of average temperature, which should allow for the rebound of heating oil volumes as compared to the relatively warm winter weather in early 2012. Our pipeline revenues are expected to benefit from increased tariffs on our indexed system, but some uncertainty remains related to the ways in which FERC’s February 22, 2013 Ratemaking Methodology Order issued in Dkt. No. IS12-185-000 et al., discussed above, will affect future changes to Buckeye’s rates in markets outside the New York City market. In addition, the ultimate resolution of the complaint of certain airlines regarding jet fuel rates to the three major New York City area airports in Dkt. No. OR12-28-000 could impact rates to those destinations. Base throughput volumes at our terminal assets are expected to remain flat, with moderate volume growth expected from return capital projects, such as the modernization of our Perth Amboy facility, transformation of our Albany facility to allow for crude service, expansion of our Chicago Complex, and completion of propylene off-take storage in the Midwest. Additionally, we are exploring opportunities to leverage our assets to provide crude supply logistic solutions as domestic shale plays continue to change the crude supply landscape. Ultimately, our ability to increase transportation and storage revenues is largely dependent on the strength of the overall economy in the markets we serve.

Looking forward to 2013 for our International Operations segment, we expect to place in-service an additional 2.8 million barrels of expansion storage capacity, including 1.2 million barrels of crude storage. We have seen increased demand for crude storage in the Caribbean as production off the coast of South America begins to ramp up. BORCO has the capability to function as a staging and blending facility in the logistics chain for producers as they move crude production to refining centers. We expect moderate increases in storage service rates prospectively and expect BORCO to be fully leased for 2013, except for required maintenance work. Our ability to achieve higher rates and increase storage utilization is ultimately dependent on the global product demand in the markets we serve. We enjoyed the initial contribution in late 2012 from our fuel oil business at our Yabucoa terminal, where we secure supply for Caribbean utility plants, and expect the contribution from that business to grow in 2013. We may experience some softness in demand for berthing and other ancillary services if the forward product pricing does not create inventory optimization opportunities for our customers.

We expect our Natural Gas Storage segment will continue to be challenged in 2013 as we do not expect any significant improvement in market fundamentals.

We expect Energy Services performance will improve in 2013 as it continues to execute on our risk mitigation strategy which benefited the segment in the second half of 2012. We do not expect a significant improvement in market fundamentals. We believe, however, that the Energy Services segment will continue to be a significant contributor in utilization of pipeline and terminal assets.

Our Development & Logistics segment has a robust pipeline of potential projects that we expect will continue its growth.

In the first quarter of 2013, we accessed the equity market and used the net proceeds to pay down existing indebtedness, which essentially was a pre-funding of our anticipated 2013 growth capital spend. We believe that,

 

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under current market conditions, we could raise additional capital in both the debt and equity markets on acceptable terms.

Throughout 2013, we will continue to evaluate opportunities 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.

The forward-looking statements contained in this “General Outlook for 2013” 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 2013” 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 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 financial policy has been to fund maintenance capital expenditures with cash from 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 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, 2012, we had $40.0 million of working capital and $378.8 million of additional borrowing capacity under our Credit Facility.

Capital Structuring Transactions

As part of our ongoing efforts to maintain a capital structure that is closely aligned with the cash-generating potential of our asset-based business, we may explore additional sources of external liquidity, including public or private debt or equity issuances. Matters to be considered will include cash interest expense and maturity profile, all to be balanced with maintaining adequate liquidity. We have a universal shelf registration statement that does not place any dollar limits on the amount of debt and equity securities that we may issue thereunder and a traditional shelf registration statement on file with the SEC that currently has a $750.0 million limit on the amount of equity securities that we may issue thereunder. The timing of any transaction may be impacted by events, such as strategic growth opportunities, legal judgments or regulatory or environmental requirements. The receptiveness of the capital markets to an offering of debt or equity securities cannot be assured and may be negatively impacted by, among other things, our long-term business prospects and other factors beyond our control, including market conditions.

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

 

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Debt

At December 31, 2012, we had the following debt obligations (in thousands):

 

4.625% Notes due July 15, 2013

   $ 300,000  

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  

5.500% Notes due August 15, 2019

     275,000  

4.875% Notes due February 1, 2021

     650,000  

6.750% Notes due August 15, 2033

     150,000  

BPL Credit Facility due September 26, 2016

     871,200  
  

 

 

 

Total debt

   $ 2,946,200  
  

 

 

 

It is our intent to refinance the 4.625% Notes in 2013. If necessary, the $300.0 million of 4.625% Notes maturing on July 15, 2013 could be refinanced using our Credit Facility. At December 31, 2012, we had $378.8 million of additional borrowing capacity under our Credit Facility. Additionally, we expect to pay approximately $72.8 million to settle interest rate swaps relating to the refinancing of the 4.625% Notes on or before July 15, 2013.

Equity

In January 2013, we completed a public offering of 6,000,000 LP Units pursuant to an effective shelf registration statement, which priced at $52.54 per unit. The underwriters also exercised an option to purchase 900,000 additional LP Units, resulting in total gross proceeds of approximately $362.5 million before deducting underwriting fees and estimated offering expenses. We used the net proceeds from this offering to reduce the indebtedness outstanding under our revolving credit facility.

In February 2012, we issued 4,262,575 LP units to institutional investors in a registered direct offering for aggregate consideration of approximately $250.0 million at a price of $58.65 per LP Unit, before deducting placement agents’ fees and estimated offering expenses. We used the majority of the net proceeds from this offering to reduce the indebtedness outstanding under our Credit Facility and to indirectly fund a portion of the Perth Amboy Facility acquisition as well as certain other growth capital expenditures.

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 we seek to invest this capital 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.

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,  
     2012     2011     2010  

Cash provided by (used in):

      

Operating activities

   $ 441,636     $ 403,892     $ 292,479  

Investing activities

     (590,322     (1,310,279     (114,188

Financing activities

     142,476       905,747       (202,239

 

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Operating Activities

2012 Compared to 2011. Net cash provided by operating activities was $441.6 million for the year ended December 31, 2012, which is an increase of $37.7 million, from $403.9 million for the corresponding period in 2011. The increase in cash provided by operating activities primarily related to an increase in income resulting from a full period of operations for the assets acquired in 2011, and the Perth Amboy Facility acquired in 2012 and a decrease in refined petroleum products inventory in 2012. In early 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 Compared to 2010. Net cash provided by operating activities was $403.9 million for the year ended December 31, 2011, which is an increase of $111.4 million, from $292.5 million for the corresponding period in 2010. The increase in cash provided by operating activities primarily related to income resulting from the operations of the BORCO facility and pipeline and terminal assets acquired in 2011 and the Yabucoa terminal in 2010 and a cash inflow related to a decrease in refined petroleum products inventory in 2011, partially offset by an increase in interest and debt expense during 2011.

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

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.

2011. Net 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 $166.0 million acquisition of pipeline and terminal assets and $305.3 million of capital expenditures, which were partially offset by $85.0 million of cash proceeds from the sale of our 20% interest in West Texas LPG Pipeline Limited Partnership.

2010. Net cash used in investing activities of $114.2 million for the year ended December 31, 2010 primarily related to $77.7 million of capital expenditures and a $32.8 million acquisition of the Yabucoa terminal.

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

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, net of non-cash changes in accruals for capital expenditures, were as follows for the periods indicated (in thousands):

 

     Year Ended December 31,  
     2012      2011      2010  

Maintenance capital expenditures

   $ 54,425      $ 57,467      $ 31,244  

Expansion and cost reduction

     276,913        247,857        46,455  
  

 

 

    

 

 

    

 

 

 

Total capital expenditures, net

   $ 331,338      $ 305,324      $ 77,699  
  

 

 

    

 

 

    

 

 

 

In 2012, maintenance capital expenditures included terminal pump replacements, 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

 

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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 and 2010, 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.

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

 

     2013  
     Low      High  

Pipelines & Terminals:

     

Maintenance capital expenditures

   $ 50,000      $ 60,000  

Expansion and cost reduction

     220,000        255,000  
  

 

 

    

 

 

 

Total capital expenditures

   $ 270,000      $ 315,000  
  

 

 

    

 

 

 

International Operations:

     

Maintenance capital expenditures

   $ 10,000      $ 20,000  

Expansion and cost reduction

     80,000        105,000  
  

 

 

    

 

 

 

Total capital expenditures

   $ 90,000      $ 125,000  
  

 

 

    

 

 

 

Overall:

     

Maintenance capital expenditures

   $ 60,000      $ 80,000  

Expansion and cost reduction

     300,000        360,000  
  

 

 

    

 

 

 

Total capital expenditures

   $ 360,000      $ 440,000  
  

 

 

    

 

 

 

Estimated maintenance capital expenditures include renewals and replacement of pipeline sections, tank floors and tank roofs and upgrades to station and terminalling equipment, field instrumentation and cathodic protection systems. Estimated major expansion and cost reduction expenditures include storage tank expansion projects at the BORCO facility, completion of additional storage tanks and rail loading facilities in the Midwest, truck loading rack upgrades in the Midwest, the refurbishment of storage tanks across our system, continued installation of vapor recovery units throughout our system of terminals, additive system installation throughout our terminal infrastructure and various upgrades and expansions of our butane blending business. In connection with the Perth Amboy Facility acquisition, our estimated expansion and cost reduction expenditures include refurbishment of the asphalt truck and rail rack, development of a new crude rail offloading system, completion of a bi-directional pipeline, conversion of tanks for distillate and gasoline storage, a new gasoline and diesel truck loading rack installation, construction of a multi-product blend and transfer piping manifold, and construction of a new 16- inch pipeline allowing direct access to our existing pipeline infrastructure. Also, estimated expansion and cost reduction expenditures include costs to repair the damaged jetty at our BORCO facility as a result of the allision of a vessel with our jetty in May 2012. We believe the recovery of the costs to repair the damaged jetty is probable. See Note 4 in the Notes to Consolidated Financial Statements for a more detailed discussion of this incident. Furthermore, cost reduction expenditures improve operational efficiencies or reduce costs.

Financing Activities

2012. Net cash flows provided by financing activities of $142.5 million for the year ended December 31, 2012 primarily related to $296.0 million of net borrowings under the Credit Facility and $246.8 million of net proceeds from the issuance of 4.3 million LP Units to reduce borrowings under our Credit Facility and fund a portion of the Perth Amboy Facility acquisition, partially offset by $371.2 million ($4.15 per LP Unit) of cash distributions paid to our unitholders.

 

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2011. Net 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 to fund a portion of the BORCO acquisition and reduce borrowings under our Credit Facility, $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.

2010. Net cash flows used in financing activities of $202.2 million for the year ended December 31, 2010 primarily related to $195.6 million of cash distributions paid to noncontrolling partners of Buckeye, which consisted primarily of distribution to holders of LP Units ($3.825 per LP Unit).

For further discussion on our equity offerings, see Note 21 in the Notes to Consolidated Financial Statements.

Contractual Obligations

The following table summarizes our contractual obligations as of December 31, 2012 (in thousands):

 

     Payments Due by Period  
     Total      Less than
1 year
     1-3 years      3-5 years      More than 5
years
 

Long-term debt (1)

   $ 2,740,000      $ 300,000      $ 275,000      $ 790,000      $ 1,375,000  

Interest payments (2) (3)

     834,832        134,496        236,442        182,605        281,289  

Operating leases:

              

Office space and other

     29,745        3,238        7,161        7,560        11,786  

Equipment (4)

     5,701        3,608        2,093        —          —    

Land leases (5)

     407,217        5,763        11,813        12,368        377,273  

Purchase obligations (6)

     90,627        90,627        —          —          —    

Capital expenditure obligations (7)

     21,665        21,665        —          —          —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total contractual obligations

   $ 4,129,787      $ 559,397      $ 532,509      $ 992,533      $ 2,045,348  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Includes long-term debt portion borrowed by Buckeye under our Credit Facility. See Note 12 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 swaps related to forecasted interest payments. As of December 31, 2012, the fair value of our interest rate swaps of $ 72.8 million and $ 57.8 million are expected to be settled on or about July 15, 2013 and October 14, 2014, respectively.
(4) Includes leases for tugboats and a barge in our International Operations segment.
(5) Includes leases for properties in connection with both the jetty and inland dock operations in the International Operations segment and leases for subsurface underground gas storage rights and surface rights in connection with our operations in the Natural Gas Storage segment. We may cancel these leases if the storage reservoir is not used for underground storage of natural gas or the removal or injection thereof for a continuous period of two consecutive years.
(6) We have short-term purchase obligations for products and services with third-party suppliers. The prices that we are obligated to pay under these contracts approximate current market prices.
(7) We have short-term payment obligations relating to capital projects we have initiated. These commitments represent unconditional payment obligations that we have agreed to pay vendors for services rendered or products purchased.

 

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For the year ended 2013, our rights-of-way payments are expected to be approximately $7.6 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 17 in the Notes to Consolidated Financial Statements.

Employee Stock Ownership Plan

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

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 Plan on and after the Freeze Date. Even though contributions under the ESOP are no longer being made, each eligible participant’s ESOP Account will continue to be credited with its share of any stock dividends or other stock distributions associated with Services Company stock.

All Services Company stock has been allocated to ESOP participants. See Note 19 in the Notes to Consolidated Financial Statements for further information.

Off-Balance Sheet Arrangements

At December 31, 2012 and 2011, 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) an appropriate discount rate. 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.

Measuring the Fair Value 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.

 

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For our annual goodwill impairment test as of January 1, 2013, 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 (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 year ended December 31, 2012. During the year ended December 31, 2011, we recorded a non-cash goodwill impairment charge of $169.6 million in the Natural Gas Storage segment. We did not record a goodwill impairment charge for the year ended December 31, 2010.

Our financial forecast for the International Operations reporting unit has assumptions relating to additional storage tank expansion associated with a potential increase in demand for crude oil. While we believe that a market participant would include the potential benefit of this expansion in its assessment of fair value, we performed a sensitivity analysis to remove the projected revenue relating to the additional storage tank expansion. An elimination of this projected revenue would not indicate an impairment; however, the excess fair value over carrying value would be minimal.

Measuring Recoverability 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 2012, we recorded a $60.0 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 the 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 Natural Gas Storage assets for impairment and concluded that no impairment of the long-lived assets existed at that time. See Note 7 and 9 in the Notes to Consolidated Financial Statements for further discussion. There was not an asset impairment charge during 2010.

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, 2012, 2011 or 2010.

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

 

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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.

Fair Value 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 Energy 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 Energy 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.

 

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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.

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, 2012

   $ 4,897     $ (101,911   $ (97,014

Items recognized or settled during the period

     19,630       —         19,630  

Fair value attributable to new deals

     (14,846     —         (14,846

Change in fair value attributable to price movements

     (18,144     (28,725     (46,869

Change in fair value attributable to non-performance risk

     24       —         24  
  

 

 

   

 

 

   

 

 

 

Fair value of contracts outstanding at December 31, 2012

   $ (8,439   $ (130,636   $ (139,075
  

 

 

   

 

 

   

 

 

 

Commodity Price Risk

Natural Gas Storage

The Natural Gas Storage segment enters into interruptible natural gas storage hub service agreements in order to manage the operational integrity of the natural gas storage facility, while also attempting to capture value from seasonal price differences in the natural gas markets. Although the Natural Gas Storage segment does not purchase or sell natural gas, the Natural Gas Storage segment is subject to commodity risk because the value of natural gas storage hub services generally fluctuates based on changes in the relative market prices of natural gas over different delivery periods. The hub service agreements do not qualify as derivatives and therefore are not accounted for at fair value. The fee to be received or paid is based on the time spread at the time of execution. The hub service agreements are accrued as fees are paid or received and recognized ratably in earnings over the entire term of the transactions.

The following is a summary of changes in the net balance sheet of our outstanding hub service agreements (in thousands):

 

Net Asset at January 1, 2012

   $  11,390  

Net revenue recognized in period (1)

     5,586  

Net unearned revenue (2)

     (4,929
  

 

 

 

Net Asset at December 31, 2012

   $ 12,047  
  

 

 

 

 

(1) Net revenue was amortized into earnings based on the net fee received for injection and withdrawal services performed during the period.
(2) Fees were collected and a net liability was recorded for injection and withdrawal services to be rendered in future periods.

 

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Energy Services

Our Energy 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, 2012, 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       $ 206,899  

Fair value assuming 10% increase in underlying commodity prices

     Asset         203,889  

Fair value assuming 10% decrease in underlying commodity prices

     Asset         209,909  

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, 2012, 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    $ (130,636

Fair value assuming 10% increase in underlying interest rates

   Liability      (116,245

Fair value assuming 10% decrease in underlying interest rates

   Liability      (141,776

 

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At December 31, 2012, we had total fixed-rate debt obligations at face value of $2,070.2 million. The fair value of these fixed-rate debt obligations at December 31, 2012 was approximately $2,203.7 million. We estimate that a 1% increase or decrease in rates for obligations of similar maturities would decrease or increase the fair value of our fixed-rate debt obligations at December 31, 2012 by approximately $100.7 million or $109.6 million, respectively.

At December 31, 2012, our variable-rate obligations were $871.2 million under the Credit Facility. Based on the balance outstanding at December 31, 2012, we estimate that a 1% increase or decrease in interest rates would increase or decrease annual interest expense by approximately $8.7 million.

See Note 15 in the Notes to Consolidated Financial Statements for additional discussion related to derivative instruments and hedging activities.

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 with the Bahamian dollar. Foreign exchange gains and losses arising from transactions denominated in a currency other than the functional currency relate to a nominal amount of supply purchases and are included in net income (loss) in the consolidated statements of operations. The effects of foreign currency transactions were not considered to be material for the years ended December 31, 2012 and 2011. There were no effects of foreign currency transactions during the year ended December 31, 2010.

 

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Item 8. Financial Statements and Supplementary Data

 

     Page

Management’s Report On Internal Control Over Financial Reporting

   61

Reports of Independent Registered Public Accounting Firm

   62

Consolidated Statements of Operations for the Years Ended December 31, 2012, 2011 and 2010

   64

Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December  31, 2012, 2011 and 2010

   65

Consolidated Balance Sheets as of December 31, 2012 and 2011

   66

Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010

   67

Consolidated Statements of Partners’ Capital for the Years Ended December  31, 2012, 2011 and 2010

   68

Notes to Consolidated Financial Statements:

  

1. Organization

   69

2. Summary of Significant Accounting Policies

   69

3. Acquisitions and Dispositions

   80

4. Commitments and Contingencies

   84

5. Inventories

   87

6. Prepaid and Other Current Assets

   88

7. Property, Plant and Equipment

   88

8. Equity Investments

   89

9. Goodwill and Intangible Assets

   91

10. Other Non-Current Assets

   92

11. Accrued and Other Current Liabilities

   93

12. Long-Term Debt

   93

13. Other Non-Current Liabilities

   96

14. Accumulated Other Comprehensive Income (Loss)

   96

15. Derivative Instruments, Hedging Activities

   96

16. Fair Value Measurements

   100

17. Pensions and Other Postretirement Benefits

   101

18. Unit-Based Compensation Plans

   106

19. Employee Stock Ownership Plan

   110

20. Related Party Transactions

   110

21. Partners’ Capital and Distributions

   110

22. Income Taxes

   114

23. Earnings Per Unit

   115

24. Business Segments

   116

25. Supplemental Cash Flow Information

   120

26. Quarterly Financial Data (Unaudited)

   120

27. Subsequent Events

   121

 

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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, 2012. 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 (“COSO”). As a result of this assessment and based on the criteria in the COSO framework, management has concluded that, as of December 31, 2012, 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, 2013    

 

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To 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, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Buckeye’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on Buckeye’s internal control over financial reporting based on our audit.

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

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

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Buckeye maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2012 of Buckeye and our report dated February 26, 2013 expressed an unqualified opinion on those consolidated financial statements.

 

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 26, 2013

 

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of Buckeye Partners, L.P.

We have audited the accompanying consolidated balance sheets of Buckeye Partners, L.P. and subsidiaries (“Buckeye”) as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, cash flows, and partners’ capital for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of Buckeye’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Buckeye Partners, L.P. and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Buckeye’s internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2013 expressed an unqualified opinion on Buckeye’s internal control over financial reporting.

 

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 26, 2013

 

 

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BUCKEYE PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit amounts)

 

     Year Ended December 31,  
     2012     2011     2010  

Revenue:

      

Product sales

   $ 3,332,301     $ 3,844,888     $ 2,469,210  

Transportation, storage and other services

     1,024,941       914,722       682,058  
  

 

 

   

 

 

   

 

 

 

Total revenue

     4,357,242       4,759,610       3,151,268  
  

 

 

   

 

 

   

 

 

 

Costs and expenses:

      

Cost of product sales and natural gas storage services

     3,344,817       3,851,579       2,462,275  

Operating expenses

     397,007       366,133       279,164  

Depreciation and amortization

     146,424       119,534       59,590  

General and administrative

     69,836       64,122       50,599  

Asset impairment expense

     59,950       —         —    

Goodwill impairment expense

     —         169,560       —    

Equity plan modification expense

     —         —         21,058  
  

 

 

   

 

 

   

 

 

 

Total costs and expenses

     4,018,034       4,570,928       2,872,686  
  

 

 

   

 

 

   

 

 

 

Operating income

     339,208       188,682       278,582  
  

 

 

   

 

 

   

 

 

 

Other income (expense):

      

Earnings from equity investments

     6,100       10,434       11,363  

Gain on sale of equity investment

     —         34,727       —    

Interest and debt expense

     (114,980     (119,561     (89,169

Other income (expense)

     (452     190       (687
  

 

 

   

 

 

   

 

 

 

Total other expense, net

     (109,332     (74,210     (78,493
  

 

 

   

 

 

   

 

 

 

Income before taxes

     229,876       114,472       200,089  

Income tax benefit

     (675     (192     (919
  

 

 

   

 

 

   

 

 

 

Net income

     230,551       114,664       201,008  

Less: Net income attributable to noncontrolling interests

     (4,134     (6,163     (157,928
  

 

 

   

 

 

   

 

 

 

Net income attributable to Buckeye Partners, L.P.

   $ 226,417     $ 108,501     $ 43,080  
  

 

 

   

 

 

   

 

 

 

Earnings per unit:

      

Basic

   $ 2.33     $ 1.20     $ 1.66  
  

 

 

   

 

 

   

 

 

 

Diluted

   $ 2.32     $ 1.20     $ 1.65  
  

 

 

   

 

 

   

 

 

 

Weighted average units outstanding:

      

Basic

     97,309       90,423       26,016  
  

 

 

   

 

 

   

 

 

 

Diluted

     97,635       90,772       26,086  
  

 

 

   

 

 

   

 

 

 

See Notes to Consolidated Financial Statements

 

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BUCKEYE PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

 

     Year Ended December 31,  
     2012     2011     2010  

Net income

   $ 230,551     $ 114,664     $ 201,008  

Other comprehensive income (loss):

      

Unrealized losses on derivative instruments

     (27,760     (104,090     (13,393

Gain on settlement of treasury lock, net of amortization

     (49     451       —    

Adjustments to funded status of benefit plans

     (3,229     (2,843     (7,019
  

 

 

   

 

 

   

 

 

 

Total other comprehensive loss

     (31,038     (106,482     (20,412
  

 

 

   

 

 

   

 

 

 

Comprehensive income

     199,513       8,182       180,596  

Less: Comprehensive income attributable to noncontrolling interests

     (4,134     (6,163     (119,647
  

 

 

   

 

 

   

 

 

 

Comprehensive income attributable to Buckeye Partners, L.P.

   $ 195,379     $ 2,019     $ 60,949  
  

 

 

   

 

 

   

 

 

 

See Notes to Consolidated Financial Statements

 

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BUCKEYE PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands, except unit amounts)

 

     December 31,  
     2012     2011  

Assets:

    

Current assets:

    

Cash and cash equivalents

   $ 6,776     $ 12,986  

Trade receivables, net

     262,023       206,601  

Construction and pipeline relocation receivables

     13,078       8,662  

Inventories

     259,163       298,304  

Derivative assets

     1,719       6,756  

Prepaid and other current assets

     91,563       92,727  
  

 

 

   

 

 

 

Total current assets

     634,322       626,036  

Property, plant and equipment, net

     4,188,648       3,847,573  

Equity investments

     68,713       65,882  

Goodwill

     818,121       753,100  

Intangible assets, net

     219,247       230,568  

Other non-current assets

     51,958       47,217  
  

 

 

   

 

 

 

Total assets

   $ 5,981,009     $ 5,570,376  
  

 

 

   

 

 

 

Liabilities and partners’ capital:

    

Current liabilities:

    

Line of credit

   $ 206,200     $ 251,200  

Accounts payable

     112,792       102,445  

Derivative liabilities

     82,989       1,859  

Accrued and other current liabilities

     192,385       199,475  
  

 

 

   

 

 

 

Total current liabilities

     594,366       554,979  

Long-term debt

     2,735,244       2,393,574  

Long-term derivative liabilities

     57,805       101,911  

Other non-current liabilities

     204,754       195,955  
  

 

 

   

 

 

 

Total liabilities

     3,592,169       3,246,419  
  

 

 

   

 

 

 

Commitments and contingent liabilities (Note 4)

     —         —    

Partners’ capital:

    

Buckeye Partners, L.P. capital:

    

Limited Partners (90,371,061 and 85,968,423 units outstanding as of December 31, 2012 and 2011, respectively)

     2,117,788       2,035,271  

Class B Units (7,974,750 and 7,304,880 units outstanding as of December 31, 2012 and 2011, respectively)

     413,304       395,639  

Accumulated other comprehensive loss

     (158,779     (127,741
  

 

 

   

 

 

 

Total Buckeye Partners, L.P. capital

     2,372,313       2,303,169  

Noncontrolling interests

     16,527       20,788  
  

 

 

   

 

 

 

Total partners’ capital

     2,388,840       2,323,957  
  

 

 

   

 

 

 

Total liabilities and partners’ capital

   $ 5,981,009     $ 5,570,376  
  

 

 

   

 

 

 

See Notes to Consolidated Financial Statements

 

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BUCKEYE PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

 

     Year Ended December 31,  
     2012     2011     2010  

Cash flows from operating activities:

      

Net income

   $ 230,551     $ 114,664     $ 201,008  

Adjustments to reconcile net income to net cash provided by operating activities:

      

Gain on sale of equity investment

     —         (34,727     —    

Value of ESOP shares released

     —         1,183       4,745  

Depreciation and amortization

     146,424       119,534       59,590  

Asset impairment expense

     59,950       —         —    

Goodwill impairment expense

     —         169,560       —    

Net changes in fair value of derivatives

     13,336       (66,747     (45,579

Non-cash deferred lease expense

     3,901       4,122       4,235  

Amortization of unfavorable storage contracts

     (10,994     (7,562     —    

Earnings from equity investments

     (6,100     (10,434     (11,363

Distributions from equity investments

     3,325       6,656       14,679  

Equity plan modification expense

     —         —         21,058  

Other non-cash items

     20,914       11,293       5,720  

Change in assets and liabilities, net of amounts related to acquisitions:

      

Trade receivables

     (53,472     (29,684     (43,109

Construction and pipeline relocation receivables

     (4,416     (1,859     7,292  

Inventories

     39,141       102,511       9,955  

Prepaid and other current assets

     (2,326     (4,220     16,368  

Accounts payable

     20,303       29,872       11,808  

Accrued and other current liabilities

     (20,742     (16,312     30,416  

Other non-current assets

     (1,624     17,546       9,528  

Other non-current liabilities

     3,465       (1,504     (3,872
  

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

     441,636       403,892       292,479  
  

 

 

   

 

 

   

 

 

 

Cash flows from investing activities:

      

Capital expenditures

     (331,338     (305,324     (77,699

Acquisition of interest in equity investment

     (350     (5,723     (13,512

Acquisitions, net of cash acquired

     (260,312     (1,084,469     (46,915

Proceeds from the sale of equity investment

     —         85,000       —    

Proceeds from disposal of property, plant and equipment

     1,678       237       23,938  
  

 

 

   

 

 

   

 

 

 

Net cash used in investing activities

     (590,322     (1,310,279     (114,188
  

 

 

   

 

 

   

 

 

 

Cash flows from financing activities:

      

Net proceeds from issuance of units

     246,805       736,871       —    

Proceeds from exercise of unit options

     1,067       3,567       4,789  

Payment of tax withholding on issuance of LTIP awards

     (2,604     —         —    

Issuance of long-term debt

     —         647,530       —    

Repayment of long term-debt

     —         (1,525     (6,178

Borrowings under BPL Credit Facility

     1,040,300       1,221,732       298,400  

Repayments under BPL Credit Facility

     (699,300     (995,732     (278,400

Net borrowings (repayments) under BES Credit Facility

     (45,000     (33,100     44,500  

Debt issuance costs

     —         (9,968     (3,551

Acquisition of additional interest in WesPac Memphis

     (17,328     —         —    

Repayment of debt assumed in BORCO acquisition

     —         (318,167     —    

Credits (costs) associated with agreement and plan of Merger

     422       (1,356     (16,427

Distributions paid to noncontrolling interests

     (10,707     (8,872     (195,564

Proceeds from settlement of treasury lock

     —         497       —    

Distributions paid to partners of Buckeye GP Holdings L.P.

     —         —         (49,808

Distributions paid to unitholders

     (371,179     (335,730     —    
  

 

 

   

 

 

   

 

 

 

Net cash provided by (used in) financing activities

     142,476       905,747       (202,239
  

 

 

   

 

 

   

 

 

 

Net decrease in cash and cash equivalents

     (6,210     (640     (23,948

Cash and cash equivalents — Beginning of year

     12,986       13,626       37,574  
  

 

 

   

 

 

   

 

 

 

Cash and cash equivalents — End of year

   $ 6,776     $ 12,986     $ 13,626  
  

 

 

   

 

 

   

 

 

 

See Notes to Consolidated Financial Statements

 

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BUCKEYE PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(In thousands)

 

    Buckeye Partners, L.P. Unitholders              
    General
Partner
    Limited
Partners
    Class B
Units
    Management
Units
    Equity Gains
on Issuance
of Buckeye’s
Limited
Partner Units
    Accumulated
Other
Comprehensive
Income (Loss)
    Noncontrolling
Interests
    Total  

Partners’ capital—January 1, 2010

  $ 7     $ 236,545     $ —       $ 3,225     $ 2,557     $ —        $ 1,209,960     $ 1,452,294  

Net income

    —         42,175       —         905       —          —          157,928       201,008  

Costs associated with agreement and plan of Merger

    —         (6,750     —         (128     —          —          (9,549     (16,427

Distributions paid to partners of BGH

    —         (48,877     —         (931     —          —          —         (49,808

Recognition of unit-based compensation charges

    —         21,916       —         419       —          —          —         22,335  

Amortization of unit-based compensation awards

    —         2,163       —         —         —          —          6,040       8,203  

Exercise of LP Unit options

    —         340       —         —         —          —          4,449       4,789  

Services Company’s non-cash ESOP distributions

    —         —         —         —         —          —          (5,385     (5,385

Distributions paid to noncontrolling interests

    —         —         —         —         —          —          (195,564     (195,564

Other comprehensive income (loss)

    —         —         —         —         —          17,869       (38,281     (20,412

Noncash accrual for distribution equivalent rights

    —         —         —         —         —          —          (936     (936

Cancellation of 80,000 LP Units in connection with the Merger

    —         —         —         —         —          —          3,132       3,132  

Other

    —         —         —         —         —          —          7,031       7,031  

Effect of Merger on partners’ capital

    (7     1,166,152       —         (3,490     (2,557     (39,128     (1,120,970     —    
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Partners’ capital—December 31, 2010

    —         1,413,664       —         —         —          (21,259     17,855       1,410,260  

Net income

    —         100,553       7,948       —         —          —          6,163       114,664  

Acquisition of 80% interest in BORCO

    —         —         —         —         —          —          276,508       276,508  

Acquisition of remaining interest in BORCO

    —         —         —         —         —          —          (278,211     (278,211

Costs associated with agreement and plan of Merger

    —         (1,356     —         —         —          —          —         (1,356

Distributions paid to unitholders

    —         (341,369     —         —         —          —          5,639         (335,730

Issuance of units to First Reserve for BORCO acquisition

    —         152,772       254,619       —         —          —          —         407,391  

Issuance of units to Vopak for BORCO acquisition

    —         36,041       60,069       —         —          —          —         96,110  

Net proceeds from issuance of units

    —         663,868       73,003       —         —          —          —         736,871  

Amortization of unit-based compensation awards

    —         9,233       —         —         —          —          —         9,233  

Exercise of LP Unit options

    —         3,567       —         —         —          —          —         3,567  

Services Company’s non-cash ESOP distributions

    —         —         —         —         —          —          (1,407     (1,407

Distributions paid to noncontrolling interests

    —         —         —         —         —          —          (8,872     (8,872

Other comprehensive loss

    —         —         —         —         —          (106,482     —         (106,482

Noncash accrual for distribution equivalent rights

    —         (1,210     —         —         —          —          —         (1,210

Other

    —         (492     —         —         —          —          3,113        2,621   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Partners’ capital—December 31, 2011

    —         2,035,271       395,639       —         —          (127,741     20,788       2,323,957  

Net income

    —         208,752       17,665       —         —          —          4,134       230,551  

Acquisition of additional interest in WesPac Memphis

    —         (14,674     —         —         —          —          (2,654     (17,328

Credits associated with agreement and plan of Merger

    —         422       —         —         —          —          —         422  

Distributions paid to unitholders

    —         (376,177     —         —         —          —          4,998       (371,179

Net proceeds from issuance of units

    —         246,805       —         —         —          —          —         246,805  

Amortization of unit-based compensation awards

    —         19,520       —         —         —          —          —         19,520  

Proceeds from exercise of unit options

    —         1,067       —         —         —          —          —         1,067  

Payment of tax withholding on issuance of LTIP awards

    —         (2,604               (2,604

Distributions paid to noncontrolling interests

    —         —         —         —         —          —          (10,707     (10,707

Other comprehensive loss

    —         —         —         —         —          (31,038     —         (31,038

Noncash accrual for distribution equivalent rights

    —         (1,328     —         —         —          —          —         (1,328

Other

    —         734       —         —         —          —          (32     702  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Partners’ capital—December 31, 2012

  $ —       $ 2,117,788     $ 413,304     $ —       $ —        $ (158,779   $ 16,527     $ 2,388,840  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

See Notes to Consolidated Financial Statements

 

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BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION

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

We were formed in 1986 and own and operate one of the largest independent refined 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. We also own and operate a natural gas storage facility in Northern California, and are a wholesale distributor of refined petroleum products in the United States in areas also served by our pipelines and terminals. 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.

On November 19, 2010, we consummated a transaction pursuant to a plan and agreement of merger (the “Merger Agreement”) with our general partner, Buckeye GP Holdings L.P. (“BGH”), BGH’s general partner and our subsidiary, Grand Ohio, LLC (“Merger Sub”). Pursuant to the Merger Agreement, Merger Sub was merged into BGH, with BGH as the surviving entity (the “Merger”). In the transaction, the incentive compensation agreement (also referred to as the incentive distribution rights) held by our general partner was cancelled, 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, all of the economic interest in BGH was acquired by us and BGH unitholders received aggregate consideration of approximately 20.0 million of our LP Units.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

Basis of Presentation and Principles of Consolidation

These consolidated financial statements were originally the financial statements of BGH prior to the effective date of the Merger. The Merger was accounted for as an equity transaction, and as such, changes in BGH’s ownership interest as a result of the Merger did not result in gain or loss recognition. The exchange of BGH’s units for our LP Units was accounted for as a BGH equity issuance and BGH was the surviving entity for accounting purposes. Although BGH was the surviving entity for accounting purposes, Buckeye was the surviving entity for legal purposes; consequently, the name on these financial statements was changed from “Buckeye GP Holdings L.P.” to “Buckeye Partners, L.P.”

The consolidated financial statements and the accompanying notes are prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) and the rules of the U.S. Securities and Exchange Commission (“SEC”). The consolidated financial statements include the accounts of our subsidiaries controlled by us and variable interest entities of which we are the primary beneficiary. We have eliminated all intercompany transactions in consolidation.

Asset Retirement Obligations

We regularly assess our legal obligations with respect to estimated retirements of certain of our long-lived assets to determine if an asset retirement obligation (“ARO”) exists. The fair value of a liability related to the retirement of long-lived assets is recorded at the time a regulatory or contractual obligation is incurred, including obligations to perform an asset retirement activity in which the timing or method of settlement are conditional on a

 

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Index to Financial Statements

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

future event that may or may not be within the control of the entity. If an ARO is identified and a liability is recorded, a corresponding asset is recorded concurrently and is depreciated over the remaining useful life of the asset. After the initial measurement, the liability is periodically adjusted for costs incurred or settled, accretion expense, and any revisions made to the assumptions related to the retirement costs. Generally, the fair value of the liability is determined based on estimates and assumptions related to (i) future retirement costs, (ii) future inflation rates and, (iii) credit-adjusted risk-free interest rates.

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

The following table presents information regarding our AROs (in thousands):

 

ARO liability balance, January 1, 2011

   $ 1,112  

Accretion expense

     100  
  

 

 

 

ARO liability balance, December 31, 2011

     1,212  

Increase in ARO liability (1)

     12,100  

Accretion expense

     112  
  

 

 

 

ARO liability balance, December 31, 2012 (2)

   $ 13,424  
  

 

 

 

 

(1) See Note 7 for a discussion of ARO recorded due to the abandonment of a portion of our NORCO pipeline system.
(2) Amount is included in other non-current liabilities.

Business Combinations

We allocate the total purchase price of a business combination to the assets acquired and the liabilities assumed based on their estimated fair values at the acquisition date, with the excess purchase price recorded as goodwill. For all material acquisitions, we engage an independent valuation specialist to assist us in determining the fair value of the assets acquired and liabilities assumed, including goodwill, based on recognized business valuation methodology. If the initial accounting for the business combination is incomplete by the end of the reporting period in which the acquisition occurs, an estimate will be recorded. Subsequent to the acquisition but not to exceed one year from the acquisition date, we will record any material adjustments retrospectively to the initial estimate based on new information obtained about facts and circumstances that existed as of the acquisition date. Also, we expense any acquisition-related costs as incurred in connection with each business combination. 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) an appropriate discount rate. 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.

 

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Index to Financial Statements

BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Business Segments

We operate and report in five business segments: (i) Pipelines & Terminals; (ii) International Operations; (iii) Natural Gas Storage; (iv) Energy Services; and (v) Development & Logistics. See Note 24 for discussion of our business segments.

Capitalization of Interest

Interest on borrowed funds is capitalized on projects during construction based on the approximate average interest rate of our debt. Interest capitalized for the years ended December 31, 2012, 2011 and 2010 was $9.2 million, $7.6 million and $2.5 million, respectively. The weighted average rates used to capitalize interest on borrowed funds was 4.5%, 4.2% and 4.8% for the years ended December 31, 2012, 2011 and 2010, respectively.

Cash and Cash Equivalents

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

Comprehensive Income

Our comprehensive income is determined based on net income adjusted for changes in fair value of derivatives for our hedging transactions, gain on settlement of treasury lock and adjustment to the funded status of our pension and post-retirement benefit plans.

Concentration of Credit Risk and Trade Receivables

Trade receivables are primarily due from oil and natural gas companies, refineries, marketing and trading companies, and commercial airlines. These concentrations of customers may affect our overall credit risk as these customers may be similarly affected by changes in economic, regulatory or other factors. We extend credit to customers and manage our credit risks through credit analysis and monitoring procedures, including credit approvals, credit limits and right of offset. Also, we manage our risk using letters of credit, prepayments and guarantees.

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

The activity in the allowance for doubtful accounts is as follows at the dates indicated (in thousands):

 

     December 31,  
     2012     2011     2010  

Balance at beginning of period

   $ 2,348     $ 2,893     $ 1,544  

Charged to expense

     1,533       200       4,868  

Write-offs, net of recoveries

     (456     (745     (3,519
  

 

 

   

 

 

   

 

 

 

Balance at end of period

   $ 3,425     $ 2,348     $ 2,893  
  

 

 

   

 

 

   

 

 

 

 

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BUCKEYE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Construction and Pipeline Relocation Receivables

Construction and pipeline relocation receivables represent valid claims against non-affiliated customers for services rendered in constructing or relocating pipelines and are recognized when services are rendered.

Contingencies

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

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

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

Cost of Product Sales and Natural Gas Storage Services

Cost of product sales relates to sales of refined petroleum products, consisting primarily of gasoline, propane, ethanol, biodiesel and middle distillates, such as heating oil, diesel fuel and kerosene, and fuel oil, as well as the effects of hedges of refined petroleum product acquisition costs and hedges of fixed-price contracts. In addition, costs related to hub service agreements, which consist of a variety of natural gas storage services under interruptible storage agreements, for which we will be required to make payment to a third party, are recognized as cost of natural gas storage services. These services principally include park and loan transactions. Parks occur when natural gas from a third party is injected and stored for a specified period. The third party then has the obligation to withdraw its stored natural gas at a future date. Title to the natural gas remains with the third party. Loans occur when natural gas is delivered to a third party in a specified period. The third party then has the obligation to redeliver natural gas at a future date. Costs related to park and loan transactions for which we are required to make payment are recognized ratably over the term of the agreement.

Debt Issuance Costs

Costs incurred upon the issuance of our debt instruments are capitalized and amortized over the life of the associated debt instrument on a straight-line basis, which approximates the effective interest method. If the debt instrument is retired before its scheduled maturity date, any remaining issuance costs associated with that debt instrument are expensed in the same period.

 

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Derivative Instruments

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

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

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

Earnings per Unit

Basic earnings per unit, which includes LP Units and Class B Units (as defined in Note 21), is determined by dividing our net income, after deducting the amount allocated to noncontrolling interests, by the weighted average units outstanding for the period. Diluted earnings per unit is calculated the same way except the weighted average units outstanding include any dilutive effect of LP Unit option grants or grants under the 2009 Long-Term Incentive Plan of Buckeye Partners, L.P. (the “LTIP”). See Note 18 for more information. Amounts reflecting historical BGH unit and per unit amounts included in this report have been restated for the reverse unit split.

Environmental Expenditures

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

 

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

Equity Investments

We account for investments in entities in which we do not exercise control, but have significant influence, using the equity method. Under this method, an investment is recorded at acquisition cost plus our equity in undistributed earnings or losses since acquisition, reduced by distributions received and amortization of excess net investment. Excess investment is the amount by which the total investment exceeds the proportionate share of the book value of the net assets of the investment. Such excess investment not related to any specific accounts of the investee are treated as goodwill and not amortized. Amounts associated with specific accounts of the investee are amortized. We evaluate equity method investments for impairment whenever events or changes in circumstances indicate that there is an “other than temporary” loss in value of the investment. In the event that the loss in value of an investment is “other than temporary”, we record a charge to earnings to adjust the carrying value to fair value. Estimates of future cash flows include (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses, (ii) long-term growth rates and (iii) probabilities assigned to different cash flow scenarios. A significant change in these underlying assumptions could result in recording an impairment charge. There were no impairments of our equity investments during the years ended December 31, 2012, 2011 or 2010.

Estimates

The preparation of consolidated financial statements in conformity with GAAP requires our management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses during the reporting period and disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Estimates and assumptions about future events and their effects cannot be made with certainty. Estimates may change as new events occur, when additional information becomes available and if our operating environment changes. Actual results could differ from our estimates.

Fair Value Measurements

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

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

 

   

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

 

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

 

   

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

At each balance sheet reporting date, we categorize our financial assets and liabilities using this hierarchy.

Foreign Currency

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. Foreign exchange gains and losses arising from transactions denominated in a currency other than the functional currency relate to a nominal amount of supply purchases and are included in net income (loss) in the consolidated statements of operations. The effects of foreign currency transactions were not considered to be material for the years ended December 31, 2012 and 2011. There were no effects of foreign currency transactions during the year ended December 31, 2010.

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. Goodwill is tested for impairment at a level of reporting referred to as a reporting unit. A reporting unit is a business segment or one level below a business segment for which discrete financial information is available and regularly reviewed by segment management. Our reporting units are our business segments.

We may perform a qualitative assessment to determine whether the fair value of our reporting units are more likely than not less than the carrying amount. If we believe the fair value is less than the carrying amount, we will perform step one of the two-step goodwill impairment test. The first step of the goodwill impairment test determines whether an impairment exists by comparing the fair value of a reporting unit with its carrying amount, including goodwill. If the estimated fair value of the reporting unit exceeds its carrying amount, no impairment is indicated. If the carrying amount of a reporting unit exceeds its estimated fair value, an impairment is indicated and the second step of the test is performed to measure the amount of impairment by comparing the implied fair value of the reporting unit goodwill to the carrying amount of that goodwill. The fair value of the reporting unit is allocated to all of the assets and liabilities of that unit as if the reporting unit had been acquired in a business combination. The excess of the fair value of the reporting unit over the amounts assigned to its assets and liabilities is the implied fair value of goodwill. The estimate of the fair value of the reporting unit is determined using a combination of an expected present value of future cash flows and a market multiple valuation method. The present value of future cash flows is estimated using (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses, (ii) long-term growth rates and (iii) 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.

Income Taxes

For U.S. federal income tax purposes, we and each of our subsidiaries, except for Buckeye Development & Logistics I LLC (“BDL”), are not taxable entities. Accordingly, our taxable income, except for BDL, is generally includable in the U.S. federal income tax returns of our individual partners and may differ significantly from taxable income reportable to our unitholders as a result of differences between the tax basis and financial reporting basis of certain assets and liabilities and other factors. In certain states in which we operate, our operating subsidiaries directly incur income-based state taxes, which are subject to examination by state taxing authorities. In addition,

 

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outside the continental U.S., our operations at the BORCO facility are not subject to income taxes by the Bahamian government; however, our operations at the Yabucoa terminal are subject to income taxes within the Commonwealth of Puerto Rico. Buckeye Caribbean Terminals LLC (“Buckeye Caribbean”) files annual income tax returns with the Puerto Rico Treasury Department.

We recognize deferred tax assets and liabilities for temporary differences between the amounts of assets and liabilities measured for financial reporting purposes and federal income tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. We evaluate the need for a valuation allowance and consider all available positive and negative evidence, including projected operating income or losses for the foreseeable future, to determine the likelihood of realizing the benefits of deferred tax assets. If the value of the deferred tax assets exceeds the estimated future benefit, we record a valuation allowance to reduce our deferred tax assets to the amount of future benefit that is more likely than not to be realized. In the future, if the realization of the deferred tax assets should occur, a reduction to the valuation allowance related to the deferred tax assets would increase net income in the period such determination is made.

Intangible Assets