e10vq
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
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þ |
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Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the quarterly period ended March 31, 2011
OR
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o |
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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)
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Delaware
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23-2432497 |
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(State or other jurisdiction of
incorporation or organization)
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(IRS Employer
Identification number) |
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One Greenway Plaza |
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Suite 600 |
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Houston, TX
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77046 |
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(Address of principal executive offices)
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(Zip Code) |
Registrants 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 þ No o
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
þ No o
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):
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Large accelerated filer þ
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Accelerated filer o
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Non-accelerated filer o
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Smaller reporting company o |
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(Do not check if a smaller reporting company) |
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Act).
Yes o No þ
Limited partner units and Class B units outstanding as of May 3, 2011: 85,874,501 and
6,915,725, respectively.
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
BUCKEYE PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
(Unaudited)
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Three Months Ended |
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March 31, |
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2011 |
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2010 |
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Revenues: |
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Product sales |
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$ |
1,037,556 |
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$ |
568,170 |
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Transportation and other services |
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214,980 |
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163,004 |
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Total revenue |
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1,252,536 |
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731,174 |
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Costs and expenses: |
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Cost of product sales and natural gas storage services |
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1,037,962 |
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569,737 |
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Operating expenses |
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80,264 |
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66,583 |
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Depreciation and amortization |
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26,241 |
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14,528 |
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General and administrative |
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15,506 |
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10,835 |
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Total costs and expenses |
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1,159,973 |
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661,683 |
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Operating income |
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92,563 |
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69,491 |
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Other income (expense): |
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Earnings from equity investments |
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3,347 |
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2,652 |
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Interest and debt expense |
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(28,497 |
) |
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(21,656 |
) |
Other income |
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400 |
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155 |
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Total other expense |
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(24,750 |
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(18,849 |
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Net income |
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67,813 |
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50,642 |
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Less: net income attributable to noncontrolling interests |
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(1,320 |
) |
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(39,372 |
) |
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Net income attributable to Buckeye Partners, L.P. |
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$ |
66,493 |
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$ |
11,270 |
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Earnings per unit: |
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Basic |
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$ |
0.79 |
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$ |
0.56 |
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Diluted |
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$ |
0.79 |
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$ |
0.56 |
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Weighted average number of units outstanding: |
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Basic |
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83,669 |
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19,952 |
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Diluted |
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83,954 |
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19,952 |
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See Notes to Unaudited Condensed Consolidated Financial Statements.
2
BUCKEYE PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
(Unaudited)
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Three Months Ended |
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March 31, |
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2011 |
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2010 |
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Net income |
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$ |
67,813 |
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$ |
50,642 |
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Other comprehensive income (loss): |
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Change in value of derivatives |
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4,606 |
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Amortization of interest rate swaps |
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241 |
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Gain on settlement of treasury lock, net of amortization |
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489 |
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Amortization of benefit plan costs |
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(110 |
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Total other comprehensive income |
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5,226 |
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Comprehensive income |
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$ |
73,039 |
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$ |
50,642 |
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See Notes to Unaudited Condensed Consolidated Financial Statements.
3
BUCKEYE PARTNERS, L.P.
CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except unit amounts)
(Unaudited)
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March 31, |
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December 31, |
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2011 |
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2010 |
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Assets: |
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Current assets: |
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Cash and cash equivalents |
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$ |
66,430 |
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$ |
13,626 |
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Trade receivables, net |
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170,902 |
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167,274 |
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Construction and pipeline relocation receivables |
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5,426 |
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6,803 |
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Inventories |
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252,831 |
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351,605 |
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Derivative assets |
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1,247 |
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1,634 |
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Prepaid and other current assets |
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81,259 |
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85,689 |
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Total current assets |
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578,095 |
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626,631 |
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Property, plant and equipment, net |
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3,448,122 |
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2,305,884 |
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Equity investments |
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108,602 |
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107,047 |
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Goodwill |
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930,070 |
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432,124 |
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Intangible assets, net |
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247,293 |
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44,067 |
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Other non-current assets |
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61,649 |
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58,463 |
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Total assets |
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$ |
5,373,831 |
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$ |
3,574,216 |
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Liabilities and partners capital: |
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Current liabilities: |
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Line of credit |
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$ |
235,000 |
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$ |
284,300 |
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Current portion of long-term debt |
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1,525 |
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Accounts payable |
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65,402 |
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68,530 |
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Derivative liabilities |
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6,913 |
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17,285 |
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Accrued and other current liabilities |
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153,173 |
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144,880 |
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Total current liabilities |
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460,488 |
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516,520 |
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Long-term debt |
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2,404,071 |
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1,519,393 |
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Other non-current liabilities |
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180,235 |
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128,043 |
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Total liabilities |
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3,044,794 |
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2,163,956 |
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Commitments and contingent liabilities |
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Partners capital: |
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Buckeye Partners, L.P. capital: |
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Limited Partners (80,354,501 and 71,436,099 units outstanding
as of March 31, 2011 and December 31, 2010, respectively) |
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1,929,637 |
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1,413,664 |
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Class B Units (6,915,725 and 0 units outstanding
as of March 31, 2011 and December 31, 2010, respectively) |
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397,469 |
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Accumulated other comprehensive loss |
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(16,033 |
) |
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(21,259 |
) |
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Total Buckeye Partners, L.P. capital |
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2,311,073 |
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1,392,405 |
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Noncontrolling interests |
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17,964 |
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17,855 |
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Total partners capital |
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2,329,037 |
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1,410,260 |
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Total liabilities and partners capital |
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$ |
5,373,831 |
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$ |
3,574,216 |
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See Notes to Unaudited Condensed Consolidated Financial Statements.
4
BUCKEYE PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
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Three Months Ended |
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March 31, |
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2011 |
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2010 |
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Cash flows from operating activities: |
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Net income |
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$ |
67,813 |
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$ |
50,642 |
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Adjustments to reconcile net income to net cash provided by operating activities: |
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Value of ESOP shares released |
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1,183 |
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1,141 |
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Depreciation and amortization |
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26,241 |
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14,528 |
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Net changes in fair value of derivatives |
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(78,611 |
) |
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(19,183 |
) |
Non-cash deferred lease expense |
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1,030 |
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|
1,059 |
|
Amortization of unfavorable storage contracts |
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(1,932 |
) |
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Earnings from equity investments |
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(3,347 |
) |
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(2,652 |
) |
Distributions from equity investments |
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1,793 |
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Amortization of other non-cash items |
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3,134 |
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2,806 |
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Change in assets and liabilities, net of amounts related to acquisitions: |
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Trade receivables |
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6,864 |
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(10,398 |
) |
Construction and pipeline relocation receivables |
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|
1,377 |
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|
2,675 |
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Inventories |
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|
169,679 |
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|
73,705 |
|
Prepaid and other current assets |
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|
7,679 |
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|
26,214 |
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Accounts payable |
|
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(25,349 |
) |
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|
(3,053 |
) |
Accrued and other current liabilities |
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(24,634 |
) |
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|
1,271 |
|
Other non-current assets |
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|
5,107 |
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|
2,948 |
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Other non-current liabilities |
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(1,645 |
) |
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|
2,345 |
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Total adjustments from operating activities |
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88,569 |
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|
93,406 |
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Net cash provided by operating activities |
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|
156,382 |
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|
144,048 |
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Cash flows from investing activities: |
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Capital expenditures |
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(38,033 |
) |
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(10,963 |
) |
Deposit for pending acquisition |
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(22,427 |
) |
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Acquisitions, net of cash acquired |
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(895,255 |
) |
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Net proceeds from disposal of property, plant and equipment |
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42 |
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22,174 |
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Net cash (used in) provided by investing activities |
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(955,673 |
) |
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11,211 |
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Cash flows from financing activities: |
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Net proceeds from issuance of units |
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420,405 |
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Proceeds from exercise of unit options |
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|
270 |
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|
2,376 |
|
Issuance of long-term debt |
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|
647,530 |
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Repayment of long term-debt |
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|
(1,525 |
) |
|
|
(1,557 |
) |
Borrowings under credit facility |
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|
521,500 |
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|
59,500 |
|
Repayments under credit facility |
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|
(284,500 |
) |
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|
(117,500 |
) |
Net repayments under BES credit agreement |
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(49,300 |
) |
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|
(56,300 |
) |
Debt issuance costs |
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(4,919 |
) |
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|
(9 |
) |
Repayment of debt assumed in BORCO acquisition |
|
|
(318,167 |
) |
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Costs associated with agreement and plan of merger |
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|
(344 |
) |
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Distributions paid to noncontrolling partners of Buckeye Partners, L.P. |
|
|
(1,204 |
) |
|
|
(47,586 |
) |
Proceeds from settlement of treasury lock |
|
|
497 |
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|
|
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Distributions paid to partners of Buckeye GP Holdings L.P. |
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(11,603 |
) |
Distributions paid to unitholders |
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|
(78,148 |
) |
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|
|
Net cash provided by (used in) financing activities |
|
|
852,095 |
|
|
|
(172,679 |
) |
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|
|
|
|
|
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Net increase (decrease) in cash and cash equivalents |
|
|
52,804 |
|
|
|
(17,420 |
) |
Cash and cash equivalents Beginning of period |
|
|
13,626 |
|
|
|
37,574 |
|
|
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Cash and cash equivalents End of period |
|
$ |
66,430 |
|
|
$ |
20,154 |
|
|
|
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|
|
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|
See Notes to Unaudited Condensed Consolidated Financial Statements.
5
BUCKEYE PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS CAPITAL
(In thousands)
(Unaudited)
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Buckeye Partners, L.P. Unitholders |
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Equity Gains |
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on Issuance |
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Accumulated |
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of Buckeyes |
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Other |
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General |
|
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Limited |
|
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Class B |
|
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Management |
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Limited |
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Comprehensive |
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Noncontrolling |
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Partner |
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Partners |
|
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Units |
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Units |
|
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Partner Units |
|
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Income (Loss) |
|
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Interests |
|
|
Total |
|
Partners capital January 1, 2011 |
|
$ |
|
|
|
$ |
1,413,664 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
(21,259 |
) |
|
$ |
17,855 |
|
|
$ |
1,410,260 |
|
Net income |
|
|
|
|
|
|
56,783 |
|
|
|
9,710 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,320 |
|
|
|
67,813 |
|
Acquisition of 80% interest in BORCO |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
276,508 |
|
|
|
276,508 |
|
Acquisition of remaining interest in BORCO |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(278,211 |
) |
|
|
(278,211 |
) |
Costs associated with agreement and plan of
merger |
|
|
|
|
|
|
(344 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(344 |
) |
Distributions paid to partners |
|
|
|
|
|
|
(78,148 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(78,148 |
) |
Issuance of units to First Reserve for BORCO
acquisition |
|
|
|
|
|
|
152,772 |
|
|
|
254,619 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
407,391 |
|
Issuance of units to Vopak for BORCO
acquisition |
|
|
|
|
|
|
36,041 |
|
|
|
60,069 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
96,110 |
|
Issuance of units to institutional investors |
|
|
|
|
|
|
350,001 |
|
|
|
75,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
425,001 |
|
Equity issuance costs |
|
|
|
|
|
|
(2,667 |
) |
|
|
(1,929 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,596 |
) |
Amortization of Buckeyes unit-based
compensation awards |
|
|
|
|
|
|
1,986 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,986 |
|
Exercise of Buckeyes LP Unit options |
|
|
|
|
|
|
270 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
270 |
|
Services Companys non-cash ESOP distributions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,410 |
) |
|
|
(1,410 |
) |
Distributions paid to noncontrolling interests |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,204 |
) |
|
|
(1,204 |
) |
Amortization of benefit plan costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(110 |
) |
|
|
|
|
|
|
(110 |
) |
Change in value of derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,606 |
|
|
|
|
|
|
|
4,606 |
|
Amortization of interest rate swaps |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
241 |
|
|
|
|
|
|
|
241 |
|
Amortization of treasury lock settlement |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8 |
) |
|
|
|
|
|
|
(8 |
) |
Proceeds from settlement of treasury lock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
497 |
|
|
|
|
|
|
|
497 |
|
Noncash accrual for distribution equivalent
rights |
|
|
|
|
|
|
(267 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(267 |
) |
Other |
|
|
|
|
|
|
(454 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,106 |
|
|
|
2,652 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners capital March 31, 2011 |
|
$ |
|
|
|
$ |
1,929,637 |
|
|
$ |
397,469 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
(16,033 |
) |
|
$ |
17,964 |
|
|
$ |
2,329,037 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners capital January 1, 2010 |
|
$ |
7 |
|
|
$ |
236,545 |
|
|
$ |
|
|
|
$ |
3,225 |
|
|
$ |
2,557 |
|
|
$ |
|
|
|
$ |
1,209,960 |
|
|
$ |
1,452,294 |
|
Net income |
|
|
|
|
|
|
11,058 |
|
|
|
|
|
|
|
212 |
|
|
|
|
|
|
|
|
|
|
|
39,372 |
|
|
|
50,642 |
|
Distributions paid to partners of BGH |
|
|
|
|
|
|
(11,386 |
) |
|
|
|
|
|
|
(217 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(11,603 |
) |
Recognition of unit-based compensation charges |
|
|
|
|
|
|
320 |
|
|
|
|
|
|
|
6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
326 |
|
Amortization of Buckeyes unit-based
compensation awards |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,024 |
|
|
|
2,024 |
|
Exercise of Buckeyes LP Unit options |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,376 |
|
|
|
2,376 |
|
Services Companys non-cash ESOP distributions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,316 |
) |
|
|
(1,316 |
) |
Distributions paid to noncontrolling interests |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(47,586 |
) |
|
|
(47,586 |
) |
Change in value of derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,928 |
) |
|
|
(1,928 |
) |
Investment in Buckeyes limited partner units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,318 |
|
|
|
4,318 |
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,465 |
) |
|
|
(2,465 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners capital March 31, 2010 |
|
$ |
7 |
|
|
$ |
236,537 |
|
|
$ |
|
|
|
$ |
3,226 |
|
|
$ |
2,557 |
|
|
$ |
|
|
|
$ |
1,204,755 |
|
|
$ |
1,447,082 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Notes to Unaudited Condensed Consolidated Financial Statements.
6
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND BASIS OF PRESENTATION
Partnership Organization
Buckeye Partners, L.P. is a publicly traded Delaware master limited partnership (MLP), and
its limited partnership units representing limited partner interests (LP Units) are listed on the
New York Stock Exchange (NYSE) under the ticker symbol BPL. Buckeye GP LLC (Buckeye GP) is
our general partner. Buckeye GP is a wholly owned subsidiary of Buckeye GP Holdings L.P. (BGH),
a Delaware limited partnership that was previously publicly traded on
the NYSE prior to BGHs
merger with a wholly owned subsidiary of Buckeye (see below for further information). As used in these Notes to Unaudited Condensed
Consolidated Financial Statements, we, us, our and Buckeye mean Buckeye Partners, L.P. and,
where the context requires, includes our subsidiaries.
We were formed in 1986 and own and operate one of the largest independent refined petroleum
products pipeline systems in the United States in terms of volumes delivered with approximately
5,400 miles of pipeline and 69 active products terminals that provide aggregate storage capacity of
over 53 million barrels. In 2011, we closed the acquisition of the Bahamas Oil Refining Company
International Limited (BORCO) terminal facility in Freeport, Grand Bahama, The Bahamas, with a
total installed capacity of approximately 21.6 million barrels (see Note 2). In addition, we
operate and maintain approximately 2,700 miles of other pipelines under agreements with major oil
and gas, petrochemical and chemical companies, and perform certain engineering and construction
management services for third parties. We also own and operate a high
performance natural gas storage
facility in northern California, and are a wholesale distributor of refined petroleum products in
the United States in areas also served by our pipelines and terminals.
We operate and report in
five business segments: Pipelines & Terminals; International Operations; Natural Gas Storage;
Energy Services; and Development & Logistics. Effective January 1, 2011, we realigned our five
business segments. We combined the Pipeline Operations and Terminalling & Storage segments into one
segment, the Pipelines & Terminals segment, and moved our terminal in Yabucoa, Puerto Rico,
previously included as part of the Terminalling & Storage segment, and the BORCO facility to a new
International Operations segment. See Note 20 for a discussion of our business
segments.
On November 19, 2010, we consummated a transaction pursuant to a plan and agreement of merger
(the Merger Agreement) with our general partner, BGH, BGHs general partner and Grand Ohio, LLC
(Merger Sub), our subsidiary. Pursuant to the Merger Agreement, Merger Sub was merged into BGH,
with BGH as the surviving entity (the Merger). In the transaction, the incentive compensation
agreement (also referred to as the incentive distribution rights) held by our general partner was
cancelled, the general partner units held by our general partner (representing an approximate 0.5%
general partner interest in us) were converted to a non-economic general partner interest, all of
the economic interest in BGH was acquired by us and BGH unitholders received aggregate
consideration of approximately 20.0 million of our LP Units.
BGH
is considered the surviving consolidated entity for accounting
purposes, although Buckeye is
the surviving consolidated entity for legal and reporting purposes. The Merger was accounted for
as an equity transaction. Therefore, changes in BGHs ownership interest as a result of the Merger
did not result in gain or loss recognition. Costs incurred associated with the Merger were charged
directly to partners capital.
Buckeye Pipe Line Services Company (Services Company) was formed in 1996 in connection with
the establishment of the Buckeye Pipe Line Services Company Employee Stock Ownership Plan (the
ESOP). At March 31, 2011, Services Company owned approximately 1.8% of our LP Units. Services
Company employees provide services to our operating subsidiaries. Pursuant to a services agreement
entered into in December 2004, our operating subsidiaries reimburse Services Company for the costs
of the services provided by Services Company. Services Company has been consolidated into our
financial statements.
Basis of Presentation and Principles of Consolidation
These consolidated financial statements reflect the financial results of BGH for periods prior
to the effective date of the Merger. The Merger was accounted for as an equity transaction, and as
such, changes in BGHs ownership interest as a result of the Merger did not result in gain or loss
recognition. Under applicable accounting
7
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
guidance, the exchange of BGHs units for our LP Units was accounted for as a BGH equity
issuance and BGH was the surviving entity for accounting purposes. Although BGH was the surviving
entity for accounting purposes, Buckeye was the surviving entity for legal purposes; consequently,
the name on these financial statements for periods prior to the Merger has been changed from
Buckeye GP Holdings L.P. to Buckeye Partners, L.P.
The reconciliation of Buckeyes net income, as historically reported, to the net income
reported in these financial statements for the three months ended March 31, 2010 is as follows (in
thousands):
|
|
|
|
|
Buckeyes net income, as previously reported |
|
$ |
52,278 |
|
Adjustments: |
|
|
|
|
Depreciation and amortization (1) |
|
|
1,116 |
|
Costs and expenses (2) |
|
|
(2,645 |
) |
Other (3) |
|
|
(107 |
) |
|
|
|
|
Net income |
|
$ |
50,642 |
|
|
|
|
|
|
|
|
(1) |
|
Represents the amortization of the market value of LP Units issued in August 1997 in
connection with the restructuring of Services Companys ESOP. The market value of those LP
Units was $64.2 million, and this amount was recorded as a deferred charge and is being
amortized on a straight-line basis over 13.5 years. This deferred charge was not
previously included in Buckeyes net income because Services Company was consolidated with
BGH, but not Buckeye, for periods prior to the effective date of the Merger. |
|
(2) |
|
Amounts include payroll and benefits costs, professional fees, certain state franchise
taxes, insurance costs and miscellaneous other expenses incurred by BGH. |
|
(3) |
|
Includes interest expense on Services Companys debt and commitment fees on BGHs
credit facility. The interest expense was not previously included in Buckeyes net income
because Services Company was consolidated with BGH, but not Buckeye, for periods prior to
the effective date of the Merger. |
Pursuant to the Merger Agreement, BGHs unitholders received a total of approximately 20.0
million of Buckeyes LP Units in the aggregate in exchange for all outstanding BGH common units and
management units. As a result, the number of Buckeyes LP Units outstanding increased from 51.6
million to 71.4 million on the date of the Merger. However, for historical reporting purposes, the
impact of this change was accounted for as a reverse split of BGHs units of 0.705 to 1.0, together
with the addition of Buckeyes existing LP Units. Therefore, since BGH was the surviving
accounting entity, the weighted average number of LP Units outstanding used for basic and diluted
earnings per unit calculations are BGHs historical weighted average common units outstanding
adjusted for the reverse unit split and the addition of Buckeyes existing units. Amounts
reflecting historical BGH unit and per unit amounts included in this report have been restated for
the reverse unit split.
The condensed consolidated financial statements and the accompanying notes are prepared in
accordance with U.S. generally accepted accounting principles (GAAP) and the rules of the U.S.
Securities and Exchange Commission (SEC). The financial statements include our accounts on a
consolidated basis. We have eliminated all intercompany transactions in consolidation. The
consolidated financial statements include the financial results of our wholly-owned subsidiaries
and the financial results of Services Company on a consolidated basis.
Recent Accounting Developments
Fair Value Measurements. In January 2010, the Financial Accounting Standards Board
(FASB) issued guidance that requires new disclosures related to fair value measurements. The new
guidance requires expanded disclosures related to a gross presentation for Level 3 activity. The
new accounting guidance is effective for fiscal years beginning after December 15, 2010 and for
interim periods within those years. The new guidance became effective for us on January 1, 2011.
We have included the enhanced disclosure requirements regarding fair value measurements in Note 14.
8
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Intangibles, Goodwill and Other. In December 2010, the FASB issued guidance that
amended the goodwill impairment test for reporting units with zero or negative carrying amounts.
The objective of this new guidance is to address questions about entities with reporting units with
zero or negative carrying amounts because some entities concluded that the first step of the
goodwill impairment test is passed in those circumstances because the fair value of their reporting
unit will generally be greater than zero. The new guidance is effective for fiscal years and
interim periods, within those years, beginning after December 15, 2010. We do not expect the
adoption of this guidance to have an impact on our consolidated financial statements.
Business Combinations. In December 2010, the FASB issued guidance that clarifies
disclosures related to pro forma information for business combinations that occurred in the current
period. The amendments specify that if an entity presents comparative financial statements, the
entity should disclose revenue and earnings of the combined entity as though the business
combination(s) that occurred during the current year had occurred as of the beginning of the
comparable prior annual reporting period only. The amendments also expand the supplemental pro
forma disclosures to include a description of the nature and amount of material, nonrecurring pro
forma adjustments directly attributable to the business combination included in the reported pro
forma revenue and earnings. The new guidance is effective prospectively for business combinations
for which the acquisition date is on or after the beginning of the first annual reporting period
beginning on or after December 15, 2010. Early adoption is permitted. We have included the
enhanced disclosure requirements regarding pro forma information for business combinations in Note
2.
2. ACQUISITIONS
The acquisitions of terminals from an affiliate of Royal Dutch Shell plc (Shell) and from
affiliates of FRC Founders Corporation (First Reserve) and Vopak Bahamas B.V. (Vopak) have been
accounted for as business combinations. The total purchase price for these acquisitions was
allocated to the fair value of the assets acquired and the liabilities assumed based on an
assessment of their fair values at the acquisition date, with amounts exceeding the fair values
being recorded as goodwill. The results of their operations have been included in our condensed
consolidated financial statements since their respective acquisition dates.
Puerto Rico Terminal Acquisition
On
December 10, 2010, we, through our wholly owned subsidiary, acquired a refined petroleum products terminal in Yabucoa, Puerto
Rico from an affiliate of Shell for $32.6 million, net of cash acquired of $3.5 million. The
terminal includes 44 storage tanks with approximately 4.6 million barrels of gasoline, jet fuel,
diesel, fuel oil and crude oil storage capacity. Shell entered into a commercial contract with us
concurrent with the acquisition regarding usage of the acquired facility. We believe the
acquisition of these assets furthers our geographic diversification efforts as this was our first
acquisition outside the continental United States and enables us to participate in a growth market
outside our existing system footprint. The operations of these acquired assets are reported in the
International Operations segment. The purchase price has been allocated to tangible and intangible
assets acquired, on a preliminary basis, as follows (in thousands):
|
|
|
|
|
Current assets |
|
$ |
172 |
|
Inventory |
|
|
867 |
|
Property, plant and equipment |
|
|
31,770 |
|
Intangible assets |
|
|
3,363 |
|
Other assets |
|
|
17,720 |
|
Current liabilities |
|
|
(3,591 |
) |
Other liabilities |
|
|
(17,720 |
) |
|
|
|
|
Allocated purchase price |
|
$ |
32,581 |
|
|
|
|
|
We completed the acquisition of the refined petroleum products terminal in Yabucoa, Puerto
Rico through the acquisition of a Puerto Rican entity, which is undergoing an audit of its Puerto
Rico income tax returns for the tax
9
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
years 2002 through 2005. The Puerto Rico Treasury Department has notified the entity of
certain areas for discussion but has not issued a preliminary or final notice of debt regarding
such years. Pursuant to the purchase and sale agreement we entered into in connection with this
acquisition, an affiliate of Shell has assumed the full responsibility, through an indemnity and hold harmless
provision, for the payment of any income tax debt that may be assessed by the Puerto Rico Treasury
Department under this audit. In the purchase price allocation above, we recorded a $17.7 million
liability related to the uncertain outcome of the income tax audit with an offsetting
indemnification asset from Shell for the same amount.
BORCO Acquisition
On December 18, 2010, we, through our wholly owned subsidiary, entered into a sale and
purchase agreement with affiliates of First Reserve, pursuant to which we agreed to acquire First
Reserves indirect 80% interest in FR Borco Coop Holdings, L.P. (FRBCH), the indirect owner of
BORCO, for $1.15 billion, financed through a combination of debt and equity, including the issuance
of Class B units representing limited partner interests (Class B Units) and LP Units to First
Reserve. BORCO is the fourth largest oil and petroleum products storage terminal in the world and
the largest petroleum products facility in the Caribbean with current storage capacity of
approximately 21.6 million barrels. On January 18, 2011, we completed the purchase of First
Reserves interest in BORCO through the acquisition by us of all of the partnership interests in FR
Borco Topco, L.P., which indirectly owned First Reserves interest.
Vopak, which is based in The Netherlands, owned the remaining 20% interest in FRBCH. On
February 16, 2011, Vopak sold its 20% interest in FRBCH to us for approximately $276.5 million of
cash and equity, which is a proportionate price and on the same terms and conditions as those in
the sale and purchase agreement with First Reserve.
The following table presents the aggregate consideration paid or issued to complete the BORCO
acquisition (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Reserve |
|
|
Vopak |
|
|
Combined |
|
Cash consideration |
|
$ |
644,049 |
|
|
$ |
164,616 |
|
|
$ |
808,665 |
|
Fair value of LP Units and Class B Units issued
(1) |
|
|
407,391 |
|
|
|
96,110 |
|
|
|
503,501 |
|
Cash paid on behalf of the sellers (2) |
|
|
96,241 |
|
|
|
15,780 |
|
|
|
112,021 |
|
|
|
|
|
|
|
|
|
|
|
Consideration issued to effect the transactions |
|
$ |
1,147,681 |
|
|
$ |
276,506 |
|
|
$ |
1,424,187 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
On January 18, 2011, we issued 2,483,444 LP Units and 4,382,889 Class B Units to First
Reserve, which represented a negotiated value of $400.0 million of consideration. On
February 16, 2011, we issued 620,861 LP Units and 1,095,722 Class B Units to Vopak, which
represented a negotiated value of $100.0 million of consideration. In accordance with
accounting for business combinations, the fair values of the units issued to First Reserve
and Vopak on their respective acquisition dates were determined to be $407.4 million and
$96.1 million, respectively. |
|
(2) |
|
Approximately $79.3 million was to be held in escrow related to Bahamian transfer taxes
payable, approximately $23.2 million was used to make certain payments to BORCOs operator
and indirect minority owner and to pay certain fees and expenses incurred by FRBCH and its
affiliates in connection with the transaction and approximately $9.5 million was used to
pay bonuses to employees that became payable as a result of the transaction. |
On January 13, 2011, we sold $650.0 million aggregate principal amount of 4.875% Notes due
2021 (the 4.875% Notes) in an underwritten public offering. The notes were issued at 99.62% of
their principal amount. Total proceeds from this offering, after underwriters fees, expenses and
debt issuance costs of $4.9 million, were approximately $642.6 million, and were used to fund a
portion of the purchase price of the BORCO acquisition.
On January 18 and 19, 2011, we issued 5,794,725 LP Units and 1,314,870 Class B Units to
institutional investors for aggregate consideration of approximately $425.0 million to fund a
portion of the BORCO acquisition.
10
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
On January 18, 2011, we issued 2,483,444 LP Units and 4,382,889 Class B Units to First Reserve
as $400.0 million of consideration to fund a portion of the BORCO acquisition. On February 16,
2011, we issued 620,861 LP Units and 1,095,722 Class B Units to Vopak as $100.0 million of
consideration to fund a portion of the BORCO acquisition. Equity issuance costs incurred on these
transactions were approximately $4.6 million. The remaining purchase price was funded with cash on
hand at closing and borrowings under our unsecured revolving credit agreement (Credit Facility).
On January 18, 2011, in connection with the BORCO acquisition, we repaid all of BORCOs
outstanding indebtedness and settled BORCOs interest rate derivative instruments, consisting of
approximately $318.2 million.
The results of operations of the BORCO acquisition are included in our consolidated financial
statements from the date of acquisition and are included in our International Operations segment.
The acquisition cost has been allocated to assets acquired and liabilities assumed based on
estimated fair values at the acquisition date, with amounts exceeding the fair value recorded as
goodwill. Fair values have been developed using recognized business valuation techniques and are
subject to change pending final valuation analysis. The purchase price has been allocated to
tangible and intangible assets acquired, on a preliminary basis, as follows (in thousands):
|
|
|
|
|
Current assets |
|
$ |
41,540 |
|
Inventory |
|
|
1,645 |
|
Property, plant and equipment |
|
|
1,105,278 |
|
Intangible assets |
|
|
206,000 |
|
Other assets |
|
|
415 |
|
Goodwill |
|
|
497,946 |
|
Current liabilities |
|
|
(55,762 |
) |
Debt, including interest rate derivative instruments |
|
|
(318,167 |
) |
Other non-current liabilities |
|
|
(54,708 |
) |
|
|
|
|
Allocated purchase price |
|
$ |
1,424,187 |
|
|
|
|
|
11
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Unaudited Pro forma Financial Results
Our condensed consolidated statements of operations do not include earnings from BORCO prior
to January 18, 2011, the effective date of the BORCO acquisition. The following table presents
selected unaudited pro forma earnings information for the three months ended March 31, 2011 and
2010, as if the acquisition had occurred on January 1, 2010. This pro forma information was
prepared using BORCOs historical financial data and reflects certain estimates and assumptions
made by our management. Our unaudited pro forma financial information was prepared for comparative
purposes only and is not necessarily indicative of what our consolidated financial results would
have been had we actually acquired BORCO on January 1, 2010 or the results that may be attained in
the future (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2011 |
|
|
2010 |
|
Revenues: |
|
|
|
|
|
|
|
|
As reported |
|
$ |
1,252,536 |
|
|
$ |
731,174 |
|
Pro forma adjustments |
|
|
8,358 |
|
|
|
46,510 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma revenues |
|
$ |
1,260,894 |
|
|
$ |
777,684 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income: |
|
|
|
|
|
|
|
|
As reported |
|
$ |
66,493 |
|
|
$ |
11,270 |
|
Pro forma adjustments |
|
|
2,653 |
|
|
|
16,782 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma net income |
|
$ |
69,146 |
|
|
$ |
28,052 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma earnings per unit: |
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.79 |
|
|
$ |
0.79 |
|
|
|
|
|
|
|
|
Diluted |
|
$ |
0.79 |
|
|
$ |
0.79 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma weighted average
number of units
outstanding: |
|
|
|
|
|
|
|
|
Basic |
|
|
87,675 |
|
|
|
35,689 |
|
|
|
|
|
|
|
|
Diluted |
|
|
87,960 |
|
|
|
35,689 |
|
|
|
|
|
|
|
|
Entry into Definitive Agreement to Acquire Pipeline & Terminal Assets
On March 18, 2011, we signed a definitive agreement with BP Products North America Inc. and
its affiliates (BP) to acquire 33 refined petroleum products terminals with total storage
capacity exceeding 10 million barrels and approximately 1,000 miles of refined petroleum products
pipelines, including BPs approximately 50% interest in Inland Corporation (Inland), for a total
transaction purchase price of $225.0 million. The terminal and pipeline assets are located in the
Midwestern, Southeastern and Western United States, further extending our operations into new, key
geographic markets. Our proposed acquisition of BPs interest in Inland, which represents $60.0
million of the total transaction purchase price, is subject to Inlands other shareholders existing
rights of first refusal. The period for such shareholders to exercise their rights of first
refusal has not ended, but all shareholders have expressed an intent to exercise such rights with
respect to some or all share to which they are entitled. We expect this acquisition to close in
the second quarter of 2011, subject to regulatory approvals, other customary closing conditions,
and, with respect to BPs interest in Inland, the co-owners right of first refusal. We expect to
fund this acquisition with borrowings under our Credit Facility.
12
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
3. COMMITMENTS AND CONTINGENCIES
Claims and Proceedings
In the ordinary course of business, we are involved in various claims and legal proceedings,
some of which are covered by insurance. We are generally unable to predict the timing or outcome of
these claims and proceedings. Based upon our evaluation of existing claims and proceedings and the
probability of losses relating to such contingencies, we have accrued certain amounts relating to
such claims and proceedings, none of which are considered material.
In June 2009, the Pipeline Hazardous Materials Safety Administration (PHMSA) proposed
penalties totaling approximately $0.6 million as a result of alleged violations of various pipeline
safety requirements raised as a result of PHMSAs 2008 integrated inspection of our procedures and
records for operations and maintenance, operator qualification, and integrity management as well as
field inspections of locations in Pennsylvania, Ohio, Illinois, Michigan and Colorado. We are
contesting portions of the proposed penalty. The timing or outcome of final resolution of this
matter cannot reasonably be determined at this time.
In April 2010, PHMSA proposed penalties totaling approximately $0.5 million in connection with
a tank overfill incident that occurred at our facility in East Chicago, Indiana in May 2005 and
other related personnel qualification issues raised as a result of PHMSAs 2008 Integrity
Inspection. We are contesting the proposed penalty. The timing or outcome of this appeal cannot
reasonably be determined at this time.
In January 2011, PHMSA issued us a final order with penalties totaling $0.2 million in
connection with issues related to documentation, inspection and physical signage of certain of our
pipelines raised as a result of PHMSAs 2005 2006 inspection of certain facilities in Illinois,
Indiana, Ohio, and Michigan as well as compliance records.
In January 2011, PHMSA issued us a final order with penalties totaling $0.1 million in
connection with an employees failure to follow certain pipeline-marking procedures in connection
with a product release that occurred in New York, New York in November 2009.
On July 30, 2010, a putative class action was filed by a unitholder against BGH, MainLine
Management LLC (MainLine Management), BGH GP Holdings, LLC (BGH GP) and each of MainLine
Managements directors in the District Court of Harris County, Texas under the caption Broadbased
Equities v. Forrest E. Wylie, et. al. In the Petition, the plaintiff alleged that MainLine
Management and its directors breached their fiduciary duties to BGHs public unitholders by, among
other things, acting to facilitate the sale of BGH to Buckeye in order to facilitate the gradual
sale by BGH GP of its interest in BGH and failing to disclose all material facts in order that the
BGH unitholders could cast an informed vote on the Merger Agreement. Among other things, the
Petition sought an order certifying a class consisting of all BGH unitholders, a determination that
the action was a proper derivative action, damages in an unspecified amount, and an award of
attorneys fees and costs.
On August 2, 2010, a putative class action was filed by a unitholder against BGH, MainLine
Management, Merger Sub, Buckeye, Buckeye GP and each of MainLine Managements directors in the
District Court of Harris County, Texas under the caption Henry James Steward v. Forrest E. Wylie,
et. al. In the Petition, the plaintiff alleged that MainLine Management and its directors breached
their fiduciary duties to BGHs public unitholders by, among other things, failing to disclose all
material facts in order that the BGH unitholders could cast an informed vote on the Merger Agreement.
The Petition also alleged that Buckeye, Buckeye GP and Merger Sub aided and abetted the breaches
of fiduciary duty. Among other things, the Petition sought an order certifying a plaintiff class
consisting of all of BGH unitholders, an order enjoining the Merger, rescission of the Merger,
damages in an unspecified amount, and an award of attorneys fees and costs.
On August 2, 2010, a putative class action was filed by a unitholder against BGH, MainLine
Management, BGH GP, ArcLight Capital Partners (ArcLight), Kelso & Company (Kelso), Buckeye,
Buckeye GP and each of MainLine Managements directors in the District Court of Harris County,
Texas under the caption JR Garrett Trust v. Buckeye GP Holdings L.P. et al. In the Petition, the
plaintiff alleged that MainLine Management and its directors breached their fiduciary duties to
BGHs public unitholders by, among other things, accepting insufficient
13
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
consideration, failing to condition the Merger on a majority vote of public unitholders of
BGH, and failing to disclose all material facts in order that the BGH
unitholders could cast an
informed vote on the Merger Agreement. The Petition also alleged that Buckeye, Buckeye GP, BGH GP,
ArcLight and Kelso aided and abetted the breaches of fiduciary duty. Among other things, the
Petition sought an order certifying a class consisting of all of BGHs unitholders, an order
enjoining the Merger, damages in an unspecified amount, and an award of attorneys fees and costs.
On August 24, 2010, the District Court of Harris County, Texas entered an order consolidating
the three previously filed putative class actions (Broadbased Equities v. Forrest E. Wylie, et. al.,
Henry James Steward v. Forrest E. Wylie, et. al., and JR Garrett Trust v. Buckeye GP Holdings L.P.,
et al.,) under the caption of Broadbased Equities v. Forrest E. Wylie, et al. and appointing
interim co-lead class counsel and interim co-liaison counsel. The plaintiffs subsequently filed a
consolidated amended class action and derivative complaint on September 1, 2010 (the Complaint).
The Complaint purported to be a putative class and derivative action alleging that MainLine
Management and its directors breached their fiduciary duties to BGHs public unitholders in
connection with the Merger by, among other things, accepting insufficient consideration and failing
to disclose all material facts in order that BGHs unitholders
could cast an informed vote on the
Merger Agreement, and that we, Buckeye GP, MainLine Management, Merger Sub, BGH GP, ArcLight and
Kelso aided and abetted the breaches of fiduciary duty.
On October 29, 2010, the parties to the litigation entered into a Memorandum of Understanding
(MOU) in connection with a proposed settlement of the class action and the Complaint. The MOU
provides for dismissal with prejudice of the litigation and a release of the defendants from all
present and future claims asserted in the litigation in exchange for, among other things, the
agreement of the defendants to amend the Merger Agreement to reduce the termination fees payable by
BGH upon termination of the Merger Agreement and to provide BGHs unitholders with supplemental
disclosure to BGHs and our joint proxy statement/prospectus, dated September 24, 2010. The
supplemental disclosure is set forth in a joint proxy statement/prospectus supplement, dated
October 29, 2010, which was filed with the SEC on November 1, 2010.
In addition, the MOU provides that, in settlement of the plaintiffs claims (including any
claim against the defendants by the plaintiffs counsel for attorneys fees or expenses related to
the litigation), the defendants (or their insurers) will make a cash
payment of $900,000 to plaintiffs counsel for attorneys fees, subject to
final court approval of the settlement. On January 25, 2011, pursuant to the MOU, the parties
signed a Stipulation of Settlement. The Stipulation of Settlement was filed with the court, and
the court preliminarily approved the settlement on March 21, 2011. The court has scheduled a
hearing to be held on May 23, 2011 to consider the final approval of the settlement. The proposed
settlement is subject to several conditions, including, without
limitation, final court approval. There
is no assurance that the court will approve the settlement.
We and the other defendants vigorously deny all liability with respect to the facts and claims
alleged in the Complaint, and specifically deny that any modifications to the Merger Agreement or
any supplemental disclosure was required or advisable under any applicable rule, statute,
regulation or law. However, to avoid the substantial burden, expense, risk, inconvenience and
distraction of continuing the litigation, and to fully and finally resolve the claims alleged, we
and the other defendants agreed to the proposed settlement described above.
Environmental Contingencies
In accordance with our accounting policy, we recorded operating expenses, net of insurance
recoveries, of $2.4 million and $2.8 million during the three months ended March 31, 2011 and 2010,
respectively, related to environmental expenditures unrelated to claims and proceedings.
Ammonia Contract Contingencies
On November 30, 2005, Buckeye Development & Logistics I LLC (BDL) (formerly Buckeye Gulf
Coast Pipe Lines, L.P.) purchased an ammonia pipeline and other assets from El Paso Merchant
Energy-Petroleum Company (EPME), a subsidiary of El Paso Corporation (El Paso). As part of the
transaction, BDL assumed the obligations of EPME under several contracts involving monthly
purchases and sales of ammonia. EPME and BDL
14
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
agreed, however, that EPME would retain the economic risks and benefits associated with those
contracts until their expiration at the end of 2012. To effectuate this agreement, BDL passes
through to EPME both the cost of purchasing ammonia under a supply contract and the proceeds from
selling ammonia under three sales contracts. For the vast majority of monthly periods since the
closing of the pipeline acquisition, the pricing terms of the ammonia contracts have resulted in
ammonia supply costs exceeding ammonia sales proceeds. The amount of the shortfall generally
increases as the market price of ammonia increases.
EPME has informed BDL that, notwithstanding the parties agreement, it will not continue to
pay BDL for shortfalls created by the pass-through of ammonia costs in excess of ammonia revenues.
EPME encouraged BDL to seek payment by invoking a $40.0 million guaranty made by El Paso, which
guaranteed EPMEs obligations to BDL. If EPME fails to reimburse BDL for these shortfalls, then
such unreimbursed shortfalls could exceed the $40.0 million cap on El Pasos guaranty. To the
extent the unreimbursed shortfalls significantly exceed the $40.0 million cap, the resulting costs
incurred by BDL could adversely affect our financial position, results of operations and cash
flows. To date, BDL has continued to receive payment for ammonia costs under the contracts at
issue. BDL has not called on El Pasos guaranty and believes only BDL may invoke the guaranty.
EPME, however, contends that El Pasos guaranty is the source of payment for the shortfalls, but
has not clarified the extent to which it believes the guaranty has been exhausted. We, in
cooperation with EPME, have terminated one of the ammonia sales contracts. Given the uncertainty
of future ammonia prices and EPMEs future actions, we continue to believe we may have risk of loss
in connection with the two remaining ammonia sales contracts and an ammonia supply contract and, at
this time, are unable to estimate the amount of any such losses we might incur in the future. We
are assessing our options in the event that we are unable to mitigate our risk with respect to the
remaining contracts through termination of such contracts by other means, including commencing
litigation or pursuing other recourse against EPME and El Paso, with respect to this matter.
Leases Where We are Lessee
We lease certain property, plant and equipment under noncancelable and cancelable operating
leases. Lease expense is charged to operating expenses on a straight-line basis over the period of
expected benefit. Contingent rental payments are expensed as incurred. Total rental expense for
the three months ended March 31, 2011 and 2010 was $7.6 million and $5.0 million, respectively.
The following table presents minimum lease payment obligations under our operating leases with
terms in excess of one year for the years ending December 31 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Office space |
|
|
|
|
|
|
Land |
|
|
|
|
|
|
and other (1) |
|
|
Equipment (2) |
|
|
Leases (3) |
|
|
Total (4) |
|
2011 (remainder) |
|
$ |
1,524 |
|
|
$ |
2,620 |
|
|
$ |
3,500 |
|
|
$ |
7,644 |
|
2012 |
|
|
2,213 |
|
|
|
3,487 |
|
|
|
4,890 |
|
|
|
10,590 |
|
2013 |
|
|
2,297 |
|
|
|
3,608 |
|
|
|
5,016 |
|
|
|
10,921 |
|
2014 |
|
|
2,387 |
|
|
|
2,093 |
|
|
|
5,100 |
|
|
|
9,580 |
|
2015 |
|
|
2,480 |
|
|
|
|
|
|
|
5,224 |
|
|
|
7,704 |
|
Thereafter |
|
|
15,315 |
|
|
|
|
|
|
|
358,591 |
|
|
|
373,906 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
26,216 |
|
|
$ |
11,808 |
|
|
$ |
382,321 |
|
|
$ |
420,345 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes leases of space in office buildings and related land leases with respect to
our Albany terminal. |
|
(2) |
|
Includes BORCO facility leases for tugboats and a barge in our International Operations
segment. |
|
(3) |
|
Includes leases for inland dock and seabed in connection with our International
Operations segment and leases for subsurface underground gas storage rights and surface
rights in connection with our operations in the Natural Gas Storage segment. We may cancel
the Natural Gas Storage segment leases if the storage reservoir is not used for underground
storage of natural gas or the removal or injection thereof for a continuous period of two
consecutive years. Lease expense associated with the Natural Gas Storage segment leases,
which is being recognized on a straight-line basis over 44 years, was approximately $1.8
million for each the three months ended March 31, 2011 and 2010. At March 31, 2011 and
December 31, 2010, the balance of our Natural Gas Storage segment deferred lease liability
was $14.4 million and |
15
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
$13.3 million, respectively. We estimate that this deferred lease liability will continue to
increase through 2032, at which time our deferred lease liability is estimated to be
approximately $64.7 million. Our deferred lease liability will then be reduced over the
remaining 19 years of the lease, since the expected annual lease payments will exceed the
amount of lease expense.
|
|
(4) |
|
Total minimum lease payment obligations for 2011 is the remaining portion from April 1
through December 31, 2011. All other years consist of the total minimum lease payment
obligations for the full year. |
Leases Where We are Lessor
We have entered into capacity leases with remaining terms from 5 to 12 years that are
accounted for as operating leases. All of the agreements provide for negotiated extensions.
Future minimum lease payments to be received under such operating leasing arrangements as of
December 31, 2011 are as follows, with the amount for 2011 consisting of the remainder of 2011
(April 1 through December 31) and all other years consisting of the total amount for the full year
(in thousands):
|
|
|
|
|
|
|
Years Ending |
|
|
|
December 31, |
|
2011 (remainder) |
|
$ |
100,067 |
|
2012 |
|
|
80,212 |
|
2013 |
|
|
43,624 |
|
2014 |
|
|
11,526 |
|
2015 |
|
|
11,152 |
|
Thereafter |
|
|
50,891 |
|
|
|
|
|
Total |
|
$ |
297,472 |
|
|
|
|
|
4. INVENTORIES
Our inventory amounts were as follows at the dates indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2011 |
|
|
2010 |
|
Refined petroleum products (1) |
|
$ |
239,605 |
|
|
$ |
340,659 |
|
Materials and supplies |
|
|
13,226 |
|
|
|
10,946 |
|
|
|
|
|
|
|
|
Total inventories |
|
$ |
252,831 |
|
|
$ |
351,605 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Ending inventory was 77.3 million and 134.9 million gallons of refined petroleum
products at March 31, 2011 and December 31, 2010, respectively. |
At March 31, 2011 and December 31, 2010, approximately 92% and 94%, respectively, of our
refined petroleum products inventory was hedged. Hedged inventory is valued at current market
prices with the change in value of the inventory reflected in our condensed consolidated statements
of operations. Inventory not accounted for as a fair value hedge is accounted for at weighted
average cost.
16
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
5. PREPAID AND OTHER CURRENT ASSETS
Prepaid and other current assets consist of the following at the dates indicated (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2011 |
|
|
2010 |
|
Prepaid insurance |
|
$ |
9,827 |
|
|
$ |
8,865 |
|
Insurance receivables |
|
|
8,721 |
|
|
|
8,886 |
|
Ammonia receivable |
|
|
1,422 |
|
|
|
1,295 |
|
Margin deposits |
|
|
8,942 |
|
|
|
18,833 |
|
Prepaid services |
|
|
22,416 |
|
|
|
24,359 |
|
Unbilled revenue |
|
|
4,982 |
|
|
|
3,263 |
|
Tax receivable |
|
|
120 |
|
|
|
120 |
|
Prepaid taxes |
|
|
6,740 |
|
|
|
5,417 |
|
Customer deposits |
|
|
6,953 |
|
|
|
2,657 |
|
Other |
|
|
11,136 |
|
|
|
11,994 |
|
|
|
|
|
|
|
|
Total prepaid and other current assets |
|
$ |
81,259 |
|
|
$ |
85,689 |
|
|
|
|
|
|
|
|
6. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consist of the following at the dates indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2011 |
|
|
2010 |
|
Land |
|
$ |
180,275 |
|
|
$ |
64,905 |
|
Rights-of-way |
|
|
97,529 |
|
|
|
97,529 |
|
Pad gas |
|
|
29,346 |
|
|
|
29,346 |
|
Buildings and leasehold improvements |
|
|
117,746 |
|
|
|
109,585 |
|
Jetties |
|
|
155,599 |
|
|
|
|
|
Machinery, equipment and office furnishings |
|
|
2,984,276 |
|
|
|
2,251,027 |
|
Construction in progress |
|
|
221,045 |
|
|
|
66,642 |
|
|
|
|
|
|
|
|
Total property, plant and equipment |
|
|
3,785,816 |
|
|
|
2,619,034 |
|
Less: Accumulated depreciation |
|
|
(337,694 |
) |
|
|
(313,150 |
) |
|
|
|
|
|
|
|
Total property, plant and equipment, net |
|
$ |
3,448,122 |
|
|
$ |
2,305,884 |
|
|
|
|
|
|
|
|
Depreciation expense was $23.2 million and $13.3 million for the three months ended March 31,
2011 and 2010, respectively.
17
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
7. EQUITY INVESTMENTS
We own interests in related businesses that are accounted for using the equity method of
accounting. The following table presents our equity investments, all included within the Pipelines
& Terminals segment, at the dates indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
Ownership |
|
|
2011 |
|
|
2010 |
|
Muskegon Pipeline LLC |
|
|
40.0 |
% |
|
$ |
14,213 |
|
|
$ |
14,552 |
|
Transport4, LLC |
|
|
25.0 |
% |
|
|
400 |
|
|
|
341 |
|
West Shore Pipe Line Company |
|
|
34.6 |
% |
|
|
43,841 |
|
|
|
43,563 |
|
West Texas LPG Pipeline
Limited Partnership (1) |
|
|
20.0 |
% |
|
|
50,148 |
|
|
|
48,591 |
|
|
|
|
|
|
|
|
|
|
|
|
Total equity investments |
|
|
|
|
|
$ |
108,602 |
|
|
$ |
107,047 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
In April 2011, we entered into an agreement to sell our interest in this investment.
See Note 22 for further information. |
The following table presents earnings from equity investments for the periods indicated (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2011 |
|
|
2010 |
|
Muskegon Pipeline LLC |
|
$ |
183 |
|
|
$ |
344 |
|
Transport4, LLC |
|
|
58 |
|
|
|
39 |
|
West Shore Pipe Line Company |
|
|
1,548 |
|
|
|
1,207 |
|
West Texas LPG Pipeline Limited Partnership |
|
|
1,558 |
|
|
|
1,062 |
|
|
|
|
|
|
|
|
Total earnings from equity investments |
|
$ |
3,347 |
|
|
$ |
2,652 |
|
|
|
|
|
|
|
|
Combined income statement data for the periods indicated for our equity method investments
are summarized below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2011 |
|
|
2010 |
|
Revenues |
|
$ |
33,303 |
|
|
$ |
31,545 |
|
Costs and expenses |
|
|
(17,008 |
) |
|
|
(15,901 |
) |
Non-operating expense |
|
|
(3,553 |
) |
|
|
(3,577 |
) |
|
|
|
|
|
|
|
Net income |
|
$ |
12,742 |
|
|
$ |
12,067 |
|
|
|
|
|
|
|
|
18
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
8. GOODWILL AND INTANGIBLE ASSETS
Goodwill
Goodwill represents the excess of the purchase price of an acquired business over the amounts
assigned to assets acquired and liabilities assumed in the transaction. Goodwill is not amortized;
it is subject to annual impairment testing. The following table summarizes our goodwill amounts by
segment at the dates indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2011 |
|
|
2010 |
|
Pipelines & Terminals: |
|
|
|
|
|
|
|
|
Purchase of general partner interests in 2004 |
|
$ |
210,066 |
|
|
$ |
210,066 |
|
Acquisition of six terminals in June 2000 |
|
|
11,355 |
|
|
|
11,355 |
|
Acquisition of Albany Terminal in 2008 |
|
|
26,829 |
|
|
|
26,829 |
|
|
|
|
|
|
|
|
Subtotal |
|
|
248,250 |
|
|
|
248,250 |
|
|
|
|
|
|
|
|
International Operations: |
|
|
|
|
|
|
|
|
Acquisition of BORCO in 2011 |
|
|
497,946 |
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Storage: |
|
|
|
|
|
|
|
|
Acquisition of Lodi Gas in 2008 |
|
|
169,560 |
|
|
|
169,560 |
|
|
|
|
|
|
|
|
Energy Services: |
|
|
|
|
|
|
|
|
Acquisition of Farm & Home in 2008 |
|
|
1,132 |
|
|
|
1,132 |
|
|
|
|
|
|
|
|
Development & Logistics: |
|
|
|
|
|
|
|
|
Purchase of general partner interests in 2004 |
|
|
13,182 |
|
|
|
13,182 |
|
|
|
|
|
|
|
|
Total goodwill |
|
$ |
930,070 |
|
|
$ |
432,124 |
|
|
|
|
|
|
|
|
19
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Intangible Assets
Intangible assets include customer relationships and contracts. These intangible assets have
definite lives and are being amortized on a straight-line basis over their estimated useful lives
ranging from 5 to 25 years. Our amortizable customer contracts are contracts that were acquired in
connection with the acquisition of BDL in March
1999, the acquisition of the Taylor, Michigan terminal in December 2005, the acquisition of certain
pipeline and terminal assets in November 2009, the acquisition of the Yabucoa, Puerto Rico terminal
in 2010 and the acquisition of BORCO in 2011 (see Note 2 for further discussion). The customer
contracts are being amortized over their contractual life, 5 years in the case of the acquisition
of certain pipeline and terminal assets in November 2009 and 5 years in the case of the terminal
acquisition in 2010.
The customer relationships resulted from the acquisition of Farm & Home Oil Company LLC (Farm
& Home) in 2008 and BORCO in 2011. We determined, through an analysis of historical customer
attrition rates at Farm & Home, that an appropriate recovery period for customer relationships is
approximately 12 years. For BORCO, due to the high customer demand at the facility, the level of
customer service being provided, the expansion capabilities of the facility, the potential of
customer recontracting rates and the location of the facility in relation to international shipping
routes, we anticipate the customer relationships to extend well beyond the existing contract terms
with a recovery period of approximately 25 years. Intangible assets consist of the following at
the dates indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2011 |
|
|
2010 |
|
Customer relationships |
|
$ |
247,663 |
|
|
$ |
41,663 |
|
Accumulated amortization |
|
|
(11,003 |
) |
|
|
(8,600 |
) |
|
|
|
|
|
|
|
Net carrying amount |
|
|
236,660 |
|
|
|
33,063 |
|
|
|
|
|
|
|
|
Customer contracts |
|
|
16,380 |
|
|
|
16,380 |
|
Accumulated amortization |
|
|
(5,747 |
) |
|
|
(5,376 |
) |
|
|
|
|
|
|
|
Net carrying amount |
|
|
10,633 |
|
|
|
11,004 |
|
|
|
|
|
|
|
|
Total intangible assets |
|
$ |
247,293 |
|
|
$ |
44,067 |
|
|
|
|
|
|
|
|
For the three months ended March 31, 2011 and 2010, amortization expense related to intangible
assets was $2.8 million and $1.1 million, respectively. Amortization expense related to intangible
assets is expected to be approximately $10.2 million for the remainder of 2011 (April 1 through
December 31), $13.4 million for 2012, $13.4 million for 2013, $13.2 million for 2014 and $12.2
million for 2015.
9. OTHER NON-CURRENT ASSETS
Other non-current assets consist of the following at the dates indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2011 |
|
|
2010 |
|
Prepaid services |
|
$ |
3,212 |
|
|
$ |
5,836 |
|
Unbilled revenue |
|
|
|
|
|
|
2,163 |
|
Derivative assets |
|
|
7,864 |
|
|
|
3,892 |
|
Debt issuance costs |
|
|
15,214 |
|
|
|
11,184 |
|
Insurance receivables |
|
|
8,441 |
|
|
|
8,826 |
|
Indemnification asset (see Note 2) |
|
|
17,720 |
|
|
|
17,720 |
|
Other |
|
|
9,198 |
|
|
|
8,842 |
|
|
|
|
|
|
|
|
Total other non-current assets |
|
$ |
61,649 |
|
|
$ |
58,463 |
|
|
|
|
|
|
|
|
20
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
10. ACCRUED AND OTHER CURRENT LIABILITIES
Accrued and other current liabilities consist of the following at the dates indicated (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2011 |
|
|
2010 |
|
Taxes other than income |
|
$ |
19,714 |
|
|
$ |
20,698 |
|
Accrued employee benefit liability |
|
|
3,817 |
|
|
|
3,817 |
|
Environmental liabilities |
|
|
12,676 |
|
|
|
10,471 |
|
Interest payable |
|
|
25,230 |
|
|
|
30,700 |
|
Payable for ammonia purchase |
|
|
1,238 |
|
|
|
2,354 |
|
Unearned revenue |
|
|
18,257 |
|
|
|
18,776 |
|
Compensation and vacation |
|
|
7,911 |
|
|
|
13,134 |
|
Accrued capital expenditures |
|
|
1,814 |
|
|
|
2,032 |
|
Deferred consideration |
|
|
1,000 |
|
|
|
2,010 |
|
Customer deposits |
|
|
10,555 |
|
|
|
5,389 |
|
Unfavorable storage contracts (1) |
|
|
9,583 |
|
|
|
|
|
Other |
|
|
41,378 |
|
|
|
35,499 |
|
|
|
|
|
|
|
|
Total accrued and other current liabilities |
|
$ |
153,173 |
|
|
$ |
144,880 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
See Note 12 for a discussion of the unfavorable storage contracts acquired in
connection with the BORCO acquisition. |
11. DEBT OBLIGATIONS
Long-term debt consists of the following at the dates indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2011 |
|
|
2010 |
|
4.625% Notes due July 15, 2013 (1) |
|
$ |
300,000 |
|
|
$ |
300,000 |
|
5.300% Notes due October 15, 2014 (1) |
|
|
275,000 |
|
|
|
275,000 |
|
5.125% Notes due July 1, 2017 (1) |
|
|
125,000 |
|
|
|
125,000 |
|
6.050% Notes due January 15, 2018 (1) |
|
|
300,000 |
|
|
|
300,000 |
|
5.500% Notes due August 15, 2019 (1) |
|
|
275,000 |
|
|
|
275,000 |
|
4.875% Notes due February 1, 2021 (1) |
|
|
650,000 |
|
|
|
|
|
6.750% Notes due August 15, 2033 (1) |
|
|
150,000 |
|
|
|
150,000 |
|
Credit Facility |
|
|
335,000 |
|
|
|
98,000 |
|
BES Credit Agreement |
|
|
235,000 |
|
|
|
284,300 |
|
Services Company 3.60% ESOP Notes due
March 28, 2011 |
|
|
|
|
|
|
1,531 |
|
Retirement premium |
|
|
|
|
|
|
(6 |
) |
|
|
|
|
|
|
|
Total debt |
|
|
2,645,000 |
|
|
|
1,808,825 |
|
Other, including unamortized discounts
and fair value hedges |
|
|
(5,929 |
) |
|
|
(3,607 |
) |
|
|
|
|
|
|
|
Subtotal debt |
|
|
2,639,071 |
|
|
|
1,805,218 |
|
Less: Current portion of long-term debt |
|
|
(235,000 |
) |
|
|
(285,825 |
) |
|
|
|
|
|
|
|
Total long-term debt |
|
$ |
2,404,071 |
|
|
$ |
1,519,393 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
We make semi-annual interest payments on these notes based on the rates noted above
with the principal balances outstanding to be paid on or before the due dates as shown
above. |
21
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The fair values of our aggregate debt and credit facilities were estimated to be $2,733.9
million and $1,897.5 million at March 31, 2011 and December 31, 2010, respectively. The fair
values of the fixed-rate debt were estimated by observing market trading prices and by comparing
the historic market prices of our publicly-issued debt with the market prices of other MLPs
publicly-issued debt with similar credit ratings and terms. The fair values of the variable-rate
debt are their carrying amounts, as the carrying amount reasonably approximates fair value due to
the variability of the interest rates.
Notes Offering
On January 13, 2011, we sold $650.0 million aggregate principal amount of 4.875% Notes due
2021 (the 4.875% Notes) in an underwritten public offering. The notes were issued at 99.62% of
their principal amount. Total proceeds from this offering, after underwriters fees, expenses and
debt issuance costs of $4.9 million, were approximately $642.6 million, and were used to fund a
portion of the purchase price for our acquisition of BORCO (see Note 2). In connection with this
offering, we settled a treasury lock agreement, which resulted in the receipt of a settlement of
$0.5 million, which is being amortized as a reduction to interest expense over the ten-year term of
the 4.875% Notes (see Note 14).
Bridge Loans
In December 2010, in connection with the proposed BORCO acquisition, we obtained a commitment
from commercial banks for senior unsecured bridge loans in an aggregate amount up to $595 million
(or up to $775 million in the event we purchased both First Reserves 80% interest and Vopaks 20%
interest in FRBCH) (the Bridge Loans). The commitment was to expire upon the earliest to occur
of the termination date as defined in the BORCO sale and purchase agreement, the consummation of
the BORCO acquisition, the termination of the BORCO sale and purchase agreement or 120 days after
December 18, 2010. We paid $2.0 million of fees in December 2010 associated with these Bridge
Loans. In January 2011, we terminated the Bridge Loans upon issuance of the 4.875% Notes.
Services Company ESOP Notes
Services Company had total debt outstanding of $1.5 million at December 31, 2010 consisting of
3.60% Senior Secured Notes (the 3.60% ESOP Notes) due March 28, 2011 payable by the ESOP to a
third-party lender. The 3.60% ESOP Notes were repaid on March 28, 2011.
Credit Facility
We have a borrowing capacity of $580.0 million under an unsecured revolving credit agreement
(the Credit Facility) with SunTrust Bank, as administrative agent, which may be expanded up to
$780.0 million subject to certain conditions and upon the further approval of the lenders. The
Credit Facilitys maturity date is August 24, 2012, which we may extend for up to two additional
one-year periods. Borrowings under the Credit Facility bear interest under one of two rate
options, selected by us, equal to either (i) the greater of (a) the federal funds rate plus 0.5%
and (b) SunTrust Banks prime rate plus an applicable margin, or (ii) the London Interbank Offered
Rate (LIBOR) plus an applicable margin. The applicable margin is determined based on the current
utilization level of the Credit Facility and ratings assigned by Standard & Poors Rating Services
and Moodys Investor Service for our senior unsecured non-credit enhanced long-term debt. At March
31, 2011 and December 31, 2010, $335.0 million and $98.0 million, respectively, were outstanding
under the Credit Facility. The weighted average interest rate for borrowings under the Credit
Facility was 0.6% at March 31, 2011.
The Credit Facility requires us to maintain a specified ratio (the Funded Debt Ratio) of no
greater than 5.00 to 1.00 subject to a provision that allows for increases to 5.50 to 1.00 in
connection with certain acquisitions. The Funded Debt Ratio is calculated by dividing consolidated
debt by annualized EBITDA, which is defined in the Credit Facility as earnings before interest,
taxes, depreciation, depletion and amortization, in each case excluding the income of certain of
our majority-owned subsidiaries and equity investments (but including distributions from those
majority-owned subsidiaries and equity investments). At March 31, 2011, our Funded Debt Ratio was
22
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
approximately 4.48 to 1.00. As permitted by the Credit Facility, the $235.0 million of
borrowings by Buckeye Energy Services LLC (BES) under its separate credit agreement (discussed
below) was excluded from the calculation of the Funded Debt Ratio.
In addition, the Credit Facility contains other covenants including, but not limited to,
covenants limiting our ability to incur additional indebtedness, to create or incur liens on our
property, to dispose of property material to our operations, and to consolidate, merge or transfer
assets. At March 31, 2011, we were not aware of any instances of noncompliance with the covenants
under our Credit Facility.
At March 31, 2011 and December 31, 2010, we had committed $1.5 million and $1.4 million,
respectively, in support of letters of credit. The obligations for letters of credit are not
reflected as debt on our condensed consolidated balance sheets.
BES Credit Agreement
BES has a credit agreement (the BES Credit Agreement) that provides for borrowings of up to
$500.0 million with a maturity date of June 25, 2013. The maximum amount available to be borrowed
under the BES Credit Agreement is initially limited to $350.0 million. An accordion feature
provides BES the ability to increase the commitments under the BES Credit Agreement to $500.0
million, subject to obtaining the requisite commitments and satisfying other customary conditions.
In addition to the accordion, subject to BESs satisfaction of certain financial covenants as set
forth in the financial covenants table below, BES may, from time to time, elect to increase or
decrease the maximum amount available for borrowing under the BES Credit Agreement in $5.0 million
increments, but in no event below $150.0 million or above $500.0 million.
Under the BES Credit Agreement, borrowings accrue interest under one of three rate options, at
BESs election, equal to (i) the Administrative Agents Cost of Funds (as defined in the BES Credit
Agreement) plus 2.25%, (ii) the Eurodollar Rate (as defined in the BES Credit Agreement) plus 2.25%
or (iii) the Prime Rate (as defined in the BES Credit Agreement) plus 1.25%. The BES Credit
Agreement also permits Daylight Overdraft Loans (as defined in the BES Credit Agreement), Swingline
Loans (as defined in the BES Credit Agreement) and letters of credit. Such alternative extensions
of credit are subject to certain conditions as specified in the BES Credit Agreement. The BES
Credit Agreement is secured by liens on certain assets of BES, including its inventory, cash
deposits (other than certain accounts), investments and hedging accounts, receivables and
intangibles.
The balances outstanding under the BES Credit Agreement were approximately $235.0 million and
$284.3 million at March 31, 2011 and December 31, 2010, respectively, both of which were classified
as current liabilities in our condensed consolidated balance sheets due to the borrowing terms set
forth in the BES Credit Agreement. The BES Credit Agreement requires BES to meet certain financial
covenants, which are defined in the BES Credit Agreement and summarized below (in millions, except
for the leverage ratio):
|
|
|
|
|
|
|
Borrowings |
|
Minimum |
|
Minimum |
|
Maximum |
outstanding on |
|
Consolidated Tangible |
|
Consolidated Net |
|
Consolidated |
BES Credit Agreement |
|
Net Worth |
|
Working Capital |
|
Leverage Ratio |
$150
|
|
$40
|
|
$30
|
|
7.0 to 1.0 |
Above $150 up to $200
|
|
$50
|
|
$40
|
|
7.0 to 1.0 |
Above $200 up to $250
|
|
$60
|
|
$50
|
|
7.0 to 1.0 |
Above $250 up to $300
|
|
$72
|
|
$60
|
|
7.0 to 1.0 |
Above $300 up to $350
|
|
$84
|
|
$70
|
|
7.0 to 1.0 |
Above $350 up to $400
|
|
$96
|
|
$80
|
|
7.0 to 1.0 |
Above $400 up to $450
|
|
$108
|
|
$90
|
|
7.0 to 1.0 |
Above $450 up to $500
|
|
$120
|
|
$100
|
|
7.0 to 1.0 |
23
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
At March 31, 2011, BESs Consolidated Tangible Net Worth and Consolidated Net Working Capital
were $120.9 million and $72.8 million, respectively, and the Consolidated Leverage Ratio was 2.8 to
1.0. The weighted average interest rate for borrowings outstanding under the BES Credit Agreement
was 2.5% at March 31, 2011.
In addition, the BES Credit Agreement contains other covenants, including, but not limited to,
covenants limiting BESs ability to incur additional indebtedness, to create or incur certain liens
on its property, to consolidate, merge or transfer its assets, to make dividends or distributions,
to dispose of its property, to make investments, to modify its risk management policy, or to engage
in business activities materially different from those presently conducted. At March 31, 2011, we
were not aware of any instances of noncompliance with the covenants under the BES Credit Agreement.
12. OTHER NON-CURRENT LIABILITIES
Other non-current liabilities consist of the following at the dates indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2011 |
|
|
2010 |
|
Accrued employee benefit liabilities (see Note 15) |
|
$ |
47,773 |
|
|
$ |
49,170 |
|
Accrued environmental liabilities |
|
|
26,651 |
|
|
|
20,346 |
|
Deferred consideration |
|
|
18,014 |
|
|
|
16,415 |
|
Deferred rent |
|
|
14,423 |
|
|
|
13,393 |
|
Uncertain tax position liability (see Note 2) |
|
|
17,720 |
|
|
|
17,720 |
|
Unfavorable storage contracts (1) |
|
|
46,820 |
|
|
|
|
|
Other |
|
|
8,834 |
|
|
|
10,999 |
|
|
|
|
|
|
|
|
Total other non-current liabilities |
|
$ |
180,235 |
|
|
$ |
128,043 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
In determining fair value of assets and liabilities acquired in the BORCO acquisition
(see Note 2), we allocated negative fair values to certain unfavorable storage contracts at
the date of acquisition and recorded them as current and long-term liabilities in the
condensed consolidated balance sheet. The unfavorable storage contracts are being
recognized in revenues based on the estimated realization of the fair value established on
the acquisition date over the contractual life. See Note 10 for the current portion of
unfavorable storage contracts. |
13. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
The following table presents the components of accumulated other comprehensive income (loss)
(AOCI) on the condensed consolidated balance sheets at the dates indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2011 |
|
|
2010 |
|
Adjustments to funded status of retirement income guarantee plan and retiree medical plan |
|
$ |
(10,323 |
) |
|
$ |
(10,323 |
) |
Amortization of interest rate swap |
|
|
(6,548 |
) |
|
|
(6,789 |
) |
Derivative instruments |
|
|
7,750 |
|
|
|
3,144 |
|
Gain on settlement of treasury lock, net of amortization |
|
|
489 |
|
|
|
|
|
Accumulated amortization of retirement income guarantee plan and retiree medical plan |
|
|
(7,401 |
) |
|
|
(7,291 |
) |
|
|
|
|
|
|
|
Total accumulated other comprehensive loss |
|
$ |
(16,033 |
) |
|
$ |
(21,259 |
) |
|
|
|
|
|
|
|
24
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
14. DERIVATIVE INSTRUMENTS, HEDGING ACTIVITIES AND FAIR VALUE MEASUREMENTS
We are exposed to certain risks, including changes in interest rates and commodity prices, in
the course of our normal business operations. We use derivative instruments to manage risks
associated with certain identifiable and anticipated transactions. Derivatives are financial
instruments whose fair value is determined by changes in a specified benchmark such as interest
rates or commodity prices. Typical derivative instruments include futures, forward contracts,
swaps and other instruments with similar characteristics. We have no trading derivative
instruments.
Our policy is to formally document all relationships between hedging instruments and hedged
items, as well as our risk management objectives and strategies for undertaking the hedge. This
process includes specific identification of the hedging instrument and the hedged transaction, the
nature of the risk being hedged and how the hedging instruments effectiveness will be assessed.
Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives used
in a transaction are highly effective in offsetting changes in cash flows or the fair value of
hedged items. A discussion of our derivative activities by risk category follows.
Interest Rate Derivatives
We utilize forward-starting interest rate swaps to manage interest rate risk related to
forecasted interest payments on anticipated debt issuances. This strategy is a component in
controlling our cost of capital associated with such borrowings. When entering into interest rate
swap transactions, we become exposed to both credit risk and market risk. We are subject to credit
risk when the value of the swap transaction is positive and the risk exists that the counterparty
will fail to perform under the terms of the contract. We are subject to market risk with respect
to changes in the underlying benchmark interest rate that impacts the fair value of the swaps. We
manage our credit risk by only entering into swap transactions with major financial institutions
with investment-grade credit ratings. We manage our market risk by associating each swap
transaction with an existing debt obligation or a specified expected debt issuance generally
associated with the maturity of an existing debt obligation.
Our practice with respect to derivative transactions related to interest rate risk has been to
have each transaction in connection with non-routine borrowings authorized by the board of
directors of Buckeye GP. In January 2009, Buckeye GPs board of directors adopted an interest rate
hedging policy which permits us to enter into certain short-term interest rate swap agreements to
manage our interest rate and cash flow risks associated with the Credit Facility. In addition, in
July 2009 and May 2010, Buckeye GPs board of directors authorized us to enter into certain
transactions, such as forward-starting interest rate swaps, to manage our interest rate and cash
flow risks related to certain expected debt issuances associated with the maturity of existing debt
obligations.
We expect to issue new fixed-rate debt (i) on or before July 15, 2013 to repay the $300.0
million of 4.625% Notes that are due on July 15, 2013 and (ii) on or before October 15, 2014 to
repay the $275.0 million of 5.300% Notes that are due on October 15, 2014, although no assurances
can be given that the issuance of fixed-rate debt will be possible on acceptable terms. We have
entered into six forward-starting interest rate swaps with a total aggregate notional amount of
$300.0 million related to the anticipated issuance of debt on or before July 15, 2013 and six
forward-starting interest rate swaps with a total aggregate notional amount of $275.0 million
related to the anticipated issuance of debt on or before October 15, 2014. The purpose of these
swaps is to hedge the variability of the forecasted interest payments on these expected debt
issuances that may result from changes in the benchmark interest rate until the expected debt is
issued. During the three months ended March 31, 2011 and 2010, unrealized gains of $4.5 million
and unrealized losses of $1.3 million, respectively, were recorded in accumulated other
comprehensive income (loss) to reflect the change in the fair values of the forward-starting
interest rate swaps. We designated the swap agreements as cash flow hedges at inception and expect
the changes in values to be highly correlated with the changes in value of the underlying
borrowings.
On January 13, 2011, we sold the 4.875% Notes in an underwritten public offering. In December
2010, in connection with the proposed offering, we entered into a treasury lock agreement to fix
the 10-year treasury rate at 3.3375% per annum on a notional amount of $650.0 million. In January
2011, we subsequently cash-settled the
25
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
treasury lock agreement upon the issuance of the 4.875%
Notes and received approximately $0.5 million, which is being recognized as a reduction to interest
expense over the term of the 4.875% Notes.
Over the next twelve months, we expect to reclassify $0.9 million of net losses, consisting of
loss attributable to forward-starting interest rate swaps terminated in 2008 associated with our
6.050% Notes, partially offset by a gain attributable to the settlement of the treasury lock
agreement associated with the 4.875% Notes in January 2011, from accumulated other comprehensive
loss to earnings as an increase to interest and debt expense.
Commodity Derivatives
Our Energy Services segment primarily uses exchange-traded refined petroleum product futures
contracts to manage the risk of market price volatility on its refined petroleum product
inventories and its physical commodity forward fixed-price purchase and sales contracts. The
derivative contracts used to hedge refined petroleum product inventories are designated as fair
value hedges. Accordingly, our method of measuring ineffectiveness compares the change in the fair
value of New York Mercantile Exchange (NYMEX) futures contracts to the change in fair value of
our hedged fuel inventory. Hedge accounting is discontinued when the hedged fuel inventory is sold
or when the related derivative contracts expire. In addition, we periodically enter into
offsetting exchange-traded futures contracts to economically close-out an existing futures contract
based on a near-term expectation to sell a portion of our fuel inventory. These offsetting
derivative contracts are not designated as hedging instruments and any resulting gains or losses
are recognized in earnings during the period. The fair values of futures contracts for inventory
designated as hedging instruments in the following tables have been presented net of these
offsetting futures contracts.
Our Energy Services segment has not used hedge accounting with respect to its fixed-price
contracts. Therefore, our fixed-price contracts and the related futures contracts used to offset
the changes in fair value of the fixed-price sales contracts are all marked-to-market on the
condensed consolidated balance sheets with gains and losses being recognized in earnings during the
period.
In order to hedge the cost of natural gas used to operate our turbine engines at our Linden,
New Jersey location, our Pipelines & Terminals segment bought natural gas futures contracts in
March 2009 with terms that coincide with the remaining term of an ongoing natural gas supply
contract (through July 2011). We designated the futures contracts as cash flow hedges at
inception.
The following table summarizes our commodity derivative instruments outstanding at March 31,
2011 (amounts in thousands of gallons, except as noted):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (1) |
|
|
Accounting |
|
Derivative Purpose |
|
Current |
|
|
Long-Term (2) |
|
|
Treatment |
|
Derivatives
NOT designated as hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
Physical derivative contracts |
|
|
6,632 |
|
|
|
|
|
|
Mark-to-market |
Futures contracts for refined products |
|
|
4,530 |
|
|
|
252 |
|
|
Mark-to-market |
|
Derivatives
designated as hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
Futures contracts for refined products |
|
|
72,660 |
|
|
|
|
|
|
Fair Value Hedge |
Futures contracts for natural gas (BBtu) (3) |
|
|
120 |
|
|
|
|
|
|
Cash Flow Hedge |
|
|
|
(1) |
|
Volume represents absolute value of net notional volume position. |
|
(2) |
|
The maximum term for derivatives included in the long-term column is June 2012. |
|
(3) |
|
BBtu represents one billion British thermal units. |
26
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table sets forth the fair value of each classification of derivative instruments
at the dates indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2011 |
|
|
|
Derivatives |
|
|
Derivatives |
|
|
|
|
|
|
Netting |
|
|
|
|
|
|
NOT Designated |
|
|
Designated |
|
|
Derivative |
|
|
Balance |
|
|
|
|
|
|
as Hedging |
|
|
as Hedging |
|
|
Carrying |
|
|
Sheet |
|
|
|
|
|
|
Instruments |
|
|
Instruments |
|
|
Value |
|
|
Adjustment |
|
|
Total |
|
Physical derivative contracts for
refined products |
|
$ |
1,247 |
|
|
$ |
|
|
|
$ |
1,247 |
|
|
$ |
|
|
|
$ |
1,247 |
|
Futures contracts for refined
products |
|
|
3,054 |
|
|
|
|
|
|
|
3,054 |
|
|
|
(3,054 |
) |
|
|
|
|
Futures contracts for natural gas |
|
|
|
|
|
|
28 |
|
|
|
28 |
|
|
|
(28 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current derivative assets |
|
|
4,301 |
|
|
|
28 |
|
|
|
4,329 |
|
|
|
(3,082 |
) |
|
|
1,247 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate derivatives |
|
|
|
|
|
|
8,320 |
|
|
|
8,320 |
|
|
|
(456 |
) |
|
|
7,864 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total non-current derivative assets |
|
|
|
|
|
|
8,320 |
|
|
|
8,320 |
|
|
|
(456 |
) |
|
|
7,864 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Physical derivative contracts for
refined products |
|
|
(2,508 |
) |
|
|
|
|
|
|
(2,508 |
) |
|
|
|
|
|
|
(2,508 |
) |
Futures contracts for refined
products |
|
|
(2,134 |
) |
|
|
(5,209 |
) |
|
|
(7,343 |
) |
|
|
3,054 |
|
|
|
(4,289 |
) |
Futures contracts for natural gas |
|
|
|
|
|
|
(144 |
) |
|
|
(144 |
) |
|
|
28 |
|
|
|
(116 |
) |
Interest rate derivatives |
|
|
|
|
|
|
(456 |
) |
|
|
(456 |
) |
|
|
456 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current derivative liabilities |
|
|
(4,642 |
) |
|
|
(5,809 |
) |
|
|
(10,451 |
) |
|
|
3,538 |
|
|
|
(6,913 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net derivative assets/(liabilities) |
|
$ |
(341 |
) |
|
$ |
2,539 |
|
|
$ |
2,198 |
|
|
$ |
|
|
|
$ |
2,198 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010 |
|
|
|
Derivatives |
|
|
Derivatives |
|
|
|
|
|
|
Netting |
|
|
|
|
|
|
NOT Designated |
|
|
Designated |
|
|
Derivative |
|
|
Balance |
|
|
|
|
|
|
as Hedging |
|
|
as Hedging |
|
|
Carrying |
|
|
Sheet |
|
|
|
|
|
|
Instruments |
|
|
Instruments |
|
|
Value |
|
|
Adjustment |
|
|
Total |
|
Physical derivative contracts for
refined products |
|
$ |
1,552 |
|
|
$ |
|
|
|
$ |
1,552 |
|
|
$ |
(30 |
) |
|
$ |
1,522 |
|
Futures contracts for refined
products |
|
|
36,916 |
|
|
|
|
|
|
|
36,916 |
|
|
|
(36,804 |
) |
|
|
112 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current derivative assets |
|
|
38,468 |
|
|
|
|
|
|
|
38,468 |
|
|
|
(36,834 |
) |
|
|
1,634 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate derivatives |
|
|
|
|
|
|
5,351 |
|
|
|
5,351 |
|
|
|
(1,459 |
) |
|
|
3,892 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term derivative assets |
|
|
|
|
|
|
5,351 |
|
|
|
5,351 |
|
|
|
(1,459 |
) |
|
|
3,892 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Physical derivative contracts for
refined products |
|
|
(3,930 |
) |
|
|
|
|
|
|
(3,930 |
) |
|
|
30 |
|
|
|
(3,900 |
) |
Futures contracts for refined
products |
|
|
(21,368 |
) |
|
|
(28,071 |
) |
|
|
(49,439 |
) |
|
|
36,804 |
|
|
|
(12,635 |
) |
Futures contracts for natural gas |
|
|
|
|
|
|
(206 |
) |
|
|
(206 |
) |
|
|
|
|
|
|
(206 |
) |
Interest rate derivatives |
|
|
|
|
|
|
(2,003 |
) |
|
|
(2,003 |
) |
|
|
1,459 |
|
|
|
(544 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current derivative liabilities |
|
|
(25,298 |
) |
|
|
(30,280 |
) |
|
|
(55,578 |
) |
|
|
38,293 |
|
|
|
(17,285 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net derivative assets/(liabilities) |
|
$ |
13,170 |
|
|
$ |
(24,929 |
) |
|
$ |
(11,759 |
) |
|
$ |
|
|
|
$ |
(11,759 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
27
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table sets forth the location of derivative instruments on our condensed
consolidated balance sheets at the dates indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2011 |
|
|
2010 |
|
Derivative assets |
|
$ |
1,247 |
|
|
$ |
1,634 |
|
Other non-current assets |
|
|
7,864 |
|
|
|
3,892 |
|
Derivative liabilities |
|
|
(6,913 |
) |
|
|
(17,285 |
) |
|
|
|
|
|
|
|
Total |
|
$ |
2,198 |
|
|
$ |
(11,759 |
) |
|
|
|
|
|
|
|
Our hedged inventory portfolio extends to the third quarter of 2011. The majority of the
unrealized loss of $5.2 million at March 31, 2011 for futures contracts designated as inventory
hedging instruments and unrealized gains in the fair values of the underlying hedged refined
petroleum product inventories will be realized by the second quarter of 2011 as the inventory is
sold. Gains of $4.0 million and $4.8 million were recorded on inventory hedges that were
ineffective for the three months ended March 31, 2011 and 2010, respectively. The time value
component of the derivative instruments fair value was excluded from our hedge assessment and
losses of $10.5 million and $16.2 million were recorded for the three months ended March 31, 2011
and 2010, respectively. At March 31, 2011, open refined petroleum product derivative contracts
(represented by the fixed-price contracts and futures contracts for fixed-price sales contracts
noted above) varied in duration, but did not extend beyond June 2012. In addition, at March 31,
2011, 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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (Loss) Recognized |
|
|
|
|
|
|
|
in Income on Derivatives |
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
|
|
|
|
March 31, |
|
|
|
Location |
|
|
2011 |
|
|
2010 |
|
Derivatives NOT designated as
hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Physical derivative contracts for refined products |
|
Product sales |
|
$ |
(3,791 |
) |
|
$ |
2,410 |
|
Physical derivative contracts for refined products |
|
Cost of product sales and natural gas storage services |
|
|
1,035 |
|
|
|
|
|
Futures contracts for refined products |
|
Cost of product sales and natural gas storage services |
|
|
(2,149 |
) |
|
|
(248 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives designated as fair
value hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Futures contracts for refined products |
|
Cost of product sales and natural gas storage services |
|
$ |
(56,900 |
) |
|
$ |
(4,910 |
) |
28
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The gains and losses reclassified from AOCI to income and the change in value recognized in
other comprehensive income (OCI) on our derivatives were as follows for the periods indicated (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (Loss) Reclassified |
|
|
|
|
|
|
|
from AOCI to Income |
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
|
|
|
|
March 31, |
|
|
|
Location |
|
|
2011 |
|
|
2010 |
|
Derivatives designated as cash
flow hedging instruments: |
|
|
|
|
|
|
|
|
Futures contracts for natural gas |
|
Cost of product sales and natural gas storage services |
|
$ |
(120 |
) |
|
$ |
(72 |
) |
Interest rate contracts |
|
Interest and debt expense |
|
|
(233 |
) |
|
|
(240 |
) |
|
|
|
|
|
|
|
|
|
|
|
Change in Value Recognized |
|
|
|
in OCI on Derivatives |
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2011 |
|
|
2010 |
|
Derivatives
designated as cash flow hedging instruments: |
|
|
|
|
|
|
|
|
Futures contracts for natural gas |
|
$ |
(29 |
) |
|
$ |
(696 |
) |
Interest rate contracts |
|
|
5,012 |
|
|
|
(1,304 |
) |
Fair Value Measurements
Fair value is defined as the price that would be received to sell an asset or paid to transfer
a liability in an orderly transaction between market participants at a specified measurement date.
Our fair value estimates are based on either (i) actual market data or (ii) assumptions that other
market participants would use in pricing an asset or liability, including estimates of risk.
Recognized valuation techniques employ inputs such as product prices, operating costs, discount
factors and business growth rates. These inputs may be readily observable, corroborated by market
data or generally unobservable. In developing our estimates of fair value, we endeavor to utilize
the best information available and apply market-based data to the extent possible. Accordingly, we
utilize valuation techniques (such as the income or market approach) that maximize the use of
observable inputs and minimize the use of unobservable inputs.
A three-tier hierarchy has been established that classifies fair value amounts recognized or
disclosed in the financial statements based on the observability of inputs used to estimate such
fair values. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and
2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3).
At each balance sheet reporting date, we categorize our financial assets and liabilities using
this hierarchy. The characteristics of fair value amounts classified within each level of the
hierarchy are described as follows:
|
|
|
Level 1 inputs are based on quoted prices, which are available in active markets for
identical assets or liabilities as of the reporting date. Active markets are defined
as those in which transactions for identical assets or liabilities occur with
sufficient frequency and volume to provide pricing information on an ongoing basis. |
|
|
|
|
Level 2 inputs are based on pricing inputs other than quoted prices in active
markets and are either directly or indirectly observable as of the measurement date.
Level 2 fair values include instruments that are valued using financial models or other
appropriate valuation methodologies and include the following: |
29
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
Quoted prices in active markets for similar assets or liabilities. |
|
|
|
|
Quoted prices in markets that are not active for identical or similar assets or
liabilities. |
|
|
|
|
Inputs other than quoted prices that are observable for the asset or liability. |
|
|
|
|
Inputs that are derived primarily from or corroborated by observable market data
by correlation or other means. |
|
|
|
Level 3 inputs are based on unobservable inputs for the asset or liability.
Unobservable inputs are used to measure fair value to the extent that observable inputs
are not available, thereby allowing for situations in which there is little, if any,
market activity for the asset or liability at the measurement date. Unobservable
inputs reflect the reporting entitys own ideas about the assumptions that market
participants would use in pricing an asset or liability (including assumptions about
risk). Unobservable inputs are based on the best information available in the
circumstances, which might include the reporting entitys internally developed data.
The reporting entity must not ignore information about market participant assumptions
that is reasonably available without undue cost and effort. Level 3 inputs are
typically used in connection with internally developed valuation methodologies where
management makes its best estimate of an instruments fair value. |
Recurring
The following table sets forth financial assets and liabilities, measured at fair value on a
recurring basis, as of the measurement dates, March 31, 2011 and December 31, 2010, and the basis
for that measurement, by level within the fair value hierarchy (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2011 |
|
|
December 31, 2010 |
|
|
|
|
|
|
|
Significant |
|
|
|
|
|
|
Significant |
|
|
|
Quoted Prices |
|
|
Other |
|
|
Quoted Prices |
|
|
Other |
|
|
|
in Active |
|
|
Observable |
|
|
in Active |
|
|
Observable |
|
|
|
Markets |
|
|
Inputs |
|
|
Markets |
|
|
Inputs |
|
|
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 1) |
|
|
(Level 2) |
|
Financial assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Physical derivative contracts
for refined products |
|
$ |
|
|
|
$ |
1,247 |
|
|
$ |
|
|
|
$ |
1,522 |
|
Futures contracts for refined
products |
|
|
|
|
|
|
|
|
|
|
112 |
|
|
|
|
|
Interest rate derivatives |
|
|
|
|
|
|
7,864 |
|
|
|
|
|
|
|
3,892 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Physical derivative contracts
for refined products |
|
|
|
|
|
|
(2,508 |
) |
|
|
|
|
|
|
(3,900 |
) |
Futures contracts for refined
products |
|
|
(4,289 |
) |
|
|
|
|
|
|
(12,635 |
) |
|
|
|
|
Futures contracts for natural gas |
|
|
(116 |
) |
|
|
|
|
|
|
(206 |
) |
|
|
|
|
Interest rate derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(544 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value |
|
$ |
(4,405 |
) |
|
$ |
6,603 |
|
|
$ |
(12,729 |
) |
|
$ |
970 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The values of the Level 1 derivative assets and liabilities were based on quoted market prices
obtained from the NYMEX.
The values of the Level 2 interest rate derivatives were determined using expected cash flow
models, which incorporated market inputs including the implied forward LIBOR yield curve for the
same period as the future interest swap settlements.
30
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The values of the Level 2 fixed-price contracts assets and liabilities were calculated using
market approaches based on observable market data inputs, including published commodity pricing
data, which is verified against other available market data, and market interest rate and
volatility data. Level 2 fixed-price contracts assets are net of credit value adjustments (CVA)
determined using an expected cash flow model, which incorporates assumptions about the credit risk
of the fixed-price contracts based on the historical and expected payment history of each customer,
the amount of product contracted for under the agreement and the customers historical and expected
purchase performance under each contract. The Energy Services segment determined CVA is
appropriate because few of the Energy Services segments customers entering into these fixed-price
contracts are large organizations with nationally-recognized credit ratings. The Level 2
fixed-price contracts assets of $1.2 million and $1.5 million as of March 31, 2011 and December 31,
2010, respectively, are net of CVA of ($0.1) million and ($0.2) million, respectively. As of March
31, 2011, the Energy Services segment did not hold any net liability derivative position containing
credit contingent features.
Non-Recurring
Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis
and are subject to fair value adjustments in certain circumstances, such as when there is evidence
of possible impairment. There were no fair value adjustments for such assets or liabilities
reflected in our condensed consolidated financial statements for the three months ended March 31,
2011 and 2010.
15. PENSIONS AND OTHER POSTRETIREMENT BENEFITS
Services Company, which employs the majority of our workforce, sponsors a retirement income
guarantee plan (RIGP), which is a defined benefit plan that generally guarantees employees hired
before January 1, 1986 a retirement benefit based on years of service and the employees highest
compensation for any consecutive 5-year period during the last 10 years of service or other
compensation measures as defined under the respective plan provisions. The retirement benefit is
subject to reduction at varying percentages for certain offsetting amounts, including benefits
payable under a retirement and savings plan discussed further below. Services Company funds the
plan through contributions to pension trust assets, generally subject to minimum funding
requirements as provided by applicable law.
Services Company also sponsors an unfunded post-retirement benefit plan (the Retiree Medical
Plan), which provides health care and life insurance benefits to certain of its retirees. To be
eligible for these benefits, an employee must have been hired prior to January 1, 1991 and meet
certain service requirements.
The components of the net periodic benefit cost for the RIGP and Retiree Medical Plan were as
follows for the three months ended March 31, 2011 and 2010 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RIGP |
|
|
Retiree Medical Plan |
|
|
|
Three Months Ended |
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
March 31, |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
Service cost |
|
$ |
63 |
|
|
$ |
68 |
|
|
$ |
86 |
|
|
$ |
30 |
|
Interest cost |
|
|
200 |
|
|
|
232 |
|
|
|
457 |
|
|
|
205 |
|
Expected return on plan assets |
|
|
(106 |
) |
|
|
(88 |
) |
|
|
|
|
|
|
|
|
Amortization of prior service benefit |
|
|
|
|
|
|
(12 |
) |
|
|
(741 |
) |
|
|
(307 |
) |
Amortization of unrecognized losses |
|
|
337 |
|
|
|
248 |
|
|
|
294 |
|
|
|
93 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit costs |
|
$ |
494 |
|
|
$ |
448 |
|
|
$ |
96 |
|
|
$ |
21 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
During the three months ended March 31, 2011, we contributed $2.0 million to the RIGP.
31
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
16. UNIT-BASED COMPENSATION PLANS
BGH GP has an equity compensation plan (BGH GP Equity Compensation Plan) for certain members
of BGH GPs senior management, who also serve as our senior management. Compensation expense
recorded with respect to the BGH GP Equity Compensation Plan was $0 and $0.3 million for the three
months ended March 31, 2011 and 2010, respectively.
We award unit-based compensation to employees and directors primarily under the 2009 Long-Term
Incentive Plan of Buckeye Partners, L.P. (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 $2.1 million and $0.9 million for the three months ended March 31, 2011 and 2010,
respectively. These compensation plans are discussed below.
BGH GPs Override Units
Effective on June 25, 2007, BGH GP instituted an Equity Compensation Plan for certain members
of senior management. This Equity Compensation Plan included both time-based and
performance-based participation in the equity of BGH GP (but not ours) referred to as override
units. These override units consisted of three equal tranches of units consisting of Value A,
Value B and Operating Units. We are required to record, as compensation expense and a
corresponding contribution to unitholders equity, the fair value of the compensation. We are not
the sponsor of this plan and have no obligations with respect to it. For the three months ended
March 31, 2010, compensation expense related to the Operating Units was $0.3 million.
On December 31, 2010, the override unit plan was modified. All outstanding Value A
and Operating Units were exchanged for LP Units.
The terms of the Value B Units remained unchanged. The Value B Units
will participate in distributions by BGH GP based on the occurrence
of an exit event and an investment return of 3.5 times the original investment and an internal rate
of return of at least 10% or on a pro-rata basis on an investment return ranging from 2.0 to 3.5
times the original investment and an internal rate of return of at least 10%.
On
January 27, 2011, BGH GP established and granted new override units in BGH GP
to a member of senior management, which consisted of Value N-1 and Value N-2 Units. The Value N-1
Units will participate in distributions by BGH GP based on the occurrence of an exit event and an investment return of 2.0 times the
original investment up to aggregate distributions of $3.0 million. The Value N-2 Units will participate in distributions by BGH GP based
on the occurrence of an exit event and an investment return of 2.5 times the original investment or
on a pro-rata basis on an investment return ranging from 2.0 to 2.5 times the original investment
up to aggregate distributions of $5.0 million.
The exit event with respect to the Value B, Value N-1 and Value N-2 Units is generally defined
as the sale by ArcLight, Kelso and their affiliates of their interests in BGH GP, the sale of
substantially all the assets of BGH GP and its subsidiaries, or any other extraordinary
transaction that the Board of Directors of BGH GP determines is an exit event.
The investment return is calculated generally as the sum of all the distributions that
ArcLight and Kelso have received from BGH GP prior to and through the exit event, divided by the
total amount of capital contributions to BGH GP that ArcLight and Kelso have made prior to the exit
event.
The cumulative grant date fair values of the Value B, Value N-1 and Value N-2 Units that
remained unvested as of March 31, 2011 are $2.2 million, $0.9 million and $1.1 million,
respectively. The vesting of the override units is contingent on a performance condition, namely
the completion of the exit event, and a market condition, primarily relating to the receipt of an
investment return at a specified multiple and internal rate of return, where applicable.
Accordingly, no compensation expense for these override units will be recorded until, and if, an
exit event and other requirements occur.
32
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
At grant date, the override units were valued using the Monte Carlo simulation method that
incorporated the market-based vesting condition into the grant date fair value of the unit awards.
The following assumptions were used for grants of the Value N-1 and N-2 Units during the period:
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, 2011 |
|
Equity value
in BGH GP (in millions) |
|
$ |
410.7 |
|
Expected life in years |
|
|
1 |
|
Risk-free interest rate |
|
|
0.25 |
% |
Volatility |
|
|
25 |
% |
LTIP
The LTIP provides for the issuance of up to 1,500,000 LP Units, subject to certain
adjustments. After giving effect to the issuance or forfeiture of phantom unit and performance
unit awards through March 31, 2011, awards representing a total of 883,449 additional LP Units
could be issued under the LTIP.
Under the terms of the Buckeye Partners, L.P. Unit Deferral and Incentive Plan (Deferral
Plan), eligible employees were allowed to defer up to 50% of their 2011 and 2010 compensation
award under our Annual Incentive Compensation Plan or other discretionary bonus program in exchange
for grants of phantom units equal in value to the amount of their cash award deferral (each such
unit, a Deferral Unit). Participants also receive one matching phantom unit for each Deferral
Unit. Approximately $1.6 million of 2010 compensation awards had been deferred at December 31,
2010, for which 50,660 phantom units (including matching units) were granted during the three
months ended March 31, 2011. These grants are included as granted in the LTIP activity table
below.
Awards under the LTIP
During the three months ended March 31, 2011, the Compensation Committee granted 107,576
phantom units to employees (including the 50,660 phantom units granted pursuant to the Deferral
Plan discussed above), 12,000 phantom units to independent directors of Buckeye GP and MainLine
Management, and 115,558 performance units to employees. The amount paid with respect to phantom
unit distribution equivalents under the LTIP was $0.3 million and $0.2 million for the three months
ended March 31, 2011 and 2010, respectively.
The following table sets forth the LTIP activity for the periods indicated (dollars in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
|
|
|
|
|
Grant Date |
|
|
|
|
|
|
|
|
|
|
|
Fair Value |
|
|
|
|
|
|
|
Number of |
|
|
per LP Unit |
|
|
|
|
|
|
LP Units |
|
|
(1) |
|
|
Total Value |
|
Unvested at January 1, 2011 |
|
|
364,913 |
|
|
$ |
51.11 |
|
|
$ |
18,650 |
|
Granted |
|
|
235,134 |
|
|
|
64.96 |
|
|
|
15,275 |
|
Vested |
|
|
(14,610 |
) |
|
|
55.35 |
|
|
|
(808 |
) |
Forfeited |
|
|
(2,657 |
) |
|
|
55.06 |
|
|
|
(146 |
) |
|
|
|
|
|
|
|
|
|
|
|
Unvested at March 31, 2011 |
|
|
582,780 |
|
|
$ |
56.58 |
|
|
$ |
32,971 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Determined by dividing the aggregate grant date fair value of awards by the number of awards
issued. The weighted-average grant date fair value per LP Unit for forfeited and vested
awards is determined before an allowance for forfeitures. |
At March 31, 2011, approximately $21.4 million of compensation expense related to the LTIP is
expected to be recognized over a weighted average period of approximately 2.0 years.
33
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Unit Option and Distribution Equivalent Plan
The following is a summary of the changes in the LP Unit options outstanding (all of which are
vested or are expected to vest) under the Option Plan for the periods indicated (dollars in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted- |
|
|
|
|
|
|
|
|
|
|
Weighted- |
|
|
Average |
|
|
|
|
|
|
|
|
|
|
Average |
|
|
Remaining |
|
|
Aggregate |
|
|
|
Number of |
|
|
Strike Price |
|
|
Contractual |
|
|
Intrinsic |
|
|
|
LP Units |
|
|
($/LP Unit) |
|
|
Term (in years) |
|
|
Value (1) |
|
Outstanding at January 1, 2011 |
|
|
241,800 |
|
|
$ |
47.04 |
|
|
|
|
|
|
|
|
|
Exercised |
|
|
(5,500 |
) |
|
|
49.13 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at March 31, 2011 |
|
|
236,300 |
|
|
|
46.99 |
|
|
|
5.5 |
|
|
$ |
3,911 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at March 31, 2011 |
|
|
231,300 |
|
|
$ |
47.33 |
|
|
|
5.5 |
|
|
$ |
3,749 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 2011 and the exercise price, multiplied by the number of
exercisable, in-the-money options. |
The total intrinsic value of options exercised was $0.1 million and $0.8 million during the
three months ended March 31, 2011 and 2010, respectively. At March 31, 2011, total unrecognized
compensation cost related to unvested LP Unit options was minimal. We expect to recognize this
remaining cost over a weighted average period of 0.7 years. At March 31, 2011, 333,000 LP Units
were available for grant in connection with the Option Plan. However, with the adoption of the
LTIP, we do not expect to make any future grants pursuant to the Option Plan. The fair value of
options vested was $0.3 million and $0.4 million during the three months ended March 31, 2011 and
2010, respectively.
17. RELATED PARTY TRANSACTIONS
We are managed by Buckeye GP, our general partner. Services Company is considered a related
party with respect to us. As discussed in Note 1, our consolidated financial statements include
the financial results of Services Company on a consolidated basis, and all intercompany
transactions have been eliminated.
Services Company, which is beneficially owned by the ESOP, owned 1.4 million of our LP Units
(approximately 1.8% of our LP Units outstanding) as of March 31, 2011. Distributions received by
Services Company from us on such LP Units are used to fund obligations of the ESOP. Distributions
paid to Services Company totaled $1.4 million and $1.5 million for the three months ended March 31,
2011 and 2010, respectively. Total distributions paid to Services Company decrease over time
because Services Company sells LP Units to fund benefits payable to ESOP participants who exit the
ESOP.
Prior to the Merger, Buckeye GP received incentive distributions from us pursuant to our
partnership agreement and incentive compensation agreement. Incentive distributions were based on
the level of quarterly cash distributions paid per LP Unit and the total number of LP Units
outstanding. Incentive distribution payments totaled $12.3 million during the three months ended
March 31, 2010.
18. PARTNERS CAPITAL AND DISTRIBUTIONS
Our LP Units represent limited partner interests, which give the holders thereof the right to
participate in distributions and to exercise the other rights and privileges available to them
under our partnership agreement. Our partnership agreement provides that, without prior approval
of our limited partners holding an aggregate of at least two-thirds of the outstanding LP Units, we
cannot issue any LP Units of a class or series having preferences or other special or senior rights
over the LP Units. In accordance with our partnership agreement, capital accounts are
34
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
maintained for our general partner and limited partners. In conjunction with the Merger, our
partnership agreement was amended.
Class B Units represent a separate class of our limited partnership interests. The Class B
Units share equally with the LP Units (i) with respect to the payment of distributions and (ii) in
the event of our liquidation. We have the option to pay distributions on the Class B Units with
cash or by issuing additional Class B Units, with the number of Class B Units issued based upon the
volume-weighted average price of the LP Units for the 10 trading days immediately preceding the
date the distributions are declared, less a discount of 15%. The Class B Units have the same
voting rights as if they were outstanding LP Units and are entitled to vote as a separate class on
any matters that materially adversely affect the rights or preferences of the Class B Units in
relation to other classes of partnership interests or as required by law. The Class B Units will
convert into LP Units on a one-for-one basis on the earlier of (a) the date on which at least 4
million barrels of incremental storage capacity are placed in service by BORCO or (b) the third
anniversary of the closing of the BORCO acquisition.
In April 2011, we issued 5,520,000 LP Units, which included 720,000 LP Units issued as part of
the overallotment option, in an underwritten public offering at a public offering price of $59.41
per LP Unit. Total proceeds from the offering, including the overallotment option and after the
underwriters discount of $1.99 per LP Unit and offering expenses, were approximately $317.0
million, and were used to reduce amounts outstanding under our Credit Facility.
Summary of Changes in Outstanding Units
The following is a reconciliation of units outstanding for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited |
|
|
Class B |
|
|
|
|
|
|
Partners |
|
|
Units |
|
|
Total |
|
Units outstanding at December 31, 2010 |
|
|
71,436,099 |
|
|
|
|
|
|
|
71,436,099 |
|
LP Units issued pursuant to the Option Plan |
|
|
5,500 |
|
|
|
|
|
|
|
5,500 |
|
LP Units issued pursuant to the LTIP |
|
|
13,872 |
|
|
|
|
|
|
|
13,872 |
|
Issuance of units to First Reserve and Vopak as
consideration for BORCO acquisition |
|
|
3,104,305 |
|
|
|
5,478,611 |
|
|
|
8,582,916 |
|
Issuance of units to institutional investors (1) |
|
|
5,794,725 |
|
|
|
1,314,870 |
|
|
|
7,109,595 |
|
Issuance of Class B Units in lieu of quarterly
cash distributions |
|
|
|
|
|
|
122,244 |
|
|
|
122,244 |
|
|
|
|
|
|
|
|
|
|
|
Units outstanding at March 31, 2011 |
|
|
80,354,501 |
|
|
|
6,915,725 |
|
|
|
87,270,226 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Proceeds were used to fund a portion of the BORCO acquisition. |
Distributions
We generally make quarterly cash distributions to unitholders of substantially all of our
available cash, generally defined in our partnership agreement as consolidated cash receipts less
consolidated cash expenditures and such retentions for working capital, anticipated cash
expenditures and contingencies as our general partner deems appropriate. Cash distributions on our
LP Units totaled $79.3 million and $61.0 million during the three months ended March 31, 2011 and
2010, respectively. We also paid distributions in kind to our Class B unitholders by issuing
122,244 Class B Units.
On May 6, 2011, we announced a quarterly distribution of $1.00 per LP Unit that will be paid
on May 31, 2011, to unitholders of record on May 16, 2011. Total cash distributed to LP
unitholders on May 31, 2011 will total approximately $85.9 million. We also expect to issue
approximately 130,000 Class B Units to our Class B unitholders in lieu of cash distributions on May
31, 2011.
35
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
19. EARNINGS PER UNIT
Basic and diluted earnings per unit (including earnings per unit for LP Units and Class B
Units) is calculated by dividing net income, after deducting the amount allocated to noncontrolling
interests, by the weighted-average number of LP Units and Class B Units outstanding during the
period.
Pursuant to the Merger Agreement, BGHs unitholders received a total of approximately 20.0
million of Buckeyes LP Units in the aggregate in exchange for all outstanding BGH common units and
management units. As a result, the number of Buckeyes LP Units outstanding increased from 51.6
million to 71.4 million on the date of the Merger. However, for historical reporting purposes, the
impact of this change was accounted for as a reverse split of BGHs units of 0.705 to 1.0, together
with the addition of Buckeyes existing LP Units. Therefore, since BGH was the surviving
accounting entity, the weighted average number of units outstanding used for basic and diluted
earnings per unit calculations are BGHs historical weighted average common units outstanding
adjusted for the reverse unit split and the addition of Buckeyes existing LP Units. Amounts
reflecting historical BGH unit and per unit amounts included in this report have been restated for
the reverse unit split.
The following table is a reconciliation of the weighted average number of units used in the
basic and diluted earnings per unit calculations for the periods indicated (in thousands, except
per unit amounts):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2011 |
|
|
2010 |
|
Net income attributable to Buckeye Partners, L.P. |
|
$ |
66,493 |
|
|
$ |
11,270 |
|
|
|
|
|
|
|
|
|
|
Basic: |
|
|
|
|
|
|
|
|
Weighted average units outstanding |
|
|
83,669 |
|
|
|
19,581 |
|
Weighted average management units outstanding |
|
|
|
|
|
|
371 |
|
|
|
|
|
|
|
|
Units for basic |
|
|
83,669 |
|
|
|
19,952 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per unit basic |
|
$ |
0.79 |
|
|
$ |
0.56 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted: |
|
|
|
|
|
|
|
|
Units used for basic calculation |
|
|
83,669 |
|
|
|
19,952 |
|
Dilutive effect of LP Unit options and LITP awards granted |
|
|
285 |
|
|
|
|
|
|
|
|
|
|
|
|
Units for diluted |
|
|
83,954 |
|
|
|
19,952 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per unit diluted |
|
$ |
0.79 |
|
|
$ |
0.56 |
|
|
|
|
|
|
|
|
20. BUSINESS SEGMENTS
We operate and report in five business segments: Pipelines & Terminals; International
Operations; Natural Gas Storage; Energy Services; and Development & Logistics. Effective January
1, 2011, we realigned our five business segments. We combined the Pipeline Operations and
Terminalling & Storage segments into one segment, the Pipelines & Terminals segment, and moved our
terminal in Yabucoa, Puerto Rico, previously included as part of the Terminalling & Storage
segment, and the BORCO facility to a new International Operations segment. We have
adjusted our quarter-to-quarter comparisons to conform to the current presentation.
Pipelines & Terminals
The Pipelines & Terminals segment receives refined petroleum products from refineries,
connecting pipelines, and bulk and marine terminals and transports those products to other
locations for a fee and provides bulk storage and terminal throughput services in the continental
United States. This segment owns and operates approximately
36
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
5,400
miles of pipeline systems in 15 states. The segment has 62 liquid petroleum products
terminals in 14 states with aggregate storage capacity of approximately 26.3 million barrels.
International Operations
The International Operations segment provides marine bulk storage and marine terminal
throughput services. The segment has two liquid petroleum product terminals, one in Puerto Rico
and one on The Grand Bahama Island in the Bahamas, with an aggregate storage capacity of 26.2
million barrels.
Natural Gas Storage
The Natural Gas Storage segment provides natural gas storage services at a natural gas storage
facility in northern California. The facility has approximately 29 Bcf of working natural gas
storage capacity and is connected to Pacific Gas and Electrics intrastate 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 areas also served by our pipelines and
terminals assets. This segment recognizes revenues when products are
delivered. The segments products include gasoline, propane and petroleum distillates such as
heating oil, diesel fuel and kerosene. The segment also has five terminals with aggregate storage
capacity of approximately 1.0 million barrels. The segments customers consist principally of
product wholesalers as well as major commercial users of these refined petroleum products.
Development & Logistics
The Development & Logistics segment provides
contract operations, engineering and construction management services as well as asset development services to energy companies
throughout the U.S. and internationally. This segment operates approximately 2,700 miles of third-party pipeline and terminals,
which are owned principally by major oil and gas, petrochemical and chemical companies, and also acts as a business development arm
for many of these same customers. The Development & Logistics segment also includes our ownership and operation of an ammonia pipeline
and our majority ownership of Sabina Pipelines, each located in Texas.
Adjusted EBITDA
Adjusted EBITDA is the primary measure used by senior management, including our Chief
Executive Officer, to evaluate our operating results and to allocate our resources. We define
EBITDA, a measure not defined under GAAP, as net income attributable to our unitholders before
interest and debt expense, income taxes and depreciation and amortization. EBITDA should not be
considered an alternative to net income, operating income, cash flow from operations or any other
measure of financial performance or liquidity presented in accordance with GAAP. The EBITDA
measure eliminates the significant level of non-cash depreciation and amortization expense that
results from the capital-intensive nature of our businesses and from intangible assets recognized
in business combinations. In addition, EBITDA is unaffected by our capital structure due to the
elimination of interest and debt expense and income taxes. We define Adjusted EBITDA, which is also
a non-GAAP measure, as EBITDA plus: (i) non-cash deferred lease expense, which is the difference
between the estimated annual land lease expense for our natural gas storage facility in the Natural
Gas Storage segment to be recorded under GAAP and the actual cash to be paid for such annual land
lease, (ii) non-cash unit-based compensation expense, and (iii) income attributable to
noncontrolling interests related to Buckeye for periods prior to the Merger in order to provide
comparability between periods before and after the Merger; less (iv) amortization of unfavorable
storage contracts acquired in connection with the BORCO acquisition.
The EBITDA and Adjusted EBITDA data presented may not be comparable to similarly titled
measures at other companies because EBITDA and Adjusted EBITDA exclude some items that affect net
income attributable to our unitholders, and these items may be defined differently by other
companies. Our senior management uses Adjusted
37
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
EBITDA to evaluate consolidated operating performance and the operating performance of our
business segments and to allocate resources and capital to the business segments. In addition, our
senior management uses Adjusted EBITDA as a performance measure to evaluate the viability of
proposed projects and to determine overall rates of return on alternative investment opportunities.
We believe that investors benefit from having access to the same financial measures that we
use. Further, we believe that these measures are useful to investors because they are one of the
bases for comparing our operating performance with that of other companies with similar operations,
although our measures may not be directly comparable to similar measures used by other companies.
Each segment uses the same accounting policies as those used in the preparation of our
consolidated financial statements. All inter-segment revenues, operating income and assets have
been eliminated. All periods are presented on a consistent basis. All of our operations and
assets are conducted and located in the United States, including Puerto Rico, or the Bahamas.
Financial information about each segment, EBITDA and Adjusted EBITDA are presented below for
the periods or at the dates indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2011 |
|
|
2010 |
|
Revenue: |
|
|
|
|
|
|
|
|
Pipelines & Terminals |
|
$ |
144,206 |
|
|
$ |
138,908 |
|
International Operations (1) |
|
|
45,075 |
|
|
|
|
|
Natural Gas Storage |
|
|
19,604 |
|
|
|
25,406 |
|
Energy Services |
|
|
1,051,312 |
|
|
|
568,202 |
|
Development & Logistics |
|
|
9,591 |
|
|
|
7,515 |
|
Intersegment |
|
|
(17,252 |
) |
|
|
(8,857 |
) |
|
|
|
|
|
|
|
Total revenue |
|
$ |
1,252,536 |
|
|
$ |
731,174 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization: |
|
|
|
|
|
|
|
|
Pipelines & Terminals |
|
$ |
12,561 |
|
|
$ |
11,269 |
|
International Operations |
|
|
10,395 |
|
|
|
|
|
Natural Gas Storage |
|
|
1,716 |
|
|
|
1,641 |
|
Energy Services |
|
|
1,235 |
|
|
|
1,195 |
|
Development & Logistics |
|
|
334 |
|
|
|
423 |
|
|
|
|
|
|
|
|
Total depreciation and amortization |
|
$ |
26,241 |
|
|
$ |
14,528 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss): |
|
|
|
|
|
|
|
|
Pipelines & Terminals |
|
$ |
71,327 |
|
|
$ |
68,490 |
|
International Operations |
|
|
18,729 |
|
|
|
|
|
Natural Gas Storage |
|
|
(400 |
) |
|
|
3,451 |
|
Energy Services |
|
|
1,267 |
|
|
|
(3,397 |
) |
Development & Logistics |
|
|
1,640 |
|
|
|
947 |
|
|
|
|
|
|
|
|
Total operating income |
|
$ |
92,563 |
|
|
$ |
69,491 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The International Operations segments revenue generated in the Bahamas was $41.4
million for the three months ended March 31, 2011, which was 91.9% of the International
Operations segments total revenue. |
38
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2011 |
|
|
2010 |
|
Adjusted EBITDA: |
|
|
|
|
|
|
|
|
Pipelines & Terminals |
|
$ |
90,120 |
|
|
$ |
83,488 |
|
International Operations |
|
|
25,507 |
|
|
|
|
|
Natural Gas Storage |
|
|
2,452 |
|
|
|
6,384 |
|
Energy Services |
|
|
2,759 |
|
|
|
(1,552 |
) |
Development & Logistics |
|
|
1,401 |
|
|
|
1,139 |
|
|
|
|
|
|
|
|
Total Adjusted EBITDA |
|
$ |
122,239 |
|
|
$ |
89,459 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GAAP Reconciliation: |
|
|
|
|
|
|
|
|
Net income |
|
$ |
67,813 |
|
|
$ |
50,642 |
|
Less: net income attributable to noncontrolling interests |
|
|
(1,320 |
) |
|
|
(39,372 |
) |
|
|
|
|
|
|
|
Net income attributable to Buckeye Partners, L.P. |
|
|
66,493 |
|
|
|
11,270 |
|
Interest and debt expense |
|
|
28,497 |
|
|
|
21,656 |
|
Income tax benefit |
|
|
(176 |
) |
|
|
(18 |
) |
Depreciation and amortization |
|
|
26,241 |
|
|
|
14,528 |
|
|
|
|
|
|
|
|
EBITDA |
|
|
121,055 |
|
|
|
47,436 |
|
Net income attributable to noncontrolling interests
affected by Merger (for periods prior to Merger) (1) |
|
|
|
|
|
|
39,134 |
|
Amortization of unfavorable storage contracts (2) |
|
|
(1,932 |
) |
|
|
|
|
Non-cash deferred lease expense |
|
|
1,030 |
|
|
|
1,059 |
|
Non-cash unit-based compensation expense |
|
|
2,086 |
|
|
|
1,830 |
|
|
|
|
|
|
|
|
Adjusted EBITDA |
|
$ |
122,239 |
|
|
$ |
89,459 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Amounts represent portions of BGHs noncontrolling interests related to Buckeye that
were eliminated as a result of the Merger. Amounts are added back for the 2010 period to
provide comparability with the 2011 period. |
|
(2) |
|
Represents amortization of unfavorable storage contracts acquired in connection with
the BORCO acquisition. |
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2011 |
|
|
2010 |
|
Capital additions, net: (1) |
|
|
|
|
|
|
|
|
Pipelines & Terminals |
|
$ |
14,629 |
|
|
$ |
7,598 |
|
International Operations |
|
|
21,703 |
|
|
|
|
|
Natural Gas Storage |
|
|
1,482 |
|
|
|
1,483 |
|
Energy Services |
|
|
176 |
|
|
|
1,705 |
|
Development & Logistics |
|
|
43 |
|
|
|
177 |
|
|
|
|
|
|
|
|
Total capital additions, net |
|
$ |
38,033 |
|
|
$ |
10,963 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Amount excludes $0.2 million and ($1.4) million of non-cash changes in accruals for
capital expenditures for the three months ended March 31, 2011 and 2010, respectively (see
Note 21). |
39
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2011 |
|
|
2010 |
|
Total Assets: |
|
|
|
|
|
|
|
|
Pipelines & Terminals (1) |
|
$ |
2,367,165 |
|
|
$ |
2,328,702 |
|
International Operations (2) |
|
|
1,904,698 |
|
|
|
60,313 |
|
Natural Gas Storage |
|
|
542,274 |
|
|
|
549,876 |
|
Energy Services |
|
|
487,429 |
|
|
|
561,382 |
|
Development & Logistics |
|
|
72,265 |
|
|
|
73,943 |
|
|
|
|
|
|
|
|
Total assets |
|
$ |
5,373,831 |
|
|
$ |
3,574,216 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Goodwill: |
|
|
|
|
|
|
|
|
Pipelines & Terminals |
|
$ |
248,250 |
|
|
$ |
248,250 |
|
International Operations |
|
|
497,946 |
|
|
|
|
|
Natural Gas Storage |
|
|
169,560 |
|
|
|
169,560 |
|
Energy Services |
|
|
1,132 |
|
|
|
1,132 |
|
Development & Logistics |
|
|
13,182 |
|
|
|
13,182 |
|
|
|
|
|
|
|
|
Total goodwill |
|
$ |
930,070 |
|
|
$ |
432,124 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All equity investments are included in the assets of the Pipelines & Terminals segment. |
|
(2) |
|
The International Operations segments long-lived assets consist of property, plant and
equipment, goodwill, intangible assets and other non-current assets. Total long-lived
assets located in or attributable to the Bahamas was $1,844.4 million at March 31, 2011,
which was 96.8% of the International Operations segments total long-lived assets. |
21. 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, |
|
|
|
2011 |
|
|
2010 |
|
Cash paid for interest (net of capitalized interest) |
|
$ |
32,708 |
|
|
$ |
32,351 |
|
Cash paid for income taxes |
|
|
15 |
|
|
|
165 |
|
Capitalized interest |
|
|
1,543 |
|
|
|
529 |
|
|
|
|
|
|
|
|
|
|
Non-cash changes in assets and liabilities: |
|
|
|
|
|
|
|
|
Change in capital expenditures in accounts payable |
|
$ |
218 |
|
|
$ |
(1,355 |
) |
|
|
|
|
|
|
|
|
|
Non-cash financing activities: |
|
|
|
|
|
|
|
|
Issuance of units to First Reserve for BORCO acquisition |
|
$ |
407,391 |
|
|
$ |
|
|
Issuance of units to Vopak for BORCO acquisition |
|
|
96,110 |
|
|
|
|
|
Issuance of Class B Units in lieu of quarterly cash
distribution |
|
|
6,709 |
|
|
|
|
|
22. SUBSEQUENT EVENTS
Entry into Agreement to Sell Interest in West Texas LPG Pipeline Limited Partnership
On April 26, 2011, we signed an agreement to sell our 20% interest in West Texas LPG Pipeline
Limited Partnership (WT LPG) to affiliates of Atlas Pipeline Partners L.P. for $85.0 million. WT
LPG owns a 2,295-mile common-carrier pipeline system that transports natural gas liquids from
points in New Mexico and Texas to Mont
40
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Belvieu, Texas for fractionation. Chevron Pipeline Company,
which owns the remaining 80% interest, is the
operator of WT LPG. The transaction is expected to close in the second quarter of 2011,
subject to customary closing conditions. The proceeds from the sale will be used to fund a portion
of our internal growth capital projects planned for 2011.
41
Item 2. Managements Discussion and Analysis of Financial Condition and Results of
Operations
The following information should be read in conjunction with our unaudited condensed
consolidated financial statements and accompanying notes included in this report. The following
information and such unaudited condensed consolidated financial statements should also be read in
conjunction with the consolidated financial statements and related notes, together with our
discussion and analysis of financial condition and results of
operations, included in our Annual
Report on Form 10-K/A for the year ended December 31, 2010.
Our consolidated financial statements have been prepared in accordance with U.S. generally
accepted accounting principles (GAAP).
Cautionary Note Regarding Forward-Looking Statements
This discussion 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 document, 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 Item 1A Risk Factors included in our
Annual Report on Form 10-K/A for the year ended December 31, 2010. 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.
Overview of Critical Accounting Policies and Estimates
A summary of the significant accounting policies we have adopted and followed in the
preparation of our condensed consolidated financial statements is included in our Annual Report on
Form 10-K/A for the year ended December 31, 2010. Certain of these accounting policies require the
use of estimates. As more fully described therein, the following estimates, in our opinion, are
subjective in nature, require the exercise of judgment and involve complex analysis: depreciation
methods, estimated useful lives and disposals of property, plant and equipment; reserves for
environmental matters; fair value of derivatives; measuring the fair value of goodwill; and
measuring recoverability of long-lived assets and equity method investments. These estimates are
based on our knowledge and understanding of current conditions and actions we may take in the
future. Changes in these estimates will occur as a result of the passage of time and the
occurrence of future events. Subsequent changes in these estimates may have a significant impact
on our financial position, results of operations and cash flows.
Overview of Business
Buckeye Partners, L.P. is a publicly traded Delaware master limited partnership (MLP), and
its limited partnership units representing limited partner interests (LP Units) are listed on the
New York Stock Exchange (NYSE) under the ticker symbol BPL. Buckeye GP LLC (Buckeye GP) is
our general partner. Buckeye GP is a wholly owned subsidiary of Buckeye GP Holdings L.P. (BGH),
a Delaware limited partnership that was previously publicly traded on
the NYSE prior to BGHs
merger with a wholly owned subsidiary of Buckeye. As used in these Notes to Unaudited Condensed Consolidated Financial Statements,
we, us, our and Buckeye mean Buckeye Partners, L.P. and, where the context requires,
includes our subsidiaries.
We were formed in 1986 and own and operate one of the largest independent refined petroleum
products pipeline systems in the United States in terms of volumes delivered with approximately
5,400 miles of pipeline and 69 active products terminals that provide aggregate storage capacity of
over 53 million barrels. In 2011, we closed
42
the acquisition of the Bahamas Oil Refining Company International Limited (BORCO) terminal
facility in Freeport, Grand Bahama, The Bahamas, with a total installed capacity of approximately
21.6 million barrels (see Note 2 in the Notes to Unaudited Condensed Consolidated Financial
Statements). In addition, we operate and maintain approximately 2,700 miles of other pipelines
under agreements with major oil and gas, petrochemical and chemical companies, and perform certain
engineering and construction management services for third parties. We also own and operate a
high performance natural gas storage facility in northern California, and are a wholesale distributor of
refined petroleum products in the United States in areas also served by our pipelines and
terminals.
We operate and report in five business segments: Pipelines & Terminals; International
Operations; Natural Gas Storage; Energy Services; and Development & Logistics. Effective January
1, 2011, we realigned our five business segments. We combined the Pipeline Operations and
Terminalling & Storage segments into one segment, the Pipelines & Terminals segment, and moved our
terminal in Yabucoa, Puerto Rico, previously included as part of the Terminalling & Storage
segment, and the BORCO facility to a new International Operations segment. We have
adjusted our quarter-to-quarter comparisons to conform to the current presentation. See Note 20 in
the Notes to Unaudited Condensed Consolidated Financial Statements for a discussion of our business
segments.
Our primary business objective is to provide stable and sustainable cash distributions to our
unitholders, while maintaining a relatively low investment risk profile. The key elements of our
strategy are to maximize utilization of our assets at the lowest cost per unit, maintain stable
long-term customer relationships, operate in a safe and environmentally responsible manner,
optimize, expand and diversify our portfolio of energy assets, and maintain a solid, conservative
financial position and our investment-grade credit rating.
Merger
On November 19, 2010, we consummated a transaction pursuant to a plan and agreement of merger
(the Merger Agreement) with our general partner, BGH, BGHs general partner and Grand Ohio, LLC
(Merger Sub), our subsidiary. Pursuant to the Merger Agreement, Merger Sub was merged into BGH,
with BGH as the surviving entity (the Merger). In the transaction, the incentive compensation
agreement (also referred to as the incentive distribution rights) held by our general partner was
cancelled, the general partner units held by our general partner (representing an approximate 0.5%
general partner interest in us) were converted to a non-economic general partner interest, all of
the economic interest in BGH was acquired by us and BGH unitholders received aggregate
consideration of approximately 20.0 million of our LP Units.
Although titled Buckeye Partners, L.P., the accompanying 2010 financial statements in this
Quarterly Report on Form 10-Q were originally the financial statements of BGH prior to the
completion of the Merger. BGH is considered the surviving consolidated entity for accounting
purposes, although Buckeye is the surviving consolidated entity for legal and reporting purposes. The
Merger was accounted for as an equity transaction. Therefore, changes in BGHs ownership interest
as a result of the Merger did not result in gain or loss recognition.
Our general partner, Buckeye GP, continues to manage us following the Merger.
Recent Developments
Acquisition of BORCO
On December 18, 2010, we, through our wholly owned subsidiary, entered into a sale and
purchase agreement with affiliates of FRC Founders Corporation (First Reserve), pursuant to which
we agreed to acquire First Reserves indirect 80% interest in FR Borco Coop Holdings, L.P.
(FRBCH), the indirect owner of BORCO, for $1.15 billion, financed through a combination of debt
and equity, including the issuance of Class B units representing limited partner interests (Class
B Units) and LP Units to First Reserve. BORCO is the fourth largest oil and petroleum products
storage terminal in the world and the largest petroleum products facility in the Caribbean with
current storage capacity of approximately 21.6 million barrels. On January 18, 2011, we completed
the purchase of First Reserves interest in BORCO through the acquisition by us of all of the
partnership interests in FR Borco Topco, L.P., which indirectly owned First Reserves interest.
43
Vopak Bahamas B.V. (Vopak), which is based in The Netherlands, owned the remaining 20%
interest in FRBCH. On February 16, 2001, Vopak sold its 20% interest in FRBCH to us for
approximately $276.5 million of cash and equity, which is a proportionate price and on the same
terms and conditions as those in the sale and purchase agreement with First Reserve.
On January 13, 2011, we sold $650.0 million aggregate principal amount of 4.875% Notes due
2021 (the 4.875% Notes) in an underwritten public offering. The notes were issued at 99.62% of
their principal amount. Total proceeds from this offering, after underwriters fees, expenses and
debt issuance costs of $4.9 million, were approximately $642.6 million, and were used to fund a
portion of the purchase price of the BORCO acquisition.
On January 18 and 19, 2011, we issued 5,794,725 LP Units and 1,314,870 Class B Units to
institutional investors for aggregate consideration of approximately $425.0 million to fund a
portion of the BORCO acquisition. On January 18, 2011, we issued 2,483,444 LP Units and 4,382,889
Class B Units to First Reserve as $400.0 million of consideration to fund a portion of the BORCO
acquisition. On February 16, 2011, we issued 620,861 LP Units and 1,095,722 Class B Units to Vopak
as $100.0 million of consideration to fund a portion of the BORCO acquisition. Equity issuance
costs incurred on these transactions were approximately $4.6 million. The remaining purchase price
was funded with cash on hand at closing and borrowings under our unsecured revolving credit
agreement (Credit Facility).
On January 18, 2011, in connection with the BORCO acquisition, we repaid all of BORCOs
outstanding indebtedness and settled BORCOs interest rate derivative instruments, consisting of
approximately $318.2 million.
For additional information, see Note 2 in the Notes to Unaudited Condensed Consolidated
Financial Statements.
Entry into Definitive Agreement to Acquire Pipeline & Terminal Assets
On March 18, 2011, we signed a definitive agreement with BP Products North America Inc. and
its affiliates (BP) to acquire 33 refined petroleum products terminals with total storage
capacity exceeding 10 million barrels and approximately 1,000 miles of refined petroleum products
pipelines, including BPs approximately 50% interest in Inland Corporation (Inland), for a total
transaction purchase price of $225.0 million. The terminal and pipeline assets are located in the
Midwestern, Southeastern and Western United States, further extending our operations into new, key
geographic markets. Our proposed acquisition of BPs interest in Inland, which represents $60.0
million of the total transaction purchase price, is subject to Inlands other shareholders existing
rights of first refusal. The period for such shareholders to exercise their rights of first
refusal has not ended, but all shareholders have expressed an intent to exercise such rights with
respect to some or all share to which they are entitled. We expect this acquisition to close in
the second quarter of 2011, subject to regulatory approvals, other customary closing conditions,
and, with respect to BPs interest in Inland, the co-owners right of first refusal. We expect to
fund this acquisition with borrowings under our Credit Facility.
Equity Offering
In April 2011, we issued 5,520,000 LP Units, which included 720,000 LP Units issued as part of
the overallotment option, in an underwritten public offering at a public offering price of $59.41
per LP Unit. Total proceeds from the offering, including the overallotment option and after the
underwriters discount of $1.99 per LP Unit and offering expenses, were approximately $317.0
million, and were used to reduce amounts outstanding under our Credit Facility.
Entry into Agreement to Sell Interest in West Texas LPG Pipeline Limited Partnership
On April 26, 2011, we signed an agreement to sell our 20% interest in West Texas LPG Pipeline
Limited Partnership (WT LPG) to affiliates of Atlas Pipeline Partners L.P. for $85.0 million. WT
LPG owns a 2,295-mile common-carrier pipeline system that transports natural gas liquids from
points in New Mexico and Texas to Mont Belvieu, Texas for fractionation. Chevron Pipeline Company,
which owns the remaining 80% interest, is the operator of WT LPG. The transaction is expected to
close in the second quarter of 2011, subject to customary
44
closing conditions. The proceeds from the sale will be used to fund a portion of our internal
growth capital projects planned for 2011.
Results of Operations
Adjusted EBITDA
Adjusted EBITDA is the primary measure used by senior management, including our Chief
Executive Officer, to evaluate our operating results and to allocate our resources. We define
EBITDA, a measure not defined under GAAP, as net income attributable to our unitholders before
interest and debt expense, income taxes and depreciation and amortization. EBITDA should not be
considered an alternative to net income, operating income, cash flow from operations or any other
measure of financial performance or liquidity presented in accordance with GAAP. The EBITDA
measure eliminates the significant level of non-cash depreciation and amortization expense that
results from the capital-intensive nature of our businesses and from intangible assets recognized
in business combinations. In addition, EBITDA is unaffected by our capital structure due to the
elimination of interest and debt expense and income taxes. We define Adjusted EBITDA, which is also
a non-GAAP measure, as EBITDA plus: (i) non-cash deferred lease expense, which is the difference
between the estimated annual land lease expense for our natural gas storage facility in the Natural
Gas Storage segment to be recorded under GAAP and the actual cash to be paid for such annual land
lease, (ii) non-cash unit-based compensation expense, and (iii) income attributable to
noncontrolling interests related to Buckeye for periods prior to the Merger in order to provide
comparability between periods before and after the Merger; less (iv) amortization of unfavorable
storage contracts acquired in connection with the BORCO acquisition.
The EBITDA and Adjusted EBITDA data presented may not be comparable to similarly titled
measures at other companies because EBITDA and Adjusted EBITDA exclude some items that affect net
income attributable to our unitholders, and these items may be defined differently by other
companies. Our senior management uses Adjusted EBITDA to evaluate consolidated operating
performance and the operating performance of our business segments and to allocate resources and
capital to the business segments. In addition, our senior management uses Adjusted EBITDA as a
performance measure to evaluate the viability of proposed projects and to determine overall rates
of return on alternative investment opportunities.
We believe that investors benefit from having access to the same financial measures that we
use. Further, we believe that these measures are useful to investors because they are one of the
bases for comparing our operating performance with that of other companies with similar operations,
although our measures may not be directly comparable to similar measures used by other companies.
45
The following table presents Adjusted EBITDA by segment and on a consolidated basis for the
periods indicated, and a reconciliation of EBITDA and Adjusted EBITDA to net income attributable to
our unitholders, which is the most comparable GAAP financial measure (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2011 |
|
|
2010 |
|
Adjusted EBITDA: |
|
|
|
|
|
|
|
|
Pipelines & Terminals |
|
$ |
90,120 |
|
|
$ |
83,488 |
|
International Operations |
|
|
25,507 |
|
|
|
|
|
Natural Gas Storage |
|
|
2,452 |
|
|
|
6,384 |
|
Energy Services |
|
|
2,759 |
|
|
|
(1,552 |
) |
Development & Logistics |
|
|
1,401 |
|
|
|
1,139 |
|
|
|
|
|
|
|
|
Total Adjusted EBITDA |
|
$ |
122,239 |
|
|
$ |
89,459 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GAAP Reconciliation: |
|
|
|
|
|
|
|
|
Net income |
|
$ |
67,813 |
|
|
$ |
50,642 |
|
Less: net income attributable to noncontrolling interests |
|
|
(1,320 |
) |
|
|
(39,372 |
) |
|
|
|
|
|
|
|
Net income attributable to Buckeye Partners, L.P. |
|
|
66,493 |
|
|
|
11,270 |
|
Interest and debt expense |
|
|
28,497 |
|
|
|
21,656 |
|
Income tax benefit |
|
|
(176 |
) |
|
|
(18 |
) |
Depreciation and amortization |
|
|
26,241 |
|
|
|
14,528 |
|
|
|
|
|
|
|
|
EBITDA |
|
|
121,055 |
|
|
|
47,436 |
|
Net income attributable to noncontrolling interests
affected by Merger (for periods prior to Merger) (1) |
|
|
|
|
|
|
39,134 |
|
Amortization of unfavorable storage contracts (2) |
|
|
(1,932 |
) |
|
|
|
|
Non-cash deferred lease expense |
|
|
1,030 |
|
|
|
1,059 |
|
Non-cash unit-based compensation expense |
|
|
2,086 |
|
|
|
1,830 |
|
|
|
|
|
|
|
|
Adjusted EBITDA |
|
$ |
122,239 |
|
|
$ |
89,459 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Amounts represent portions of BGHs noncontrolling interests related to Buckeye that
were eliminated as a result of the Merger. Amounts are added back for the 2010 period to
provide comparability with the 2011 period. |
|
(2) |
|
Represents amortization of unfavorable storage contracts acquired in connection with
the BORCO acquisition. |
46
Segment Results
A summary of financial information by business segment follows for the periods indicated (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2011 |
|
|
2010 |
|
Revenues: |
|
|
|
|
|
|
|
|
Pipelines & Terminals |
|
$ |
144,206 |
|
|
$ |
138,908 |
|
International Operations |
|
|
45,075 |
|
|
|
|
|
Natural Gas Storage |
|
|
19,604 |
|
|
|
25,406 |
|
Energy Services |
|
|
1,051,312 |
|
|
|
568,202 |
|
Development & Logistics |
|
|
9,591 |
|
|
|
7,515 |
|
Intersegment |
|
|
(17,252 |
) |
|
|
(8,857 |
) |
|
|
|
|
|
|
|
Total revenues |
|
$ |
1,252,536 |
|
|
$ |
731,174 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses: (1) |
|
|
|
|
|
|
|
|
Pipelines & Terminals |
|
$ |
72,879 |
|
|
$ |
70,418 |
|
International Operations |
|
|
26,346 |
|
|
|
|
|
Natural Gas Storage |
|
|
20,004 |
|
|
|
21,955 |
|
Energy Services |
|
|
1,050,045 |
|
|
|
571,599 |
|
Development & Logistics |
|
|
7,951 |
|
|
|
6,568 |
|
Intersegment |
|
|
(17,252 |
) |
|
|
(8,857 |
) |
|
|
|
|
|
|
|
Total costs and expenses |
|
$ |
1,159,973 |
|
|
$ |
661,683 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization: |
|
|
|
|
|
|
|
|
Pipelines & Terminals |
|
$ |
12,561 |
|
|
$ |
11,269 |
|
International Operations |
|
|
10,395 |
|
|
|
|
|
Natural Gas Storage |
|
|
1,716 |
|
|
|
1,641 |
|
Energy Services |
|
|
1,235 |
|
|
|
1,195 |
|
Development & Logistics |
|
|
334 |
|
|
|
423 |
|
|
|
|
|
|
|
|
Total depreciation and amortization |
|
$ |
26,241 |
|
|
$ |
14,528 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss): |
|
|
|
|
|
|
|
|
Pipelines & Terminals |
|
$ |
71,327 |
|
|
$ |
68,490 |
|
International Operations |
|
|
18,729 |
|
|
|
|
|
Natural Gas Storage |
|
|
(400 |
) |
|
|
3,451 |
|
Energy Services |
|
|
1,267 |
|
|
|
(3,397 |
) |
Development & Logistics |
|
|
1,640 |
|
|
|
947 |
|
|
|
|
|
|
|
|
Total operating income |
|
$ |
92,563 |
|
|
$ |
69,491 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Total costs and expenses includes depreciation and amortization. |
47
The following table presents product volumes transported and average daily throughput for the
Pipelines & Terminals segment in barrels per day (bpd), average daily throughput for the
International Operations segment and total volumes sold in gallons for the Energy Services segment
for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2011 |
|
|
2010 |
|
Pipelines & Terminals (average bpd): |
|
|
|
|
|
|
|
|
Pipelines: |
|
|
|
|
|
|
|
|
Gasoline |
|
|
602,900 |
|
|
|
608,900 |
|
Jet fuel |
|
|
326,500 |
|
|
|
322,300 |
|
Diesel fuel |
|
|
240,500 |
|
|
|
227,500 |
|
Heating oil |
|
|
110,600 |
|
|
|
113,900 |
|
LPGs |
|
|
17,200 |
|
|
|
20,500 |
|
Other products |
|
|
5,300 |
|
|
|
800 |
|
|
|
|
|
|
|
|
Total pipelines throughput |
|
|
1,303,000 |
|
|
|
1,293,900 |
|
|
|
|
|
|
|
|
Terminals: |
|
|
|
|
|
|
|
|
Products throughput |
|
|
535,500 |
|
|
|
556,300 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International Operations (average bpd): |
|
|
|
|
|
|
|
|
Products throughput (1) |
|
|
533,900 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy Services (in thousands of gallons): |
|
|
|
|
|
|
|
|
Sales volumes |
|
|
381,500 |
|
|
|
266,900 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The BORCO facility was acquired on January 18, 2011, and the Yabucoa, Puerto Rico terminal
was acquired on December 10, 2010. |
Three Months Ended March 31, 2011 Compared to Three Months Ended March 31, 2010
Consolidated
Adjusted EBITDA. Adjusted EBITDA increased by $32.7 million, or 36.6%, to $122.2
million for the three months ended March 31, 2011 from $89.5 million for the corresponding period
in 2010. The International Operations segment, the Pipelines & Terminals segment, the Energy
Services segment and the Development & Logistics segment were responsible for the increase in
Adjusted EBITDA. The International Operations segment increased Adjusted EBITDA by $25.5 million,
as this segment was added in 2011 as a result of the acquisitions of BORCO and the Yabucoa, Puerto
Rico terminal in January 2011 and December 2010, respectively. The Pipelines & Terminals segments
Adjusted EBITDA increased by $6.6 million for the three months ended March 31, 2011 as compared to
the corresponding period in 2010, driven by the benefit of higher tariff rates and terminalling
fees, favorable settlement experience and the impact of internal growth projects, increased
pipeline transportation volumes and increased other revenues. The Energy Services segments
Adjusted EBITDA increased by $4.4 million for the three months ended March 31, 2011 as compared to
the corresponding period in 2010, as a result of increased volumes of product sold and higher
margins, partially offset by increased expenses. The Development & Logistics segments Adjusted
EBITDA increased by $0.2 million for the three months ended March 31, 2011 as compared to the
corresponding period in 2010, primarily due to increased operating contract services. Adjusted
EBITDA was also favorably impacted by an increase of $0.6 million in income from equity investments
for the three months ended March 31, 2011 as compared to the corresponding period in 2010.
These increases in Adjusted EBITDA were partially offset by a decrease in Adjusted EBITDA in
the Natural Gas Storage segment. The Natural Gas Storage segments Adjusted EBITDA decreased by
$3.9 million for the three months ended March 31, 2011 as compared to the corresponding period in
2010, as a result of low natural gas prices, low volatility in those
prices and compressed seasonal spreads, which led to a decrease in the net contribution
48
from hub services activities and a decrease
in lease revenue. The revenue and expense factors affecting the variance in consolidated Adjusted
EBITDA are more fully discussed below.
Revenue. Revenue was $1,252.5 million for the three months ended March 31, 2011,
which is an increase of $521.3 million, or 71.3%, from the three months ended March 31, 2010. The
increase in revenue for the three months ended March 31, 2011 as compared to the corresponding
period in 2010 was caused primarily by the following:
|
|
|
an increase of $483.1 million in revenue from the Energy Services segment, resulting
from an overall increase in refined petroleum product prices and volumes of product
sold during the three months ended March 31, 2011 as compared to the corresponding
period in 2010. The 114.6 million gallon increase in sales volume resulted in an
increase in revenue of approximately $235.0 million, and the increase in the average
sales price per gallon from $2.13 in the 2010 period to $2.79 in the 2011 period, or
approximately $0.66 per gallon, contributed to an increase in revenue of approximately
$248.1 million; |
|
|
|
|
revenue of $45.1 million from the International Operations segment, as the result of
the BORCO acquisition in 2011 and the Puerto Rico terminal acquisition in December
2010; |
|
|
|
|
an increase of $5.3 million in revenue from the Pipelines & Terminals segment,
resulting from the benefit of higher tariff rates and terminalling fees, the impact of
internal growth projects, increased transportation volumes, favorable settlement
experience and increased other revenues; and |
|
|
|
|
an increase of $2.1 million in revenue from the Development & Logistics segment,
resulting primarily from increased operating service revenues and increased revenues
from the assignment of certain service contracts from the Pipelines & Terminals segment
to the Development & Logistics segment in April 2010. |
The increase in revenue was partially offset by:
|
|
|
a decrease of $5.8 million in revenue from the Natural Gas Storage segment,
resulting primarily from lower fees from lease and hub services transactions as a result of
general market conditions, including low natural gas prices, low
volatility in those prices and compressed seasonal
spreads. |
Total Costs and Expenses. Total costs and expenses were $1,160.0 million for the
three months ended March 31, 2011, which is an increase of $498.3 million, or 75.3%, from the
corresponding period in 2010. Total costs and expenses reflect:
|
|
|
an increase of $478.4 million in the Energy Services segments cost of product sales
in the 2011 period as compared to the 2010 period, primarily as a result of increased
refined petroleum product prices and increased volumes sold. The average cost of
products sold increased from approximately $2.12 per gallon in the 2010 period to
approximately $2.77 per gallon in the 2011 period, or approximately $0.65 per gallon,
resulting in an increase in cost of products sold of approximately $233.9 million, and
sales volumes increased by 114.6 million gallons between the 2010 and 2011 periods,
contributing $244.9 million to the increase in cost of products sold; |
|
|
|
$26.3 million of costs and expenses of the International Operations segment; |
|
|
|
an increase of $2.5 million in costs and expenses of the Pipelines & Terminals
segment, primarily due to higher payroll related costs, professional fees and
environmental remediation expenses, partially offset by lower expenses related to
contract service activities from the assignment of certain service contracts from the
Pipelines & Terminals segment to the Development & Logistics segment, lower bad debt
expense and lower operating power costs; |
|
|
|
an increase of $1.4 million in costs and expenses of the Development & Logistics
segment, primarily due to increased operating service activities discussed above,
including increased costs from the assignment of certain service contracts from the
Pipelines & Terminals segment to the Development & Logistics segment, partially offset
by higher income tax benefit, which is not a component of Adjusted EBITDA as presented
in the reconciliation above; and |
49
|
|
|
an increase of $11.7 million in depreciation and amortization, primarily on assets
acquired in the BORCO acquisition. Depreciation and amortization expense are not
components of Adjusted EBITDA as presented in the reconciliation above. |
Total costs and expenses also reflect the following decreases:
|
|
|
a decrease of $2.0 million in costs and expenses of the Natural Gas Storage
segment, resulting from lower costs associated with hub services transactions
recognized as an expense, resulting from lower hub services activities. |
Income attributable to noncontrolling interests. Income attributable to
noncontrolling interests, which through November 19, 2010, the date of the merger between Buckeye
and BGH, represents Services Companys equity and equity interests in Buckeye that were not owned
by BGH, and includes portions of Sabina Pipelines (Sabina) and WesPac Pipelines Memphis LLC
(WesPac Memphis) that are not owned by Buckeye, was $1.3 million for the three months ended March
31, 2011 as compared to $39.4 million in the corresponding period in 2010. The 2011 amount
includes $1.7 million of noncontrolling interests expense related to the 20% of BORCO not acquired
by us until February 16, 2011.
Consolidated net income attributable to unitholders. Consolidated net income
attributable to our unitholders was $66.5 million for the three months ended March 31, 2011
compared to $11.3 million for the three months ended March 31, 2010. Interest and debt expense
increased by $6.8 million for the three months ended March 31, 2011 as compared to the
corresponding period in 2010, which increase was largely attributable to the issuance in January
2011 of $650.0 million aggregate principal amount of 4.875% Notes due 2021 and higher outstanding
borrowings under BESs credit agreement (BES Credit Agreement) and under our Credit Facility,
partially offset by an increase of $1.0 million in capitalized interest, primarily as a result of
the BORCO acquisition. Other revenue and expense items impacting operating income are discussed
above.
For a more detailed discussion of the above factors affecting our results, see the following
discussion by segment.
Pipelines & Terminals
Adjusted EBITDA. Adjusted EBITDA from the Pipelines & Terminals segment of $90.1
million for the three months ended March 31, 2011 increased by $6.6 million, or 7.9%, from $83.5
million for the corresponding period in 2010. The increase in Adjusted EBITDA was driven primarily
by a $2.5 million benefit of higher tariff rates and terminalling fees, favorable settlement
experience of $2.4 million, a $1.7 million increase related to a terminal acquisition in 2010 and
increased storage, rental and other service revenues, a $0.6 million increase in income from equity
investments and a $0.7 million decrease in cash operating expenses. These increases in Adjusted
EBITDA were partially offset by a $1.3 million decrease in revenue from contract service activities
at customer facilities as discussed below. The revenue and expense factors affecting the variance
in Adjusted EBITDA are more fully discussed below.
Revenue. Revenue from the Pipelines & Terminals segment was $144.2 million for the
three months ended March 31, 2011, which is an increase of $5.3 million, or 3.8%, from the
corresponding period in 2010. Revenues increased due to favorable settlement experience of $2.4
million reflecting the favorable impact of higher refined petroleum product prices, a $2.5 million
benefit of higher tariff rates and terminal fees resulting from overall average tariff rate
increases of approximately 2.6% implemented on May 1, 2010, and an increase of $1.7 million related
to a terminal acquisition in 2010 and increased storage, rental and other service revenues.
Overall pipeline transportation volumes increased by 0.7%, which resulted in a $0.6 million
increase in transportation revenues. These increases in revenue were partially offset by an
overall decrease of 3.7% in terminalling volumes, due to decreased diesel, ethanol and jet fuel
throughput volumes and a $1.3 million decrease in revenue from contract service activities at
customer facilities connected to our refined petroleum products pipelines pursuant to the
assignment of such service contract to the Development & Logistics segment.
50
Total Costs and Expenses. Total costs and expenses from the Pipelines & Terminals
segment were $72.9 million for the three months ended March 31, 2011, which is an increase of $2.5
million, or 3.5%, from the corresponding period in 2010. The increase in total costs and expenses
was primarily due to a $3.2 million increase in payroll related costs, a $1.3 million increase in
depreciation and amortization as a result of assets placed into service, a $1.0 million increase in
professional fees, a $0.5 million increase in environmental remediation expenses
and a $0.3 million increase in integrity program expenditures. Depreciation and amortization
expense are not components of Adjusted EBITDA as presented in the reconciliation above.
These increases in total costs and expenses were partially offset by a $1.3 million decrease
in contract service activities due to the assignment of certain operating service contracts from
the Pipelines & Terminals segment to the Development & Logistics segment, a $1.5 million decrease
in bad debt expense and a $1.0 million decrease in operating power costs due to contract
renegotiations.
Operating Income. Operating income from the Pipelines & Terminals segment was $71.3
million for the three months ended March 31, 2011 compared to operating income of $68.5 million for
the three months ended March 31, 2010. Revenue and expense items impacting operating income are
discussed above.
International Operations
Adjusted EBITDA. Adjusted EBITDA from the International Operations segment was $25.5
million for the three months ended March 31, 2011. The revenue and expense factors affecting
Adjusted EBITDA are more fully discussed below.
Revenue. Revenue from the International Operations segment was $45.1 million for the
three months ended March 31, 2011. Revenues included storage fees of $33.7 million, which
represent fees charged for storage of various products, berthing fees of $4.3 million, which
represent amounts charged to ships that utilize the facilitys jetties, and other ancillary service
revenues of $5.2 million. Also included in revenue is the recognition of $1.9 million of revenue
from unfavorable storage contracts acquired in connection with the BORCO acquisition, which is not
a component of Adjusted EBITDA as presented in the reconciliation above.
Total Costs and Expenses. Total costs and expenses from the International Operations
segment were $26.3 million for the three months ended March 31, 2011, and included $15.9 million of
costs and expenses related to operating the BORCO facility and the Yabucoa terminal, including
payroll and benefits related costs, repairs and maintenance costs, insurance costs, professional
fees, costs related to the transition services agreement we entered into with Vopak in connection
with the acquisition and other expenses. Total costs and expenses also included $10.4 million of
depreciation and amortization, primarily related to the depreciation of property, plant and
equipment and the amortization of intangible assets (see Note 2 in the Notes to Unaudited Condensed
Consolidated Financial Statements for further discussion). Depreciation and amortization is not a
component of Adjusted EBITDA as presented in the reconciliation above.
Operating Income. Operating income from the International Operations segment was
$18.7 million for the three months ended March 31, 2011. Revenue and expense items impacting
operating income are discussed above.
Natural Gas Storage
Adjusted EBITDA. Adjusted EBITDA from the Natural Gas Storage segment of $2.5 million
for the three months ended March 31, 2011 decreased by $3.9 million, or 61.6%, from $6.4 million
for the corresponding period in 2010. The decrease in Adjusted EBITDA was primarily the result of
a decrease of $1.8 million in the net contribution from hub service activities, a decrease of $0.6
million in lease revenues and an increase of $1.6 million in other operating expenses during the
three months ended March 31, 2011. The revenue and expense factors affecting the variance in
Adjusted EBITDA are more fully discussed below.
Revenue. Revenue from the Natural Gas Storage segment was $19.6 million for the three
months ended March 31, 2011, which is a decrease of $5.8 million, or 22.8%, from the corresponding
period in 2010. This overall decrease is attributable to lower fees recognized as revenue and
lower underlying volume for hub services provided
51
during the three months ended March 31, 2011.
Market conditions resulted in a decrease of $5.2 million in fees for hub service agreements
recognized as revenue during the three months ended March 31, 2011 as compared to the corresponding
period in 2010. Lease revenue decreased $0.6 million for the three months ended March 31, 2011,
due to a decrease in the fee charged for each volumetric unit of storage capacity leased.
Total Costs and Expenses. Total costs and expenses from the Natural Gas Storage
segment were $20.0 million for the three months ended March 31, 2011, which is a decrease of $2.0
million, or 8.9%, from the corresponding period in 2010. Costs of natural gas storage services,
which includes hub services fees paid to customers for hub service activities, decreased $3.3
million, which is the primary driver of the decrease in expenses. Total costs and expenses also
include a decrease of $0.3 million in payroll related costs. These decreases in total costs and
expenses were partially offset by an increase of $1.3 million in outside service costs, primarily
due to well workover costs in the current period, and a $0.1 million increase in depreciation and
amortization. Depreciation and amortization are not components of Adjusted EBITDA as presented in
the reconciliation above.
Operating Income (Loss). Operating loss from the Natural Gas Storage segment was $0.4
million for the three months ended March 31, 2011 compared to operating income of $3.5 million for
the three months ended March 31, 2010. Revenue and expense items impacting operating income (loss)
are discussed above.
Energy Services
Adjusted EBITDA. Adjusted EBITDA from the Energy Services segment of $2.8 million for
the three months ended March 31, 2011 increased by $4.4 million, or 277.8%, from a loss of $1.6
million for the corresponding period in 2010. The increase in Adjusted EBITDA was primarily driven
by higher volumes, higher rack margins and more opportunities to optimize our storage as compared
to the 2010 period. At the rack, sales volumes were 42.9% higher than in the 2010 period. The
revenue and expense factors affecting the variance in Adjusted EBITDA are more fully discussed
below.
Revenue. Revenue from the Energy Services segment was $1,051.3 million for the three
months ended March 31, 2011, which is an increase of $483.1 million, or 85.0%, from the
corresponding period in 2010. This increase in revenue was primarily due to an increase in refined
petroleum product average sales prices of approximately $0.66 per gallon (average sales price per
gallon was $2.79 and $2.13 for the 2011 and 2010 periods, respectively) resulting in an increase of
$248.1 million in the 2011 period, and an increase of 42.9% in sales volumes that contributed an
additional $235.0 million in revenue.
Total Costs and Expenses. Total costs and expenses from the Energy Services segment
were $1,050.0 million for the three months ended March 31, 2011, which is an increase of $478.4
million, or 83.7%, from the corresponding period in 2010. The increase in total costs and expenses
was primarily due to a $478.8 million increase in cost of product sales as a result of increased
volumes sold and an increase in refined petroleum product prices (average cost of product sold per
gallon was $2.77 and $2.12 for the 2011 and 2010 periods, respectively). The increase in the cost
of product sold between the 2010 and 2011 periods was due to the 42.9% increase in volumes, and the
$0.65 per gallon increase in product sales price was $233.9 million and $244.9 million,
respectively. These increases in total costs and expenses were partially offset by a decrease of
$0.7 million in bad debt expense.
Operating Income (Loss). Operating income from the Energy Services segment was $1.3
million for the three months ended March 31, 2011 compared to operating loss of $3.4 million for
the three months ended March 31, 2010. Revenue and expense items impacting operating income (loss)
are discussed above.
Development & Logistics
Adjusted EBITDA. Adjusted EBITDA from the Development & Logistics segment of $1.4
million for the three months ended March 31, 2011 increased by $0.2 million, or 23.0%, from $1.2
million for the corresponding period in 2010, primarily due to by higher operating contract margins
of $0.8 million, partially offset by higher operating expenses of $0.5 million. The revenue and
expense factors affecting the variance in Adjusted EBITDA are more fully discussed below.
52
Revenue. Revenue from the Development & Logistics segment was $9.6 million for the
three months ended March 31, 2011, which is an increase of $2.1 million, or 27.6%, from the
corresponding period in 2010. The increase in revenue was primarily due to an increase of $1.1
million in operating service revenues and an increase of $0.2 million in rental revenues from the
2010 period, primarily due to the assignment of certain service contracts from the Pipelines &
Terminals segment to the Development & Logistics segment, and an increase of $1.3 million
in operating service revenues as a result of higher fees and increased reimbursable costs.
These increases in revenues were partially offset by reduced construction contract activity
following completion of certain construction projects, resulting in a $0.3 million reduction in
construction contract revenues.
Total Costs and Expenses. Total costs and expenses from the Development & Logistics
segment were $8.0 million for the three months ended March 31, 2011, which is an increase of $1.4
million, or 21.1%, from the corresponding period in 2010. The increase in total costs and expenses
was the result of the increased operating services activities discussed above, including increased
costs from the assignment of certain service contracts from the Pipelines & Terminals segment to
the Development & Logistics segment, partially offset by higher income tax benefit of $0.2 million,
which is not a component of Adjusted EBITDA as presented in the reconciliation above.
Operating Income. Operating income from the Development & Logistics segment was $1.6
million for the three months ended March 31, 2011 compared to operating income of $0.9 million for
the three months ended March 31, 2010. Revenue and expense items impacting operating income are
discussed above.
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 the Credit Facility. BES funds its working capital
needs principally from its operations and the BES Credit Agreement. Our financial policy has been
to fund sustaining capital expenditures with cash from operations. Expansion and cost improvement
capital expenditures, along with acquisitions, have typically been funded from external sources
including the 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.
In 2011, we completed the purchase of First Reserves and Vopaks interests in FRBCH, the
indirect owner of BORCO, for approximately $1.4 billion in cash and equity. We also assumed
BORCOs outstanding indebtedness and settled BORCOs interest rate derivative instruments,
consisting of approximately $318.2 million. In order to fund a portion of the combined purchase
price and the repayment of the assumption of BORCOs indebtedness, in January 2011, we accessed the
capital markets through a $650.0 million note issuance due 2021. The notes were issued at 99.62%
of their principal amount. In addition, in January 2011, we issued 5,794,725 LP Units and
1,314,870 Class B Units to institutional investors for aggregate consideration of approximately
$425.0 million. The proceeds from the debt offering and these equity issuances were used to fund a
portion of the BORCO acquisition. The remaining purchase price for the BORCO acquisition and the
repayment of the assumed debt was funded through the issuance of LP Units and Class B Units to both
First Reserve and Vopak, cash on hand and borrowings under our Credit Facility.
In April 2011, we issued 5,520,000 LP Units, which included 720,000 LP Units issued as part of
the overallotment option, in an underwritten public offering at a public offering price of $59.41
per LP Unit. Total proceeds from the offering, including the overallotment option and after the
underwriters discount of $1.99 per LP Unit and offering expenses, were approximately $317.0
million, and were used to reduce amounts outstanding under our Credit Facility.
As a result of our actions in 2011 and the fact that no debt facilities mature prior to 2012,
we believe that availabilities under our Credit Facility and the BES Credit Agreement, coupled with
ongoing cash flows from operations, will be sufficient to fund our operations for the remainder of
2011, including any expansion plans for the
53
BORCO terminal facility and the anticipated
acquisition of assets from BP. In addition, we expect to use the proceeds from the
sale of WT LPG to fund a portion of our internal growth capital projects planned for 2011. We will
continue to evaluate a variety of financing sources, including the debt and equity markets
described above, throughout 2011.
Debt
At March 31, 2011, we had $66.4 million of cash and cash equivalents on hand and approximately
$245.0 million of available credit under the Credit Facility, after application of the facilitys
funded debt ratio covenant. In addition, at March 31, 2011, BES had $65.6 million of available
credit under the BES Credit Agreement, pursuant to certain borrowing base calculations under that
agreement.
At March 31, 2011, we had an aggregate face amount of $2,645.0 million of debt, which
consisted of the following:
|
|
|
$300.0 million of 4.625% Notes due 2013 (the 4.625% Notes); |
|
|
|
|
$275.0 million of 5.300% Notes due 2014 (the 5.300% Notes); |
|
|
|
|
$125.0 million of 5.125% Notes due 2017 (the 5.125% Notes); |
|
|
|
|
$300.0 million of 6.050% Notes due 2018 (the 6.050% Notes); |
|
|
|
|
$275.0 million of 5.500% Notes due 2019 (the 5.500% Notes); |
|
|
|
|
$650.0 million of 4.875% Notes due 2021 (the 4.875% Notes); |
|
|
|
|
$150.0 million of 6.750% Notes due 2033 (the 6.750% Notes); |
|
|
|
|
$335.0 million outstanding under the Credit Agreement; and |
|
|
|
|
$235.0 million outstanding under the BES Credit Agreement. |
See Note 11 in the Notes to Unaudited Condensed Consolidated Financial Statements for more
information about the terms of the debt discussed above.
On January 13, 2011, we sold the 4.875% Notes in an underwritten public offering. The notes
were issued at 99.62% of their principal amount. Total proceeds from this offering, after
underwriters fees, expenses and debt issuance costs of $4.9 million, were approximately $642.6
million, and were used to fund a portion of the purchase price for our acquisition of BORCO. See
Note 2 in the Notes to Unaudited Condensed Consolidated Financial Statements for further discussion
of the BORCO acquisition.
On January 18, 2011, in connection with the BORCO acquisition, we repaid all of BORCOs
outstanding indebtedness and settled BORCOs interest rate derivative instruments, consisting of
approximately $318.2 million.
The fair values of our aggregate debt and credit facilities were estimated to be $2,733.9
million and $1,897.5 million at March 31, 2011 and December 31, 2010, respectively. The fair
values of the fixed-rate debt were estimated by observing market trading prices and by comparing
the historic market prices of our publicly-issued debt with the market prices of other MLPs
publicly-issued debt with similar credit ratings and terms. The fair values of our variable-rate
debt are their carrying amounts, as the carrying amount reasonably approximates fair value due to
the variability of the interest rates.
Equity
On January 18 and 19, 2011, we issued 5,794,725 LP Units and 1,314,870 Class B Units to
institutional investors for aggregate consideration of approximately $425.0 million to fund a
portion of the BORCO acquisition. On January 18, 2011, we issued 2,483,444 LP Units and 4,382,889
Class B Units to First Reserve as $400.0 million of consideration to fund a portion of the
acquisition of First Reserves 80% interest in BORCO. On February 16, 2011, we issued 620,861 LP
Units and 1,095,722 Class B Units to Vopak as $100.0 million of consideration to fund a portion of
the acquisition of Vopaks 20% interest in BORCO. Equity issuance costs incurred on these
transactions were approximately $4.6 million.
54
As discussed above, in April 2011, we issued 5,520,000 LP Units, which included 720,000 LP
Units issued as part of the overallotment option, in an underwritten public offering at a public
offering price of $59.41 per LP Unit. Total proceeds from the offering, including the
overallotment option and after the underwriters discount of $1.99 per LP Unit and offering
expenses, were approximately $317.0 million, and were used to reduce amounts outstanding under our
Credit Facility.
Registration Statement
We may issue equity or debt securities to assist us in meeting our liquidity and capital
spending requirements. We have a universal shelf registration statement on file with the U.S.
Securities and Exchange Commission (SEC) that does not
place any dollar limits on the amount of debt
and equity securities that we may issue thereunder.
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, |
|
|
|
2011 |
|
|
2010 |
|
Cash provided by (used in): |
|
|
|
|
|
|
|
|
Operating activities |
|
$ |
156,382 |
|
|
$ |
144,048 |
|
Investing activities |
|
|
(955,673 |
) |
|
|
11,211 |
|
Financing activities |
|
|
852,095 |
|
|
|
(172,679 |
) |
Operating Activities
Net
cash flows provided by operating activities was $156.4 million for the three months ended
March 31, 2011 compared to $144.0 million for the three months ended March 31, 2010. The following
were the principal factors impacting net cash flows provided by operating activities for the three
months ended March 31, 2011:
|
|
|
The net change in fair values of derivatives was a decrease of $78.6 million to cash
flows from operating activities for the three months ended March 31, 2011, resulting
from the decrease in value related to futures contracts executed to hedge physical
inventory. The offsetting adjustment is made to the value of inventory by adjusting
inventory to current market prices. |
|
|
|
|
The net impact of working capital changes was an increase of $135.6 million to cash
flows from operating activities for the three months ended March 31, 2011. The
principal factors affecting the working capital changes were: |
|
|
|
Inventories decreased by $169.7 million due to a decrease in
volume of hedged inventory stored by the Energy Services segment. From time to
time, the Energy Services segment stores hedged inventory to attempt to capture
value when market conditions are economically favorable. |
|
|
|
|
Trade receivables decreased by $6.9 million, due to the timing
of collections from customers, primarily as a result of the timing of the BORCO
acquisition, which occurred on January 18, 2011. |
|
|
|
|
Prepaid and other current assets decreased by $7.7 million
primarily due to a decrease in margin deposits on futures contracts in our
Energy Services segment as a result of increased commodity prices during the
three months ended March 31, 2011 (increased commodity prices result in an
increase in our broker equity account and therefore less margin deposit is
required), partially offset by an increase in prepaid insurance due to the
timing of policy renewals and an increase in unbilled revenue within our
Natural Gas Storage segment reflecting billings to counterparties in accordance
with terms of their storage agreements. |
|
|
|
|
Construction and pipeline relocation receivables decreased by
$1.4 million primarily due to a decrease in construction activity in the 2011
period. |
55
|
|
|
Accrued and other current liabilities decreased by $24.6
million primarily due to a decrease in accrued interest as a result of interest
payments made during the period, a decrease in accrued compensation and
benefits and a decrease due to the payment of accrued ammonia purchases during
the period. |
|
|
|
|
Accounts payable decreased by $25.3 million, due to lower
payable balances at March 31, 2011 as a result of the timing of invoice
payments, including those related to capital spending at our BORCO facility. |
Investing Activities
Net
cash flows used in investing activities was $955.7 million for the three months ended March
31, 2011 compared to net cash flows provided by investing activities of $11.2 million for the three
months ended March 31, 2010. The following were the principal factors resulting in the $966.9
million increase in net cash flows used in investing activities:
|
|
|
Capital expenditures increased by $27.0 million for the three months ended March 31,
2011 compared with the three months ended March 31, 2010. See below for a discussion
of capital spending. |
|
|
|
|
We completed the acquisition of BORCO by purchasing interests from First Reserve and
Vopak on January 18, 2011 and February 16, 2011, respectively, for approximately $1.4
billion of total consideration, consisting of $893.7 million in cash, which is net of
cash acquired of $27.0 million. The remaining consideration of $503.5 million
consisted of the issuance of LP Units and Class B Units. See Financing Activities
below for a discussion of the repayment of BORCOs outstanding indebtedness, which
occurred in connection with the BORCO acquisition. See Note 2 in the Notes to
Unaudited Condensed Consolidated Financial Statements for further discussion regarding
the BORCO acquisition. |
|
|
|
|
We paid $22.4 million as a deposit for the pending acquisition of pipeline and
terminal assets from BP, which we expect to close in the second quarter of 2011. See
Recent Developments for further discussion. |
|
|
|
|
Cash proceeds from the sale of the Buckeye NGL Pipeline were $22.0 million during
the three months ended March 31, 2010. |
Capital expenditures, net of non-cash changes in accruals for capital expenditures, were as
follows for the periods indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2011 |
|
|
2010 |
|
Sustaining capital expenditures |
|
$ |
7,473 |
|
|
$ |
3,270 |
|
Expansion and cost reduction |
|
|
30,560 |
|
|
|
7,693 |
|
|
|
|
|
|
|
|
Total capital expenditures, net |
|
$ |
38,033 |
|
|
$ |
10,963 |
|
|
|
|
|
|
|
|
Expansion and cost reduction projects in the first three months of 2011 included upgrades and
expansions of the jetty structure at BORCO, terminal ethanol and butane blending, new pipeline
connections, continued progress on a new pipeline and
terminal billing system as well as various other operating infrastructure projects. In the first
three months of 2010, expansion and cost reduction projects included the Kirby Hills Phase II
expansion project, terminal ethanol and butane blending, the construction of three additional tanks
with capacity of 0.4 million barrels in Linden, New Jersey and various other pipeline and terminal
operating infrastructure projects.
We expect to spend
approximately $320.0 million to $410.0 million for capital expenditures in
2011, of which approximately $50.0 million to $70.0 million is expected to relate to sustaining
capital expenditures and $270.0 million to $340.0 million is expected to relate to expansion and
cost reduction projects. Approximately $220.0 million to $280.0 million of these amounts are
related to capital expenditures in 2011 for the BORCO facility, of which $200.0 million to $250.0
million is expected to relate to expansion projects and $20.0 million to $30.0 million
56
is expected
to relate to sustaining capital expenditures. Approximately $100.0 million to $130.0 million of
these amounts are related to capital expenditures in 2011 for our other assets, excluding the BORCO
facility, of which $70.0 million to $90.0 million is expected to relate to expansion projects and
$30.0 million to $40.0 million is expected to relate to sustaining capital expenditures.
Sustaining 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. Major expansion and
cost reduction expenditures in 2011 will include upgrades and expansions of the jetty structure,
the inland dock and berth developments and terminal storage tank expansion projects at the BORCO
facility, completion of additional storage tanks in the Midwest, the
refurbishment of storage tanks and
facilities in the Northeast, installation of vapor recovery units
throughout our system of terminals, new injection and withdrawal
wells at our natural gas storage facilities and various
upgrades and expansions of our ethanol business. Cost reduction expenditures improve operational
efficiencies or reduce costs.
Financing Activities
Net
cash flows provided by financing activities was $852.1 million for the three months ended
March 31, 2011 compared to net cash flows used in financing activities of $172.7 million for the
three months ended March 31, 2010. The following were the principal factors resulting in the
$1,024.8 million increase in net cash flows provided by financing activities:
|
|
|
We borrowed $521.5 million and $59.5 million and repaid $284.5 million and $117.5
million under the Credit Facility during the three months ended March 31, 2011 and
2010, respectively. |
|
|
|
|
We repaid $318.2 million of debt assumed in the BORCO acquisition, which includes
settlement of BORCOs interest rate derivative instruments (see Note 2 in the Notes to
Unaudited Condensed Consolidated Financial Statements). |
|
|
|
|
Repayments under the Services Company 3.60% ESOP Notes were $1.5 million and $1.6
million during the three months ended March 31, 2011 and 2010, respectively. The 3.60%
ESOP Notes were repaid in full in March 2011. |
|
|
|
|
Net repayments under the BES Credit Agreement were $49.3 million and $56.3 million
during the three months ended March 31, 2011 and 2010, respectively. |
|
|
|
|
We received $647.5 million from the issuance in January 2011 of $650.0 million in
aggregate principal amount of the 4.875% Notes in an underwritten public offering.
Debt issuance costs incurred were $4.9 million. Proceeds from this offering were used
to fund a portion of the BORCO acquisition. In connection with this debt offering, we
settled a treasury lock agreement, which resulted in the receipt of $0.5 million that
is being amortized into interest expense over the ten-year term of the 4.875% Notes. |
|
|
|
|
We received total proceeds of $425.0 million from the issuance of 5,794,725 LP Units
and 1,314,870 Class B Units to institutional investors in January 2011 to fund a
portion of the BORCO acquisition. Equity issuance costs incurred in our equity
transactions were approximately $4.6 million. |
|
|
|
|
We received $0.3 million and $2.4 million in net proceeds from the exercise of LP
Unit options during the three months ended March 31, 2011 and 2010, respectively. |
|
|
|
|
Cash distributions paid to our partners were $78.1 million ($0.9875 per LP Unit) for
the three months ended March 31, 2011. Cash distributions paid to partners of BGH were
$11.6 million ($0.41 per unit) for the three months ended March 31, 2010. In
connection with the Merger, BGHs units were converted into Buckeye LP Units. |
|
|
|
|
Distributions to noncontrolling partners of Buckeye, consisting primarily of
distributions paid by Sabina and WesPac Memphis, were $1.2 million for the three months
ended March 31, 2011. Distributions to noncontrolling partners of Buckeye, consisting
primarily of distributions to holders of LP Units, were $47.6 million for the three
months ended March 31, 2010. Included in this amount was approximately $1.1 million of
distributions paid primarily by Sabina and WesPac Memphis. Buckeye paid cash
distributions of $0.9375 per LP Unit in the 2010 period. In connection with the
Merger, the majority of noncontrolling interests were eliminated. |
57
Derivatives
See Item 3. Quantitative and Qualitative Disclosures About Market Risk Market Risk Non
Trading Instruments for a discussion of commodity derivatives used by our Energy Services segment.
Other Considerations
Contractual Obligations
The following table summarizes our contractual obligations as of March 31, 2011 (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period (1) |
|
|
|
Total |
|
|
Less than 1 year |
|
|
1-3 years |
|
|
3-5 years |
|
|
More than 5 years |
|
Long-term debt (2) |
|
$ |
2,410,000 |
|
|
$ |
|
|
|
$ |
635,000 |
|
|
$ |
275,000 |
|
|
$ |
1,500,000 |
|
Interest payments (3) |
|
|
927,873 |
|
|
|
63,767 |
|
|
|
214,929 |
|
|
|
185,988 |
|
|
|
463,189 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating leases: (4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Office space and other (5) |
|
|
26,216 |
|
|
|
1,524 |
|
|
|
4,510 |
|
|
|
4,867 |
|
|
|
15,315 |
|
Equipment (6) |
|
|
11,808 |
|
|
|
2,620 |
|
|
|
7,095 |
|
|
|
2,093 |
|
|
|
|
|
Land leases (7) |
|
|
382,321 |
|
|
|
3,500 |
|
|
|
9,906 |
|
|
|
10,324 |
|
|
|
358,591 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase obligations (8) |
|
|
46,653 |
|
|
|
46,653 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditure
obligations (9) |
|
|
1,814 |
|
|
|
1,814 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual cash
obligations |
|
$ |
3,806,685 |
|
|
$ |
119,878 |
|
|
$ |
871,440 |
|
|
$ |
478,272 |
|
|
$ |
2,337,095 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Less than 1 year represents amounts for the remainder of 2011 (April 1 through December
31), 1-3 years represents amounts for 2012 and 2013, 3-5 years represents amounts for 2014
and 2015, and more than 5 years represents amounts after 2015. |
|
(2) |
|
We have long-term payment obligations under our Credit Facility and our underwritten
publicly issued notes. Amounts shown in the table represent our scheduled future
maturities of long-term debt principal for the periods indicated. We have assumed that the
borrowings under our Credit Facility as of March 31, 2011 will not be repaid until the
maturity date of the facility. See Note 11 in the Notes to Unaudited Condensed
Consolidated Financial Statements for additional information regarding our debt
obligations. |
|
(3) |
|
Interest payments include amounts due on our notes and interest payments and commitment
fees due on our Credit Facility. The interest amount calculated on the Credit Facility is
based on the assumption that the amount outstanding and the interest rate charged both
remain at their current levels. |
|
(4) |
|
We lease certain property, plant and equipment under noncancelable and cancelable
operating leases. Amounts shown in the table represent minimum lease payment obligations
under our operating leases with terms in excess of one year for the periods indicated.
Lease expense is charged to operating expenses on a straight line basis over the period of
expected benefit. Contingent rental payments are expensed as incurred. Total rental
expense for the three months ended March 31, 2011 and 2010 was $7.6 million and $5.0
million, respectively. |
|
(5) |
|
Includes leases of space in office buildings and related land leases with respect to
our Albany terminal. |
|
(6) |
|
Includes BORCO facility leases for tugboats and a barge in our International Operations
segment. |
|
(7) |
|
Includes leases for inland dock and seabed in connection with our International
Operations segment and leases for subsurface underground gas storage rights and surface
rights in connection with our operations in the Natural Gas Storage segment. We may cancel
the Natural Gas Storage segment leases if the storage reservoir is not used for underground
storage of natural gas or the removal or injection thereof for a continuous period of two
consecutive years. Lease expense associated with the Natural Gas Storage segment leases,
which is being recognized on a straight-line basis over 44 years, was approximately $1.8
million for each the three months ended March 31, 2011 and 2010. At March 31, 2011 and
December 31, 2010, the balance of our Natural Gas Storage segment deferred lease liability
was $14.4 million and |
58
|
|
|
|
|
$13.3 million, respectively. We estimate that this deferred lease
liability will continue to increase through 2032, at which time our deferred lease
liability is estimated to be approximately $64.7 million. Our deferred lease liability
will then be reduced over the remaining 19 years of the lease, since the expected annual
lease payments will exceed the amount of lease expense. |
|
(8) |
|
We have long and short-term purchase obligations for products and services with
third-party suppliers. The prices that we are obligated to pay under these contracts
approximate current market prices. The table shows our commitments and estimated payment
obligations under these contracts for the periods indicated.
Our estimated future payment obligations are based on the contractual price under each
contract for products and services at March 31, 2011. |
|
(9) |
|
We have short-term payment obligations relating to capital projects we have initiated.
These commitments represent unconditional payment obligations that we have agreed to pay
vendors for services rendered or products purchased. |
In addition, our obligations related to our pension and postretirement benefit plans are
discussed in Note 15 in the Notes to Unaudited Condensed Consolidated Financial Statements.
Off-Balance Sheet Arrangements
There have been no material changes with regard to our off-balance sheet arrangements since
those reported in our Annual Report on Form 10-K/A for the year ended December 31, 2010.
Related Party Transactions
With respect to related party transactions, see Note 17 in the Notes to Unaudited Condensed
Consolidated Financial Statements.
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
Market Risk Trading Instruments
We have no trading derivative instruments.
Market Risk Non-Trading Instruments
We are exposed to financial market risk resulting from changes in commodity prices and
interest rates. BORCOs functional currency is the U.S. dollar and it is equivalent in value with
the Bahamian dollar. Foreign exchange gains and losses arising from transactions denominated in a
currency other than the functional currency are included in net income in the consolidated
statements of operations. The effects of foreign currency transactions were not considered to be
material for the three months ended March 31, 2011.
Commodity Risk
Natural Gas Storage
The Natural Gas Storage segment enters into interruptible natural gas storage hub service
agreements in order to maximize the daily utilization of the natural gas storage facility, while
also attempting to capture value from seasonal price differences in the natural gas markets.
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.
59
As of March 31, 2011, the Natural Gas Storage segment has recorded the following assets and
liabilities related to its hub services agreements (in thousands):
|
|
|
|
|
|
|
March 31, |
|
|
|
2011 |
|
Assets: |
|
|
|
|
Hub service agreements |
|
$ |
28,657 |
|
|
|
|
|
|
Liabilities: |
|
|
|
|
Hub service agreements |
|
|
(18,331 |
) |
|
|
|
|
Total |
|
$ |
10,326 |
|
|
|
|
|
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 commodity forward fixed-price purchase and sales contracts. The
derivative contracts used to hedge refined petroleum product inventories are classified as fair
value hedges. Accordingly, our method of measuring ineffectiveness compares the changes in the
fair value of the New York Mercantile Exchange (NYMEX) futures contracts to the change in fair
value of our hedged fuel inventory.
Our Energy Services segment has not used hedge accounting with respect to its physical
derivative contracts. Therefore, our physical derivative contracts and the related futures
contracts used to offset the changes in fair value of the physical derivative contracts are all
marked-to-market on the consolidated balance sheet with gains and losses being recognized in
earnings during the period. In addition, hedge accounting has not been elected for futures
contracts that have been executed to economically hedge a portion of the Energy Services segments
refined petroleum products held in inventory; therefore, the changes in fair value of the futures
contracts are marked-to-market on the consolidated balance sheet with gains and losses being
recognized in earnings during the period.
As of March 31, 2011, the Energy Services segment had derivative assets and liabilities as
follows (in thousands):
|
|
|
|
|
|
|
March 31, |
|
|
|
2011 |
|
Assets: |
|
|
|
|
Physical derivative contracts for refined products |
|
$ |
1,247 |
|
|
|
|
|
|
Liabilities: |
|
|
|
|
Physical derivative contracts for refined products |
|
|
(2,508 |
) |
Futures contracts for refined products |
|
|
(4,289 |
) |
Futures contracts for natural gas |
|
|
(116 |
) |
|
|
|
|
Total |
|
$ |
(5,666 |
) |
|
|
|
|
Our hedged inventory portfolio extends to the third quarter of 2011. The majority of the
unrealized loss at March 31, 2011 for inventory hedges represented by futures contracts will be
realized by the second quarter of 2011 as the inventory is sold. During the three months ended
March 31, 2011, a gain of $4.0 million was recorded on inventory hedges that were ineffective, and
a loss of $10.5 million was recorded in earnings related to the time value component of the
derivative instruments fair value that was excluded from the assessment of hedge effectiveness. At
March 31, 2011, open refined petroleum product derivative contracts varied in duration in the
overall portfolio, but did not extend beyond June 2012. In addition, at March 31, 2011, we had
refined petroleum product inventories that we intend to use to satisfy a portion of the physical
derivative contracts.
60
Based on a hypothetical 10% movement in the underlying quoted market prices of the commodity
financial instruments outstanding at March 31, 2011, the estimated fair value of the portfolio of
commodity financial instruments would be as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
|
|
|
|
|
|
Financial |
|
|
|
|
|
|
|
Instrument |
|
|
|
Resulting |
|
|
Portfolio |
|
Scenario |
|
Classification |
|
|
Fair Value |
|
Fair value assuming no change in underlying
commodity prices (as is) |
|
Liability |
|
$ |
(5,666 |
) |
Fair value assuming 10% increase in underlying
commodity prices |
|
Liability |
|
$ |
(27,549 |
) |
Fair value assuming 10% decrease in underlying
commodity prices |
|
Asset |
|
$ |
16,217 |
|
The value of the open futures contract positions noted above were based upon quoted market
prices obtained from NYMEX. The value of the physical derivative contracts was based on observable
market data related to the obligation to provide refined petroleum products to customers.
As discussed above, these commodity financial instruments are used primarily to manage the
risk of market price volatility on the Energy Services segments refined petroleum product
inventories and its physical derivative contracts. The derivative contracts used to hedge refined
petroleum product inventories are classified as fair value hedges and are, therefore, expected to
be highly effective in offsetting changes in the fair value of the refined petroleum product
inventories.
Interest Rate Risk
We utilize forward-starting interest rate swaps to manage interest rate risk related to
forecasted interest payments on anticipated debt issuances. This strategy is a component in
controlling our cost of capital associated with such borrowings. When entering into interest rate
swap transactions, we become exposed to both credit risk and market risk. We are subject to credit
risk when the value of the swap transaction is positive and the risk exists that the counterparty
will fail to perform under the terms of the contract. We are subject to market risk with respect
to changes in the underlying benchmark interest rate that impact the fair value of the swaps. We
manage our credit risk by only entering into swap transactions with major financial institutions
with investment-grade credit ratings. We manage our market risk by associating each swap
transaction with an existing debt obligation or a specified expected debt issuance generally
associated with the maturity of an existing debt obligation.
Our practice with respect to derivative transactions related to interest rate risk has been to
have each transaction in connection with non-routine borrowings authorized by the board of
directors of Buckeye GP. In January 2009, Buckeye GPs board of directors adopted an interest rate
hedging policy which permits us to enter into certain short-term interest rate hedge agreements to
manage our interest rate and cash flow risks associated with the Credit Facility. In addition, in
July 2009 and May 2010, Buckeye GPs board of directors authorized us to enter into certain
transactions, such as forward starting interest rate swaps, to manage our interest rate and cash
flow risks related to certain expected debt issuances associated with the maturity of existing debt
obligations.
At March 31, 2011, we had total fixed-rate debt obligations at face value of $2,075.0 million,
consisting of $300.0 million of the 4.625% Notes, $275.0 million of the 5.300% Notes, $125.0
million of the 5.125% Notes, $300.0 million of the 6.050% Notes, $275.0 million of the 5.500%
Notes, $650.0 million of the 4.875% Notes and $150.0 million of the 6.750% Notes. The fair value
of these fixed-rate debt obligations at March 31, 2011 was approximately $2,163.9 million. We
estimate that a 1% decrease in rates for obligations of similar maturities would increase the fair
value of our fixed-rate debt obligations by approximately $133.8 million.
61
At March 31, 2011, our variable-rate obligations were $335.0 million under the Credit Facility
and $235.0 million under the BES Credit Agreement. Based on the balances outstanding at March 31,
2011, we estimate that a 1% increase or decrease in interest rates would increase or decrease
annual interest expense by approximately $5.7 million.
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. The purpose of these
swaps is to hedge the variability of the forecasted interest payments on these expected debt
issuances that may result from changes in the benchmark interest rate until the expected debt is
issued. During the three months ended March 31, 2011, unrealized losses of $4.5 million were
recorded in accumulated other comprehensive income (loss) to reflect the change in the fair values
of the forward-starting interest rate swaps. We designated the swap agreements as cash flow hedges
at inception and expect the changes in values to be highly correlated with the changes in value of
the underlying borrowings.
On January 13, 2011, we sold the 4.875% Notes in an underwritten public offering. In December
2010, in connection with the proposed offering, we entered into a treasury lock agreement to fix
the ten-year treasury rate at 3.3375% per annum on a notional amount of $650.0 million. In January
2011, we subsequently cash-settled the treasury lock agreement upon the issuance of the 4.875%
Notes and received approximately $0.5 million, which is being recognized as a reduction to interest
and debt expense over the ten-year term of the 4.875% Notes.
The following table presents the effect of hypothetical price movements on the estimated fair
value of our interest rate swap portfolio and the related change in fair value of the underlying
debt at March 31, 2011 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial |
|
|
|
|
|
|
|
Instrument |
|
|
|
Resulting |
|
|
Portfolio |
|
Scenario |
|
Classification |
|
|
Fair Value |
|
Fair value assuming no change in underlying
interest rates (as is) |
|
Asset |
|
$ |
7,864 |
|
Fair value assuming 10% increase in underlying
interest rates |
|
Asset |
|
$ |
29,020 |
|
Fair value assuming 10% decrease in underlying
interest rates |
|
Liability |
|
$ |
(14,238 |
) |
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 SECs 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.
62
(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 2011 that have materially affected, or are reasonably likely to materially affect, our
internal controls over financial reporting.
We closed the BORCO acquisitions on January 18, 2011 and February 16, 2011, and have begun the
evaluation of the internal control structure of BORCO. We expect that evaluation to continue
during the remainder of 2011. In recording the BORCO acquisitions, we followed our normal
accounting procedures and internal controls. Our management also reviewed the operations of BORCO
that are included in our earnings for the three months ended March 31, 2011.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
For information on legal proceedings, see Part 1, 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.
Item 1A. Risk Factors
Security holders and potential investors in our securities should carefully consider the risk
factors set forth in Part 1, Item 1A. Risk Factors of our Annual Report on Form 10-K/A for the
year ended December 31, 2010 in addition to other information in such report and in this quarterly
report. 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.
Item 6. Exhibits
(a) Exhibits
|
|
|
2.1
|
|
Sale and Purchase Agreement by and among Vopak Bahamas B.V., Koninklijke Vopak
N.V. and Buckeye Atlantic Holdings LLC dated as of February 15, 2011
(Incorporated by reference to Exhibit 2.1 of Buckeye Partners, L.P.s Current
Report on Form 8-K filed on February 22, 2011). |
|
|
|
2.2
|
|
Asset Purchase Agreement, dated March 17, 2011, by and among BP Products North
America Inc., BP West Coast Products LLC, and Buckeye Partners, L.P.
(Incorporated by reference to Exhibit 2.1 of Buckeye Partners, L.P.s Current
Report on Form 8-K filed on March 18, 2011). |
|
|
|
2.3
|
|
Share Purchase Agreement, dated March 17, 2011, by and among BP Oil Pipeline
Company and Buckeye Partners, L.P. (Incorporated by reference to Exhibit 2.1
of Buckeye Partners, L.P.s Current Report on Form 8-K filed on March 18,
2011). |
|
|
|
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). |
63
|
|
|
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). |
|
|
|
4.1
|
|
Indenture dated as of July 10, 2003, between Buckeye Partners, L.P. and
SunTrust Bank, as Trustee (Incorporated by reference to Exhibit 4.1 of Buckeye
Partners, L.P.s Registration Statement on Form S-4 filed September 19, 2003). |
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4.2
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First Supplemental Indenture dated as of July 10, 2003, between Buckeye
Partners, L.P. and SunTrust Bank, as Trustee (Incorporated by reference to
Exhibit 4.2 of Buckeye Partners, L.P.s Registration Statement on Form S-4
filed September 19, 2003). |
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4.3
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Second Supplemental Indenture dated as of August 19, 2003, between Buckeye
Partners, L.P. and SunTrust Bank, as Trustee (Incorporated by reference to
Exhibit 4.3 of Buckeye Partners, L.P.s Registration Statement on Form S-4
filed September 19, 2003). |
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4.4
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Third Supplemental Indenture dated as of October 12, 2004, between Buckeye
Partners, L.P. and SunTrust Bank, as Trustee (Incorporated by reference to
Exhibit 4.1 of Buckeye Partners, L.P.s Current Report on Form 8-K filed on
October 14, 2004). |
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4.5
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Fourth Supplemental Indenture dated as of June 30, 2005, between Buckeye
Partners, L.P. and SunTrust Bank, as Trustee (Incorporated by reference to
Exhibit 4.1 of Buckeye Partners, L.P.s Current Report on Form 8-K filed on
June 30, 2005). |
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4.6
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Fifth Supplemental Indenture dated as of January 11, 2008, between Buckeye
Partners, L.P. and U.S. Bank National Association (successor to SunTrust
Bank), as Trustee (Incorporated by reference to Exhibit 4.1 of Buckeye
Partners, L.P.s Current Report on Form 8-K filed on January 11, 2008). |
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4.7
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Sixth Supplemental Indenture dated as of August 18, 2009, between Buckeye
Partners, L.P. and U.S. Bank National Association (successor-in-interest to
SunTrust Bank), as Trustee (Incorporated by reference to Exhibit 4.1 of
Buckeye Partners, L.P.s Current Report on Form 8-K filed on August 24, 2009). |
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4.8
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Seventh Supplemental Indenture dated as of January 13, 2011, between Buckeye
Partners, L.P. and U.S. Bank National Association (successor-in-interest to
SunTrust Bank), as Trustee (Incorporated by reference to Exhibit 4.1 of
Buckeye Partners, L.P.s Current Report on Form 8-K filed on January 20,
2011). |
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4.9
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Registration Rights Agreement, by and among Buckeye Partners, L.P., BGH GP
Holdings, LLC, ArcLight Energy Partners Fund III, L.P., ArcLight Energy
Partners Fund IV, L.P., Kelso Investment Associates VIII, L.P. and KEP VI, LLC
(Incorporated by reference to Exhibit 10.2 of Buckeye Partners, L.P.s Current
Report on Form 8-K filed on June 11, 2010). |
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4.10
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Registration Rights Agreement by and among Buckeye Partners, L.P., FR XI
Offshore AIV, L.P. and the other investors named therein, dated as of December
18, 2010 (Incorporated by reference to Exhibit 10.4 of Buckeye Partners,
L.P.s Current Report on Form 8-K filed on December 21, 2010). |
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4.11
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Registration Rights Agreement by and among Buckeye Partners, L.P. and the
investors named therein, dated as of December 18, 2010 (Incorporated by
reference to Exhibit 10.5 of Buckeye Partners, L.P.s Current Report on Form
8-K filed on December 21, 2010). |
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4.12
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Registration Rights Agreement by and between Buckeye Partners, L.P. and Vopak
Bahamas B.V. dated as of February 15, 2011 (Incorporated by reference to
Exhibit 10.2 of Buckeye Partners, L.P.s Current Report on Form 8-K filed on
February 22, 2011). |
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*10.1
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Buckeye Partners, L.P. Annual Incentive Compensation Plan, as Amended and
Restated, effective as of January 1, 2011 (Incorporated by reference to
Exhibit 10.1 of Buckeye Partners, L.P.s Current Report on Form 8-K filed on
January 19, 2011). |
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10.2
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Unit Purchase Agreement by and between Buckeye Partners, L.P. and Vopak
Bahamas B.V. dated as of February 15, 2011 (Incorporated by reference to
Exhibit 10.1 of Buckeye Partners, L.P.s Current Report of Form 8-K filed on
February 22, 2011). |
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10.3
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Transition Support Agreement by and among Buckeye Atlantic Holdings LLC, Vopak
Bahamas B.V., FR Borco Topco L.P., FR Borco Coop Holdings, L.P., FR Borco Coop
Holdings GP Limited, Bahamas Oil Refining Company International Limited and
Vopak Koninklijke N.V. dated as of February 15, 2011 (Incorporated by
reference to Exhibit 10.1 of Buckeye Partners, L.P.s Current Report of Form
8-K filed on February 22, 2011). |
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*/**10.4
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2011 Amendment to the Buckeye Partners, L.P. Unit Option and Distribution
Equivalent Plan, dated March 25, 2011. |
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**31.1
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Certification of Chief Executive Officer pursuant to Rule 13a-14 (a) under the
Securities Exchange Act of 1934. |
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**31.2
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Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the
Securities Exchange Act of 1934. |
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**32.1
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Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350. |
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**32.2
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Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350. |
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**101.INS
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XBRL Instance Document. |
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**101.SCH
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XBRL Taxonomy Extension Schema Document. |
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**101.CAL
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XBRL Taxonomy Extension Calculation Linkbase Document. |
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**101.LAB
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XBRL Taxonomy Extension Label Linkbase Document. |
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**101.PRE
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XBRL Taxonomy Extension Presentation Linkbase Document. |
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**101.DEF
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XBRL Taxonomy Extension Definition Linkbase Document. |
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* |
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Represents management contract or compensatory plan or arrangement. |
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** |
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Filed herewith. |
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Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. Buckeye agrees to
furnish supplementally a copy of the omitted schedules to the SEC upon request. |
65
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.
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By: |
BUCKEYE
PARTNERS, L.P. (Registrant)
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By: |
Buckeye GP
LLC, as General Partner
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Date: May 9, 2011 |
By: |
/s/ Keith E. St.Clair
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Keith E. St.Clair |
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Senior Vice President and Chief Financial Officer (Principal Financial Officer) |
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66