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 June 30, 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
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(IRS Employer |
incorporation or organization)
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Identification number) |
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One Greenway Plaza |
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Suite 600 |
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Houston, TX
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77046 |
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(Address of principal executive offices)
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(Zip Code) |
Registrants telephone number, including area code: (832) 615-8600
Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the Registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the
Exchange Act. (Check one):
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Large
accelerated filer þ
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Accelerated
filer o
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Non-accelerated filer o
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Smaller reporting company o |
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(Do not check if a smaller reporting company) |
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Act).
Yes o No þ
Limited partner units outstanding as of August 3, 2010: 51,535,672
PART I. FINANCIAL INFORMATION
Item 1. 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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Six Months Ended |
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June 30, |
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June 30, |
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2010 |
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2009 |
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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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$ |
501,744 |
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$ |
201,777 |
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$ |
1,069,914 |
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$ |
470,556 |
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Transportation and other services |
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165,532 |
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149,443 |
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328,536 |
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297,504 |
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Total revenue |
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667,276 |
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351,220 |
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1,398,450 |
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768,060 |
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Costs and expenses: |
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Cost of product sales and natural gas storage
services |
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498,645 |
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193,440 |
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1,068,382 |
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444,116 |
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Operating expenses |
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67,560 |
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68,595 |
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133,269 |
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142,102 |
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Depreciation and amortization |
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15,786 |
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14,675 |
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31,430 |
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29,155 |
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Asset impairment expense |
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72,540 |
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72,540 |
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General and administrative |
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11,446 |
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8,365 |
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20,510 |
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16,439 |
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Reorganization expense |
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28,113 |
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28,113 |
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Total costs and expenses |
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593,437 |
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385,728 |
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1,253,591 |
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732,465 |
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Operating income (loss) |
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73,839 |
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(34,508 |
) |
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144,859 |
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35,595 |
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Other income (expense): |
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Earnings from equity investments |
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2,764 |
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3,142 |
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5,416 |
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5,224 |
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Interest and debt expense |
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(21,262 |
) |
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(16,061 |
) |
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(42,811 |
) |
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(33,237 |
) |
Other income |
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84 |
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156 |
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239 |
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267 |
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Total other expense |
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(18,414 |
) |
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(12,763 |
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(37,156 |
) |
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(27,746 |
) |
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Net income (loss) |
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55,425 |
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(47,271 |
) |
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107,703 |
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7,849 |
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Less: net income attributable to
noncontrolling interests |
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(1,818 |
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(1,100 |
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(3,583 |
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(2,460 |
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Net income (loss) attributable
to Buckeye Partners, L.P. |
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$ |
53,607 |
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$ |
(48,371 |
) |
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$ |
104,120 |
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$ |
5,389 |
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Allocation of net income (loss)
attributable to Buckeye Partners, L.P.: |
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Net income allocated to general partner |
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$ |
12,797 |
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$ |
11,455 |
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$ |
25,292 |
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$ |
23,121 |
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Net income (loss) allocated to limited partners |
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$ |
40,810 |
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$ |
(59,826 |
) |
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$ |
78,828 |
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$ |
(17,732 |
) |
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Earnings (Loss) Per Limited Partner Unit: |
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Basic |
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$ |
0.79 |
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$ |
(1.17 |
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$ |
1.52 |
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$ |
(0.36 |
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Diluted |
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$ |
0.78 |
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$ |
(1.17 |
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$ |
1.51 |
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$ |
(0.36 |
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Weighted average number of
limited partner units outstanding: |
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Basic |
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51,512 |
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51,243 |
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51,492 |
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49,830 |
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Diluted |
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51,712 |
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51,243 |
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51,673 |
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49,830 |
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See Notes to Unaudited Condensed Consolidated Financial Statements.
2
BUCKEYE PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)
(Unaudited)
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Three Months Ended |
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Six Months Ended |
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June 30, |
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June 30, |
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2010 |
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2009 |
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2010 |
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2009 |
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Net income (loss) |
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$ |
55,425 |
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$ |
(47,271 |
) |
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$ |
107,703 |
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$ |
7,849 |
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Other comprehensive income (loss): |
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Change in value of derivatives |
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(34,672 |
) |
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353 |
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(36,600 |
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543 |
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Amortization of interest rate swaps |
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242 |
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240 |
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482 |
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480 |
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Amortization of benefit plan costs |
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(590 |
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1 |
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(568 |
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(358 |
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Adjustment to funded status of benefit plans |
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7,970 |
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7,970 |
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Total other comprehensive income (loss) |
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(35,020 |
) |
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8,564 |
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(36,686 |
) |
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8,635 |
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Comprehensive income (loss) |
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$ |
20,405 |
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$ |
(38,707 |
) |
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$ |
71,017 |
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$ |
16,484 |
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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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June 30, |
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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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$ |
12,513 |
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$ |
34,599 |
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Trade receivables, net |
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113,576 |
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124,165 |
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Construction and pipeline relocation receivables |
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11,626 |
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14,095 |
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Inventories |
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275,174 |
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310,214 |
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Derivative assets |
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10,093 |
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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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67,621 |
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103,691 |
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Total current assets |
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490,603 |
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613,723 |
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Property, plant and equipment, net |
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2,227,659 |
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2,228,265 |
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Equity investments |
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98,568 |
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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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42,931 |
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45,157 |
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Other non-current assets |
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41,698 |
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62,777 |
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Total assets |
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$ |
3,110,335 |
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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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$ |
194,179 |
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$ |
239,800 |
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Accounts payable |
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64,163 |
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56,525 |
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Derivative liabilities |
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367 |
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14,665 |
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Accrued and other current liabilities |
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116,903 |
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106,743 |
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Total current liabilities |
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375,612 |
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417,733 |
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Long-term debt |
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1,421,181 |
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1,498,970 |
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Other non-current liabilities |
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127,627 |
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102,851 |
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Total liabilities |
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1,924,420 |
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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
June 30, 2010 and December 31, 2009) |
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1,762 |
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1,849 |
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Limited Partners (51,524,772 and 51,438,265 units outstanding
as of June 30, 2010 and December 31, 2009, respectively) |
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1,199,649 |
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1,214,136 |
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Accumulated other comprehensive loss |
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(37,533 |
) |
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(847 |
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Total Buckeye Partners, L.P. unitholders capital |
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1,163,878 |
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1,215,138 |
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Noncontrolling interests |
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22,037 |
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|
20,957 |
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Total partners capital |
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1,185,915 |
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1,236,095 |
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Total liabilities and partners capital |
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$ |
3,110,335 |
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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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Six Months Ended |
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June 30, |
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2010 |
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|
2009 |
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Cash flows from operating activities: |
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Net income |
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$ |
107,703 |
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$ |
7,849 |
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Adjustments to reconcile net income to cash provided by
operating activities: |
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Depreciation and amortization |
|
|
31,430 |
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|
|
29,155 |
|
Asset impairment expense |
|
|
|
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|
72,540 |
|
Net changes in fair value of derivatives |
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|
(12,901 |
) |
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|
4,672 |
|
Non-cash deferred lease expense |
|
|
2,117 |
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|
2,250 |
|
Reorganization expense |
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|
28,113 |
|
Earnings from equity investments |
|
|
(5,416 |
) |
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|
(5,224 |
) |
Distributions from equity investments |
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|
3,700 |
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|
2,827 |
|
Amortization of other non-cash items |
|
|
4,418 |
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|
|
2,438 |
|
Change in assets and liabilities: |
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Trade receivables |
|
|
10,589 |
|
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|
(2,832 |
) |
Construction and pipeline relocation receivables |
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|
2,469 |
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|
|
4,855 |
|
Inventories |
|
|
28,065 |
|
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(27,742 |
) |
Prepaid and other current assets |
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|
36,679 |
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(20,548 |
) |
Accounts payable |
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|
7,638 |
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|
5,791 |
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Accrued and other current liabilities |
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|
10,790 |
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(3,912 |
) |
Other non-current assets |
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2,792 |
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|
533 |
|
Other non-current liabilities |
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|
3,706 |
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1,812 |
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Total adjustments from operating activities |
|
|
126,076 |
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|
94,728 |
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Net cash provided by operating activities |
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|
233,779 |
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|
102,577 |
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Cash flows from investing activities: |
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Capital expenditures |
|
|
(27,572 |
) |
|
|
(39,819 |
) |
Contributions to equity investments |
|
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|
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|
|
(3,880 |
) |
Net proceeds from disposal of property, plant and equipment |
|
|
22,274 |
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|
21 |
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Net cash used in investing activities |
|
|
(5,298 |
) |
|
|
(43,678 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
Net proceeds from issuance of limited partner units |
|
|
|
|
|
|
104,779 |
|
Proceeds from exercise of limited partner unit options |
|
|
2,976 |
|
|
|
38 |
|
Borrowings under credit facility |
|
|
95,000 |
|
|
|
77,333 |
|
Repayments under credit facility |
|
|
(173,000 |
) |
|
|
(166,600 |
) |
Net (repayments) borrowings under BES credit agreement |
|
|
(45,621 |
) |
|
|
3,000 |
|
Debt issuance costs |
|
|
(3,227 |
) |
|
|
(18 |
) |
Costs associated with agreement and plan of merger |
|
|
(1,341 |
) |
|
|
|
|
Distributions paid to noncontrolling interests |
|
|
(2,503 |
) |
|
|
(2,713 |
) |
Distributions paid to partners |
|
|
(122,851 |
) |
|
|
(111,564 |
) |
|
|
|
|
|
|
|
Net cash used in financing activities |
|
|
(250,567 |
) |
|
|
(95,745 |
) |
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents |
|
|
(22,086 |
) |
|
|
(36,846 |
) |
Cash and cash equivalents Beginning of period |
|
|
34,599 |
|
|
|
58,843 |
|
|
|
|
|
|
|
|
Cash and cash equivalents End of period |
|
$ |
12,513 |
|
|
$ |
21,997 |
|
|
|
|
|
|
|
|
See Notes to Unaudited Condensed Consolidated Financial Statements.
5
BUCKEYE PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS CAPITAL (DEFICIT)
(In thousands)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Buckeye Partners, L.P. Unitholders |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
General |
|
|
Limited |
|
|
Comprehensive |
|
|
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 (loss) |
|
|
23,121 |
|
|
|
(17,732 |
) |
|
|
|
|
|
|
2,460 |
|
|
|
7,849 |
|
Change in value of derivatives |
|
|
|
|
|
|
|
|
|
|
543 |
|
|
|
|
|
|
|
543 |
|
Amortization of interest rate swaps |
|
|
|
|
|
|
|
|
|
|
480 |
|
|
|
|
|
|
|
480 |
|
Adjustment to funded status of
benefit plans |
|
|
|
|
|
|
|
|
|
|
7,970 |
|
|
|
|
|
|
|
7,970 |
|
Amortization of benefit plan costs |
|
|
|
|
|
|
|
|
|
|
(358 |
) |
|
|
|
|
|
|
(358 |
) |
Distributions paid to partners |
|
|
(22,407 |
) |
|
|
(89,157 |
) |
|
|
|
|
|
|
|
|
|
|
(111,564 |
) |
Distributions paid to
noncontrolling interests |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,713 |
) |
|
|
(2,713 |
) |
Net proceeds from the issuance of
limited partner units |
|
|
|
|
|
|
104,779 |
|
|
|
|
|
|
|
|
|
|
|
104,779 |
|
Amortization of unit-based
compensation awards |
|
|
|
|
|
|
477 |
|
|
|
|
|
|
|
|
|
|
|
477 |
|
Exercise of limited partner unit options |
|
|
|
|
|
|
38 |
|
|
|
|
|
|
|
|
|
|
|
38 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance June 30, 2009 |
|
$ |
(5,966 |
) |
|
$ |
1,199,549 |
|
|
$ |
(10,332 |
) |
|
$ |
20,522 |
|
|
$ |
1,203,773 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance January 1, 2010 |
|
$ |
1,849 |
|
|
$ |
1,214,136 |
|
|
$ |
(847 |
) |
|
$ |
20,957 |
|
|
$ |
1,236,095 |
|
Net income |
|
|
25,292 |
|
|
|
78,828 |
|
|
|
|
|
|
|
3,583 |
|
|
|
107,703 |
|
Costs associated with
agreement and plan of merger |
|
|
|
|
|
|
(1,846 |
) |
|
|
|
|
|
|
|
|
|
|
(1,846 |
) |
Change in value of derivatives |
|
|
|
|
|
|
|
|
|
|
(36,600 |
) |
|
|
|
|
|
|
(36,600 |
) |
Amortization of interest rate swaps |
|
|
|
|
|
|
|
|
|
|
482 |
|
|
|
|
|
|
|
482 |
|
Amortization of benefit plan costs |
|
|
|
|
|
|
|
|
|
|
(568 |
) |
|
|
|
|
|
|
(568 |
) |
Distributions paid to partners |
|
|
(25,379 |
) |
|
|
(97,472 |
) |
|
|
|
|
|
|
|
|
|
|
(122,851 |
) |
Distributions paid to
noncontrolling interests |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,503 |
) |
|
|
(2,503 |
) |
Non-cash accrual for distribution
equivalent rights |
|
|
|
|
|
|
(563 |
) |
|
|
|
|
|
|
|
|
|
|
(563 |
) |
Amortization of unit-based
compensation awards |
|
|
|
|
|
|
3,596 |
|
|
|
|
|
|
|
|
|
|
|
3,596 |
|
Exercise of limited partner unit options |
|
|
|
|
|
|
2,976 |
|
|
|
|
|
|
|
|
|
|
|
2,976 |
|
Other |
|
|
|
|
|
|
(6 |
) |
|
|
|
|
|
|
|
|
|
|
(6 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance June 30, 2010 |
|
$ |
1,762 |
|
|
$ |
1,199,649 |
|
|
$ |
(37,533 |
) |
|
$ |
22,037 |
|
|
$ |
1,185,915 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 June 30, 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.
Agreement and Plan of Merger
On June 10, 2010, we and our general partner entered into an Agreement and Plan of Merger (the
Merger Agreement) with BGH, its general partner and Grand Ohio, LLC (Merger Sub), our
subsidiary, pursuant to which Merger Sub will be merged into BGH, with BGH as the surviving entity
(the Merger). In the transaction, the incentive compensation agreement (also referred to as the
incentive distribution rights) held by our general partner will be cancelled, the general partner
units held by our general partner (representing an approximate 0.5% general partner interest in us)
will be converted to a non-economic general partner interest, all of the economic interest in BGH
will be acquired by us and BGH unitholders will receive aggregate consideration of approximately
20.0 million of our LP Units.
The terms of the Merger Agreement were unanimously approved by the audit committee of the
board of directors of our general partner (Audit Committee), and by the board of directors of
BGHs general partner. Additionally, the majority unitholder of BGH, BGH GP Holdings, LLC, and
ArcLight Energy Partners Fund III, L.P., ArcLight Energy Partners Fund IV, L.P., Kelso Investment
Associates VII, L.P., and KEP VI, LLC have executed a Support Agreement (Support Agreement)
agreeing to vote in favor of the Merger and against any alternative transaction. The Support
Agreement will automatically terminate if the board of directors of the general partner of BGH
changes its recommendation to BGHs unitholders with respect to the Merger or the Merger Agreement
is terminated.
7
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
After the Merger, the board of directors of our general partner is expected to consist of nine
members, three of whom are expected to be the existing independent members of our Audit Committee, one of whom
is expected to be the existing chief executive officer of our general partner and three of whom are
expected to be the three existing independent members of the audit committee of the board of directors of BGHs
general partner. In addition, BGHs general partner, which will own a non-economic general partner
interest in BGH and will continue to be owned by BGH GP Holdings, LLC, will have the right and
authority to designate two additional members of the board of directors, subject to reduction if
BGH GP Holdings, LLCs ownership of our LP Units drops below certain thresholds. The remaining
seven members of our general partners board of directors will be elected by holders of our LP
Units.
The Merger Agreement is subject to, among other things, approval by the affirmative vote of
the holders of a majority of our LP Units outstanding and entitled to vote at a meeting of the
holders of our LP Units, approval by the (a) affirmative vote of holders of a majority of BGHs
common units and (b) affirmative vote of holders of a majority of BGHs common units and management
units, voting together as a single class, and the effectiveness of a registration statement on Form
S-4 with respect to the issuance of the LP Units in connection with the Merger.
The Merger will be accounted for as an equity transaction. Therefore, changes in BGHs
ownership interest as a result of the Merger will not result in gain or loss recognition. BGH will
be considered the surviving consolidated entity for accounting purposes, while we will be the
surviving consolidated entity for legal and reporting purposes.
We incurred $1.8 million of costs associated with the Merger during the three and six months
ended June 30, 2010, of which $1.3 million has been paid. We charged these costs directly to
partners capital.
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 June 30, 2010, and the results of our operations and
cash flows for the periods presented. The results of operations for the three and six months ended
June 30, 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.
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 reclassification in the condensed consolidated statements of operations is as
follows:
|
|
|
Earnings from equity investments are now presented on a separate line item in the
condensed consolidated statements of operations for the three and six months ended June
30, 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 reclassification in the condensed consolidated statements of cash flows is as follows:
|
|
|
We have separately disclosed cash flows from the issuance of long-term debt and
borrowings under our credit facility for the six months ended June 30, 2009. These
amounts had been included within the same line item in the 2009 period. |
These reclassifications had no impact on net income (loss) or cash flows from operating,
investing or financing activities.
8
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 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 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 and six months ended June 30, 2009 were
$3.2 million and $6.5 million, respectively.
9
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
3. COMMITMENTS AND CONTINGENCIES
Claims and Proceedings
In the ordinary course of business, we are involved in various claims and legal proceedings,
some of which are covered by insurance. We are generally unable to predict the timing or outcome of
these claims and proceedings. Based upon our evaluation of existing claims and proceedings and the
probability of losses relating to such contingencies, we have accrued certain amounts relating to
such claims and proceedings, none of which are considered material.
In 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 are contesting the
proposed penalty. The timing or outcome of this appeal cannot reasonably be determined at this
time.
On July
30, 2010, a putative class action was filed by a unitholder against BGH, MainLine Management
LLC (MainLine Management), BGH GP Holdings, LLC (BGH GP), and each of MainLine Managements
directors in the District Court of Harris County, Texas under the
caption Broadbased
Equities v. Forrest E. Wylie, et. al. In the Petition, the plaintiff alleges that MainLine
Management and its directors breached their fiduciary duties to BGHs public unitholders by,
among other things, acting to facilitate the sale of BGH to Buckeye in order to facilitate
the gradual sale by BGH GP of its interest in BGH and failing to disclose all material facts
in order that the BGH unitholders can cast an informed vote on the Merger Agreement. Among
other things, the Petition seeks an order certifying a class consisting of all BGH
unitholders, a determination that the action is a proper derivative action, damages
in an unspecified amount, and an award of attorneys fees and costs. The defendants
have not yet answered or otherwise responded to the Petition.
On August
2, 2010, a putative class action was filed by a unitholder against BGH, MainLine Management,
Grand Ohio, LLC, Buckeye, Buckeye GP, and each of MainLine Managements directors in the
District Court of Harris County, Texas under the caption Henry James Steward v. Forrest
E. Wylie, et. al. In the Petition, the plaintiff alleges that MainLine Management and
its directors breached their fiduciary duties to BGHs public unitholders by, among other
things, failing to disclose all material facts in order that the BGH unitholders can cast
an informed vote on the Merger Agreement. The Petition also alleges that Buckeye,
Buckeye GP and Grand Ohio, LLC aided and abetted the breaches of fiduciary duty. Among
other things, the Petition seeks an order certifying a plaintiff class consisting of
all of BGH unitholders, an order enjoining the Merger, rescission of the Merger, damages
in an unspecified amount, and an award of attorneys fees and costs. Neither we nor the
other defendants have yet answered or otherwise responded to the Petition.
On August
2, 2010, a putative class action was filed by a unitholder against BGH, MainLine Management,
BGH GP, ArcLight Capital Partners, LLC (ArcLight), Kelso & Company (Kelso), Buckeye,
Buckeye GP, and each of MainLine Managements directors, in the District Court of Harris
County, Texas under the caption Henry James Steward v. Forrest E. Wylie, et. al. In the
Petition, the plaintiff alleges that MainLine Management and its directors breached their
fiduciary duties to BGHs public unitholders by, among other things, accepting insufficient
consideration, failing to condition the Merger on a majority vote of public unitholders of
BGH, and failing to disclose all material facts in order that the BGH unitholders can cast
an informed vote on the Merger Agreement. The Petition also alleges that Buckeye, Buckeye
GP, BGH GP, ArcLight, and Kelso aided and abetted the breaches of fiduciary duty. Among
other things, the Petition seeks an order certifying a class consisting of all of BGHs
unitholders, an order enjoining the Merger, damages in an unspecified amount, and an award
of attorneys fees and costs. Neither we nor the other defendants have yet answered or
otherwise responded to the Petition.
Environmental Contingencies
In accordance with our accounting policy, we recorded operating expenses, net of insurance
recoveries, of $2.5 million and $1.2 million during the three months ended June 30, 2010 and 2009,
respectively, and $5.4 million and $6.6 million during the six months ended June 30, 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.
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
out of pocket 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.
10
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Customer Bankruptcy
One of our customers filed for bankruptcy in October 2009; approximately $4.2 million remained
payable to us from the customer pursuant to a pre-bankruptcy contract. In June 2010, we entered
into a settlement with the bankrupt customer and its largest creditor pursuant to which we expect
to be paid at least $2.0 million upon the sale of certain of the customers assets within the
bankruptcy proceedings, and we were released from both asserted and unasserted claims. At this
time, we expect the sale of the assets to be completed, and the settlement payment to be made to
us, in the third quarter of 2010. As a result of the settlement, our Development & Logistics
segment recognized approximately $2.1 million in expense related to the write-off of a portion of
the outstanding receivable balance during the three and six months ended June 30, 2010.
4. INVENTORIES
Our inventory amounts were as follows at the dates indicated:
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
Refined petroleum products (1) |
|
$ |
264,638 |
|
|
$ |
299,473 |
|
Materials and supplies |
|
|
10,536 |
|
|
|
10,741 |
|
|
|
|
|
|
|
|
Total inventories |
|
$ |
275,174 |
|
|
$ |
310,214 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Ending inventory was 130.4 million and 141.7 million gallons of refined petroleum
products at June 30, 2010 and December 31, 2009, respectively. |
At June 30, 2010 and December 31, 2009, approximately 95% 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.
5. PREPAID AND OTHER CURRENT ASSETS
Prepaid and other current assets consist of the following at the dates indicated:
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
Prepaid insurance |
|
$ |
2,226 |
|
|
$ |
6,916 |
|
Insurance receivables |
|
|
11,238 |
|
|
|
13,544 |
|
Ammonia receivable |
|
|
1,690 |
|
|
|
7,429 |
|
Margin deposits |
|
|
7,921 |
|
|
|
21,037 |
|
Prepaid services |
|
|
21,742 |
|
|
|
21,571 |
|
Unbilled revenue |
|
|
2,469 |
|
|
|
13,201 |
|
Tax receivable |
|
|
7,162 |
|
|
|
7,162 |
|
Prepaid taxes |
|
|
4,001 |
|
|
|
2,213 |
|
Other |
|
|
9,172 |
|
|
|
10,618 |
|
|
|
|
|
|
|
|
Total prepaid and other current assets |
|
$ |
67,621 |
|
|
$ |
103,691 |
|
|
|
|
|
|
|
|
11
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
Ownership |
|
|
2010 |
|
|
2009 |
|
Muskegon Pipeline LLC |
|
|
40.0 |
% |
|
$ |
14,514 |
|
|
$ |
15,273 |
|
Transport4, LLC |
|
|
25.0 |
% |
|
|
373 |
|
|
|
379 |
|
West Shore Pipe Line Company |
|
|
24.9 |
% |
|
|
30,526 |
|
|
|
30,320 |
|
West Texas LPG Pipeline Limited Partnership |
|
|
20.0 |
% |
|
|
53,155 |
|
|
|
50,879 |
|
|
|
|
|
|
|
|
|
|
|
|
Total equity investments |
|
|
|
|
|
$ |
98,568 |
|
|
$ |
96,851 |
|
|
|
|
|
|
|
|
|
|
|
|
The following table presents earnings from equity investments for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
Muskegon Pipeline LLC |
|
$ |
227 |
|
|
$ |
173 |
|
|
$ |
571 |
|
|
$ |
538 |
|
Transport4, LLC |
|
|
30 |
|
|
|
40 |
|
|
|
69 |
|
|
|
70 |
|
West Shore Pipe Line Company |
|
|
1,294 |
|
|
|
1,094 |
|
|
|
2,501 |
|
|
|
2,197 |
|
West Texas LPG Pipeline Limited Partnership |
|
|
1,213 |
|
|
|
1,835 |
|
|
|
2,275 |
|
|
|
2,419 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total earnings from equity investments |
|
$ |
2,764 |
|
|
$ |
3,142 |
|
|
$ |
5,416 |
|
|
$ |
5,224 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7. INTANGIBLE ASSETS
Intangible assets consist of the following at the dates indicated:
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
Customer relationships |
|
$ |
38,300 |
|
|
$ |
38,300 |
|
Accumulated amortization |
|
|
(7,115 |
) |
|
|
(5,631 |
) |
|
|
|
|
|
|
|
Net carrying amount |
|
|
31,185 |
|
|
|
32,669 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer contracts |
|
|
16,380 |
|
|
|
16,380 |
|
Accumulated amortization |
|
|
(4,634 |
) |
|
|
(3,892 |
) |
|
|
|
|
|
|
|
Net carrying amount |
|
|
11,746 |
|
|
|
12,488 |
|
|
|
|
|
|
|
|
Total intangible assets |
|
$ |
42,931 |
|
|
$ |
45,157 |
|
|
|
|
|
|
|
|
For the three months ended June 30, 2010 and 2009, amortization expense related to intangible
assets was $1.1 million and $0.9 million, respectively. For the six months ended June 30, 2010 and
2009, amortization expense related to intangible assets was $2.2 million and $1.8 million,
respectively. Amortization expense related to intangible assets is expected to be approximately
$4.5 million for each of the next five years.
12
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
8. OTHER NON-CURRENT ASSETS
Other non-current assets consist of the following at the dates indicated:
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
Deferred charge, net (1) |
|
$ |
3,675 |
|
|
$ |
6,024 |
|
Prepaid services |
|
|
8,065 |
|
|
|
11,640 |
|
Derivative assets |
|
|
|
|
|
|
17,204 |
|
Debt issuance costs |
|
|
12,459 |
|
|
|
11,058 |
|
Insurance receivables |
|
|
7,530 |
|
|
|
7,265 |
|
Other |
|
|
9,969 |
|
|
|
9,586 |
|
|
|
|
|
|
|
|
Total other non-current assets |
|
$ |
41,698 |
|
|
$ |
62,777 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Net of accumulated amortization of $61.7 million and $58.2 million at June 30, 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. |
9. ACCRUED AND OTHER CURRENT LIABILITIES
Accrued and other current liabilities consist of the following at the dates indicated:
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
Taxes - other than income |
|
$ |
16,201 |
|
|
$ |
15,381 |
|
Accrued charges due Buckeye GP |
|
|
694 |
|
|
|
1,218 |
|
Accrued charges due Services Company |
|
|
2,829 |
|
|
|
6,104 |
|
Accrued employee benefit liability |
|
|
3,287 |
|
|
|
3,287 |
|
Environmental liabilities |
|
|
11,549 |
|
|
|
10,799 |
|
Accrued interest |
|
|
30,695 |
|
|
|
30,609 |
|
Payable for ammonia purchase |
|
|
1,803 |
|
|
|
7,015 |
|
Deferred revenue |
|
|
20,306 |
|
|
|
6,829 |
|
Accrued capital expenditures |
|
|
425 |
|
|
|
1,611 |
|
Reorganization |
|
|
|
|
|
|
2,133 |
|
Deferred consideration |
|
|
2,010 |
|
|
|
1,675 |
|
Other |
|
|
27,104 |
|
|
|
20,082 |
|
|
|
|
|
|
|
|
Total accrued and other current liabilities |
|
$ |
116,903 |
|
|
$ |
106,743 |
|
|
|
|
|
|
|
|
13
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
10. DEBT OBLIGATIONS
Long-term debt consists of the following at the dates indicated:
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
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 |
|
|
|
|
|
|
78,000 |
|
BES Credit Agreement |
|
|
194,179 |
|
|
|
239,800 |
|
|
|
|
|
|
|
|
Total debt |
|
|
1,619,179 |
|
|
|
1,742,800 |
|
Less: Unamortized discount |
|
|
(4,525 |
) |
|
|
(4,854 |
) |
Adjustment associated with fair value hedges |
|
|
706 |
|
|
|
824 |
|
|
|
|
|
|
|
|
Subtotal debt |
|
|
1,615,360 |
|
|
|
1,738,770 |
|
Less: Current portion of long-term debt |
|
|
(194,179 |
) |
|
|
(239,800 |
) |
|
|
|
|
|
|
|
Total long-term debt |
|
$ |
1,421,181 |
|
|
$ |
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 $1,672.6
million and $1,762.1 million at June 30, 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 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 June
30, 2010, no amounts were outstanding under the Credit Facility, while at December 31, 2009, $78.0
million was outstanding under the Credit Facility.
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 June 30, 2010, our Funded Debt Ratio
was approximately 3.86 to 1.00. As permitted by the Credit Facility,
the $194.2 million of borrowings by Buckeye Energy Services
LLC (BES) under its separate credit agreement (discussed below) was excluded from the
calculation of the Funded Debt Ratio.
14
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 June 30, 2010, we were not aware of any instances of noncompliance with the covenants
under our Credit Facility.
At June 30, 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 had a credit agreement (the BES Credit Agreement) that provided for borrowings of up to
$250.0 million with a maturity date of May 20, 2011. On June 25, 2010, BES amended and restated
the BES Credit Agreement to increase the total commitments for borrowings available to BES up to
$500.0 million. However, the maximum amount available to be borrowed under the amended and
restated BES Credit Agreement is initially limited to $350.0 million. An accordion feature
provides BES the ability to increase the commitments under the BES Credit Agreement to $500.0
million, subject to obtaining the requisite commitments and satisfying other customary conditions.
In addition to the accordion, subject to BESs satisfaction of certain financial covenants as set
forth in the financial covenants table below, BES may, from time to time, elect to increase or
decrease the maximum amount available for borrowing under the BES Credit Agreement in $5.0 million
increments, but in no event below $150.0 million or above $500.0 million. The maturity date of the
BES Credit Agreement is June 25, 2013. BES incurred $3.2 million of debt issuance costs related to
the amendment, which will be amortized into interest expense over the term of the BES Credit
Agreement.
Under the BES Credit Agreement, borrowings accrue interest under one of three rate options, at
BESs election, equal to (i) the Administrative Agents Cost of Funds (as defined in the BES Credit
Agreement) plus 2.25%, (ii) the Eurodollar Rate (as defined in the BES Credit Agreement) plus 2.25%
or (iii) the Prime Rate (as defined in the BES Credit Agreement) plus 1.25%. The BES Credit
Agreement also permits Daylight Overdraft Loans (as defined in the BES Credit Agreement), Swingline
Loans (as defined in the BES Credit Agreement) and letters of credit. Such alternative extensions
of credit are subject to certain conditions as specified in the BES Credit Agreement. The BES
Credit Agreement is secured by liens on certain assets of BES, including its inventory, cash
deposits (other than certain accounts), investments and hedging accounts, receivables and
intangibles.
The balances outstanding under the BES Credit Agreement were approximately $194.2 million and
$239.8 million at June 30, 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 |
|
Above $250 up to $300 |
|
$ |
72 |
|
|
$ |
60 |
|
|
|
7.0 to 1.0 |
|
Above $300 up to $350 |
|
$ |
84 |
|
|
$ |
70 |
|
|
|
7.0 to 1.0 |
|
Above $350 up to $400 |
|
$ |
96 |
|
|
$ |
80 |
|
|
|
7.0 to 1.0 |
|
Above $400 up to $450 |
|
$ |
108 |
|
|
$ |
90 |
|
|
|
7.0 to 1.0 |
|
Above $450 up to $500 |
|
$ |
120 |
|
|
$ |
100 |
|
|
|
7.0 to 1.0 |
|
15
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
At June 30, 2010, BESs Consolidated Tangible Net Worth and Consolidated Net Working Capital
were $121.3 million and $71.5 million, respectively, and the Consolidated Leverage Ratio was 2.3 to
1.0. The weighted average interest rate for borrowings outstanding under the BES Credit Agreement
was 2.5% at June 30, 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 June 30, 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:
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
Accrued employee benefit liabilities (see Note 14) |
|
$ |
45,799 |
|
|
$ |
45,837 |
|
Accrued environmental liabilities |
|
|
18,891 |
|
|
|
19,053 |
|
Deferred consideration |
|
|
17,420 |
|
|
|
18,425 |
|
Derivative liabilities |
|
|
18,953 |
|
|
|
|
|
Deferred rent |
|
|
11,275 |
|
|
|
9,158 |
|
Deferred revenue |
|
|
7,082 |
|
|
|
1,532 |
|
Other |
|
|
8,207 |
|
|
|
8,846 |
|
|
|
|
|
|
|
|
Total other non-current liabilities |
|
$ |
127,627 |
|
|
$ |
102,851 |
|
|
|
|
|
|
|
|
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:
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
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 |
|
|
(7,271 |
) |
|
|
(7,753 |
) |
Derivative instruments |
|
|
(19,099 |
) |
|
|
17,501 |
|
Accumulated amortization of retirement income guarantee
plan and retiree medical plan |
|
|
(6,710 |
) |
|
|
(6,142 |
) |
|
|
|
|
|
|
|
Total accumulated other comprehensive loss |
|
$ |
(37,533 |
) |
|
$ |
(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.
16
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Our policy is to formally document all relationships between hedging instruments and hedged
items, as well as our risk management objectives and strategies for undertaking the hedge. This
process includes specific identification of the hedging instrument and the hedged transaction, the
nature of the risk being hedged and how the hedging instruments effectiveness will be assessed.
Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives used
in a transaction are highly effective in offsetting changes in cash flows or the fair value of
hedged items. A discussion of our derivative activities by risk category follows.
Interest Rate Derivatives
We utilize forward-starting interest rate swaps to manage interest rate risk related to
forecasted interest payments on anticipated debt issuances. This strategy is a component in
controlling our cost of capital associated with such borrowings. When entering into interest rate
swap transactions, we become exposed to both credit risk and market risk. We are subject to credit
risk when the value of the swap transaction is positive and the risk exists that the counterparty
will fail to perform under the terms of the contract. We are subject to market risk with respect
to changes in the underlying benchmark interest rate that impacts the fair value of the swaps. We
manage our credit risk by only entering into swap transactions with major financial institutions
with investment-grade credit ratings. We manage our market risk by associating each swap
transaction with an existing debt obligation or a specified expected debt issuance generally
associated with the maturity of an existing debt obligation.
Our practice with respect to derivative transactions related to interest rate risk has been to
have each transaction in connection with non-routine borrowings authorized by the board of
directors of Buckeye GP. In January 2009, Buckeye GPs board of directors adopted an interest rate
hedging policy which permits us to enter into certain short-term interest rate swap agreements to
manage our interest rate and cash flow risks associated with the Credit Facility. In addition, in
July 2009 and May 2010, Buckeye GPs board of directors authorized us to enter into certain
transactions, such as forward-starting interest rate swaps, to manage our interest rate and cash
flow risks related to certain expected debt issuances associated with the maturity of existing debt
obligations.
We expect to issue new fixed-rate debt (i) on or before July 15, 2013 to repay the $300.0
million of 4.625% Notes that are due on July 15, 2013 and (ii) on or before October 15, 2014 to
repay the $275.0 million of 5.300% Notes that are due on October 15, 2014, although no assurances
can be given that the issuance of fixed-rate debt will be possible on acceptable terms. 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. During the three months
ended June 30, 2010, we entered into two forward-starting interest rate swaps with a total
aggregate notional amount of $100.0 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 $125.0 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 and six months ended June 30, 2010, unrealized losses of
$34.9 million and $36.2 million, respectively, were recorded in accumulated other comprehensive
income (loss) to reflect the change in the fair values of the forward-starting interest rate swaps.
We designated the swap agreements as cash flow hedges at inception and expect the changes in
values to be highly correlated with the changes in value of the underlying borrowings.
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 forward-starting
interest rate swaps terminated 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
17
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 condensed consolidated
balance sheets with gains and losses being recognized in earnings during the period.
In order to hedge the cost of natural gas used to operate our turbine engines at our Linden,
New Jersey location, our 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
(through July 2011). We designated the futures contract as a cash flow hedge at inception.
The following table summarizes our commodity derivative instruments outstanding at June 30,
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 |
|
|
29,050 |
|
|
|
168 |
|
|
Mark-to-market |
Futures contracts for fixed-price sales contracts |
|
|
24,612 |
|
|
|
168 |
|
|
Mark-to-market |
Futures contracts for inventory |
|
|
2,777 |
|
|
|
|
|
|
Mark-to-market |
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives designated as hedging
instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
Futures contracts for inventory |
|
|
123,522 |
|
|
|
|
|
|
Fair Value Hedge |
Futures contracts for natural gas (BBtu) |
|
|
360 |
|
|
|
30 |
|
|
Cash Flow Hedge |
|
|
|
(1) |
|
Volume represents net notional position. |
|
(2) |
|
The maximum term for derivatives included in the long-term column is October 2011. |
|
(3) |
|
BBtu represents one billion British thermal units. |
18
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table sets forth the fair value of each classification of derivative instruments
at the dates indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 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 |
|
$ |
5,213 |
|
|
$ |
(258 |
) |
|
$ |
4,955 |
|
|
$ |
4,959 |
|
|
$ |
(3,662 |
) |
|
$ |
1,297 |
|
Futures contracts for fixed-
price sales contracts |
|
|
1,492 |
|
|
|
(1,806 |
) |
|
|
(314 |
) |
|
|
7,594 |
|
|
|
(384 |
) |
|
|
7,210 |
|
Futures contracts for
inventory |
|
|
3,336 |
|
|
|
(3,457 |
) |
|
|
(121 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives designated as hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Futures contracts for inventory |
|
|
8,094 |
|
|
|
(2,748 |
) |
|
|
5,346 |
|
|
|
1,992 |
|
|
|
(20,517 |
) |
|
|
(18,525 |
) |
Futures contracts for
natural gas |
|
|
|
|
|
|
(140 |
) |
|
|
(140 |
) |
|
|
312 |
|
|
|
|
|
|
|
312 |
|
Interest rate contracts |
|
|
|
|
|
|
(18,953 |
) |
|
|
(18,953 |
) |
|
|
17,204 |
|
|
|
|
|
|
|
17,204 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
|
|
|
|
|
|
$ |
(9,227 |
) |
|
|
|
|
|
|
|
|
|
$ |
7,498 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Locations: |
|
2010 |
|
|
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative assets |
|
$ |
10,093 |
|
|
$ |
4,959 |
|
Other non-current assets |
|
|
|
|
|
|
17,204 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative liabilities |
|
|
(367 |
) |
|
|
(14,665 |
) |
Other non-current liabilities |
|
|
(18,953 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
(9,227 |
) |
|
$ |
7,498 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our hedged inventory portfolio extends to the first quarter of 2011. The majority of the
unrealized income of $5.2 million at June 30, 2010 for inventory hedges represented by futures
contracts will be realized by the third quarter of 2010 as the related inventory is sold. Gains
recorded on inventory hedges that were ineffective were approximately $1.0 million and $3.3 million
for the three months ended June 30, 2010 and 2009, respectively. For the six months ended June 30,
2010 and 2009, gains recorded on inventory hedges that were ineffective were approximately $5.8
million and $7.6 million, respectively. At June 30, 2010, open refined petroleum product
derivative contracts (represented by the fixed-price sales contracts and futures contracts for
fixed-price sales contracts noted above) varied in duration, but did not extend beyond October
2011. In addition, at June 30, 2010, we had refined petroleum product inventories which we intend
to use to satisfy a portion of the fixed-price sales contracts.
19
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The gains and losses on our derivative instruments recognized in income were as follows for
the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (Loss) Recognized in Income on Derivatives |
|
|
|
|
|
|
Three Months Ended |
|
Six Months Ended |
|
|
|
|
|
|
June 30, |
|
June 30, |
|
|
Location |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
Derivatives NOT designated as
hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed-price sales contracts |
|
Product sales |
|
$ |
6,268 |
|
|
$ |
(13,866 |
) |
|
$ |
8,678 |
|
|
$ |
(571 |
) |
Futures contracts for fixed-price sales contracts |
|
Cost of product sales and natural gas storage services |
|
|
(2,972 |
) |
|
|
19,007 |
|
|
|
(3,466 |
) |
|
|
11,461 |
|
Futures contracts for inventory |
|
Cost of product sales and natural gas storage services |
|
|
20 |
|
|
|
|
|
|
|
266 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives designated as fair
value hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Futures contracts for inventory |
|
Cost of product sales and natural gas storage services |
|
$ |
18,123 |
|
|
$ |
(31,251 |
) |
|
$ |
13,213 |
|
|
$ |
(3,603 |
) |
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 |
|
Six Months Ended |
|
|
|
|
|
|
June 30, |
|
June 30, |
|
|
Location |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
Derivatives designated as cash
flow hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Futures contracts for natural gas |
|
Cost of product sales and natural gas storage services |
|
$ |
(96 |
) |
|
$ |
(162 |
) |
|
$ |
(168 |
) |
|
$ |
(215 |
) |
Futures contracts for refined petroleum products |
|
Cost of product sales and natural gas storage services |
|
|
|
|
|
|
(379 |
) |
|
|
|
|
|
|
(146 |
) |
Interest rate contracts |
|
Interest and debt expense |
|
|
(242 |
) |
|
|
(164 |
) |
|
|
(482 |
) |
|
|
(656 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in Value Recognized in OCI on Derivatives |
|
|
Three Months Ended |
|
Six Months Ended |
|
|
June 30, |
|
June 30, |
|
|
2010 |
|
2009 |
|
2010 |
|
2009 |
Derivatives designated as cash
flow hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Futures contracts for natural gas |
|
$ |
85 |
|
|
$ |
46 |
|
|
$ |
(611 |
) |
|
$ |
163 |
|
Interest rate contracts |
|
|
(34,853 |
) |
|
|
(158 |
) |
|
|
(36,157 |
) |
|
|
(157 |
) |
20
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. |
21
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, June 30, 2010 and December 31, 2009, and the basis
for that measurement, by level within the fair value hierarchy:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 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 |
|
$ |
|
|
|
$ |
5,121 |
|
|
$ |
|
|
|
$ |
4,959 |
|
Futures contracts for inventory
and fixed-price sales contracts |
|
|
4,973 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset held in trust |
|
|
|
|
|
|
|
|
|
|
1,793 |
|
|
|
|
|
Interest rate derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17,204 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed-price sales contracts |
|
|
|
|
|
|
(166 |
) |
|
|
|
|
|
|
(3,662 |
) |
Futures contracts for inventory
and fixed-price sales contracts |
|
|
(202 |
) |
|
|
|
|
|
|
(11,003 |
) |
|
|
|
|
Interest rate derivatives |
|
|
|
|
|
|
(18,953 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
4,771 |
|
|
$ |
(13,998 |
) |
|
$ |
(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 derivatives was based on observable market data related to similar obligations.
The Level 2 derivative assets of $5.1 million and $5.0 million as of June 30, 2010 and
December 31, 2009, respectively, are net of a credit valuation adjustment (CVA) of ($0.6) million
and ($0.9) million, respectively. 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.
22
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Non-Recurring
Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis
and are subject to fair value adjustments in certain circumstances, such as when there is evidence
of impairment. The following table presents the fair value of an asset carried on the condensed
consolidated balance sheet by asset classification and by level within the valuation hierarchy (as
described above) at the date indicated for which a nonrecurring change in fair value has been
recorded during the three and six months ended June 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
2009 |
|
Level 1 |
|
Level 2 |
|
Level 3 |
|
Losses |
Assets held for sale (1) |
|
$ |
5,760 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
5,760 |
|
|
$ |
72,540 |
|
|
|
|
(1) |
|
Represents net assets held for sale that were included in prepaid and other current assets at
June 30, 2009 (see Note 2). |
As a result of a loss in the customer base utilizing the Buckeye NGL Pipeline, we recorded a
non-cash impairment charge of $72.5 million during the three and six months ended June 30, 2009.
The estimated fair value was based on a probability-weighted combination of income and market
approaches.
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 three months ended June 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RIGP |
|
|
Retiree Medical Plan |
|
|
|
Three Months Ended |
|
|
Three Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
Service cost |
|
$ |
65 |
|
|
$ |
207 |
|
|
$ |
117 |
|
|
$ |
105 |
|
Interest cost |
|
|
227 |
|
|
|
369 |
|
|
|
786 |
|
|
|
491 |
|
Expected return on plan assets |
|
|
(86 |
) |
|
|
(189 |
) |
|
|
|
|
|
|
|
|
Amortization of prior service benefit |
|
|
(11 |
) |
|
|
(118 |
) |
|
|
(1,175 |
) |
|
|
(859 |
) |
Amortization of unrecognized losses |
|
|
242 |
|
|
|
355 |
|
|
|
354 |
|
|
|
261 |
|
Settlement/curtailment charge (1) |
|
|
|
|
|
|
7,171 |
|
|
|
|
|
|
|
800 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit costs |
|
$ |
437 |
|
|
$ |
7,795 |
|
|
$ |
82 |
|
|
$ |
798 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
In connection with our reorganization in 2009, $8.0 million of the aggregate amount of $28.1
million of expenses incurred through June 30, 2009 was recorded as an adjustment to the funded
status of the RIGP and the Retiree Medical Plan, which represent settlement and curtailment
adjustments. |
23
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The components of the net periodic benefit cost for the RIGP and Retiree Medical
Plan were as follows for the six months ended June 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RIGP |
|
|
Retiree Medical Plan |
|
|
|
Six Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
Service cost |
|
$ |
133 |
|
|
$ |
415 |
|
|
$ |
147 |
|
|
$ |
210 |
|
Interest cost |
|
|
459 |
|
|
|
740 |
|
|
|
991 |
|
|
|
983 |
|
Expected return on plan assets |
|
|
(174 |
) |
|
|
(380 |
) |
|
|
|
|
|
|
|
|
Amortization of prior service benefit |
|
|
(23 |
) |
|
|
(235 |
) |
|
|
(1,482 |
) |
|
|
(1,719 |
) |
Amortization of unrecognized losses |
|
|
490 |
|
|
|
712 |
|
|
|
447 |
|
|
|
522 |
|
Settlement/curtailment charge (1) |
|
|
|
|
|
|
7,171 |
|
|
|
|
|
|
|
800 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit costs |
|
$ |
885 |
|
|
$ |
8,423 |
|
|
$ |
103 |
|
|
$ |
796 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
In connection with our reorganization in 2009, $8.0 million of the aggregate amount of $28.1
million of expenses incurred through June 30, 2009 was recorded as an adjustment to the funded
status of the RIGP and the Retiree Medical Plan, which represent settlement and curtailment
adjustments. |
During the six months ended June 30, 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 LTIP), which became effective in March 2009. We
formerly awarded options to acquire LP Units to employees pursuant to the Buckeye Partners, L.P.
Unit Option and Distribution Equivalent Plan (the Option Plan). We recognized total unit-based
compensation expense of $1.3 million and $0.4 million for the three months ended June 30, 2010 and
2009, respectively, and $2.5 million and $0.5 million for the six months ended June 30, 2010 and
2009, respectively.
Long-Term Incentive Plan
The LTIP provides for the issuance of up to 1,500,000 LP Units, subject to certain
adjustments. After giving effect to the issuance or forfeiture of phantom unit and performance
unit awards through June 30, 2010, awards representing a total of 1,113,451 additional LP Units
could be issued under the 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 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 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 LTIP activity table below.
24
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Awards under the LTIP
During the six months ended June 30, 2010, the Compensation Committee granted 123,290 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, and 121,926 performance units to employees. The amount paid with respect to phantom
unit distribution equivalents under the LTIP was $0.3 million for the six months ended June 30,
2010.
The following table sets forth the 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 |
|
|
257,216 |
|
|
|
56.20 |
|
|
|
14,455 |
|
Vested |
|
|
(18,454 |
) |
|
|
39.17 |
|
|
|
(723 |
) |
Forfeited |
|
|
(11,281 |
) |
|
|
48.28 |
|
|
|
(545 |
) |
|
|
|
|
|
|
|
|
|
|
|
Unvested at June 30, 2010 |
|
|
367,576 |
|
|
$ |
51.05 |
|
|
$ |
18,764 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 June 30, 2010, approximately $13.1 million of compensation expense related to the LTIP is
expected to be recognized over a weighted average period of approximately 2.2 years.
Unit Option and Distribution Equivalent Plan
The following is a summary of the changes in the LP Unit options outstanding (all of which are
vested or are expected to vest) under the Option Plan for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted- |
|
|
|
|
|
|
|
|
|
|
Weighted- |
|
|
Average |
|
|
|
|
|
|
|
|
|
|
Average |
|
|
Remaining |
|
|
Aggregate |
|
|
|
Number of |
|
|
Strike Price |
|
|
Contractual |
|
|
Intrinsic |
|
|
|
LP Units |
|
|
($/LP Unit) |
|
|
Term (in years) |
|
|
Value (1) |
|
Outstanding at January 1, 2010 |
|
|
349,400 |
|
|
$ |
46.25 |
|
|
|
|
|
|
|
|
|
Exercised |
|
|
(68,200 |
) |
|
|
43.62 |
|
|
|
|
|
|
|
|
|
Forfeited |
|
|
(6,000 |
) |
|
|
49.47 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at June 30, 2010 |
|
|
275,200 |
|
|
|
46.79 |
|
|
|
6.1 |
|
|
$ |
3,371 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at June 30, 2010 |
|
|
176,000 |
|
|
$ |
45.80 |
|
|
|
5.3 |
|
|
$ |
2,331 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 June 2010 and the exercise price, multiplied by the number of
exercisable, in-the-money options. |
25
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The total intrinsic value of options exercised during the six months ended June 30, 2010 was
$1.0 million. There were no option exercises during the six months ended June 30, 2009. At June
30, 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 0.7 years. At June
30, 2010, 333,000 LP Units were available for grant in connection with the Option Plan. However,
with the adoption of the LTIP, we do not expect to make any future grants pursuant to the Option
Plan. The fair value of options vested was $0.4 million and $0.3 million during the six months
ended June 30, 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. MainLine Management is a
wholly owned subsidiary of BGH GP. Affiliates of each of ArcLight and Kelso, 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
$27.4 million and $52.7 million for the three months ended June 30, 2010 and 2009, respectively.
For the six months ended June 30, 2010 and 2009, we incurred $54.9 million and $81.3 million,
respectively, of such costs. Amounts for the 2009 periods include costs related to our
organizational restructuring. We reimbursed Services Company for these costs.
Services Company, which is beneficially owned by the ESOP, owned 1.5 million of our LP Units
(approximately 3.0% of our LP Units outstanding) as of June 30, 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 $1.4 million and $1.9 million for the three months ended June 30,
2010 and 2009, respectively. For the six months ended June 30, 2010 and 2009, distributions paid
to Services Company totaled $3.0 million and $3.8 million, respectively. Total distributions paid
to Services Company decrease over time as Services Company sells LP Units to fund benefits payable
to ESOP participants who exit the ESOP.
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 six months ended June 30, 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 $12.6 million and $11.5
million during the three months ended June 30, 2010 and 2009, respectively. During the six months
ended June 30, 2010 and 2009, incentive distribution payments totaled $24.9 million and $22.0
million, respectively.
26
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 |
|
|
|
|
|
|
68,200 |
|
|
|
68,200 |
|
LP Units issued pursuant to the LTIP |
|
|
|
|
|
|
18,307 |
|
|
|
18,307 |
|
|
|
|
|
|
|
|
|
|
|
Units outstanding at June 30, 2010 |
|
|
243,914 |
|
|
|
51,524,772 |
|
|
|
51,768,686 |
|
|
|
|
|
|
|
|
|
|
|
Cash Distributions
We generally make quarterly cash distributions to unitholders of substantially all of our
available cash, generally defined in our partnership agreement as consolidated cash receipts less
consolidated cash expenditures and such retentions for working capital, anticipated cash
expenditures and contingencies as our general partner deems appropriate. Cash distributions
totaled $122.9 million and $111.6 million during the six months ended June 30, 2010 and 2009,
respectively.
On August 6, 2010, we announced a quarterly distribution of $0.9625 per LP Unit that will be
paid on August 31, 2010, to unitholders of record on August 16, 2010. Total cash distributed to
unitholders on August 31, 2010 will total approximately $62.7 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
LTIP awards calculated using the treasury stock method. Outstanding unit options and LTIP awards
are excluded from the calculation of diluted earnings per LP Unit in periods when we experience a
net loss because the effect is antidilutive.
27
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The amount of net income or loss allocated to limited partner interests is net of our general
partners share of such earnings. The following table presents the allocation of net income to our
general partner for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
Net income allocation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable
to Buckeye Partners, L.P. |
|
$ |
53,607 |
|
|
$ |
(48,371 |
) |
|
$ |
104,120 |
|
|
$ |
5,389 |
|
Less: General partners allocation
of incentive distributions |
|
|
(12,604 |
) |
|
|
(11,739 |
) |
|
|
(24,919 |
) |
|
|
(23,205 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to limited partners
and
general partner after incentive
distributions |
|
|
41,003 |
|
|
|
(60,110 |
) |
|
|
79,201 |
|
|
|
(17,816 |
) |
General partners ownership interest |
|
|
0.471 |
% |
|
|
0.473 |
% |
|
|
0.471 |
% |
|
|
0.474 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) allocation to general partner
based upon ownership interest |
|
$ |
193 |
|
|
$ |
(284 |
) |
|
$ |
373 |
|
|
$ |
(84 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partners incentive distributions |
|
$ |
12,604 |
|
|
$ |
11,739 |
|
|
$ |
24,919 |
|
|
$ |
23,205 |
|
Income (loss) allocation to general partner |
|
|
193 |
|
|
|
(284 |
) |
|
|
373 |
|
|
|
(84 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income allocated to general partner |
|
|
12,797 |
|
|
|
11,455 |
|
|
|
25,292 |
|
|
|
23,121 |
|
Adjustment for application of
two-class method for MLPs (1) |
|
|
275 |
|
|
|
|
|
|
|
556 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income allocated to general partner in
in accordance with two-class method |
|
$ |
13,072 |
|
|
$ |
11,455 |
|
|
$ |
25,848 |
|
|
$ |
23,121 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
We allocate net income to our general partner based on the distributions 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. |
28
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table presents the computation of basic and diluted earnings (loss) per LP Unit
for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
Earnings per LP Unit Calculation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable
to Buckeye Partners, L.P. |
|
$ |
53,607 |
|
|
$ |
(48,371 |
) |
|
$ |
104,120 |
|
|
$ |
5,389 |
|
Less: Net income allocated to general
partner
in accordance with two-class method |
|
|
(13,072 |
) |
|
|
(11,455 |
) |
|
|
(25,848 |
) |
|
|
(23,121 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to limited
partners
in accordance with two-class method |
|
$ |
40,535 |
|
|
$ |
(59,826 |
) |
|
$ |
78,272 |
|
|
$ |
(17,732 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator: (in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average LP Units outstanding |
|
|
51,512 |
|
|
|
51,243 |
|
|
|
51,492 |
|
|
|
49,830 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average LP Units outstanding |
|
|
51,512 |
|
|
|
51,243 |
|
|
|
51,492 |
|
|
|
49,830 |
|
Dilutive effect of LP Unit options
and LTIP awards granted (1) |
|
|
200 |
|
|
|
|
|
|
|
181 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
51,712 |
|
|
|
51,243 |
|
|
|
51,673 |
|
|
|
49,830 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per LP Unit: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.79 |
|
|
$ |
(1.17 |
) |
|
$ |
1.52 |
|
|
$ |
(0.36 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
$ |
0.78 |
|
|
$ |
(1.17 |
) |
|
$ |
1.51 |
|
|
$ |
(0.36 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
For the three and six months ended June 30, 2009, the dilutive effect of unit-based
compensation was not presented because its effect on the net loss per LP Unit would have been
antidilutive. |
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 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. In addition, we have excluded the Buckeye NGL Pipeline impairment expense of $72.5
million and the reorganization expense of $28.1 million from Adjusted EBITDA in order to
29
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
evaluate our results of operations on a comparative basis over multiple periods. 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.
Financial information about each segment, EBITDA and Adjusted EBITDA are presented below for
the periods or at the dates indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
Revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline Operations |
|
$ |
99,339 |
|
|
$ |
98,175 |
|
|
$ |
195,876 |
|
|
$ |
197,370 |
|
Terminalling & Storage |
|
|
40,768 |
|
|
|
29,429 |
|
|
|
83,139 |
|
|
|
60,072 |
|
Natural Gas Storage |
|
|
21,249 |
|
|
|
16,672 |
|
|
|
46,655 |
|
|
|
31,749 |
|
Energy Services |
|
|
501,949 |
|
|
|
201,676 |
|
|
|
1,070,151 |
|
|
|
470,156 |
|
Development & Logistics |
|
|
10,785 |
|
|
|
8,805 |
|
|
|
18,300 |
|
|
|
17,930 |
|
Intersegment |
|
|
(6,814 |
) |
|
|
(3,537 |
) |
|
|
(15,671 |
) |
|
|
(9,217 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue |
|
$ |
667,276 |
|
|
$ |
351,220 |
|
|
$ |
1,398,450 |
|
|
$ |
768,060 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline Operations |
|
$ |
45,393 |
|
|
$ |
(50,033 |
) |
|
$ |
91,365 |
|
|
$ |
(5,117 |
) |
Terminalling & Storage |
|
|
24,232 |
|
|
|
11,041 |
|
|
|
47,698 |
|
|
|
22,034 |
|
Natural Gas Storage |
|
|
3,422 |
|
|
|
5,794 |
|
|
|
6,977 |
|
|
|
12,032 |
|
Energy Services |
|
|
(158 |
) |
|
|
(1,480 |
) |
|
|
(3,234 |
) |
|
|
4,932 |
|
Development & Logistics |
|
|
950 |
|
|
|
170 |
|
|
|
2,053 |
|
|
|
1,714 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating income (loss) |
|
$ |
73,839 |
|
|
$ |
(34,508 |
) |
|
$ |
144,859 |
|
|
$ |
35,595 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline Operations |
|
$ |
9,770 |
|
|
$ |
9,724 |
|
|
$ |
19,411 |
|
|
$ |
19,301 |
|
Terminalling & Storage |
|
|
2,528 |
|
|
|
2,019 |
|
|
|
5,022 |
|
|
|
3,885 |
|
Natural Gas Storage |
|
|
1,765 |
|
|
|
1,345 |
|
|
|
3,532 |
|
|
|
2,926 |
|
Energy Services |
|
|
1,265 |
|
|
|
1,063 |
|
|
|
2,552 |
|
|
|
2,122 |
|
Development & Logistics |
|
|
458 |
|
|
|
524 |
|
|
|
913 |
|
|
|
921 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total depreciation and amortization |
|
$ |
15,786 |
|
|
$ |
14,675 |
|
|
$ |
31,430 |
|
|
$ |
29,155 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
Adjusted EBITDA: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline Operations |
|
$ |
57,614 |
|
|
$ |
58,190 |
|
|
$ |
115,431 |
|
|
$ |
114,058 |
|
Terminalling & Storage |
|
|
26,938 |
|
|
|
15,538 |
|
|
|
53,139 |
|
|
|
28,379 |
|
Natural Gas Storage |
|
|
6,280 |
|
|
|
8,579 |
|
|
|
12,749 |
|
|
|
17,542 |
|
Energy Services |
|
|
1,346 |
|
|
|
580 |
|
|
|
(195 |
) |
|
|
8,064 |
|
Development & Logistics |
|
|
347 |
|
|
|
1,717 |
|
|
|
1,483 |
|
|
|
3,255 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Adjusted EBITDA |
|
$ |
92,525 |
|
|
$ |
84,604 |
|
|
$ |
182,607 |
|
|
$ |
171,298 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GAAP Reconciliation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
55,425 |
|
|
$ |
(47,271 |
) |
|
$ |
107,703 |
|
|
$ |
7,849 |
|
Less: net income attributable
to noncontrolling interests |
|
|
(1,818 |
) |
|
|
(1,100 |
) |
|
|
(3,583 |
) |
|
|
(2,460 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable
to Buckeye Partners, L.P. unitholders |
|
|
53,607 |
|
|
|
(48,371 |
) |
|
|
104,120 |
|
|
|
5,389 |
|
Interest and debt expense |
|
|
21,262 |
|
|
|
16,061 |
|
|
|
42,811 |
|
|
|
33,237 |
|
Income tax (benefit) expense |
|
|
(647 |
) |
|
|
63 |
|
|
|
(665 |
) |
|
|
128 |
|
Depreciation and amortization |
|
|
15,786 |
|
|
|
14,675 |
|
|
|
31,430 |
|
|
|
29,155 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA |
|
|
90,008 |
|
|
|
(17,572 |
) |
|
|
177,696 |
|
|
|
67,909 |
|
Non-cash deferred lease expense |
|
|
1,058 |
|
|
|
1,125 |
|
|
|
2,117 |
|
|
|
2,250 |
|
Non-cash unit-based compensation expense |
|
|
1,459 |
|
|
|
398 |
|
|
|
2,794 |
|
|
|
486 |
|
Asset impairment expense |
|
|
|
|
|
|
72,540 |
|
|
|
|
|
|
|
72,540 |
|
Reorganization expense |
|
|
|
|
|
|
28,113 |
|
|
|
|
|
|
|
28,113 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA |
|
$ |
92,525 |
|
|
$ |
84,604 |
|
|
$ |
182,607 |
|
|
$ |
171,298 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
|
2010 |
|
|
2009 |
|
Capital additions, net: (1) |
|
|
|
|
|
|
|
|
Pipeline Operations |
|
$ |
14,252 |
|
|
$ |
12,561 |
|
Terminalling & Storage |
|
|
7,621 |
|
|
|
12,021 |
|
Natural Gas Storage |
|
|
3,292 |
|
|
|
12,906 |
|
Energy Services |
|
|
2,064 |
|
|
|
1,802 |
|
Development & Logistics |
|
|
343 |
|
|
|
529 |
|
|
|
|
|
|
|
|
Total capital additions, net |
|
$ |
27,572 |
|
|
$ |
39,819 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contributions to equity investments: |
|
|
|
|
|
|
|
|
Pipeline Operations |
|
$ |
|
|
|
$ |
3,880 |
|
|
|
|
|
|
|
|
Total contributions to equity investments |
|
$ |
|
|
|
$ |
3,880 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Amount excludes ($1.2) million and ($0.9) million of non-cash changes in accruals for
capital expenditures for the six months ended June 30, 2010 and 2009, respectively (see
Note 20). |
31
BUCKEYE PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
Total Assets: |
|
|
|
|
|
|
|
|
Pipeline Operations (1) |
|
$ |
1,536,124 |
|
|
$ |
1,592,916 |
|
Terminalling & Storage |
|
|
526,720 |
|
|
|
532,971 |
|
Natural Gas Storage |
|
|
548,061 |
|
|
|
573,261 |
|
Energy Services |
|
|
436,271 |
|
|
|
482,025 |
|
Development & Logistics |
|
|
63,159 |
|
|
|
74,476 |
|
|
|
|
|
|
|
|
Total assets |
|
$ |
3,110,335 |
|
|
$ |
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:
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
|
2010 |
|
|
2009 |
|
Cash paid for interest (net of capitalized interest) |
|
$ |
40,022 |
|
|
$ |
32,231 |
|
Cash paid for income taxes |
|
|
417 |
|
|
|
1,292 |
|
Capitalized interest |
|
|
1,117 |
|
|
|
2,684 |
|
|
|
|
|
|
|
|
|
|
Non-cash changes in assets and liabilities: |
|
|
|
|
|
|
|
|
Change in capital expenditures in accounts payable |
|
$ |
(1,186 |
) |
|
$ |
(865 |
) |
21. SUBSEQUENT EVENT
On August 2, 2010, we completed the acquisition of additional shares of West Shore Pipe Line
Company (West Shore) common stock from an affiliate of BP plc, resulting in an increase in our
ownership interest in West Shore from 24.9% to 34.6%. We paid approximately $13.4 million for this
additional interest.
32
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 and in this quarterly report on
Form 10-Q. 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.
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.
33
We operate and report in five business segments: Pipeline Operations; Terminalling & Storage;
Natural Gas Storage; Energy Services; and Development & Logistics. We own and operate one of the
largest independent refined petroleum products pipeline systems in the United States in terms of
volumes delivered with approximately 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.
Recent Developments
Agreement and Plan of Merger
On June 10, 2010, we and our general partner entered into an Agreement and Plan of Merger (the
Merger Agreement) with BGH, its general partner, and Grand Ohio, LLC (Merger Sub), our
subsidiary, pursuant to which Merger Sub will be merged into BGH, with BGH as the surviving entity
(the Merger). In the transaction, the incentive compensation agreement (also referred to as the
incentive distribution rights) held by our general partner will be cancelled, the general partner
units held by our general partner (representing an approximate 0.5% general partner interest in us)
will be converted to a non-economic general partner interest, all of the economic interest in BGH
will be acquired by us and BGH unitholders will receive aggregate consideration of approximately
20.0 million of our LP Units.
The terms of the Merger Agreement were unanimously approved by the audit committee of the
board of directors of our general partner (Audit Committee), and by the board of directors of
BGHs general partner. Additionally, the majority unitholder of BGH, BGH GP Holdings, LLC, and
ArcLight Energy Partners Fund III, L.P., ArcLight Energy Partners Fund IV, L.P., Kelso Investment
Associates VII, L.P., and KEP VI, LLC have executed a Support Agreement (Support Agreement)
agreeing to vote in favor of the Merger and against any alternative transaction. The Support
Agreement will automatically terminate if the board of directors of the general partner of BGH
changes its recommendation to BGHs unitholders with respect to the Merger or the Merger Agreement
is terminated.
After the Merger, the board of directors of our general partner is expected to consist of nine
members, three of whom are expected to be the existing independent members of our Audit Committee, one of whom
is expected to be the existing chief executive officer of our general partner and three of whom are
expected to be the three existing independent members of the audit committee of the board of directors of BGHs
general partner. In addition, BGHs general partner, which will own a non-economic general partner
interest in BGH and will continue to be owned by BGH GP Holdings, LLC, will have the right and
authority to designate two additional members of the board of directors, subject to reduction if
BGH GP Holdings, LLCs ownership of our LP Units drops below certain thresholds. The remaining
seven members of our general partners board of directors will be elected by holders of our LP
Units.
The Merger Agreement is subject to, among other things, approval by the affirmative vote of
the holders of a majority of our LP Units outstanding and entitled to vote at a meeting of the
holders of our LP Units, approval by the (a) affirmative vote of holders of a majority of BGHs
common units and (b) affirmative vote of holders of a majority of BGHs common units and management
units, voting together as a single class, and the effectiveness of a registration statement on Form
S-4 with respect to the issuance of the LP Units in connection with the Merger.
The Merger will be accounted for as an equity transaction. Therefore, changes in BGHs
ownership interest as a result of the Merger will not result in gain or loss recognition. BGH will
be considered the surviving consolidated entity for accounting purposes, while we will be the
surviving consolidated entity for legal and reporting purposes.
We incurred $1.8 million of costs associated with the Merger during the three and six months
ended June 30, 2010, of which $1.3 million has been paid. We charged these costs directly to
partners capital.
34
Amendment to BES Credit Agreement
On June 25, 2010, Buckeye Energy Services LLC (BES) amended and restated its credit
agreement (the BES Credit Agreement) to increase the total commitments for borrowings available
to BES up to $500.0 million. However, the maximum amount available to be borrowed under the
amended and restated BES Credit Agreement is initially limited to $350.0 million. An accordion
feature provides BES the ability to increase the commitments under the BES Credit Agreement to
$500.0 million, subject to obtaining the requisite commitments and satisfying other customary
conditions. In addition to the accordion, subject to BESs satisfaction of certain financial
covenants, BES may, from time to time, elect to increase or decrease the maximum amount available
for borrowing under the BES Credit Agreement in $5.0 million increments, but in no event below
$150.0 million or above $500.0 million. The maturity date of the BES Credit Agreement is June 25,
2013. BES incurred $3.2 million of debt issuance costs related to the amendment, which will be
amortized into interest expense over the term of the BES Credit Agreement. See Note 10 in the
Notes to Unaudited Condensed Consolidated Financial Statements for further discussion.
Purchase of Additional Interest in West Shore Pipe Line Company
On August 2, 2010, we completed the acquisition of additional shares of West Shore Pipe Line
Company (West Shore) common stock from an affiliate of BP plc, resulting in an increase in our
ownership interest in West Shore from 24.9% to 34.6%. We paid approximately $13.4 million for this
additional interest.
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 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. In addition, we have excluded the
Buckeye NGL Pipeline impairment expense of $72.5 million and the reorganization expense of $28.1
million from Adjusted EBITDA in order to evaluate our results of operations on a comparative basis
over multiple periods.
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
35
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.
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 |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
Adjusted EBITDA: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline Operations |
|
$ |
57,614 |
|
|
$ |
58,190 |
|
|
$ |
115,431 |
|
|
$ |
114,058 |
|
Terminalling & Storage |
|
|
26,938 |
|
|
|
15,538 |
|
|
|
53,139 |
|
|
|
28,379 |
|
Natural Gas Storage |
|
|
6,280 |
|
|
|
8,579 |
|
|
|
12,749 |
|
|
|
17,542 |
|
Energy Services |
|
|
1,346 |
|
|
|
580 |
|
|
|
(195 |
) |
|
|
8,064 |
|
Development & Logistics |
|
|
347 |
|
|
|
1,717 |
|
|
|
1,483 |
|
|
|
3,255 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Adjusted EBITDA |
|
$ |
92,525 |
|
|
$ |
84,604 |
|
|
$ |
182,607 |
|
|
$ |
171,298 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GAAP Reconciliation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
55,425 |
|
|
$ |
(47,271 |
) |
|
$ |
107,703 |
|
|
$ |
7,849 |
|
Less: net income attributable
to noncontrolling interests |
|
|
(1,818 |
) |
|
|
(1,100 |
) |
|
|
(3,583 |
) |
|
|
(2,460 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable
to Buckeye Partners, L.P. unitholders |
|
|
53,607 |
|
|
|
(48,371 |
) |
|
|
104,120 |
|
|
|
5,389 |
|
Interest and debt expense |
|
|
21,262 |
|
|
|
16,061 |
|
|
|
42,811 |
|
|
|
33,237 |
|
Income tax (benefit) expense |
|
|
(647 |
) |
|
|
63 |
|
|
|
(665 |
) |
|
|
128 |
|
Depreciation and amortization |
|
|
15,786 |
|
|
|
14,675 |
|
|
|
31,430 |
|
|
|
29,155 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA |
|
|
90,008 |
|
|
|
(17,572 |
) |
|
|
177,696 |
|
|
|
67,909 |
|
Non-cash deferred lease expense |
|
|
1,058 |
|
|
|
1,125 |
|
|
|
2,117 |
|
|
|
2,250 |
|
Non-cash unit-based compensation expense |
|
|
1,459 |
|
|
|
398 |
|
|
|
2,794 |
|
|
|
486 |
|
Asset impairment expense |
|
|
|
|
|
|
72,540 |
|
|
|
|
|
|
|
72,540 |
|
Reorganization expense |
|
|
|
|
|
|
28,113 |
|
|
|
|
|
|
|
28,113 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA |
|
$ |
92,525 |
|
|
$ |
84,604 |
|
|
$ |
182,607 |
|
|
$ |
171,298 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36
Segment Results
A summary of financial information by business segment follows for the periods indicated (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline Operations |
|
$ |
99,339 |
|
|
$ |
98,175 |
|
|
$ |
195,876 |
|
|
$ |
197,370 |
|
Terminalling & Storage |
|
|
40,768 |
|
|
|
29,429 |
|
|
|
83,139 |
|
|
|
60,072 |
|
Natural Gas Storage |
|
|
21,249 |
|
|
|
16,672 |
|
|
|
46,655 |
|
|
|
31,749 |
|
Energy Services |
|
|
501,949 |
|
|
|
201,676 |
|
|
|
1,070,151 |
|
|
|
470,156 |
|
Development & Logistics |
|
|
10,785 |
|
|
|
8,805 |
|
|
|
18,300 |
|
|
|
17,930 |
|
Intersegment |
|
|
(6,814 |
) |
|
|
(3,537 |
) |
|
|
(15,671 |
) |
|
|
(9,217 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
$ |
667,276 |
|
|
$ |
351,220 |
|
|
$ |
1,398,450 |
|
|
$ |
768,060 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses: (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline Operations |
|
$ |
53,946 |
|
|
$ |
148,208 |
|
|
$ |
104,511 |
|
|
$ |
202,487 |
|
Terminalling & Storage |
|
|
16,536 |
|
|
|
18,388 |
|
|
|
35,441 |
|
|
|
38,038 |
|
Natural Gas Storage |
|
|
17,827 |
|
|
|
10,878 |
|
|
|
39,678 |
|
|
|
19,717 |
|
Energy Services |
|
|
502,107 |
|
|
|
203,156 |
|
|
|
1,073,385 |
|
|
|
465,224 |
|
Development & Logistics |
|
|
9,835 |
|
|
|
8,635 |
|
|
|
16,247 |
|
|
|
16,216 |
|
Intersegment |
|
|
(6,814 |
) |
|
|
(3,537 |
) |
|
|
(15,671 |
) |
|
|
(9,217 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
$ |
593,437 |
|
|
$ |
385,728 |
|
|
$ |
1,253,591 |
|
|
$ |
732,465 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline Operations |
|
$ |
9,770 |
|
|
$ |
9,724 |
|
|
$ |
19,411 |
|
|
$ |
19,301 |
|
Terminalling & Storage |
|
|
2,528 |
|
|
|
2,019 |
|
|
|
5,022 |
|
|
|
3,885 |
|
Natural Gas Storage |
|
|
1,765 |
|
|
|
1,345 |
|
|
|
3,532 |
|
|
|
2,926 |
|
Energy Services |
|
|
1,265 |
|
|
|
1,063 |
|
|
|
2,552 |
|
|
|
2,122 |
|
Development & Logistics |
|
|
458 |
|
|
|
524 |
|
|
|
913 |
|
|
|
921 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total depreciation and amortization |
|
$ |
15,786 |
|
|
$ |
14,675 |
|
|
$ |
31,430 |
|
|
$ |
29,155 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset impairment expense: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline Operations |
|
$ |
|
|
|
$ |
72,540 |
|
|
$ |
|
|
|
$ |
72,540 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reorganization expense: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline Operations |
|
$ |
|
|
|
$ |
23,054 |
|
|
$ |
|
|
|
$ |
23,054 |
|
Terminalling and Storage |
|
|
|
|
|
|
2,402 |
|
|
|
|
|
|
|
2,402 |
|
Natural Gas Storage |
|
|
|
|
|
|
291 |
|
|
|
|
|
|
|
291 |
|
Energy Services |
|
|
|
|
|
|
944 |
|
|
|
|
|
|
|
944 |
|
Development & Logistics |
|
|
|
|
|
|
1,422 |
|
|
|
|
|
|
|
1,422 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total reorganization expense |
|
$ |
|
|
|
$ |
28,113 |
|
|
$ |
|
|
|
$ |
28,113 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline Operations |
|
$ |
45,393 |
|
|
$ |
(50,033 |
) |
|
$ |
91,365 |
|
|
$ |
(5,117 |
) |
Terminalling & Storage |
|
|
24,232 |
|
|
|
11,041 |
|
|
|
47,698 |
|
|
|
22,034 |
|
Natural Gas Storage |
|
|
3,422 |
|
|
|
5,794 |
|
|
|
6,977 |
|
|
|
12,032 |
|
Energy Services |
|
|
(158 |
) |
|
|
(1,480 |
) |
|
|
(3,234 |
) |
|
|
4,932 |
|
Development & Logistics |
|
|
950 |
|
|
|
170 |
|
|
|
2,053 |
|
|
|
1,714 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating income (loss) |
|
$ |
73,839 |
|
|
$ |
(34,508 |
) |
|
$ |
144,859 |
|
|
$ |
35,595 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Total costs and expenses includes depreciation and amortization, asset impairment expense
and reorganization expense. |
37
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 (bpd) and
total volumes sold in gallons for the Energy Services segment for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
Pipeline Operations (average bpd): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline |
|
|
668,900 |
|
|
|
685,700 |
|
|
|
639,100 |
|
|
|
659,200 |
|
Jet fuel |
|
|
339,300 |
|
|
|
345,100 |
|
|
|
330,900 |
|
|
|
339,200 |
|
Diesel fuel |
|
|
223,100 |
|
|
|
193,200 |
|
|
|
225,300 |
|
|
|
207,500 |
|
Heating oil |
|
|
36,100 |
|
|
|
52,200 |
|
|
|
74,800 |
|
|
|
91,500 |
|
LPGs |
|
|
21,300 |
|
|
|
18,800 |
|
|
|
20,900 |
|
|
|
16,600 |
|
NGLs |
|
|
|
|
|
|
20,500 |
|
|
|
|
|
|
|
20,900 |
|
Other products |
|
|
3,700 |
|
|
|
10,000 |
|
|
|
2,100 |
|
|
|
11,700 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Pipeline Operations |
|
|
1,292,400 |
|
|
|
1,325,500 |
|
|
|
1,293,100 |
|
|
|
1,346,600 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Terminalling & Storage (average bpd): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Products throughput (1) |
|
|
570,000 |
|
|
|
459,800 |
|
|
|
563,200 |
|
|
|
470,200 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy Services (in thousands of gallons): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales volumes |
|
|
235,100 |
|
|
|
134,000 |
|
|
|
502,100 |
|
|
|
317,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Reported quantities exclude transfer volumes, which are non-revenue generating transfers
among our various terminals. For the three and six months ended June 30, 2009, we previously
reported 489.4 thousand and 505.1 thousand, respectively, which included transfer volumes. |
Three Months Ended June 30, 2010 Compared to Three Months Ended June 30, 2009
Consolidated
Adjusted EBITDA. Adjusted EBITDA increased by $7.9 million, or 9.4%, to $92.5 million
for the three months ended June 30, 2010 from $84.6 million for the corresponding period in 2009.
The Terminalling & Storage segment was primarily responsible for this increase in Adjusted EBITDA.
The Terminalling & Storage segments Adjusted EBITDA increased by $11.4 million for the three
months ended June 30, 2010 as compared to the corresponding period in 2009, driven by increased
throughput volumes, growth in fees, increased 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 Energy
Services segments Adjusted EBITDA increased by $0.7 million for the three months ended June 30,
2010 as compared to the corresponding period in 2009 as a result of increased volumes of product
sold, partially offset by increased costs and expenses.
These increases in Adjusted EBITDA were partially offset by decreases in Adjusted EBITDA in
the Pipeline Operations segment, the Development & Logistics segment and the Natural Gas Storage
segment. The Pipeline Operations segments Adjusted EBITDA decreased by $0.6 million for the three
months ended June 30, 2010 as compared to the corresponding period in 2009, due to decreased
transportation revenues resulting from lower volumes transported during the three months ended June
30, 2010 and increased operating expenses, partially offset by the benefit of increased tariffs,
favorable settlement experience and increased other revenues. The Development & Logistics
segments Adjusted EBITDA decreased by $1.3 million for the three months ended June 30, 2010 as
compared to the corresponding period in 2009, due to $2.4 million of expenses related to the
write-off in the 2010 period of a portion of an outstanding receivable balance and other costs
associated with a customer bankruptcy (see Note 3 in the Notes to Unaudited Condensed Consolidated
Financial Statements for further discussion) and reduced operating contract services, partially
offset by revenues from the sale of ammonia linefill. The Natural Gas Storage segments Adjusted
EBITDA decreased by $2.3 million for the three months ended June 30, 2010 as compared to the
corresponding period in 2009. High storage inventory levels in the western region, above normal
temperatures
38
and general uncertainty regarding the economic recovery have added pressure on market-based
fees charged for storage services, and therefore led to a decrease in the net contribution from hub
services activities and decreased lease revenue.
Overall, Adjusted EBITDA was also impacted favorably by the continued effectiveness of cost
control measures we implemented in 2009. Largely as a result of these efforts, costs decreased by
approximately $4.8 million during the three months ended June 30, 2010 as compared to the
corresponding period in 2009. Offsetting this favorable impact was a
decrease of $0.3 million in
income from equity investments for the three months ended June 30, 2010 as compared to the
corresponding period in 2009. The revenue and expense factors affecting the variance in
consolidated Adjusted EBITDA are more fully discussed below.
Revenue. Revenue was $667.3 million for the three months ended June 30, 2010, which
is an increase of $316.1 million, or 90.0%, from the three months ended June 30, 2009. This
overall increase was caused by increases in revenues in all segments for the three months ended
June 30, 2010 as compared to the corresponding period in 2009 as follows:
|
|
|
an increase of $300.2 million in revenue from the Energy Services segment, resulting
from an overall increase in refined petroleum product prices and volumes of product
sold during the three months ended June 30, 2010 as compared to the corresponding
period in 2009; |
|
|
|
an increase of $11.4 million in revenue from the Terminalling & Storage segment,
resulting from increased throughput volumes, increased fees, storage and rental
revenue, including $1.5 million in storage fees from previously underutilized tankage
identified in connection with our best practices initiative and other marketing
opportunities, increased revenue from the contribution of terminals acquired in
November 2009 and favorable settlement experience; |
|
|
|
an increase of $4.5 million in revenue from the Natural Gas Storage segment,
resulting primarily from higher fees from hub services transactions recognized as
revenue, partially offset by reduced lease revenues as a result of general market
conditions as discussed above; |
|
|
|
an increase of $2.0 million in revenue from the Development & Logistics segment,
resulting primarily from the sale of ammonia linefill; and |
|
|
|
an increase of $1.1 million in revenue from the Pipeline Operations segment,
resulting from the benefit of higher tariffs, favorable settlement experience,
increased revenues from the contribution of pipeline assets acquired in November 2009
and increased other revenues. |
Total Costs and Expenses. Total costs and expenses were $593.4 million for the three
months ended June 30, 2010, which is an increase of $207.7 million, or 53.8%, from the
corresponding period in 2009. Total costs and expenses reflect:
|
|
|
an increase in refined petroleum product prices, which, coupled with an increase in
volumes sold, resulted in a $299.7 million increase in the Energy Services segments
cost of product sales in the 2010 period as compared to the 2009 period; |
|
|
|
an increase of $6.9 million in the Natural Gas Storage segments costs and expenses
resulting from higher costs associated with hub services transactions recognized as
expense caused primarily by general market conditions as discussed above; |
|
|
|
an increase in the Development & Logistics segments costs and expenses due to $2.4
million of expenses related to the write-off in the 2010 period of a portion of an
outstanding receivable balance and other costs associated with a customer bankruptcy;
and |
|
|
|
an increase of $1.1 million in depreciation and amortization, primarily due to
expense on assets placed in service in the second half of 2009 in connection with the
Kirby Hills Phase II expansion project, and certain internal-use software, which was
placed in service in the fourth quarter of 2009, and an increase of $1.1 million in
non-cash unit-based compensation expense, neither of which are components of Adjusted
EBITDA as presented in the reconciliation above. |
Total costs and expenses in the 2009 period include the recognition of a non-cash $72.5
million asset impairment expense in the Pipeline Operations segment related to the Buckeye NGL
Pipeline and $28.1 million of expenses across all segments associated with organizational
restructuring, neither of which are components of
39
Adjusted EBITDA as presented in the reconciliation above. These two charges were the primary
cause of a partially offsetting decrease in total costs and expenses for the 2010 period as
compared to the 2009 period. Total costs and expenses for the three months ended June 30, 2010
reflect the effectiveness of cost management efforts we implemented in 2009.
Total costs and expenses also reflect the following decreases:
|
|
|
a decrease in costs and expenses of the Pipeline Operations segment, resulting
substantially from a decrease related to the asset impairment expense and the
organizational restructuring charges recognized in the 2009 period as discussed above
and lower payroll and benefits costs, which was primarily attributable to the
organizational restructuring that occurred in 2009 and resulted in reduced headcount,
partially offset by increased integrity program expenses and increased professional
fees; and |
|
|
|
a decrease in costs and expenses of the Terminalling & Storage segment, resulting
primarily from a decrease related to expenses for organizational restructuring
recognized in the 2009 period and decreased payroll and benefits costs, partially
offset by higher environmental remediation expenses and higher operating expenses for
terminals acquired in November 2009. |
Consolidated net income attributable to unitholders. Consolidated net income
attributable to our unitholders was $53.6 million for the three months ended June 30, 2010 compared
to a net loss of $48.4 million for the three months ended June 30, 2009. Interest and debt expense
increased by $5.2 million for the three months ended June 30, 2010 as compared to the corresponding
period in 2009, which increase was largely attributable to the issuance in August 2009 of $275.0
million aggregate principal amount of 5.500% Notes due 2019 and higher outstanding borrowings under
the BES Credit Agreement, partially offset by lower outstanding borrowings under our unsecured
revolving credit agreement (the Credit Facility). In addition, depreciation and amortization
increased by $1.1 million, primarily due to expense on assets placed in service in the second half
of 2009 in connection with the Kirby Hills Phase II expansion project, 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. Adjusted EBITDA from the Pipeline Operations segment of $57.6
million for the three months ended June 30, 2010 decreased by $0.6 million, or 1.0%, from $58.2
million for the corresponding period in 2009. The decrease in Adjusted EBITDA was driven primarily
by a decrease of $3.2 million in transportation revenues, resulting from lower volumes transported
during the three months ended June 30, 2010 compared with the corresponding period in 2009. The
decrease in volumes transported is partially attributable to the sale of the Buckeye NGL Pipeline
on January 1, 2010 (see Note 2 in the Notes to Unaudited Condensed Consolidated Financial
Statements). This decrease in Adjusted EBITDA was partially offset by a $2.4 million increase in
other revenue, the benefit of higher tariffs of $1.9 million, favorable settlement experience of
$1.0 million and increased revenue of $0.8 million from pipeline assets acquired in November 2009.
The Pipeline Operations segments decrease in Adjusted EBITDA
was also due to a $0.3 million
decrease in income from equity investments and a $3.1 million increase in operating expenses. The
revenue and expense factors affecting the variance in Adjusted EBITDA are more fully discussed
below.
Revenue. Revenue from the Pipeline Operations segment was $99.3 million for the three
months ended June 30, 2010, which is an increase of $1.1 million, or 1.2%, from the corresponding
period in 2009. Revenues increased due to the benefit of higher tariffs of $1.9 million, the
result of overall average tariff increases of approximately 3.8% implemented on July 1, 2009 and
2.61% implemented on May 1, 2010. In addition, favorable settlement experience of $1.0 million,
increased revenues of $0.8 million from pipeline assets acquired in November 2009 and increased
other revenue of $2.4 million contributed to the increase in revenues. These increases in revenue
were partially offset by a $3.2 million decrease related to a 2.5% decrease in transportation
volumes due in part to the sale of the Buckeye NGL Pipeline on January 1, 2010 and reduced revenues
of $1.3 million from a product supply
40
arrangement with a wholesale distributor and contract service activities at customer
facilities connected to our refined petroleum products pipelines pursuant to the assignment of such
service contract to the Development & Logistics segment.
Total Costs and Expenses. Total costs and expenses from the Pipeline Operations
segment were $53.9 million for the three months ended June 30, 2010, which is a decrease of $94.3
million, or 63.6%, from the corresponding period in 2009. Total costs and expenses for the 2009
period include a $72.5 million non-cash asset impairment expense and $23.1 million of expense
related to an organizational restructuring. These charges in the 2009 period, which are not
components of Adjusted EBITDA as presented in the reconciliation above, were the primary reason
that costs and expenses in the 2009 period were 63.6% higher than in the 2010 period. Total costs
and expenses for the three months ended June 30, 2010 also reflect an increase of $2.1 million in
integrity program expenses, primarily due to increased levels of pipeline maintenance activities,
and an increase of $0.7 million in professional fees, partially offset by a decrease of $1.3
million in payroll and benefits costs primarily related to our best practices initiative in 2009,
and a decrease of $1.2 million in operating power costs due to lower transportation volumes and
power contract renegotiations as part of our best practices initiative.
Operating Income. Operating income from the Pipeline Operations segment was $45.4
million for the three months ended June 30, 2010 compared to an operating loss of $50.0 million for
the three months ended June 30, 2009. Other revenue and expense items impacting operating income
are discussed above.
Terminalling & Storage
Adjusted EBITDA. Adjusted EBITDA from the Terminalling & Storage segment of $26.9
million for the three months ended June 30, 2010 increased by $11.4 million, or 73.4%, from $15.5
million for the corresponding period in 2009. The increase in Adjusted EBITDA reflects an increase
of $10.7 million from the contribution of terminals acquired in November 2009, the impact of
internal growth projects, increased throughput volumes, higher fees, increased storage, rental and
other service revenue, increased settlement experience and a $0.7 million decrease in operating
expenses. The revenue and expense factors affecting the variance in Adjusted EBITDA are more fully
discussed below.
Revenue. Revenue from the Terminalling & Storage segment was $40.8 million for the
three months ended June 30, 2010, which is an increase of $11.4 million, or 38.5%, from the
corresponding period in 2009. Approximately $8.7 million of the increase resulted primarily from
terminals acquired in November 2009, internal growth projects, increased throughput volumes, higher
fees, higher storage and rental revenue, including $1.5 million in storage fees from previously
underutilized tankage identified in connection with our best practices initiative and other
marketing opportunities, and increased butane-blending revenue. Also contributing to the improved
revenue was an increase of $2.6 million in settlement experience reflecting the favorable impact of
higher refined petroleum product prices during the three months ended June 30, 2010 as compared to
the corresponding period in 2009. In addition to the 13.8% increase in volumes resulting from the
acquisition of terminals in November 2009, terminalling volumes increased 10.2% for the three
months ended June 30, 2010 as compared to the corresponding period in 2009, largely due to
increased ethanol throughput volumes.
Total Costs and Expenses. Total costs and expenses from the Terminalling & Storage
segment were $16.5 million for the three months ended June 30, 2010, which is a decrease of $1.9
million, or 10.1%, from the corresponding period in 2009. The decrease in total costs and expenses
in the 2010 period as compared to the 2009 period is due to a $2.4 million decrease related to
expenses for organizational restructuring recognized in the 2009 period and a $1.1 million decrease
in payroll and benefits costs primarily related to our best practices initiative in 2009. These
decreases were partially offset by a $0.8 million increase in environmental remediation expenses, a
$0.6 million increase in operating expenses for terminals acquired in November 2009 and a $0.5
million increase in depreciation and amortization. Depreciation and amortization and the
organizational restructuring charges are not components of Adjusted EBITDA as presented in the
reconciliation above.
Operating Income. Operating income from the Terminalling & Storage segment was $24.2
million for the three months ended June 30, 2010 compared to operating income of $11.0 million for
the three months ended June 30, 2009. Depreciation and amortization increased by $0.5 million for
the three months ended June 30, 2010 as a result
41
of the terminals acquired in November 2009. Other revenue and expense items impacting
operating income are discussed above.
Natural Gas Storage
Adjusted EBITDA. Adjusted EBITDA from the Natural Gas Storage segment of $6.3 million
for the three months ended June 30, 2010 decreased by $2.3 million, or 26.8%, from $8.6 million for
the corresponding period in 2009. The decrease in Adjusted EBITDA was primarily the result of a
$1.0 million decrease in the net contribution from hub service activities, a decrease of $0.6
million in lease revenues and an increase of $0.7 million in other operating expenses during the
three months ended June 30, 2010. High storage inventory levels in the western region, above
normal temperatures and general uncertainty regarding the economic recovery have added pressure on
market-based lease fees charged for storage services, and therefore led to a decrease in the net
contribution from hub services activities and decreased lease revenue. This decrease in lease
revenues as a result of reduced fees was partially offset by increased storage capacity from the
commissioning of the Kirby Hills Phase II expansion project, which was placed in service in June
2009. The revenue and expense factors affecting the variance in Adjusted EBITDA are more fully
discussed below.
Revenue. Revenue from the Natural Gas Storage segment was $21.2 million for the three
months ended June 30, 2010, which is an increase of $4.5 million, or 27.5%, from the corresponding
period in 2009. This overall increase is attributable to greater underlying volume and higher fees
recognized as revenue for hub services provided during the three months ended June 30, 2010. The
fees for hub services agreements are based on the relative market prices of natural gas over
different delivery periods. A positive market price spread results in receipt of a fee from the
customer that is reflected as transportation and other services revenue. A negative market price
spread results in payment of a fee to the customer that is 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 allow us 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 the three months ended June 30, 2010 and 2009,
there were 165 and 150 outstanding hub service contracts, respectively, for which revenue was being
recognized ratably. Market conditions contributed to higher fees of $5.2 million for hub service
agreements recognized as revenue during the three months ended June 30, 2010 compared to the same
period in 2009, partially offset by reduced market-based fees charged for storage
services as a result of high storage inventory levels in the western region, above normal
temperatures and general uncertainty regarding the economic recovery. Additionally, lease revenue
decreased $0.6 million for the three months ended June 30, 2010, as a decrease in the fee charged
for each volumetric unit of storage capacity leased was partially offset by increased storage
capacity from the commissioning of the Kirby Hills Phase II expansion project, which was placed in
service in June 2009.
Total Costs and Expenses. Total costs and expenses from the Natural Gas Storage
segment were $17.8 million for the three months ended June 30, 2010, which is an increase of $6.9
million, or 63.9%, 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; a negative market price spread results in payment of a fee to the
customer that is reflected as cost of natural gas storage services ratably as those services are
provided. Other operating expenses increased $0.7 million, primarily due to increased fuel costs,
professional fees, maintenance materials expense and rental expense. Total costs and expenses also
include an increase of $0.5 million in depreciation and amortization, partially offset by a
decrease of $0.3 million related to an organizational restructuring recognized in the 2009 period,
neither of which are components of Adjusted EBITDA as presented in the reconciliation above.
Operating Income. Operating income from the Natural Gas Storage segment was $3.4
million for the three months ended June 30, 2010 compared to operating income of $5.8 million for
the three months ended June 30, 2009. Depreciation and amortization increased by $0.5 million for
the three months ended June 30, 2010 from the corresponding period in 2009 due to expense on assets
placed in service in the second half of 2009 in connection with the Kirby Hills Phase II expansion
project. Other revenue and expense items impacting operating income are discussed above.
42
Energy Services
Adjusted EBITDA. Adjusted EBITDA from the Energy Services segment of $1.3 million for
the three months ended June 30, 2010 increased by $0.7 million, or 132.1%, from $0.6 million for
the corresponding period in 2009. This increase in Adjusted EBITDA was primarily the result of a
75.4% increase in sales volumes, partially offset by lower margins for each gallon of product sold.
The higher than normal levels of inventory for gasoline and distillate products industry-wide, in
conjunction with an overall decline in demand has continued to suppress margins at the rack through
the second quarter of 2010. In addition, contango opportunities in the market are at reduced
levels as compared to the 2009 period which contributed to lower gross margin recognized during the
2010 period. The revenue and expense factors affecting the variance in Adjusted EBITDA are more
fully discussed below.
Revenue. Revenue from the Energy Services segment was $501.9 million for the three
months ended June 30, 2010, which is an increase of $300.2 million, or 148.9%, from the
corresponding period in 2009. This increase was primarily due to an increase in refined petroleum
product prices, which correspondingly increased the cost of product sales, and an increase of 75.4%
in sales volumes.
Total Costs and Expenses. Total costs and expenses from the Energy Services segment
were $502.1 million for the three months ended June 30, 2010, which is an increase of $298.9
million, or 147.2%, from the corresponding period in 2009. The increase in total costs and
expenses was primarily due to an increase of $299.7 million in cost of product sales as a result of
increased volumes sold and an increase in refined petroleum product prices, an increase of $0.4
million in payroll related costs and an increase of $0.4 million in bad debt expense, partially
offset by a decrease of $0.7 million in maintenance materials expense and professional fees and a
decrease of $0.9 million related to an organizational restructuring recognized in the 2009 period.
The organizational restructuring charge is not a component of Adjusted EBITDA as presented in the
reconciliation above.
Operating Income (loss). Operating loss from the Energy Services segment was $0.2
million for the three months ended June 30, 2010 compared to an operating loss of $1.5 million for
the three months ended June 30, 2009. Depreciation and amortization increased by $0.2 million for
the three months ended June 30, 2010 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. Adjusted EBITDA from the Development & Logistics segment of $0.4
million for the three months ended June 30, 2010 decreased by $1.3 million, or 79.8%, from $1.7
million for the corresponding period in 2009, primarily due to the recognition of $2.4 million of
expenses related to the write-off in the 2010 period of a portion of an outstanding receivable
balance and other costs associated with a customer bankruptcy, and reduced operating contract
margins of $0.2 million, partially offset by a net increase of $1.1 million related to the sale of
ammonia linefill. The revenue and expense factors affecting the variance in Adjusted EBITDA are
more fully discussed below.
Revenue. Revenue from the Development & Logistics segment, which consists principally
of our contract operations and engineering services for third-party pipelines, was $10.8 million
for the three months ended June 30, 2010, which is an increase of $2.0 million, or 22.5%, from the
corresponding period in 2009. The increase in revenue was partially due to a $1.5 million increase
in other revenue, primarily from the recognition of $1.1 million of revenue related to the sale of
ammonia linefill. In addition, operating service revenues increased $2.2 million from the 2009
period, primarily due to the assignment of certain service contracts from the Pipeline Operations
segment to the Development & Logistics segment. These increases in revenue were partially offset
by the completion and non-replacement of construction projects in 2009, resulting in a $2.1 million
reduction in certain construction contract revenues.
Total Costs and Expenses. Total costs and expenses from the Development & Logistics
segment were $9.8 million for the three months ended June 30, 2010, which is an increase of $1.2
million, or 13.9%, from the corresponding period in 2009. The increase in total costs and expenses
was the result of the recognition of $2.4 million of expenses related to the write-off in the 2010
period of a portion of an outstanding receivable balance and other costs associated with a customer
bankruptcy, and increased operating services activities discussed above,
43
partially offset by reduced construction contract activity and lower income tax expense.
Total costs and expenses also include a decrease of $1.4 million related to an organizational
restructuring recognized in the 2009 period, which is not a component of Adjusted EBITDA as
presented in the reconciliation above.
Operating Income. Operating income from the Development & Logistics segment was $1.0
million for the three months ended June 30, 2010 compared to operating income of $0.2 million for
the three months ended June 30, 2009. Income tax expense decreased by $0.7 million for the three
months ended June 30, 2010 due to the recognition of a tax benefit of $0.6 million primarily
related to the write-off of a portion of an outstanding receivable balance and other costs
associated with a customer bankruptcy as discussed above. Other revenue and expense items
impacting operating income are discussed above.
Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009
Consolidated
Adjusted EBITDA. Adjusted EBITDA increased by $11.3 million, or 6.6%, to $182.6
million for the six months ended June 30, 2010 from $171.3 million for 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 $24.7 million for the six months ended June 30, 2010 as compared to the
corresponding period in 2009, driven by increased throughput volumes, growth in fees, storage and
rental revenues, the contribution from terminals acquired in November 2009, favorable settlement
experience and lower operating expenses. The Pipeline Operations segments Adjusted EBITDA
increased by $1.3 million for the six months ended June 30, 2010 as compared to the corresponding
period in 2009, primarily due to increased tariffs and favorable settlement experience, which more
than offset the impact of lower volumes transported during the six months ended June 30, 2010
compared to the corresponding period in 2009.
These increases in Adjusted EBITDA were partially offset by decreases in Adjusted EBITDA in
the Energy Services segment, the Natural Gas Storage segment and the Development & Logistics
segment. The Energy Services segments Adjusted EBITDA decreased by $8.3 million for the six
months ended June 30, 2010 as compared to the corresponding period in 2009, primarily due to lower
margins realized on products sold as a result of weakened market conditions during the six months
ended June 30, 2010, partially offset by increased volumes of products sold. The Natural Gas
Storage segments Adjusted EBITDA decreased by $4.8 million for the six months ended June 30, 2010
as compared to the corresponding period in 2009 as a result of high storage inventory levels in the
western region, above normal temperatures and general uncertainty regarding the economic recovery
which have added pressure on market-based lease fees charged for storage services, and therefore
led to a decrease in the net contribution from hub services activities. The Development &
Logistics segments Adjusted EBITDA decreased by $1.8 million for the six months ended June 30,
2010 as compared to the corresponding period in 2009, due to $2.4 million of expenses related to
the write-off in the 2010 period of a portion of an outstanding receivable balance and other costs
associated with a customer bankruptcy and due to reduced operating and construction contract
services.
Overall, Adjusted EBTIDA was also impacted favorably by the continued effectiveness of cost
control measures we implemented in 2009. Largely as a result of these efforts, costs decreased by
approximately $9.4 million during the six months ended June 30, 2010 as compared to the
corresponding period in 2009. Income from equity investments increased by $0.2 million for the six
months ended June 30, 2010 as compared to the corresponding period in 2009. The revenue and
expense factors affecting the variance in consolidated Adjusted EBITDA are more fully discussed
below.
Revenue. Revenue was $1,398.5 million for the six months ended June 30, 2010, which
is an increase of $630.4 million, or 82.1%, from the six months ended June 30, 2009. The increase
in revenue for the six months ended June 30, 2010 as compared to the corresponding period in 2009
was caused primarily by the following:
|
|
|
an increase of $600.0 million in revenue from the Energy Services segment, resulting
from an overall increase in refined petroleum product prices and volumes of product
sold during the six months ended June 30, 2010 as compared to the corresponding period
in 2009;
|
44
|
|
|
an increase of $23.0 million in revenue from the Terminalling & Storage segment,
resulting from increased throughput volumes, increased fees, storage and rental
revenue, including $3.2 million in storage fees from previously underutilized tankage
identified in connection with our best practices initiative and other marketing
opportunities, increased revenue from the contribution of terminals acquired in
November 2009 and favorable settlement experience; |
|
|
|
an increase of $15.0 million in revenue from the Natural Gas Storage segment,
resulting primarily from higher fees from hub services transactions recognized as
revenue; and |
|
|
|
an increase of $0.4 million in revenue from the Development & Logistics segment,
resulting primarily from the sale of ammonia linefill. |
The increase in revenue was partially offset by:
|
|
|
a decrease of $1.5 million in revenue from the Pipeline Operations segment,
resulting primarily from lower transportation volumes and lower other revenue,
partially offset by increased tariffs, favorable settlement experience and increased
revenues from the contribution of pipeline assets acquired in November 2009. |
Total Costs and Expenses. Total costs and expenses were $1,253.6 million for the six
months ended June 30, 2010, which is an increase of $521.1 million, or 71.1%, 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 $609.6 million increase in the Energy Services segments
cost of product sales in the 2010 period as compared to the 2009 period; |
|
|
|
an increase of $20.0 million in the Natural Gas Storage segments costs and expenses
resulting from higher costs associated with hub services transactions recognized as
expense caused primarily by general market conditions as discussed above; |
|
|
|
an increase of $2.2 million in depreciation and amortization, primarily due to
expense on assets placed in service in the second half of 2009 in connection with the
Kirby Hills Phase II expansion project, and certain internal-use software, which was
placed in service in the fourth quarter of 2009, and an increase of $2.3 million in
non-cash unit-based compensation expense, neither of which are components of Adjusted
EBITDA as presented in the reconciliation above; and |
|
|
|
no significant change in the Development & Logistics segments costs and expenses
from the 2009 period to the 2010 period, as $2.4 million of expenses related to the
write-off in the 2010 period of a portion of an outstanding receivable balance and
other costs associated with a customer bankruptcy and increased operating services
activities in the 2010 period were substantially offset by a decrease of $1.4 million
related to an organizational restructuring recognized in the 2009 period and reduced
construction contract activity in the 2010 period. |
Total costs and expenses in the 2009 period include the recognition of a non-cash $72.5
million asset impairment expense in the Pipeline Operations segment, related to the Buckeye NGL
Pipeline and $28.1 million of expenses across all segments associated with organizational
restructuring, none of which are components of Adjusted EBITDA as presented in the reconciliation
above. These two charges were the primary cause of a partially offsetting decrease in total costs
and expenses for the 2010 period as compared to the 2009 period. Total costs and expenses for the
six months ended June 30, 2010 reflect the effectiveness of cost management efforts we implemented
in 2009.
Total costs and expenses also reflect the following decreases:
|
|
|
a decrease in costs and expenses of the Pipeline Operations segment, resulting
substantially from a decrease related to the asset impairment expense and the
organizational restructuring charges recognized in the 2009 period as discussed above
and lower payroll and benefits costs, which was primarily attributable to the
organizational restructuring that occurred in 2009 and resulted in reduced headcount,
as well as from lower contract service activities, lower environmental remediation
|
45
|
|
|
expenses, lower contract service activities and lower operating power costs due to
lower transportation volumes and power contract renegotiations as part of our best
practices initiative; and |
|
|
|
a decrease in costs and expenses of the Terminalling & Storage segment, resulting
primarily from a decrease related to expenses for organizational restructuring
recognized in the 2009 period, lower environmental remediation expenses and lower
payroll and benefits costs, partially offset by higher operating expense for terminals
acquired in November 2009 and higher bad debt expense. |
Consolidated net income attributable to unitholders. Consolidated net income
attributable to our unitholders was $104.1 million for the six months ended June 30, 2010 compared
to $5.4 million for the six months ended June 30, 2009. Interest and debt expense increased by
$9.6 million for the six months ended June 30, 2010 as compared to the corresponding period in
2009, which increase was largely attributable to the issuance in August 2009 of $275.0 million
aggregate principal amount of 5.500% Notes due 2019, higher outstanding borrowings under the BES
Credit Agreement and lower interest capitalized on construction projects, partially offset by lower
outstanding borrowings under the Credit Facility. In addition, depreciation and amortization
increased by $2.2 million, primarily due to expense on assets placed in service in the second half
of 2009 in connection with the Kirby Hills Phase II expansion project 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. Adjusted EBITDA from the Pipeline Operations segment of $115.4
million for the six months ended June 30, 2010 increased by $1.3 million, or 1.2%, from $114.1
million for the corresponding period in 2009. The increase in Adjusted EBITDA was driven primarily
by the benefit of higher tariffs of $4.6 million, favorable settlement experience of $3.0 million,
increased revenues of $1.4 million from pipeline assets acquired in November 2009, a $1.4 million
increase in other net revenues and a $0.2 million increase in income from equity investments.
These increases in Adjusted EBITDA were partially offset by an $8.9 million decrease in
transportation revenues resulting from lower volumes transported during the six months ended June
30, 2010 compared with the corresponding period in 2009 and lower volumes resulting from the sale
of the Buckeye NGL Pipeline on January 1, 2010, and a $0.4 million increase in operating expenses.
The revenue and expense factors affecting the variance in Adjusted EBITDA are more fully discussed
below.
Revenue. Revenue from the Pipeline Operations segment was $195.9 million for the six
months ended June 30, 2010, which is a decrease of $1.5 million, or 0.8%, from the corresponding
period in 2009. Revenues decreased by $8.9 million, resulting from a 4.0% decrease in
transportation volumes, due in part to the sale of the Buckeye NGL Pipeline on January 1, 2010 and
a $2.2 million decrease in revenue from a product supply arrangement with a wholesale distributor
and contract service activities at customer facilities connected to our refined petroleum products
pipelines pursuant to the assignment of such service contract to the Development & Logistics
segment. These decreases in revenue were partially offset by higher tariffs of $4.6 million, the
result of overall average tariff increases of approximately 3.8% implemented on July 1, 2009 and
2.61% implemented on May 1, 2010, favorable settlement experience of $3.0 million and increased
revenues of $1.4 million from pipeline assets acquired in November 2009.
Total Costs and Expenses. Total costs and expenses from the Pipeline Operations
segment were $104.5 million for the six months ended June 30, 2010, which is a decrease of $98.0
million, or 48.4%, from the corresponding period in 2009. Total costs and expenses for the 2009
period include a $72.5 million non-cash asset impairment expense and $23.1 million of expense
related to organizational restructuring. These charges in the six months ended June 30, 2009 were
the primary reason that total costs and expenses in the 2009 period were 48.4% higher than in the
2010 period. The asset impairment expense and the organizational restructuring charges are not
components of Adjusted EBITDA as presented in the reconciliation above.
In addition, total costs and expenses in the 2010 period were lower than in the 2009 period as
a result of a $3.3 million decrease in payroll and benefits costs, resulting primarily from our
best practices initiative, a $1.5 million reduction in environmental remediation expenses, a $1.3
million decrease in operating power costs due to lower
transportation volumes and power contract renegotiations as part of our best practices
initiative, a $1.2 million
46
decrease in contract service activities at customer facilities connected
to our refined petroleum products pipelines, and a $0.8 million decrease in product costs,
resulting from reduced volumes of product sold to a wholesale distributor. These decreases in
total costs and expenses were partially offset by an increase of $4.7 million in professional fees
and other expenses, including an increase of $2.2 million in integrity program expenses and an
increase of $0.6 million in bad debt expense.
Operating Income. Operating income from the Pipeline Operations segment was $91.4
million for the six months ended June 30, 2010 compared to an operating loss of $5.1 million for
the six months ended June 30, 2009. Income from equity investments increased by $0.2 million for
the six months ended June 30, 2010 as compared to the corresponding period in 2009. Other revenue
and expense items impacting operating income are discussed above.
Terminalling & Storage
Adjusted EBITDA. Adjusted EBITDA from the Terminalling & Storage segment of $53.1
million for the six months ended June 30, 2010 increased by $24.7 million, or 87.2%, from $28.4
million for the corresponding period in 2009. The increase in Adjusted EBITDA reflects an increase
of $21.9 million from the contribution of terminals acquired in November 2009, the impact of
internal growth projects, increased throughput volumes, higher fees, increased storage, rental and
other service revenue, increased settlement experience and a $2.8 million decrease in operating
expenses. The revenue and expense factors affecting the variance in Adjusted EBITDA are more fully
discussed below.
Revenue. Revenue from the Terminalling & Storage segment was $83.1 million for the
six months ended June 30, 2010, which is an increase of $23.0 million, or 38.4%, from the
corresponding period in 2009. Approximately $19.5 million of the increase resulted primarily from
terminals acquired in November 2009, internal growth projects, increased throughput volumes, higher
fees, higher storage and rental revenue, including $3.2 million in storage fees from previously
underutilized tankage identified in connection with our best practices initiative and other
marketing opportunities, and increased butane-blending revenue. Also contributing to the improved
revenue was an increase of $3.5 million in settlement experience, reflecting the favorable impact
of higher refined petroleum product prices during the six months ended June 30, 2010 as compared to
the corresponding period in 2009. In addition to the 12.1% increase in volumes resulting from the
acquisition of terminals in November 2009, terminalling volumes increased 7.6% for the six months
ended June 30, 2010 as compared to the corresponding period in 2009, largely due to increased
ethanol throughput volumes.
Total Costs and Expenses. Total costs and expenses from the Terminalling & Storage
segment were $35.4 million for the six months ended June 30, 2010, which is a decrease of $2.6
million, or 6.8%, from the corresponding period in 2009. The decrease in total costs and expenses
in the 2010 period as compared to the 2009 period is due to a $2.4 million decrease related to
expenses for organizational restructuring recognized in the 2009 period, a $1.5 million decrease in
environmental remediation expenses and a $1.5 million decrease in payroll and benefits costs
primarily related to our best practices initiative in 2009, partially offset by a $1.3 million
increase in operating expenses for terminals acquired in November 2009, a $0.6 million increase in
bad debt expense and a $1.1 million increase in depreciation and amortization, primarily due to
expense on assets acquired in November 2009. Depreciation and amortization and the organizational
restructuring charges are not components of Adjusted EBITDA as presented in the reconciliation
above.
Operating Income. Operating income from the Terminalling & Storage segment was $47.7
million for the six months ended June 30, 2010 compared to operating income of $22.0 million for
the six months ended June 30, 2009. Depreciation and amortization increased by $1.1 million for
the six months ended June 30, 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. Adjusted EBITDA from the Natural Gas Storage segment of $12.7
million for the six months ended June 30, 2010 decreased by $4.8 million, or 27.3%, from $17.5
million for the corresponding period
in 2009. The decrease in Adjusted EBITDA was primarily the result of a $4.9 million decrease
in the net
47
contribution from hub service activities and an increase of $0.6 million in operating
expenses, partially offset by an increase of $0.8 million in lease revenues during the six months
ended June 30, 2010. 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. Revenue from the Natural Gas Storage segment was $46.7 million for the six
months ended June 30, 2010, which is an increase of $15.0 million, or 46.9%, from the corresponding
period in 2009. This overall increase is attributable to greater underlying volume and higher fees
recognized as revenue for hub services provided during the six months ended June 30, 2010. During
the six months ended June 30, 2010 and 2009, there were 232 and 205 outstanding hub service
contracts, respectively, for which revenue was being recognized ratably. Market conditions
contributed to higher fees of $14.1 million for hub service agreements recognized as revenue during
the six months ended June 30, 2010 as compared to the corresponding period in 2009. Lease revenue
also increased $0.8 million for the six months ended June 30, 2010, as increased storage capacity
from the commissioning of the Kirby Hills Phase II expansion project, which was placed in service
in June 2009, was partially offset by a decrease in the fee charged for each volumetric unit of
storage capacity leased.
Total Costs and Expenses. Total costs and expenses from the Natural Gas Storage
segment were $39.7 million for the six months ended June 30, 2010, which is an increase of $20.0
million, or 101.2%, 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. Other
operating expenses increased by $0.6 million, primarily due to increased fuel costs, professional
fees, maintenance materials expense and supplies and rental expenses, partially offset by decreased
outside service costs. Total costs and expenses also include an increase of $0.6 million in
depreciation and amortization, partially offset by a decrease of $0.3 million related to
organizational restructuring charges recognized in the 2009 period, neither of which are components
of Adjusted EBITDA as presented in the reconciliation above.
Operating Income. Operating income from the Natural Gas Storage segment was $7.0
million for the six months ended June 30, 2010 compared to operating income of $12.0 million for
the six months ended June 30, 2009. Depreciation and amortization increased by $0.6 million for
the six months ended June 30, 2010 from the corresponding period in 2009 due to expense on assets
placed in service in the second half of 2009 in connection with the Kirby Hills Phase II expansion
project. Other revenue and expense items impacting operating income are discussed above.
Energy Services
Adjusted EBITDA. Adjusted EBITDA from the Energy Services segment decreased by $8.3
million, or 102.4%, to a loss of $0.2 million during the six months ended June 30, 2010 compared
with income of $8.1 million for the corresponding period in 2009. This decrease in Adjusted EBITDA
was a result of the withdrawal of product from inventory as market conditions changed and commodity
prices were no longer in contango. The increase in product supply in the market place from
inventory liquidation, coupled with lower overall product demand, created additional pressure on
margins, which was partially offset by a 58.4% increase in Energy Services sales volume. The
revenue and expense factors affecting the variance in Adjusted EBITDA are more fully discussed
below.
Revenue. Revenue from the Energy Services segment was $1,070.2 million for the six
months ended June 30, 2010, which is an increase of $600.0 million, or 127.6%, from the
corresponding period in 2009. This increase was primarily due to an increase in refined petroleum
product prices in the 2010 period, which correspondingly increased the cost of product sales, and
an increase of 58.4% in sales volumes.
Total Costs and Expenses. Total costs and expenses from the Energy Services segment
were $1,073.4 million for the six months ended June 30, 2010, which is an increase of $608.2
million, or 130.7%, from the corresponding period in 2009. The increase in total costs and
expenses was primarily due to an increase of $609.6 million in cost of product sales as a result of
increased volumes sold and an increase in refined petroleum product prices and an increase of $0.7
million in bad debt expense, partially offset by a decrease of $1.4 million in maintenance
materials expense and professional fees. Total costs and expenses also include an increase of $0.5
million in depreciation and
48
amortization, partially offset by a decrease of $0.9 million related to an organizational
restructuring recognized in the 2009 period, neither of which are components of Adjusted EBITDA as
presented in the reconciliation above.
Operating Income (loss). Operating loss from the Energy Services segment was $3.2
million for the six months ended June 30, 2010 compared to operating income of $4.9 million for the
six months ended June 30, 2009. Depreciation and amortization increased by $0.5 million for the
six months ended June 30, 2010 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. Adjusted EBITDA from the Development & Logistics segment of $1.5
million for the six months ended June 30, 2010 decreased by $1.8 million, or 54.4%, from $3.3
million for the corresponding period in 2009, primarily due to reduced construction contract
margins of $2.5 million and reduced operating contract margins of $0.4 million, partially offset by
a net increase of $1.2 million related to the sale of ammonia linefill. The revenue and expense
factors affecting the variance in Adjusted EBITDA are more fully discussed below.
Revenue. Revenue from the Development & Logistics segment was $18.3 million for the
six months ended June 30, 2010, which is an increase of $0.4 million, or 2.1%, from the
corresponding period in 2009. The increase in revenue was partially due to the recognition of $1.2
million of revenue related to the sale of ammonia linefill. In addition, operating service
revenues increased by $2.0 million from the 2009 period, primarily due to the assignment of certain
service contracts from the Pipeline Operations segment to the Development & Logistics segment.
These increases in revenue were partially offset by reduced construction contract activity
following completion of certain construction projects in 2009, resulting in a $3.6 million
reduction in certain construction contract revenues.
Total Costs and Expenses. Total costs and expenses from the Development & Logistics
segment were $16.2 million for the six months ended June 30, 2010, which is consistent with the
corresponding period in 2009. Total costs and expenses include $1.4 million of expense related to
an organizational restructuring recognized in the 2009 period, which is not a component of Adjusted
EBITDA as presented in the reconciliation above. Total costs and expenses increased as a result of
the recognition of $2.4 million of expenses related to the write-off in the 2010 period of a
portion of an outstanding receivable balance and other costs associated with a customer bankruptcy,
and increased operating services activities discussed above, partially offset by reduced contract
construction activity discussed above and lower income tax expense.
Operating Income. Operating income from the Development & Logistics segment was $2.1
million for the six months ended June 30, 2010 compared to operating income of $1.7 million for the
six months ended June 30, 2009. Income tax expense decreased by $0.8 million for the six months
ended June 30, 2010, primarily due to the recognition of a tax benefit of $0.6 million primarily
related to the write-off of a portion of an outstanding receivable balance and other costs
associated with a customer bankruptcy as discussed above. 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 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. BES funds its working capital
needs principally from its operations and the BES Credit Agreement. Our financial policy has been
to fund sustaining capital expenditures with cash from operations. Expansion and cost improvement
capital expenditures, along with acquisitions, have typically been funded from external sources
including the Credit Facility as well as debt and equity offerings. Our goal has been to fund at
least half of these expenditures with proceeds from equity offerings in order to maintain our
investment-grade credit rating.
49
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 June 30, 2010, we had $12.5 million of cash and cash equivalents on hand and approximately
$580.0 million of available credit under the Credit Facility, after application of the facilitys
funded debt ratio covenant. In addition, at June 30, 2010, BES had $20.6 million of available
credit under the BES Credit Agreement, pursuant to certain borrowing base calculations under that
agreement.
At June 30, 2010, we had an aggregate face amount of $1,619.2 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); and |
|
|
|
$194.2 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 $1,672.6
million and $1,762.1 million at June 30, 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.
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.
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):
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
|
2010 |
|
|
2009 |
|
Cash provided by (used in): |
|
|
|
|
|
|
|
|
Operating activities |
|
$ |
233,779 |
|
|
$ |
102,577 |
|
Investing activities |
|
|
(5,298 |
) |
|
|
(43,678 |
) |
Financing activities |
|
|
(250,567 |
) |
|
|
(95,745 |
) |
50
Operating Activities
Net cash flow provided by operating activities was $233.8 million for the six months ended
June 30, 2010 compared to $102.6 million for the six months ended June 30, 2009. The following
were the principal factors resulting in the $131.2 million increase in net cash flows provided by
operating activities:
|
|
|
The net change in fair values of derivatives was a decrease of $12.9 million to cash
flows from operating activities for the six months ended June 30, 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 $96.2 million to cash
flows from operating activities for the six months ended June 30, 2010. The principal
factors affecting the working capital changes were: |
|
|
|
Prepaid and other current assets decreased by $36.7 million
primarily due to a decrease in margin deposits on futures contracts in our
Energy Services segment as a result of increased commodity prices during the
six months ended June 30, 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, a decrease in receivables related to ammonia contracts and
a decrease in prepaid insurance due to continued amortization of the balance
over the policy period. |
|
|
|
Inventories decreased by $28.1 million due to a decrease in
volume of hedged inventory stored by the Energy Services segment. From time to
time, the Energy Services segment stores hedged inventory to attempt to capture
value when market conditions are economically favorable. |
|
|
|
Trade receivables decreased by $10.6 million primarily due to
the timing of collections from customers, partially offset by increased
activity from our Energy Services segment due to higher volumes and higher
commodity prices in the 2010 period. |
|
|
|
Accrued and other current liabilities increased by $10.8
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
six months ended June 30, 2010 for which the customer is billed up front for
services provided over the entire term of the contract, partially offset by the
payment of accrued ammonia purchases during the period and a reduction in the
reorganization accrual. |
|
|
|
Accounts payable increased by $7.6 million primarily due to
higher payable balances at June 30, 2010 as a result of increased trading
activity at BES resulting from increased volumes and increased commodity prices
during the period. |
|
|
|
Construction and pipeline relocation receivables decreased by
$2.5 million primarily due to a decrease in construction activity in the 2010
period. |
Investing Activities
Net cash flow used in investing activities was $5.3 million for the six months ended June 30,
2010 compared to $43.7 million for the six months ended June 30, 2009. The following were the
principal factors resulting in the $38.4 million decrease in net cash flows used in investing
activities:
|
|
|
Capital expenditures decreased by $12.2 million for the six months ended June 30,
2010 compared with the six months ended June 30, 2009. See below for a discussion of
capital spending. |
|
|
|
We contributed $3.9 million to West Texas LPG Pipeline Limited Partnership in the
six months ended June 30, 2009 for our pro-rata share of an expansion project required
to meet increased pipeline demand caused by increased product production in the Fort
Worth basin and East Texas regions. |
|
|
|
Cash proceeds from the sale of the Buckeye NGL Pipeline were $22.0 million during
the six months ended June 30, 2010. |
51
Capital expenditures, net of non-cash changes in accruals for capital expenditures, were as
follows for the periods indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
|
2010 |
|
|
2009 |
|
Sustaining capital expenditures |
|
$ |
9,195 |
|
|
$ |
7,773 |
|
Expansion and cost reduction |
|
|
18,377 |
|
|
|
32,046 |
|
|
|
|
|
|
|
|
Total capital expenditures, net |
|
$ |
27,572 |
|
|
$ |
39,819 |
|
|
|
|
|
|
|
|
Expansion and cost reduction projects in the first six months of 2010 included terminal
ethanol and butane blending, new pipeline connections, natural gas storage well recompletions,
continued progress on a new pipeline and terminal billing system as well as various other operating
infrastructure projects. In the first six months 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 $75.0 million to $95.0 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 $50.0 million to $60.0 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, various
terminal expansions and upgrades and pipeline and terminal automation projects.
Financing Activities
Net cash flow used in financing activities was $250.6 million for the six months ended June
30, 2010 compared to $95.7 million for the six months ended June 30, 2009. The following were the
principal factors resulting in the $154.9 million increase in net cash flows used in financing
activities:
|
|
|
We borrowed $95.0 million and $77.3 million and repaid $173.0 million and $166.6
million under the Credit Facility during the six months ended June 30, 2010 and 2009,
respectively. |
|
|
|
Net repayments under the BES Credit Agreement were $45.6 million during the six
months ended June 30, 2010, while net borrowings under the BES Credit Agreement were
$3.0 million during the six months ended June 30, 2009. |
|
|
|
We incurred $3.2 million of debt issuance costs during the six months ended June 30,
2010 related to the amendment to the BES Credit Agreement in June 2010 (see Note 10 in
the Notes to Unaudited Condensed Consolidated Financial Statements). |
|
|
|
We received $3.0 million in net proceeds from the exercise of LP Unit options during
the six months ended June 30, 2010. We received $104.8 million in net proceeds from an
underwritten equity offering in March and April of 2009 for the public issuance of 3.0
million LP Units. |
|
|
|
Cash distributions paid to our partners increased by $11.3 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 $122.9
million ($1.8875 per LP Unit) and $111.6 million ($1.7875 per LP Unit) during the six
months ended June 30, 2010 and 2009, respectively. |
|
|
|
We paid $1.3 million of costs associated with the Merger during the six months ended
June 30, 2010. |
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.
52
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 our 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 June 30, 2010 and 2009 was $5.5 million and
$5.1 million, respectively. For the six months ended June 30, 2010 and 2009, total rental expense
was $10.5 million and $10.3 million, respectively. There have been no material changes in our
operating lease commitments since those reported in our Annual Report on Form 10-K for the year
ended 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.
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.
53
As of June 30, 2010, the Natural Gas Storage segment has recorded the following assets and
liabilities related to its hub services agreements (in thousands):
|
|
|
|
|
|
|
June 30, |
|
|
|
2010 |
|
Assets: |
|
|
|
|
Hub service agreements |
|
$ |
32,394 |
|
|
|
|
|
|
Liabilities: |
|
|
|
|
Hub service agreements |
|
|
(26,750 |
) |
|
|
|
|
Total |
|
$ |
5,644 |
|
|
|
|
|
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.
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 condensed consolidated
balance sheet with gains and losses being recognized in earnings during the period.
As of June 30, 2010, the Energy Services segment had derivative assets and liabilities as
follows (in thousands):
|
|
|
|
|
|
|
June 30, |
|
|
|
2010 |
|
Assets: |
|
|
|
|
Fixed-price sales contracts |
|
$ |
5,121 |
|
Futures contracts for inventory and fixed-price sales contracts |
|
|
4,973 |
|
|
|
|
|
|
Liabilities: |
|
|
|
|
Fixed-price sales contracts |
|
|
(166 |
) |
Futures contracts for inventory and fixed-price sales contracts |
|
|
(202 |
) |
|
|
|
|
Total |
|
$ |
9,726 |
|
|
|
|
|
Our hedged inventory portfolio extends to the first quarter of 2011. The majority of the
unrealized income at June 30, 2010 for inventory hedges represented by futures contracts will be
realized by the third quarter of 2010 as the related inventory is sold. Gains recorded on
inventory hedges that were ineffective were approximately $1.0 million and $5.8 million for the
three and six months ended June 30, 2010, respectively. At June 30, 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 October 2011. In addition, at June 30, 2010, we had refined petroleum product inventories
which we intend to use to satisfy a portion of the fixed-price sales contracts.
54
Based on a hypothetical 10% movement in the underlying quoted market prices of the commodity
financial instruments outstanding at June 30, 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) |
|
Asset |
|
$ |
9,726 |
|
Fair value assuming 10% increase in underlying
commodity prices |
|
Liability |
|
$ |
(3,589 |
) |
Fair value assuming 10% decrease in underlying
commodity prices |
|
Asset |
|
$ |
23,044 |
|
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.
As discussed above, these commodity financial instruments are used primarily to manage the
risk of market price volatility on the Energy Services segment 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 and are, therefore, expected to
be highly effective in offsetting changes in the fair value of the refined petroleum product
inventories.
Interest Rate Risk
We utilize forward-starting interest rate swaps to manage interest rate risk related to
forecasted interest payments on anticipated debt issuances. This strategy is a component in
controlling our cost of capital associated with such borrowings. When entering into interest rate
swap transactions, we become exposed to both credit risk and market risk. We are subject to credit
risk when the value of the swap transaction is positive and the risk exists that the counterparty
will fail to perform under the terms of the contract. We are subject to market risk with respect
to changes in the underlying benchmark interest rate that impact the fair value of the swaps. We
manage our credit risk by only entering into swap transactions with major financial institutions
with investment-grade credit ratings. We manage our market risk by associating each swap
transaction with an existing debt obligation or a specified expected debt issuance generally
associated with the maturity of an existing debt obligation.
Our practice with respect to derivative transactions related to interest rate risk has been to
have each transaction in connection with non-routine borrowings authorized by the board of
directors of Buckeye GP. In January 2009, Buckeye GPs board of directors adopted an interest rate
hedging policy which permits us to enter into certain short-term interest rate hedge agreements to
manage our interest rate and cash flow risks associated with the Credit Facility. In addition, in
July 2009 and May 2010, Buckeye GPs board of directors authorized us to enter into certain
transactions, such as forward starting interest rate swaps, to manage our interest rate and cash
flow risks related to certain expected debt issuances associated with the maturity of existing debt
obligations.
At June 30, 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
June 30, 2010 was approximately $1,478.4 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 $87.3 million.
55
At June 30, 2010, our variable-rate obligation was $194.2 million under the BES Credit
Agreement. Based on the balance outstanding at June 30, 2010, we estimate that a 1% increase or
decrease in interest rates would increase or decrease annual interest expense by approximately $1.9
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. During the three months
ended June 30, 2010, we entered into two forward-starting interest rate swaps with a total
aggregate notional amount of $100.0 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 $125.0 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 and six months ended June 30, 2010, unrealized losses of
$34.9 million and $36.2 million, respectively, were recorded in accumulated other comprehensive
income (loss) to reflect the change in the fair values of the forward-starting interest rate swaps.
We designated the swap agreements as cash flow hedges at inception and expect the changes in
values to be highly correlated with the changes in value of the underlying borrowings.
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 June 30, 2010 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Financial |
|
|
|
|
|
Instrument |
|
|
|
Resulting |
|
Portfolio |
|
Scenario |
|
Classification |
|
Fair Value |
|
Fair value assuming no change in underlying
interest rates (as is) |
|
Liability |
|
$ |
(18,953 |
) |
Fair value assuming 10% increase in underlying
interest rates |
|
Asset |
|
$ |
414 |
|
Fair value assuming 10% decrease in underlying
interest rates |
|
Liability |
|
$ |
(39,148 |
) |
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.
56
(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 second
quarter of 2010, that have materially affected, or are reasonably likely to materially affect, our
internal controls over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
For information on legal proceedings, see Part 1, Item 1, Financial Statements, Note 3,
Commitments and Contingencies in the Notes to Unaudited Condensed Consolidated Financial
Statements included in this quarterly report, which is incorporated into this item by reference.
Item 1A. Risk Factors
Security holders and potential investors in our securities should carefully consider the risk
factors set forth below and 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.
While the Merger Agreement is in effect, BGHs opportunities to enter into different business
combination transactions with other parties on more favorable terms may be limited, and both we and
BGH may be limited in our ability to pursue other attractive business opportunities.
While the Merger Agreement is in effect, BGH is prohibited from knowingly initiating,
soliciting or encouraging the submission of any acquisition proposal or from participating in any
discussions or negotiations regarding any acquisition proposal, subject to certain exceptions. As
a result of these provisions in the Merger Agreement, BGHs opportunities to enter into more
favorable transactions may be limited. Likewise, if BGH were to sell directly to a third party, it
might have received more value with respect to the general partner interest in us and the incentive
distribution rights in us based on the value of the business at such time.
Moreover, the Merger Agreement provides for the payment of up to $29.0 million in termination
fees under specified circumstances, which may discourage other parties from proposing alternative
transactions that could be more favorable to the BGH unitholders or our unitholders.
Both we and BGH have also agreed to refrain from taking certain actions with respect to our
businesses and financial affairs pending completion of the Merger or termination of the Merger
Agreement. These restrictions could be in effect for an extended period of time if completion of
the Merger is delayed. These limitations do not preclude us from conducting our business in the
ordinary or usual course or from acquiring assets or businesses so long as such activity does not
have a material adverse effect as such term is defined in the Merger Agreement or materially
affect our or BGHs ability to complete the transactions contemplated by the Merger Agreement.
In addition to the economic costs associated with pursuing the Merger, the management of BGHs
general partner and our general partner will continue to devote substantial time and other human
resources to the proposed Merger, which could limit BGHs and our ability to pursue other
attractive business opportunities, including potential joint ventures, stand-alone projects and
other transactions. If either we or BGH are unable to pursue such other attractive business
opportunities, then our growth prospects and the long-term strategic position of our businesses
following the Merger could be adversely affected.
Our existing unitholders will be diluted by the Merger.
The Merger will dilute the ownership position of our existing unitholders. Pursuant to the
Merger Agreement, BGHs unitholders will receive approximately 20.0 million of our LP Units as a
result of the Merger. Immediately
57
following the Merger, we will be owned approximately 72% by our current unitholders and
approximately 28% by former BGH unitholders.
The number of our outstanding LP Units will increase as a result of the Merger, which could
make it more difficult to pay the current level of quarterly distributions.
As of August 3, 2010, there were approximately 51.5 million of our LP Units outstanding. We
will issue approximately 20.0 million of our LP Units in connection with the Merger. Accordingly,
the dollar amount required to pay the current per LP Unit quarterly distributions will increase,
which will increase the likelihood that we will not have sufficient funds to pay the current level
of quarterly distributions to all of our unitholders. Using the amount of $0.9625 per LP Unit
declared with respect to the second quarter of 2010, the aggregate cash distribution to be paid to
our unitholders will total approximately $49.6 million, resulting in a distribution of $13.1
million to our general partner for its general partner units and incentive distribution rights.
Therefore, our combined total distribution to be paid with respect to the second quarter of 2010
will be $62.7 million. Pursuant to the Merger Agreement, BGH unitholders will receive
approximately 20.0 million of our LP Units as a result of the Merger. Our combined pro forma
distribution with respect to the second quarter 2010, had the Merger been completed prior to such
distribution, would result in $0.9625 per LP Unit being distributed on approximately 71.5 million
of our LP Units, or a total of $68.8 million, with our general partner no longer receiving any
distributions. As a result, we would be required to distribute an additional $6.1 million per
quarter in order to maintain the distribution level of $0.9625 per LP Unit paid with respect to the
second quarter of 2010.
Although the elimination of the incentive distribution rights may increase the cash available
for distribution to our LP Units in the future, this source of funds may not be sufficient to meet
the overall increase in cash required to maintain the current level of quarterly distributions to
holders of our LP Units.
Failure to complete the Merger or delays in completing the Merger could negatively impact our
LP Unit price and the BGH unit price.
If the Merger is not completed for any reason, we and BGH may be subject to a number of
material risks, including the following:
|
|
|
we will not realize the benefits expected from the Merger, including a potentially
enhanced financial and competitive position; |
|
|
|
|
the price of our LP Units or BGH units may decline to the extent that the current
market price of these securities reflects a market assumption that the Merger will be
completed; and |
|
|
|
|
some costs relating to the Merger, such as certain investment banking fees and legal
and accounting fees, must be paid even if the Merger is not completed. |
The costs of the Merger could adversely affect our operations and cash flows available for
distribution to our unitholders.
We and BGH estimate the total costs of the Merger to be approximately $12.0 million, primarily
consisting of investment banking and legal advisors fees, accounting fees, financial printing and
other related costs. These costs could adversely affect our operations and cash flows available
for distributions to our unitholders. The foregoing estimate is preliminary and is subject to
change.
Tax Risks Related to the Merger
No ruling has been obtained with respect to the tax consequences of the Merger.
No ruling has been or will be requested from the Internal Revenue Service (IRS) with respect
to the tax consequences of the Merger. Instead, we and BGH are relying on the opinions of our
respective counsel as to the tax consequences of the Merger, and counsels conclusions may not be
sustained if challenged by the IRS.
58
The intended tax consequences of the Merger are dependent upon our and BGH being treated as
partnerships for tax purposes.
The treatment of the Merger as nontaxable to our unitholders and BGHs unitholders is
dependent upon each of us and BGH being treated as a partnership for federal income tax purposes.
If either we or BGH were treated as a corporation for federal income tax purposes, the consequences
of the Merger would be materially different and the Merger would likely be a fully taxable
transaction to a BGH unitholder.
Tax Risks to Existing Buckeye Unitholders
An existing holder of our LP Units may be required to recognize a gain as a result of the
decrease in its allocable share of our nonrecourse liabilities as a result of the Merger.
As a result of the Merger, the allocable share of nonrecourse liabilities allocated to our
existing unitholders will be recalculated to take into account the LP Units issued by us in the
Merger. If an existing holder of our LP Units experiences a reduction in its share of our
nonrecourse liabilities as a result of the Merger, which is referred to as a reducing debt shift,
such holder will be deemed to have received a cash distribution equal to the amount of the
reduction. A reduction in a unitholders share of our liabilities will result in a corresponding
basis reduction in such unitholders LP Units. A reducing debt shift and the resulting deemed cash
distribution may, under certain circumstances, result in the recognition of taxable gain by a
holder of our LP Units, to the extent that the deemed cash distribution exceeds such unitholders
tax basis in its LP Units. Although we have not received an opinion with respect to the shift of
nonrecourse liabilities, we do not expect that any constructive cash distribution will exceed any
existing unitholders tax basis in its LP Units.
We estimate that the Merger will result in an increase in the amount of net income (or
decrease in the amount of net loss) allocable to all of our existing unitholders.
We estimate that the closing of the Merger will result in an increase in the amount of net
income (or decrease in the amount of net loss) allocable to all of our existing unitholders. In
addition, the federal income tax liability of an existing unitholder could be further increased if
we make a future offering of LP Units and use the proceeds of the offering in a manner that does
not produce substantial additional deductions, such as to repay indebtedness currently outstanding
or to acquire property that is not eligible for depreciation or amortization for federal income tax
purposes or that is depreciable or amortizable at a rate significantly slower than the rate
currently applicable to our assets.
59
Item 6. Exhibits
(a) Exhibits
|
|
|
2.1
|
|
Agreement and Plan of Merger, dated June 10, 2010, by and among Buckeye
Partners, L.P., Buckeye GP LLC, Buckeye GP Holdings L.P., MainLine Management
LLC and Grand Ohio, LLC, a subsidiary of Buckeye Partners, L.P. (Incorporated
by reference to Exhibit 2.1 of Buckeye Partners, L.P.s Current Report on Form
8-K filed on June 11, 2010). |
|
|
|
*10.1
|
|
Buckeye Partners, L.P. Annual Incentive Compensation Plan, as Amended and
Restated, effective as of May 6, 2010 (Incorporated by reference to Exhibit
10.15 of Buckeye Partners, L.P.s Registration Statement on Form S-4 filed on
July 14, 2010). |
|
|
|
10.2
|
|
Amended and Restated Credit Agreement, dated as of June 25, 2010, among
Buckeye Energy Services LLC, BNP Paribas and other lenders party thereto
(Incorporated by reference to Exhibit 10.1 of Buckeye Partners, L.P.s Current
Report on Form 8-K filed on July 1, 2010). |
|
|
|
10.3
|
|
Support Agreement, by and among Buckeye Partners, L.P., BGH GP Holdings, LLC,
ArcLight Energy Partners Fund III, L.P., ArcLight Energy Partners Fund IV,
L.P., Kelso Investment Associates VIII, L.P. and KEP VI, LLC (Incorporated by
reference to Exhibit 10.1 of Buckeye Partners, L.P.s Current Report on Form
8-K filed on June 11, 2010). |
|
|
|
10.4
|
|
Registration Rights Agreement, by and among Buckeye Partners, L.P., BGH GP
Holdings, LLC, ArcLight Energy Partners Fund III, L.P., ArcLight Energy
Partners Fund IV, L.P., Kelso Investment Associates VIII, L.P. and KEP VI, LLC
(Incorporated by reference to Exhibit 10.2 of Buckeye Partners, L.P.s Current
Report on Form 8-K filed on June 11, 2010). |
|
|
|
**31.1
|
|
Certification of Chief Executive Officer pursuant to Rule 13a-14 (a) under the
Securities Exchange Act of 1934. |
|
|
|
**31.2
|
|
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the
Securities Exchange Act of 1934. |
|
|
|
**32.1
|
|
Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350. |
|
|
|
**32.2
|
|
Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350. |
|
|
|
**101.INS
|
|
XBRL Instance Document. |
|
|
|
**101.SCH
|
|
XBRL Taxonomy Extension Schema Document. |
|
|
|
**101.CAL
|
|
XBRL Taxonomy Extension Calculation Linkbase Document. |
|
|
|
**101.LAB
|
|
XBRL Taxonomy Extension Label Linkbase Document. |
|
|
|
**101.PRE
|
|
XBRL Taxonomy Extension Presentation Linkbase Document. |
|
|
|
**101.DEF
|
|
XBRL Taxonomy Extension Definition Linkbase Document. |
|
|
|
* |
|
Represents management contract or compensatory plan or arrangement. |
|
** |
|
Filed herewith. |
|
|
|
Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. Buckeye agrees to
furnish supplementally a copy of the omitted schedules to the SEC upon request. |
60
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: August 6, 2010 |
By: |
/s/ Keith E. St.Clair
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Keith E. St.Clair |
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Senior Vice President and Chief Financial Officer
(Principal Accounting Officer and Principal
Financial Officer) |
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