10-Q
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 March 31, 2013

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 April 30, 2013: 97,420,064 and 8,160,943, respectively.

 

 

 


Table of Contents

TABLE OF CONTENTS

 

 

         Page  
PART I. FINANCIAL INFORMATION   

Item 1.

 

Financial Statements

  
 

Condensed Consolidated Statements of Operations for the Three Months Ended March  31, 2013 and 2012 (Unaudited)

     2   
 

Condensed Consolidated Statements of Comprehensive Income for the Three Months Ended March  31, 2013 and 2012 (Unaudited)

     3   
 

Condensed Consolidated Balance Sheets as of March 31, 2013 and December 31, 2012 (Unaudited)

     4   
 

Condensed Consolidated Statements of Cash Flows for the Three Months Ended March  31, 2013 and 2012 (Unaudited)

     5   
 

Condensed Consolidated Statements of Partners’ Capital for the Three Months Ended March  31, 2013 and 2012 (Unaudited)

     6   
 

Notes to Unaudited Condensed Consolidated Financial Statements:

  
 

1. Organization and Basis of Presentation

     7   
 

2. Acquisition

     8   
 

3. Commitments and Contingencies

     8   
 

4. Inventories

     10   
 

5. Prepaid and Other Current Assets

     11   
 

6. Equity Investments

     11   
 

7. Long-Term Debt

     11   
 

8. Derivative Instruments and Hedging Activities

     12   
 

9. Fair Value Measurements

     16   
 

10. Pensions and Other Postretirement Benefits

     18   
 

11. Unit-Based Compensation Plans

     18   
 

12. Partners’ Capital and Distributions

     19   
 

13. Earnings Per Unit

     21   
 

14. Business Segments

     21   
 

15. Supplemental Cash Flow Information

     24   

Item 2.

 

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

     25   

Item 3.

 

Quantitative and Qualitative Disclosures About Market Risk

     35   

Item 4.

 

Controls and Procedures

     37   
PART II. OTHER INFORMATION   

Item 1.

 

Legal Proceedings

     38   

Item 1A.

 

Risk Factors

     38   

Item 6.

 

Exhibits

     39   

 

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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  
     March 31,  
     2013     2012  

Revenue:

    

Product sales

   $ 1,069,217     $ 1,027,888  

Transportation, storage and other services

     275,744       231,551  
  

 

 

   

 

 

 

Total revenue

     1,344,961       1,259,439  
  

 

 

   

 

 

 

Costs and expenses:

    

Cost of product sales and natural gas storage services

     1,073,693       1,031,485  

Operating expenses

     97,357       97,218  

Depreciation and amortization

     37,591       33,027  

General and administrative

     17,171       16,975  
  

 

 

   

 

 

 

Total costs and expenses

     1,225,812       1,178,705  
  

 

 

   

 

 

 

Operating income

     119,149       80,734  
  

 

 

   

 

 

 

Other income (expense):

    

Earnings from equity investments

     1,629       1,949  

Interest and debt expense

     (30,249     (28,810

Other income (expense)

     101       (69
  

 

 

   

 

 

 

Total other expense, net

     (28,519     (26,930
  

 

 

   

 

 

 

Income before taxes

     90,630       53,804  

Income tax expense

     (131     (337
  

 

 

   

 

 

 

Net income

     90,499       53,467  

Less: Net income attributable to noncontrolling interests

     (1,158     (1,508
  

 

 

   

 

 

 

Net income attributable to Buckeye Partners, L.P.

   $ 89,341     $ 51,959  
  

 

 

   

 

 

 

Earnings per unit:

    

Basic

   $ 0.87     $ 0.55  
  

 

 

   

 

 

 

Diluted

   $ 0.86     $ 0.54  
  

 

 

   

 

 

 

Weighted average units outstanding:

    

Basic

     103,247       95,229  
  

 

 

   

 

 

 

Diluted

     103,571       95,558  
  

 

 

   

 

 

 

See Notes to Unaudited Condensed Consolidated Financial Statements.

 

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BUCKEYE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)

(Unaudited)

 

     Three Months Ended  
     March 31,  
     2013     2012  

Net income

   $ 90,499     $ 53,467  

Other comprehensive income:

    

Unrealized gains on derivative instruments

     8,847       17,291  

Adjustment to funded status of benefit plans

     (24     23  
  

 

 

   

 

 

 

Total other comprehensive income

     8,823       17,314  
  

 

 

   

 

 

 

Comprehensive income

     99,322       70,781  

Less: Comprehensive income attributable to noncontrolling interests

     (1,158     (1,508
  

 

 

   

 

 

 

Comprehensive income attributable to Buckeye Partners, L.P.

   $ 98,164     $ 69,273  
  

 

 

   

 

 

 

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)

 

     March 31,     December 31,  
     2013     2012  

Assets:

    

Current assets:

    

Cash and cash equivalents

   $ 4,564     $ 6,776  

Trade receivables, net

     275,125       262,023  

Construction and pipeline relocation receivables

     13,818       13,078  

Inventories

     192,827       259,163  

Derivative assets

     2,194       1,719  

Prepaid and other current assets

     67,065       91,563  
  

 

 

   

 

 

 

Total current assets

     555,593       634,322  

Property, plant and equipment, net

     4,227,029       4,188,648  

Equity investments

     70,143       68,713  

Goodwill

     811,525       818,121  

Intangible assets, net

     212,370       219,247  

Other non-current assets

     52,369       51,958  
  

 

 

   

 

 

 

Total assets

   $ 5,929,029     $ 5,981,009  
  

 

 

   

 

 

 

Liabilities and partners’ capital:

    

Current liabilities:

    

Line of credit

   $ 124,900     $ 206,200  

Accounts payable

     122,425       112,792  

Derivative liabilities

     79,797       82,989  

Accrued and other current liabilities

     156,620       192,385  
  

 

 

   

 

 

 

Total current liabilities

     483,742       594,366  

Long-term debt

     2,455,412       2,735,244  

Long-term derivative liabilities

     53,147       57,805  

Other non-current liabilities

     202,053       204,754  
  

 

 

   

 

 

 

Total liabilities

     3,194,354       3,592,169  
  

 

 

   

 

 

 

Commitments and contingencies (Note 3)

    

Partners’ capital:

    

Buckeye Partners, L.P. capital:

    

Limited Partners (97,417,696 and 90,371,061 units outstanding as of March 31, 2013 and December 31, 2012, respectively)

     2,447,787       2,117,788  

Class B Units (8,160,943 and 7,974,750 units outstanding as of March 31, 2013 and December 31, 2012, respectively)

     420,262       413,304  

Accumulated other comprehensive loss

     (149,956     (158,779
  

 

 

   

 

 

 

Total Buckeye Partners, L.P. capital

     2,718,093       2,372,313  

Noncontrolling interests

     16,582       16,527  
  

 

 

   

 

 

 

Total partners’ capital

     2,734,675       2,388,840  
  

 

 

   

 

 

 

Total liabilities and partners’ capital

   $ 5,929,029     $ 5,981,009  
  

 

 

   

 

 

 

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)

 

     Three Months Ended
March 31,
 
     2013     2012  

Cash flows from operating activities:

    

Net income

   $ 90,499     $ 53,467  

Adjustments to reconcile net income to net cash provided by (used in) operating activities:

    

Depreciation and amortization

     37,591       33,027  

Net changes in fair value of derivatives

     291       2,952  

Non-cash deferred lease expense

     942       975  

Amortization of unfavorable storage contracts

     (2,748     (2,748

Earnings from equity investments

     (1,629     (1,949

Distributions from equity investments

     125       1,853  

Other non-cash items

     4,356       4,412  

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

    

Trade receivables

     (13,102     14,803  

Construction and pipeline relocation receivables

     (740     (260

Inventories

     66,336       110,897  

Prepaid and other current assets

     24,418       31,156  

Accounts payable

     9,588       (31,670

Accrued and other current liabilities

     (30,347     (27,532

Other non-current assets

     (1,116     1,853  

Other non-current liabilities

     (2,047     (9,635
  

 

 

   

 

 

 

Net cash provided by operating activities

     182,417       181,601  
  

 

 

   

 

 

 

Cash flows from investing activities:

    

Capital expenditures

     (67,186     (74,313

Deposit in anticipation of acquisition

     —         (14,000

Proceeds from disposal of property, plant and equipment

     358       317  
  

 

 

   

 

 

 

Net cash used in investing activities

     (66,828     (87,996
  

 

 

   

 

 

 

Cash flows from financing activities:

    

Net proceeds from issuance of units

     349,564       247,461  

Net proceeds from exercise of unit options

     —         (61

Payment of tax withholding on issuance of LTIP awards

     (3,498     —    

Borrowings under BPL Credit Facility

     339,000       111,000  

Repayments under BPL Credit Facility

     (619,000     (255,000

Net borrowings (repayments) under BES Credit Facility

     (81,300     (99,800

Distributions paid to noncontrolling interests

     (2,295     (2,395

Distributions paid to unitholders

     (100,272     (92,737
  

 

 

   

 

 

 

Net cash used in financing activities

     (117,801     (91,532
  

 

 

   

 

 

 

Net (decrease) increase in cash and cash equivalents

     (2,212     2,073  

Cash and cash equivalents — Beginning of period

     6,776       12,986  
  

 

 

   

 

 

 

Cash and cash equivalents — End of period

   $ 4,564     $ 15,059  
  

 

 

   

 

 

 

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)

 

                  Accumulated              
                  Other              
     Limited     Class B      Comprehensive     Noncontrolling        
     Partners     Units      Loss     Interests     Total  

Partners’ capital - January 1, 2013

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

Net income

     82,383       6,958        —         1,158       90,499  

Distributions paid to unitholders

     (101,475     —          —         1,203       (100,272

Net proceeds from issuance of units

     349,564       —          —         —         349,564  

Amortization of unit-based compensation awards

     3,343       —           —         —         3,343  

Payment of tax withholding on issuance of LTIP awards

     (3,498     —          —         —         (3,498

Distributions paid to noncontrolling interests

     —         —          —         (2,295     (2,295

Other comprehensive income

     —         —          8,823       —         8,823  

Noncash accrual for distribution equivalent rights

     (334     —          —         —         (334

Other

     16       —          —         (11     5  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Partners’ capital - March 31, 2013

   $ 2,447,787     $ 420,262      $ (149,956   $ 16,582     $ 2,734,675  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Partners’ capital - January 1, 2012

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

Net income

     47,946       4,013        —         1,508       53,467  

Distributions paid to unitholders

     (94,090     —          —         1,353       (92,737

Net proceeds from issuance of units

     247,461       —          —         —         247,461  

Amortization of unit-based compensation awards

     2,627       —          —         —         2,627  

Net proceeds from exercise of unit options

     (61     —          —         —         (61

Distributions paid to noncontrolling interests

     —         —          —         (2,395     (2,395

Other comprehensive income

     —         —          17,314       —         17,314  

Noncash accrual for distribution equivalent rights

     (241     —          —         —         (241

Other

     687       —          —         9       696  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Partners’ capital - March 31, 2012

   $ 2,239,600     $ 399,652      $ (110,427   $ 21,263     $ 2,550,088  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

See Notes to Unaudited Condensed Consolidated Financial Statements.

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND BASIS OF PRESENTATION

Organization

Buckeye Partners, L.P. is a publicly traded Delaware master limited partnership and its limited partnership units representing limited partner interests (“LP Units”) are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “BPL.” Buckeye GP LLC (“Buckeye GP”) is our general partner. As used in these Notes to 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, miles of pipeline and active product terminals. In addition, we operate and/or maintain third-party pipelines under agreements with major oil and gas, petrochemical and chemical companies, and perform certain engineering and construction management services for third parties. We also own and operate a natural gas storage facility in Northern California, and are a wholesale distributor of refined petroleum products in the United States in areas also served by our pipelines and terminals, as well as in the Caribbean. Beginning in late 2012, we began to provide fuel oil supply and distribution services to third parties in the Caribbean. Our flagship marine terminal in The Bahamas, Bahamas Oil Refining Company International Limited (“BORCO”), is one of the largest marine crude oil and petroleum products storage facilities in the world, serving the international markets as a global logistics hub.

Basis of Presentation and Principles of Consolidation

The unaudited 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”). Accordingly, our financial statements reflect all normal and recurring adjustments that are, in the opinion of management, necessary for a fair presentation of our results of operations for the interim periods. The consolidated financial statements include the accounts of our subsidiaries controlled by us and variable interest entities of which we are the primary beneficiary. We have eliminated all intercompany transactions in consolidation.

We believe that the disclosures in these unaudited condensed consolidated financial statements are adequate to make the information presented not misleading. These interim financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto contained in our Annual Report on Form 10-K for the year ended December 31, 2012.

Recent Accounting Developments

Reclassification Adjustments Out of Accumulated Other Comprehensive Income (“AOCI”). In February 2013, the Financial Accounting Standards Board (“FASB”) issued guidance requiring entities to disclose additional information about reclassification adjustments, including changes in AOCI balances by component and significant items reclassified out of AOCI. Under the new guidance, an entity would (i) disaggregate the total change of each component of OCI and separately present reclassification adjustments and current-period OCI, and (ii) present information about significant items reclassified out of AOCI by component either on the face of the statement where net income is presented or as a separate disclosure in the notes to the financial statements. This guidance is effective for interim and annual periods beginning after December 15, 2012. We adopted this guidance on January 1, 2013, which did not have an impact on our condensed consolidated financial statements, or a material impact on our disclosures, as there were no significant reclassification adjustments during the three months ended March 31, 2013.

Balance Sheet: Disclosures about Offsetting Assets and Liabilities. In December 2011, the FASB issued guidance requiring an entity to provide enhanced disclosures that will enable users of its financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. In January 2013, the FASB issued an update to this guidance clarifying that the scope of disclosures applied to derivatives accounted for in accordance with FASB Accounting Standards Codification (“ASC”) Topic 815, Derivative and Hedging,

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

including bifurcated embedded derivatives, repurchase agreements and reverse purchase agreements and securities lending transactions that are either offset in accordance with FASB ASC Section 210-20-45 or Section 815-10-45 or subject to an enforceable master netting arrangement or similar agreement. This guidance is effective for interim and annual reporting periods beginning on or after January 1, 2013 and should be applied retrospectively. We adopted this guidance on January 1, 2013, which did not have an impact on our condensed consolidated financial statements, or a material impact on our disclosures. See Note 8 for information about our netting policy for derivatives.

2. ACQUISITION

Business Combination

In July 2012, we acquired a marine terminal facility for liquid petroleum products in New York Harbor from Chevron U.S.A Inc. for $260.3 million in cash. 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

   $ 547  

Property, plant and equipment

     198,091  

Intangible assets

     13,350  

Goodwill

     58,425  

Environmental liabilities

     (10,101
  

 

 

 

Allocated purchase price

   $ 260,312  
  

 

 

 

3. COMMITMENTS AND CONTINGENCIES

Claims and Legal Proceedings

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

On May 25, 2012, a ship allided with a jetty at our BORCO facility while berthing, causing damage to portions of the jetty. The extent of the damage is presently estimated to range between $20.0 million and $30.0 million. Buckeye has insurance to cover this loss, subject to a $5.0 million deductible. On May 26, 2012, we commenced legal proceedings in The Bahamas against the vessel’s owner and the vessel to obtain security for the cost of repairs and other losses incurred as a result of the incident. Full security for our claim has been provided by the vessel owner’s insurers, reserving all of their defenses. We also have notified the customer on whose behalf the vessel was at the BORCO facility that we intend to hold them responsible for all damages and losses resulting from the incident pursuant to the terms of an agreement between the parties. Any disputes between us and our customer on this matter are subject to arbitration in Houston, Texas. The vessel owner and customer are each claiming they are entitled to limit their liability to approximately $17.0 million, but we are contesting the right of either vessel owner or customer to such limitation. At this time, we have not experienced any material interruption of service at the BORCO facility as a result of the incident and have commenced the process of repairing the jetty. We recorded a loss on disposal due to the assets destroyed in the incident and other related costs incurred; however, since we believe recovery of our losses is probable, we recorded a corresponding receivable. As of March 31, 2013, we have a $5.0 million receivable included in “Other non-current assets” in our unaudited condensed consolidated balance sheet, representing reimbursement of the deductible. To the extent the proceeds from the recovery of our losses is in excess of the carrying value of the destroyed assets or other costs incurred, we will recognize a gain when such proceeds are received and are not refundable. As of March 31, 2013, no gain had been recognized; however, we recorded a $2.4 million deferred liability in “Accrued and other current liabilities” in our unaudited condensed consolidated balance sheet, representing excess proceeds received over the loss on disposal and other costs incurred.

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

Federal Energy Regulatory Commission (“FERC”) Proceedings

FERC Docket No. IS12-185 – Buckeye Pipe Line Show Cause Proceeding. On March 30, 2012, FERC issued an order (the “Show Cause Order”) regarding the market-based methodology used by Buckeye Pipe Line Company, L.P. (“BPLC”) to set tariff rates on its pipeline system (the “Buckeye System”). In 1991, BPLC sought and received FERC permission to determine rate changes on the Buckeye System using a unique methodology that constrains rates in markets not found to be competitive based on rate changes in markets that FERC found to be competitive, as well as certain other limits on rate increases. FERC ordered the continuation of this methodology for the Buckeye System in 1994, subject to FERC’s authority to cause BPLC to terminate the program in the future. The Show Cause Order, among other things, stated that FERC would review the continued efficacy of BPLC’s unique program and directed BPLC to show cause why it should not be required to discontinue the program on the Buckeye System and avail itself of the generic ratemaking methodologies used by other oil pipelines. The Show Cause Order also disallowed proposed rate increases on the Buckeye System that would have become effective April 1, 2012. The Show Cause Order did not impact any of the pipeline systems or terminals owned by Buckeye’s other operating subsidiaries. On April 23, 2012, BPLC requested rehearing as to the disallowance of certain rates. On February 22, 2013, FERC issued an order in Dkt. No. IS12-185-000 et al. discontinuing the Buckeye Pipe Line Program, and affirming on rehearing its rejection of all rate increases filed in March 2012 (“Ratemaking Methodology Order”). The Ratemaking Methodology Order permitted Buckeye to retain its currently-filed rates in place, to make future rate changes in under market-based ratemaking authority in markets previously found to be competitive by FERC, and to make future changes in rates in other markets pursuant to the generic FERC ratemaking methods, which would include indexing. No requests for rehearing have been filed with respect to the Ratemaking Methodology Order.

FERC Docket No. OR12-28 – Airlines Complaint against BPLC New York City Jet Fuel Rates. On September 20, 2012, a complaint was filed with FERC by Delta Air Lines, JetBlue Airways, United/Continental Air Lines, and US Airways challenging BPLC’s rates for transportation of jet fuel from New Jersey to three New York City airports. The complaint was not directed at BPLC’s rates for service to other destinations, and does not involve pipeline systems and terminals owned by Buckeye’s other operating subsidiaries. The complaint challenges these jet fuel transportation rates as generating revenues in excess of costs and thus being “unjust and unreasonable” under the Interstate Commerce Act. On October 10, 2012, BPLC filed its answer to the complaint, contending that the airlines’ allegations are based on inappropriate adjustments to the pipeline’s costs and revenues, and that, in any event, any revenue recovery by BPLC in excess of costs would be irrelevant because BPLC’s rates are set under a FERC-approved program that ties rates to competitive levels. BPLC also sought dismissal of the complaint to the extent it seeks to challenge the portion of BPLC’s rates that were deemed just and reasonable, or “grandfathered,” under Section 1803 of the Energy Policy Act of 1992. BPLC further contested the airlines’ ability to seek relief as to past charges where the rates are lawful under BPLC’s FERC-approved rate program. On October 25, 2012, the complainants filed their answer to BPLC’s motion to dismiss and answer. On November 9, 2012, BPLC filed a response addressing newly raised arguments in the complainants’ October 25th answer. On February 22, 2013, FERC issued an order setting the airline complaint in Dkt. No. OR12-28-000 for hearing, but holding the hearing in abeyance and setting the dispute for settlement procedures before a settlement judge. If FERC were to find these challenged rates to be in excess of costs and not otherwise protected by law, it could order BPLC to reduce these rates prospectively and could order repayment to the complaining airlines of any past charges found to be in excess of just and reasonable levels for up to two years prior to the filing date of the complaint. BPLC intends to vigorously defend its rates. On March 8, 2013, an order was issued consolidating this complaint proceeding with the proceeding regarding BPLC’s application for market-based rates in the New York City market in Dkt. No. OR13-3-00 (discussed below), for settlement purposes, and settlement discussions under the supervision of the FERC settlement judge are ongoing. The timing or outcome of final resolution of this matter cannot reasonably be determined at this time.

FERC Docket No. OR13-3 – Buckeye Pipe Line’s Market-Based Rate Application. On October 15, 2012, BPLC filed an application with FERC seeking authority to charge market-based rates for deliveries of refined petroleum products to the New York City-area market (the “Application”). In the Application, BPLC seeks to charge market-based rates from its three origin points in northeastern New Jersey to its five destinations on its Long Island System,

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

including deliveries of jet fuel to the Newark, LaGuardia, and JFK airports. The jet fuel rates were also the subject of the airlines’ OR12-28 complaint discussed above. On December 14, 2012, Delta Air Lines, JetBlue Airways, United/Continental Air Lines, and US Airways filed a joint intervention and protest challenging the Application and requesting its rejection. On January 14, 2013, BPLC filed its answer to the protest and requested summary disposition as to those non-jet-fuel rates that were not challenged in the protest. On January 29, 2013, the protestants responded to BPLC’s answer, and on February 13, 2013, BPLC filed a further answer to the protestants’ January 29, 2013 pleading. On February 28, 2013, FERC issued an order setting the Application for hearing, holding the hearing in abeyance and setting the dispute for settlement procedures before a settlement judge. As discussed above, the Application has been consolidated with the complaint proceeding in Dkt. No. OR12-28-000 for settlement purposes and settlement discussions under the supervision of the FERC settlement judge are ongoing. If FERC were to approve the Application, BPLC would be permitted prospectively to set these rates in response to competitive forces, and the basis for the airlines’ claim for relief in their OR12-28 complaint as to BPLC’s future rates would be irrelevant prospectively. The timing or outcome of FERC’s review of the Application cannot reasonably be determined at this time.

Environmental Contingencies

We recorded operating expenses, net of insurance recoveries, of $1.5 million and $1.2 million during the three months ended March 31, 2013 and 2012, respectively, related to environmental remediation expenditures unrelated to claims and legal proceedings. Costs incurred may be in excess of our estimate, which may have a material impact on our financial condition, results of operations or cash flows. As of March 31, 2013 and December 31, 2012, we recorded environmental liabilities of $63.3 million and $61.8 million, respectively. At March 31, 2013 and December 31, 2012, we had $12.5 million and $17.7 million, respectively, of receivables related to these environmental remediation expenditures covered by insurance.

4. INVENTORIES

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

 

     March 31,     December 31,  
     2013     2012  

Refined petroleum products (1)

   $ 178,870     $ 246,918  

Materials and supplies

     13,957       12,245  
  

 

 

   

 

 

 

Total inventories

   $ 192,827     $ 259,163  
  

 

 

   

 

 

 

 

(1) Ending inventory was 57.5 million and 80.9 million gallons of refined petroleum products at March 31, 2013 and December 31, 2012, respectively.

At March 31, 2013 and December 31, 2012, approximately 92% and 88% of our refined petroleum products inventory volumes were hedged, respectively. Because we generally designate inventory as a hedged item upon purchase, hedged inventory is valued at current market prices with the change in value of the inventory reflected in our unaudited condensed consolidated statements of operations. Inventory not accounted for as a fair value hedge is accounted for at the lower of cost or market using the weighted average cost method.

 

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BUCKEYE PARTNERS, L.P.

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5. PREPAID AND OTHER CURRENT ASSETS

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

 

                                               
     March 31,      December 31,  
     2013      2012  

Prepaid insurance

   $ 7,576      $ 12,585  

Insurance receivables related to environmental remediation reserves

     4,498        11,081  

Margin deposits

     13,625        14,038  

Prepaid services

     15,131        20,031  

Unbilled revenue

     1,237        2,406  

Prepaid taxes

     5,326        5,040  

Vendor prepayments

     7,571        9,480  

Other

     12,101        16,902  
  

 

 

    

 

 

 

Total prepaid and other current assets

   $ 67,065      $ 91,563  
  

 

 

    

 

 

 

6. EQUITY INVESTMENTS

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

 

                                               
     Three Months Ended  
     March 31,  
     2013      2012  

Muskegon Pipeline LLC

   $ 241      $ 263  

Transport4, LLC

     56        —    

West Shore Pipe Line Company

     1,250        1,685  

South Portland Terminal LLC

     82        1  
  

 

 

    

 

 

 

Total earnings from equity investments

   $ 1,629      $ 1,949  
  

 

 

    

 

 

 

Summarized combined income statement data for our equity method investments are as follows for the periods indicated (amounts represent 100% of investee income statement data in thousands):

 

                                               
     Three Months Ended  
     March 31,  
     2013     2012  

Revenue

   $ 17,376     $ 16,299  

Costs and expenses

     (9,935     (8,264

Non-operating expense

     (2,622     (3,137
  

 

 

   

 

 

 

Net income

   $ 4,819     $ 4,898  
  

 

 

   

 

 

 

7. LONG-TERM DEBT

Current Maturities Expected to be Refinanced

It is our intent to refinance the 4.625% Notes in 2013. If necessary, the $300.0 million of 4.625% Notes maturing on July 15, 2013 could be refinanced using our Revolving Credit Facility dated September 26, 2011 (the “Credit Facility”) with SunTrust Bank. At March 31, 2013, we had $740.1 million of additional borrowing capacity under our Credit Facility. Therefore, we have classified these notes as long-term debt in the unaudited condensed consolidated balance sheet at March 31, 2013. Additionally, we expect to pay approximately $68.9 million to settle interest rate swaps relating to the refinancing of the 4.625% Notes on or before July 15, 2013.

 

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8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

We are exposed to financial market risks, including changes in interest rates and commodity prices, in the course of our normal business operations. We use derivative instruments to manage risks.

Interest Rate Derivatives

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

We 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 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. 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. During the three months ended March 31, 2013 and 2012, unrealized gains of $8.6 million and $17.1 million, respectively, were recorded in accumulated other comprehensive loss to reflect the change in the fair values of the forward-starting interest rate swaps.

Over the next twelve months, we expect to reclassify $5.8 million of net losses from accumulated other comprehensive loss to interest and debt expense. The loss consists of the change in fair value on forward-starting interest rate swaps that were settled in 2008 and served as a designated cash flow hedge of our 6.050% Notes, partially offset by a gain attributable to the settlement in January 2011 of the treasury lock agreement associated with the 4.875% Notes. The loss also consists of the change in fair value on forward-starting interest rate swaps that will settle in 2013 and serve as a designated cash flow hedge for the refinancing of our 4.625% Notes.

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

 

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The following table summarizes our commodity derivative instruments outstanding at March 31, 2013 (amounts in thousands of gallons):

 

     Volume (1)      Accounting

Derivative Purpose

   Current      Long-Term      Treatment

Derivatives NOT designated as hedging instruments:

        

Physical fixed price derivative contracts

     12,876        42      Mark-to-market

Physical index derivative contracts

     77,933        —        Mark-to-market

Futures contracts for refined petroleum products

     8,106        —        Mark-to-market

Derivatives designated as hedging instruments:

        
        

Futures contracts for refined petroleum products

     49,854        —        Fair Value Hedge

 

(1) Volume represents absolute value of net notional volume position.

 

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The following table sets forth the fair value of each classification of derivative instruments and the locations of the derivative instruments on our condensed consolidated balance sheets at the dates indicated (in thousands):

 

     March 31, 2013  
     Derivatives     Derivatives     Gross     Netting        
     NOT Designated     Designated     Derivative     Balance        
     as Hedging     as Hedging     Carrying     Sheet        
     Instruments     Instruments     Value     Adjustment (1)     Net Total  

Physical fixed price derivative contracts

   $ 1,510     $ —       $ 1,510     $ (170   $ 1,340  

Physical index derivative contracts

     900       —         900       (46     854  

Futures contracts for refined products

     13,954       1,416       15,370       (15,370     —    
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total current derivative assets

     16,364       1,416       17,780       (15,586     2,194  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Physical fixed price derivative contracts

     3       —         3       —         3  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total non-current derivative assets

     3       —         3       —         3  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Physical fixed price derivative contracts

     (1,325     —         (1,325     170       (1,155

Physical index derivative contracts

     (376     —         (376     46       (330

Futures contracts for refined products

     (23,406     (1,406     (24,812     15,370       (9,442

Interest rate derivatives

     —         (68,870     (68,870     —         (68,870
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total current derivative liabilities

     (25,107     (70,276     (95,383     15,586       (79,797
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Interest rate derivatives

     —         (53,147     (53,147     —         (53,147
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total non-current derivative liabilities

     —         (53,147     (53,147     —         (53,147
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net derivative assets (liabilities)

   $ (8,740   $ (122,007   $ (130,747   $ —       $ (130,747
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) Amounts represent the netting of physical fixed and index contracts’ assets and liabilities when a legal right of offset exists. Futures contracts are subject to settlement through margin requirements and are additionally presented on a net basis.

 

     December 31, 2012  
     Derivatives     Derivatives     Gross     Netting        
     NOT Designated     Designated     Derivative     Balance        
     as Hedging     as Hedging     Carrying     Sheet        
     Instruments     Instruments     Value     Adjustment (1)     Net Total  

Physical fixed price derivative contracts

   $ 1,489     $ —       $ 1,489     $ (335   $ 1,154  

Physical index derivative contracts

     724       —         724       (159     565  

Futures contracts for refined products

     10,359       435       10,794       (10,794     —    
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total current derivative assets

     12,572       435       13,007       (11,288     1,719  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Physical fixed price derivative contracts

     (2,377     —         (2,377     335       (2,042

Physical index derivative contracts

     (705     —         (705     159       (546

Futures contracts for refined products

     (15,268     (3,096     (18,364     10,794       (7,570

Interest rate derivatives

     —         (72,831     (72,831     —         (72,831
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total current derivative liabilities

     (18,350     (75,927     (94,277     11,288       (82,989
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Interest rate derivatives

     —         (57,805     (57,805     —         (57,805
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total non-current derivative liabilities

     —         (57,805     (57,805     —         (57,805
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net derivative assets (liabilities)

   $ (5,778   $ (133,297   $ (139,075   $ —       $ (139,075
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) Amounts represent the netting of physical fixed and index contracts’ assets and liabilities when a legal right of offset exists. Futures contracts are subject to settlement through margin requirements and are additionally presented on a net basis.

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

Our hedged inventory portfolio extends to the third quarter of 2013. The majority of the unrealized gain at March 31, 2013 for inventory hedges represented by futures contracts was minimal and will be realized by the second quarter of 2013 as the related inventory is sold. At March 31, 2013, open refined petroleum product derivative contracts (represented by the physical fixed-price contracts, physical index contracts, and futures contracts for fixed-price sales contracts noted above) varied in duration in the overall portfolio, but did not extend beyond May 2014. In addition, at March 31, 2013, we had refined petroleum product inventories that we intend to use to satisfy a portion of the physical derivative contracts.

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

 

          Three Months Ended
March 31,
 
    

Location

   2013     2012  

Derivatives NOT designated as hedging instruments:

  

 

Physical fixed price
derivative contracts

  

Product sales

   $ 581     $ (893

Physical index
derivative contracts

  

Product sales

     409       102  

Physical fixed price
derivative contracts

  

Cost of product sales and
natural gas storage services

     (86     (1,387

Physical index
derivative contracts

  

Cost of product sales and
natural gas storage services

     (3     (43

Future contracts for refined
products

  

Cost of product sales and
natural gas storage services

     4,340       3,371  

Derivatives designated as fair value hedging instruments:

       

Future contracts for refined
products

  

Cost of product sales and
natural gas storage services

     776       (29,171

Physical inventory - hedged
items

  

Cost of product sales and
natural gas storage services

     (481     28,458  

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

   $ 1,585     $ (732

Time value excluded from hedge
assessment

  

Cost of product sales and
natural gas storage services

     (1,290     20  
     

 

 

   

 

 

 

Net gain (loss) in income

      $ 295     $ (712
     

 

 

   

 

 

 

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

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

 

            Loss Reclassified  
            from AOCI to Income for the  
            Three Months Ended  
            March 31,  
     Location      2013     2012  

Derivatives designated as cash flow hedging instruments:

  

 

Interest rate contracts

     Interest and debt expense       $ (228   $ (230
            Gain Recognized  
            in OCI on Derivatives for the  
            Three Months Ended  
            March 31,  
            2013     2012  

Derivatives designated as cash flow hedging instruments:

  

    

Interest rate contracts

      $ 8,619     $ 17,061  

9. FAIR VALUE MEASUREMENTS

We categorize our financial assets and liabilities using the three-tier hierarchy as follows.

Recurring

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

 

     March 31, 2013     December 31, 2012  
     Level 1     Level 2     Level 1     Level 2  

Financial assets:

        

Physical fixed price derivative contracts

   $ —       $ 1,343     $ —       $ 1,154  

Physical index derivative contracts

     —         854       —         565  

Financial liabilities:

        

Physical fixed price derivative contracts

     —         (1,155     —         (2,042

Physical index derivative contracts

     —         (330     —         (546

Futures contracts for refined products

     (9,442     —         (7,570     —    

Interest rate derivatives

     —         (122,017     —         (130,636
  

 

 

   

 

 

   

 

 

   

 

 

 

Fair value

   $ (9,442   $ (121,305   $ (7,570   $ (131,505
  

 

 

   

 

 

   

 

 

   

 

 

 

The values of the Level 1 derivative assets and liabilities were based on quoted market prices obtained from the New York Mercantile Exchange.

 

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

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

The values of the Level 2 derivative contracts were calculated using market approaches based on observable market data inputs, including published commodity pricing data, which is verified against other available market data, and market interest rate and volatility data. Level 2 fixed price derivative assets are net of credit value adjustments (“CVAs”) determined using an expected cash flow model, which incorporates assumptions about the credit risk of the derivative contracts based on the historical and expected payment history of each customer, the amount of product contracted for under the agreement and the customer’s historical and expected purchase performance under each contract. The Energy Services segment determined CVAs are appropriate because few of the Energy Services segment’s customers entering into these derivative contracts are large organizations with nationally-recognized credit ratings. The Level 2 fixed price derivative assets of $1.3 million and $1.2 million as of March 31, 2013 and December 31, 2012, respectively, are net of CVA of ($0.1) million for both periods, respectively. As of March 31, 2013, the Energy Services segment did not hold any net liability derivative position containing credit contingent features.

Financial instruments included in current assets and current liabilities are reported in the unaudited condensed consolidated balance sheets at amounts which approximate fair value due to the relatively short period to maturity of these financial instruments. The fair values of our fixed-rate debt were estimated by observing market trading prices and by comparing the historic market prices of our publicly issued debt with the market prices of the publicly-issued debt of other master limited partnerships with similar credit ratings and terms. The fair values of our variable-rate debt are their carrying amounts, as the carrying amount reasonably approximates fair value due to the variability of the interest rates. The carrying value and fair value, using Level 2 input values, of our debt were as follows at the dates indicated (in thousands):

 

     March 31, 2013      December 31, 2012  
     Carrying
Amount
     Fair Value      Carrying
Amount
     Fair Value  

Fixed-rate debt

   $ 2,070,412      $ 2,245,415      $ 2,070,244      $ 2,203,662  

Variable-rate debt

     509,900        509,900        871,200        871,200  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total debt

   $ 2,580,312      $ 2,755,315      $ 2,941,444      $ 3,074,862  
  

 

 

    

 

 

    

 

 

    

 

 

 

We recognize transfers between levels within the fair value hierarchy as of the beginning of the reporting period. We did not have any transfers between Level 1 and Level 2 during the three months ended March 31, 2013 and 2012, respectively.

Non-Recurring

Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments in certain circumstances, such as when there is evidence of impairment. For the three months ended March 31, 2013 and 2012, there were no fair value adjustments related to such assets or liabilities reflected in our unaudited condensed consolidated financial statements.

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

10. PENSIONS AND OTHER POSTRETIREMENT BENEFITS

Buckeye Pipe Line Services Company (“Services Company”), which employs the majority of our workforce, sponsors a defined benefit plan, the Retirement Income Guarantee Plan (the “RIGP”), and an unfunded post-retirement benefit plan (the “Retiree Medical Plan”). The components of the net periodic benefit cost for the RIGP and Retiree Medical Plan were as follows for the periods indicated (in thousands):

 

     RIGP     Retiree Medical Plan  
     Three Months Ended     Three Months Ended  
     March 31,     March 31,  
     2013     2012     2013     2012  

Service cost

   $ 67     $ 71     $ 86     $ 76  

Interest cost

     227       207       493       482  

Expected return on plan assets

     (124     (87     —         —    

Amortization of prior service cost

     —         —         (750     (741

Amortization of unrecognized losses

     377       454       346       311  

Actuarial loss due to settlements

     341       —         —         —    
  

 

 

   

 

 

   

 

 

   

 

 

 

Net periodic benefit cost

   $ 888     $ 645     $ 175     $ 128  
  

 

 

   

 

 

   

 

 

   

 

 

 

During the three months ended March 31, 2013, we contributed approximately $0.3 million in aggregate to the RIGP and Retiree Medical Plan.

11. UNIT-BASED COMPENSATION PLANS

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 $3.3 million and $2.6 million for the three months ended March 31, 2013 and 2012, respectively. These compensation plans are discussed below.

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 March 31, 2013, awards representing a total of 195,525 additional LP Units could be issued under the LTIP.

At December 31, 2012 and 2011, actual compensation awards deferred were $1.4 million and $0.7 million, for which 51,668 and 23,426 phantom units (including matching units) were granted during the first quarter of 2013 and the year ended 2012, respectively. These grants are included as granted in the LTIP activity table below.

Awards under the LTIP

During the three months ended March 31, 2013, the Compensation Committee granted 170,769 phantom units to employees (including the 51,668 phantom units granted as discussed above), 14,000 phantom units to independent directors of Buckeye GP and 166,089 performance units to employees.

 

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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 (in thousands, except per unit amounts):

 

           Weighted  
           Average  
           Grant Date  
     Number of     Fair Value  
     LP Units     per LP Unit  

Unvested at January 1, 2013

     745     $ 62.08  

Granted

     388       52.93  

Vested

     (213     56.74  

Forfeited

     (31     60.43  
  

 

 

   

Unvested at March 31, 2013

     889     $ 59.44  
  

 

 

   

At March 31, 2013, approximately $31.4 million of compensation expense related to the LTIP is expected to be recognized over a weighted average period of approximately 2.1 years.

Unit Option and Distribution Equivalent Plan

The following is a summary of the changes in the options outstanding (all of which are vested) under the Option Plan for the periods indicated (in thousands, except per unit amounts):

 

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

Outstanding at January 1, 2013

     74     $ 47.19        3.3      $ 35  
       

 

 

    

 

 

 

Exercised

     (1     38.12        
  

 

 

         

Outstanding at March 31, 2013

     73       47.31        3.1      $ 1,005  
  

 

 

      

 

 

    

 

 

 

Exercisable at March 31, 2013

     73     $ 47.31        3.1      $ 1,005  
  

 

 

      

 

 

    

 

 

 

 

(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 March 2013 and the exercise price, multiplied by the number of exercisable, in-the-money options.

The total intrinsic value of options exercised was minimal and $0.3 million during the three months ended March 31, 2013 and 2012, respectively.

12. PARTNERS’ CAPITAL AND DISTRIBUTIONS

In January 2013, we completed a public offering of 6.0 million LP Units pursuant to an effective shelf registration statement, which priced at $52.54 per unit. The underwriters also exercised an option to purchase 0.9 million additional LP Units, resulting in total gross proceeds of approximately $362.5 million before deducting underwriting fees and estimated offering expenses. We used the net proceeds from this offering to reduce the indebtedness outstanding under our 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 summary of changes in units outstanding for the periods indicated (in thousands):

 

     Limited      Class B         
     Partners      Units      Total  

Units outstanding at January 1, 2013

     90,371        7,975        98,346  

LP Units issued pursuant to the Option Plan (1)

     —          —          —    

LP Units issued pursuant to the LTIP (1)

     147        —          147  

Issuance of units to institutional investors

     6,900        —          6,900  

Issuance of Class B Units in lieu of quarterly cash distributions

     —          186        186  
  

 

 

    

 

 

    

 

 

 
     97,418        8,161        105,579  
  

 

 

    

 

 

    

 

 

 

 

(1) The number of units issued represents issuance net of tax withholding.

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. Actual cash distributions on our LP Units totaled $101.5 million and $94.1 million during the three months ended March 31, 2013 and 2012, respectively. We also paid distributions in-kind to our Class B unitholders by issuing 186,193 Class B Units during the three months ended March 31, 2013.

On May 3, 2013, we announced a quarterly distribution of $1.05 per LP Unit that will be paid on May 31, 2013, to LP unitholders of record on May 16, 2013. Based on the LP Units outstanding as of March 31, 2013, cash distributed to LP unitholders on May 31, 2013 will total approximately $102.7 million. Based on Class B Units outstanding as of March 31, 2013, we also expect to issue approximately 166,000 Class B Units in lieu of cash distributions on May 31, 2013, to Class B unitholders of record on May 16, 2013. 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, which is expected to occur in the second half of 2013, or (b) the third anniversary of the issuance of the Class B units.

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

13. EARNINGS PER UNIT

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

 

     Three Months Ended  
     March 31,  
     2013      2012  

Net income attributable to Buckeye Partners, L.P.

   $ 89,341      $ 51,959  

Basic:

     

Weighted average units outstanding - basic

     103,247        95,229  
  

 

 

    

 

 

 

Earnings per unit - basic

   $ 0.87      $ 0.55  
  

 

 

    

 

 

 

Diluted:

     

Weighted average units outstanding - basic

     103,247        95,229  

Dilutive effect of LP Unit options and LTIP awards granted

     324        329  
  

 

 

    

 

 

 

Weighted average units outstanding - diluted

     103,571        95,558  
  

 

 

    

 

 

 

Earnings per unit - diluted

   $ 0.86      $ 0.54  
  

 

 

    

 

 

 

14. BUSINESS SEGMENTS

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

Pipelines & Terminals

The Pipelines & Terminals segment receives refined petroleum products from refineries, connecting pipelines, and bulk and marine terminals, transports those products to other locations for a fee and provides bulk storage and terminal throughput services in the continental United States for refined petroleum products and other hydrocarbons. This segment owns and operates pipeline systems and refined petroleum products terminals in the continental United States. In addition, the segment provides crude oil services, including train off-loading, storage and throughput.

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 Grand Bahama Island in The Bahamas. Beginning in late 2012, the segment began to provide fuel oil supply and distribution services to third parties in the Caribbean.

Natural Gas Storage

The Natural Gas Storage segment provides natural gas storage services at a natural gas storage facility in Northern California. The facility is connected to Pacific Gas and Electric’s intrastate natural gas pipelines that service natural gas demand in the San Francisco and Sacramento, California areas. The Natural Gas Storage segment does not trade or market natural gas.

Energy Services

The Energy Services segment is a wholesale distributor of refined petroleum products in the Northeastern and Midwestern United States. This segment recognizes revenues when products are delivered. The segment’s products

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

include gasoline, propane, ethanol, biodiesel and petroleum distillates such as heating oil, diesel fuel and kerosene. 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 consists primarily of our contract operations of third-party pipelines, which are owned principally by major oil and gas, petrochemical and chemical companies and are located primarily in Texas and Louisiana. This segment also performs pipeline construction management services, typically for cost plus a fixed fee, for these same customers. Additionally, the Development & Logistics segment includes our ownership and operation of two underground propane storage caverns in Indiana and Illinois and an ammonia pipeline, as well as our majority ownership of the Sabina Pipeline, located in Texas.

Adjusted EBITDA

Adjusted EBITDA is the primary measure used by our senior management, including our Chief Executive Officer, to: (i) evaluate our consolidated operating performance and the operating performance of our business segments; (ii) allocate resources and capital to business segments; (iii) evaluate the viability of proposed projects; and (iv) determine overall rates of return on alternative investment opportunities. Adjusted EBITDA eliminates: (i) non-cash expenses, including but not limited to depreciation and amortization expense resulting from the significant capital investments we make in our businesses and from intangible assets recognized in business combinations; (ii) charges for obligations expected to be settled with the issuance of equity instruments; and (iii) items that are not indicative of our core operating performance results and business outlook.

We believe that investors benefit from having access to the same financial measures that we use and that these measures are useful to investors because they aid in comparing our operating performance with that of other companies with similar operations. The Adjusted EBITDA data presented by us may not be comparable to similarly titled measures at other companies because these items may be defined differently by other companies.

Each segment uses the same accounting policies as those used in the preparation of our audited condensed 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 continental United States, except for our terminals located in Puerto Rico and The Bahamas.

The following tables summarize our financial information by each segment for the periods indicated (in thousands):

 

     Three Months Ended  
     March 31,  
     2013     2012  

Revenue:

    

Pipelines & Terminals

   $ 194,200     $ 165,928  

International Operations (1)

     170,850       50,235  

Natural Gas Storage

     13,883       10,211  

Energy Services

     961,819       1,030,426  

Development & Logistics

     11,912       12,465  

Intersegment

     (7,703     (9,826
  

 

 

   

 

 

 

Total revenue

   $ 1,344,961     $ 1,259,439  
  

 

 

   

 

 

 

 

(1) The International Operations segment’s revenue generated in The Bahamas was $52.7 million and $46.1 million for the three months ended March 31, 2013 and 2012, respectively. The remainder relates primarily to the fuel oil supply and distribution services in the Caribbean.

 

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BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

For the three months ended March 31, 2013 and 2012, no customer contributed 10% or more of consolidated revenue.

The following tables present Adjusted EBITDA by segment and on a consolidated basis and a reconciliation of net income to Adjusted EBITDA for the periods indicated (in thousands):

 

     Three Months Ended  
     March 31,  
     2013     2012  

Adjusted EBITDA:

    

Pipelines & Terminals

   $ 115,544     $ 88,232  

International Operations

     35,243       31,666  

Natural Gas Storage

     (1,827     (1,268

Energy Services

     7,191       (6,172

Development & Logistics

     2,698       2,529  
  

 

 

   

 

 

 

Total Adjusted EBITDA

   $ 158,849     $ 114,987  
  

 

 

   

 

 

 

Reconciliation of Net Income to Adjusted EBITDA:

    

Net income

   $ 90,499     $ 53,467  

Less: Net income attributable to noncontrolling interests

     (1,158     (1,508
  

 

 

   

 

 

 

Net income attributable to Buckeye Partners, L.P.

     89,341       51,959  

Add:  Interest and debt expense

     30,249       28,810  

Income tax expense

     131       337  

Depreciation and amortization

     37,591       33,027  

Non-cash deferred lease expense

     942       975  

Non-cash unit-based compensation expense

     3,343       2,627  

Less: Amortization of unfavorable storage contracts (1)

     (2,748     (2,748
  

 

 

   

 

 

 

Adjusted EBITDA

   $ 158,849     $ 114,987  
  

 

 

   

 

 

 

 

(1) Represents amortization of negative fair values allocated to certain 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

 

15. SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flows and non-cash transactions were as follows for the periods indicated (in thousands):

 

     Three Months Ended  
     March 31,  
     2013     2012  

Cash paid for interest (net of capitalized interest)

   $ 48,987     $ 48,045  

Cash paid for income taxes

     172       2,302  

Capitalized interest

     1,527       2,041  

Non-cash investing activities:

    

Increase (decrease) in accounts payable and accrued and other current liabilities related to capital expenditures

   $ (5,621   $ (4,144

Non-cash financing activities:

    

Issuance of Class B Units in lieu of quarterly cash distribution

   $ 8,274     $ 7,579  

 

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Cautionary Note Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q (this “Report”) contains various forward-looking statements and information that are based on our beliefs, as well as assumptions made by us and information currently available to us. When used in this Report, words such as “proposed,” “anticipate,” “project,” “potential,” “could,” “should,” “continue,” “estimate,” “expect,” “may,” “believe,” “will,” “plan,” “seek,” “outlook” and similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements. Although we believe that such expectations reflected in such forward-looking statements are reasonable, we cannot give any assurances that such expectations will prove to be correct. Such statements are subject to a variety of risks, uncertainties and assumptions as described in more detail in Part I “Item 1A, Risk Factors” included in our Annual Report on Form 10-K for the year ended December 31, 2012. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Although the expectations in the forward-looking statements are based on our current beliefs and expectations, caution should be taken not to place undue reliance on any such forward-looking statements because such statements speak only as of the date hereof. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason.

The following information should be read in conjunction with our unaudited condensed consolidated financial statements and accompanying notes included in this Report.

Overview of Business

Buckeye Partners, L.P. is a publicly traded Delaware master limited partnership and its limited partnership units representing limited partner interests (“LP Units”) are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “BPL.” Buckeye GP LLC (“Buckeye GP”) is our general partner. As used in this Report, unless otherwise indicated, “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 6,000 miles of pipeline and over 100 active products terminals that provide aggregate storage capacity of approximately 70 million barrels. We also operate and/or maintain third-party pipelines under agreements with major oil and gas, petrochemical and chemical companies, and perform certain engineering and construction management services for third parties. We also own and operate a natural gas storage facility in Northern California, and are a wholesale distributor of refined petroleum products in the United States in areas also served by our pipelines and terminals, as well as in the Caribbean. Beginning in late 2012, we began to provide fuel oil supply and distribution services to third parties in the Caribbean. Our flagship marine terminal in The Bahamas, Bahamas Oil Refining Company International Limited (“BORCO”), is one of the largest marine crude oil and petroleum products storage facilities in the world, serving the international markets as a global logistics hub.

Our primary business objective is to provide stable and sustainable cash distributions to our LP unitholders, while maintaining a relatively low investment risk profile. The key elements of our strategy are to: (i) maximize utilization of our assets at the lowest cost per unit; (ii) maintain stable long-term customer relationships; (iii) operate in a safe and environmentally responsible manner; (iv) optimize, expand and diversify our portfolio of energy assets; and (v) maintain a solid, conservative financial position and our investment-grade credit rating.

 

 

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Recent Development

Equity Offering

In January 2013, we completed a public offering of 6.0 million LP Units pursuant to an effective shelf registration statement, which priced at $52.54 per unit. The underwriters also exercised an option to purchase 0.9 million additional LP Units, resulting in total gross proceeds of approximately $362.5 million before deducting underwriting fees and estimated offering expenses. We used the net proceeds from this offering to reduce the indebtedness outstanding under our Revolving Credit Agreement dated September 26, 2011 (the “Credit Facility”) with SunTrust Bank.

Overview of Operating Results

Net income attributable to our unitholders was $89.3 million for the three months ended March 31, 2013, which was an increase of $37.4 million, or 71.9% from $52.0 million for the corresponding period in 2012. Operating income was $119.1 million for the three months ended March 31, 2013, which is an increase of $38.4 million, or 47.6% from $80.7 million for the corresponding period in 2012. Our first quarter results includes year-over-year improvement in our Pipelines & Terminals, International Operations, Energy Services and Development and Logistics segments, while our Natural Gas Storage segment experienced challenges associated with a decline in storage rates compared to the first quarter of 2012.

The increase in net income attributable to our unitholders was primarily the result of increased revenue in our Pipelines & Terminals segment, as well as increased contribution from our Energy Services segment. Throughput volumes for 2013 at terminals increased over the prior year as recent growth capital projects became operational in the latter half of 2012, including our propylene and storage project at our Chicago complex and transformation of our Albany terminal to add the ability to provide crude-handling services. This represents further product diversification for Buckeye as we were able to leverage our existing assets to provide a broader array of services to our customers. Additionally, our Energy Services segment benefitted from improved rack margins, largely the result of renewable identification number (“RIN”) sales. Our Energy Services segment generates RINs through its ethanol blending and bio-blended diesel activities. The market for RINs, which are legislatively required to be purchased by refiners, experienced a substantial increase in value during the quarter. Furthermore, we continued to benefit from the execution of our risk mitigation strategy, which included focusing on fewer, more strategic locations in which to transact business, better managing our inventories and reducing the cost structure of the business. Sales volumes declined as a result of our continued execution of this risk mitigation strategy.

 

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Results of Operations

Consolidated Summary

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

 

     Three Months Ended
March 31,
 
     2013     2012  

Revenue

   $ 1,344,961     $ 1,259,439  

Costs and expenses

     1,225,812       1,178,705  
  

 

 

   

 

 

 

Operating income

     119,149       80,734  

Other expense, net

     (28,519     (26,930
  

 

 

   

 

 

 

Income before taxes

     90,630       53,804  

Income tax expense

     (131     (337
  

 

 

   

 

 

 

Net income

     90,499       53,467  

Less: Net income attributable to noncontrolling interests

     (1,158     (1,508
  

 

 

   

 

 

 

Net income attributable to Buckeye Partners, L.P.

   $ 89,341     $ 51,959  
  

 

 

   

 

 

 

Earnings per unit-diluted

   $ 0.86     $ 0.54  
  

 

 

   

 

 

 

Non-GAAP Financial Measures

Adjusted EBITDA is the primary measure used by our senior management, including our Chief Executive Officer, to: (i) evaluate our consolidated operating performance and the operating performance of our business segments; (ii) allocate resources and capital to business segments; (iii) evaluate the viability of proposed projects; and (iv) determine overall rates of return on alternative investment opportunities. Distributable cash flow is another measure used by our senior management to provide a clearer picture of cash available for distribution to its unitholders. Adjusted EBITDA and distributable cash flow eliminate: (i) non-cash expenses, including but not limited to, depreciation and amortization expense resulting from the significant capital investments we make in our businesses and from intangible assets recognized in business combinations; (ii) charges for obligations expected to be settled with the issuance of equity instruments; and (iii) items that are not indicative of our core operating performance results and business outlook.

We believe that investors benefit from having access to the same financial measures that we use and that these measures are useful to investors because they aid in comparing our operating performance with that of other companies with similar operations. The Adjusted EBITDA and distributable cash flow data presented by us may not be comparable to similarly titled measures at other companies because these items may be defined differently by other companies.

 

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The following table presents Adjusted EBITDA by segment and on a consolidated basis, distributable cash flow and a reconciliation of net income, which is the most comparable GAAP financial measure, to Adjusted EBITDA and distributable cash flow for the periods indicated (in thousands):

 

     Three Months Ended
March 31,
 
     2013     2012  

Adjusted EBITDA:

    

Pipelines & Terminals

   $ 115,544     $ 88,232  

International Operations

     35,243       31,666  

Natural Gas Storage

     (1,827     (1,268

Energy Services

     7,191       (6,172

Development & Logistics

     2,698       2,529  
  

 

 

   

 

 

 

Total Adjusted EBITDA

   $ 158,849     $ 114,987  
  

 

 

   

 

 

 

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

    

Net income

   $ 90,499     $ 53,467  

Less: Net income attributable to noncontrolling interests

     (1,158     (1,508
  

 

 

   

 

 

 

Net income attributable to Buckeye Partners, L.P.

     89,341       51,959  

Add: Interest and debt expense

     30,249       28,810  

Income tax expense

     131       337  

Depreciation and amortization

     37,591       33,027  

Non-cash deferred lease expense

     942       975  

Non-cash unit-based compensation expense

     3,343       2,627  

Less: Amortization of unfavorable storage contracts (1)

     (2,748     (2,748
  

 

 

   

 

 

 

Adjusted EBITDA

     158,849       114,987  
  

 

 

   

 

 

 

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

     (29,382     (27,917

Income tax expense, excluding non-cash taxes

     (131     (337

Maintenance capital expenditures

     (5,133     (13,110
  

 

 

   

 

 

 

Distributable cash flow

   $ 124,203     $ 73,623  
  

 

 

   

 

 

 

 

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

 

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The following table presents product volumes and average tariff rates for the Pipelines & Terminals segment in barrels per day (“bpd”) and total volumes sold in gallons for the Energy Services segment for the periods indicated:

 

     Three Months Ended
March 31,
 
     2013      2012  

Pipelines & Terminals (average bpd in thousands):

     

Pipelines:

     

Gasoline

     681.0        662.7  

Jet fuel

     321.3        332.5  

Middle distillates (1)

     368.8        337.4  

Other products (2)

     29.3        23.0  
  

 

 

    

 

 

 

Total pipelines throughput

     1,400.4        1,355.6  
  

 

 

    

 

 

 

Terminals:

     

Products throughput

     953.9        877.2  
  

 

 

    

 

 

 

Pipeline Average Tariff (cents/ bbl)

     78.9        79.4  
  

 

 

    

 

 

 

Energy Services (in millions of gallons):

     

Sales volumes

     312.0        344.8  
  

 

 

    

 

 

 

 

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

Three Months Ended March 31, 2013 Compared to Three Months Ended March 31, 2012

Consolidated

Adjusted EBITDA was $158.8 million for the three months ended March 31, 2013, which is an increase of $43.8 million, or 38.1%, from $115.0 million for the corresponding period in 2012. The increase in Adjusted EBITDA was primarily related to positive contributions from growth capital spending and higher blending capabilities, particularly butane blending, in the Pipelines & Terminals segment, as well as increased storage capacity and customer utilization of our BORCO facility in the International Operations segment. In addition, our Energy Services segment benefitted from increased earnings as a result of higher margins and lower operating costs. The higher margins were primarily the result of the sale of RINs, which are tradable “credits” that we generate by blending biofuels into finished gasoline or diesel products.

Revenue was $1,345.0 million for the three months ended March 31, 2013, which is an increase of $85.6 million, or 6.8%, from $1,259.4 million for the corresponding period in 2012. The increase in revenue was primarily related to increased pipeline and terminalling volumes directly attributable to our growth capital spending and higher blending capabilities, as well as favorable settlement experience in the Pipelines & Terminals segment. In addition, revenue in our International Operations segment increased as a result of incremental storage capacity brought online in the second half of 2012 and early 2013, as well as new service offerings providing fuel oil supply and distribution services in the International Operations segment. These increases in revenue were offset by lower product sales volume in our Energy Services segment.

Operating income was $119.1 million for the three months ended March 31, 2013, which is an increase of $38.4 million, or 47.6%, of $80.7 million for the corresponding period in 2012. The increase in operating income was primarily related to increased pipeline and terminalling volumes directly attributable to our growth capital spending and diversification initiatives in the Pipelines & Terminals segment and increased contribution from our Energy Services segment as a result of higher margins and lower operating costs.

 

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Distributable cash flow was $124.2 million for the three months ended March 31, 2013, which is an increase of $50.6 million, or 68.7%, from $73.6 million as compared to the corresponding period in 2012. The increase in distributable cash flow was primarily related to an increase of $43.8 million in Adjusted EBITDA as described above and an $8.0 million decrease in maintenance capital expenditures relating to the timing of pipeline and tank integrity work performed in the Pipelines & Terminals segment, as well as tank integrity work performed in the International Operations segment.

Adjusted EBITDA by Segment

Pipelines & Terminals. Adjusted EBITDA from the Pipelines & Terminals segment was $115.5 million for the three months ended March 31, 2013, which is an increase of $27.3 million, or 31.0%, from $88.2 million for the corresponding period in 2012. The positive factors impacting Adjusted EBITDA were primarily related to $10.8 million of incremental revenue from capital investments in internal growth and diversification initiatives, including expanded butane blending capabilities, crude-handling services, as well as storage and throughput of other hydrocarbons, $8.3 million of favorable settlement experience, a $5.6 million increase in revenue due to higher pipeline and terminalling volumes, a $4.6 million increase in revenue resulting from the Perth Amboy Facility acquired in July 2012, a $2.3 million decrease in outside services, pursuant to the integration of assets acquired in 2011, a $0.6 million increase in other revenue, resulting from an increase in terminalling storage contracts and a $0.4 million increase in earnings due to the purchase of an additional 20% ownership interest in WesPac Pipelines – Memphis LLC in the second half of 2012, which increased our ownership interest from 50% to 70%.

The negative factors impacting Adjusted EBITDA were a $2.4 million increase in operating expenses from the Perth Amboy Facility acquired in the second half of 2012, a $1.6 million decrease in revenue due to lower average pipeline tariff rates and shorter-haul shipments, $1.0 million in fees related to the legal proceedings before the Federal Energy Regulatory Commission (“FERC”) and a $0.3 million decrease in earnings from equity investments primarily due to higher environmental remediation costs.

Pipeline volumes increased by 3.3% due to stronger gasoline and middle distillates, demand resulting from changes in regional production and supply, as well as higher heating oil shipments due to cooler temperatures when compared to the corresponding period in 2012. Terminalling volumes increased by 8.7% due to higher demand for gasoline and distillates resulting from new customer contracts and service offerings at select locations, effective commercialization of acquired assets and continued positive contribution from our recently completed internal growth projects.

International Operations. Adjusted EBITDA from the International Operations segment was $35.2 million for the three months ended March 31, 2013, which is an increase of $3.5 million, or 11.3%, from $31.7 million for the corresponding period in 2012. The positive factors impacting Adjusted EBITDA were primarily related to a $4.6 million increase in storage revenue as a result of incremental storage capacity brought online and a $1.6 million increase in ancillary revenues, including berthing of ships at our jetties, and heating services due to increased customer utilization of our facilities.

The increase in revenue was offset by a loss of $1.0 million ($114.3 million in revenue and $115.3 million in cost of product sales) related to new service offerings providing fuel oil supply and distribution services in the Caribbean, which included product downgrade and start-up costs, and a $1.7 million increase in operating expenses primarily as a result of increased costs necessary to operate the expanded capabilities of the BORCO facility.

Natural Gas Storage. Adjusted EBITDA from the Natural Gas Storage segment was a loss of $1.8 million for the three months ended March 31, 2013, which is $0.5 million, or 44.1%, less favorable than a loss of $1.3 million for the corresponding period in 2012. The decrease in Adjusted EBITDA was primarily the result of a $4.3 million increase in costs of natural gas storage services, which includes increased costs for hub services activities related to opportunities to optimize the asset in future periods, partially offset by a $2.4 million increase in revenue for hub service activities from optimization strategies, a $1.3 million increase in storage revenue and a $0.1 million decrease in operating expenses which primarily related to lower property taxes. Storage revenue and hub services revenue are affected by the difference in natural gas commodity prices for the periods in which natural gas is injected and withdrawn from the storage facility (i.e., time spread).

 

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Energy Services. Adjusted EBITDA from the Energy Services segment was $7.2 million for the three months ended March 31, 2013, which is an improvement of $13.4 million, or 216.5%, from a loss of $6.2 million for the corresponding period in 2012. The positive factors impacting Adjusted EBITDA were primarily related to improved cooler weather conditions in the Northeast driving distillate demand and higher margins on the sale of RINs, which are tradable “credits” generated by blending biofuels into finished gasoline or diesel products.

The increase in Adjusted EBITDA was primarily related to a $80.3 million decrease in cost of product sales, which included a $98.3 million decrease due to 9.5% less volumes sold, offset by a $18.0 million increase in refined petroleum product cost due to a price increase of approximately $0.06 per gallon (average cost prices per gallon were $3.05 and $2.99 for the 2013 and 2012 periods, respectively) and a $1.7 million decrease in operating expenses, which primarily related to overhead costs.

The decrease in cost of product sales was partially offset by a $68.6 million decrease in revenue, which included a $98.1 million decrease due to 9.5% less volumes sold, offset by a $29.5 million increase in refined petroleum product sales due to a price increase of approximately $0.09 per gallon (average sales price per gallon were $3.08 and $2.99 for the 2013 and 2012 periods, respectively).

Development & Logistics. Adjusted EBITDA from the Development & Logistics segment was $2.7 million for the three months ended March 31, 2013, which is an increase of $0.2 million, or 6.7%, from $2.5 million for the corresponding period in 2012. The increase in Adjusted EBITDA was primarily due to a $0.3 million increase in storage and throughput revenue related to the LPG storage caverns, partially offset by a net $0.1 million increase in operating expenses.

Liquidity and Capital Resources

General

Our primary cash requirements, in addition to normal operating expenses and debt service, are for working capital, capital expenditures, business acquisitions and distributions to partners. Our principal sources of liquidity are cash from operations, borrowings under our Credit Facility and proceeds from the issuance of our units. We will, from time to time, issue debt securities to permanently finance amounts borrowed under our Credit Facility. Buckeye Energy Services LLC (“BES”) funds its working capital needs principally from its operations and its portion of our Credit Facility. Our financial policy has been to fund maintenance capital expenditures with cash from operations. Expansion and cost reduction capital expenditures, along with acquisitions, have typically been funded from external sources including our Credit Facility as well as debt and equity offerings. Our goal has been to fund at least half of these expenditures with proceeds from equity offerings in order to maintain our investment-grade credit rating. Based on current market conditions, we believe our borrowing capacity under our Credit Facility, cash flows from operations and access to debt and equity markets, if necessary, will be sufficient to fund our primary cash requirements, including our expansion plans over the next 12 months.

Current Liquidity

As of March 31, 2013, we had $71.9 million of working capital and $740.1 million of additional borrowing capacity under our Credit Facility.

Capital Structuring Transactions

As part of our ongoing efforts to maintain a capital structure that is closely aligned with the cash-generating potential of our asset-based business, we may explore additional sources of external liquidity, including public or private debt or equity issuances. Matters to be considered will include cash interest expense and maturity profile, all to be balanced with maintaining adequate liquidity. We have a universal shelf registration statement that does not place any dollar limits on the amount of debt and equity securities that we may issue thereunder and a traditional shelf registration statement on file with the SEC that currently has a $750.0 million limit on the amount of equity

 

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securities that we may issue thereunder. The timing of any transaction may be impacted by events, such as strategic growth opportunities, legal judgments or regulatory or environmental requirements. The receptiveness of the capital markets to an offering of debt or equity securities cannot be assured and may be negatively impacted by, among other things, our long-term business prospects and other factors beyond our control, including market conditions.

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

Capital Allocation

We continually review our investment options with respect to our capital resources that are not distributed to our unitholders or used to pay down our debt and seek to invest these capital resources in various projects and activities based on their return to Buckeye. Potential investments could include, among others: add-on or other enhancement projects associated with our current assets; greenfield or brownfield development projects; and merger and acquisition activities.

Debt

The $300.0 million of 4.625% Notes maturing on July 15, 2013 has been classified as long-term debt under the assumption that our Credit Facility could be used to refinance this debt, if required. At March 31, 2013, we had $740.1 million of additional borrowing capacity availability under our Credit Facility. It is our intent to refinance our 4.625% Notes in 2013. Additionally, we expect to pay approximately $68.9 million to settle interest rate swaps relating to the refinancing of the 4.625% Notes on or before July 15, 2013.

At March 31, 2013, we had total fixed-rate and variable-rate debt obligations of $2,070.4 million and $509.9 million, respectively, with an aggregate fair value of $2,755.3 million. At March 31, 2013, we were not aware of any instances of noncompliance with the covenants under our Credit Facility.

Equity

In January 2013, we completed a public offering of 6.0 million LP Units pursuant to an effective shelf registration statement, which priced at $52.54 per unit. The underwriters also exercised an option to purchase 0.9 million additional LP Units, resulting in total gross proceeds of approximately $362.5 million before deducting underwriting fees and estimated offering expenses. We used the net proceeds from this offering to reduce the indebtedness outstanding under our Credit Facility.

Cash Flows from Operating, Investing and Financing Activities

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

 

     Three Months Ended
March 31,
 
     2013     2012  

Cash provided by (used in):

    

Operating activities

   $ 182,417     $ 181,601  

Investing activities

     (66,828     (87,996

Financing activities

     (117,801     (91,532
  

 

 

   

 

 

 

Net (decrease) increase in cash and cash equivalents

   $ (2,212   $ 2,073  
  

 

 

   

 

 

 

 

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Operating Activities

Net cash provided by operating activities of $182.4 million for the three months ended March 31, 2013, primarily related to $90.5 million of net income, $66.3 million associated with a favorable change in inventory and $37.6 million of depreciation and amortization. Net cash provided by operating activities of $181.6 million for the three months ended March 31, 2012, primarily related to $110.9 million associated with a favorable change in inventory, $53.5 million of net income and $33.0 million of depreciation and amortization. In 2012, we developed and executed a strategy to mitigate our basis risk that included the reduction of refined petroleum product inventories in the Midwest. In 2013, we continue to effectively manage our exposure to basis risk through reduction of inventory.

Future Operating Cash Flows. Our future operating cash flows will vary based on a number of factors, many of which are beyond our control, including demand for our services, the cost of commodities, the effectiveness of our strategy, legal environmental and regulatory requirements and our ability to capture value associated with commodity price volatility.

Investing Activities

Net cash used in investing activities of $66.8 million for the three months ended March 31, 2013 primarily related to $67.2 million of capital expenditures. Net cash used in investing activities of $88.0 million for the three months ended March 31, 2012, primarily related to $74.3 million of capital expenditures and a $14.0 million deposit for the Perth Amboy Facility acquired in 2012. See below for a discussion of capital spending.

Financing Activities

Net cash used in financing activities of $117.8 million for the three months ended March 31, 2013 primarily related to $361.3 million of net repayments under the Credit Facility and $100.3 million ($1.0375 per LP Unit) of cash distributions paid to our unitholders, partially offset by $349.6 million of net proceeds from the issuance of 6.9 million LP Units to reduce borrowings under our Credit Facility. Net cash used in financing activities of $91.5 million for the three months ended March 31, 2012 primarily related to $243.8 million of net repayments under the Credit Facility and $92.7 million ($1.0375 per LP Unit) of cash distributions paid to our unitholders, partially offset by $247.5 million of net proceeds from the issuance of 4.3 million LP Units to institutional investors in a registered direct offering.

Capital Expenditures

We have capital expenditures, which we define as “maintenance capital expenditures,” in order to maintain and enhance the safety and integrity of our pipelines, terminals, storage facilities and related assets, and “expansion and cost reduction capital expenditures” to expand the reach or capacity of those assets, to improve the efficiency of our operations and to pursue new business opportunities. Capital expenditures, excluding non-cash changes in accruals for capital expenditures, were as follows for the periods indicated (in thousands):

 

     Three Months Ended
March 31,
 
     2013      2012  

Maintenance capital expenditures

   $ 5,133      $ 13,110  

Expansion and cost reduction

     62,053        61,203  
  

 

 

    

 

 

 

Total capital expenditures, net

   $ 67,186      $ 74,313  
  

 

 

    

 

 

 

In the three months ended March 31, 2013, maintenance capital expenditures included pump replacements and truck rack infrastructure upgrades, as well as pipeline and tank integrity work. Expansion and cost reduction capital expenditures included significant investments in storage tank expansion at BORCO and Perth Amboy, butane blending, rail off-loading facilities, and various other cost reduction and revenue generating projects. In the three

 

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months ended March 31, 2012, maintenance capital expenditures included terminal pump replacements and truck rack infrastructure upgrades, as well as pipeline and tank integrity work, and expansion and cost reduction projects included significant investments in storage tank expansion at BORCO, biodiesel and butane blending, rail off-loading facilities, and continued progress on a new pipeline and terminal billing system as well as various other operating infrastructure projects.

We have estimated our capital expenditures as follows for the year ending December 31, 2013 (in thousands):

 

     2013  
     Low      High  

Pipelines & Terminals:

     

Maintenance capital expenditures

   $ 50,000      $ 60,000  

Expansion and cost reduction

     200,000        235,000  
  

 

 

    

 

 

 

Total capital expenditures

   $ 250,000      $ 295,000  
  

 

 

    

 

 

 

International Operations:

     

Maintenance capital expenditures

   $ 10,000      $ 20,000  

Expansion and cost reduction

     80,000        105,000  
  

 

 

    

 

 

 

Total capital expenditures

   $ 90,000      $ 125,000  
  

 

 

    

 

 

 

Overall:

     

Maintenance capital expenditures

   $ 60,000      $ 80,000  

Expansion and cost reduction

     280,000        340,000  
  

 

 

    

 

 

 

Total capital expenditures

   $ 340,000      $ 420,000  
  

 

 

    

 

 

 

Estimated maintenance capital expenditures include renewals and replacement of pipeline sections, tank floors and tank roofs and upgrades to station and terminalling equipment, field instrumentation and cathodic protection systems. Estimated major expansion and cost reduction expenditures include storage tank expansion projects at BORCO and Perth Amboy; completion of additional storage tanks and truck loading rack upgrades; rail offloading facilities and the refurbishment of storage tanks across our system; continued installation of vapor recovery units throughout our system of terminals; additive system installation throughout our terminal infrastructure; and various upgrades and expansions of our butane blending business. In connection with our 2012 Perth Amboy Facility acquisition, our estimated expansion and cost reduction expenditures include: development of a new crude rail offloading system; completion of a bi-directional pipeline; conversion of tanks for distillate and gasoline storage; a new gasoline and diesel truck loading rack installation; construction of a multi-product blend and transfer piping manifold; and construction of a new 16-inch pipeline allowing direct access to our existing pipeline infrastructure. Also, estimated expansion and cost reduction expenditures include costs to repair the damaged jetty at our BORCO facility as a result of the allision of a vessel with our jetty in May 2012. We believe the recovery of the costs to repair the damaged jetty is probable. See Note 3 in the Notes to Unaudited Condensed Consolidated Financial Statements for a more detailed discussion of this incident. Furthermore, cost reduction expenditures improve operational efficiencies or reduce costs.

Off-Balance Sheet Arrangements

There have been no material changes with regard to our off-balance sheet arrangements since our Annual Report on Form 10-K for the year ended December 31, 2012.

 

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Recent Accounting Pronouncements

See Note 1 in the Notes to Unaudited Condensed Consolidated Financial Statements for a description of certain new accounting pronouncements that will or may affect our consolidated financial statements.

 

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following should be read in conjunction with Quantitative and Qualitative Disclosures About Market Risk included under Item 7A in our Annual Report on Form 10-K for the year ended December 31, 2012. There have been no material changes in that information other than as discussed below. Also see Note 8 in the Notes to Unaudited Condensed Consolidated Financial Statements for additional discussion related to derivative instruments and hedging activities.

Market Risk – Non-Trading Instruments

We are exposed to financial market risks, including changes in commodity prices and interest rates. The primary factors affecting our market risk and the fair value of our derivative portfolio at any point in time are the volume of open derivative positions, changing refined petroleum commodity prices, and prevailing interest rates for our interest rate swaps. We are also susceptible to basis risk created when we enter into financial hedges that are priced at a certain location, but the sales or exchanges of the underlying commodity are at another location where prices and price changes might differ from the prices and price changes at the location upon which the hedging instrument is based. Since prices for refined petroleum products and interest rates are volatile, there may be material changes in the fair value of our derivatives over time, driven both by price volatility and the changes in volume of open derivative transactions.

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

 

     Commodity
Instruments
    Interest
Rate Swaps
    Total  

Fair value of contracts outstanding at January 1, 2013

   $ (8,439   $ (130,636   $ (139,075

Items recognized or settled during the period

     (6,199     —         (6,199

Fair value attributable to new deals

     (6,803     —         (6,803

Change in fair value attributable to price movements

     12,704       8,619       21,323  

Change in fair value attributable to non-performance risk

     7       —         7  
  

 

 

   

 

 

   

 

 

 

Fair value of contracts outstanding at March 31, 2013

   $ (8,730   $ (122,017   $ (130,747
  

 

 

   

 

 

   

 

 

 

Commodity Risk

Natural Gas Storage

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

 

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

 

Net Asset at January 1, 2013

   $ 12,048  

Net expenses recognized in period (1)

     (3,203

Net unearned revenue (2)

     (5,015
  

 

 

 

Net Asset at March 31, 2013

   $ 3,830  
  

 

 

 

 

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

Energy Services

Our Energy Services segment primarily uses exchange-traded refined petroleum product futures contracts to manage the risk of market price volatility on its refined petroleum product inventories and its physical derivative contracts. Based on a hypothetical 10% movement in the underlying quoted market prices of the futures contracts and observable market data from third-party pricing publications for physical derivative contracts related to designated hedged refined petroleum products inventories outstanding and physical derivative contracts at March 31, 2013, the estimated fair value would be as follows (in thousands):

 

     Resulting         

Scenario

   Classification      Fair Value  

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

     Asset          $ 152,565  

Fair value assuming 10% increase in underlying commodity prices

     Asset          $ 152,226  

Fair value assuming 10% decrease in underlying commodity prices

     Asset          $ 152,862  

Interest Rate Risk

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

 

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

 

     Resulting         

Scenario

   Classification      Fair Value  

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

     Liability       $ (122,017

Fair value assuming 10% increase in underlying interest rates

     Liability       $ (108,739

Fair value assuming 10% decrease in underlying interest rates

     Liability       $ (135,309

See Note 8 in the Notes to Unaudited Condensed Consolidated Financial Statements for additional discussion related to derivative instruments and hedging activities.

 

Item 4. Controls and Procedures

(a) Evaluation of Disclosure Controls and Procedures.

Our management, with the participation of our Chief Executive Officer (the “CEO”) and Chief Financial Officer (the “CFO”), evaluated the design and effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the CEO and CFO concluded that our disclosure controls and procedures as of the end of the period covered by this report are designed and operating effectively to provide reasonable assurance that the information required to be disclosed by us in reports filed under the Securities Exchange Act of 1934, as amended, is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (ii) accumulated and communicated to management, including the CEO and CFO, as appropriate to allow timely decisions regarding disclosure. A controls system cannot provide absolute assurance, however, that the objectives of the controls system are met, and no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a company have been detected.

(b) Change in Internal Control Over Financial Reporting.

There have been no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) or in other factors during the first quarter of 2013 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

 

 

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PART II. OTHER INFORMATION

 

Item 1. Legal Proceedings

In the ordinary course of business, we are involved in various claims and legal proceedings, some of which are covered by insurance. We are generally unable to predict the timing or outcome of these claims and proceedings. For information on unresolved legal proceedings not otherwise described below, see Part I, Item 1, Financial Statements, Note 3, “Commitments and Contingencies” in the Notes to Unaudited Condensed Consolidated Financial Statements included in this quarterly report, which is incorporated into this item by reference.

In January 2013, the Pipeline Hazardous Materials Safety Administration proposed penalties totaling approximately $0.1 million as a result of alleged violations related to line marker requirements and right-of-way inspection requirements that were raised as a result of an inspection of our facilities in Auburn, NY. We paid the penalties in February 2013.

On December 3, 2012, a complaint was filed in the Circuit Court for Washington County, Wisconsin by Chad Altschafl, et al., as plaintiffs, naming Buckeye, Services Company, Buckeye Pipe Line Holdings, L.P. (“BPH”), BPLC and West Shore Pipe Line Company (“West Shore”), as defendants, which complaint was amended by the plantiffs on April 18, 2013. The complaint in the Altschafl case attempts to allege various emotional distress and property damage claims under Wisconsin law arising out of a release of gasoline from a pipeline owned by West Shore in the Town of Jackson, Wisconsin on July 17, 2012. Owners of 206 properties in the area of Jackson, Wisconsin are the plaintiffs in the case. No dollar amount of damages is stated in the complaint, but the plaintiffs seek damages to reimburse them for, among other things, the costs of restoring their properties and of installing a permanent supply of potable water and the diminution in value of their properties. The plaintiffs also seek punitive damages. On January 21, 2013, we filed an answer to the complaint, denying its claims and asserting affirmative defenses, and a motion to dismiss the claims for emotional distress and for medical monitoring costs. A hearing on the motion is scheduled for June 4, 2013. The case is not presently scheduled for trial. The timing or outcome of final resolution of this matter cannot reasonably be determined at this time. Buckeye, Services Company, BPH and Buckeye Pipe Line are entitled to certain indemnifications by West Shore pursuant to an agreement between Buckeye Pipe Line and West Shore, which we believe would result in West Shore indemnifying us for any losses stemming from this litigation. In addition, West Shore has insurance that we believe should cover such losses, subject to a $3.0 million deductible. West Shore is pursuing that insurance coverage.

 

Item 1A. Risk Factors

Security holders and potential investors in our securities should carefully consider the risk factors set forth in Part I, “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2012. We have identified these risk factors as important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.

 

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Item 6. Exhibits

(a) Exhibits

 

    3.1    Amended and Restated Certificate of Limited Partnership of Buckeye Partners, L.P., dated as of February 4, 1998 (Incorporated by reference to Exhibit 3.2 of Buckeye Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 1997).
    3.2    Certificate of Amendment to Amended and Restated Certificate of Limited Partnership of Buckeye Partners, L.P., dated as of April 26, 2002 (Incorporated by reference to Exhibit 3.2 of Buckeye Partners, L.P.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2002).
    3.3    Certificate of Amendment to Amended and Restated Certificate of Limited Partnership of Buckeye Partners, L.P., dated as of June 1, 2004, effective as of June 3, 2004 (Incorporated by reference to Exhibit 3.3 of the Buckeye Partners, L.P.’s Registration Statement on Form S-3 filed June 16, 2004).
    3.4    Certificate of Amendment to Amended and Restated Certificate of Limited Partnership of Buckeye Partners, L.P., dated as of December 15, 2004 (Incorporated by reference to Exhibit 3.5 of Buckeye Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2004).
    3.5    Amended and Restated Agreement of Limited Partnership of Buckeye Partners, L.P., dated as of November 19, 2010 (Incorporated by reference to Exhibit 3.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed November 22, 2010).
    3.6    Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Buckeye Partners, L.P., dated as of January 18, 2011 (Incorporated by reference to Exhibit 3.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on January 20, 2011).
    3.7    Amendment No. 2 to Amended and Restated Agreement of Limited Partnership of Buckeye Partners, L.P., dated as of February 21, 2013 (Incorporated by reference to Exhibit 3.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on February 25, 2013).
*31.1    Certification of Chief Executive Officer pursuant to Rule 13a-14 (a) under the Securities Exchange Act of 1934.
*31.2    Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
*32.1    Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350.
*32.2    Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350.
*101.INS    XBRL Instance Document.
*101.SCH    XBRL Taxonomy Extension Schema Document.
*101.CAL    XBRL Taxonomy Extension Calculation Linkbase Document.
*101.LAB    XBRL Taxonomy Extension Label Linkbase Document.
*101.PRE    XBRL Taxonomy Extension Presentation Linkbase Document.
*101.DEF    XBRL Taxonomy Extension Definition Linkbase Document.

 

* Filed herewith.

 

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SIGNATURES

Pursuant to the requirements of Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

    BY:  

BUCKEYE PARTNERS, L.P.

(Registrant)

    BY:  

Buckeye GP LLC,

as General Partner

Date: May 7, 2013     By:   /s/ Keith E. St.Clair
      Keith E. St.Clair
     

Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

 

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