Form 10-Q for quarterly period ended September 30, 2011
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2011

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

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 Web site, if any, every Interactive Data 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 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

Limited partner units and Class B units outstanding as of November 2, 2011: 85,941,866 and 7,175,839, respectively.

 

 

 


Table of Contents

TABLE OF CONTENTS

 

          Page  
PART I. FINANCIAL INFORMATION   
Item 1.    Financial Statements   
  

Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September  30, 2011 and 2010 (Unaudited)

     2   
  

Condensed Consolidated Statements of Comprehensive Income (Loss) for the Three and Nine Months Ended September 30, 2011 and 2010 (Unaudited)

     3   
  

Condensed Consolidated Balance Sheets as of September 30, 2011 and December  31, 2010 (Unaudited)

     4   
  

Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September  30, 2011 and 2010 (Unaudited)

     5   
  

Condensed Consolidated Statements of Partners’ Capital for the Nine Months Ended September  30, 2011 and 2010 (Unaudited)

     6   
  

Notes to Unaudited Condensed Consolidated Financial Statements:

  
  

1.      Organization and Basis of Presentation

     7   
  

2.      Acquisitions and Dispositions

     10   
  

3.      Commitments and Contingencies

     14   
  

4.      Inventories

     16   
  

5.      Prepaid and Other Current Assets

     17   
  

6.      Property, Plant and Equipment

     17   
  

7.      Equity Investments

     18   
  

8.      Goodwill and Intangible Assets

     19   
  

9.      Other Non-Current Assets

     21   
  

10.    Accrued and Other Current Liabilities

     21   
  

11.    Long-term Debt

     22   
  

12.    Other Non-Current Liabilities

     24   
  

13.    Accumulated Other Comprehensive Income (Loss)

     25   
  

14.    Derivative Instruments, Hedging Activities and Fair Value Measurements

     25   
  

15.    Pensions and Other Postretirement Benefits

     33   
  

16.    Unit-Based Compensation Plans

     34   
  

17.    Related Party Transactions

     36   
  

18.    Partners’ Capital and Distributions

     37   
  

19.    Earnings (Loss) Per Unit

     38   
  

20.    Business Segments

     39   
  

21.    Relocation

     43   
  

22.    Supplemental Cash Flow Information

     44   
Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations      45   
Item 3.    Quantitative and Qualitative Disclosures About Market Risk      68   
Item 4.    Controls and Procedures      72   
PART II. OTHER INFORMATION   
Item 1.    Legal Proceedings      72   
Item 1A.    Risk Factors      72   
Item 6.    Exhibits      73   

 

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Table of Contents

PART I. FINANCIAL INFORMATION

 

Item 1. Financial Statements

BUCKEYE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit amounts)

(Unaudited)

 

     Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
     2011     2010     2011     2010  

Revenue:

        

Product sales

   $ 884,436     $ 564,044     $ 2,775,698     $ 1,633,958  

Transportation and other services

     232,475       170,813       670,841       499,349  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total revenue

     1,116,911       734,857       3,446,539       2,133,307  
  

 

 

   

 

 

   

 

 

   

 

 

 

Costs and expenses:

        

Cost of product sales and natural gas storage services

     881,596       560,248       2,773,899       1,628,630  

Operating expenses

     96,776       68,685       266,909       204,037  

Depreciation and amortization

     31,230       15,062       87,227       44,259  

General and administrative

     15,054       11,349       47,751       35,438  

Goodwill impairment expense

     169,560       —          169,560       —     
  

 

 

   

 

 

   

 

 

   

 

 

 

Total costs and expenses

     1,194,216       655,344       3,345,346       1,912,364  
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

     (77,305     79,513       101,193       220,943  
  

 

 

   

 

 

   

 

 

   

 

 

 

Other income (expense):

        

Earnings from equity investments

     2,379       3,391       7,760       8,807  

Gain on sale of equity investment

     —          —          34,112       —     

Interest and debt expense

     (33,199     (22,082     (90,292     (65,088

Other income (expense)

     (75     140       432       380  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (expense)

     (30,895     (18,551     (47,988     (55,901
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

     (108,200     60,962       53,205       165,042  

Less: net income attributable to noncontrolling interests

     (1,500     (49,021     (4,391     (130,324
  

 

 

   

 

 

   

 

 

   

 

 

 

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

   $ (109,700   $ 11,941     $ 48,814     $ 34,718  
  

 

 

   

 

 

   

 

 

   

 

 

 

Earnings (loss) per unit:

        

Basic

   $ (1.18   $ 0.60     $ 0.55     $ 1.74  
  

 

 

   

 

 

   

 

 

   

 

 

 

Diluted

   $ (1.18   $ 0.60     $ 0.54     $ 1.74  
  

 

 

   

 

 

   

 

 

   

 

 

 

Weighted average number of units outstanding:

        

Basic

     92,982       19,952       89,499       19,952  
  

 

 

   

 

 

   

 

 

   

 

 

 

Diluted

     92,982       19,952       89,831       19,952  
  

 

 

   

 

 

   

 

 

   

 

 

 

See Notes to Unaudited Condensed Consolidated Financial Statements.

 

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BUCKEYE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

(Unaudited)

 

     Three Months Ended
September 30,
     Nine Months Ended
September 30,
 
     2011     2010      2011     2010  

Net income (loss)

   $ (108,200   $ 60,962      $ 53,205     $ 165,042  

Other comprehensive income (loss):

         

Change in value of derivatives

     (83,565     —           (92,659     —     

Amortization of interest rate swaps

     242       —           724       —     

Gain on settlement of treasury lock, net of amortization

     (12     —           464       —     

Amortization of benefit plan costs

     (154     —           (394     —     
  

 

 

   

 

 

    

 

 

   

 

 

 

Total other comprehensive loss

     (83,489     —           (91,865     —     
  

 

 

   

 

 

    

 

 

   

 

 

 

Comprehensive income (loss)

   $ (191,689   $ 60,962      $ (38,660   $ 165,042  
  

 

 

   

 

 

    

 

 

   

 

 

 

See Notes to Unaudited Condensed Consolidated Financial Statements.

 

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BUCKEYE PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except unit amounts)

(Unaudited)

 

     September 30,
2011
    December 31,
2010
 

Assets:

    

Current assets:

    

Cash and cash equivalents

   $ 16,196     $ 13,626  

Trade receivables, net

     175,995       167,274  

Construction and pipeline relocation receivables

     6,156       6,803  

Inventories

     384,306       351,605  

Derivative assets

     27,330       1,634  

Prepaid and other current assets

     80,868       85,689  
  

 

 

   

 

 

 

Total current assets

     690,851       626,631  

Property, plant and equipment, net

     3,738,178       2,305,884  

Equity investments

     67,400       107,047  

Goodwill

     761,283       432,124  

Intangible assets, net

     249,382       44,067  

Other non-current assets

     50,836       58,463  
  

 

 

   

 

 

 

Total assets

   $ 5,557,930     $ 3,574,216  
  

 

 

   

 

 

 

Liabilities and partners’ capital:

    

Current liabilities:

    

Line of credit

   $ 346,800     $ 284,300  

Current portion of long-term debt

     —          1,525  

Accounts payable

     68,882       68,530  

Derivative liabilities

     1,656       17,285  

Accrued and other current liabilities

     183,049       144,880  
  

 

 

   

 

 

 

Total current liabilities

     600,387       516,520  

Long-term debt

     2,315,106       1,519,393  

Long-term derivative liabilities

     89,515       —     

Other non-current liabilities

     189,209       128,043  
  

 

 

   

 

 

 

Total liabilities

     3,194,217       2,163,956  
  

 

 

   

 

 

 

Commitments and contingent liabilities

     —          —     

Partners’ capital:

    

Buckeye Partners, L.P. capital:

    

Limited Partners (85,923,830 and 71,436,099 units outstanding as of September 30, 2011 and December 31, 2010, respectively)

     2,067,607       1,413,664  

Class B Units (7,175,839 and 0 units outstanding as of September 30, 2011 and December 31, 2010, respectively)

     391,238       —     

Accumulated other comprehensive loss

     (113,124     (21,259
  

 

 

   

 

 

 

Total Buckeye Partners, L.P. capital

     2,345,721       1,392,405  

Noncontrolling interests

     17,992       17,855  
  

 

 

   

 

 

 

Total partners’ capital

     2,363,713       1,410,260  
  

 

 

   

 

 

 

Total liabilities and partners’ capital

   $ 5,557,930     $ 3,574,216  
  

 

 

   

 

 

 

See Notes to Unaudited Condensed Consolidated Financial Statements.

 

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BUCKEYE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

 

     Nine Months Ended
September 30,
 
     2011     2010  

Cash flows from operating activities:

    

Net income

   $ 53,205     $ 165,042  

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

    

Gain on sale of equity investment

     (34,112     —     

Value of ESOP shares released

     1,183       3,480  

Depreciation and amortization

     87,227       44,259  

Goodwill impairment expense

     169,560       —     

Net changes in fair value of derivatives

     (150,433     (16,152

Non-cash deferred lease expense

     3,091       3,176  

Amortization of unfavorable storage contracts

     (4,813     —     

Earnings from equity investments

     (7,760     (8,807

Distributions from equity investments

     1,922       11,027  

Amortization of other non-cash items

     10,074       7,552  

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

    

Trade receivables

     922       (9,530

Construction and pipeline relocation receivables

     647       5,251  

Inventories

     (9,590     56,657  

Prepaid and other current assets

     8,121       31,289  

Accounts payable

     (3,691     (377

Accrued and other current liabilities

     (36,724     (2,367

Other non-current assets

     11,669       3,059  

Other non-current liabilities

     81,564       2,548  
  

 

 

   

 

 

 

Total adjustments from operating activities

     128,857       131,065  
  

 

 

   

 

 

 

Net cash provided by operating activities

     182,062       296,107  
  

 

 

   

 

 

 

Cash flows from investing activities:

    

Capital expenditures

     (191,368     (49,275

Acquisition of interest in equity investment

     (5,723     (13,512

Deposit in anticipation of acquisition

     (500     —     

Acquisitions, net of cash acquired

     (1,079,411     (1,269

Proceeds from sale of equity investment

     85,000       —     

Net proceeds from disposal of property, plant and equipment

     573        22,448  
  

 

 

   

 

 

 

Net cash used in investing activities

     (1,191,429     (41,608
  

 

 

   

 

 

 

Cash flows from financing activities:

    

Net proceeds from issuance of units

     736,977       —     

Proceeds from exercise of unit options

     2,226       4,275  

Issuance of long-term debt

     647,530       —     

Repayment of long term-debt

     (1,525     (4,644

Borrowings under BPL Credit Facilities

     1,100,232       175,900  

Repayments under BPL Credit Facilities

     (952,532     (233,900

Net borrowings (repayments) under BES Credit Facilities

     62,500       (28,000

Debt issuance costs

     (9,968     (3,245

Repayment of debt assumed in BORCO acquisition

     (318,167     —     

Costs associated with agreement and plan of merger

     (1,415     (4,514

Distributions paid to noncontrolling partners of Buckeye Partners, L.P.

     (4,260     (145,516

Proceeds from settlement of treasury lock

     497       —     

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

     —          (36,507

Distributions paid to unitholders

     (250,158     —     
  

 

 

   

 

 

 

Net cash provided by (used in) financing activities

     1,011,937       (276,151
  

 

 

   

 

 

 

Net increase (decrease) in cash and cash equivalents

     2,570       (21,652

Cash and cash equivalents — Beginning of period

     13,626       37,574  
  

 

 

   

 

 

 

Cash and cash equivalents — End of period

   $ 16,196     $ 15,922  
  

 

 

   

 

 

 

See Notes to Unaudited Condensed Consolidated Financial Statements.

 

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BUCKEYE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(In thousands)

(Unaudited)

 

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

Partners’ capital - January 1, 2011

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

Net income

    —          45,311       3,503       —          —          —          4,391       53,205  

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

    —          (1,415     —          —          —          —          —          (1,415

Distributions paid to partners

    —          (250,158     —          —          —          —          —          (250,158

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  

Issuance of units to institutional investors

    —          350,001       75,000       —          —          —          —          425,001  

Equity issuance costs

    —          (2,700     (1,953     —          —          —          —          (4,653

Net proceeds from issuance of LP Units in underwritten public offering

    —          316,629       —          —          —          —          —          316,629  

Amortization of unit-based compensation awards

    —          6,588       —          —          —          —          —          6,588  

Exercise of LP Unit options

    —          2,226       —          —          —          —          —          2,226  

Services Company’s non-cash ESOP distributions

    —          —          —          —          —          —          (1,410     (1,410

Distributions paid to noncontrolling interests

    —          —          —          —          —          —          (4,260     (4,260

Amortization of benefit plan costs

    —          —          —          —          —          (394     —          (394

Change in value of derivatives

    —          —          —          —          —          (92,659     —          (92,658

Amortization of interest rate swaps

    —          —          —          —          —          724       —          723  

Amortization of treasury lock settlement

    —          —          —          —          —          (33     —          (33

Proceeds from settlement of treasury lock

    —          —          —          —          —          497       —          497  

Noncash accrual for distribution equivalent rights

    —          (892     —          —          —          —          —          (892

Other

    —          (460     —          —          —          —          3,119       2,659  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Partners’ capital - September 30, 2011

  $ —        $ 2,067,607     $ 391,238     $ —        $ —        $ (113,124   $ 17,992     $ 2,363,713  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Partners’ capital - January 1, 2010

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

Net income

    —          34,068       —          650       —          —          130,324       165,042  

Costs associated with agreement and plan of merger

    —          (2,746     —          (52     —          —          (4,129     (6,927

Distributions paid to partners of BGH

    —          (35,823     —          (684     —          —          —          (36,507

Recognition of unit-based compensation charges

    —          941       —          18       —          —          —          959  

Amortization of unit-based compensation awards

    —          —          —          —          —          —          5,159       5,159  

Exercise of LP Unit options

    —          —          —          —          —          —          4,275       4,275  

Services Company’s non-cash ESOP distributions

    —          —          —          —          —          —          (2,639     (2,639

Distributions paid to noncontrolling interests

    —          —          —          —          —          —          (145,516     (145,516

Change in value of derivatives

    —          —          —          —          —          —          (58,772     (58,772

BGH’s investment in LP units

    —          —          —          —          —          —          4,503       4,503  

Other

    —          —          —          —          —          —          690       690  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Partners’ capital - September 30, 2010

  $ 7     $ 232,985     $ —        $ 3,157     $ —        $ 2,557     $ 1,143,855     $ 1,382,561  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

See Notes to Unaudited Condensed Consolidated Financial Statements.

 

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Table of Contents

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND BASIS OF PRESENTATION

Partnership 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. Buckeye GP 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 BGH’s merger with a wholly owned subsidiary of Buckeye (see below for further information). As used in these Notes to Unaudited Condensed 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 with approximately 6,100 miles of pipeline and over 100 active products terminals that provide aggregate storage capacity of over 64 million barrels. In 2011, we acquired (i) the Bahamas Oil Refining Company International Limited (“BORCO”) terminal facility in Freeport, Grand Bahama, The Bahamas, with a total installed capacity of approximately 21.6 million barrels, (ii) 33 refined petroleum products terminals with a total storage capacity of over 10 million barrels and approximately 650 miles of refined petroleum products pipelines (see Note 2) and (iii) a 124-mile pipeline and terminal in Bangor, Maine with approximately 140,000 barrels of storage capacity and a terminal in Portland, Maine through a 50/50 joint venture with approximately 725,000 barrels (see Note 2). In addition, we operate and maintain approximately 3,400 miles of other 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 high performance 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.

We operate and report in five business segments: Pipelines & Terminals; International Operations; Natural Gas Storage; Energy Services; and Development & Logistics. Effective January 1, 2011, we realigned our five business segments. We combined the Pipeline Operations and Terminalling & Storage segments into one segment, the Pipelines & Terminals segment, and moved our terminal in Yabucoa, Puerto Rico, previously included as part of the Terminalling & Storage segment, to a new International Operations segment with the BORCO facility. See Note 20 for a discussion of our business segments.

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 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.

Buckeye Pipe Line Services Company (“Services Company”) was formed in 1996 in connection with the establishment of the Buckeye Pipe Line Services Company Employee Stock Ownership Plan (the “ESOP”). At September 30, 2011, Services Company owned approximately 1.6% of our LP Units. Services Company employees provide services to our operating subsidiaries. Pursuant to a services agreement entered into in December 2004, our operating subsidiaries reimburse Services Company for the costs of the services provided by Services Company. Services Company has been consolidated into our financial statements.

Basis of Presentation and Principles of Consolidation

These consolidated financial statements reflect the financial results of BGH for periods prior to the effective date of the Merger. BGH is considered the surviving consolidated entity for accounting purposes, although Buckeye

 

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is the surviving consolidated entity for legal and reporting purposes. The Merger was accounted for as an equity transaction. Therefore, changes in BGH’s ownership interest as a result of the Merger did not result in gain or loss recognition. Costs incurred associated with the Merger were charged directly to partners’ capital. Under applicable accounting guidance, 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. Consequently, the name on these financial statements for periods prior to the Merger has been changed from “Buckeye GP Holdings L.P.” to “Buckeye Partners, L.P.”

The reconciliation of Buckeye’s net income, as historically reported, to the net income reported in these financial statements for the three and nine months ended September 30, 2010 is as follows (in thousands):

 

     Three Months Ended
September 30, 2010
    Nine Months Ended
September 30, 2010
 

Buckeye’s net income, as previously reported

   $ 63,113     $ 170,816  

Adjustments:

    

Depreciation and amortization (1)

     1,115       3,348  

Costs and expenses (2)

     (3,198     (8,860

Other (3)

     (68     (262
  

 

 

   

 

 

 

Net income

   $ 60,962     $ 165,042  
  

 

 

   

 

 

 

 

(1) Represents the amortization of the market value of LP Units issued in August 1997 in connection with the restructuring of Services Company’s ESOP. The market value of those LP Units was $64.2 million, and this amount was recorded as a deferred charge and is being amortized on a straight-line basis over 13.5 years. This deferred charge was not previously included in Buckeye’s net income because Services Company was consolidated with BGH, but not Buckeye, for periods prior to the effective date of the Merger.
(2) Amounts include payroll and benefits costs, professional fees, certain state franchise taxes, insurance costs and miscellaneous other expenses incurred by BGH.
(3) Includes interest expense on Services Company’s debt and commitment fees on BGH’s credit facility. The interest expense was not previously included in Buckeye’s net income because Services Company was consolidated with BGH, but not Buckeye, for periods prior to the effective date of the Merger.

Pursuant to the Merger Agreement, BGH’s unitholders received a total of approximately 20.0 million of Buckeye’s LP Units in the aggregate 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 on the date of the Merger. 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. Therefore, since BGH was the surviving accounting entity, the weighted average number of LP Units outstanding used for basic and diluted earnings (loss) per unit calculations are BGH’s historical weighted average common units outstanding adjusted for the reverse unit split and the addition of Buckeye’s existing units. Amounts reflecting historical BGH unit and per unit amounts included in this report have been restated for the reverse unit split.

The condensed 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 financial statements include our accounts on a consolidated basis. We have eliminated all intercompany transactions in consolidation. The consolidated financial statements include the financial results of our wholly-owned subsidiaries and the financial results of Services Company on a consolidated basis.

Recent Accounting Developments

Fair Value Measurements. In January 2010, the Financial Accounting Standards Board (“FASB”) issued guidance that requires new disclosures related to fair value measurements. The new guidance requires expanded disclosures related to a gross presentation for Level 3 activity. The new accounting guidance was effective for fiscal years beginning after December 15, 2010 and for interim periods within those years. The new guidance became

 

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effective for us on January 1, 2011. We have included the enhanced disclosure requirements regarding fair value measurements in Note 14.

In May 2011, the FASB issued guidance that is intended to result in convergence between GAAP and International Financial Reporting Standards requirements for measurement of and disclosures about fair value. The amendments are not expected to have a significant impact on companies applying GAAP. Key provisions of the new guidance include: a prohibition on grouping financial instruments for purposes of determining fair value, except when an entity manages market and credit risks on the basis of the entity’s net exposure to the group; an extension of the prohibition against the use of a blockage factor to all fair value measurements (that prohibition currently applies only to financial instruments with quoted prices in active markets); and a requirement that for recurring Level 3 fair value measurements, entities disclose quantitative information about unobservable inputs, a description of the valuation process used and qualitative details about the sensitivity of the measurements. In addition, for items not carried at fair value but for which fair value is disclosed, entities will be required to disclose the level within the fair value hierarchy that applies to the fair value measurement disclosed. This new guidance is effective for interim and annual periods beginning after December 15, 2011. We do not expect the adoption of this guidance to have an impact on our consolidated financial statements.

Intangibles, Goodwill and Other. In December 2010, the FASB issued guidance that amended the goodwill impairment test for reporting units with zero or negative carrying amounts. The objective of this new guidance was to address questions about entities with reporting units with zero or negative carrying amounts because some entities concluded that the first step of the goodwill impairment test is passed in those circumstances because the fair value of their reporting unit will generally be greater than zero. The new guidance was effective for fiscal years and interim periods, within those years, beginning after December 15, 2010. Our adoption did not have any material impact on our consolidated financial statements.

In September 2011, the FASB issued guidance that will amend testing goodwill for impairment. Under the revised guidance, entities testing goodwill for impairment have the option of performing a qualitative assessment before calculating the fair value of the reporting unit (i.e., step 1 of the goodwill impairment test). If entities determine, on the basis of qualitative factors, that the fair value of the reporting unit is more likely than not less than the carrying amount, the two-step impairment test would be required. The amended guidance does not change how goodwill is calculated or assigned to reporting units nor revise the requirement to test goodwill for impairment annually or between annual tests if events or circumstances warrant. However, it does revise the examples of events and circumstances that an entity should consider. The amendments are effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. Early adoption is permitted. We do not expect the adoption of this guidance to have an impact on our consolidated financial statements. For the goodwill interim impairment testing for the Natural Gas Storage reporting unit (see Note 8), we did not apply the amended guidance as described above.

Business Combinations. In December 2010, the FASB issued guidance that clarifies disclosures related to pro forma information for business combinations that occurred in the current period. The amendments specify that if an entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The amendments also expand the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The new guidance was effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. We have included the enhanced disclosure requirements regarding pro forma information for business combinations in Note 2.

Presentation of Comprehensive Income. In June 2011, the FASB issued guidance that will require companies to present the components of net income and other comprehensive income either as one continuous statement or as two consecutive statements. The guidance eliminates the option to present components of other comprehensive income as part of the statement of changes in unitholders’ equity. The guidance does not change the items which must be reported in other comprehensive income, how such items are measured or when they must be reclassified to net income. The new guidance is effective for interim and annual periods beginning after December 15, 2011. Because

 

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this guidance impacts presentation only, it will have no effect on our financial condition, results of operations or cash flows.

2. ACQUISITIONS AND DISPOSITIONS

Acquisitions

The acquisitions of terminals from an affiliate of Royal Dutch Shell plc (“Shell”) and from affiliates of FRC Founders Corporation (“First Reserve”) and Vopak Bahamas B.V. (“Vopak”), the acquisition of pipeline and terminal assets from BP Products North America Inc. and its affiliates (“BP”) and the acquisition of a pipeline, terminal and equity investment from an affiliate of ExxonMobil Corporation (ExxonMobil) located in Maine have been accounted for as business combinations. The total purchase price for these acquisitions was allocated to the fair value of the assets acquired and the liabilities assumed based on an assessment of their fair values at the acquisition date, with amounts exceeding the fair values being recorded as goodwill. The results of their operations have been included in our condensed consolidated financial statements since their respective acquisition dates.

Puerto Rico Terminal Acquisition

On December 10, 2010, we, through a wholly owned subsidiary, acquired a refined petroleum products terminal in Yabucoa, Puerto Rico from an affiliate of Shell for $32.8 million, net of cash acquired of $3.5 million. The terminal includes 44 storage tanks with approximately 4.6 million barrels of gasoline, jet fuel, diesel, fuel oil and crude oil storage capacity. Shell entered into a commercial contract with us concurrent with the acquisition regarding usage of the acquired facility. We believe the acquisition of these assets furthers our geographic diversification efforts as this was our first acquisition outside the continental United States and enabled us to participate in a growth market outside our existing system footprint. The operations of these acquired assets are reported in the International Operations segment. The purchase price has been allocated to tangible and intangible assets acquired and liabilities assumed as follows (in thousands):

 

Current assets

   $ 183  

Inventory

     867  

Property, plant and equipment

     31,770  

Intangible assets

     3,363  

Other assets

     17,720  

Current liabilities

     (3,413

Other non-current liabilities

     (17,720
  

 

 

 

Allocated purchase price

   $ 32,770  
  

 

 

 

During 2011, we completed the acquisition of the refined petroleum products terminal in Yabucoa, Puerto Rico through the acquisition of a Puerto Rican entity, which is undergoing an audit of its Puerto Rico income tax returns for the tax years 2002 through 2005. The Puerto Rico Treasury Department has completed the audit of such years and has informed us that no adjustment is required to the taxable income or losses reported on such years. However, the Puerto Rico Treasury Department has notified the entity of a certain area for discussion on taxable year 2008 related to the possible recapture of investment tax credits previously granted to Shell but has not issued a preliminary or final notice of debt regarding such issue. Pursuant to the purchase and sale agreement we entered into in connection with this acquisition, an affiliate of Shell has assumed the full responsibility, through an indemnity and hold harmless provision, for the payment of any income tax debt that may be assessed by the Puerto Rico Treasury Department under this audit. In the purchase price allocation above, we recorded a $17.7 million liability related to the uncertain outcome of the income tax audit with an offsetting indemnification asset from Shell for the same amount.

 

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BORCO Acquisition

On December 18, 2010, we, through a wholly owned subsidiary, entered into a sale and purchase agreement with affiliates of First Reserve, pursuant to which we agreed to acquire First Reserve’s indirect 80% interest in FR Borco Coop Holdings, L.P. (“FRBCH”), the indirect owner of BORCO, for $1.15 billion, financed through a combination of debt and equity, including the issuance of Class B units representing limited partner interests (“Class B Units”) and LP Units to First Reserve. BORCO is the fourth largest oil and petroleum products storage terminal in the world and the largest petroleum products facility in the Caribbean with current storage capacity of approximately 21.6 million barrels. On January 18, 2011, we completed the purchase of First Reserve’s interest in BORCO through the acquisition by us of all of the partnership interests in FR Borco Topco, L.P., which indirectly owned First Reserve’s interest.

Vopak, which is based in The Netherlands, owned the remaining 20% interest in FRBCH. On February 16, 2011, Vopak sold its 20% interest in FRBCH to us for approximately $276.5 million of cash and equity, which is a proportionate price and on the same terms and conditions as those in the sale and purchase agreement with First Reserve.

The following table presents the aggregate consideration paid or issued to complete the BORCO acquisition (in thousands):

 

     First Reserve      Vopak      Combined  

Cash consideration

   $ 644,049      $ 164,616      $ 808,665  

Fair value of LP Units and Class B Units issued (1)

     407,391        96,110        503,501  

Cash paid on behalf of the sellers (2)

     96,241        15,780        112,021  
  

 

 

    

 

 

    

 

 

 

Consideration issued to effect the transactions

   $ 1,147,681      $ 276,506      $ 1,424,187  
  

 

 

    

 

 

    

 

 

 

 

(1) On January 18, 2011, we issued 2,483,444 LP Units and 4,382,889 Class B Units to First Reserve, which represented a negotiated value of $400.0 million of consideration. On February 16, 2011, we issued 620,861 LP Units and 1,095,722 Class B Units to Vopak, which represented a negotiated value of $100.0 million of consideration. In accordance with accounting for business combinations, the fair values of the units issued to First Reserve and Vopak on their respective acquisition dates were determined to be $407.4 million and $96.1 million, respectively.
(2) Approximately $79.3 million was to be held in escrow related to Bahamian transfer taxes payable, approximately $23.2 million was used to make certain payments to BORCO’s operator and indirect minority owner and to pay certain fees and expenses incurred by FRBCH and its affiliates in connection with the transaction and approximately $9.5 million was used to pay bonuses to employees that became payable as a result of the transaction.

On January 13, 2011, we issued $650.0 million aggregate principal amount of 4.875% Notes due 2021 (the “4.875% Notes”) in an underwritten public offering. The notes were issued at 99.62% of their principal amount. Total proceeds from this offering, after underwriters’ fees, expenses and debt issuance costs of $4.9 million, were approximately $642.6 million, and were used to fund a portion of the purchase price of the BORCO acquisition.

On January 18 and 19, 2011, we issued 5,794,725 LP Units and 1,314,870 Class B Units to institutional investors for aggregate consideration of approximately $425.0 million to fund a portion of the BORCO acquisition. On January 18, 2011, we issued 2,483,444 LP Units and 4,382,889 Class B Units to First Reserve as $400.0 million of consideration to fund a portion of the BORCO acquisition. On February 16, 2011, we issued 620,861 LP Units and 1,095,722 Class B Units to Vopak as $100.0 million of consideration to fund a portion of the BORCO acquisition. Equity issuance costs incurred on these transactions were approximately $4.6 million. The remaining purchase price was funded with cash on hand at closing and borrowings under our Prior BPL Credit Facility (as defined in Note 11).

On January 18, 2011, in connection with the BORCO acquisition, we repaid all of BORCO’s outstanding indebtedness and settled BORCO’s interest rate derivative instruments, collectively representing approximately $318.2 million.

 

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The results of operations of the BORCO acquisition are included in our condensed consolidated financial statements from the date of acquisition and are included in our International Operations segment. The acquisition cost has been allocated to assets acquired and liabilities assumed based on estimated fair values at the acquisition date, with amounts exceeding the fair value recorded as goodwill, which represents both expected synergies from combining the BORCO acquisition with our existing operations and the economic value attributable to future expansion projects resulting from this acquisition. Fair values have been developed using recognized business valuation techniques and are subject to change pending final valuation analysis. The purchase price has been allocated to tangible and intangible assets acquired and liabilities assumed, on a preliminary basis, as follows (in thousands):

 

Current assets

   $ 40,842  

Inventory

     1,645  

Property, plant and equipment

     1,105,278  

Intangible assets

     206,000  

Other assets

     415  

Goodwill

     498,719  

Current liabilities

     (54,627

Debt, including interest rate derivative instruments

     (318,167

Other non-current liabilities

     (55,918
  

 

 

 

Allocated purchase price

   $ 1,424,187  
  

 

 

 

Pipelines and Terminals Acquisition

On June 1, 2011, we acquired 33 refined petroleum products terminals with total storage capacity of over 10 million barrels and approximately 650 miles of refined petroleum products pipelines from BP for $166.0 million. The terminal and pipeline assets are located in the Midwestern, Southeastern and Western United States. BP entered into multiple commercial contracts with us concurrent with the acquisition relating to the continued usage of these assets. We believe the acquisition of these assets further extends our operations into new, key geographic markets. The operations of these acquired assets are reported in the Pipelines & Terminals segment. We funded this acquisition with borrowings under our Prior BPL Credit Facility. The purchase price has been allocated to tangible and intangible assets acquired and liabilities assumed, on a preliminary basis, as follows (in thousands):

 

Inventory

   $ 1,161  

Property, plant and equipment

     174,597  

Intangible assets

     8,940  

Environmental and other liabilities

     (18,722
  

 

 

 

Allocated purchase price

   $ 165,976  
  

 

 

 

Acquisition of Refined Petroleum Products Terminals and Pipeline in Maine

On July 19, 2011, we acquired a 124-pipeline and terminal in Bangor, Maine (“Bangor terminal”) with approximately 140,000 barrels of storage capacity and a terminal in Portland, Maine (“South Portland terminal”) through a 50/50 joint venture with Irving Oil Terminals Inc. with approximately 725,000 barrels of storage capacity from an affiliate of ExxonMobil for $23.5 million in cash. The South Portland terminal is operated by our Development & Logistics segment. We accounted for the South Portland terminal using the equity method of accounting. See Note 7 for equity investment information. The pipeline, Bangor terminal and equity investment are reported in the Pipelines & Terminals segment. We financed this acquisition with borrowings under our Prior BPL Credit Facility. The purchase price was allocated principally to property, plant, and equipment, on a preliminary basis.

 

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Unaudited Pro forma Financial Results

Our condensed consolidated statements of operations do not include earnings from BORCO prior to January 18, 2011, the effective date of the BORCO acquisition. The following table presents selected unaudited pro forma earnings information for the three and nine months ended September 30, 2011 and 2010, as if the BORCO acquisition had occurred on January 1, 2010. This pro forma information does not give effect to any of the other acquisitions we have made since January 1, 2010, as pro forma results including those acquisitions would not be materially different from the information presented in our accompanying condensed consolidated statements of operations. The pro forma information presented below was prepared using BORCO’s historical financial data and reflects certain estimates and assumptions made by our management. Our unaudited pro forma financial information was prepared for comparative purposes only and is not necessarily indicative of what our consolidated financial results would have been had we actually acquired BORCO on January 1, 2010 or the results that may be attained in the future (in thousands):

 

     Three Months Ended
September 30,
     Nine Months Ended
September 30,
 
     2011     2010      2011      2010  

Revenue:

          

As reported

   $ 1,116,911     $ 734,857      $ 3,446,539      $ 2,133,307  

Pro forma adjustments

     —          49,370        8,422        146,489  
  

 

 

   

 

 

    

 

 

    

 

 

 

Pro forma revenue

   $ 1,116,911     $ 784,227      $ 3,454,961      $ 2,279,796  
  

 

 

   

 

 

    

 

 

    

 

 

 

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

          

As reported

   $ (109,700   $ 11,941      $ 48,814      $ 34,718  

Pro forma adjustments

     —          15,687        4,772        50,173  
  

 

 

   

 

 

    

 

 

    

 

 

 

Pro forma net income (loss) attributable to Buckeye Partners, L.P.:

   $ (109,700   $ 27,628      $ 53,586      $ 84,891  
  

 

 

   

 

 

    

 

 

    

 

 

 

Pro forma earnings (loss) per unit:

          

Basic

   $ (1.18   $ 0.77      $ 0.59      $ 2.37  
  

 

 

   

 

 

    

 

 

    

 

 

 

Diluted

   $ (1.18   $ 0.77      $ 0.59      $ 2.37  
  

 

 

   

 

 

    

 

 

    

 

 

 

Pro forma weighted average number of units outstanding:

          

Basic

     92,982       35,720        90,670        35,826  
  

 

 

   

 

 

    

 

 

    

 

 

 

Diluted

     92,982       35,720        91,002        35,826  
  

 

 

   

 

 

    

 

 

    

 

 

 

Dispositions

On May 11, 2011, we sold our 20% interest in West Texas LPG Pipeline Limited Partnership (“WT LPG”) to affiliates of Atlas Pipeline Partners L.P. for $85.0 million. WT LPG owns a 2,295-mile common-carrier pipeline system that transports natural gas liquids from points in New Mexico and Texas to Mont Belvieu, Texas for fractionation. Chevron Pipeline Company, which owns the remaining 80% interest, is the operator of WT LPG. The proceeds from the sale were used to fund a portion of our internal growth capital projects in 2011. We recognized a gain of $34.1 million on the sale of our interest in WT LPG.

 

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3. COMMITMENTS AND CONTINGENCIES

Claims and Proceedings

In the ordinary course of business, we are involved in various claims and legal proceedings, some of which are covered by insurance. We are generally unable to predict the timing or outcome of these claims and proceedings. Based upon our evaluation of existing claims and proceedings and the probability of losses relating to such contingencies, we have accrued certain amounts relating to such claims and proceedings, none of which are considered material.

In June 2009, the Pipeline Hazardous Materials Safety Administration (“PHMSA”) proposed penalties totaling approximately $0.6 million as a result of alleged violations of various pipeline safety requirements raised as a result of PHMSA’s 2008 integrated inspection of our procedures and records for operations and maintenance, operator qualification, and integrity management as well as field inspections of locations in Pennsylvania, Ohio, Illinois, Michigan and Colorado. We are contesting portions of the proposed penalty. The timing or outcome of final resolution of this matter cannot reasonably be determined at this time.

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 are contesting the proposed penalty. The timing or outcome of this appeal cannot reasonably be determined at this time.

In January 2011, PHMSA issued a proposed penalty totalling $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 are contesting portions of the proposed penalty. The timing or outcome of final resolution of this matter cannot reasonably be determined at this time.

Environmental Contingencies

We are subject to federal, state and local laws and regulations relating to the protection of the environment. These laws and regulations 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 occur or remediation efforts are probable and can be reasonably estimated based upon past experience, discussions with operating personnel, advice of outside engineering or consulting firms, discussions with general counsel or current facts and circumstances. 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. Recoveries of environmental remediation expenses from other parties are recorded when their receipt is deemed probable.

In accordance with our accounting policy, we recorded operating expenses, net of recoveries, of $4.6 million and $2.2 million during the three months ended September 30, 2011 and 2010, respectively, related to environmental expenditures unrelated to claims and proceedings. For the nine months ended September 30, 2011 and 2010, we recorded operating expenses, net of recoveries, of $9.4 million and $7.6 million, respectively, related to environmental expenditures unrelated to claims and proceedings. At September 30, 2011 and December 31, 2010, approximately $ 17.8 million and $ 10.5 million, respectively, were recorded in accrued and other current liabilities (see Note 10) and $ 38.8 million and $ 20.3 million, respectively, were recorded in other non-current liabilities (see Note 12), respectively.

Ammonia Contract Contingencies

On November 30, 2005, Buckeye Development & Logistics I LLC (“BDL”) (formerly Buckeye Gulf Coast Pipe Lines, L.P.) purchased an ammonia pipeline and other assets from El Paso Merchant Energy-Petroleum Company (“EPME”), a subsidiary of El Paso Corporation (“El Paso”). As part of the transaction, BDL assumed the obligations of EPME under several contracts involving monthly purchases and sales of ammonia. EPME and BDL agreed, however, that EPME would retain the economic risks and benefits associated with those contracts until their

 

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expiration at the end of 2012. To effectuate this agreement, BDL passes through to EPME both the cost of purchasing ammonia under a supply contract and the proceeds from selling ammonia under three sales contracts. For the vast majority of monthly periods since the closing of the pipeline acquisition, the pricing terms of the ammonia contracts have resulted in ammonia supply costs exceeding ammonia sales proceeds. The amount of the shortfall generally increases as the market price of ammonia increases.

EPME has informed BDL that, notwithstanding the parties’ agreement, it will not continue to pay BDL for shortfalls created by the pass-through of ammonia costs in excess of ammonia revenues. EPME encouraged BDL to seek payment by invoking a $40.0 million guaranty made by El Paso, which guaranteed EPME’s obligations to BDL. If EPME fails to reimburse BDL for these shortfalls, then such unreimbursed shortfalls could exceed the $40.0 million cap on El Paso’s guaranty. To the extent the unreimbursed shortfalls significantly exceed the $40.0 million cap, the resulting costs incurred by BDL could adversely affect our financial position, results of operations and cash flows. To date, BDL has continued to receive payment for ammonia costs under the contracts at issue. BDL has not called on El Paso’s guaranty and believes only BDL may invoke the guaranty. EPME, however, contends that El Paso’s guaranty is the source of payment for the shortfalls, but has not clarified the extent to which it believes the guaranty has been exhausted. We, in cooperation with EPME, have terminated one of the ammonia sales contracts. Given the uncertainty of future ammonia prices and EPME’s future actions, we continue to believe we may have risk of loss in connection with the two remaining ammonia sales contracts and an ammonia supply contract and, at this time, are unable to estimate the amount of any such losses we might incur in the future. We are assessing our options in the event that we are unable to mitigate our risk with respect to the remaining contracts through termination of such contracts by other means, including commencing litigation or pursuing other recourse against EPME and El Paso, with respect to this matter.

Leases –Where We are Lessee

We lease certain property, plant and equipment under noncancelable and cancelable operating leases. Lease expense is charged to operating expenses on a straight-line basis over the period of expected benefit. Contingent rental payments are expensed as incurred. Total rental expense for the three months ended September 30, 2011 and 2010 was $7.4 million and $5.7 million, respectively. For the nine months ended September 30, 2011 and 2010, total rental expense was $22.0 million and $16.2 million, respectively. The following table presents minimum lease payment obligations under our operating leases with the amount for 2011 consisting of the remainder of 2011 (October 1 through December 31) and all other years consisting of the total amount for the full year (in thousands):

 

     Office space
and other (1)
     Equipment (2)      Land
Leases (3)
     Total  

2011 (remainder)

   $ 509      $ 877      $ 1,167      $ 2,553  

2012

     2,345        3,487        4,890        10,722  

2013

     2,555        3,608        5,017        11,180  

2014

     2,655        2,093        5,100        9,848  

2015

     2,758        —           5,224        7,982  

Thereafter

     17,200        —           358,590        375,790  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 28,022      $ 10,065      $ 379,988      $ 418,075  
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Includes leases of space in office buildings and related land leases with respect to our Albany terminal.
(2) Includes BORCO facility leases for tugboats and a barge in our International Operations segment.
(3)

Includes leases for inland dock and seabed in connection with our 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 the Natural Gas Storage segment 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. Lease expense associated with the Natural Gas Storage segment leases, which is being recognized on a straight-line basis over 44 years, was approximately $1.8 million for each of the three months ended September 30, 2011 and 2010 and $5.4 million for each of the nine months ended September 30, 2011 and 2010. At September 30, 2011

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

  and December 31, 2010, the balance of our Natural Gas Storage segment deferred lease liability was $16.4 million and $13.3 million, respectively. We estimate that this deferred lease liability will continue to increase through 2032, at which time our deferred lease liability is estimated to be approximately $64.7 million. Our deferred lease liability will then be reduced over the remaining 19 years of the lease, since the expected annual lease payments will exceed the amount of lease expense.

Leases – Where We are Lessor

We have entered into capacity and other leases with remaining terms from 4 to 12 years that are accounted for as operating leases. All of the agreements provide for negotiated extensions. Future minimum lease payments to be received under such operating leasing arrangements as of December 31, 2011 are as follows, with the amount for 2011 consisting of the remainder of 2011 (October 1 through December 31) and all other years consisting of the total amount for the full year (in thousands):

 

     Years Ending
December 31,
 

2011 (remainder)

   $ 22,943  

2012

     80,212  

2013

     43,624  

2014

     11,526  

2015

     11,152  

Thereafter

     50,891  
  

 

 

 

Total

   $ 220,348  
  

 

 

 

4. INVENTORIES

Our inventory amounts were as follows at the dates indicated (in thousands):

 

     September 30,
2011
     December 31,
2010
 

Refined petroleum products (1)

   $ 371,452      $ 340,659  

Materials and supplies

     12,854        10,946  
  

 

 

    

 

 

 

Total inventories

   $ 384,306      $ 351,605  
  

 

 

    

 

 

 

 

(1) Ending inventory was 133.2 million and 134.9 million gallons of refined petroleum products at September 30, 2011 and December 31, 2010, respectively.

At September 30, 2011 and December 31, 2010, approximately 96% and 94% of our refined petroleum products inventory was hedged, respectively. Hedged inventory is valued at current market prices with the change in value of the inventory reflected in our condensed consolidated statements of operations. Inventory not accounted for as a fair value hedge is accounted for at weighted average cost.

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

5. PREPAID AND OTHER CURRENT ASSETS

Prepaid and other current assets consist of the following at the dates indicated (in thousands):

 

     September 30,
2011
     December 31,
2010
 

Prepaid insurance

   $ 10,899      $ 8,865  

Insurance receivables

     8,133        8,886  

Ammonia receivable

     1,797        1,295  

Margin deposits

     4,643        18,833  

Prepaid services

     11,084        24,359  

Unbilled revenue

     9,982        3,263  

Tax receivable

     2,834        120  

Prepaid taxes

     4,103        5,417  

Customer deposits

     4,505        2,657  

Other

     22,888        11,994  
  

 

 

    

 

 

 

Total prepaid and other current assets

   $ 80,868      $ 85,689  
  

 

 

    

 

 

 

6. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consist of the following at the dates indicated (in thousands):

 

     September 30,
2011
    December 31,
2010
 

Land

   $ 226,211     $ 64,905  

Rights-of-way

     108,532       97,529  

Pad gas

     29,346       29,346  

Buildings and leasehold improvements

     122,729       109,585  

Jetties and subsea pipelines

     158,281       —     

Gas storage facility

     196,643       196,077  

Pipeline and terminals

     2,866,776       1,982,049  

Vehicles, equipment and office furnishings

     90,637       72,901  

Construction in progress

     329,693       66,642  
  

 

 

   

 

 

 

Total property, plant and equipment

     4,128,848       2,619,034  

Less: Accumulated depreciation

     (390,670     (313,150
  

 

 

   

 

 

 

Total property, plant and equipment, net

   $ 3,738,178     $ 2,305,884  
  

 

 

   

 

 

 

Depreciation expense was $27.7 million and $13.7 million for the three months ended September 30, 2011 and 2010, respectively. For the nine months ended September 30, 2011 and 2010, depreciation expense was $77.0 million and $40.4 million, respectively.

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

7. EQUITY INVESTMENTS

We own interests in related businesses that are accounted for using the equity method of accounting. The following table presents our equity investments, all included within the Pipelines & Terminals segment, at the dates indicated (in thousands):

 

     Ownership     September 30,
2011
     December 31,
2010
 

Muskegon Pipeline LLC

     40.0   $ 14,490      $ 14,552  

Transport4, LLC

     25.0     446        341  

West Shore Pipe Line Company

     34.6     46,498        43,563  

West Texas LPG Pipeline Limited Partnership (1)

     —          —           48,591  

South Portland Terminal LLC (2)

     50.0     5,966        —     
    

 

 

    

 

 

 

Total equity investments

     $ 67,400      $ 107,047  
    

 

 

    

 

 

 

 

(1) In May 2011, we sold our 20% interest in this investment. See Note 2 for further information.
(2) See Note 2 for a discussion of the acquisition of this interest.

The following table presents earnings from equity investments for the periods indicated (in thousands):

 

     Three Months Ended
September 30,
     Nine Months Ended
September 30,
 
     2011      2010      2011      2010  

Muskegon Pipeline LLC

   $ 454      $ 488      $ 552      $ 1,059  

Transport4, LLC

     43        51        143        120  

West Shore Pipe Line Company

     1,638        1,229        4,524        3,730  

West Texas LPG Pipeline Limited Partnership (1)

     —           1,623        2,297        3,898  

South Portland Terminal LLC (2)

     244        —           244        —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Total earnings from equity investments

   $ 2,379      $ 3,391      $ 7,760      $ 8,807  
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) In May 2011, we sold our 20% interest in WT LPG. Amounts for WT LPG are included through the date of the sale of our interest.
(2) See Note 2 for a discussion of the acquisition of this interest.

Combined income statement data for the periods indicated for our equity investments are summarized below (in thousands):

 

     Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
     2011     2010     2011     2010  

Revenues

   $ 19,485     $ 36,546     $ 80,989     $ 103,845  

Costs and expenses

     (8,140     (19,690     (43,106     (55,934

Non-operating expense

     (2,812     (3,983     (9,632     (11,021
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (1)

   $ 8,533     $ 12,873     $ 28,251     $ 36,890  
  

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) In May 2011, we sold our 20% interest in WT LPG. Amounts for WT LPG are included through the date of the sale of our interest.

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

8. GOODWILL AND INTANGIBLE ASSETS

Goodwill

Goodwill represents the excess of the purchase price of an acquired business over the amounts assigned to assets acquired and liabilities assumed in the transaction. We do not amortize goodwill; rather, we test our goodwill (at the reporting unit level) for impairment on January 1 of each fiscal year, and more frequently if circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. The following table summarizes our goodwill amounts by segment at the dates indicated (in thousands):

 

     September 30,
2011
    December 31,
2010
 

Pipelines & Terminals:

    

Purchase of general partner interests in 2004

   $ 210,066     $ 210,066  

Acquisition of six terminals in June 2000

     11,355       11,355  

Acquisition of Albany Terminal in 2008

     26,829       26,829  
  

 

 

   

 

 

 

Subtotal

     248,250       248,250  
  

 

 

   

 

 

 

International Operations:

    

Acquisition of BORCO in 2011

     498,719       —     
  

 

 

   

 

 

 

Natural Gas Storage:

    

Acquisition of Lodi Gas in 2008

     169,560       169,560  

Impairment charge in 2011

     (169,560     —     
  

 

 

   

 

 

 

Subtotal

     —          169,560  
  

 

 

   

 

 

 

Energy Services:

    

Acquisition of Farm & Home in 2008

     1,132       1,132  
  

 

 

   

 

 

 

Development & Logistics:

    

Purchase of general partner interests in 2004

     13,182       13,182  
  

 

 

   

 

 

 

Total goodwill

   $ 761,283     $ 432,124  
  

 

 

   

 

 

 

During the three months ended September 30, 2011, we concluded the continued downward performance in operating income and Adjusted EBITDA (as defined in Note 20) in the Natural Gas Storage segment due to decreases in contracted storage prices relating to low volatility in natural gas prices and compressed seasonal spreads was an impairment indicator; therefore, we performed an interim 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 necessary. If the carrying amount of a reporting unit exceeds its estimated fair value, the second step measures the amount of impairment by comparing the implied fair value of the reporting unit goodwill with its carrying amount of that goodwill. An entity would assign the fair value of a reporting unit 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 a 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 Natural Gas reporting unit was 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, operating expenses and volumes, (ii) long-term growth rates and (iii) appropriate discount rates. The market multiple valuation method uses appropriate market multiples from comparable companies on the reporting unit’s earnings before interest, tax, depreciation and amortization. Due to the current market conditions, we weighted 100% to the expected present value of future cash flows method.

Our Natural Gas reporting unit failed step one of the goodwill impairment test; therefore, we performed the second step. As a result of our step two analysis, we concluded goodwill in the Natural Gas segment was fully

 

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

impaired and recorded a non-cash goodwill impairment charge of $169.6 million as of September 30, 2011. We considered the goodwill impairment an indicator of impairment related to the long-lived assets associated with the Natural Gas reporting unit. Accordingly, we evaluated these assets for impairment in connection with our step two analysis and concluded that no impairment of the long-lived asset existed.

Intangible Assets

Intangible assets include customer relationships and contracts. These intangible assets have definite lives and are being amortized on a straight-line basis over their estimated useful lives ranging from 5 to 25 years. Our amortizable customer contracts are contracts that were acquired in connection with the acquisition of BDL in March 1999, the acquisition of the Taylor, Michigan terminal in December 2005, the acquisition of certain pipeline and terminal assets in November 2009, the acquisition of the Yabucoa, Puerto Rico terminal in 2010 and the acquisition of pipelines and terminals from BP in June 2011 (see Note 2 for further discussion). The customer contracts are being amortized over their contractual life of approximately 5 years.

The customer relationships resulted from the acquisition of Farm & Home Oil Company LLC (“Farm & Home”) in 2008 and BORCO in 2011. We determined, through an analysis of historical customer attrition rates at Farm & Home, that an appropriate recovery period for customer relationships is approximately 12 years. For BORCO, due to the high customer demand at the facility, the level of customer service being provided, the expansion capabilities of the facility, the potential of customer recontracting rates and the location of the facility in relation to international shipping routes, we anticipate the customer relationships will extend well beyond the existing contract terms with a recovery period of approximately 25 years. Intangible assets consist of the following at the dates indicated (in thousands):

 

     September 30,
2011
    December 31,
2010
 

Customer relationships

   $ 247,663     $ 41,663  

Accumulated amortization

     (17,112     (8,600
  

 

 

   

 

 

 

Net carrying amount

     230,551       33,063  
  

 

 

   

 

 

 

Customer contracts

     25,320       16,380  

Accumulated amortization

     (6,489     (5,376
  

 

 

   

 

 

 

Net carrying amount

     18,831       11,004  
  

 

 

   

 

 

 

Total intangible assets, net

   $ 249,382     $ 44,067  
  

 

 

   

 

 

 

For the three months ended September 30, 2011 and 2010, amortization expense related to intangible assets was $3.3 million and $1.1 million, respectively. For the nine months ended September 30, 2011 and 2010, amortization expense related to intangible assets was $9.6 million and $3.3 million, respectively. Amortization expense related to intangible assets is expected to be approximately $3.3 million for the remainder of 2011 (October 1 through December 31), $13.4 million for 2012, $13.4 million for 2013, $13.2 million for 2014 and $12.2 million for 2015.

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

9. OTHER NON-CURRENT ASSETS

Other non-current assets consist of the following at the dates indicated (in thousands):

 

 

     September 30,
2011
     December 31,
2010
 

Prepaid services

   $ 1,468      $ 5,836  

Unbilled revenue

     —           2,163  

Derivative assets

     37        3,892  

Debt issuance costs

     15,072        11,184  

Insurance receivables

     7,518        8,826  

Indemnification asset (see Note 2)

     17,720        17,720  

Other

     9,021        8,842  
  

 

 

    

 

 

 

Total other non-current assets

   $ 50,836      $ 58,463  
  

 

 

    

 

 

 

10. ACCRUED AND OTHER CURRENT LIABILITIES

Accrued and other current liabilities consist of the following at the dates indicated (in thousands):

 

     September 30,
2011
     December 31,
2010
 

Taxes - other than income

   $ 19,141      $ 20,698  

Accrued employee benefit liability

     3,817        3,817  

Environmental liabilities

     17,787        10,471  

Interest payable

     23,675        30,700  

Payable for ammonia purchase

     2,865        2,354  

Unearned revenue

     12,101        18,776  

Compensation and vacation

     14,779        13,134  

Accrued capital expenditures

     22,116        2,032  

Deferred consideration

     1,000        2,010  

Customer deposits

     8,633        5,389  

Unfavorable storage contracts (1)

     10,994        —     

Other

     46,141        35,499  
  

 

 

    

 

 

 

Total accrued and other current liabilities

   $ 183,049      $ 144,880  
  

 

 

    

 

 

 

 

(1) See Note 12 for a discussion of the unfavorable storage contracts acquired in connection with the BORCO acquisition.

 

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

11. LONG-TERM DEBT

Long-term debt consists of the following at the dates indicated (in thousands):

 

     September 30,
2011
    December 31,
2010
 

4.625% Notes due July 15, 2013 (1)

   $ 300,000     $ 300,000  

5.300% Notes due October 15, 2014 (1)

     275,000       275,000  

5.125% Notes due July 1, 2017 (1)

     125,000       125,000  

6.050% Notes due January 15, 2018 (1)

     300,000       300,000  

5.500% Notes due August 15, 2019 (1)

     275,000       275,000  

4.875% Notes due February 1, 2021 (1)

     650,000       —     

6.750% Notes due August 15, 2033 (1)

     150,000       150,000  

BPL Credit Facilities (2)

     592,500        98,000  

BES Credit Facility

     —          284,300  

Services Company 3.60% ESOP Notes due March 28, 2011

     —          1,531  

Retirement premium

     —          (6
  

 

 

   

 

 

 

Total debt

     2,667,500       1,808,825  

Other, including unamortized discounts and fair value hedges

     (5,594     (3,607
  

 

 

   

 

 

 

Subtotal debt

     2,661,906       1,805,218  

Less: Current portion of long-term debt and line of credit

     (346,800     (285,825
  

 

 

   

 

 

 

Total long-term debt

   $ 2,315,106     $ 1,519,393  
  

 

 

   

 

 

 

 

(1) We make semi-annual interest payments on these notes based on the rates noted above with the principal balances outstanding to be paid on or before the due dates as shown above.
(2) Includes the Credit Facility and Prior BPL Credit Facility as defined below.

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

The fair values of our aggregate debt and credit facilities were estimated to be $2,789.0 million and $1,897.5 million at September 30, 2011 and December 31, 2010, respectively. The fair values of the fixed-rate debt were estimated by observing market trading prices and by comparing the historic market prices of our publicly-issued debt with the market prices of other MLPs’ publicly-issued debt with similar credit ratings and terms. The fair values of the variable-rate debt are their carrying amounts, as the carrying amount reasonably approximates fair value due to the variability of the interest rates.

Notes Offering

On January 13, 2011, we sold the 4.875% Notes in an underwritten public offering. The notes were issued at 99.62% of their principal amount. Total proceeds from this offering, after underwriters’ fees, expenses and debt issuance costs of $4.9 million, were approximately $642.6 million, and were used to fund a portion of the purchase price for our acquisition of BORCO (see Note 2). In connection with this offering, we settled a treasury lock agreement, which resulted in the receipt of a settlement of $0.5 million, which is being amortized as a reduction to interest expense over the ten-year term of the 4.875% Notes (see Note 14).

Bridge Loans

In December 2010, in connection with the proposed BORCO acquisition, we obtained a commitment from commercial banks for senior unsecured bridge loans in an aggregate amount up to $595 million (or up to $775 million in the event we purchased both First Reserve’s 80% interest and Vopak’s 20% interest in FRBCH) (the “Bridge Loans”). The commitment was to expire upon the earliest to occur of the termination date as defined in the BORCO sale and purchase agreement, the consummation of the BORCO acquisition, the termination of the BORCO sale and purchase agreement or 120 days after December 18, 2010. We paid $2.0 million of fees in December 2010 associated with these Bridge Loans. In January 2011, we terminated the Bridge Loans upon issuance of the 4.875% Notes.

Services Company ESOP Notes

At December 31, 2010, Services Company had total debt outstanding of $1.5 million consisting of 3.60% Senior Secured Notes due March 28, 2011 payable by the ESOP to a third-party lender, which were repaid on March 28, 2011.

Credit Facility

On September 26, 2011, Buckeye and its indirect wholly-owned subsidiary, Buckeye Energy Services LLC (“BES”), as borrowers, entered into a Revolving Credit Agreement (the “Credit Facility”) with SunTrust Bank, as administrative agent and other lenders to provide for a $1.25 billion senior unsecured revolving credit agreement of which we have a borrowing capacity of $1.25 billion and BES has a sublimit of $500.0 million. The Credit Facility’s maturity date is September 26, 2016, with an option to extend the term for two successive one-year periods and a $500.0 million accordion option to increase the commitments. Concurrently with the execution of the Credit Facility, Buckeye and BES borrowed $243.7 million and $318.8 million, respectively, and used the proceeds to repay all amounts outstanding under Buckeye’s senior unsecured revolving credit agreement dated November 13, 2006 (“Prior BPL Credit Facility”) and BES’s amended and restated senior revolving credit agreement dates as of June 25, 2010 (“BES Credit Facility”), respectively, and customary fees and expenses related to the Credit Facility. Buckeye and BES incurred debt issuance costs of approximately $3.6 million and $1.4 million, respectively, related to the Credit Facility. These costs were included in other non-current assets and are being amortized over the Credit Facility terms of five years. As a result of the termination of the Prior BPL Credit Facility and BES Credit Facility, we expensed $0.3 million and $3.0 million, respectively, of unamortized deferred financing costs associated with the credit facilities, which is reflected in interest and debt expense in our condensed consolidated statement of operations.

Under the Credit Facility, interest accrues on advances at a LIBOR rate or a base rate plus an applicable margin based on the election of the applicable borrower for each interest period. The issuing fees for all letters of credit are

 

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

also based on an applicable margin. The applicable margin used in connection with interest rates and fees is based on the credit ratings assigned to our senior unsecured long-term debt securities. The applicable margin for LIBOR rate loans, swing line loans, and letter of credit fees ranges from 1.0% to 1.75% and the applicable margin for base rate loans ranges from 0% to 0.75%. The borrowers will also pay a fee based on our credit ratings on the actual daily unused amount of the aggregate commitments. At September 30, 2011 and December 31, 2010, Buckeye had $592.5 million and $98.0 million, respectively, and BES had $0 million and $284.3 million, respectively, outstanding under their respective credit agreements. The BES outstanding balances were classified as current liabilities in our condensed consolidated balance sheets as related funds were used to finance current working capital needs. The weighted average interest rate for borrowings under the Credit Facility was 2.71% at September 30, 2011.

The Credit Facility includes covenants limiting, as of the last day of each fiscal quarter, the ratio of consolidated funded debt (“Funded Debt Ratio”) to consolidated EBITDA, as defined in the Credit Facility, measured for the preceding twelve months, to not more than 5.00 to 1.00. This requirement is subject to a provision for increases to 5.50 to 1.00 in connection with certain future acquisitions. The Funded Debt Ratio is calculated by dividing consolidated debt by annualized EBITDA, which is defined in the Credit Facility as earnings before interest, taxes, depreciation, depletion and amortization determined on a consolidated basis in accordance with generally accepted accounting principles. At September 30, 2011, our Funded Debt Ratio was approximately 4.3 to 1.00. At September 30, 2011, we were not aware of any instances of noncompliance with the covenants under our Credit Facility.

At September 30, 2011 and December 31, 2010, we had committed $1.8 million and $1.4 million, respectively, in support of letters of credit. The obligations for letters of credit are not reflected as debt in our condensed consolidated balance sheets.

12. OTHER NON-CURRENT LIABILITIES

Other non-current liabilities consist of the following at the dates indicated (in thousands):

 

     September 30,
2011
     December 31,
2010
 

Accrued employee benefit liabilities (see Note 15)

   $ 49,930      $ 49,170  

Accrued environmental liabilities

     38,817        20,346  

Deferred consideration

     17,514        16,415  

Deferred rent

     16,484        13,393  

Uncertain tax position liability (see Note 2)

     17,720        17,720  

Unfavorable storage contracts (1)

     41,893        —     

Other

     6,851        10,999  
  

 

 

    

 

 

 

Total other non-current liabilities

   $ 189,209      $ 128,043  
  

 

 

    

 

 

 

 

(1) In determining fair value of assets and liabilities acquired in the BORCO acquisition (see Note 2), we allocated negative fair values to certain unfavorable storage contracts at the date of acquisition and recorded them as current and long-term liabilities in the condensed consolidated balance sheet. The unfavorable storage contracts are being recognized to revenue based on the estimated realization of the fair value established on the acquisition date over the contractual life. At September 30, 2011, amount is net of $4.8 million of recognized revenue. Revenue to be recognized related to these unfavorable storage contracts is expected to be approximately $2.7 million for the remainder of 2011 (October 1 through December 31), $11.0 million for 2012 and 2013, $11.1 million for 2014 and 2015 and $6.0 million for 2016. See Note 10 for the current portion of unfavorable storage contracts.

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

13. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The following table presents the components of accumulated other comprehensive income (loss) (“AOCI”) in our condensed consolidated balance sheets at the dates indicated (in thousands):

 

     September 30,
2011
    December 31,
2010
 

Adjustments to funded status of retirement income guarantee plan and retiree medical plan

   $ (10,323   $ (10,323

Amortization of interest rate swap

     (6,065     (6,789

Derivative instruments

     (89,515     3,144  

Gain on settlement of treasury lock, net of amortization

     464       —     

Accumulated amortization of retirement income guarantee plan and retiree medical plan

     (7,685     (7,291
  

 

 

   

 

 

 

Total accumulated other comprehensive loss

   $ (113,124   $ (21,259
  

 

 

   

 

 

 

14. DERIVATIVE INSTRUMENTS, HEDGING ACTIVITIES AND FAIR VALUE MEASUREMENTS

We are exposed to certain risks, including changes in interest rates and commodity prices, in the course of our normal business operations. We use derivative instruments to manage risks associated with certain identifiable and anticipated transactions. Derivatives are financial instruments whose fair value is determined by changes in a specified benchmark such as interest rates or commodity prices. Typical derivative instruments include futures, forward contracts, swaps and other instruments with similar characteristics.

We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategies for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives used in a transaction are highly effective in offsetting changes in cash flows or the fair value of hedged items. A discussion of our derivative activities by risk category follows.

Interest Rate Derivatives

We utilize forward-starting interest rate swaps to manage interest rate risk related to forecasted interest payments on anticipated debt issuances. This strategy is a component in controlling our cost of capital associated with such borrowings. When entering into interest rate swap transactions, we become exposed to both credit risk and market risk. We are subject to credit risk when the value of the swap transaction is positive and the risk exists that the counterparty will fail to perform under the terms of the contract. We are subject to market risk with respect to changes in the underlying benchmark interest rate that impacts the fair value of the swaps. We manage our credit risk by only entering into swap transactions with major financial institutions with investment-grade credit ratings. We manage our market risk by associating each swap transaction with an existing 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.

We expect to issue new fixed-rate debt (i) on or before July 15, 2013 to repay the $300.0 million of 4.625% Notes that are due on July 15, 2013 and (ii) on or before October 15, 2014 to repay the $275.0 million of 5.300% Notes that are due on October 15, 2014, although no assurances can be given that the issuance of fixed-rate debt will

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

be possible on acceptable terms. We have entered into six forward-starting interest rate swaps with a total aggregate notional amount of $300.0 million related to the anticipated issuance of debt on or before July 15, 2013 and six forward-starting interest rate swaps with a total aggregate notional amount of $275.0 million related to the anticipated issuance of debt on or before October 15, 2014. The purpose of these swaps is to hedge the variability of the forecasted interest payments on these expected debt issuances that may result from changes in the benchmark interest rate until the expected debt is issued. We designated the swap agreements as cash flow hedges at inception and expect the changes in values to be highly correlated with the changes in value of the underlying borrowings.

On January 13, 2011, we issued the 4.875% Notes in an underwritten public offering. In December 2010, in connection with the proposed offering, we entered into a treasury lock agreement to fix the 10-year treasury rate at 3.3375% per annum on a notional amount of $650.0 million. In January 2011, we subsequently cash-settled the treasury lock agreement upon the issuance of the 4.875% Notes and received approximately $0.5 million, which is being recognized as a reduction to interest expense over the term of the 4.875% Notes.

During the three months ended September 30, 2011 and 2010, unrealized losses of $83.6 million and $22.0 million, respectively, were recorded in accumulated other comprehensive income (loss) to reflect the change in the fair values of the forward-starting interest rate swaps. During the nine months ended September 30, 2011 and 2010, unrealized losses of $92.4 million and $58.1 million, respectively, were recorded in accumulated other comprehensive income (loss).

Over the next twelve months, we expect to reclassify $0.9 million of net losses, consisting of loss attributable to forward-starting interest rate swaps terminated in 2008 associated with our 6.050% Notes, partially offset by a gain attributable to the settlement of the treasury lock agreement associated with the 4.875% Notes in January 2011, from accumulated other comprehensive loss to earnings as an increase to interest and debt expense.

Commodity Derivatives

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 commodity forward fixed-price purchase and sales contracts. The derivative contracts used to hedge refined petroleum product inventories are designated as fair value hedges. Accordingly, our method of measuring ineffectiveness compares the change in the fair value of New York Mercantile Exchange (“NYMEX”) futures contracts to the change in fair value of our hedged fuel inventory. The time value component is excluded from our hedge assessment and reported directly in earnings. Hedge accounting is discontinued when the hedged fuel inventory is sold or when the related derivative contracts expire. In addition, we periodically enter into offsetting exchange-traded futures contracts to economically close-out an existing futures contract based on a near-term expectation to sell a portion of our fuel inventory. These offsetting derivative contracts are not designated as hedging instruments and any resulting gains or losses are recognized in earnings during the period. The fair values of futures contracts for inventory designated as hedging instruments in the following tables have been presented net of these offsetting futures contracts.

Our Energy Services segment has not used hedge accounting with respect to its fixed-price contracts. Therefore, our fixed-price contracts and the related futures contracts used to offset the changes in fair value of the fixed-price sales contracts are all marked-to-market in our condensed consolidated balance sheets with gains and losses being recognized in earnings during the period.

In order to hedge the cost of natural gas used to operate our turbine engines at our Linden, New Jersey location, our Pipelines & Terminals segment bought natural gas futures contracts in March 2009 with terms that coincide with the terms of a natural gas supply contract that expired in August 2011. The natural gas futures contracts were designated as cash flow hedges at inception and the change in fair value was recorded in other comprehensive income (“OCI”). As the forecasted event occurred and was recognized in earnings, the change in fair value was reclassed from OCI to earnings. As of September 30, 2011, there were no designated cash flow hedges of our natural gas supply contracts and the amount that had been recorded in OCI was reclassed to earnings.

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

The following table summarizes our commodity derivative instruments outstanding at September 30, 2011 (amounts in thousands of gallons, except as noted):

 

     Volume (1)      Accounting
Treatment
 

Derivative Purpose

   Current      Long-Term (2)     

Derivatives NOT designated as hedging instruments:

        

Physical derivative contracts for refined products

     9,262        126        Mark-to-market   

Futures contracts for refined products

     12,726        —           Mark-to-market   

Derivatives designated as hedging instruments:

        

Futures contracts for refined products

     127,974        —           Fair Value Hedge   

 

(1) Volume represents absolute value of net notional volume position.
(2) The maximum term for derivatives included in the long-term column is December 2012.

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

The following table sets forth the fair value of each classification of derivative instruments at the dates indicated (in thousands):

 

     September 30, 2011  
     Derivatives
NOT Designated
as Hedging
Instruments
    Derivatives
Designated

as Hedging
Instruments
    Derivative
Carrying
Value
    Netting
Balance
Sheet
Adjustment
    Total  

Physical derivative contracts for refined products

   $ 7,446     $ —        $ 7,446     $ (281   $ 7,165  

Futures contracts for refined products

     44,226       23,775       68,001       (47,836     20,165  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total current derivative assets

     51,672       23,775       75,447       (48,117     27,330  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Physical derivative contracts

     37       —          37       —          37  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total non-current derivative assets

     37       —          37       —          37  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Physical derivative contracts for refined products

     (1,937     —          (1,937     281       (1,656

Futures contracts for refined products

     (46,406     (1,430     (47,836     47,836       —     
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total current derivative liabilities

     (48,343     (1,430     (49,773     48,117       (1,656
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Interest rate derivatives

     —          (89,515     (89,515     —          (89,515
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total non-current derivative liabilities

     —          (89,515     (89,515     —          (89,515
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net derivative assets/(liabilities)

   $ 3,366     $ (67,170   $ (63,804   $ —        $ (63,804
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

     December 31, 2010  
     Derivatives
NOT Designated
as Hedging
Instruments
    Derivatives
Designated
as Hedging
Instruments
    Derivative
Carrying
Value
    Netting
Balance
Sheet
Adjustment
    Total  

Physical derivative contracts for refined products

   $ 1,552     $ —        $ 1,552     $ (30   $ 1,522  

Futures contracts for refined products

     36,916       —          36,916       (36,804     112  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total current derivative assets

     38,468       —          38,468       (36,834     1,634  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Interest rate derivatives

     —          5,351       5,351       (1,459     3,892  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total non-current derivative assets

     —          5,351       5,351       (1,459     3,892  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Physical derivative contracts for refined products

     (3,930     —          (3,930     30       (3,900

Futures contracts for refined products

     (21,368     (28,071     (49,439     36,804       (12,635

Futures contracts for natural gas

     —          (206     (206     —          (206

Interest rate derivatives

     —          (2,003     (2,003     1,459       (544
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total current derivative liabilities

     (25,298     (30,280     (55,578     38,293       (17,285
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net derivative assets/(liabilities)

   $ 13,170     $ (24,929   $ (11,759   $ —        $ (11,759
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

Our hedged inventory portfolio extends to the fourth quarter of 2011. The majority of the unrealized net gain of $22.3 million at September 30, 2011 for futures contracts designated as inventory hedging instruments and unrealized gains in the fair values of the underlying hedged refined petroleum product inventories will be realized by the fourth quarter of 2011 as the inventory is sold. At September 30, 2011, open refined petroleum product derivative contracts (represented by the fixed-price contracts and futures contracts for fixed-price sales contracts noted above) varied in duration, but did not extend beyond December 2012. In addition, at September 30, 2011, we had refined petroleum product inventories that we intend to use to satisfy a portion of the physical derivative contracts.

The following table sets forth the location of derivative instruments in our condensed consolidated balance sheets at the dates indicated (in thousands):

 

     September 30,
2011
    December 31,
2010
 

Derivative assets

   $ 27,330     $ 1,634  

Other non-current assets

     37       3,892  

Derivative liabilities

     (1,656     (17,285

Other non-current liabilities

     (89,515     —     
  

 

 

   

 

 

 

Total

   $ (63,804   $ (11,759
  

 

 

   

 

 

 

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

The gains and losses on our derivative instruments recognized in income were as follows for the periods indicated (in thousands):

 

          Gain (Loss) Recognized in Income on Derivatives  
          Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
     

Location

   2011     2010     2011     2010  

Derivatives NOT designated as hedging instruments:

        

Physical derivative contracts for refined products

  

Product sales

   $ 7,507     $ (1,974   $ 5,920     $ 6,704  

Physical derivative contracts for refined products

  

Cost of product sales and natural gas storage services

     4,277       —          6,044       —     

Futures contracts for refined products

  

Cost of product sales and natural gas storage services

     (1,016     3,428       165       228  

Derivatives designated as fair value hedging instruments:

        

Futures contracts for refined products

  

Cost of product sales and natural gas storage services

     30,240       (15,159     (18,591     (1,946

Physical Inventory - Hedge items

  

Cost of product sales and natural gas storage services

     (27,768     20,300       12,515       (3,495

Ineffectiveness excluding the time value component on fair value hedging instruments:

        

Fair value hedge ineffectiveness (excluding time value)

  

Cost of product sales and natural gas storage services

   $ 3,825     $ (1,469   $ 3,621     $ 9,111  

Time value excluded from hedge assessment

  

Cost of product sales and natural gas storage services

     (1,353     6,609       (9,697     (14,553
     

 

 

   

 

 

   

 

 

   

 

 

 

Net impact on income

      $ 2,472     $ 5,140     $ (6,076   $ (5,442
     

 

 

   

 

 

   

 

 

   

 

 

 

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

The gains and losses reclassified from AOCI to income and the change in value recognized in OCI on our derivatives were as follows for the periods indicated (in thousands):

 

          Gain (Loss) Reclassified from AOCI to Income  
          Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
     

Location

   2011     2010     2011     2010  

Derivatives designated as cash flow hedging instruments:

  

     

Futures contracts for natural gas

  

Cost of product sales and natural gas storage services

   $ (32   $ (122   $ (251   $ (291

Futures contracts for refined petroleum products

  

Cost of product sales and natural gas storage services

     —          —          —          —     

Interest rate contracts

  

Interest and debt expense

     (229     (241     (691     (723
          Change in Value Recognized in OCI on Derivatives  
          Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
          2011     2010     2011     2010  

Derivatives designated as cash flow hedging instruments:

  

   

Futures contracts for natural gas

      $ —        $ (337   $ (46   $ (949

Interest rate contracts

        (83,596     (21,957     (92,366     (58,114

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 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 (such as the income or market approach) 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 hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). At each balance sheet reporting date, we categorize our financial assets and liabilities using this hierarchy. The characteristics of fair value amounts classified within each level of the hierarchy are described as follows:

 

   

Level 1 inputs are based on quoted prices, which are available in active markets for identical assets or liabilities as of the reporting date. Active markets are defined as those in which transactions for identical assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

 

   

Level 2 inputs are based on pricing inputs other than quoted prices in active markets and are either directly or indirectly observable as of the measurement date. Level 2 fair values include instruments that are valued using financial models or other appropriate valuation methodologies and include the following:

 

   

Quoted prices in active markets for similar assets or liabilities.

 

   

Quoted prices in markets that are not active for identical or similar assets or liabilities.

 

   

Inputs other than quoted prices that are observable for the asset or liability.

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

   

Inputs that are derived primarily from or corroborated by observable market data by correlation or other means.

 

   

Level 3 inputs are based on unobservable inputs for the asset or liability. Unobservable inputs are used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. Unobservable inputs reflect the reporting entity’s own ideas about the assumptions that market participants would use in pricing an asset or liability (including assumptions about risk). Unobservable inputs are based on the best information available in the circumstances, which might include the reporting entity’s internally developed data. The reporting entity must not ignore information about market participant assumptions that is reasonably available without undue cost and effort. Level 3 inputs are typically used in connection with internally developed valuation methodologies where management makes its best estimate of an instrument’s fair value.

Recurring

The following table sets forth financial assets and liabilities, measured at fair value on a recurring basis, as of the measurement dates, September 30, 2011 and December 31, 2010, and the basis for that measurement, by level within the fair value hierarchy (in thousands):

 

     September 30, 2011     December 31, 2010  
     Quoted Prices
in Active
Markets
     Significant
Other
Observable
Inputs
    Quoted Prices
in Active
Markets
    Significant
Other
Observable
Inputs
 
     (Level 1)      (Level 2)     (Level 1)     (Level 2)  

Financial assets:

         

Physical derivative contracts for refined products

   $ —         $ 7,202     $ —        $ 1,522  

Futures contracts for refined products

     20,165        —          112       —     

Interest rate derivatives

     —           —          —          3,892  

Financial liabilities:

         

Physical derivative contracts for refined products

     —           (1,656     —          (3,900

Futures contracts for refined products

     —           —          (12,635     —     

Futures contracts for natural gas

     —           —          (206     —     

Interest rate derivatives

     —           (89,515     —          (544
  

 

 

    

 

 

   

 

 

   

 

 

 

Fair value

   $ 20,165      $ (83,969   $ (12,729   $ 970  
  

 

 

    

 

 

   

 

 

   

 

 

 

The values of the Level 1 derivative assets and liabilities were based on quoted market prices obtained from the NYMEX.

The values of the Level 2 interest rate derivatives were determined using expected cash flow models, which incorporated market inputs including the implied forward LIBOR yield curve for the same period as the future interest swap settlements.

The values of the Level 2 fixed-price contracts assets and liabilities were calculated using market approaches based on observable market data inputs, including published commodity pricing data, which is verified against other

 

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available market data, and market interest rate and volatility data. Level 2 fixed-price contracts assets are net of credit value adjustments (“CVA”) determined using an expected cash flow model, which incorporates assumptions about the credit risk of the fixed-price contracts based on the historical and expected payment history of each customer, the amount of product contracted for under the agreement and the customer’s historical and expected purchase performance under each contract. The Energy Services segment determined CVA is appropriate because few of the Energy Services segment’s customers entering into these fixed-price contracts are large organizations with nationally-recognized credit ratings. The Level 2 fixed-price contracts assets of $7.2 million and $1.5 million as of September 30, 2011 and December 31, 2010, respectively, are net of CVA of ($0.1) million for both periods, respectively. As of September 30, 2011, the Energy Services segment did not hold any net liability derivative position containing credit contingent features.

Non-Recurring

Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments in certain circumstances, such as when there is evidence of possible impairment. During the three and nine months ended September 30, 2011, we recorded a non-cash goodwill impairment charge based on Level 3 inputs. See Note 8 for a discussion of our valuation methodology relating to the goodwill impairment test. For the three and nine months ended September 30, 2011, there were not any fair value adjustments reflected in our condensed consolidated financial statements.

15. PENSIONS AND OTHER POSTRETIREMENT BENEFITS

Services Company, which employs the majority of our workforce, sponsors a retirement income guarantee plan (“RIGP”), which is a defined benefit plan that generally guarantees employees hired before January 1, 1986 a retirement benefit based on years of service and the employee’s highest compensation for any consecutive 5-year period during the last 10 years of service or other compensation measures as defined under the respective plan provisions. The retirement benefit is subject to reduction at varying percentages for certain offsetting amounts, including benefits payable under a retirement and savings plan discussed further below. Services Company funds the plan through contributions to pension trust assets, generally subject to minimum funding requirements as provided by applicable law.

Services Company also sponsors an unfunded post-retirement benefit plan (the “Retiree Medical Plan”), which provides health care and life insurance benefits to certain of its retirees. To be eligible for these benefits, an employee must have been hired prior to January 1, 1991 and meet certain service requirements.

The components of the net periodic benefit cost for the RIGP and Retiree Medical Plan were as follows for the three months ended September 30, 2011 and 2010 (in thousands):

 

     RIGP     Retiree Medical Plan  
     Three Months Ended
September 30,
    Three Months Ended
September 30,
 
     2011     2010     2011     2010  

Service cost

   $ 86     $ 66     $ 66     $ 74  

Interest cost

     199       226       508       495  

Expected return on plan assets

     (59     (86     —          —     

Amortization of prior service benefit

     —          (11     (740     (741

Amortization of unrecognized losses

     260       241       327       223  

Settlement charge

     406       —          —          —     
  

 

 

   

 

 

   

 

 

   

 

 

 

Net periodic benefit costs

   $ 892     $ 436     $ 161     $ 51  
  

 

 

   

 

 

   

 

 

   

 

 

 

 

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

The components of the net periodic benefit cost for the RIGP and Retiree Medical Plan were as follows for the nine months ended September 30, 2011 and 2010 (in thousands):

 

     RIGP     Retiree Medical Plan  
     Nine Months Ended
September 30,
    Nine Months Ended
September 30,
 
     2011     2010     2011     2010  

Service cost

   $ 222     $ 199     $ 227     $ 221  

Interest cost

     598       685       1,446       1,486  

Expected return on plan assets

     (247     (260     —          —     

Amortization of prior service benefit

     —          (34     (2,222     (2,223

Amortization of unrecognized losses

     896       731       933       670  

Settlement charge

     609       —          —          —     
  

 

 

   

 

 

   

 

 

   

 

 

 

Net periodic benefit costs

   $ 2,078     $ 1,321     $ 384     $ 154  
  

 

 

   

 

 

   

 

 

   

 

 

 

During the nine months ended September 30, 2011, we contributed $2.4 million to the RIGP.

16. UNIT-BASED COMPENSATION PLANS

BGH GP Holdings LLC (“BGH GP”) has an equity compensation plan (“BGH GP Equity Compensation Plan”) for certain members of our senior management. Compensation expense recorded with respect to the BGH GP Equity Compensation Plan was $0 and $0.3 million for the three months ended September 30, 2011 and 2010, respectively. For the nine months ended September 30, 2011 and 2010, compensation expense recorded with respect to the BGH GP Equity Compensation Plan was $0 and $0.9 million, respectively.

We award unit-based compensation to employees and directors primarily under the Buckeye Partners, L.P. 2009 Long-Term Incentive Plan (the “LTIP”). We formerly awarded options to acquire LP Units to employees pursuant to the Buckeye Partners, L.P. Unit Option and Distribution Equivalent Plan (the “Option Plan”). We recognized compensation expense related to the LTIP and the Option Plan of $1.7 million and $1.3 million for the three months ended September 30, 2011 and 2010, respectively. For the nine months ended September 30, 2011 and 2010, we recognized compensation expense related to the LTIP and the Option Plan of $6.6 million and $3.8 million, respectively. These compensation plans are discussed below.

BGH GP’s Override Units

Effective on June 25, 2007, BGH GP instituted the BGH GP Equity Compensation Plan. The BGH GP Equity Compensation Plan included both time-based and performance-based participation in the equity of BGH GP (but not ours) referred to as override units. These override units consisted of three equal tranches of units consisting of Value A, Value B and Operating Units. We are required to record, as compensation expense and a corresponding contribution to unitholders’ equity, the fair value of the compensation. We are not the sponsor of this plan and have no obligations with respect to it. Compensation expense related to this plan was $0 and $0.3 million for the three months ended September 30, 2011 and 2010, respectively. For the nine months ended September 30, 2011 and 2010, compensation expense related to this plan was $0 and $0.9 million, respectively.

On December 31, 2010, the override unit plan was modified. All outstanding Value A and Operating Units were exchanged for LP Units owned by BGH GP. The terms of the Value B Units remained unchanged. The Value B Units will participate in distributions by BGH GP based on the occurrence of an exit event and an investment return of 3.5 times the original investment and an internal rate of return of at least 10% or on a pro-rata basis on an investment return ranging from 2.0 to 3.5 times the original investment and an internal rate of return of at least 10%.

On January 27, 2011, BGH GP established and granted new override units in BGH GP to a member of senior management, which consisted of Value N-1 and Value N-2 Units. The Value N-1 Units will participate in distributions by BGH GP based on the occurrence of an exit event and an investment return of 2.0 times the original investment up to aggregate distributions of $3.0 million. The Value N-2 Units will participate in distributions by

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

BGH GP based on the occurrence of an exit event and an investment return of 2.5 times the original investment or on a pro-rata basis on an investment return ranging from 2.0 to 2.5 times the original investment up to aggregate distributions of $5.0 million.

The exit event with respect to the Value B, Value N-1 and Value N-2 Units is generally defined as the sale by ArcLight Capital Partners (“ArcLight”), Kelso & Company (“Kelso”) and their affiliates of their interests in BGH GP, the sale of substantially all the assets of BGH GP and its subsidiaries, or any other “extraordinary” transaction that the Board of Directors of BGH GP determines is an exit event.

The investment return is calculated generally as the sum of all the distributions that ArcLight and Kelso have received from BGH GP prior to and through the exit event, divided by the total amount of capital contributions to BGH GP that ArcLight and Kelso have made prior to the exit event.

The cumulative grant date fair values of the Value B, Value N-1 and Value N-2 Units that remained unvested as of September 30, 2011 are $2.2 million, $0.9 million and $1.1 million, respectively. The vesting of the override units is contingent on a performance condition, namely the completion of the exit event, and a market condition, primarily relating to the receipt of an investment return at a specified multiple and internal rate of return, where applicable. Accordingly, no compensation expense for these override units will be recorded until, and if, an exit event and other requirements occur.

At grant date, the override units were valued using the Monte Carlo simulation method that incorporated the market-based vesting condition into the grant date fair value of the unit awards. The following assumptions were used for grants of the Value N-1 and N-2 Units during the period:

 

     Three Months Ended
March 31, 2011
 

Equity value in BGH GP (in millions)

   $ 410.7  

Expected life in years

     1  

Risk-free interest rate

     0.25

Volatility

     25

LTIP

The LTIP provides for the issuance of up to 1,500,000 LP Units, subject to certain adjustments. After giving effect to the issuance or forfeiture of phantom unit and performance unit awards through September 30, 2011, awards representing a total of 876,914 additional LP Units could be issued under the LTIP.

Under the terms of the Buckeye Partners, L.P. Unit Deferral and Incentive Plan (“Deferral Plan”), eligible employees were allowed to defer up to 50% of their 2011 and 2010 compensation award under our Annual Incentive Compensation Plan or other discretionary bonus program in exchange for grants of phantom units equal in value to the amount of their cash award deferral (each such unit, a “Deferral Unit”). Participants also receive one matching phantom unit for each Deferral Unit. Approximately $1.6 million of 2010 compensation awards had been deferred at December 31, 2010, for which 50,660 phantom units (including matching units) were granted during the nine months ended September 30, 2011. These grants are included as granted in the LTIP activity table below.

Awards under the LTIP

During the nine months ended September 30, 2011, the Compensation Committee granted 111,216 phantom units to employees (including the 50,660 phantom units granted pursuant to the Deferral Plan discussed above), 14,000 phantom units to independent directors of Buckeye GP and 122,843 performance units to employees. The amount paid with respect to phantom unit distribution equivalents under the LTIP was $0.8 million and $0.4 million for the nine months ended September 30, 2011 and 2010, respectively.

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

The following table sets forth the LTIP activity for the periods indicated (dollars in thousands):

 

     Number of
LP Units
    Weighted
Average
Grant Date
Fair Value
per LP Unit (1)
     Total Value  

Unvested at January 1, 2011

     364,913     $ 51.11      $ 18,650  

Granted

     248,059       64.89        16,096  

Vested

     (15,246     55.35        (844

Forfeited

     (9,047     55.91        (506
  

 

 

      

 

 

 

Unvested at September 30, 2011

     588,679     $ 56.74      $ 33,396  
  

 

 

      

 

 

 

 

(1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. The weighted-average grant date fair value per LP Unit for forfeited and vested awards is determined before an allowance for forfeitures.

At September 30, 2011, approximately $16.4 million of compensation expense related to the LTIP is expected to be recognized over a weighted average period of approximately 1.5 years.

Unit Option and Distribution Equivalent Plan

The following is a summary of the changes in the LP Unit options outstanding (all of which are vested or are expected to vest) under the Option Plan for the periods indicated (dollars in thousands):

 

     Number of
LP Units
    Weighted-
Average
Strike Price
($/LP Unit)
     Weighted-
Average
Remaining
Contractual
Term (in years)
     Aggregate
Intrinsic
Value (1)
 

Outstanding at January 1, 2011

     241,800     $ 46.98        

Exercised

     (79,600     47.45        
  

 

 

         

Outstanding at September 30, 2011

     162,200       46.75        4.9      $ 2,556  
  

 

 

      

 

 

    

 

 

 

Exercisable at September 30, 2011

     157,200     $ 47.25        4.9      $ 2,399  
  

 

 

      

 

 

    

 

 

 

 

(1) Aggregate intrinsic value reflects fully vested LP Unit options at the date indicated. Intrinsic value is determined by calculating the difference between our closing LP Unit price on the last trading day in September 2011 and the exercise price, multiplied by the number of exercisable, in-the-money options.

The total intrinsic value of options exercised was $1.3 million and $1.5 million during the nine months ended September 30, 2011 and 2010, respectively. At September 30, 2011, total unrecognized compensation cost related to unvested LP Unit options was $0.2 million. We expect to recognize this remaining cost over a weighted average period of 0.2 years. At September 30, 2011, 333,000 LP Units were available for grant in connection with the Option Plan. However, with the adoption of the LTIP, we do not expect to make any future grants pursuant to the Option Plan. The fair value of options vested was $0.1 million and $0.4 million during the nine months ended September 30, 2011 and 2010, respectively.

17. RELATED PARTY TRANSACTIONS

We are managed by Buckeye GP, our general partner. Services Company is considered a related party with respect to us. As discussed in Note 1, our consolidated financial statements include the financial results of Services Company on a consolidated basis, and all intercompany transactions have been eliminated.

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

Services Company, which is beneficially owned by the ESOP, owned 1.3 million of our LP Units (approximately 1.6% of our LP Units outstanding) as of September 30, 2011. Distributions received by Services Company from us on such LP Units are used to fund obligations of the ESOP. Distributions paid to Services Company totalled $2.9 million and $4.5 million for the nine months ended September 30, 2011 and 2010, respectively. Total distributions paid to Services Company decrease over time because Services Company sells LP Units to fund benefits payable to ESOP participants who exit the ESOP.

Prior to the Merger, Buckeye GP received incentive distributions from us pursuant to our partnership agreement and incentive compensation agreement. Incentive distributions were based on the level of quarterly cash distributions paid per LP Unit and the total number of LP Units outstanding. Incentive distribution payments totaled $37.8 million during the nine months ended September 30, 2010.

18. PARTNERS’ CAPITAL AND DISTRIBUTIONS

Our LP Units represent limited partner interests, which give the holders thereof the right to participate in distributions and to exercise the other rights and privileges available to them under our partnership agreement. Our partnership agreement provides that, without prior approval of our limited partners holding an aggregate of at least two-thirds of the outstanding LP Units, we cannot issue any LP Units of a class or series having preferences or other special or senior rights over the LP Units. In accordance with our partnership agreement, capital accounts are maintained for our general partner and limited partners. In conjunction with the Merger, our partnership agreement was amended.

Class B Units represent a separate class of our limited partnership interests. The Class B Units share equally with the LP Units (i) with respect to the payment of distributions and (ii) in the event of our liquidation. We have the option to pay distributions on the Class B Units with cash or by issuing additional Class B Units, with the number of Class B Units issued based upon the volume-weighted average price of the LP Units for the 10 trading days immediately preceding the date the distributions are declared, less a discount of 15%. The Class B Units have the same voting rights as if they were outstanding LP Units and are entitled to vote as a separate class on any matters that materially adversely affect the rights or preferences of the Class B Units in relation to other classes of partnership interests or as required by law. The Class B Units will convert into LP Units on a one-for-one basis on the earlier of (a) the date on which at least 4 million barrels of incremental storage capacity are placed in service by BORCO or (b) the third anniversary of the closing of the BORCO acquisition.

In April 2011, we issued 5,520,000 LP Units, which included 720,000 LP Units issued as part of the overallotment option, in an underwritten public offering at a public offering price of $59.41 per LP Unit. Total proceeds from the offering, including the overallotment option and after the underwriters’ discount of $1.99 per LP Unit and offering expenses, were approximately $316.6 million, and were used to reduce amounts outstanding under our Prior BPL Credit Facility.

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

Summary of Changes in Outstanding Units

The following is a reconciliation of units outstanding for the periods indicated:

 

     Limited
Partners
     Class B
Units
     Total  

Units outstanding at December 31, 2010

     71,436,099        —           71,436,099  

LP Units issued pursuant to the Option Plan

     54,380        —           54,380  

LP Units issued pursuant to the LTIP

     14,321        —           14,321  

Issuance of units to First Reserve and Vopak as consideration for BORCO acquisition

     3,104,305        5,478,611        8,582,916  

Issuance of units to institutional investors (1)

     5,794,725        1,314,870        7,109,595  

Issuance of units in underwritten public offering

     5,520,000        —           5,520,000  

Issuance of Class B Units in lieu of quarterly cash distributions

     —           382,358        382,358  
  

 

 

    

 

 

    

 

 

 

Units outstanding at September 30, 2011

     85,923,830        7,175,839        93,099,669  
  

 

 

    

 

 

    

 

 

 

 

(1) Proceeds were used to fund a portion of the BORCO acquisition.

Distributions

We generally make quarterly cash distributions to unitholders of substantially all of our available cash, generally defined in our partnership agreement as consolidated cash receipts less consolidated cash expenditures and such retentions for working capital, anticipated cash expenditures and contingencies as our general partner deems appropriate. Cash distributions on our LP Units totaled $252.2 million and $185.8 million during the nine months ended September 30, 2011 and 2010, respectively. We also paid distributions in kind to our Class B unitholders by issuing 382,358 Class B Units during the nine months ended September 30, 2011.

On November 4, 2011, we announced a quarterly distribution of $1.0250 per LP Unit that will be paid on November 30, 2011, to LP unitholders of record on November 15, 2011. Total cash distributed to LP unitholders on November 30, 2011 will total approximately $88.4 million. We also expect to issue approximately 138,000 Class B Units in lieu of cash distributions on November 30, 2011, to Class B unitholders of record on November 15, 2011.

19. EARNINGS (LOSS) PER UNIT

Basic and diluted earnings (loss) per unit (includes LP Units and Class B Units) is calculated by dividing net income (loss), after deducting the amount allocated to noncontrolling interests, by the weighted-average number of LP Units and Class B Units outstanding during the period.

Pursuant to the Merger Agreement, BGH’s unitholders received a total of approximately 20.0 million of Buckeye’s LP Units in the aggregate 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 on the date of the Merger. 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. Therefore, since BGH was the surviving accounting entity, the weighted average number of units outstanding used for basic and diluted earnings (loss) per unit calculations are BGH’s historical weighted average common units outstanding adjusted for the reverse unit split and the addition of Buckeye’s existing LP Units. Amounts reflecting historical BGH unit and per unit amounts included in this report have been restated for the reverse unit split.

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

The following table is a reconciliation of the weighted average number of units used in the basic and diluted earnings (loss) per unit calculations for the periods indicated (in thousands, except per unit amounts):

 

     Three Months Ended
September 30,
     Nine Months Ended
September 30,
 
     2011     2010      2011      2010  

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

   $ (109,700   $ 11,941      $ 48,814      $ 34,718  

Basic:

          

Weighted average units outstanding

     92,982       19,581        89,499        19,581  

Weighted average management units outstanding

     —          371        —           371  
  

 

 

   

 

 

    

 

 

    

 

 

 

Units for basic

     92,982       19,952        89,499        19,952  
  

 

 

   

 

 

    

 

 

    

 

 

 

Earnings (loss) per unit - basic

   $ (1.18   $ 0.60      $ 0.55      $ 1.74  
  

 

 

   

 

 

    

 

 

    

 

 

 

Diluted:

          

Units for basic

     92,982       19,952        89,499        19,952  

Dilutive effect of LP unit options and LTIP awards granted

     —          —           332        —     
  

 

 

   

 

 

    

 

 

    

 

 

 

Units for diluted

     92,982       19,952        89,831        19,952  
  

 

 

   

 

 

    

 

 

    

 

 

 

Earnings (loss) per unit - diluted

   $ (1.18   $ 0.60      $ 0.54      $ 1.74  
  

 

 

   

 

 

    

 

 

    

 

 

 

For the three months ended September 30, 2011, there were 367 potential units excluded in computing the dilutive effect of LP unit options and LTIP awards granted in the diluted earnings (loss) per unit as the effect of their inclusion would have been anti-dilutive.

20. BUSINESS SEGMENTS

We operate and report in five business segments: Pipelines & Terminals; International Operations; Natural Gas Storage; Energy Services; and Development & Logistics. Effective January 1, 2011, we realigned our five business segments. We combined the Pipeline Operations and Terminalling & Storage segments into one segment, the Pipelines & Terminals segment, and moved our terminal in Yabucoa, Puerto Rico, previously included as part of the Terminalling & Storage segment, to a new International Operations segment with the BORCO facility. We recast our period-to-period comparisons to conform to the current presentation.

Pipelines & Terminals

The Pipelines & Terminals segment receives refined petroleum products from refineries, connecting pipelines, and bulk and marine terminals and transports those products to other locations for a fee and provides bulk storage and terminal throughput services in the continental United States. This segment owns and operates approximately 6,100 miles of pipeline systems in 17 states. The segment has 95 liquid petroleum products terminals in 21 states with aggregate storage capacity of approximately 37.1 million barrels.

International Operations

The International Operations segment provides marine bulk storage and marine terminal throughput services. The segment has two liquid petroleum product terminals, one in Puerto Rico and one on The Grand Bahama Island in The Bahamas, with an aggregate storage capacity of 26.2 million barrels.

Natural Gas Storage

The Natural Gas Storage segment provides natural gas storage services at a natural gas storage facility in northern California. The facility has approximately 29 Bcf of working natural gas storage capacity and is connected

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

to Pacific Gas and Electric’s intrastate gas pipelines that service natural gas demand in the San Francisco and Sacramento, California areas.

Energy Services

The Energy Services segment is a wholesale distributor of refined petroleum products in areas also served by our pipelines and terminals assets. This segment recognizes revenues when products are delivered. The segment’s products include gasoline, propane and petroleum distillates such as heating oil, diesel fuel and kerosene. The segment also has five terminals with aggregate storage capacity of approximately 1.0 million barrels. The segment’s customers consist principally of product wholesalers as well as major commercial users of these refined petroleum products.

Development & Logistics

The Development & Logistics segment provides contract operations, engineering and construction management services as well as asset development services to energy companies throughout the U.S. and internationally. This segment operates approximately 2,700 miles of third-party pipeline and terminals, which are owned principally by major oil and gas, petrochemical and chemical companies, and also acts as a business development arm for many of these same customers. The Development & Logistics segment also includes our ownership and operation of an ammonia pipeline and our majority ownership of the Sabina Pipeline, each located in Texas.

Adjusted EBITDA

Adjusted EBITDA is the primary measure used by senior management, including our Chief Executive Officer, to evaluate our operating results and to allocate our resources. We define EBITDA, a measure not defined under GAAP, as net income (loss) attributable to our unitholders before interest and debt expense, income taxes and depreciation and amortization. EBITDA should not be considered an alternative to net income, operating income, cash flow from operations or any other measure of financial performance or liquidity presented in accordance with GAAP. The EBITDA measure eliminates the significant level of non-cash depreciation and amortization expense that results from the capital-intensive nature of our businesses and from intangible assets recognized in business combinations. In addition, EBITDA is unaffected by our capital structure due to the elimination of interest and debt expense and income taxes. We define Adjusted EBITDA, which is also a non-GAAP measure, as EBITDA plus: (i) non-cash deferred lease expense, which is the difference between the estimated annual land lease expense for our natural gas storage facility in the Natural Gas Storage segment to be recorded under GAAP and the actual cash to be paid for such annual land lease; (ii) non-cash unit-based compensation expense; (iii) income attributable to noncontrolling interests related to Buckeye for periods prior to the Merger in order to provide comparability between periods before and after the Merger; and (iv) goodwill impairment expense associated with the Natural Gas Storage segment; less (i) amortization of unfavorable storage contracts acquired in connection with the BORCO acquisition; and (ii) gain on the sale of our equity investment in WT LPG.

The EBITDA and Adjusted EBITDA data presented may not be comparable to similarly titled measures at other companies because EBITDA and Adjusted EBITDA exclude some items that affect net income (loss) attributable to our unitholders, and these items may be defined differently by other companies. Our senior management uses Adjusted EBITDA to evaluate consolidated operating performance and the operating performance of our business segments and to allocate resources and capital to the business segments. In addition, our senior management uses Adjusted EBITDA as a performance measure to evaluate the viability of proposed projects and to determine overall rates of return on alternative investment opportunities.

We believe that investors benefit from having access to the same financial measures that we use. Further, we believe that these measures are useful to investors because they are one of the bases for comparing our operating performance with that of other companies with similar operations, although our measures may not be directly comparable to similar measures used by other companies.

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

Each segment uses the same accounting policies as those used in the preparation of our consolidated financial statements. All inter-segment revenues, operating income and assets have been eliminated. All periods are presented on a consistent basis. All of our operations and assets are conducted and located in the United States, including Puerto Rico, or the Bahamas.

Financial information about each segment, EBITDA, Adjusted EBITDA and a reconciliation of EBITDA and Adjusted EBITDA to net income (loss) attributable to our unitholders, which is the most comparable GAAP financial measure (in thousands) are presented below for the periods or at the dates indicated (in thousands):

 

     Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
     2011     2010     2011     2010  

Revenue:

        

Pipelines & Terminals

   $ 162,740     $ 145,521     $ 456,056     $ 424,536  

International Operations (1)

     47,986       —          146,051       —     

Natural Gas Storage

     15,742       21,663       49,431       68,318  

Energy Services

     894,618       566,804       2,810,055       1,636,955  

Development & Logistics

     10,766       9,082       30,937       27,382  

Intersegment

     (14,941     (8,213     (45,991     (23,884
  

 

 

   

 

 

   

 

 

   

 

 

 

Total revenue

   $ 1,116,911     $ 734,857     $ 3,446,539     $ 2,133,307  
  

 

 

   

 

 

   

 

 

   

 

 

 

Depreciation and amortization:

        

Pipelines & Terminals

   $ 14,727     $ 11,649     $ 40,502     $ 34,346  

International Operations

     12,868       —          36,299       —     

Natural Gas Storage

     1,807       1,643       5,326       4,924  

Energy Services

     1,379       1,331       3,894       3,702  

Development & Logistics

     449       439       1,206       1,287  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total depreciation and amortization

   $ 31,230     $ 15,062     $ 87,227     $ 44,259  
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss):

        

Pipelines & Terminals

   $ 69,258     $ 72,647     $ 208,377     $ 209,586  

International Operations

     17,657       —          56,358       —     

Natural Gas Storage

     (172,078     2,795       (178,096     9,548  

Energy Services

     5,415       2,581       8,940       (1,287

Development & Logistics

     2,443       1,490       5,614       3,096  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total operating income (loss)

   $ (77,305   $ 79,513     $ 101,193     $ 220,943  
  

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) The International Operations segment’s revenue generated in The Bahamas was $53.1 million and $143.3 million for the three and nine months ended September 30, 2011, respectively, which represents 92.8% and 92.3% of the International Operations segment’s total revenue for the two periods.

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

     Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
     2011     2010     2011     2010  

Adjusted EBITDA:

        

Pipelines & Terminals

   $ 86,510     $ 89,051     $ 260,743     $ 256,458  

International Operations

     30,095       —          86,248       —     

Natural Gas Storage

     426       5,753       266       18,311  

Energy Services

     6,978       4,586       13,578       4,340  

Development & Logistics

     2,519       2,013       5,563       3,500  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total Adjusted EBITDA

   $ 126,528     $ 101,403     $ 366,398     $ 282,609  
  

 

 

   

 

 

   

 

 

   

 

 

 

GAAP Reconciliation:

        

Net income (loss)

   $ (108,200   $ 60,962     $ 53,205     $ 165,042  

Less: net income attributable to noncontrolling interests

     (1,500     (49,021     (4,391     (130,324
  

 

 

   

 

 

   

 

 

   

 

 

 

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

     (109,700     11,941       48,814       34,718  

Interest and debt expense

     33,199       22,082       90,292       65,088  

Income tax expense (benefit)

     —          229       (193     (435

Depreciation and amortization

     31,230       15,062       87,227       44,259  
  

 

 

   

 

 

   

 

 

   

 

 

 

EBITDA

     (45,271     49,314       226,140       143,630  

Net income attributable to noncontrolling interests affected by Merger (for periods prior to Merger) (1)

     —          49,150       —          130,205  

Gain on sale of equity investment

     —          —          (34,112     —     

Amortization of unfavorable storage contracts (2)

     (485     —          (4,813     —     

Non-cash deferred lease expense

     1,030       1,059       3,091       3,176  

Non-cash unit-based compensation expense

     1,694       1,880       6,532       5,598  

Goodwill impairment expense

     169,560       —          169,560       —     
  

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

   $ 126,528     $ 101,403     $ 366,398     $ 282,609  
  

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) Amounts represent portions of BGH’s noncontrolling interests related to Buckeye that were eliminated as a result of the Merger. Amounts are added back for the 2010 periods to provide comparability with the 2011 periods.
(2) Represents amortization of unfavorable storage contracts acquired in connection with the BORCO acquisition.

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

     Nine Months Ended
September 30,
 
     2011      2010  

Capital additions, net: (1)

     

Pipelines & Terminals

   $ 61,156      $ 38,129  

International Operations

     122,837        —     

Natural Gas Storage

     5,673        7,466  

Energy Services

     1,228        2,835  

Development & Logistics

     474        845  
  

 

 

    

 

 

 

Total capital additions, net

   $ 191,368      $ 49,275  
  

 

 

    

 

 

 

 

(1) Amount excludes $20.1 million and $1.0 million of non-cash changes in accruals for capital expenditures for the nine months ended September 30, 2011 and 2010, respectively (see Note 22).

 

     September 30,
2011
     December 31,
2010
 

Total Assets:

     

Pipelines & Terminals (1)

   $ 2,524,983      $ 2,328,702  

International Operations (2)

     1,999,967        60,313  

Natural Gas Storage

     365,484        549,876  

Energy Services

     595,242        561,382  

Development & Logistics

     72,254        73,943  
  

 

 

    

 

 

 

Total assets

   $ 5,557,930      $ 3,574,216  
  

 

 

    

 

 

 

Goodwill:

     

Pipelines & Terminals

   $ 248,250      $ 248,250  

International Operations

     498,719        —     

Natural Gas Storage

     —           169,560  

Energy Services

     1,132        1,132  

Development & Logistics

     13,182        13,182  
  

 

 

    

 

 

 

Total goodwill

   $ 761,283      $ 432,124  
  

 

 

    

 

 

 

 

(1) All equity investments are included in the assets of the Pipelines & Terminals segment.
(2) The International Operations segment’s long-lived assets consist of property, plant and equipment, goodwill, intangible assets and other non-current assets. Total long-lived assets located in or attributable to The Bahamas was $1,911.0 million at September 30, 2011, which was 97.3% of the International Operations segment’s total long-lived assets.

21. RELOCATION