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, 2010
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 Date File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files). Yes
o 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 outstanding as of May 3, 2010: 51,501,265
PART I. FINANCIAL INFORMATION
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Item 1. |
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Financial Statements |
BUCKEYE PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per limited partner unit amounts)
(Unaudited)
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Three Months Ended |
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March 31, |
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2010 |
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2009 |
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Revenues: |
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Product sales |
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$ |
568,170 |
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$ |
268,779 |
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Transportation and other services |
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163,004 |
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148,061 |
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Total revenue |
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731,174 |
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416,840 |
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Costs and expenses: |
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Cost of product sales and natural gas storage services |
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569,737 |
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250,676 |
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Operating expenses |
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65,709 |
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73,507 |
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Depreciation and amortization |
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15,644 |
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14,480 |
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General and administrative |
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9,064 |
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8,074 |
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Total costs and expenses |
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660,154 |
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346,737 |
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Operating income |
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71,020 |
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70,103 |
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Other income (expense): |
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Earnings from equity investments |
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2,652 |
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2,082 |
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Interest and debt expense |
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(21,549 |
) |
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(17,176 |
) |
Other income |
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155 |
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111 |
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Total other expense |
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(18,742 |
) |
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(14,983 |
) |
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Net income |
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52,278 |
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55,120 |
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Less: net income attributable to noncontrolling interests |
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(1,765 |
) |
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(1,360 |
) |
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Net income attributable to Buckeye Partners, L.P. |
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$ |
50,513 |
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$ |
53,760 |
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Allocation of net income attributable to Buckeye Partners,
L.P.: |
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Net income allocated to general partner |
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$ |
12,495 |
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$ |
11,666 |
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Net income allocated to limited partners |
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$ |
38,018 |
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$ |
42,094 |
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Earnings Per Limited Partner Unit: |
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Basic |
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$ |
0.73 |
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$ |
0.87 |
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Diluted |
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$ |
0.73 |
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$ |
0.87 |
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Weighted average number of limited partner units outstanding: |
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Basic |
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51,471 |
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48,401 |
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Diluted |
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51,634 |
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48,406 |
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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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2010 |
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2009 |
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Net income |
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$ |
52,278 |
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$ |
55,120 |
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Other comprehensive income (loss): |
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Change in value of derivatives |
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(1,928 |
) |
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190 |
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Amortization of interest rate swaps |
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240 |
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240 |
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Amortization of benefit plan costs |
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22 |
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(359 |
) |
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Total other comprehensive income (loss) |
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(1,666 |
) |
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71 |
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Comprehensive income |
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$ |
50,612 |
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$ |
55,191 |
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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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2010 |
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2009 |
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Assets: |
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Current assets: |
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Cash and cash equivalents |
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$ |
16,507 |
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$ |
34,599 |
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Trade receivables, net |
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134,563 |
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124,165 |
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Construction and pipeline relocation receivables |
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11,420 |
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14,095 |
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Inventories |
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246,230 |
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310,214 |
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Derivative assets |
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1,964 |
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4,959 |
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Assets held for sale |
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22,000 |
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Prepaid and other current assets |
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77,125 |
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103,691 |
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Total current assets |
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487,809 |
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613,723 |
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Property, plant and equipment, net |
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2,224,409 |
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2,228,265 |
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Equity investments |
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99,503 |
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96,851 |
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Goodwill |
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208,876 |
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208,876 |
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Intangible assets, net |
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44,044 |
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45,157 |
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Other non-current assets |
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56,333 |
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62,777 |
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Total assets |
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$ |
3,120,974 |
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$ |
3,255,649 |
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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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$ |
183,500 |
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$ |
239,800 |
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Accounts payable |
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53,562 |
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56,525 |
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Derivative liabilities |
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2,831 |
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14,665 |
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Accrued and other current liabilities |
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105,604 |
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106,743 |
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Total current liabilities |
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345,497 |
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417,733 |
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Long-term debt |
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1,441,076 |
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1,498,970 |
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Other non-current liabilities |
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105,800 |
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102,851 |
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Total liabilities |
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1,892,373 |
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2,019,554 |
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Commitments and contingent liabilities |
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Partners capital: |
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Buckeye Partners, L.P. unitholders capital: |
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General Partner (243,914 units outstanding as of
March 31, 2010 and December 31, 2009) |
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1,801 |
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1,849 |
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Limited Partners (51,492,565 and 51,438,265 units
outstanding
as of March 31, 2010 and December 31, 2009,
respectively) |
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1,207,739 |
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1,214,136 |
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Accumulated other comprehensive loss |
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(2,513 |
) |
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(847 |
) |
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Total Buckeye Partners, L.P. unitholders capital |
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1,207,027 |
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1,215,138 |
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Noncontrolling interests |
|
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21,574 |
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20,957 |
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Total partners capital |
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1,228,601 |
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1,236,095 |
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Total liabilities and partners capital |
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$ |
3,120,974 |
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$ |
3,255,649 |
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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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2010 |
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2009 |
|
Cash flows from operating activities: |
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Net income |
|
$ |
52,278 |
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$ |
55,120 |
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|
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Adjustments to reconcile net income to cash provided by
operating activities: |
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|
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Depreciation and amortization |
|
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15,644 |
|
|
|
14,480 |
|
Net changes in fair value of derivatives |
|
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(19,183 |
) |
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|
4,103 |
|
Non-cash deferred lease expense |
|
|
1,059 |
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|
1,125 |
|
Earnings from equity investments |
|
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(2,652 |
) |
|
|
(2,082 |
) |
Distributions from equity investments |
|
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|
235 |
|
Amortization of other non-cash items |
|
|
2,481 |
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|
|
879 |
|
Change in assets and liabilities: |
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Trade receivables |
|
|
(10,398 |
) |
|
|
(2,012 |
) |
Construction and pipeline relocation receivables |
|
|
2,675 |
|
|
|
3,064 |
|
Inventories |
|
|
73,705 |
|
|
|
26,101 |
|
Prepaid and other current assets |
|
|
26,899 |
|
|
|
2,704 |
|
Accounts payable |
|
|
(2,963 |
) |
|
|
(11,079 |
) |
Accrued and other current liabilities |
|
|
347 |
|
|
|
(17,748 |
) |
Other non-current assets |
|
|
2,964 |
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|
2,103 |
|
Other non-current liabilities |
|
|
1,890 |
|
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|
2,640 |
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Total adjustments from operating activities |
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|
92,468 |
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|
24,513 |
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Net cash provided by operating activities |
|
|
144,746 |
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|
79,633 |
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Cash flows from investing activities: |
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Capital expenditures |
|
|
(10,963 |
) |
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|
(20,976 |
) |
Net proceeds (expenditures) for disposal of property,
plant and equipment |
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|
22,174 |
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(42 |
) |
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Net cash provided by (used in) investing activities |
|
|
11,211 |
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(21,018 |
) |
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Cash flows from financing activities: |
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Net proceeds from issuance of limited partner units |
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|
91,042 |
|
Proceeds from exercise of limited partner unit options |
|
|
2,376 |
|
|
|
|
|
Borrowings under credit facilities |
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|
59,500 |
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|
30,000 |
|
Repayments under credit facilities |
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|
(117,500 |
) |
|
|
(120,267 |
) |
Net repayments under BES credit agreement |
|
|
(56,300 |
) |
|
|
(46,000 |
) |
Debt issuance costs |
|
|
(9 |
) |
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|
(13 |
) |
Distributions paid to noncontrolling interests |
|
|
(1,148 |
) |
|
|
(1,307 |
) |
Distributions paid to partners |
|
|
(60,968 |
) |
|
|
(53,651 |
) |
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Net cash used in financing activities |
|
|
(174,049 |
) |
|
|
(100,196 |
) |
|
|
|
|
|
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|
Net decrease in cash and cash equivalents |
|
|
(18,092 |
) |
|
|
(41,581 |
) |
Cash and cash equivalents Beginning of period |
|
|
34,599 |
|
|
|
58,843 |
|
|
|
|
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Cash and cash equivalents End of period |
|
$ |
16,507 |
|
|
$ |
17,262 |
|
|
|
|
|
|
|
|
See Notes to Unaudited Condensed Consolidated Financial Statements.
5
BUCKEYE PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS CAPITAL (DEFICIT)
(In thousands)
(Unaudited)
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Buckeye Partners, L.P. Unitholders |
|
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|
|
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|
|
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Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
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Other |
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|
|
General |
|
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Limited |
|
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Comprehensive |
|
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Noncontrolling |
|
|
|
|
|
|
Partner |
|
|
Partners |
|
|
Income (Loss) |
|
|
Interests |
|
|
Total |
|
Balance January 1, 2009 |
|
$ |
(6,680 |
) |
|
$ |
1,201,144 |
|
|
$ |
(18,967 |
) |
|
$ |
20,775 |
|
|
$ |
1,196,272 |
|
Net income |
|
|
11,666 |
|
|
|
42,094 |
|
|
|
|
|
|
|
1,360 |
|
|
|
55,120 |
|
Change in value of derivatives |
|
|
|
|
|
|
|
|
|
|
190 |
|
|
|
|
|
|
|
190 |
|
Amortization of interest rate swaps |
|
|
|
|
|
|
|
|
|
|
240 |
|
|
|
|
|
|
|
240 |
|
Amortization of benefit plan costs |
|
|
|
|
|
|
|
|
|
|
(359 |
) |
|
|
|
|
|
|
(359 |
) |
Distributions paid to partners |
|
|
(10,721 |
) |
|
|
(42,930 |
) |
|
|
|
|
|
|
|
|
|
|
(53,651 |
) |
Distributions paid to
noncontrolling interests |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,307 |
) |
|
|
(1,307 |
) |
Net proceeds from the issuance of
limited partner units |
|
|
|
|
|
|
91,042 |
|
|
|
|
|
|
|
|
|
|
|
91,042 |
|
Amortization of unit-based
compensation awards |
|
|
|
|
|
|
90 |
|
|
|
|
|
|
|
|
|
|
|
90 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance March 31, 2009 |
|
$ |
(5,735 |
) |
|
$ |
1,291,440 |
|
|
$ |
(18,896 |
) |
|
$ |
20,828 |
|
|
$ |
1,287,637 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance January 1, 2010 |
|
$ |
1,849 |
|
|
$ |
1,214,136 |
|
|
$ |
(847 |
) |
|
$ |
20,957 |
|
|
$ |
1,236,095 |
|
Net income |
|
|
12,495 |
|
|
|
38,018 |
|
|
|
|
|
|
|
1,765 |
|
|
|
52,278 |
|
Change in value of derivatives |
|
|
|
|
|
|
|
|
|
|
(1,928 |
) |
|
|
|
|
|
|
(1,928 |
) |
Amortization of interest rate swaps |
|
|
|
|
|
|
|
|
|
|
240 |
|
|
|
|
|
|
|
240 |
|
Amortization of benefit plan costs |
|
|
|
|
|
|
|
|
|
|
22 |
|
|
|
|
|
|
|
22 |
|
Distributions paid to partners |
|
|
(12,543 |
) |
|
|
(48,425 |
) |
|
|
|
|
|
|
|
|
|
|
(60,968 |
) |
Distributions paid to
noncontrolling interests |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,148 |
) |
|
|
(1,148 |
) |
Non-cash
accrual for distribution equivalent rights |
|
|
|
|
|
|
(390 |
) |
|
|
|
|
|
|
|
|
|
|
(390 |
) |
Amortization of unit-based
compensation awards |
|
|
|
|
|
|
2,024 |
|
|
|
|
|
|
|
|
|
|
|
2,024 |
|
Exercise of limited partner unit
options |
|
|
|
|
|
|
2,376 |
|
|
|
|
|
|
|
|
|
|
|
2,376 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance March 31, 2010 |
|
$ |
1,801 |
|
|
$ |
1,207,739 |
|
|
$ |
(2,513 |
) |
|
$ |
21,574 |
|
|
$ |
1,228,601 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Notes to Unaudited Condensed Consolidated Financial Statements.
6
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Except for per unit amounts, or as otherwise noted within the context of each footnote
disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are
stated in thousands.
1. ORGANIZATION AND BASIS OF PRESENTATION
Partnership Organization
Buckeye Partners, L.P. is a publicly traded Delaware master limited partnership (MLP), the
limited partner units (LP Units) of which are listed on the New York Stock Exchange (NYSE)
under the ticker symbol BPL. 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 67 active products terminals that provide aggregate storage capacity of
approximately 27.2 million barrels. In addition, we operate and maintain approximately 2,400 miles
of other pipelines under agreements with major oil and gas, petrochemical and chemical companies,
and perform certain engineering and construction management services for third parties. We also
own and operate a major 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: Pipeline Operations;
Terminalling & Storage; Natural Gas Storage; Energy Services; and Development & Logistics.
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 MLP that is also publicly traded on the NYSE under
the ticker symbol BGH.
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, 2010, Services Company owned approximately 3.0% of our LP Units. Services
Company employees provide services to our operating subsidiaries. Pursuant to a services agreement
entered into in December 2004 (the Services Agreement), our operating subsidiaries reimburse
Services Company for the costs of the services provided by Services Company.
Basis of Presentation
The accompanying unaudited condensed consolidated financial statements reflect all adjustments
that are, in the opinion of our management, of a normal and recurring nature and necessary for a
fair statement of our financial position as of March 31, 2010, and the results of our operations
and cash flows for the periods presented. The results of operations for the three months ended
March 31, 2010 are not necessarily indicative of results of our operations for the 2010 fiscal
year. The unaudited condensed consolidated financial statements have been prepared pursuant to the
rules and regulations of the U.S. Securities and Exchange Commission (SEC). We have eliminated
all intercompany transactions in consolidation. Certain information and note disclosures normally
included in annual financial statements prepared in accordance with U.S. generally accepted
accounting principles (GAAP) have been condensed or omitted pursuant to those rules and
regulations. These interim financial statements should be read in conjunction with our consolidated
financial statements and notes thereto presented in our Annual Report on Form 10-K for the year
ended December 31, 2009, as filed with the SEC on February 26, 2010.
7
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Reclassifications
Certain prior year amounts have been reclassified in the condensed consolidated statements of
operations and condensed consolidated statements of cash flows to conform to the current-year
presentation. The reclassifications in the condensed consolidated statements of operations are as
follows:
|
|
|
Earnings from equity investments are now presented on a separate line item in the
condensed consolidated statements of operations for the three months ended March 31,
2009. The other investment income that had previously been included with earnings from
equity investments has been reclassified and included in Other income in the 2009
period. |
|
|
The reclassifications in the condensed consolidated statements of cash flows are as follows: |
|
|
|
We have separately disclosed cash flows from the issuance of long-term debt and
borrowings under our credit facilities for the three months ended March 31, 2009.
These amounts had been included within the same line item in the 2009 period. |
These reclassifications had no impact on net income or cash flows from operating, investing or
financing activities.
Recent Accounting Developments
Consolidation of Variable Interest Entities (VIEs). In June 2009, the Financial
Accounting Standards Board (FASB) amended consolidation guidance for VIEs. The objective of this
new guidance is to improve financial reporting by companies involved with VIEs. This guidance
requires each reporting company to perform an analysis to determine whether the companys variable
interest or interests give it a controlling financial interest in a VIE. The new guidance is
effective as of the beginning of each reporting companys first annual reporting period that begins
after November 15, 2009, for interim periods within that first annual reporting period, and for
interim and annual reporting periods thereafter. This guidance was effective for us on January 1,
2010. The adoption of this guidance did not have an impact on our consolidated financial
statements.
Fair Value Measurements. In January 2010, the FASB issued guidance that requires new
disclosures related to fair value measurements. The new guidance requires expanded disclosures
related to transfers between Level 1 and 2 activities and a gross presentation for Level 3
activity. The new accounting guidance is effective for fiscal years and interim periods beginning
after December 15, 2009, except for the new disclosures related to Level 3 activities, which are
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, 2010, except for the new disclosures
related to Level 3 activities, which will be effective for us on January 1, 2011. We have included
the enhanced disclosure requirements regarding fair value measurements in Note 13.
2. ACQUISITION AND DISPOSITION
Refined Petroleum Products Terminals and Pipeline Assets Acquisition
On November 18, 2009, we acquired from ConocoPhillips certain refined petroleum product
terminals and pipeline assets for approximately $47.1 million in cash. In addition, we acquired
certain inventory on hand upon completion of the transaction for additional consideration of $7.3
million. The assets include over 300 miles of active pipeline that provide connectivity between
the East St. Louis, Illinois and East Chicago, Indiana markets and three terminals providing 2.3
million barrels of storage tankage. ConocoPhillips entered into certain commercial contracts with
us concurrent with our acquisition regarding usage of the acquired facilities. We believe the
acquisition of these assets has given us greater access to markets and refinery operations in the
Midwest and increased the commercial value of these assets and certain of our existing assets to
our customers by offering enhanced distribution connectivity and flexible storage capabilities.
The operations of these acquired assets are
8
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
reported in the Pipeline Operations and Terminalling &
Storage segments. The purchase price has been allocated to the tangible and intangible assets
acquired, as follows:
|
|
|
|
|
Inventory |
|
$ |
7,287 |
|
Property, plant and equipment |
|
|
44,400 |
|
Intangible assets |
|
|
4,580 |
|
Environmental and other liabilities |
|
|
(1,834 |
) |
|
|
|
|
Allocated purchase price |
|
$ |
54,433 |
|
|
|
|
|
Sale of Buckeye NGL Pipeline
Effective January 1, 2010, we sold our ownership interest in an approximately 350-mile natural
gas liquids pipeline (the Buckeye NGL Pipeline) that runs from Wattenberg, Colorado to Bushton,
Kansas for $22.0 million. The assets had been classified as Assets held for sale in our
consolidated balance sheet at December 31, 2009 with a carrying amount equal to the proceeds
received. Revenues for Buckeye NGL Pipeline for the three months ended March 31, 2009 were $3.3
million.
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 April 2010, the Pipeline Hazardous Materials Safety Administration (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 plan on
contesting the proposed penalty. The timing or outcome of this appeal cannot reasonably be
determined at this time.
Environmental Contingencies
In accordance with our accounting policy, we recorded operating expenses, net of insurance
recoveries, of $2.8 million and $5.3 million during the three months ended March 31, 2010 and 2009,
respectively, related to environmental expenditures unrelated to claims and proceedings.
Ammonia Contract Contingencies
On November 30, 2005, Buckeye Gulf Coast Pipe Lines, L.P. (BGC) 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, BGC assumed the obligations of EPME
under several contracts involving monthly purchases and sales of ammonia. EPME and BGC 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, BGC 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 costs
exceeding ammonia sales proceeds. The amount of the shortfall generally increases as the
market price of ammonia increases.
9
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
EPME has informed BGC that, notwithstanding the parties agreement, it will not continue to
pay BGC for shortfalls created by the pass-through of ammonia costs in excess of ammonia revenues.
EPME encouraged BGC to seek payment by invoking a $40.0 million guaranty made by El Paso which
guaranteed EPMEs obligations to BGC. If EPME fails to reimburse BGC for these shortfalls for a
significant period during the remainder of the term of the ammonia agreements, 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 BGC could adversely affect our financial position, results of operations and cash
flows. To date, BGC has continued to receive payment for ammonia costs under the contracts at
issue. BGC has not called on El Pasos guaranty and believes only BGC 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 have been
working with EPME to terminate the ammonia sales contracts and ammonia supply contracts and, at no
cost to us, have terminated one of the ammonia sales contracts. Given, however, the uncertainty of
future ammonia prices and EPMEs future actions, we continue to believe we have risk of loss 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 and EPME are unable to terminate the remaining
contracts or otherwise mitigate the remaining risk, including potential recourse against EPME and
El Paso, with respect to this matter.
Customer Bankruptcy
One of our customers filed for bankruptcy in October 2009 and, since such filing, has not paid any amounts due to us pursuant a contract under which approximately $4.2 million remains payable. At this time, we are unable to estimate the impact of the bankruptcy on amounts payable to us.
4. INVENTORIES
Our inventory amounts were as follows at the dates indicated:
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
Refined petroleum products (1) |
|
$ |
235,696 |
|
|
$ |
299,473 |
|
Materials and supplies |
|
|
10,534 |
|
|
|
10,741 |
|
|
|
|
|
|
|
|
Total inventories |
|
$ |
246,230 |
|
|
$ |
310,214 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Ending inventory was 109.3 million and 141.7 million gallons of refined petroleum
products at March 31, 2010 and December 31, 2009, respectively. |
At March 31, 2010 and December 31, 2009, approximately 93% and 99%, respectively, of our
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.
10
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: |
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
Prepaid insurance |
|
$ |
4,718 |
|
|
$ |
6,916 |
|
Insurance receivables |
|
|
12,948 |
|
|
|
13,544 |
|
Ammonia receivable |
|
|
7,005 |
|
|
|
7,429 |
|
Margin deposits |
|
|
5,731 |
|
|
|
21,037 |
|
Prepaid services |
|
|
21,267 |
|
|
|
21,571 |
|
Unbilled revenue |
|
|
3,087 |
|
|
|
13,201 |
|
Tax receivable |
|
|
7,162 |
|
|
|
7,162 |
|
Prepaid taxes |
|
|
4,226 |
|
|
|
2,213 |
|
Other |
|
|
10,981 |
|
|
|
10,618 |
|
|
|
|
|
|
|
|
Total prepaid and other current assets |
|
$ |
77,125 |
|
|
$ |
103,691 |
|
|
|
|
|
|
|
|
6. 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 Pipeline
Operations segment, at the dates indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
Ownership |
|
|
2010 |
|
|
2009 |
|
Muskegon Pipeline LLC |
|
|
40.0 |
% |
|
$ |
15,617 |
|
|
$ |
15,273 |
|
Transport4, LLC |
|
|
25.0 |
% |
|
|
418 |
|
|
|
379 |
|
West Shore Pipe Line Company |
|
|
24.9 |
% |
|
|
31,526 |
|
|
|
30,320 |
|
West Texas LPG Pipeline Limited Partnership |
|
|
20.0 |
% |
|
|
51,942 |
|
|
|
50,879 |
|
|
|
|
|
|
|
|
|
|
|
|
Total equity investments |
|
|
|
|
|
$ |
99,503 |
|
|
$ |
96,851 |
|
|
|
|
|
|
|
|
|
|
|
|
The following table presents earnings from equity investments for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2010 |
|
|
2009 |
|
Muskegon Pipeline LLC |
|
$ |
344 |
|
|
$ |
365 |
|
Transport4, LLC |
|
|
39 |
|
|
|
29 |
|
West Shore Pipe Line Company |
|
|
1,207 |
|
|
|
1,103 |
|
West Texas LPG Pipeline Limited Partnership |
|
|
1,062 |
|
|
|
585 |
|
|
|
|
|
|
|
|
Total earnings from equity investments |
|
$ |
2,652 |
|
|
$ |
2,082 |
|
|
|
|
|
|
|
|
11
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
7. INTANGIBLE ASSETS
Intangible assets consist of the following at the dates indicated:
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
Customer relationships |
|
$ |
38,300 |
|
|
$ |
38,300 |
|
Accumulated amortization |
|
|
(6,373 |
) |
|
|
(5,631 |
) |
|
|
|
|
|
|
|
Net carrying amount |
|
|
31,927 |
|
|
|
32,669 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer contracts |
|
|
16,380 |
|
|
|
16,380 |
|
Accumulated amortization |
|
|
(4,263 |
) |
|
|
(3,892 |
) |
|
|
|
|
|
|
|
Net carrying amount |
|
|
12,117 |
|
|
|
12,488 |
|
|
|
|
|
|
|
|
Total intangible assets |
|
$ |
44,044 |
|
|
$ |
45,157 |
|
|
|
|
|
|
|
|
For the three months ended March 31, 2010 and 2009, amortization expense related to intangible
assets was $1.1 million and $0.9 million, respectively. Amortization expense related to intangible
assets is expected to be approximately $4.5 million for each of the next five years.
8. OTHER NON-CURRENT ASSETS
|
Other non-current assets consist of the following at the dates indicated: |
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
Deferred charge, net (1) |
|
$ |
4,849 |
|
|
$ |
6,024 |
|
Prepaid services |
|
|
8,799 |
|
|
|
11,640 |
|
Long-term derivative assets |
|
|
15,900 |
|
|
|
17,204 |
|
Debt issuance costs |
|
|
10,123 |
|
|
|
11,058 |
|
Insurance receivables |
|
|
7,057 |
|
|
|
7,265 |
|
Other |
|
|
9,605 |
|
|
|
9,586 |
|
|
|
|
|
|
|
|
Total other non-current assets |
|
$ |
56,333 |
|
|
$ |
62,777 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Net of accumulated amortization of $59.4 million and $58.2 million at March 31, 2010
and December 31, 2009, respectively. The market value of the LP Units issued in August
1997 in connection with the restructuring of Services Companys ESOP was $64.2 million.
This fair value was recorded as a deferred charge and is being amortized on a straight-line
basis over 13.5 years. |
12
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
9. ACCRUED AND OTHER CURRENT LIABILITIES
Accrued and other current liabilities consist of the following at the dates indicated:
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
Taxes other than income |
|
$ |
18,794 |
|
|
$ |
15,381 |
|
Accrued charges due Buckeye GP |
|
|
937 |
|
|
|
1,218 |
|
Accrued charges due Services Company |
|
|
420 |
|
|
|
6,104 |
|
Accrued employee benefit liability |
|
|
3,287 |
|
|
|
3,287 |
|
Environmental liabilities |
|
|
10,746 |
|
|
|
10,799 |
|
Accrued interest |
|
|
18,568 |
|
|
|
30,609 |
|
Payable for ammonia purchase |
|
|
7,056 |
|
|
|
7,015 |
|
Deferred revenue |
|
|
18,501 |
|
|
|
6,829 |
|
Accrued capital expenditures |
|
|
256 |
|
|
|
1,611 |
|
Reorganization |
|
|
854 |
|
|
|
2,133 |
|
Deferred consideration |
|
|
2,010 |
|
|
|
1,675 |
|
Other |
|
|
24,175 |
|
|
|
20,082 |
|
|
|
|
|
|
|
|
Total accrued and other current liabilities |
|
$ |
105,604 |
|
|
$ |
106,743 |
|
|
|
|
|
|
|
|
10. DEBT OBLIGATIONS
|
Long-term debt consists of the following at the dates indicated: |
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
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 |
|
6.750% Notes due August 15, 2033 (1) |
|
|
150,000 |
|
|
|
150,000 |
|
Credit Facility |
|
|
20,000 |
|
|
|
78,000 |
|
BES Credit Agreement |
|
|
183,500 |
|
|
|
239,800 |
|
|
|
|
|
|
|
|
Total debt |
|
|
1,628,500 |
|
|
|
1,742,800 |
|
Less: Unamortized discount |
|
|
(4,689 |
) |
|
|
(4,854 |
) |
Adjustment associated with fair value hedges |
|
|
765 |
|
|
|
824 |
|
|
|
|
|
|
|
|
Subtotal debt |
|
|
1,624,576 |
|
|
|
1,738,770 |
|
Less: Current portion of long-term debt |
|
|
(183,500 |
) |
|
|
(239,800 |
) |
|
|
|
|
|
|
|
Total long-term debt |
|
$ |
1,441,076 |
|
|
$ |
1,498,970 |
|
|
|
|
|
|
|
|
|
|
|
(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. |
The fair values of our aggregate debt and credit facilities were estimated to be $1,677.4
million and $1,762.1 million at March 31, 2010 and December 31, 2009, 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
13
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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.
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, 2010 and December 31, 2009, $20.0 million and $78.0 million, respectively, were outstanding
under the Credit Facility. The weighted average interest rate for borrowings outstanding under the
Credit Facility was 0.6% at March 31, 2010.
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 future acquisitions. The Funded Debt Ratio is calculated by dividing
consolidated debt by annualized EBITDA, which is defined in the Credit Facility as earnings before
interest, taxes, depreciation, depletion and amortization, 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, 2010, our Funded Debt
Ratio was approximately 4.29 to 1.00. As permitted by the Credit Facility, the $183.5 million of
borrowings by Buckeye Energy Services LLC (BES) under its separate credit agreement (discussed
below) were 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, 2010, we were not aware of any instances of noncompliance with the covenants
under our Credit Facility.
At March 31, 2010 and December 31, 2009, we had committed $1.4 million 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
$250.0 million. The BES Credit Agreements maturity date is May 20, 2011. 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 1.75%,
(ii) the Eurodollar Rate (as defined in the BES Credit Agreement) plus 1.75% or (iii) the Base Rate
(as defined in the BES Credit Agreement) plus 0.25%. 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.
14
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The balances outstanding under the BES Credit Agreement were approximately $183.5 million
and $239.8 million at March 31, 2010 and December 31, 2009, respectively, both of which were
classified as current liabilities in our condensed consolidated balance sheets. 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 |
At March 31, 2010, BESs Consolidated Tangible Net Worth and Consolidated Net Working Capital
were $122.3 million and $75.0 million, respectively, and the Consolidated Leverage Ratio was 2.1 to
1.0. The weighted average interest rate for borrowings outstanding under the BES Credit Agreement
was 2.0% at March 31, 2010.
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, 2010, we
were not aware of any instances of noncompliance with the covenants under the BES Credit Agreement.
11. OTHER NON-CURRENT LIABILITIES
Other non-current liabilities consist of the following at the dates indicated:
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
Accrued employee benefit liabilities (see Note 14) |
|
$ |
44,772 |
|
|
$ |
45,837 |
|
Accrued environmental liabilities |
|
|
18,687 |
|
|
|
19,053 |
|
Deferred consideration |
|
|
17,923 |
|
|
|
18,425 |
|
Deferred rent |
|
|
10,217 |
|
|
|
9,158 |
|
Deferred revenue |
|
|
6,762 |
|
|
|
1,532 |
|
Other |
|
|
7,439 |
|
|
|
8,846 |
|
|
|
|
|
|
|
|
Total other non-current liabilities |
|
$ |
105,800 |
|
|
$ |
102,851 |
|
|
|
|
|
|
|
|
15
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
12. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
The following table presents the components of accumulated other comprehensive income (loss)
on the condensed consolidated balance sheets at the dates indicated:
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
Adjustments to funded status of retirement income guarantee
plan and retiree medical plan |
|
$ |
(4,453 |
) |
|
$ |
(4,453 |
) |
Amortization of interest rate swap |
|
|
(7,513 |
) |
|
|
(7,753 |
) |
Derivative instruments |
|
|
15,573 |
|
|
|
17,501 |
|
Accumulated amortization of retirement income guarantee
plan and retiree medical plan |
|
|
(6,120 |
) |
|
|
(6,142 |
) |
|
|
|
|
|
|
|
Total accumulated other comprehensive loss |
|
$ |
(2,513 |
) |
|
$ |
(847 |
) |
|
|
|
|
|
|
|
13. 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 and do not engage in hedging activity with respect to trading 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, 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 an existing debt obligation.
16
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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. During
2009, we entered into four forward-starting interest rate swaps with a total aggregate notional
amount of $200.0 million related to the anticipated issuance of debt on or before July 15, 2013 and
three forward-starting interest rate swaps with a total aggregate notional amount of $150.0 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, 2010, unrealized losses of $1.3 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.
Over the next twelve months, we expect to reclassify $1.0 million of accumulated other
comprehensive loss as an increase to interest expense that was generated by terminated
forward-starting interest rate swaps in 2008 associated with our 6.050% Notes.
Commodity Derivatives
Our Energy Services segment primarily uses exchange-traded refined petroleum product futures
contracts to manage the risk of market price volatility on its refined petroleum product
inventories and its fixed-price 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. Presentations 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
sales contracts. Therefore, our fixed-price sales contracts and the related futures contracts used
to offset those fixed-price sales contracts are all marked-to-market on the 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 Pipeline Operations segment bought natural gas futures contracts in March
2009 with terms that coincide with the remaining term of an ongoing natural gas supply contract
(January 2010 through July 2011). We designated the futures contract as a cash flow hedge at
inception.
17
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes our commodity derivative instruments outstanding at March 31,
2010 (amounts in thousands of gallons, except as noted):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (1) |
|
|
Accounting |
|
Derivative Purpose |
|
Current |
|
|
Long-Term (2) |
|
|
Treatment |
|
Derivatives NOT designated as hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
Fixed-price sales contracts |
|
|
18,417 |
|
|
|
210 |
|
|
Mark-to-market |
Futures contracts for fixed-price sales contracts |
|
|
11,844 |
|
|
|
210 |
|
|
Mark-to-market |
Futures contracts for inventory |
|
|
5,586 |
|
|
|
|
|
|
Mark-to-market |
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives designated as hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
Futures contracts for inventory |
|
|
90,426 |
|
|
|
|
|
|
Fair Value Hedge |
Futures contracts for natural gas (BBtu) (3) |
|
|
360 |
|
|
|
120 |
|
|
Cash Flow Hedge |
|
|
|
(1) |
|
Volume represents net notional position. |
|
(2) |
|
The maximum term for derivatives included in the long-term column is August 2011. |
|
(3) |
|
BBtu represents one billion British thermal units. |
The following table sets forth the fair value of each classification of derivative instruments
at the dates indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2010 |
|
|
December 31, 2009 |
|
|
|
|
|
|
|
|
|
|
|
Derivative |
|
|
|
|
|
|
|
|
|
|
Derivative |
|
|
|
Assets |
|
|
(Liabilities) |
|
|
Net Carrying |
|
|
Assets |
|
|
(Liabilities) |
|
|
Net Carrying |
|
|
|
Fair value |
|
|
Fair value |
|
|
Value |
|
|
Fair value |
|
|
Fair value |
|
|
Value |
|
Derivatives NOT designated as hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed-price sales contracts |
|
$ |
1,906 |
|
|
$ |
(1,217 |
) |
|
$ |
689 |
|
|
$ |
4,959 |
|
|
$ |
(3,662 |
) |
|
$ |
1,297 |
|
Futures contracts for fixed-price
sales contracts |
|
|
4,817 |
|
|
|
(13 |
) |
|
|
4,804 |
|
|
|
7,594 |
|
|
|
(384 |
) |
|
|
7,210 |
|
Futures contracts for inventory |
|
|
1,749 |
|
|
|
(1,443 |
) |
|
|
306 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives designated as hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Futures contracts for inventory |
|
|
1,277 |
|
|
|
(7,616 |
) |
|
|
(6,339 |
) |
|
|
1,992 |
|
|
|
(20,517 |
) |
|
|
(18,525 |
) |
Futures contracts for natural gas |
|
|
|
|
|
|
(327 |
) |
|
|
(327 |
) |
|
|
312 |
|
|
|
|
|
|
|
312 |
|
Interest rate contracts |
|
|
15,900 |
|
|
|
|
|
|
|
15,900 |
|
|
|
17,204 |
|
|
|
|
|
|
|
17,204 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
|
|
|
|
|
|
$ |
15,033 |
|
|
|
|
|
|
|
|
|
|
$ |
7,498 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
Balance Sheet Locations: |
|
2010 |
|
|
2009 |
|
Derivative assets |
|
$ |
1,964 |
|
|
$ |
4,959 |
|
Other non-current assets |
|
|
15,900 |
|
|
|
17,204 |
|
Derivative liabilities |
|
|
(2,831 |
) |
|
|
(14,665 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
15,033 |
|
|
$ |
7,498 |
|
|
|
|
|
|
|
|
Substantially all of the unrealized net loss of $6.0 million at March 31, 2010 for
inventory hedges represented by futures contracts will be realized by the second quarter of 2010 as
the related inventory is sold. Gains recorded on inventory hedges that were ineffective were
approximately $4.8 million and $4.3 million for the three months ended March 31, 2010 and 2009,
respectively. At March 31, 2010, open refined petroleum product derivative contracts (represented
by the fixed-price sales contracts and futures contracts for fixed-price sales contracts noted
18
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
above) varied in duration, but did not extend beyond May 2011. In addition, at March 31, 2010, we
had refined petroleum product inventories which we intend to use to satisfy a portion of the
fixed-price sales contracts.
The gains and losses on our derivative instruments recognized in income on our derivatives
were as follows for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (Loss) Recognized in |
|
|
|
|
|
Income on Derivatives |
|
|
|
|
|
Three Months Ended |
|
|
|
|
|
March 31, |
|
|
|
Location |
|
2010 |
|
|
2009 |
|
Derivatives NOT designated
as hedging instruments: |
|
|
|
|
|
|
|
|
|
|
Fixed-price sales contracts |
|
Product sales |
|
$ |
2,410 |
|
|
$ |
13,295 |
|
Futures contracts for fixed-price sales contracts |
|
Cost of product sales and natural gas storage services |
|
|
(494 |
) |
|
|
(7,546 |
) |
Futures contracts for inventory
|
|
Cost of product sales and natural gas storage services |
|
|
246 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives designated as
fair value hedging instruments: |
|
|
|
|
|
|
|
|
|
|
Futures contracts for inventory |
|
Cost of product sales and natural gas storage services |
|
$ |
(4,910 |
) |
|
$ |
27,648 |
|
The gains and losses reclassified from accumulated other comprehensive income (AOCI) to
income and the change in value recognized in other comprehensive income (OCI) on our derivatives
were as follows for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (Loss) Reclassified from |
|
|
|
|
|
AOCI to Income |
|
|
|
|
|
Three Months Ended |
|
|
|
|
|
March 31, |
|
|
|
Location |
|
2010 |
|
|
2009 |
|
Derivatives designated as cash
flow hedging instruments: |
|
|
|
|
|
|
|
|
|
|
Futures contracts for natural gas |
|
Cost of product sales and natural gas storage services |
|
$ |
(72 |
) |
|
$ |
(53 |
) |
Interest rate contracts |
|
Interest and debt expense |
|
|
(240 |
) |
|
|
(602 |
) |
|
|
|
|
|
|
|
|
|
|
|
Change in Value Recognized |
|
|
|
in OCI on Derivatives |
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2010 |
|
|
2009 |
|
Derivatives designated as cash flow hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Futures contracts for natural gas |
|
$ |
(696 |
) |
|
$ |
116 |
|
Futures contracts for refined petroleum products |
|
|
|
|
|
|
(233 |
) |
Interest rate contracts |
|
|
(1,304 |
) |
|
|
(108 |
) |
19
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Fair Value Measurements
Fair value is defined as the price that would be received to sell an asset or paid to transfer
a liability in an orderly transaction between market participants at a specified measurement
date. Our fair value estimates are based on either (i) actual market data or (ii) assumptions that
other market participants would use in pricing an asset or liability, including estimates of risk.
Recognized valuation techniques employ inputs such as product prices, operating costs, discount
factors and business growth rates. These inputs may be either readily observable, corroborated by
market data or generally unobservable. In developing our estimates of fair value, we endeavor to
utilize the best information available and apply market-based data to the extent
possible. Accordingly, we utilize valuation techniques (such as the income or market approach)
that maximize the use of observable inputs and minimize the use of unobservable inputs.
A three-tier hierarchy has been established that classifies fair value amounts recognized or
disclosed in the financial statements based on the observability of inputs used to estimate such
fair values. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and
2) to be more reliable and predictable than those based primarily on unobservable inputs (Level
3). At each balance sheet reporting date, we categorize our financial assets and liabilities using
this hierarchy. The characteristics of fair value amounts classified within each level of the
hierarchy are described as follows.
|
|
|
Level 1 inputs are based on quoted prices, which are available in active markets for
identical assets or liabilities as of the reporting date. Active markets are defined
as those in which transactions for identical assets or liabilities occur with
sufficient frequency and volume to provide pricing information on an ongoing basis. |
|
|
|
|
Level 2 inputs are based on pricing inputs other than quoted prices in active
markets and are either directly or indirectly observable as of the measurement date.
Level 2 fair values include instruments that are valued using financial models or other
appropriate valuation methodologies and include the following: |
|
|
|
Quoted prices in active markets for similar assets or liabilities. |
|
|
|
|
Quoted prices in markets that are not active for identical or similar assets or
liabilities. |
|
|
|
|
Inputs other than quoted prices that are observable for the asset or liability. |
|
|
|
|
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. |
20
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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, 2010 and December 31, 2009, and the basis
for that measurement, by level within the fair value hierarchy:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2010 |
|
|
December 31, 2009 |
|
|
|
|
|
|
|
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: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed-price sales contracts |
|
$ |
|
|
|
$ |
1,906 |
|
|
$ |
|
|
|
$ |
4,959 |
|
Futures contracts for inventory
and fixed-price sales contracts |
|
|
58 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset held in trust |
|
|
|
|
|
|
|
|
|
|
1,793 |
|
|
|
|
|
Interest rate derivatives |
|
|
|
|
|
|
15,900 |
|
|
|
|
|
|
|
17,204 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed-price sales contracts |
|
|
|
|
|
|
(1,217 |
) |
|
|
|
|
|
|
(3,662 |
) |
Futures contracts for inventory
and fixed-price sales contracts |
|
|
(1,614 |
) |
|
|
|
|
|
|
(11,003 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
(1,556 |
) |
|
$ |
16,589 |
|
|
$ |
(9,210 |
) |
|
$ |
18,501 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The value of the Level 1 derivative assets and liabilities were based on quoted market prices
obtained from the NYMEX. The value of the Level 1 asset held in trust was obtained from quoted
market prices. The value of the Level 2 derivative assets and liabilities were based on observable
market data related to the obligations to provide petroleum products. The value of the Level 2
interest rate derivative was based on observable market data related to similar obligations.
The Level 2 derivative assets of $1.9 million and $5.0 million as of March 31, 2010 and
December 31, 2009, respectively, are each net of a credit valuation adjustment (CVA) of ($0.9)
million. Because few of the Energy Services segments customers entering into these fixed-price
sales contracts are large organizations with nationally-recognized credit ratings, the Energy
Services segment determined that a CVA, which is based on the credit risk of such contracts, is
appropriate. The CVA is 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.
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,
2010 and 2009.
21
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
14. 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 periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RIGP |
|
|
Retiree Medical Plan |
|
|
|
Three Months Ended |
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
March 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
Service cost |
|
$ |
68 |
|
|
$ |
208 |
|
|
$ |
30 |
|
|
$ |
105 |
|
Interest cost |
|
|
232 |
|
|
|
371 |
|
|
|
205 |
|
|
|
492 |
|
Expected return on plan assets |
|
|
(88 |
) |
|
|
(191 |
) |
|
|
|
|
|
|
|
|
Amortization of prior service benefit |
|
|
(12 |
) |
|
|
(117 |
) |
|
|
(307 |
) |
|
|
(860 |
) |
Amortization of unrecognized losses |
|
|
248 |
|
|
|
357 |
|
|
|
93 |
|
|
|
261 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit costs |
|
$ |
448 |
|
|
$ |
628 |
|
|
$ |
21 |
|
|
$ |
(2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
During the three months ended March 31, 2010, we contributed $1.5 million to the RIGP.
15. UNIT-BASED COMPENSATION PLANS
We award unit-based compensation to employees and directors primarily under the 2009 Long-Term
Incentive Plan of Buckeye Partners, L.P. (the Buckeye LTIP), which became effective in March
2009. We formerly awarded options to acquire LP Units to employees pursuant to the Unit Option and
Distribution Equivalent Plan (the Option Plan). We recognized total unit-based compensation
expense of $0.9 million and $0.1 million for the three months ended March 31, 2010 and 2009,
respectively.
Long-Term Incentive Plan
The Buckeye 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, 2010, a total of 1,114,277 additional LP Units could be issued under
the Buckeye LTIP.
On December 16, 2009, the Compensation Committee approved the terms of the Buckeye Partners,
L.P. Unit Deferral and Incentive Plan (Deferral Plan). The Compensation Committee is expressly
authorized to adopt the Deferral Plan under the terms of the Buckeye LTIP, which grants the
Compensation Committee the authority to establish a program pursuant to which our phantom units may
be awarded in lieu of cash compensation at the election of the employee. At December 31, 2009,
eligible employees were allowed to defer up to 50% of their 2009 compensation award under our
Annual Incentive Compensation Plan or other discretionary bonus program in
22
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 $1.8 million of 2009 compensation awards had been deferred at December 31, 2009, for
which 62,332 phantom units (including matching units) were granted during the three months ended
March 31, 2010. These grants are included as granted in the Buckeye LTIP activity table below.
Awards under the Buckeye LTIP
During the three months ended March 31, 2010, the Compensation Committee granted 119,691
phantom units to employees (including the 62,332 phantom units granted pursuant to the Deferral
Plan discussed above), 12,000 phantom units to independent directors of Buckeye GP and MainLine
Management LLC, and 114,725 performance units to employees. The amount paid with respect to phantom
unit distributions under the Buckeye LTIP was $0.2 million for the three months ended March 31,
2010.
The following table sets forth the Buckeye LTIP activity for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
|
|
|
|
Grant Date |
|
|
|
|
|
|
Number of |
|
|
Fair Value |
|
|
|
|
|
|
LP Units |
|
|
per LP Unit (1) |
|
|
Total Value |
|
Unvested at January 1, 2010 |
|
|
140,095 |
|
|
$ |
39.81 |
|
|
$ |
5,577 |
|
Granted |
|
|
246,416 |
|
|
|
56.42 |
|
|
|
13,903 |
|
Forfeited |
|
|
(1,307 |
) |
|
|
39.06 |
|
|
|
(51 |
) |
|
|
|
|
|
|
|
|
|
|
|
Unvested at March 31, 2010 |
|
|
385,204 |
|
|
$ |
50.44 |
|
|
$ |
19,429 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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, 2010, approximately $14.5 million of compensation expense related to the Buckeye
LTIP is expected to be recognized over a weighted average period of approximately 2.3 years.
23
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Unit Option and Distribution Equivalent Plan
The following is a summary of the changes in the LP Unit options outstanding (all of which are
vested or are expected to vest) under the Option Plan for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted- |
|
|
|
|
|
|
|
|
|
|
Weighted- |
|
|
Average |
|
|
|
|
|
|
|
|
|
|
Average |
|
|
Remaining |
|
|
Aggregate |
|
|
|
Number of |
|
|
Strike Price |
|
|
Contractual |
|
|
Intrinsic |
|
|
|
LP Units |
|
|
($/LP Unit) |
|
|
Term (in years) |
|
|
Value (1) |
|
Outstanding at January 1, 2010 |
|
|
349,400 |
|
|
$ |
46.25 |
|
|
|
|
|
|
|
|
|
Exercised |
|
|
(54,300 |
) |
|
|
43.74 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at March 31, 2010 |
|
|
295,100 |
|
|
|
46.66 |
|
|
|
6.3 |
|
|
$ |
3,956 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at March 31, 2010 |
|
|
189,900 |
|
|
$ |
45.59 |
|
|
|
5.4 |
|
|
$ |
2,750 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 2010 and the exercise price, multiplied by the number of
exercisable, in-the-money options. |
The total intrinsic value of options exercised during the three months ended March 31, 2010
was $0.8 million. There were no option exercises during the three months ended March 31, 2009. At
March 31, 2010, total unrecognized compensation cost related to unvested LP Unit options was $0.1
million. We expect to recognize this cost over a weighted average period of 0.9 years. At March
31, 2010, 333,000 LP Units were available for grant in connection with the Option Plan. However,
with the adoption of the Buckeye LTIP, we do not expect to make any future grants pursuant to the
Option Plan. The fair value of options vested was $0.4 million and $0.3 million during the three
months ended March 31, 2010 and 2009, respectively.
16. RELATED PARTY TRANSACTIONS
We are managed by Buckeye GP, which is a wholly owned subsidiary of BGH. BGH is managed by
its general partner, MainLine Management LLC (MainLine Management). MainLine Management is a
wholly owned subsidiary of BGH GP Holdings, LLC (BGH GP). Affiliates of each of ArcLight Capital
Partners, LLC (ArcLight) and Kelso & Company, along with certain members of our senior
management, own the majority of the outstanding equity interests of BGH GP. In addition to owning
MainLine Management, BGH GP owns approximately 62% of BGHs common units.
Under certain agreements, we are obligated to reimburse Services Company for certain direct
and indirect costs related to the business activities of us and our subsidiaries. Services Company
is reimbursed for insurance-related expenses, general and administrative costs, compensation and
benefits payable to employees of Services Company, tax information and reporting costs, legal and
audit fees and an allocable portion of overhead expenses. BGH previously reimbursed Services
Company for the executive compensation costs and related benefits paid to Buckeye GPs four highest
salaried employees. Since January 1, 2009, we are paying for all executive compensation and
related benefits earned by Buckeye GPs four highest salaried officers in exchange for an annual
fixed payment from BGH of $3.6 million. Total costs incurred by us for the above services totaled
$27.5 million and $28.6 million for the three months ended March 31, 2010 and 2009, respectively.
We reimbursed Services Company for these costs.
Services Company, which is beneficially owned by the ESOP, owned 1.6 million of our LP Units
(approximately 3.0% of our LP Units outstanding) as of March 31, 2010. 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 $1.5 million and $1.9 million for the three months ended March 31,
2010 and 2009, respectively.
24
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
We incurred a senior administrative charge for certain management services performed by
affiliates of Buckeye GP of $0.5 million for the three months ended March 31, 2009. The senior
administrative charge was waived indefinitely on April 1, 2009 as these affiliates are currently
not providing services to us that were contemplated as being covered by the senior administrative
charge. As a result, there were no related charges recorded in the last nine months of 2009 or
during the three months ended March 31, 2010.
Buckeye GP receives incentive distributions from us pursuant to our partnership agreement and
incentive compensation agreement. Incentive distributions are based on the level of quarterly cash
distributions paid per LP Unit. Incentive distribution payments totaled $12.3 million and $10.5
million during the three months ended March 31, 2010 and 2009, respectively.
17. PARTNERS CAPITAL AND DISTRIBUTIONS
Summary of Changes in Outstanding General Partner Units and LP Units
The following is a reconciliation of General Partner Units and LP Units outstanding for the
periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General |
|
|
Limited |
|
|
|
|
|
|
Partner |
|
|
Partners |
|
|
Total |
|
Units outstanding at December 31, 2009 |
|
|
243,914 |
|
|
|
51,438,265 |
|
|
|
51,682,179 |
|
LP Units issued pursuant to the Option Plan |
|
|
|
|
|
|
54,300 |
|
|
|
54,300 |
|
|
|
|
|
|
|
|
|
|
|
Units outstanding at March 31, 2010 |
|
|
243,914 |
|
|
|
51,492,565 |
|
|
|
51,736,479 |
|
|
|
|
|
|
|
|
|
|
|
Cash Distributions
We 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
totaled $61.0 million and $53.7 million during the three months ended March 31, 2010 and 2009,
respectively.
On May 7, 2010, we announced a quarterly distribution of $0.95 per LP Unit that will be paid
on May 28, 2010, to unitholders of record on May 17, 2010. Total cash distributed to unitholders
on May 28, 2010 will total approximately $61.7 million.
18. EARNINGS PER LIMITED PARTNER UNIT
We use the two-class method for the computation of earnings per LP Unit. The two-class method
requires the determination of net income allocated to limited partner interests as shown in the
table below. Basic earnings per LP Unit is computed by dividing net income or loss allocated to
limited partner interests per the two-class method by the weighted-average number of LP Units
outstanding during a period. Diluted earnings per LP Unit is computed by dividing net income or
loss allocated to limited partner interests per the two-class method by the weighted-average number
of LP Units outstanding during a period, plus the dilutive effect of outstanding unit options and
Buckeye LTIP awards calculated using the treasury stock method. Outstanding unit options and
Buckeye LTIP awards are excluded from the calculation of diluted earnings per LP Unit in periods we
experience a net loss because the effect is antidilutive.
25
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table presents the computation of basic and diluted earnings per LP Unit for the
periods indicated:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2010 |
|
|
2009 |
|
Net income allocation: |
|
|
|
|
|
|
|
|
Net income attributable to Buckeye Partners, L.P. |
|
$ |
50,513 |
|
|
$ |
53,760 |
|
Less: General partners allocation of incentive distributions |
|
|
(12,315 |
) |
|
|
(11,466 |
) |
|
|
|
|
|
|
|
Net income available to limited partners and general partner
after incentive distributions |
|
|
38,198 |
|
|
|
42,294 |
|
General partners ownership interest |
|
|
0.472 |
% |
|
|
0.474 |
% |
|
|
|
|
|
|
|
Income allocation to general partner based upon ownership
interest |
|
$ |
180 |
|
|
$ |
200 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partners incentive distributions |
|
$ |
12,315 |
|
|
$ |
11,466 |
|
Income allocation to general partner |
|
|
180 |
|
|
|
200 |
|
|
|
|
|
|
|
|
Total income allocated to general partner |
|
|
12,495 |
|
|
|
11,666 |
|
Adjustment for application of two-class method for MLPs (1) |
|
|
281 |
|
|
|
|
|
|
|
|
|
|
|
|
Net income allocated to general partner in accordance with two-class method |
|
$ |
12,776 |
|
|
$ |
11,666 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
We allocate net income to our general partner based on the distribution paid during the
current quarter (including the incentive distribution interest in excess of the general
partners ownership interest). Guidance issued by the FASB requires that the distribution
pertaining to the current period net income, which is to be paid in the subsequent quarter,
be utilized in the earnings per LP Unit calculation. We reflect the impact of this
difference as the Adjustment for application of two-class method for MLPs. |
26
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table presents the computation of basic and diluted earnings per LP Unit for the
periods indicated:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2010 |
|
|
2009 |
|
Earnings per LP Unit Calculation: |
|
|
|
|
|
|
|
|
Numerator: |
|
|
|
|
|
|
|
|
Net income attributable to Buckeye Partners, L.P. |
|
$ |
50,513 |
|
|
$ |
53,760 |
|
Less: Net income allocated to general partner in accordance with two-class method |
|
|
(12,776 |
) |
|
|
(11,666 |
) |
|
|
|
|
|
|
|
Net income available to limited partners in accordance with two-class method |
|
$ |
37,737 |
|
|
$ |
42,094 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator: |
|
|
|
|
|
|
|
|
Basic: |
|
|
|
|
|
|
|
|
Weighted average LP Units oustanding |
|
|
51,471 |
|
|
|
48,401 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted: |
|
|
|
|
|
|
|
|
Weighted average LP Units oustanding |
|
|
51,471 |
|
|
|
48,401 |
|
Dilutive effect of LP Unit options and Buckeye LTIP awards
granted |
|
|
163 |
|
|
|
5 |
|
|
|
|
|
|
|
|
Total |
|
|
51,634 |
|
|
|
48,406 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per LP Unit: |
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.73 |
|
|
$ |
0.87 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
$ |
0.73 |
|
|
$ |
0.87 |
|
|
|
|
|
|
|
|
19. BUSINESS SEGMENTS
We operate and report in five business segments: Pipeline Operations; Terminalling & Storage;
Natural Gas Storage; Energy Services; and Development & Logistics.
Adjusted EBITDA
In the first quarter of 2010, we revised our internal management reports provided to senior
management, including the Chief Executive Officer, to redefine adjusted earnings before interest,
taxes and depreciation and amortization (Adjusted EBITDA) to now exclude non-cash unit-based
compensation expense. We believe this revised measure provides an improved means by which to gauge
our performance and increases comparability to similar measures used by other companies.
Adjusted EBITDA is the primary measure used by senior management to evaluate our operating
results and to allocate our resources. We define Adjusted EBITDA 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, and (ii) non-cash unit-based compensation
expense. EBITDA and Adjusted EBITDA are non-GAAP measures of performance and are reconciled to the
most comparable GAAP measure, net income attributable to unitholders.
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.
27
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Financial information about each segment, EBITDA and Adjusted EBITDA are presented below for
the periods or at the dates indicated:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2010 |
|
|
2009 |
|
Revenue: |
|
|
|
|
|
|
|
|
Pipeline Operations |
|
$ |
96,537 |
|
|
$ |
99,195 |
|
Terminalling & Storage |
|
|
42,371 |
|
|
|
30,643 |
|
Natural Gas Storage |
|
|
25,406 |
|
|
|
15,077 |
|
Energy Services |
|
|
568,202 |
|
|
|
268,480 |
|
Development & Logistics |
|
|
7,515 |
|
|
|
9,125 |
|
Intersegment |
|
|
(8,857 |
) |
|
|
(5,680 |
) |
|
|
|
|
|
|
|
Total revenue |
|
$ |
731,174 |
|
|
$ |
416,840 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss): |
|
|
|
|
|
|
|
|
Pipeline Operations |
|
$ |
45,972 |
|
|
$ |
44,916 |
|
Terminalling & Storage |
|
|
23,466 |
|
|
|
10,993 |
|
Natural Gas Storage |
|
|
3,555 |
|
|
|
6,238 |
|
Energy Services |
|
|
(3,076 |
) |
|
|
6,412 |
|
Development & Logistics |
|
|
1,103 |
|
|
|
1,544 |
|
|
|
|
|
|
|
|
Total operating income |
|
$ |
71,020 |
|
|
$ |
70,103 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization: |
|
|
|
|
|
|
|
|
Pipeline Operations |
|
$ |
9,641 |
|
|
$ |
9,577 |
|
Terminalling & Storage |
|
|
2,494 |
|
|
|
1,866 |
|
Natural Gas Storage |
|
|
1,767 |
|
|
|
1,581 |
|
Energy Services |
|
|
1,287 |
|
|
|
1,059 |
|
Development & Logistics |
|
|
455 |
|
|
|
397 |
|
|
|
|
|
|
|
|
Total depreciation and amortization |
|
$ |
15,644 |
|
|
$ |
14,480 |
|
|
|
|
|
|
|
|
28
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2010 |
|
|
2009 |
|
Adjusted EBITDA: |
|
|
|
|
|
|
|
|
Pipeline Operations |
|
$ |
57,817 |
|
|
$ |
55,868 |
|
Terminalling & Storage |
|
|
26,201 |
|
|
|
12,841 |
|
Natural Gas Storage |
|
|
6,469 |
|
|
|
8,963 |
|
Energy Services |
|
|
(1,541 |
) |
|
|
7,485 |
|
Development & Logistics |
|
|
1,136 |
|
|
|
1,537 |
|
|
|
|
|
|
|
|
Total Adjusted EBITDA |
|
$ |
90,082 |
|
|
$ |
86,694 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GAAP Reconciliation: |
|
|
|
|
|
|
|
|
Net income |
|
$ |
52,278 |
|
|
$ |
55,120 |
|
Less: net income attributable to noncontrolling interests |
|
|
(1,765 |
) |
|
|
(1,360 |
) |
|
|
|
|
|
|
|
Net income attributable to Buckeye Partners, L.P.
unitholders |
|
|
50,513 |
|
|
|
53,760 |
|
Interest and debt expense |
|
|
21,549 |
|
|
|
17,176 |
|
Income tax (benefit) expense |
|
|
(18 |
) |
|
|
65 |
|
Depreciation and amortization |
|
|
15,644 |
|
|
|
14,480 |
|
|
|
|
|
|
|
|
EBITDA |
|
|
87,688 |
|
|
|
85,481 |
|
Non-cash deferred lease expense |
|
|
1,059 |
|
|
|
1,125 |
|
Non-cash unit-based compensation expense |
|
|
1,335 |
|
|
|
88 |
|
|
|
|
|
|
|
|
Adjusted EBITDA |
|
$ |
90,082 |
|
|
$ |
86,694 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2010 |
|
|
2009 |
|
Capital additions: (1) |
|
|
|
|
|
|
|
|
Pipeline Operations |
|
$ |
4,833 |
|
|
$ |
6,634 |
|
Terminalling & Storage |
|
|
2,581 |
|
|
|
5,641 |
|
Natural Gas Storage |
|
|
1,399 |
|
|
|
6,375 |
|
Energy Services |
|
|
618 |
|
|
|
730 |
|
Development & Logistics |
|
|
177 |
|
|
|
74 |
|
|
|
|
|
|
|
|
Total capital additions |
|
$ |
9,608 |
|
|
$ |
19,454 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Amount includes ($1.4) million and ($1.5) million of non-cash changes in accruals for
capital expenditures for the three months ended March 31, 2010 and 2009, respectively. |
29
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
Total Assets: |
|
|
|
|
|
|
|
|
Pipeline Operations (1) |
|
$ |
1,553,321 |
|
|
$ |
1,592,916 |
|
Terminalling & Storage |
|
|
531,917 |
|
|
|
532,971 |
|
Natural Gas Storage |
|
|
547,484 |
|
|
|
573,261 |
|
Energy Services |
|
|
417,213 |
|
|
|
482,025 |
|
Development & Logistics |
|
|
71,039 |
|
|
|
74,476 |
|
|
|
|
|
|
|
|
Total assets |
|
$ |
3,120,974 |
|
|
$ |
3,255,649 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Goodwill: |
|
|
|
|
|
|
|
|
Pipeline Operations |
|
$ |
|
|
|
$ |
|
|
Terminalling & Storage |
|
|
38,184 |
|
|
|
38,184 |
|
Natural Gas Storage |
|
|
169,560 |
|
|
|
169,560 |
|
Energy Services |
|
|
1,132 |
|
|
|
1,132 |
|
Development & Logistics |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total goodwill |
|
$ |
208,876 |
|
|
$ |
208,876 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All equity investments are included in the assets of the Pipeline Operations segment. |
20. SUPPLEMENTAL CASH FLOW INFORMATION
Supplemental cash flows and non-cash transactions were as follows for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2010 |
|
|
2009 |
|
Cash paid for interest (net of capitalized interest) |
|
$ |
32,272 |
|
|
$ |
25,675 |
|
Cash paid for income taxes |
|
|
163 |
|
|
|
544 |
|
Capitalized interest |
|
|
529 |
|
|
|
1,281 |
|
|
|
|
|
|
|
|
|
|
Non-cash changes in assets and liabilities: |
|
|
|
|
|
|
|
|
Change in capital expenditures in accounts payable |
|
$ |
1,355 |
|
|
$ |
(1,522 |
) |
30
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 for the year ended December 31, 2009.
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 for the year ended December 31, 2009. 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. You should not put undue
reliance on any forward-looking statements. The forward-looking statements in this Quarterly
Report 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 for the year ended December 31, 2009. 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), the
limited partner units (LP Units) of which are listed on the New York Stock Exchange (NYSE)
under the ticker symbol BPL. Unless the context requires otherwise, references to we, us,
our, and Buckeye mean Buckeye Partners, L.P. and, where the context requires, include our
subsidiaries.
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 MLP that is also publicly traded on the NYSE under
the ticker symbol BGH.
31
Our primary business strategies are to generate stable cash flows, increase pipeline and
terminal throughput and pursue strategic cash-flow accretive acquisitions that complement our
existing asset base, improve operating efficiencies and allow increased cash distributions to our
unitholders.
We operate and report in five business segments: Pipeline Operations; Terminalling & Storage;
Natural Gas Storage; Energy Services; and Development & Logistics. Our principal line of business
is the transportation, terminalling, storage and marketing of refined petroleum products in the
United States for major integrated oil companies, large refined petroleum product marketing
companies and major end users of refined petroleum products on a fee basis through facilities we
own and operate. We own a major natural gas storage facility in northern California. In addition,
we operate and maintain approximately 2,400 miles of other pipelines under agreements with major
oil and gas, petrochemical and chemical companies, and perform certain engineering and construction
management services for third parties.
Recent Developments
Sale of Buckeye NGL Pipeline
Effective January 1, 2010, we sold our ownership interest in an approximately 350-mile natural
gas liquids pipeline (the Buckeye NGL Pipeline) that runs from Wattenberg, Colorado to Bushton,
Kansas for $22.0 million. The assets had been classified as Assets held for sale in our
consolidated balance sheet at December 31, 2009 with a carrying amount equal to the proceeds
received.
Results of Operations
Adjusted EBITDA
In the first quarter of 2010, we revised our internal management reports provided to senior
management, including the Chief Executive Officer, to redefine adjusted earnings before interest,
taxes and depreciation and amortization (Adjusted EBITDA) to now exclude non-cash unit-based
compensation expense. We believe this revised measure provides an improved means by which to gauge
our performance and increases comparability to similar measures used by other companies.
Adjusted EBITDA is the primary measure used by senior management 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 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 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 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, and (ii) non-cash unit-based compensation expense.
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 vary among other companies. Our senior
management uses Adjusted EBITDA to evaluate consolidated operating performance and the operating
performance of the 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.
32
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.
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, |
|
|
|
2010 |
|
|
2009 |
|
Adjusted EBITDA: |
|
|
|
|
|
|
|
|
Pipeline Operations |
|
$ |
57,817 |
|
|
$ |
55,868 |
|
Terminalling & Storage |
|
|
26,201 |
|
|
|
12,841 |
|
Natural Gas Storage |
|
|
6,469 |
|
|
|
8,963 |
|
Energy Services |
|
|
(1,541 |
) |
|
|
7,485 |
|
Development & Logistics |
|
|
1,136 |
|
|
|
1,537 |
|
|
|
|
|
|
|
|
Total Adjusted EBITDA |
|
$ |
90,082 |
|
|
$ |
86,694 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GAAP Reconciliation: |
|
|
|
|
|
|
|
|
Net income |
|
$ |
52,278 |
|
|
$ |
55,120 |
|
Less: net income attributable to noncontrolling interests |
| |
(1,765 |
) |
|
|
(1,360 |
) |
|
|
|
|
|
|
|
Net income attributable to Buckeye Partners, L.P.
unitholders |
|
|
50,513 |
|
|
|
53,760 |
|
Interest and debt expense |
|
|
21,549 |
|
|
|
17,176 |
|
Income tax (benefit) expense |
|
|
(18 |
) |
|
|
65 |
|
Depreciation and amortization |
|
|
15,644 |
|
|
|
14,480 |
|
|
|
|
|
|
|
|
EBITDA |
|
|
87,688 |
|
|
|
85,481 |
|
Non-cash deferred lease expense |
|
|
1,059 |
|
|
|
1,125 |
|
Non-cash unit-based compensation expense |
|
|
1,335 |
|
|
|
88 |
|
|
|
|
|
|
|
|
Adjusted EBITDA |
|
$ |
90,082 |
|
|
$ |
86,694 |
|
|
|
|
|
|
|
|
33
Segment Results
A summary of financial information by business segment follows for the periods indicated (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2010 |
|
|
2009 |
|
Revenues: |
|
|
|
|
|
|
|
|
Pipeline Operations |
|
$ |
96,537 |
|
|
$ |
99,195 |
|
Terminalling & Storage |
|
|
42,371 |
|
|
|
30,643 |
|
Natural Gas Storage |
|
|
25,406 |
|
|
|
15,077 |
|
Energy Services |
|
|
568,202 |
|
|
|
268,480 |
|
Development & Logisitics |
|
|
7,515 |
|
|
|
9,125 |
|
Intersegment |
|
|
(8,857 |
) |
|
|
(5,680 |
) |
|
|
|
|
|
|
|
Total revenues |
|
$ |
731,174 |
|
|
$ |
416,840 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses: (1) |
|
|
|
|
|
|
|
|
Pipeline Operations |
|
$ |
50,565 |
|
|
$ |
54,279 |
|
Terminalling & Storage |
|
|
18,905 |
|
|
|
19,650 |
|
Natural Gas Storage |
|
|
21,851 |
|
|
|
8,839 |
|
Energy Services |
|
|
571,278 |
|
|
|
262,068 |
|
Development & Logisitics |
|
|
6,412 |
|
|
|
7,581 |
|
Intersegment |
|
|
(8,857 |
) |
|
|
(5,680 |
) |
|
|
|
|
|
|
|
Total costs and expenses |
|
$ |
660,154 |
|
|
$ |
346,737 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization: |
|
|
|
|
|
|
|
|
Pipeline Operations |
|
$ |
9,641 |
|
|
$ |
9,577 |
|
Terminalling & Storage |
|
|
2,494 |
|
|
|
1,866 |
|
Natural Gas Storage |
|
|
1,767 |
|
|
|
1,581 |
|
Energy Services |
|
|
1,287 |
|
|
|
1,059 |
|
Development & Logisitics |
|
|
455 |
|
|
|
397 |
|
|
|
|
|
|
|
|
Total depreciation and amortization |
|
$ |
15,644 |
|
|
$ |
14,480 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss): |
|
|
|
|
|
|
|
|
Pipeline Operations |
|
$ |
45,972 |
|
|
$ |
44,916 |
|
Terminalling & Storage |
|
|
23,466 |
|
|
|
10,993 |
|
Natural Gas Storage |
|
|
3,555 |
|
|
|
6,238 |
|
Energy Services |
|
|
(3,076 |
) |
|
|
6,412 |
|
Development & Logisitics |
|
|
1,103 |
|
|
|
1,544 |
|
|
|
|
|
|
|
|
Total operating income |
|
$ |
71,020 |
|
|
$ |
70,103 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes depreciation and amortization. |
34
The following table presents product volumes transported in the Pipeline Operations
segment and average daily throughput for the Terminalling & Storage segment in barrels per day and
total volumes sold in gallons for the Energy Services segment for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2010 |
|
|
2009 |
|
Pipeline Operations: (average barrels per day) |
|
|
|
|
|
|
|
|
Gasoline |
|
|
608,900 |
|
|
|
632,400 |
|
Jet fuel |
|
|
322,300 |
|
|
|
333,300 |
|
Diesel fuel |
|
|
227,500 |
|
|
|
222,000 |
|
Heating oil |
|
|
113,900 |
|
|
|
131,100 |
|
LPGs |
|
|
20,500 |
|
|
|
14,400 |
|
NGLs |
|
|
|
|
|
|
21,300 |
|
Other products |
|
|
800 |
|
|
|
13,400 |
|
|
|
|
|
|
|
|
Total Pipeline Operations |
|
|
1,293,900 |
|
|
|
1,367,900 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Terminalling & Storage: (average barrels per day) |
|
|
|
|
|
|
|
|
Products throughput (1) |
|
|
556,300 |
|
|
|
480,800 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy Services: (in thousands of gallons) |
|
|
|
|
|
|
|
|
Sales volumes |
|
|
266,900 |
|
|
|
205,200 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Reported quantities exclude transfer volumes, which are non-revenue generating
transfers among our various terminals. For the three months ended March 31, 2009, we
previously reported 521.0 thousand, which included transfer volumes. |
Three Months Ended March 31, 2010 Compared to Three Months Ended March 31, 2009
Consolidated
Adjusted EBITDA increased by $3.4 million, or 3.9%, to $90.1 million in the three months ended
March 31, 2010 from $86.7 million in the corresponding period in 2009. The Terminalling & Storage
segment and the Pipeline Operations segment were primarily responsible for this increase in
Adjusted EBITDA. The Terminalling & Storage segments Adjusted EBITDA increased by $13.4 million
in the three months ended March 31, 2010 as compared to the corresponding period in 2009, driven
primarily by growth in fees, storage and rental revenues, the contribution from terminals acquired
in November 2009 (see Note 2 in the Notes to Unaudited Condensed Consolidated Financial
Statements), favorable settlement experience and lower operating expenses. The Pipeline Operations
segments Adjusted EBITDA increased by $1.9 million in the three months ended March 31, 2010 as
compared to the corresponding period in 2009, primarily due to increased tariffs, favorable
settlement experience and lower overall operating expenses, which more than offset the impact of
lower volumes transported during the three months ended March 31, 2010 compared to the
corresponding period in 2009. The Energy Services segments Adjusted EBITDA decreased by $9.0
million in the three months ended March 31, 2010 as compared to the corresponding
period in 2009 as a result of lower margins realized on products sold as a result of weakened
market conditions during the three months ended March 31, 2010, partially offset by increased
volumes of product sold. The Natural Gas Storage segments Adjusted EBITDA decreased by $2.5
million in the three months ended March 31, 2010 as compared to the corresponding period in 2009 as
a result of general market conditions, which led to increased hub service expense transactions
partially offset by increased hub service revenue transactions. The Development & Logistics
segments Adjusted EBITDA decreased by $0.4 million in the three months ended March 31, 2010 as
compared to the corresponding period in 2009 as a result of reduced operating services and
construction revenues. Further contributing to the increase in Adjusted EBITDA was the continued
effectiveness of cost control measures we implemented in 2009. Largely as a result of these
efforts, costs decreased by approximately $4.6 million during the three months ended March 31, 2010
as compared to the corresponding period in 2009. Income from equity investments increased by $0.6
million in the three months ended March 31, 2010 as compared to the corresponding
35
period in 2009. The revenue and expense factors affecting the variance in consolidated Adjusted EBITDA are more
fully discussed below.
Revenue was $731.1 million for the three months ended March 31, 2010, which is an increase of
$314.3 million, or 75.4%, from the three months ended March 31, 2009. This overall increase was
caused primarily by an increase of $299.7 million in revenues from the Energy Services segment, an
increase of $11.8 million in revenues from the Terminalling & Storage segment and an increase of
$10.3 million in revenues from the Natural Gas Storage segment. The increase in revenues in the
Energy Services segment resulted from an overall increase in refined petroleum product prices and
volumes of product sold in the first quarter of 2010 as compared to the corresponding period in
2009. The increase in revenues in the Terminalling & Storage segment resulted primarily from
increased fees, storage and rental revenue, including $1.7 million in storage fees from previously underutilized
tankage identified in connection with our best-practice initiatives, increased revenue from terminals acquired in November
2009 and favorable settlement experience. The increase in revenues from the Natural Gas Storage
segment resulted from increased activity from the commencement of operations of the Kirby Hills
Phase II expansion project in June 2009. These increases in revenue were partially offset by a
decrease of $2.7 million in revenues from the Pipeline Operations segment and a decrease of $1.6
million in revenue from the Development & Logistics segment. Revenue decreased in the Pipeline
Operations segment primarily due to lower transportation volumes and lower miscellaneous revenues,
partially offset by increased tariffs, favorable settlement experience and increased revenues from
the pipeline assets acquired in November 2009. Revenue decreased in the Development & Logistics
segment primarily due to decreased construction activities.
Total costs and expenses were $660.2 million for the three months ended March 31, 2010, which
is an increase of $313.5 million, or 90.4%, from the corresponding period in 2009. Total costs and
expenses reflect an increase in refined petroleum product prices, which, coupled with an increase
in volume sold, resulted in a $309.9 million increase in the Energy Services segments cost of
product sales in the 2010 period as compared to the 2009 period. Total costs and expenses also
reflect an increase of $13.1 million in the Natural Gas Storage segments costs and expenses
resulting from higher costs associated with hub services transactions caused by general market
conditions. Total costs and expenses also include an increase of $1.1 million in depreciation and
amortization and an increase of $1.2 million in non-cash unit-based compensation expense, which are
not components of Adjusted EBITDA as presented in the reconciliation above. These increases in
total costs and expenses were largely offset by decreases of $3.7 million, $1.1 million and $0.8
million in the costs and expenses of the Pipeline Operations segment, the Development & Logistics
segment and the Terminalling & Storage segment, respectively. The decrease in the costs and
expenses of the Pipeline Operations segment was driven by lower payroll and benefits costs, which
was primarily attributable to the organizational restructuring that occurred in 2009, which
resulted in reduced headcount, as well as from lower contract service activities and lower
environmental remediation expenses. The decrease in the costs and expenses of the Development &
Logistics segment was primarily due to reduced construction contract activity and reduced operating
services activities. The decrease in the costs and expenses of the Terminalling & Storage segment
primarily resulted from lower environmental remediation expenses. Total costs and expenses for the
three months ended March 31, 2010 reflect the effectiveness of cost management efforts we
implemented in 2009.
Consolidated net income attributable to our unitholders was $50.5 million for the three months
ended March 31, 2010 compared to $53.8 million for the three months ended March 31, 2009. Interest
and debt expense increased by $4.3 million in the three months ended March 31, 2010 as compared to
the corresponding period in 2009, which was largely attributable to the issuance in August 2009 of
$275.0 million aggregate principal amount of 5.500% Notes due 2019. In addition, depreciation and
amortization increased by $1.1 million, primarily due to the assets utilized
with respect to the Kirby Hills Phase II expansion project, which were placed in service in
the second half of 2009, and certain internal-use software, which was placed in service in the
fourth quarter of 2009.
For a more detailed discussion of the above factors affecting our results, see the following
discussion by segment.
Pipeline Operations
Adjusted EBITDA from the Pipeline Operations segment of $57.8 million in the three months
ended March 31, 2010 increased by $1.9 million, or 3.5%, from $55.9 million in the corresponding
period in 2009. The increase in
36
Adjusted EBITDA was driven primarily by the benefit of higher
tariffs of $2.5 million, favorable settlement experience of $2.0 million and increased revenues of
$0.6 million from pipeline assets acquired in November 2009. The Pipeline Operations segments
improved Adjusted EBITDA was also due to a $0.6 million increase in income from equity investments
and a $2.6 million decrease in operating expenses. These increases in Adjusted EBITDA were
partially offset by a decrease of $4.8 million in transportation revenues resulting from lower
volumes transported in the three months ended March 31, 2010 compared with the corresponding period
in 2009 and lower volumes resulting from the sale of Buckeye NGL Pipeline on January 1, 2010 (see
Note 2 in the Notes to Unaudited Condensed Consolidated Financial
Statements) and a $3.1 million
decrease in miscellaneous other revenue. The revenue and expense factors affecting the variance in
Adjusted EBITDA are more fully discussed below.
Revenue from the Pipeline Operations segment was $96.5 million in the three months ended March
31, 2010, which is a decrease of $2.7 million, or 2.7%, from the corresponding period in 2009.
Revenues decreased primarily due to a $4.8 million decrease related to a 5.4% decrease in
transportation volumes due in part to the sale of Buckeye NGL Pipeline on January 1, 2010 and a
$3.1 million decrease in miscellaneous other revenue, including revenues from a product supply
arrangement with a wholesale distributor and contract service activities at customer facilities
connected to our refined petroleum products pipelines. These decreases were partially offset by
higher tariffs of $2.5 million, favorable settlement experience of $2.0 million and increased
revenues of $0.6 million from the pipeline assets acquired in November 2009. An overall average
tariff increase of approximately 3.8% was implemented on July 1, 2009.
Total costs and expenses from the Pipeline Operations segment were $50.6 million for the three
months ended March 31, 2010, which is a decrease of $3.7 million, or 6.8%, from the corresponding
period in 2009. Total costs and expenses include decreases in (i) payroll and benefits costs of
$2.2 million, pursuant to our best-practice initiative in 2009; (ii) contract service activities of
$1.1 million at customer facilities connected to our refined petroleum products pipelines; (iii)
environmental remediation expenses of $1.5 million and (iv) product costs of $0.4 million as a
result of reduced volumes of product sold to a wholesale distributor. These decreases were
partially offset by an increase of $0.4 million in professional fees, as well as increases in other
expenses, primarily consisting of an increase of $0.6 million in bad debt expense. Total costs and
expenses also include an increase of $0.7 million in non-cash unit-based compensation expense,
which is not a component of Adjusted EBITDA as presented in the reconciliation above.
Operating income from the Pipeline Operations segment was $46.0 million for the three months
ended March 31, 2010 compared to operating income of $44.9 million for the three months ended March
31, 2009. Depreciation and amortization of $9.6 million for the three months ended March 31, 2010
was consistent with the corresponding period in 2009. Other revenue and expense items impacting
operating income are discussed above.
Terminalling & Storage
Adjusted EBITDA from the Terminalling & Storage segment of $26.2 million in the three months
ended March 31, 2010 increased by $13.4 million, or 104.0%, from $12.8 million in the corresponding
period in 2009. The increase in Adjusted EBITDA reflects an increase of $10.6 million primarily
from terminals acquired in November 2009, internal growth projects, higher fees, storage, rental
and other service revenue and increased settlement experience and a $2.3 million decrease in
operating expenses. In addition to the 10.5% increase in volumes resulting from the acquisition of
terminals in November 2009, terminalling volumes increased 5.2% in the three months ended March 31,
2010 as compared to the corresponding period in 2009 largely due increased ethanol throughput
volumes. The revenue and expense factors affecting the variance in Adjusted EBITDA are more fully
discussed below.
Revenue from the Terminalling & Storage segment was $42.4 million in the three months ended
March 31, 2010, which is an increase of $11.8 million, or 38.3%, from the corresponding period in
2009. The majority of the increase resulted from an increase of $10.9 million, primarily from (i)
terminals acquired in November 2009, (ii) internal growth projects, (iii) higher fees, as well as
higher storage and rental revenue of $3.5 million, including $1.7 million in storage fees from
previously underutilized tankage identified in connection with our best-practice initiatives and
(iv) increased butane-blending revenue. Also contributing to the improved revenue was an increase
of $0.9 million in settlement experience reflecting the favorable impact of higher refined
petroleum product prices during the three months ended March 31, 2010 as compared to the
corresponding period in 2009. In addition to the 10.5% increase in volumes resulting from the
acquisition of terminals in November 2009, terminalling volumes increased 5.2% in the three months
ended March 31, 2010 as compared to the corresponding period in 2009 largely due to increased
ethanol throughput volumes.
37
Total costs and expenses from the Terminalling & Storage segment were $18.9 million for the three months
ended March 31, 2010, which is a decrease of $0.8 million, or 3.8%, from the corresponding period in 2009. Total
costs and expenses reflect a $2.4 million decrease in environmental remediation expenses and a decrease in payroll and benefits
costs of approximately $0.6 million,
partially offset by a $1.0 million increase in operating expenses for terminals acquired in November 2009 and a $0.6 million
increase in bad debt expense. Total costs and expenses also include an increase of $0.6 million in depreciation and amortization
and an increase of $0.2 million in non-cash unit-based compensation expense, which are not components of Adjusted EBITDA as presented
in the reconciliation above.
Operating income from the Terminalling & Storage segment was $23.5 million for the three
months ended March 31, 2010 compared to operating income of $11.0 million for the three months
ended March 31, 2009. Depreciation and amortization increased by $0.6 million for the three months
ended March 31, 2010 as a result of the terminals acquired in November 2009. Other revenue and
expense items impacting operating income are discussed above.
Natural Gas Storage
Adjusted EBITDA from the Natural Gas Storage segment of $6.5 million in the three months ended March 31,
2010 decreased by $2.5 million, or 27.8%, from $9.0 million in the corresponding period in 2009. The decrease
in Adjusted EBITDA was primarily a result of a $3.9 million decrease in the net contribution from hub service
activities during the three months ended March 31, 2010, partially offset by increased lease revenues of $1.5
million. The increase in lease revenues was the result of increased storage capacity from the commissioning of
the Kirby Hills Phase II expansion project, which was placed in service in June 2009, partially offset by a
decrease in the fee charged for each volumetric unit of storage capacity leased. The revenue and expense
factors affecting the variance in Adjusted EBITDA are more fully discussed below.
Revenue from the Natural Gas Storage segment was $25.4 million in the three months ended March
31, 2010, which is an increase of $10.3 million, or 68.5%, from the corresponding period in 2009.
This overall increase is attributable to greater underlying volume for hub services provided during
the three months ended March 31, 2010 compared to the same period in 2009. In addition, this
increase is due to higher fees recognized as revenue for hub services provided during the three
months ended March 31, 2010. The fees for hub services agreements are based on the relative market
prices of natural gas over different delivery periods. When that market price spread is positive,
a fee is received from the customer and reflected as transportation and other services revenue.
When that market price spread is negative, a fee is paid to the customer and reflected as cost of
natural gas storage services. These fees are recognized as revenue or cost of natural gas storage services ratably
as the underlying services are provided or utilized. Such agreements are entered into in order to
maximize the daily utilization of the natural gas storage facility and to attempt to capture value
from seasonal price differences in the natural gas markets. During each respective period, there
were 155 outstanding hub service contracts for which revenue was being recognized ratably. Market
conditions contributed to higher fees for hub service agreements recognized as revenue during the
three months ended March 31, 2010 compared to the same period in 2009. In addition, lease revenue
increased $1.5 million in the three months ended March 31, 2010, as storage capacity increased
from the commissioning of the Kirby Hills Phase II expansion project, which was placed in service
in June 2009, partially offset by a decrease in the fee charged for each volumetric unit of storage
capacity leased.
Total costs and expenses from the Natural Gas Storage segment were $21.9 million for the three
months ended March 31, 2010, which is an increase of $13.1 million, or 147.2%, from the
corresponding period in 2009. The primary driver of the increase in expenses is an increase in hub
services fees paid to customers for hub service activities. As stated above, hub service fees are
based on the relative market prices of natural gas over different delivery periods; when that
market price spread is negative, a fee is paid to the customer, which is reflected as cost
of natural gas storage services ratably as those services are provided. Total costs and expenses also
include an increase of $0.2 million in depreciation and amortization and an increase of $0.1
million in non-cash unit-based compensation expense, which are not components of Adjusted EBITDA as
presented in the reconciliation above.
Operating income from the Natural Gas Storage segment was $3.5 million for the three months
ended March 31, 2010 compared to operating income of $6.3 million for the three months ended March
31, 2009. Depreciation and amortization increased by $0.2 million in the 2010 period from the
corresponding period in 2009
38
due to depreciation expense on the assets utilized with respect to the
Kirby Hills Phase II expansion project, which were placed in service in the second half of 2009.
Other revenue and expense items impacting operating income are discussed above.
Energy Services
Adjusted EBITDA from the Energy Services segment, which was a loss of $1.5 million, decreased
during the three months ended March 31, 2010 by $9.0 million, or 120.6%, from income of $7.5
million in the corresponding period in 2009. This decrease in Adjusted EBITDA was a result of the
withdrawal of product from inventory as the market conditions changed and commodity prices were no longer in contango. The increase in product supply from inventory liquidation, coupled with lower
overall product demand, created additional pressure on margins, which was partially offset by a
30.1% increase in sales volume. The revenue and expense factors affecting the variance in Adjusted
EBITDA are more fully discussed below.
Revenue from the Energy Services segment was $568.2 million in the three months ended March
31, 2010, which is an increase of $299.7 million, or 111.6%, from the corresponding period in 2009.
This increase was primarily due to an increase in refined petroleum product prices, which
correspondingly increases the cost of products sales, and an increase of 30.1% in sales volumes.
Total costs and expenses from the Energy Services segment were $571.3 million for the three
months ended March 31, 2010, which is an increase of $309.2 million, or 118.0%, from the
corresponding period in 2009. The increase in total costs and expenses was primarily due to an
increase of $309.9 million in cost of product sales as a result of increased volumes and an
increase in refined petroleum product prices and an increase of $0.5 million in bad debt expense. Total costs and expenses also include an increase of
$0.2 million in depreciation and amortization and an increase of $0.2 million in non-cash
unit-based compensation expense, which are not components of Adjusted EBITDA as presented in the
reconciliation above.
Operating loss from the Energy Services segment was $3.1 million for the three months ended
March 31, 2010 compared to operating income of $6.4 million for the three months ended March 31,
2009. Depreciation and amortization increased by $0.2 million for the 2010 period from the
corresponding period in 2009 due to amortization of certain internal-use software that was placed
in service in the fourth quarter of 2009. Other revenue and expense items impacting operating
income (loss) are discussed above.
Development & Logistics
Adjusted EBITDA from the Development & Logistics segment of $1.1 million in the three months
ended March 31, 2010 decreased by $0.4 million, or 26.1%, from $1.5 million in the corresponding
period in 2009. The revenue and expense factors affecting the variance in Adjusted EBITDA are more
fully discussed below.
Revenue from the Development & Logistics segment, which consists principally of our contract
operations and engineering services for third-party pipelines, was $7.5 million in the three months
ended March 31, 2010, which is a decrease of $1.6 million, or 17.6%, from the corresponding period
in 2009. The decrease was primarily due to the completion and non-replacement of construction
projects in 2009, resulting in a $1.5 million reduction in certain construction contract revenues.
The decrease was also partially the result of a $0.2 million reduction in operating services
primarily related to the non-renewal of an operating lease contract that expired in 2009.
Total costs and expenses from the Development & Logistics segment were $6.4 million for the
three months ended March 31, 2010, which is a decrease of $1.1 million, or 15.4%, from the
corresponding period in 2009. The decrease was the result of the reduced construction contract activity and reduced operating
services activities discussed above.
Operating income from the Development & Logistics segment was $1.1 million for the three
months ended March 31, 2010 compared to operating income of $1.5 million for the three months ended
March 31, 2009. Depreciation and amortization of $0.4 million for the three months ended March 31,
2010 was relatively consistent with the corresponding period in 2009, and income taxes decreased by
$0.1 million for the three months ended
39
March 31, 2010 due to lower earnings. Other 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 unsecured
revolving credit agreement (the Credit Facility) and proceeds from the issuance of our LP Units.
We will, from time to time, issue debt securities to permanently finance amounts borrowed under the
Credit Facility. Buckeye Energy Services LLC (BES) funds its working capital needs principally
from its operations and a secured credit facility (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.
As a result of our actions to minimize external financing requirements and the fact that no
debt facilities mature prior to 2011, we believe that availabilities under our credit facilities,
coupled with ongoing cash flows from operations, will be sufficient to fund our operations for the
remainder of 2010. We will continue to evaluate a variety of financing sources, including the debt
and equity markets described above, throughout 2010. However, continuing volatility in the debt
and equity markets will make the timing and cost of any such potential financing uncertain.
At March 31, 2010, we had $16.5 million of cash and cash equivalents on hand and approximately
$413.0 million of available credit under the Credit Facility, after application of the facilitys
funded debt ratio covenant. In addition, at March 31, 2010, BES
had
$40.5 million of available
credit under the BES Credit Agreement, pursuant to certain borrowing base calculations under that
agreement.
At March 31, 2010, we had an aggregate face amount of $1,628.5 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); |
|
|
|
|
$150.0 million of 6.750% Notes due 2033 (the 6.750% Notes); |
|
|
|
|
$20.0 million outstanding under our Credit Facility; and |
|
|
|
|
$183.5 million outstanding under the BES Credit Agreement. |
See Note 10 in the Notes to Unaudited Condensed Consolidated Financial Statements for more
information about the terms of the debt discussed above.
The fair values of our aggregate debt and credit facilities were estimated to be $1,677.4
million and $1,762.1 million at March 31, 2010 and December 31, 2009, 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.
40
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 would allow us to issue an unlimited amount of debt
and equity securities for general partnership purposes.
Credit Ratings
Our debt securities are rated BBB by Standard & Poors Ratings Services and Baa2 by Moodys
Investors Service, both with stable outlooks. Such ratings reflect only the view of the rating
agency and should not be interpreted as a recommendation to buy, sell or hold our securities.
These ratings may be revised or withdrawn at any time by the agencies at their discretion and
should be evaluated independently of any other rating.
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, |
|
|
|
2010 |
|
|
2009 |
|
Cash provided by (used in): |
|
|
|
|
|
|
|
|
Operating activities |
|
$ |
144,746 |
|
|
$ |
79,633 |
|
Investing activities |
|
|
11,211 |
|
|
|
(21,018 |
) |
Financing activities |
|
|
(174,049 |
) |
|
|
(100,196 |
) |
Operating Activities
Net cash flow provided by operating activities was $144.7 million for the three months ended
March 31, 2010 compared to $79.6 million for the three months ended March 31, 2009. The following
were the principal factors resulting in the $65.1 million increase in net cash flows provided by
operating activities:
|
|
|
The net change in fair values of derivatives was a decrease of $19.2 million to cash
flows from operating activities for the three months ended March 31, 2010, resulting
from the increase in value related to fixed-price sales contracts compared to a lower
level of opposite fluctuations in futures contracts purchased to hedge such
fluctuations. |
|
|
|
|
The net impact of working capital changes was an increase of $90.3 million to cash
flows from operating activities for the three months ended March 31, 2010. The
principal factors affecting the working capital changes were: |
|
o |
|
Inventories decreased by $73.7 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. |
|
|
o |
|
Trade receivables increased by $10.4 million primarily due to
increased activity from our Energy Services segment due to higher volumes and
higher commodity prices in the 2010 period. |
|
|
o |
|
Prepaid and other current assets decreased by $26.9 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
first quarter of 2010 (increased commodity prices result in an increase in our
broker equity account and therefore less margin deposit is required), a
decrease in unbilled revenue within our Natural Gas Storage segment reflecting
billings to counterparties in accordance with terms of their storage agreements
and a decrease in prepaid insurance due to continued amortization of the balance
over the policy period. |
41
|
o |
|
Accrued and other current liabilities increased by $0.3 million
primarily due to increases in unearned revenue primarily in the Natural Gas
Storage segment as a result of increased hub services contracts during the
first quarter of 2010 for which the customer is billed up front for services
provided over the entire term of the contract, an increase in accrued property
taxes for the Natural Gas Storage segment as a result of the Kirby Hills II
expansion project and an increase in accrued excise taxes for the Energy
Services segment due to higher revenues, largely offset by a reduction in
accrued interest resulting from interest payments made during the three months
ended March 31, 2010 and a reduction in the reorganization accrual. |
|
|
o |
|
Accounts payable decreased by $3.0 million primarily due to
lower payable balances at March 31, 2010 as a result of lower outside services
and project work performed in the first quarter of 2010. |
|
|
o |
|
Construction and pipeline relocation receivables decreased by
$2.7 million primarily due to a decrease in construction activity in the 2010
period. |
Investing Activities
Net cash flow provided by investing activities was $11.2 million for the three months ended
March 31, 2010 compared to net cash flow used in investing activities of $21.0 million for the
three months ended March 31, 2009. The following were the principal factors resulting in the $32.2
million increase in net cash flows provided by investing activities:
|
|
|
Capital expenditures decreased by $10.0 million for the three months ended March 31,
2010 compared with the three months ended March 31, 2009. See below for a discussion
of capital spending. |
|
|
|
|
Cash proceeds from the sale of the Buckeye NGL Pipeline were $22.0 million during
the three months ended March 31, 2010. |
Capital expenditures are summarized below (net of non-cash changes in accruals for capital
expenditures for the three months ended March 31, 2010 and 2009) for the periods indicated (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2010 |
|
|
2009 |
|
Sustaining capital expenditures |
|
$ |
3,270 |
|
|
$ |
4,883 |
|
Expansion and cost reduction |
|
|
7,693 |
|
|
|
16,093 |
|
|
|
|
|
|
|
|
Total capital expenditures |
|
$ |
10,963 |
|
|
$ |
20,976 |
|
|
|
|
|
|
|
|
Expansion and cost reduction projects in the first quarter of 2010 included terminal ethanol
and butane blending, new pipeline connections, natural gas well recompletions, continued progress
on a new pipeline and terminal billing system as well as various other operating infrastructure
projects. In the first quarter of 2009, 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 $90.0 million to $110.0 million for capital expenditures in
2010, of which approximately $25.0 million to $35.0 million is expected to relate to sustaining
capital expenditures and $65.0 million to $75.0 million is expected to relate to expansion and cost
reduction projects. 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 2010 will include the completion of additional
product storage tanks in the Midwest, the construction of a 4.4 mile pipeline in central
Connecticut to connect our pipeline in Connecticut to a third-party electric generation plant
currently under construction, various terminal expansions and upgrades and pipeline and terminal
automation projects.
42
Financing Activities
Net cash flow used in financing activities was $174.0 million for the three months ended March
31, 2010 compared to $100.2 million for the three months ended March 31, 2009. The following were
the principal factors resulting in the $73.8 million increase in net cash flows used in financing
activities:
|
|
|
We borrowed $59.5 million and $30.0 million and repaid $117.5 million and $120.3
million under the Credit Facility during the three months ended March 31, 2010 and
2009, respectively. |
|
|
|
|
Net repayments under the BES Credit Agreement were $56.3 million and $46.0 million
during the three months ended March 31, 2010 and 2009, respectively. |
|
|
|
|
We received $2.4 million in net proceeds from the exercise of LP Unit options during
the first quarter of 2010. We received $91.0 million in net proceeds from an
underwritten equity offering in March 2009 for the public issuance of 2.6 million LP
Units. |
|
|
|
|
Cash distributions paid to our partners increased by $7.3 million period-to-period
due to an increase in the number of LP Units outstanding and an increase in our
quarterly cash distribution rate per LP Unit. We paid cash distributions of $61.0
million ($0.9375 per LP Unit) and $53.7 million ($0.8875 per LP Unit) during the three
months ended March 31, 2010 and 2009, respectively. |
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
With the exception of routine fluctuations in the balance of the Credit Facility and the BES
Credit Agreement, there have been no material changes in our scheduled maturities of or debt
obligations since those reported in our Annual Report on Form 10-K for the year ended December 31,
2009.
Total rental expense for the three months ended March 31, 2010 and 2009 was $5.0 million and
$5.3 million, respectively. There have been no material changes in our operating lease commitments
since December 31, 2009.
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 for the year ended December 31, 2009.
Related Party Transactions
With respect to related party transactions, see Note 16 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 and do not engage in hedging activity with respect
to trading instruments.
43
Market Risk Non-Trading Instruments
We are exposed to financial market risk resulting from changes in commodity prices and
interest rates. We do not currently have foreign exchange risk.
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.
As of March 31, 2010, the Natural Gas Storage segment has recorded the following assets and
liabilities related to its hub services agreements (in thousands):
|
|
|
|
|
|
|
March 31, |
|
|
|
2010 |
|
Assets: |
|
|
|
|
Hub service agreements |
|
$ |
32,780 |
|
|
|
|
|
|
Liabilities: |
|
|
|
|
Hub service agreements |
|
|
(24,284 |
) |
|
|
|
|
Total |
|
$ |
8,496 |
|
|
|
|
|
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 fixed-price 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.
The Energy Services segment has not used hedge accounting with respect to its fixed-price
sales contracts. Therefore, its fixed-price sales contracts and the related futures contracts used
to offset those fixed-price sales contracts are all marked-to-market on the balance sheet with
gains and losses being recognized in earnings during each reporting period.
As of March 31, 2010, the Energy Services segment had derivative assets and liabilities as
follows (in thousands):
|
|
|
|
|
|
|
March 31, |
|
|
|
2010 |
|
Assets: |
|
|
|
|
Fixed-price sales contracts |
|
$ |
1,964 |
|
|
|
|
|
|
Liabilities: |
|
|
|
|
Fixed-price sales contracts |
|
|
(1,217 |
) |
Futures contracts for inventory and fixed-price sales
contracts |
|
|
(1,614 |
) |
|
|
|
|
Total |
|
$ |
(867 |
) |
|
|
|
|
44
Substantially all of the unrealized loss at March 31, 2010 for inventory hedges represented by
futures contracts will be realized by the second quarter of 2010 as the related inventory is sold.
Gains recorded on inventory hedges that were ineffective were approximately $4.8 million for the
three months ended March 31, 2010. At March 31, 2010, open refined petroleum product derivative
contracts (represented by the fixed-price sales contracts and futures contracts for fixed-price
sales contracts and inventory noted above) varied in duration, but did not extend beyond May 2011.
In addition, at March 31, 2010, we had refined petroleum product inventories which we intend to use
to satisfy a portion of the fixed-price sales contracts.
Based on a hypothetical 10% movement in the underlying quoted market prices of the commodity
financial instruments outstanding at March 31, 2010, 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 |
|
$ |
(867 |
) |
Fair value assuming 10% increase in
underlying commodity prices |
|
Liability |
|
$ |
(22,720 |
) |
Fair value assuming 10% decrease in
underlying commodity prices |
|
Asset |
|
$ |
20,986 |
|
The value of the open futures contract positions noted above were based upon quoted market
prices obtained from NYMEX. The value of the fixed-price sales contracts was based on observable
market data related to the obligation to provide refined petroleum products to customers.
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, 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 an existing debt obligation.
At March 31, 2010, we had total fixed-rate debt obligations at face value of $1,425.0 million,
consisting of $125.0 million of the 5.125% Notes, $275.0 million of the 5.300% Notes, $300.0
million of the 4.625% Notes, $150.0 million of the 6.750% Notes, $300.0 million of the 6.050% Notes
and $275.0 million of the 5.500% Notes. The fair value of these fixed-rate debt obligations at
March 31, 2010 was approximately $1,473.9 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 $89.3 million.
45
At March 31, 2010, our variable-rate obligations were $20.0 million under the Credit Facility
and $183.5 million under the BES Credit Agreement. Based on the balances outstanding at March 31,
2010, a hypothetical 100 basis point increase or decrease in interest rates would increase or
decrease annual interest expense by approximately $2.0 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. During
2009, we entered into four forward-starting interest rate swaps with a total aggregate notional
amount of $200.0 million related to the anticipated issuance of debt on or before July 15, 2013 and
three forward-starting interest rate swaps with a total aggregate notional amount of $150.0 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, 2010, unrealized losses of $1.3 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.
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, 2010 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
Financial |
|
|
|
|
|
|
Instrument |
|
|
|
Resulting |
|
|
Portfolio |
|
Scenario |
|
Classification |
|
Fair Value |
Fair value assuming no change in
underlying interest rates (as is) |
|
Asset |
|
$ |
15,900 |
|
Fair value assuming 10% increase in
underlying interest rates |
|
Asset |
|
$ |
28,824 |
|
Fair value assuming 10% decrease in
underlying interest rates |
|
Asset |
|
$ |
2,242 |
|
|
|
|
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.
(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 2010, that have materially affected, or are reasonably likely to materially affect, our
internal controls over financial reporting.
46
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.
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 for the year
ended December 31, 2009 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.
(a) Exhibits
|
|
|
10.1
|
|
Buckeye Partners, L.P. Annual Incentive Compensation Plan, as amended and
restated, effective as of January 1, 2010 (Incorporated by reference to
Exhibit 10.13 of Buckeye Partners, L.P.s Annual Report on Form 10-K for the
year ended December 31, 2009). |
|
|
|
*31.1
|
|
Certification of Chief Executive Officer pursuant to Rule 13a-14 (a) under the
Securities Exchange Act of 1934. |
|
|
|
*31.2
|
|
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the
Securities Exchange Act of 1934. |
|
|
|
*32.1
|
|
Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350. |
|
|
|
*32.2
|
|
Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350. |
47
SIGNATURES
Pursuant to the requirements of Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
|
|
|
|
|
|
|
|
By: |
BUCKEYE PARTNERS, L.P.
|
|
|
|
(Registrant) |
|
|
|
|
|
|
|
|
|
|
By: |
Buckeye GP LLC,
|
|
|
|
as General Partner |
|
|
|
|
|
|
|
|
|
Date: May 7, 2010 |
By: |
/s/ Keith E. St.Clair
|
|
|
|
Keith E. St.Clair |
|
|
|
Senior Vice President and
Chief Financial Officer
(Principal Accounting Officer and
Principal Financial Officer) |
|
|
48