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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the quarterly period ended | ||
| ||
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
Commission file number: 1-14569
PLAINS ALL AMERICAN PIPELINE, L.P.
(Exact name of registrant as specified in its charter)
Delaware | 76-0582150 | |
(State or other jurisdiction of | (I.R.S. Employer | |
333 Clay Street, Suite 1600
Houston, Texas 77002
(Address of principal executive offices)
(Zip Code)
(713) 646-4100
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes /x/x No / /o
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes ýx No o
At MayAugust 2, 2005, there were outstanding 67,868,10867,914,576 Common Units.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
Page | |||||||
June 30, 2005 and December 31, 2004 | 3 | ||||||
For the three months and six months ended | 4 | ||||||
For the | 5 | ||||||
Consolidated Statement of | 6 | ||||||
For the three months and six months ended | 7 | ||||||
7 | |||||||
8 | |||||||
20 | |||||||
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS | 38 | ||||||
38 | |||||||
40 | |||||||
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds | 40 | ||||||
40 | |||||||
41 | |||||||
41 | |||||||
41 | |||||||
42 |
2
Item 1. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except unit data)
|
| June 30, |
| December 31, |
| ||||
|
| 2005 |
| 2004 |
| ||||
|
| (unaudited) |
| ||||||
ASSETS |
|
|
|
|
|
|
| ||
CURRENT ASSETS |
|
|
|
|
|
|
| ||
Cash and cash equivalents |
| $ | 38,000 |
|
| $ | 12,988 |
|
|
Trade accounts receivable, net |
| 1,035,774 |
|
| 521,785 |
|
| ||
Inventory |
| 848,173 |
|
| 498,200 |
|
| ||
Other current assets |
| 107,568 |
|
| 68,229 |
|
| ||
Total current assets |
| 2,029,515 |
|
| 1,101,202 |
|
| ||
PROPERTY AND EQUIPMENT |
| 2,012,677 |
|
| 1,911,509 |
|
| ||
Accumulated depreciation |
| (218,626 | ) |
| (183,887 | ) |
| ||
|
| 1,794,051 |
|
| 1,727,622 |
|
| ||
OTHER ASSETS |
|
|
|
|
|
|
| ||
Pipeline linefill in owned assets |
| 165,957 |
|
| 168,352 |
|
| ||
Inventory in third party assets |
| 61,351 |
|
| 59,279 |
|
| ||
Other, net |
| 83,664 |
|
| 103,956 |
|
| ||
Total assets |
| $ | 4,134,538 |
|
| $ | 3,160,411 |
|
|
LIABILITIES AND PARTNERS’ CAPITAL |
|
|
|
|
|
|
| ||
CURRENT LIABILITIES |
|
|
|
|
|
|
| ||
Accounts payable |
| $ | 1,141,364 |
|
| $ | 850,912 |
|
|
Due to related parties |
| 40,917 |
|
| 32,897 |
|
| ||
Short-term debt |
| 820,769 |
|
| 175,472 |
|
| ||
Other current liabilities |
| 147,992 |
|
| 54,436 |
|
| ||
Total current liabilities |
| 2,151,042 |
|
| 1,113,717 |
|
| ||
LONG-TERM LIABILITIES |
|
|
|
|
|
|
| ||
Long-term debt under credit facilities and other |
| 6,421 |
|
| 151,753 |
|
| ||
Senior notes, net of unamortized discount of $3,267 and $2,729, respectively |
| 946,733 |
|
| 797,271 |
|
| ||
Other long-term liabilities and deferred credits |
| 30,365 |
|
| 27,466 |
|
| ||
Total liabilities |
| 3,134,561 |
|
| 2,090,207 |
|
| ||
COMMITMENTS AND CONTINGENCIES (NOTE 9) |
|
|
|
|
|
|
| ||
PARTNERS’ CAPITAL |
|
|
|
|
|
|
| ||
Common unitholders (67,914,976 and 62,740,218 units outstanding at |
| 970,199 |
|
| 919,826 |
|
| ||
Class B common unitholder (1,307,190 units outstanding at |
| — |
|
| 18,775 |
|
| ||
Class C common unitholders (3,245,700 units outstanding at |
| — |
|
| 100,423 |
|
| ||
General partner |
| 29,778 |
|
| 31,180 |
|
| ||
Total partners’ capital |
| 999,977 |
|
| 1,070,204 |
|
| ||
|
| $ | 4,134,538 |
|
| $ | 3,160,411 |
|
|
The accompanying notes are an integral part of these consolidated financial statements.
3
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit data)
|
| Three Months Ended |
| Six Months Ended |
| ||||||||
|
| June 30, |
| June 30, |
| ||||||||
|
| 2005 |
| 2004 |
| 2005 |
| 2004 |
| ||||
|
| (unaudited) |
| (unaudited) |
| ||||||||
REVENUES |
|
|
|
|
|
|
|
|
| ||||
Crude oil and LPG sales (includes buy/sell transactions of approximately $3,706,119 and $3,450,671 for the three month periods, and $7,125,168 and $5,285,528 for the six month periods, respectively) |
| $ | 6,919,504 |
| $ | 4,931,969 |
| $ | 13,337,293 |
| $ | 8,555,451 |
|
Other gathering, marketing, terminalling and storage revenues |
| 11,323 |
| 9,106 |
| 19,496 |
| 16,727 |
| ||||
Pipeline margin activities revenues (includes buy/sell transactions of approximately $40,049 and $34,924 for the three month periods, and $73,557 and $81,347 for the six month periods, respectively) |
| 174,858 |
| 138,831 |
| 332,485 |
| 281,166 |
| ||||
Pipeline tariff activities revenues |
| 55,022 |
| 51,829 |
| 109,929 |
| 83,035 |
| ||||
Total revenues |
| 7,160,707 |
| 5,131,735 |
| 13,799,203 |
| 8,936,379 |
| ||||
COSTS AND EXPENSES |
|
|
|
|
|
|
|
|
| ||||
Crude oil and LPG purchases and related costs (includes buy/sell transactions of approximately $3,583,578 and $3,374,566 for the three month periods, and $6,984,505 and $5,166,200 for the six month periods, respectively) |
| 6,804,159 |
| 4,859,173 |
| 13,138,805 |
| 8,417,244 |
| ||||
Pipeline margin activities purchases (includes buy/sell transactions of approximately $37,299 and $33,343 for the three month periods, and $68,798 and $77,686 for the six month periods, respectively) |
| 167,531 |
| 132,694 |
| 319,045 |
| 269,128 |
| ||||
Field operating costs (excluding LTIP charge) |
| 66,846 |
| 59,035 |
| 130,322 |
| 95,851 |
| ||||
LTIP charge—operations |
| 975 |
| — |
| 1,319 |
| 567 |
| ||||
General and administrative expenses (excluding LTIP charge) |
| 19,198 |
| 19,603 |
| 39,414 |
| 35,081 |
| ||||
LTIP charge—general and administrative |
| 6,951 |
| — |
| 8,846 |
| 3,661 |
| ||||
Depreciation and amortization |
| 19,448 |
| 15,998 |
| 38,566 |
| 29,118 |
| ||||
Total costs and expenses |
| 7,085,108 |
| 5,086,503 |
| 13,676,317 |
| 8,850,650 |
| ||||
Gain on sales of assets |
| 445 |
| 84 |
| 445 |
| 84 |
| ||||
OPERATING INCOME |
| 76,044 |
| 45,316 |
| 123,331 |
| 85,813 |
| ||||
OTHER INCOME/(EXPENSE) |
|
|
|
|
|
|
|
|
| ||||
Interest expense (net of $346 and $219 capitalized for the three month periods, respectively, and $966 and $397 capitalized for the six month periods, respectively) |
| (14,253 | ) | (9,967 | ) | (28,811 | ) | (19,499 | ) | ||||
Interest and other income (expense), net |
| 491 |
| 328 |
| 570 |
| 369 |
| ||||
Income before cumulative effect of change in accounting principle |
| 62,282 |
| 35,677 |
| 95,090 |
| 66,683 |
| ||||
Cumulative effect of change in accounting principle |
| — |
| — |
| — |
| (3,130 | ) | ||||
NET INCOME |
| $ | 62,282 |
| $ | 35,677 |
| $ | 95,090 |
| $ | 63,553 |
|
NET INCOME—LIMITED PARTNERS |
| $ | 57,602 |
| $ | 33,247 |
| $ | 86,867 |
| $ | 58,954 |
|
NET INCOME—GENERAL PARTNER |
| $ | 4,680 |
| $ | 2,430 |
| $ | 8,223 |
| $ | 4,599 |
|
BASIC NET INCOME PER LIMITED PARTNER UNIT |
|
|
|
|
|
|
|
|
| ||||
Income before cumulative effect of change in accounting principle |
| $ | 0.76 |
| $ | 0.54 |
| $ | 1.27 |
| $ | 1.03 |
|
Cumulative effect of change in accounting principle |
| — |
| — |
| — |
| (0.05 | ) | ||||
Net income |
| $ | 0.76 |
| $ | 0.54 |
| $ | 1.27 |
| $ | 0.98 |
|
DILUTED NET INCOME PER LIMITED PARTNER UNIT |
|
|
|
|
|
|
|
|
| ||||
Income before cumulative effect of change in accounting principle |
| $ | 0.74 |
| $ | 0.54 |
| $ | 1.26 |
| $ | 1.03 |
|
Cumulative effect of change in accounting principle |
| — |
| — |
| — |
| (0.05 | ) | ||||
Net income |
| $ | 0.74 |
| $ | 0.54 |
| $ | 1.26 |
| $ | 0.98 |
|
BASIC WEIGHTED AVERAGE UNITS OUTSTANDING |
| 67,893 |
| 61,556 |
| 67,706 |
| 59,985 |
| ||||
DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING |
| 69,274 |
| 61,556 |
| 68,719 |
| 59,985 |
|
S
The accompanying notes are an integral part of these consolidated financial statements.
4
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
| March 31, 2005 | December 31, 2004 | ||||||
---|---|---|---|---|---|---|---|---|
| (unaudited) | |||||||
ASSETS | ||||||||
CURRENT ASSETS | ||||||||
Cash and cash equivalents | $ | 21,839 | $ | 12,988 | ||||
Trade accounts receivable, net | 1,030,139 | 521,785 | ||||||
Inventory | 711,280 | 498,200 | ||||||
Other current assets | 82,510 | 68,229 | ||||||
Total current assets | 1,845,768 | 1,101,202 | ||||||
PROPERTY AND EQUIPMENT | 1,977,606 | 1,911,509 | ||||||
Accumulated depreciation | (201,657 | ) | (183,887 | ) | ||||
1,775,949 | 1,727,622 | |||||||
OTHER ASSETS | ||||||||
Pipeline linefill in owned assets | 166,147 | 168,352 | ||||||
Inventory in third party assets | 55,271 | 59,279 | ||||||
Other, net | 91,067 | 103,956 | ||||||
Total assets | $ | 3,934,202 | $ | 3,160,411 | ||||
LIABILITIES AND PARTNERS' CAPITAL | ||||||||
CURRENT LIABILITIES | ||||||||
Accounts payable | $ | 1,270,276 | $ | 850,912 | ||||
Due to related parties | 35,277 | 32,897 | ||||||
Short-term debt | 560,962 | 175,472 | ||||||
Other current liabilities | 94,801 | 54,436 | ||||||
Total current liabilities | 1,961,316 | 1,113,717 | ||||||
LONG-TERM LIABILITIES | ||||||||
Long-term debt under credit facilities and other | 132,880 | 151,753 | ||||||
Senior notes, net of unamortized discount of $2,640 and $2,729, respectively | 797,360 | 797,271 | ||||||
Other long-term liabilities and deferred credits | 32,089 | 27,466 | ||||||
Total liabilities | 2,923,645 | 2,090,207 | ||||||
COMMITMENTS AND CONTINGENCIES (NOTE 9) | ||||||||
PARTNERS' CAPITAL | ||||||||
Common unitholders (67,868,108 and 62,740,218 units outstanding at March 31, 2005, and December 31, 2004, respectively) | 980,569 | 919,826 | ||||||
Class B common unitholder (no units and 1,307,190 units outstanding at March 31, 2005 and December 31, 2004, respectively) | — | 18,775 | ||||||
Class C common unitholders (no units and 3,245,700 units outstanding at March 31, 2005 and December 31, 2004, respectively) | — | 100,423 | ||||||
General partner | 29,988 | 31,180 | ||||||
Total partners' capital | 1,010,557 | 1,070,204 | ||||||
$ | 3,934,202 | $ | 3,160,411 | |||||
|
| Six Months Ended |
| ||||
|
| 2005 |
| 2004 |
| ||
|
| (unaudited) |
| ||||
CASH FLOWS FROM OPERATING ACTIVITIES |
|
|
|
|
| ||
Net income |
| $ | 95,090 |
| $ | 63,553 |
|
Adjustments to reconcile to cash flows from operating activities: |
|
|
|
|
| ||
Depreciation and amortization |
| 38,566 |
| 29,118 |
| ||
Cumulative effect of change in accounting principle |
| — |
| 3,130 |
| ||
Change in derivative fair value |
| 26,327 |
| (556 | ) | ||
Long-Term Incentive Plan charge |
| 10,165 |
| 4,228 |
| ||
Noncash amortization of terminated interest rate swap |
| 790 |
| 714 |
| ||
Noncash loss on foreign currency revaluation |
| (918 | ) | (573 | ) | ||
Net cash paid for terminated swaps |
| (865 | ) | — |
| ||
Gain on sales of assets |
| (445 | ) | (84 | ) | ||
Changes in assets and liabilities, net of acquisitions: |
|
|
|
|
| ||
Trade accounts receivable and other |
| (589,411 | ) | (27,918 | ) | ||
Inventory |
| (351,461 | ) | (24,135 | ) | ||
Accounts payable and other current liabilities |
| 311,073 |
| 99,423 |
| ||
Due to related parties |
| 7,697 |
| 210 |
| ||
Net cash provided by (used in) operating activities |
| (453,392 | ) | 147,110 |
| ||
CASH FLOWS FROM INVESTING ACTIVITIES |
|
|
|
|
| ||
Cash paid in connection with acquisitions |
| (14,545 | ) | (443,210 | ) | ||
Additions to property and equipment |
| (86,254 | ) | (32,170 | ) | ||
Proceeds from sales of assets |
| 3,380 |
| 737 |
| ||
Net cash used in investing activities |
| (97,419 | ) | (474,643 | ) | ||
CASH FLOWS FROM FINANCING ACTIVITIES |
|
|
|
|
| ||
Net borrowings/(repayments) on long-term revolving credit facility |
| (143,639 | ) | 415,827 |
| ||
Net borrowings/(repayments) on working capital revolving credit facility |
| 71,800 |
| (12,100 | ) | ||
Net borrowings/(repayments) on short-term letter of credit and hedged inventory facility |
| 575,300 |
| (96,091 | ) | ||
Proceeds from the issuance of senior notes |
| 149,277 |
| — |
| ||
Net proceeds from the issuance of common units |
| 22,308 |
| 101,213 |
| ||
Distributions paid to unitholders and general partner |
| (92,657 | ) | (72,673 | ) | ||
Other financing activities |
| (5,826 | ) | (2,141 | ) | ||
Net cash provided by financing activities |
| 576,563 |
| 334,035 |
| ||
Effect of translation adjustment on cash |
| (740 | ) | 1,417 |
| ||
Net increase in cash and cash equivalents |
| 25,012 |
| 7,919 |
| ||
Cash and cash equivalents, beginning of period |
| 12,988 |
| 4,137 |
| ||
Cash and cash equivalents, end of period |
| $ | 38,000 |
| $ | 12,056 |
|
Cash paid for interest, net of amounts capitalized |
| $ | 35,825 |
| $ | 20,547 |
|
The accompanying notes are an integral part of these consolidated financial statements.
5
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total |
| |||||
|
|
|
|
|
| Class B |
| Class C |
| General |
|
|
| Partners' |
| |||||||||
|
| Common Units |
| Common Units |
| Common Units |
| Partner |
| Total |
| Capital |
| |||||||||||
|
| Units |
| Amount |
| Units |
| Amount |
| Units |
| Amount |
| Amount |
| Units |
| Amount |
| |||||
|
| (unaudited) |
| |||||||||||||||||||||
Balance at December 31, 2004 |
| 62,740 |
| $ | 919,826 |
| 1,307 |
| $ | 18,775 |
| 3,246 |
| $ | 100,423 |
| $ | 31,180 |
| 67,293 |
| $ | 1,070,204 |
|
Private placement of common units |
| 575 |
| 21,860 |
| — |
| — |
| — |
| — |
| 448 |
| 575 |
| 22,308 |
| |||||
Conversion of Class B Units |
| 1,307 |
| 18,323 |
| (1,307 | ) | (18,323 | ) | — |
| — |
| — |
| — |
| — |
| |||||
Conversion of Class C Units |
| 3,246 |
| 99,302 |
| — |
| — |
| (3,246 | ) | (99,302 | ) | — |
| — |
| — |
| |||||
LTIP Issuance |
| 47 |
| 1,863 |
| — |
| — |
| — |
| — |
| 38 |
| 47 |
| 1,901 |
| |||||
Distributions |
| — |
| (81,694 | ) | — |
| (801 | ) | — |
| (1,988 | ) | (8,174 | ) | — |
| (92,657 | ) | |||||
Net income |
| — |
| 84,958 |
| — |
| 548 |
| — |
| 1,361 |
| 8,223 |
| — |
| 95,090 |
| |||||
Other comprehensive income |
| — |
| (94,239 | ) | — |
| (199 | ) | — |
| (494 | ) | (1,937 | ) | — |
| (96,869 | ) | |||||
Balance at June 30, 2005 |
| 67,915 |
| $ | 970,199 |
| — |
| $ | — |
| — |
| $ | — |
| $ | 29,778 |
| 67,915 |
| $ | 999,977 |
|
The accompanying notes are an integral part of these consolidated financial statements.
6
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONSCOMPREHENSIVE INCOME AND
CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME
(in thousands, except per unit data)
thousands)
Statements of Comprehensive Income
| Three Months Ended March 31, | |||||||
---|---|---|---|---|---|---|---|---|
| 2005 | 2004 | ||||||
| (unaudited) | |||||||
REVENUES | ||||||||
Crude oil and LPG sales (includes approximately $3,419,049 and $1,834,857, respectively, related to buy/sell transactions) | $ | 6,417,789 | $ | 3,623,482 | ||||
Other gathering, marketing, terminalling and storage revenues | 8,173 | 7,621 | ||||||
Pipeline margin activities revenues (includes approximately $33,508 and $46,424, respectively, related to buy/sell transactions) | 157,627 | 142,335 | ||||||
Pipeline tariff activities revenues | 54,907 | 31,206 | ||||||
Total revenues | 6,638,496 | 3,804,644 | ||||||
COSTS AND EXPENSES | ||||||||
Crude oil and LPG purchases and related costs (includes purchases of approximately $3,397,536 and $1,791,634, respectively, related to buy/sell transactions) | 6,334,646 | 3,557,071 | ||||||
Pipeline margin activities purchases (includes approximately $31,499 and $44,343, respectively, related to buy/sell transactions) | 151,514 | 136,434 | ||||||
Field operating costs (excluding LTIP charge) | 63,476 | 37,816 | ||||||
LTIP charge—operations | 344 | 567 | ||||||
General and administrative expenses (excluding LTIP charge) | 20,216 | 15,478 | ||||||
LTIP charge—general and administrative | 1,895 | 3,661 | ||||||
Depreciation and amortization | 19,118 | 13,120 | ||||||
Total costs and expenses | 6,591,209 | 3,764,147 | ||||||
OPERATING INCOME | 47,287 | 40,497 | ||||||
OTHER INCOME (EXPENSE) | ||||||||
Interest expense (net of capitalized interest of $620 and $178, respectively) | (14,558 | ) | (9,532 | ) | ||||
Interest and other income (expense), net | 79 | 41 | ||||||
Income before cumulative effect of change in accounting principle | 32,808 | 31,006 | ||||||
Cumulative effect of change in accounting principle | — | (3,130 | ) | |||||
NET INCOME | $ | 32,808 | $ | 27,876 | ||||
NET INCOME—LIMITED PARTNERS | $ | 29,265 | $ | 25,707 | ||||
NET INCOME—GENERAL PARTNER | $ | 3,543 | $ | 2,169 | ||||
BASIC NET INCOME PER LIMITED PARTNER UNIT | ||||||||
Income before cumulative effect of change in accounting principle | $ | 0.43 | $ | 0.49 | ||||
Cumulative effect of change in accounting principle | — | (0.05 | ) | |||||
Basic net income per limited partner unit | $ | 0.43 | $ | 0.44 | ||||
DILUTED NET INCOME PER LIMITED PARNTER UNIT | ||||||||
Income before cumulative effect of change in accounting principle | $ | 0.43 | $ | 0.49 | ||||
Cumulative effect of change in accounting principle | — | (0.05 | ) | |||||
Diluted net income per limited partner unit | $ | 0.43 | $ | 0.44 | ||||
BASIC WEIGHTED AVERAGE UNITS OUTSTANDING | 67,517 | 58,414 | ||||||
DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING | 68,156 | 59,017 | ||||||
|
| Three Months Ended |
| Six Months Ended |
| ||||||||||||
|
| June 30, |
| June 30, |
| ||||||||||||
|
| 2005 |
| 2004 |
| 2005 |
| 2004 |
| ||||||||
|
| (unaudited) |
| ||||||||||||||
Net income |
| $ | 62,282 |
|
| $ | 35,677 |
|
|
| $ | 95,090 |
|
| $ | 63,553 |
|
Other comprehensive income (loss) |
| (27,111 | ) |
| 14,047 |
|
|
| (96,869 | ) |
| 3,233 |
| ||||
Comprehensive income (loss) |
| $ | 35,171 |
|
| $ | 49,724 |
|
|
| $ | (1,779 | ) |
| $ | 66,786 |
|
Statement of Changes in Accumulated Other Comprehensive Income
|
| Net Deferred |
| Currency |
| Total |
| |||||||
|
| (unaudited) |
| |||||||||||
Balance at December 31, 2004 |
|
| $ | 25,937 |
|
|
| $ | 70,934 |
|
| $ | 96,871 |
|
Current period activity: |
|
|
|
|
|
|
|
|
|
|
| |||
Reclassification adjustments for settled contracts |
|
| (568 | ) |
|
| — |
|
| (568 | ) | |||
Changes in fair value of outstanding hedge positions |
|
| (88,082 | ) |
|
| — |
|
| (88,082 | ) | |||
Currency translation adjustment |
|
| — |
|
|
| (8,219 | ) |
| (8,219 | ) | |||
Total period activity |
|
| (88,650 | ) |
|
| (8,219 | ) |
| (96,869 | ) | |||
Balance at June 30, 2005 |
|
| $ | (62,713 | ) |
|
| $ | 62,715 |
|
| $ | 2 |
|
The accompanying notes are an integral part of these consolidated financial statements.
7
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF CASH FLOWS(in thousands)
| Three Months Ended March 31, | ||||||||
---|---|---|---|---|---|---|---|---|---|
| 2005 | 2004 | |||||||
| (unaudited) | ||||||||
CASH FLOWS FROM OPERATING ACTIVITIES | |||||||||
Net income | $ | 32,808 | 27,876 | ||||||
Adjustments to reconcile to cash flows from operating activities: | |||||||||
Depreciation and amortization | 19,118 | 13,120 | |||||||
Cumulative effect of change in accounting principle | — | 3,130 | |||||||
Change in derivative fair value | 13,406 | (7,498 | ) | ||||||
LTIP charge | 2,239 | 4,228 | |||||||
�� | Noncash amortization of terminated interest rate swap | 387 | 357 | ||||||
Noncash loss on foreign currency revaluation | 544 | 410 | |||||||
Changes in assets and liabilities, net of acquisitions: | |||||||||
Trade accounts receivable and other | (554,814 | ) | 34,620 | ||||||
Inventory | (208,035 | ) | 32,473 | ||||||
Accounts payable and other current liabilities | 420,145 | 24,711 | |||||||
Due to related parties | 2,353 | (446 | ) | ||||||
Net cash provided by (used in) operating activities | (271,849 | ) | 132,981 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES | |||||||||
Cash paid in connection with acquisitions | (13,467 | ) | (143,228 | ) | |||||
Additions to property and equipment | (50,011 | ) | (13,325 | ) | |||||
Proceeds from sales of assets | 1,758 | 650 | |||||||
Net cash used in investing activities | (61,720 | ) | (155,903 | ) | |||||
CASH FLOWS FROM FINANCING ACTIVITIES | |||||||||
Net borrowings/(repayments) on long-term revolving credit facility | (18,290 | ) | 168,720 | ||||||
Net borrowings/(repayments) on working capital revolving credit facility | 41,800 | (11,200 | ) | ||||||
Net borrowings/(repayments) on short-term letter of credit and hedged inventory facility | 344,600 | (100,491 | ) | ||||||
Net proceeds from the issuance of common units | 22,308 | 88 | |||||||
Distributions paid to unitholders and general partner | (45,005 | ) | (35,174 | ) | |||||
Other financing activities | (2,849 | ) | (879 | ) | |||||
Net cash provided by financing activities | 342,564 | 21,064 | |||||||
Effect of translation adjustment on cash | (144 | ) | (242 | ) | |||||
Net increase (decrease) in cash and cash equivalents | 8,851 | (2,100 | ) | ||||||
Cash and cash equivalents, beginning of period | 12,988 | 4,137 | |||||||
Cash and cash equivalents, end of period | $ | 21,839 | $ | 2,037 | |||||
Cash paid for interest, net of amounts capitalized | $ | 13,198 | $ | 2,150 | |||||
The accompanying notes are an integral part of these consolidated financial statements.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIESCONSOLIDATED STATEMENT OF PARTNERS' CAPITAL(in thousands)
| | | Class B Common Units | Class C Common Units | | | | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Common Units | | | Total Partners' Capital Amount | ||||||||||||||||||||
| General Partner Amount | Total Units | ||||||||||||||||||||||
| Units | Amount | Units | Amount | Units | Amount | ||||||||||||||||||
| (unaudited) | |||||||||||||||||||||||
Balance at December 31, 2004 | 62,740 | $ | 919,826 | 1,307 | $ | 18,775 | 3,246 | $ | 100,423 | $ | 31,180 | 67,293 | $ | 1,070,204 | ||||||||||
Private placement of common units | 575 | 21,860 | — | — | — | — | 448 | 575 | 22,308 | |||||||||||||||
Conversion of Class B Units | 1,307 | 18,323 | (1,307 | ) | (18,323 | ) | — | — | — | — | — | |||||||||||||
Conversion of Class C Units | 3,246 | 99,302 | — | — | (3,246 | ) | (99,302 | ) | — | — | — | |||||||||||||
Distributions | — | (38,428 | ) | — | (801 | ) | — | (1,988 | ) | (3,788 | ) | — | (45,005 | ) | ||||||||||
Net income | — | 27,356 | — | 548 | — | 1,361 | 3,543 | — | 32,808 | |||||||||||||||
Other comprehensive income | — | (67,670 | ) | — | (199 | ) | — | (494 | ) | (1,395 | ) | — | (69,758 | ) | ||||||||||
Balance at March 31, 2005 | 67,868 | $ | 980,569 | — | $ | — | — | $ | — | $ | 29,988 | 67,868 | $ | 1,010,557 | ||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME ANDCHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME(in thousands)
Statements of Comprehensive Income
| Three Months Ended March 31, | ||||||
---|---|---|---|---|---|---|---|
| 2005 | 2004 | |||||
| (unaudited) | ||||||
Net income | $ | 32,808 | $ | 27,876 | |||
Other comprehensive income (loss) | (69,758 | ) | (10,814 | ) | |||
Comprehensive income (loss) | $ | (36,950 | ) | $ | 17,062 | ||
Statement of Changes in Accumulated Other Comprehensive Income
| Net Deferred Gain (Loss) on Derivative Instruments | Currency Translation Adjustments | Total | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
| (unaudited) | |||||||||||
Balance at December 31, 2004 | $ | 25,937 | $ | 70,934 | $ | 96,871 | ||||||
Current period activity: | ||||||||||||
Reclassification adjustments for settled contracts | (1,496 | ) | — | (1,496 | ) | |||||||
Changes in fair value of outstanding hedge positions | (65,876 | ) | — | (65,876 | ) | |||||||
Currency translation adjustment | — | (2,386 | ) | (2,386 | ) | |||||||
Total period activity | (67,372 | ) | (2,386 | ) | (69,758 | ) | ||||||
Balance at March 31, 2005 | $ | (41,435 | ) | $ | 68,548 | $ | 27,113 | |||||
The accompanying notes are an integral part of these consolidated financial statements.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Note 1—Organization and Accounting Policies
Plains All American Pipeline, L.P. ("PAA"(“PAA”) is a Delaware limited partnership formed in September of 1998. Our operations are conducted directly and indirectly through our operating subsidiaries, Plains Marketing, L.P., Plains Pipeline, L.P. and Plains Marketing Canada, L.P. We are engaged in interstate and intrastate crude oil transportation, and crude oil gathering, marketing, terminalling and storage, as well as the marketing and storage of liquefied petroleum gas and other natural gas related petroleum products. We refer to liquified petroleum gas and other natural gas related petroleum products collectively as "LPG."“LPG.” We own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key oil producing basins and at major market hubs in the United States and Canada.
The accompanying consolidated financial statements and related notes present (i) our consolidated financial position as of March 31,June 30, 2005, and December 31, 2004, (ii) the results of our consolidated operations for the three months and six months ended March 31,June 30, 2005 and 2004, (iii) our consolidated cash flows for the threesix months ended March 31,June 30, 2005 and 2004, (iv) our consolidated changes in partners'partners’ capital for the threesix months ended March 31,June 30, 2005, (v) our consolidated comprehensive income for the three months and six months ended March 31,June 30, 2005 and 2004, and (vi) our changes in consolidated accumulated other comprehensive income for the threesix months ended March 31,June 30, 2005. The financial statements have been prepared in accordance with the instructions for interim reporting as prescribed by the Securities and Exchange Commission. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods have been reflected. All significant intercompany transactions have been eliminated. Certain reclassifications are made to prior periods to conform to current period presentation. The results of operations for the threesix months ended March 31,June 30, 2005 should not be taken as indicative of the results to be expected for the full year. The consolidated interim financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our 2004 Annual Report on Form 10-K.
Note 2—Trade Accounts Receivable
The majority of our trade accounts receivable relate to our gathering and marketing activities and can generally be described as high volume and low margin activities. As is customary in the industry, a portion of these receivables is reflected net of payables to the same counterparty based on contractual agreements. We routinely review our trade accounts receivable balances to identify past due amounts and analyze the reasons such amounts have not been collected. In many instances, such uncollected amounts involve billing delays and discrepancies or disputes as to the appropriate price, volume or quality of crude oil delivered, received or exchanged. We also attempt to monitor changes in the creditworthiness of our customers as a result of developments related to each customer, the industry as a whole and the general economy. Based on these analyses, as well as our historical experience and the facts and circumstances surrounding certain aged balances, we have established an allowance for doubtful trade accounts receivable. At March 31,June 30, 2005, substantially all of our net trade accounts receivable were less than 60 days past the scheduled invoice date. OurThe following is a reconciliation of the changes in our allowance for doubtful trade accounts receivable totaled $0.7 million. balance (in millions):
Balance at December 31, 2004 |
| $ | 0.6 |
|
Applied to accounts receivable balances |
| (0.7 | ) | |
Increase in reserve charged to expense |
| 0.8 |
| |
Balance at June 30, 2005 |
| $ | 0.7 |
|
8
We consider this reserve adequate; however, there is no assurance that actual amounts will not vary significantly from estimated amounts. The discovery of previously unknown facts or adverse developments affecting one of our counterparties or the industry as a whole could adversely impact our results of operations.
Note 3—Inventory and Linefill
Inventory primarily consists of crude oil and LPG in pipelines, storage tanks and rail cars that is valued at the lower of cost or market, with cost determined using an average cost method. Linefill and minimum working inventory requirements in owned assets are recorded at historical cost and consist of crude oil and LPG used to pack our pipelines such that when an incremental barrel enters, it forces a barrel out at another location, as well as the minimum amount of crude oil and LPG necessary to operate our storage and terminalling facilities.
Linefill and minimum working inventory requirements in third party assets are included in "Inventory"“Inventory” (a current asset) in determining the average cost of operating inventory and applying the lower of cost or market analysis. At the end of each period, we reclassify the linefill in third party assets not expected to be liquidated within the succeeding twelve months out of "Inventory,"“Inventory,” at average cost, and into "Inventory“Inventory in Third Party Assets"Assets” (a long-term asset), which is reflected as a separate line item within other assets on the consolidated balance sheet.
At March 31,June 30, 2005 and December 31, 2004, inventory and linefill consisted of:
|
| June 30, 2005 |
| December 31, 2004 |
| |||||||||||||||||||||||||||||
| | March 31, 2005 | December 31, 2004 |
|
|
|
|
| Dollar/ |
|
|
|
|
| Dollar/ |
| ||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | Barrels | $ | $/barrel | Barrels | $ | $/barrel |
| Barrels |
| Dollars |
| barrel |
| Barrels |
| Dollars |
| barrel |
| ||||||||||||||
| | (Barrels in thousands and dollars in millions) |
| (Barrels in thousands and dollars in millions) |
| |||||||||||||||||||||||||||||
Inventory(1) | Inventory(1) |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
Crude oil | Crude oil | 14,131 | $ | 679.6 | $ | 48.09 | 8,716 | $ | 396.2 | $ | 45.46 |
| 14,959 |
| $ | 737.2 |
| $ | 49.28 |
| 8,716 |
| $ | 396.2 |
| $ | 45.46 |
| ||||||
LPG | LPG | 845 | 29.4 | $ | 34.79 | 2,857 | 100.1 | $ | 35.04 |
| 3,132 |
| 108.5 |
| $ | 34.64 |
| 2,857 |
| 100.1 |
| $ | 35.04 |
| ||||||||||
Other | — | 2.3 | N/A | — | 1.9 | N/A | ||||||||||||||||||||||||||||
Inventory subtotal | 14,976 | 711.3 | 11,573 | 498.2 | ||||||||||||||||||||||||||||||
Parts and supplies |
| N/A |
| 2.5 |
| N/A |
| N/A |
| 1.9 |
| N/A |
| |||||||||||||||||||||
Inventory subtotal |
| 18,091 |
| 848.2 |
|
|
| 11,573 |
| 498.2 |
|
|
| |||||||||||||||||||||
Inventory in third-party assets | Inventory in third-party assets |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
Crude oil | Crude oil | 1,249 | 44.9 | $ | 35.95 | 1,294 | 48.7 | $ | 37.64 |
| 1,248 |
| 50.5 |
| $ | 40.38 |
| 1,294 |
| 48.7 |
| $ | 37.64 |
| ||||||||||
LPG | LPG | 318 | 10.4 | $ | 32.70 | 318 | 10.6 | $ | 33.33 |
| 318 |
| 10.9 |
| $ | 34.28 |
| 318 |
| 10.6 |
| $ | 33.33 |
| ||||||||||
Inventory in third-party assets subtotal | 1,567 | 55.3 | 1,612 | 59.3 | ||||||||||||||||||||||||||||||
Inventory in third-party assets subtotal |
| 1,566 |
| 61.4 |
|
|
| 1,612 |
| 59.3 |
|
|
| |||||||||||||||||||||
Linefill | Linefill |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
Crude oil | 5,924 | 165.3 | $ | 27.90 | 6,015 | 168.4 | $ | 28.00 | ||||||||||||||||||||||||||
LPG | 26 | 0.8 | $ | 30.77 | — | — | N/A | |||||||||||||||||||||||||||
Linefill subtotal | 5,950 | 166.1 | 6,015 | 168.4 | ||||||||||||||||||||||||||||||
Crude oil linefill |
| 5,924 |
| 165.1 |
| $ | 27.87 |
| 6,015 |
| 168.4 |
| $ | 28.00 |
| |||||||||||||||||||
LPG linefill |
| 26 |
| 0.9 |
| $ | 30.77 |
| — |
| — |
| N/A |
| ||||||||||||||||||||
Linefill subtotal |
| 5,950 |
| 166.0 |
|
|
| 6,015 |
| 168.4 |
|
|
| |||||||||||||||||||||
Total | Total | 22,493 | $ | 932.7 | 19,200 | $ | 725.9 |
| 25,607 |
| $ | 1,075.6 |
|
|
| 19,200 |
| $ | 725.9 |
|
|
| ||||||||||||
(1)
9
Note 4—Debt
Debt consists of the following:
| March 31, 2005 | December 31, 2004 | |||||
---|---|---|---|---|---|---|---|
Short-term debt: | |||||||
Senior secured hedged inventory borrowing facility bearing interest at a rate of 3.5% and 3.0% at March 31, 2005 and December 31, 2004, respectively | $ | 425.0 | $ | 80.4 | |||
Working capital borrowings, bearing interest at a rate of 3.7% at March 31, 2005 and December 31, 2004(1) | 130.0 | 88.2 | |||||
Other | 6.0 | 6.9 | |||||
Total short-term debt | 561.0 | 175.5 | |||||
Long-term debt: | |||||||
Senior unsecured revolving credit facility, bearing interest at 3.5% at March 31, 2005 and December 31, 2004(1) | $ | 125.0 | $ | 143.6 | |||
4.75% senior notes due August 2009, net of unamortized discount of $0.7 million at March 31, 2005 and December 31, 2004 | 174.3 | 174.3 | |||||
7.75% senior notes due October 2012, net of unamortized discount of $0.3 million at March 31, 2005 and December 31, 2004 | 199.7 | 199.7 | |||||
5.63% senior notes due December 2013, net of unamortized discount of $0.6 million at March 31, 2005 and December 31, 2004 | 249.4 | 249.4 | |||||
5.88% senior notes due August 2016, net of unamortized discount of $1.1 million at March 31, 2005 and December 31, 2004 | 173.9 | 173.9 | |||||
Other | 7.9 | 8.1 | |||||
Total long-term debt(1) | 930.2 | 949.0 | |||||
Total debt | $ | 1,491.2 | $ | 1,124.5 | |||
|
| June 30, |
| December 31, |
| ||||||
|
| 2005 |
| 2004 |
| ||||||
|
| (in millions) |
| ||||||||
Short-term debt: |
|
|
|
|
|
|
|
|
| ||
Senior secured hedged inventory facility bearing interest at a rate of 4.0% and 3.0% at June 30, 2005 and December 31, 2004, respectively |
|
| $ | 655.7 |
|
|
| $ | 80.4 |
|
|
Working capital borrowings, bearing interest at a rate of 4.2% and 3.7% at June 30, 2005 and December 31, 2004, respectively(1) |
|
| 160.0 |
|
|
| 88.2 |
|
| ||
Other |
|
| 5.1 |
|
|
| 6.9 |
|
| ||
Total short-term debt |
|
| 820.8 |
|
|
| 175.5 |
|
| ||
Long-term debt: |
|
|
|
|
|
|
|
|
| ||
Senior notes— |
|
|
|
|
|
|
|
|
| ||
4.75% senior notes due August 2009, net of unamortized discount of $0.6 million and $0.7 million at June 30, 2005 and December 31, 2004, respectively |
|
| $ | 174.4 |
|
|
| $ | 174.3 |
|
|
7.75% senior notes due October 2012, net of unamortized discount of $0.3 million and $0.3 million at June 30, 2005 and December 31, 2004, respectively |
|
| 199.7 |
|
|
| 199.7 |
|
| ||
5.63% senior notes due December 2013, net of unamortized discount of $0.6 million and $0.6 million at June 30, 2005 and December 31, 2004, respectively |
|
| 249.4 |
|
|
| 249.4 |
|
| ||
5.25% senior notes due June 2015, net of unamortized discount of $0.7 million at June 30, 2005 |
|
| 149.3 |
|
|
| — |
|
| ||
5.88% senior notes due August 2016, net of unamortized discount of $1.1 million and $1.1 million at June 30, 2005 and December 31, 2004, respectively |
|
| 173.9 |
|
|
| 173.9 |
|
| ||
Senior notes, net of unamortized discount |
|
| 946.7 |
|
|
| 797.3 |
|
| ||
Long-term debt under credit facilities and other— |
|
|
|
|
|
|
|
|
| ||
Senior unsecured revolving credit facility, bearing interest at 3.5% at December 31, 2004(1) |
|
| — |
|
|
| 143.6 |
|
| ||
Other |
|
| 6.5 |
|
|
| 8.1 |
|
| ||
Long-term debt under credit facilities and other |
|
| 6.5 |
|
|
| 151.7 |
|
| ||
Total long-term debt(1)(2) |
|
| 953.2 |
|
|
| 949.0 |
|
| ||
Total debt |
|
| $ | 1,774.0 |
|
|
| $ | 1,124.5 |
|
|
(1)
In April(2)At June 30, 2005, the aggregate fair value of our fixed rate senior notes is estimated to be approximately $1.0 billion.
10
During May 2005, we amendedcompleted the sale of $150 million of 5.25% Senior Notes due 2015. The notes were sold at 99.518% of face value. The notes were co-issued by us and a 100% owned consolidated finance subsidiary (neither of which have independent assets or operations). Interest payments are due on June 15 and December 15 of each year. The notes are fully and unconditionally guaranteed, jointly and severally, by all of our senior secured hedged inventory facilityexisting 100% owned subsidiaries, except for subsidiaries which are minor. We used the proceeds to increase the capacityrepay amounts outstanding under the facility from $425 million to $500 million. We are in the process of negotiating an additional expansion of this facility to increase its capacity by up to $300 million. our credit facilities and for general partnership purposes.
In addition, in May 2005, we amended our senior unsecured credit facility to increase the capacity from $750 million to $900 million and increased the sub-facility for Canadian borrowings to $360 million. The amended facility can be expanded to $1.25 billion.
During Aprilbillion, subject to obtaining additional lender commitments. Additionally, in the second quarter of 2005, we entered into a treasury lock with a large creditworthy financial institution. A treasury lock is a financial derivative instrument that enablesamended our senior secured hedged inventory facility to increase the companycapacity under the facility from $425 million to lock in the U.S. Treasury Note rate, typically in anticipation of a debt issuance. The treasury lock has a notional principal amount of $75 million and an effective rate of 4.18%. The treasury lock matures in May 2005.$800 million.
Note 5—Earnings Per CommonLimited Partner Unit
Except as discussed in the following paragraph, basic and diluted net income per limited partner unit is determined by dividing net income after deducting the amount allocated to the general partner interest, (including its incentive distribution in excess of its 2% interest), by the weighted average number of outstanding limited partner units during the period. Partnership income is first allocated to the general partner based on the amount of incentive distributions. The remainder is then allocated between the limited partners and general partner based on percentage ownership in the Partnership.
Emerging Issues Task Force Issue No. 03-06 (“EITF 03-06”), “Participating Securities and the Two-Class Method under FASB Statement No. 128” addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity when, and if, it declares dividends on its common stock. Essentially, EITF 03-06 provides that in any accounting period where our aggregate net income exceeds our aggregate distribution for such period, we are required to present earnings per unit as if all of the earnings for the periods were distributed, regardless of the pro forma nature of this allocation and whether those earnings would actually be distributed during a particular period from an economic or practical perspective. EITF 03-06 does not impact our overall net income or other financial results, however, for periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing the earnings per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights held by our general partner, even though we make cash distributions on the basis of cash available for distributions, not earnings, in any given accounting period. In accounting periods where aggregate net income does not exceed our aggregate distributions for such period, EITF 03-06 does not have any impact on our earnings per unit calculation.
11
The following sets forth the computation of basic and diluted earnings per commonlimited partner unit. The net income available to limited partners and the weighted average limited partner units outstanding have been adjusted for instruments considered common unit equivalents at March 31,June 30, 2005 and 2004.
| | Three months ended March 31, |
| Three months ended |
| Six months ended |
| |||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | 2005 | 2004 |
| 2005 |
| 2004 |
| 2005 |
| 2004 |
| ||||||||||
| | (in thousands, except per unit data) |
| (in thousands, except per unit data) |
| |||||||||||||||||
Net income | Net income | $ | 32,808 | $ | 27,876 |
| $ | 62,282 |
| $ | 35,677 |
| $ | 95,090 |
| $ | 63,553 |
| ||||
Less: | Less: |
|
|
|
|
|
|
|
|
| ||||||||||||
General partner's incentive distribution right | (2,946 | ) | (1,644 | ) | ||||||||||||||||||
Subtotal | 29,862 | 26,232 | ||||||||||||||||||||
General partner 2% ownership | (597 | ) | (525 | ) | ||||||||||||||||||
Numerator for basic earnings per limited parner unit: | ||||||||||||||||||||||
Net income available for limited partners | 29,265 | 25,707 | ||||||||||||||||||||
General partner’s incentive distribution paid |
| (3,504 | ) | (1,752 | ) | (6,450 | ) | (3,396 | ) | |||||||||||||
Subtotal |
| 58,778 |
| 33,925 |
| 88,640 |
| 60,157 |
| |||||||||||||
General partner 2% ownership |
| (1,176 | ) | (678 | ) | (1,773 | ) | (1,203 | ) | |||||||||||||
Net income available to limited partners |
| 57,602 |
| 33,247 |
| 86,867 |
| 58,954 |
| |||||||||||||
Pro forma additional general partner’s incentive distribution |
| (6,174 | ) | — |
| (560 | ) | — |
| |||||||||||||
Net income available to limited partners under EITF 03-06 (numerator for basic and diluted earnings per limited partner unit) |
| $ | 51,428 |
| $ | 33,247 |
| $ | 86,307 |
| $ | 58,954 |
| |||||||||
Denominator: |
|
|
|
|
|
|
|
|
| |||||||||||||
Denominator for basic earnings per limited partner unit-weighted average number of limited partner units |
| 67,893 |
| 61,556 |
| 67,706 |
| 59,985 |
| |||||||||||||
Effect of dilutive securities: | Effect of dilutive securities: |
|
|
|
|
|
|
|
|
| ||||||||||||
Increase in general partner's incentive distribution-contingent equity issuance | — | (16 | ) | |||||||||||||||||||
Numerator for diluted earnings per limited partner unit | $ | 29,265 | $ | 25,691 | ||||||||||||||||||
Denominator: | ||||||||||||||||||||||
Denominator for basic earnings per limited partner unit—weighted average number of limited partner units | 67,517 | 58,414 | ||||||||||||||||||||
Effect of dilutive securities: | ||||||||||||||||||||||
2005 LTIP | 639 | — | ||||||||||||||||||||
Contingent equity issuance | — | 603 | ||||||||||||||||||||
Denominator for diluted earnings per limited partner unit—weighted average number of limited partner units | 68,156 | 59,017 | ||||||||||||||||||||
Weighted average LTIP units (see Note 7) |
| 1,381 |
| — |
| 1,013 |
| — |
| |||||||||||||
Denominator for diluted earnings per limited partner unit-weighted average number of limited partner units |
| 69,274 |
| 61,556 |
| 68,719 |
| 59,985 |
| |||||||||||||
Basic net income per limited partner unit | Basic net income per limited partner unit | $ | 0.43 | $ | 0.44 |
| $ | 0.76 |
| $ | 0.54 |
| $ | 1.27 |
| $ | 0.98 |
| ||||
Diluted net income per limited partner unit | Diluted net income per limited partner unit | $ | 0.43 | $ | 0.44 |
| $ | 0.74 |
| $ | 0.54 |
| $ | 1.26 |
| $ | 0.98 |
| ||||
Note 6—Partners'Partners’ Capital and Distributions
Private Placement of Common Units.
On February 25, 2005, we issued 575,000 common units to a subsidiary of Vulcan Energy Corporation. The sale price for the common units was $38.13 per unit resulting in net proceeds, including the general partner'spartner’s proportionate capital contribution and expenses associated with the sale, of approximately $22.3 million. We intend to use the net proceeds from the private placement to fund a portion of our 2005 expansion capital program. Pending the incurrence of these expenditures,Although the net proceeds were used to repay indebtedness under our revolving credit facilities.facilities at closing, they will ultimately be used to fund a portion of our 2005 expansion capital program as those expenditures are incurred.
Conversion of Class B and Class C Common Units.
In accordance with a common unitholder vote at a special meeting on January 20, 2005, each Class B common unit and Class C common unit became convertible into one common unit upon request of the holder. In February 2005, all of the Class B and Class C common units converted into common units.
12
Distributions
The following table details the distributions we have declared and paid in 2005:
|
|
|
| Total of distribution paid to: |
| ||||||||||||||||||
|
| Distribution |
|
|
| General partner: |
| ||||||||||||||||
|
| per Limited |
| Limited |
| Incentive |
|
|
| ||||||||||||||
Distribution Payment Date |
|
|
| Partner Unit |
| Partners |
| Distribution |
| 2% ownership |
| ||||||||||||
|
| (in millions, except per unit data) |
| ||||||||||||||||||||
August 12, 2005(1) |
|
| $ | 0.6500 |
|
|
| $ | 44.1 |
|
|
| $ | 3.8 |
|
|
| $ | 0.9 |
|
| ||
May 13, 2005 |
|
| $ | 0.6375 |
|
|
| $ | 43.3 |
|
|
| $ | 3.5 |
|
|
| $ | 0.9 |
|
| ||
February 14, 2005 |
|
| $ | 0.6125 |
|
|
| $ | 41.2 |
|
|
| $ | 3.0 |
|
|
| $ | 0.8 |
|
| ||
Distributions(1)
On AprilThe distribution we declared on July 22, 2005, we declared a cash distribution of $0.6375 per unit on our outstanding common units. The distribution is payable on May 13,August 12, 2005, to unitholders of record on May 3, 2005, for the period January 1, 2005, through March 31,August 2, 2005. The total distribution to be paid is approximately $47.7 million, with approximately $43.3 million to be paid to our common unitholders and $0.9 million and $3.5 million to be paid to our general partner for its general partner and incentive distribution interests, respectively.
On January 25, 2005, we declared a cash distribution of $0.6125 per unit on our outstanding common units, Class B common units and Class C common units. The distribution was paid on February 14, 2005, to unitholders of record on February 4, 2005, for the period October 1, 2004, through December 31, 2004. The total distribution paid was approximately $45.0 million, with approximately $41.2 million paid to our common unitholders and $0.8 million and $3.0 million paid to our general partner for its general partner and incentive distribution interests, respectively.
Note 7—Long-Term Incentive Plans
Our general partner has adopted the Plains All American GP LLC 1998 Long-Term Incentive Plan (the "1998 LTIP"“1998 LTIP”) and the 2005 Long-Term Incentive Plan (the "2005 LTIP"“2005 LTIP”) for employees and directors of our general partner and its affiliates who perform services for us.
As of March 31, 2005, there are approximately 150,000Approximately 92,000 phantom units outstanding under the 1998 LTIP of which we expect approximately 93,000 to vestvested in May 2005. We paid cash in lieu of delivery of common units for approximately 20,000 of the phantom units and issued approximately 47,000 new common units (after netting for taxes) in connection with the vesting. As of June 30, 2005, there are approximately 57,000 phantom units outstanding under the 1998 LTIP, which have vesting terms over the next four years, if certain performance criteria are met. The majority of the awards outstanding under the 1998 LTIP have performance-based vesting terms and, therefore, we recognize expense when it is considered probable that the awards will vest.
In February 2005, our Board of Directors and Compensation Committee approved grants of approximately 1.9 million phantom units and 1.4 million distribution equivalent rights ("DERs) under the 2005 LTIP. Approximately 1.4 million of the phantom units vest over a six year period (with performance accelerators) while the remaining awards vest over time only if certain performance criteria are met and are forfeited after six years if the performance criteria are not met. No phantom units vest prior to the dates indicated below for each tranche. The DERs vest over time (with performance accelerators) and terminate with the vesting or forfeiture of the related phantom units. The following awards were outstanding under the 2005 LTIP at March 31, 2005.
| | Phantom Units | DERs | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Annualized Distribution Rate | | |||||||||||||
Date | A(1) | B(2) | Total | A(1) | B(2) | Total | ||||||||
$2.60 | May 2007 | 549 | 150 | 699 | 353 | 150 | 503 | |||||||
$2.70 | May 2008 | — | — | — | 132 | 75 | 207 | |||||||
$2.80 | May 2009 | 411 | 150 | 561 | 132 | 75 | 207 | |||||||
$2.90 | May 2010 | — | — | — | 132 | 100 | 232 | |||||||
$3.00 | May 2010 | 411 | 200 | 611 | 132 | 100 | 232 | |||||||
1,371 | 500 | 1,871 | 881 | 500 | 1,381 | |||||||||
Compensation expense is recognized ratably over time for the phantom units and DERs that vest based on the passage of time. To the extent that the vesting of the awards or DERs is accelerated, the
related compensation expense will also be accelerated. For those phantom units and DERs that vest upon the achievement of performance criteria, expense is recognized when it is considered probable the criteria will be achieved.met.
In addition to the phantom units discussed above, fourFour of our non-employee directors each have received an LTIP awardsaward of 5,000 units in the aggregate.units. These awards vest yearly in 25% increments (1,250 units)units each). The awards have an automatic re-grant feature such that as they vest, a similar amount is granted. For the other two non-employee directors, any director compensation is assigned to the entity that designated them as directors. In those cases, no LTIP award was granted, but a cash payment is made. In June 2005, 5,000 director units vested.
13
In February 2005, our Board of Directors and Compensation Committee approved grants of approximately 1.9 million phantom units and 1.4 million distribution equivalent rights (“DERs”) under the 2005 LTIP. Approximately 1.4 million of the phantom units vest over a six year period (with performance accelerators) while the remaining awards vest over time only if certain performance criteria are met and are forfeited after seven years if the performance criteria are not met. No phantom units vest prior to the dates indicated below for each tranche. The DERs vest over time and terminate with the vesting or forfeiture of the related phantom units. The following awards were outstanding under the 2005 LTIP at June 30, 2005:
Annualized |
|
|
| Phantom Units |
| DERs |
| ||||||||||||||||
Distribution Rate |
|
|
| Date |
| A(1) |
| B(2) |
| Total |
| A(1) |
| B(2) |
| Total |
| ||||||
|
|
|
| (in thousands) |
| ||||||||||||||||||
$2.60 |
| May 2007 |
| 561 |
|
| 150 |
|
| 711 |
|
| 363 |
|
|
| 150 |
|
| 513 |
| ||
$2.70 |
| May 2008 |
| — |
|
| — |
|
| — |
|
| 136 |
|
|
| 75 |
|
| 211 |
| ||
$2.80 |
| May 2009 |
| 421 |
|
| 150 |
|
| 571 |
|
| 136 |
|
|
| 75 |
|
| 211 |
| ||
$2.90 |
| May 2010 |
| — |
|
| — |
|
| — |
|
| 136 |
|
|
| 100 |
|
| 211 |
| ||
$3.00 |
| May 2010 |
| 421 |
|
| 200 |
|
| 622 |
|
| 136 |
|
|
| 100 |
|
| 211 |
| ||
|
|
|
| 1,403 |
|
| 500 |
|
| 1,903 |
|
| 907 |
|
|
| 500 |
|
| 1,407 |
| ||
(1)Awards that vest over six years. Achievement of the indicated distribution rate performance criteria can accelerate the vesting to the date indicated. The phantom unit awards are common stock equivalents as they will vest at the end of a determinant time and are included in our diluted earnings per unit calculation.
(2)Awards that vest only upon the achievement of the distribution rate performance criteria and the date indicated. In addition, the awards will be forfeited if the performance criteria are not met in seven years. These awards are not common stock equivalents as they may never vest and are not included in our diluted earnings per unit calculation.
Compensation expense is recognized ratably over time for the phantom units and DERs that vest based on the passage of time. To the extent that the vesting of the awards or DERs is accelerated, the related compensation expense will also be accelerated. For those phantom units and DERs that vest upon the achievement of performance criteria, expense is recognized when it is considered probable the criteria will be achieved.
We have concluded that it is probable that we will achieve a $2.60$2.80 annualized distribution rate and therefore have accelerated the vesting of the portion of the awards that vest based onup to that rate. We recognized total compensation expense of approximately $2.2$7.9 million in the second quarter of 2005 for a total of $10.2 million in the first quarterhalf of 2005 related to the awards granted under our 1998 LTIP and our 2005 LTIP.
Note 8—Derivative Instruments and Hedging Activities
We utilize various derivative instruments to (i) manage our exposure to commodity price risk, (ii) engage in a controlled trading program, (iii) manage our exposure to interest rate risk and (iv) manage our exposure to currency exchange rate risk. Our risk management policies and procedures are designed to monitor interest rates, currency exchange rates, NYMEX and over-the-counter positions, as well as physical volumes, grades, locations and delivery schedules, to ensure that our hedging activities address our market risks. We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. We calculate hedge effectiveness on a quarterly basis. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument'sinstrument’s effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of the hedged items.
14
Summary of Financial Impact
The majority of our derivative activity is related to our commodity price risk hedging activities. Through these activities, we hedge our exposure to price fluctuations with respect to crude oil and LPG in storage, andas well as with respect to expected purchases, sales and transportation of these commodities. The derivative instruments we use consist primarily of futures and options contracts traded on the NYMEX and over-the-counter transactions, including crude oil swap and option contracts entered into with financial institutions and other energy companies.
The majority of the instruments that qualify for hedge accounting are cash flow hedges. Therefore, the corresponding changes in fair value for the effective portion of the hedges are deferred to Accumulated Other Comprehensive Income ("OCI"(“OCI”) and recognized in revenues or crude oil and LPG purchases and related costs in the periods during which the underlying physical transactions occur. Derivatives that do not qualify for hedge accounting and the portion of cash flow hedges that is not highly effective (as defined in Statement of Financial Accounting Standard No. 133) in offsetting changes in cash flows of the hedged items are marked-to-market in revenues each period.
During the first quarterhalf of 2005, our earnings include a net gain of approximately $35.5$77.8 million resulting from all derivative activities, including the change in fair value of open derivatives and settled derivatives taken to earnings during the quarter.period. This gain includes:
a)
·
·the net change in fair value during the quarter of the portion of cash flow hedges related to open derivatives that is not highly effective in offsetting changes in cash flows of hedged items (a loss of approximately $0.7$0.4 million).
b)
The following table summarizes the net assets and liabilities related to the fair value of our open derivative positions on our consolidated balance sheet as of March 31,June 30, 2005:
Other current assets | $ | 21.6 |
| $ | 25.5 |
| ||
Other long-term assets | 9.6 |
| 0.9 |
| ||||
Other current-liabilities | (65.8 | ) |
| (100.4 | ) | |||
Other long-term liabilities and deferred credits | (12.2 | ) |
| (6.5 | ) |
The net liability as of March 31,June 30, 2005, relates mostly to unrealized losses on effective cash flow hedges that are deferred to OCI. At March 31,June 30, 2005, there is a total unrealized net loss of approximately $41.4$62.7 million deferred to OCI. This includes $35.7$56.5 million, which predominantly relates to unrealized losses on derivatives used to hedge physical inventory in storage that receive hedge accounting, and $5.7$6.2 million relating to terminated interest rate swaps, which are being amortized to interest expense over the original terms of the terminated instruments. The inventory hedges are mostly short derivative positions that will result in losses when prices rise. These hedge losses are offset by an increase in the physical inventory value and will be reclassed into earnings from OCI in the same period that the underlying physical inventory is sold. The total amount of deferred net losses recorded in OCI are expected to be reclassified to future earnings, contemporaneously with the related physical purchase or delivery of the underlying commodity or payments of interest.
15
Of the total net loss deferred in OCI at March 31,June 30, 2005, a net loss of $36.0$57.8 million will be reclassified into earnings in the next twelve months and the remaining net loss at various intervals (ending in 2016 for amounts related to our terminated interest rate swaps and 2009 for amounts related to our commodity price-risk hedging). Because a portion of these amounts is based on market prices at the current period end, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.
During the threesix months ended March 31,June 30, 2005, no amounts were reclassified to earnings from OCI in connection with forecasted transactions that were no longer considered probable of occurring.
Note 9—Commitments and Contingencies
Litigation
Export License Matter.In our gathering and marketing activities, we import and export crude oil from and to Canada. Exports of crude oil are subject to the "short supply"“short supply” controls of the Export Administration Regulations ("EAR"(“EAR”) and must be licensed by the Bureau of Industry and Security (the
"BIS" “BIS”) of the U.S. Commerce Department. In 2002, we determined that we may have violated the terms of our licenses with respect to the quantity of crude oil exported and the end-users in Canada. Export of crude oil except as authorized by license is a violation of the EAR. In October 2002, we submitted to the BIS an initial notification of voluntary disclosure. The BIS subsequently informed us that we could continue to export while previous exports were under review. We applied for and received several new licenses allowing for export volumes and end users that more accurately reflect our anticipated business and customer needs. We also conducted reviews of new and existing contracts and implemented new procedures and practices in order to monitor compliance with applicable laws regarding the export of crude oil to Canada. As a result, we subsequently submitted additional information to the BIS in October 2003 and May 2004. In August 2004, we received a request from the BIS for additional information. We have responded to this and subsequent requests, and continue to cooperate fully with BIS officials. At this time, we have received neither a warning letter nor a charging letter, which could involve the imposition of penalties, and no indication of what penalties the BIS might assess. As a result, we cannot reasonably estimate the ultimate impact of this matter.
Alfons Sperber v. Plains Resources Inc., et al. On December 18, 2003, a putative class action lawsuit was filed in the Delaware Chancery Court, New Castle County, entitled Alfons Sperber v. Plains Resources Inc., et al. This suit, brought on behalf of a putative class of Plains All American Pipeline, L.P. common unitholders, asserted breach of fiduciary duty and breach of contract claims against us, Plains AAP, L.P., and Plains All American GP LLC and its directors, as well as breach of fiduciary duty claims against Plains Resources Inc. and its directors (Plains Resources, Inc. is a unitholder and an interest owner in our general partner). The complaint sought to enjoin or rescind a proposed acquisition of all of the outstanding stock of Plains Resources Inc., as well as declaratory relief, an accounting, disgorgement and the imposition of a constructive trust, and an award of damages, fees, expenses and costs, among other things. This lawsuit has been settled in principle. The court has approved the settlement and the settlement became final in March 2005.
Pipeline Releases.In December 2004 and January 2005, we experienced two unrelated releases of crude oil that reached rivers located near the sites where the releases originated. In late December 2004, one of our pipelines in West Texas experienced a rupture that resulted in the release of approximately 4,500 barrels of crude oil, a portion of which reached a remote location of the Pecos River. In early January 2005, an overflow from a temporary storage tank located in East Texas resulted in the release of approximately 1,200 barrels of crude oil, a portion of which reached the Sabine River. In both cases, emergency response personnel under the supervision of a unified command structure consisting of representatives of Plains Pipeline,our personnel, the U.S. Environmental Protection Agency (“EPA”), the Texas Commission on Environmental Quality and the Texas Railroad Commission conducted clean-up operations at each site. Approximately 4,200 barrels and 980 barrels were recovered from the two respective sites. The unrecovered oil has been or will be removed or otherwise addressed by PAAus in the course of site remediation. Aggregate costs associated with the releases, including estimated remediation costs, are estimated to be approximately $3.0$3.5 million to $3.5$4.0 million. We continue to work with the appropriate state and federal environmental authorities in respondingwith respect to the releasessite restoration and no enforcement proceedings have been instituted by any governmental authority at this time.
General.We, in the ordinary course of business, are a claimant and/or a defendant in various legal proceedings. We do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.
16
Environmental
We may experience future releases of crude oil into the environment from our pipeline and storage operations, or discover past releases that were previously unidentified. Although we maintain
an inspection program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to any such environmental releases from our assets may substantially affect our business. As we expand our pipeline assets through acquisitions, we expect the absolute number of releases during a given period to increase and we have, in fact, experienced such an increase in connection with our purchase of the Link assets. As a result, we have also received an increased number of requests for information from governmental agencies with respect to such leaks (such as EPA requests under Clean Water Act Section 308), commensurate with the scale and scope of our pipeline operations. We cannot predict the effect, if any, of increased scrutiny by governmental authorities of the crude oil pipeline business.
At March 31,June 30, 2005, our reserve for environmental liabilities totaled approximately $23.3$23.7 million. Approximately $16.3$14.9 million of the reserve is related to liabilities assumed as part of the Link acquisition. Although we believe our reserve is adequate, no assurance can be given that any costs incurred in excess of this reserve would not have a material adverse effect on our financial condition, results of operations or cash flows.
Other
A pipeline, terminal or other facility may experience damage as a result of an accident or natural disaster. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We maintain insurance of various types that we consider adequate to cover our operations and properties. The insurance covers our assets in amounts consideredwe consider reasonable. The insurance policies are subject to deductibles that we consider reasonable and not excessive. Our insurance does not cover every potential risk associated with operating pipelines, terminals and other facilities, including the potential loss of significant revenues. The overall trendAdditionally, we choose to self-insure certain types of risks, including risks associated with gradual seepage and pollution and property damage for pipe in the environmental insurance industry appearsground, which we believe are cost prohibitive to be a contraction in the breadth and depth of available coverage, while costs, deductibles and retention levels have increased. Absent a material favorable change in the insurance markets, this trend is expected to continue as we continue to grow and expand. As a result, we anticipate that we will elect to self-insure more of our activities or incorporate higher retention in our insurance arrangements.insure.
The occurrence of a significant event not fully insured, indemnified or reserved against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. We believe we are adequately insured for public liability and property damage to others with respect to our operations. We believe that our levels of coverage and retention are generally consistent with those of similarly situated companies in our industry. With respect to all of our coverage, no assurance can be given that we will be able to maintain adequate insurance in the future at rates we consider reasonable, or that we have established adequate reserves to the extent that such risks are not insured.
17
Our operations consist of two operating segments: (i) pipeline transportation operations ("Pipeline Operations"(“Pipeline”) and (ii) gathering, marketing, terminalling and storage operations ("(“GMT&S"&S”). Through our pipeline segment, we engage in interstate and intrastate crude oil pipeline transportation and certain related margin activities. Through our GMT&S segment, we engage in purchases and resales of crude oil and LPG at various points along the distribution chain and we operate certain terminalling and storage assets. We believe that the combination of our terminalling and storage activities and gathering and marketing activities provides a counter-cyclical balance that has a stabilizing effect on our results of operations and cash flow. In a contango market (oil prices for future deliveries are higher than for current deliveries), we use our tankage to improve our gathering margins by storing crude oil we have purchased at lower prices in the current month for delivery at higher prices in future months. In a backwardated market (oil prices for future deliveries are lower than for current deliveries), we use and lease less storage capacity, but increased marketing margins (premiums for prompt delivery)delivery resulting from high demand) provide an offset to this reduced cash flow. In addition, we supplement the counter-cyclical balance of our asset base with derivative hedging activities.
We evaluate segment performance based on segment profit and maintenance capital. We define segment profit as revenues less (i) purchases, (ii) field operating costs, and (iii) segment general and administrative expenses. Each of the items above excludes depreciation and amortization. As a master limited partnership, we make quarterly distributions of our “available cash” (as defined in our partnership agreement) to our unitholders. Therefore, we look at each period’s earnings before non-cash depreciation and amortization as an important measure of segment performance. The exclusion of depreciation and amortization expense could be viewed as limiting the usefulness of segment profit as a performance measure because it does not account in current periods for the implied reduction in value of our capital assets, such as crude oil pipelines and facilities, caused by aging and wear and tear. Management compensates for this limitation by recognizing that depreciation and amortization are largely offset by repair and maintenance costs, which mitigate the actual decline in the value of our principal fixed assets. These maintenance costs are a component of field operating costs included in segment profit or in maintenance capital, depending on the nature of the cost. Maintenance capital, which is deducted in determining “available cash”, consists of capital expenditures required either to maintain the existing operating capacity of partially or fully depreciated assets or to extend their useful lives. Capital expenditures made to expand our existing capacity, whether through construction or
acquisition, are considered expansion capital expenditures, not considered maintenance capital expenditures.capital. Repair and maintenance expenditures associated with existing assets that do not extend the useful life or expand the operating capacity are charged to expense as incurred. The following table reflects certain financial data for each segment for the periods indicated (note that eachindicated:
|
| Pipeline |
| GMT&S |
| Total |
| |||||
Three Months Ended June 30, 2005(1) |
| (in millions) |
| |||||||||
Revenues: |
|
|
|
|
|
|
|
|
| |||
External Customers (includes buy/sell revenues of $40.0 and $3,706.1, respectively)(2) |
|
| $ | 229.9 |
|
| $ | 6,930.8 |
| $ | 7,160.7 |
|
Intersegment(3) |
|
| 30.6 |
|
| 0.2 |
| 30.8 |
| |||
Total revenues of reportable segments |
|
| $ | 260.5 |
|
| $ | 6,931.0 |
| $ | 7,191.5 |
|
Segment profit(2)(4)(5) |
|
| $ | 41.4 |
|
| $ | 53.7 |
| $ | 95.1 |
|
Non-cash SFAS 133 impact(2) |
|
| $ | — |
|
| $ | (12.9 | ) | $ | (12.9 | ) |
Maintenance capital |
|
| $ | 2.5 |
|
| $ | 1.5 |
| $ | 4.0 |
|
18
|
|
| Pipeline |
|
| GMT&S |
| Total |
| |||
|
|
| (in millions) |
| ||||||||
Three Months Ended June 30, 2004 |
|
|
|
|
|
|
|
|
| |||
Revenues: |
|
|
|
|
|
|
|
|
| |||
External Customers (includes buy/sell revenues of $34.9 and $3,450.7, respectively)(2) |
|
| $ | 190.7 |
|
| $ | 4,941.1 |
| $ | 5,131.8 |
|
Intersegment(3) |
|
| 32.1 |
|
| 0.2 |
| 32.3 |
| |||
Total revenues of reportable segments |
|
| $ | 222.8 |
|
| $ | 4,941.3 |
| $ | 5,164.1 |
|
Segment profit(2)(4)(5) |
|
| $ | 47.7 |
|
| $ | 13.5 |
| $ | 61.2 |
|
Non-cash SFAS 133 impact(2) |
|
| $ | — |
|
| $ | (6.9 | ) | $ | (6.9 | ) |
Maintenance capital |
|
| $ | 0.6 |
|
| $ | 0.7 |
| $ | 1.3 |
|
Six Months Ended June 30, 2005(1) |
|
|
| |||||||||
Revenues: |
|
|
|
|
|
|
|
|
| |||
External Customers (includes buy/sell revenues of $73.6 and $7,125.2, respectively)(2) |
|
| $ | 442.4 |
|
| $ | 13,356.8 |
| $ | 13,799.2 |
|
Intersegment(3) |
|
| 65.3 |
|
| 0.4 |
| 65.7 |
| |||
Total revenues of reportable segments |
|
| $ | 507.7 |
|
| $ | 13,357.2 |
| $ | 13,864.9 |
|
Segment profit(2)(4)(5) |
|
| $ | 91.5 |
|
| $ | 70.0 |
| $ | 161.5 |
|
Non-cash SFAS 133 impact(2) |
|
| $ | — |
|
| $ | (26.3 | ) | $ | (26.3 | ) |
Maintenance capital |
|
| $ | 5.3 |
|
| $ | 2.7 |
| $ | 8.0 |
|
Six Months Ended June 30, 2004 |
|
|
|
|
|
|
|
|
| |||
Revenues: |
|
|
|
|
|
|
|
|
| |||
External Customers (includes buy/sell revenues of $81.3 and $5,285.5, respectively)(2) |
|
| $ | 364.2 |
|
| $ | 8,572.2 |
| $ | 8,936.4 |
|
Intersegment(3) |
|
| 47.9 |
|
| 0.4 |
| 48.3 |
| |||
Total revenues of reportable segments |
|
| $ | 412.1 |
|
| $ | 8,572.6 |
| $ | 8,984.7 |
|
Segment profit(2)(4)(5) |
|
| $ | 73.2 |
|
| $ | 41.6 |
| $ | 114.8 |
|
Non-cash SFAS 133 impact(2) |
|
| $ | — |
|
| $ | 0.5 |
| $ | 0.5 |
|
Maintenance capital |
|
| $ | 2.1 |
|
| $ | 1.0 |
| $ | 3.1 |
|
(1)In May 2005, we reclassified certain minor pipeline gathering assets from the GMT&S segment to the Pipeline segment. Historically, we have been the sole shipper on these assets as part of our gathering and marketing operations. Prior period segment information has not been restated for this change since the items in the following table excludes depreciation and amortization):impact to such periods was not material.
| Pipeline | GMT&S | Total | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
| (in millions) | |||||||||||
Three Months Ended March 31, 2005 | ||||||||||||
Revenues: | ||||||||||||
External Customers (includes buy/sell revenues in our Pipeline and GMT&S segments of $33.5 and $3,419.0, respectively)(2) | $ | 212.5 | $ | 6,426.0 | $ | 6,638.5 | ||||||
Intersegment(1) | 34.7 | 0.2 | 34.9 | |||||||||
Total revenues of reportable segments | $ | 247.2 | $ | 6,426.2 | $ | 6,673.4 | ||||||
Segment profit(2) | $ | 50.1 | $ | 16.3 | $ | 66.4 | ||||||
SFAS 133 noncash mark-to-market adjustment(2) | $ | — | $ | (13.4 | ) | $ | (13.4 | ) | ||||
Maintenance capital | $ | 2.8 | $ | 1.2 | $ | 4.0 | ||||||
Three Months Ended March 31, 2004 | ||||||||||||
Revenues: | ||||||||||||
External Customers (includes buy/sell revenues in our Pipeline and GMT&S segments of $46.4 and $1,834.9, respectively)(2) | $ | 173.5 | $ | 3,631.1 | $ | 3,804.6 | ||||||
Intersegment(1) | 15.8 | 0.2 | 16.0 | |||||||||
Total revenues of reportable segments | $ | 189.3 | $ | 3,631.3 | $ | 3,820.6 | ||||||
Segment profit(2) | $ | 25.5 | $ | 28.1 | $ | 53.6 | ||||||
SFAS 133 noncash mark-to-market adjustment(2) | $ | — | $ | 7.5 | $ | 7.5 | ||||||
Maintenance capital | $ | 1.4 | $ | 0.3 | $ | 1.7 | ||||||
(1)(2)
(3)
(4)GMT&S segment profit includes interest expense of $5.8 million and $0.3 million for the quarters ended June 30, 2005 and 2004, respectively, and $9.2 million and $0.4 million for the six month periods ended June 30, 2005 and 2004, respectively, on contango inventory purchases.
(5)The following table reconciles segment profit to consolidated income before cumulative effect of change in accounting principle:
|
| For the three months |
| For the six months |
| ||||||||||||
|
| ended June 30, |
| ended June 30, |
| ||||||||||||
|
| 2005 |
| 2004 |
| 2005 |
| 2004 |
| ||||||||
|
| (in millions) |
| ||||||||||||||
Segment profit |
|
| $ | 95.1 |
|
|
| $ | 61.2 |
|
| $ | 161.5 |
| $ | 114.8 |
|
Depreciation and amortization |
|
| (19.4 | ) |
|
| (16.0 | ) |
| (38.6 | ) | (29.1 | ) | ||||
Gain on sales of assets |
|
| 0.4 |
|
|
| 0.1 |
|
| 0.4 |
| 0.1 |
| ||||
Interest expense |
|
| (14.3 | ) |
|
| (10.0 | ) |
| (28.8 | ) | (19.5 | ) | ||||
Interest income and other, net |
|
| 0.5 |
|
|
| 0.4 |
|
| 0.6 |
| 0.4 |
| ||||
Income before cumulative effect of change in accounting principle |
|
| $ | 62.3 |
|
|
| $ | 35.7 |
|
| $ | 95.1 |
| $ | 66.7 |
|
19
| For the three months ended March 31, | ||||||
---|---|---|---|---|---|---|---|
| 2005 | 2004 | |||||
| (in millions) | ||||||
Segment profit | $ | 66.4 | $ | 53.6 | |||
Depreciation and amortization | (19.1 | ) | (13.1 | ) | |||
Interest expense | (14.6 | ) | (9.5 | ) | |||
Interest and other income (expense), net | 0.1 | — | |||||
Income before cumulative effect of change in accounting principle | $ | 32.8 | $ | 31.0 | |||
Item 2. MANAGEMENT'SMANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to provide investors with an understanding of our financial condition and results of our operations and should be read in conjunction with our historical consolidated financial statements and accompanying notes. For more detailed information regarding the basis of presentation for the following financial information, see the "Notes“Notes to the Consolidated Financial Statements."” Our discussion and analysis includes the following:
·Executive Summary
·Acquisition Activities
·Results of Operations
·Outlook
·Liquidity and Capital Resources
·Commitments
·Forward-Looking Statements and Associated Risks
Company Overview
We are engaged in interstate and intrastate crude oil transportation and crude oil gathering, marketing, terminalling and storage, as well as the marketing and storage of liquefied petroleum gas and other natural gas related petroleum products. We refer to liquified petroleum gas and other natural gas related petroleum products collectively as "LPG."“LPG.” We have an extensive network of pipeline transportation, terminalling, storage and gathering assets in key oil producing basins and at major market hubs in the United States and Canada. We were formed in September of 1998, and our operations are conducted directly and indirectly through our operating subsidiaries, Plains Marketing, L.P., Plains Pipeline, L.P. and Plains Marketing Canada, L.P.
We are one of the largest midstream crude oil companies in North America. As of March 31,June 30, 2005, we owned approximately 15,000 miles of active crude oil pipelines, approximately 37 million barrels of active terminalling and storage capacity and over 400 transport trucks. Currently, we handle an average of over 2.93.0 million barrels per day of physical crude oil through our extensive network of assets located in major oil producing regions of the United States and Canada.
Our operations consist of two operating segments: (i) pipeline transportation operations ("Pipeline Operations"(“Pipeline”) and (ii) gathering, marketing, terminalling and storage operations ("(“GMT&S"&S”). Through our pipeline segment, we engage in interstate and intrastate crude oil pipeline transportation and certain related margin activities. Through our GMT&S segment, we engage in purchases and resales of crude oil and LPG at various points along the distribution chain and we operate certain terminalling and storage assets.
First Quarter 2005 Operating Results Overview
During the firstsecond quarter of 2005, we recognized net income of $32.8$62.3 million and earnings per diluted limited partner unit of $0.43,$0.74, compared to $27.9$35.7 million and $0.44,$0.54, respectively during the firstsecond quarter of 2004.
20
Key items in the firstsecond quarter of 2005 included:
· Very favorable market conditions characterized by relatively strong contango market conditions and reasonably high volatility of acquisitions completed during 2004 and the first quarter of 2005.
·The inclusion in the firstsecond quarter of 2005 of an aggregate charge of approximately $2.2$7.9 million related to both our 1998 Long-Term Incentive Plan ("(“1998 LTIP"LTIP”) and our 2005 Long-Term Incentive Plan ("(“2005 LTIP"LTIP”).
·A non-cash loss of approximately $13.4$12.9 million in the firstsecond quarter of 2005 resulting from the mark-to-market of open derivative instruments pursuant to Statement of Financial Accounting Standard No. 133, as amended ("(“SFAS 133"133”).
During the first half of 2005, we recognized net income of $95.1 million and earnings per diluted limited partner unit of $1.26, compared to $63.6 million and $0.98, respectively during the first half of 2004. The first half of 2005 was characterized by similar market conditions characterizedas were found in the second quarter. Other items impacting first half results were (i) the contributions from assets acquired during 2004, (ii) an aggregate charge of $10.2 million related to our 1998 and 2005 LTIP, and (iii) a non-cash loss of approximately $26.3 million resulting from the mark-to-market of open derivative positions pursuant to SFAS 133. Earnings per limited partner unit (both basic and diluted) for the 2005 periods were reduced by relatively strong contango market conditionsthe application of Emerging Issues Task Force Issue No. 03-06 “Participating Securities and reasonably high volatility and wide differentialsthe Two-Class Method under FASB Statement No. 128.” See Note 5 “Earnings Per Limited Partner Unit” in various grades of crude oil.
We completed several acquisitions during 2005 and 2004 that have impacted the results of operations and liquidity discussed herein. The following acquisitions were accounted for, and the purchase prices were allocated, in accordance with SFAS 141 "Business“Business Combinations."” Our ongoing acquisition activity is discussed further in "Outlook"“Outlook” below.
During the first quarterhalf of 2005, we completed severalthree small transactions for aggregate consideration of approximately $24.3 million. The transactions included several crude oil pipeline systems along the Gulf Coast as well as in Canada. We also acquired an LPG pipeline and terminal in Oklahoma. These acquisitions did not materially impact our results of operations, either individually or in the aggregate.
During 2004, we completed several acquisitions for aggregate consideration of approximately $549.5 million. The aggregate consideration includes cash paid, estimated transaction costs and assumed liabilities and net working capital items. The Link and Capline acquisitions had a material impact on our operations. The following table summarizes our 2004 acquisitions:
Acquisition | Effective Date | Acquisition Price | Operating Segment |
|
|
| Effective |
| Acquisition |
| Operating Segment |
| |||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (in millions) |
|
| (in millions) |
| ||||||||||||||
Capline and Capwood Pipeline Systems ("Capline acquisition") | 03/01/04 | $ | 158.5 | Pipeline | |||||||||||||||
Link Energy LLC ("Link acquisition") | 04/01/04 | 332.3 | Pipeline/GMT&S | ||||||||||||||||
Capline and Capwood Pipeline Systems (“Capline acquisition”) | Capline and Capwood Pipeline Systems (“Capline acquisition”) |
| 03/01/04 |
|
| $ | 158.5 |
|
| Pipeline |
| ||||||||
Link Energy LLC (“Link acquisition”) | Link Energy LLC (“Link acquisition”) |
| 04/01/04 |
|
| 332.3 |
|
| Pipeline/GMT&S |
| |||||||||
Cal Ven Pipeline System | 05/01/04 | 19.0 | Pipeline | Cal Ven Pipeline System |
| 05/01/04 |
|
| 19.0 |
|
| Pipeline |
| ||||||
Schaefferstown Propane Storage Facility | 08/25/04 | 32.0 | GMT&S | Schaefferstown Propane Storage Facility |
| 08/25/04 |
|
| 32.0 |
|
| GMT&S |
| ||||||
Other | various | 7.7 | GMT&S | Other |
| various |
|
| 7.7 |
|
| GMT&S |
| ||||||
Total 2004 Acquisitions | $ | 549.5 | Total 2004 Acquisitions |
|
|
|
| $ | 549.5 |
|
|
|
| ||||||
21
Analysis of Operating Segments
Our operations consist of two operating segments: (i) Pipeline Operations and (ii) GMT&S Operations.&S. Through our pipeline segment, we engage in interstate and intrastate crude oil pipeline transportation and certain related margin activities. Through our GMT&S segment, we engage in purchases and resales of crude oil and LPG at various points along the distribution chain, and we operate certain terminalling and storage assets. We believe that the combination of our terminalling and storage activities and gathering and marketing activities provides a counter-cyclical balance that has a stabilizing effect on our results of operations and cash flow. In a contango market (oil prices for
future deliveries are higher than for current deliveries), we use our tankage to improve our gathering margins by storing crude oil we have purchased at lower prices in the current month for delivery at higher prices in future months. In a backwardated market (oil prices for future deliveries are lower than for current deliveries), we use less storage capacity, but increased marketing margins (premiums for prompt delivery)delivery resulting from high demand) provide an offset to this reduced cash flow. In addition, we supplement the counter-cyclical balance of our asset base with derivative hedging activities.
We evaluate segment performance based on segment profit and maintenance capital. We define segment profit as revenues less (i) purchases, (ii) field operating costs and (iii) segment general and administrative ("(“G&A"&A”) expenses. Each of the items above excludes depreciation and amortization. As a master limited partnership, we make quarterly distributions of our "available cash"“available cash” (as defined in our partnership agreement) to our unitholders. Therefore, we look at each period'speriod’s earnings before non-cash depreciation and amortization as an important measure of segment performance. The exclusion of depreciation and amortization expense could be viewed as limiting the usefulness of segment profit as a performance measure because it does not account in current periods for the implied reduction in value of our capital assets, such as crude oil pipelines and facilities, caused by aging and wear and tear. Management compensates for this limitation by recognizing that depreciation and amortization are largely offset by repair and maintenance costs, which keepmitigate the actual decline in the value of our principal fixed assets from declining.assets. These maintenance costs are a component of field operating costs included in segment profit or in maintenance capital, depending on the nature of the cost. Maintenance capital, which is deducted in determining “available cash”, consists of capital expenditures required either to maintain the existing operating capacity of partially or fully depreciated assets or to extend their useful lives. Capital expenditures made to expand our existing capacity, whether through construction or acquisition, are considered expansion capital expenditures, not considered maintenance capital expenditures.capital. Repair and maintenance expenditures associated with existing assets that do not extend the useful life or expand the operating capacity are charged to expense as incurred. See Note 10 "Operating Segments"“Operating Segments” in the "Notes“Notes to the Consolidated Financial Statements" Statements”
22
for a reconciliation of segment profit to consolidated income before cumulative effect of change in accounting principle. The following table reflects our results of operations and maintenance capital for each segment.
|
| Pipeline |
| GMT&S |
| ||
|
| (in millions) |
| ||||
Three Months Ended June 30, 2005(1)(2) |
|
|
|
|
| ||
Revenues |
| $ | 260.5 |
| $ | 6,931.0 |
|
Purchases(3) |
| (167.8 | ) | (6,834.7 | ) | ||
Field operating costs (excluding LTIP charge) |
| (37.7 | ) | (29.1 | ) | ||
LTIP charge—operations |
| (0.3 | ) | (0.7 | ) | ||
Segment G&A expenses (excluding LTIP charge)(4) |
| (9.2 | ) | (9.9 | ) | ||
LTIP charge—general and administrative(4) |
| (4.1 | ) | (2.9 | ) | ||
Segment profit |
| $ | 41.4 |
| $ | 53.7 |
|
Noncash SFAS 133 impact(5) |
| $ | — |
| $ | (12.9 | ) |
Maintenance capital |
| $ | 2.5 |
| $ | 1.5 |
|
Three Months Ended June 30, 2004 (2) |
|
|
|
|
| ||
Revenues |
| $ | 222.8 |
| $ | 4,941.3 |
|
Purchases(3) |
| (132.9 | ) | (4,891.3 | ) | ||
Field operating costs |
| (31.9 | ) | (27.2 | ) | ||
Segment G&A expenses(4) |
| (10.3 | ) | (9.3 | ) | ||
Segment profit |
| $ | 47.7 |
| $ | 13.5 |
|
Noncash SFAS 133 impact(5) |
| $ | — |
| $ | (6.9 | ) |
Maintenance capital |
| $ | 0.6 |
| $ | 0.7 |
|
Table continued on following page
23
|
| Pipeline |
| GMT&S |
| ||
|
| (in millions) |
| ||||
Six Months Ended June 30, 2005(1)(2) |
|
|
|
|
| ||
Revenues |
| $ | 507.7 |
| $ | 13,357.2 |
|
Purchases(3) |
| (319.5 | ) | (13,204.1 | ) | ||
Field operating costs (excluding LTIP charge) |
| (71.7 | ) | (58.6 | ) | ||
LTIP charge—operations |
| (0.4 | ) | (0.9 | ) | ||
Segment G&A expenses (excluding LTIP charge)(4) |
| (19.4 | ) | (20.0 | ) | ||
LTIP charge—general and administrative(4) |
| (5.2 | ) | (3.6 | ) | ||
Segment profit |
| $ | 91.5 |
| $ | 70.0 |
|
Noncash SFAS 133 impact(5) |
| $ | — |
| $ | (26.3 | ) |
Maintenance capital |
| $ | 5.3 |
| $ | 2.7 |
|
Six Months Ended June 30, 2004(2) |
|
|
|
|
| ||
Revenues |
| $ | 412.1 |
| $ | 8,572.6 |
|
Purchases(3) |
| (269.6 | ) | (8,464.2 | ) | ||
Field operating costs (excluding LTIP charge) |
| (51.2 | ) | (45.7 | ) | ||
LTIP charge—operations |
| (0.1 | ) | (0.4 | ) | ||
Segment G&A expenses (excluding LTIP charge)(4) |
| (16.3 | ) | (18.7 | ) | ||
LTIP charge—general and administrative(4) |
| (1.7 | ) | (2.0 | ) | ||
Segment profit |
| $ | 73.2 |
| $ | 41.6 |
|
Noncash SFAS 133 impact(5) |
| $ | — |
| $ | 0.5 |
|
Maintenance capital |
| $ | 2.1 |
| $ | 1.0 |
|
Three Months Ended March 31,(1)In May 2005, we reclassified certain minor pipeline gathering assets from the GMT&S segment to the Pipeline segment. Historically, we have been the sole shipper on these assets as part of our gathering and 2004marketing operations. Prior period segment information has not been restated for this change since the impact to such periods was not material.
| Pipeline | GMT&S | |||||
---|---|---|---|---|---|---|---|
| (in millions) | ||||||
Three Months Ended March 31, 2005(1) | |||||||
Revenues | $ | 247.2 | $ | 6,426.2 | |||
Purchases | (151.7 | ) | (6,369.4 | ) | |||
Field operating costs (excluding LTIP charge) | (34.0 | ) | (29.5 | ) | |||
LTIP charge—operations | (0.1 | ) | (0.2 | ) | |||
Segment G&A expenses (excluding LTIP charge)(2) | (10.1 | ) | (10.1 | ) | |||
LTIP charge—general and administrative | (1.2 | ) | (0.7 | ) | |||
Segment profit | $ | 50.1 | $ | 16.3 | |||
SFAS 133 noncash mark-to-market adjustment(3) | $ | — | $ | (13.4 | ) | ||
Maintenance capital | $ | 2.8 | $ | 1.2 | |||
Three Months Ended March 31, 2004(1) | |||||||
Revenues | $ | 189.3 | $ | 3,631.3 | |||
Purchases | (136.7 | ) | (3,572.9 | ) | |||
Field operating costs (excluding LTIP charge) | (19.3 | ) | (18.5 | ) | |||
LTIP charge—operations | (0.1 | ) | (0.4 | ) | |||
Segment G&A expenses (excluding LTIP charge)(2) | (6.0 | ) | (9.4 | ) | |||
LTIP charge—general and administrative | (1.7 | ) | (2.0 | ) | |||
Segment profit | $ | 25.5 | $ | 28.1 | |||
SFAS 133 noncash mark-to-market adjustment(3) | $ | — | $ | 7.5 | |||
Maintenance capital | $ | 1.4 | $ | 0.3 | |||
(1)(2)
(3)GMT&S purchases include interest of $5.8 million and $0.3 million for the quarters ended June 30, 2005 and 2004, respectively, and $9.2 million and $0.4 million for the six month periods ended June 30, 2005 and 2004, respectively, on contango inventory purchases.
(2)(4)
(3)(5)
Pipeline Operations
As of March 31,June 30, 2005, we owned approximately 15,000 miles (of which approximately 13,000 miles are included in our pipeline segment) of active gathering and mainline crude oil pipelines located throughout the United States and Canada. Our activities from pipeline operations generally consist of transporting volumes of crude oil for a fee and third party leases of pipeline capacity (collectively referred to as "tariff activities"“tariff activities”), as well as barrel exchanges and buy/sell arrangements (collectively referred to as "pipeline“pipeline margin activities"activities”). In connection with certain of our merchant activities conducted under our gathering and marketing business, we are also shippers on certain of our own pipelines. These transactions are conducted at published tariff rates and eliminated in consolidation. Tariffs and other fees on our pipeline systems vary by receipt point and delivery point. The segment profit generated by our tariff and other fee-related activities depends on the volumes transported on the pipeline and the level of the tariff and other fees charged as well as the fixed and variable field costs of operating the pipeline. Segment profit from our pipeline capacity leases, barrel exchanges and buy/sell arrangements generally reflect a negotiated amount.
24
�� The following table sets forth our operating results from our Pipeline Operations segment for the periods indicated:
|
| Three months ended |
| Six months ended |
| ||||||||
|
| 2005 |
| 2004 |
| 2005 |
| 2004 |
| ||||
|
| (in millions) |
| ||||||||||
Operating Results(1) |
|
|
|
|
|
|
|
|
| ||||
Revenues |
|
|
|
|
|
|
|
|
| ||||
Tariff activities |
| $ | 85.6 |
| $ | 84.0 |
| $ | 175.3 |
| $ | 130.9 |
|
Pipeline margin activities(2) |
| 174.9 |
| 138.8 |
| 332.4 |
| 281.2 |
| ||||
Total pipeline operations revenues |
| 260.5 |
| 222.8 |
| 507.7 |
| 412.1 |
| ||||
Costs and Expenses |
|
|
|
|
|
|
|
|
| ||||
Pipeline margin activities purchases |
| (167.8 | ) | (132.9 | ) | (319.5 | ) | (269.6 | ) | ||||
Field operating costs (excluding LTIP charge) |
| (37.7 | ) | (31.9 | ) | (71.7 | ) | (51.2 | ) | ||||
LTIP charge—operations |
| (0.3 | ) | — |
| (0.4 | ) | (0.1 | ) | ||||
Segment G&A expenses (excluding LTIP charge)(3) |
| (9.2 | ) | (10.3 | ) | (19.4 | ) | (16.3 | ) | ||||
LTIP charge—general and administrative(3) |
| (4.1 | ) | — |
| (5.2 | ) | (1.7 | ) | ||||
Segment profit |
| $ | 41.4 |
| $ | 47.7 |
| $ | 91.5 |
| $ | 73.2 |
|
Maintenance capital |
| $ | 2.5 |
| $ | 0.6 |
| $ | 5.3 |
| $ | 2.1 |
|
Average Daily Volumes (thousands of barrels per day)(4) |
|
|
|
|
|
|
|
|
| ||||
Tariff activities |
|
|
|
|
|
|
|
|
| ||||
All American |
| 50 |
| 59 |
| 52 |
| 57 |
| ||||
Basin |
| 283 |
| 271 |
| 280 |
| 273 |
| ||||
Capline |
| 143 |
| 169 |
| 152 |
| 112 |
| ||||
West Texas/New Mexico Area Systems(5) |
| 410 |
| 374 |
| 406 |
| 291 |
| ||||
Canada |
| 248 |
| 259 |
| 258 |
| 250 |
| ||||
Other |
| 603 |
| 463 |
| 548 |
| 302 |
| ||||
Total tariff activities |
| 1,737 |
| 1,595 |
| 1,696 |
| 1,285 |
| ||||
Pipeline margin activities |
| 67 |
| 74 |
| 71 |
| 73 |
| ||||
Total |
| 1,804 |
| 1,669 |
| 1,767 |
| 1,358 |
|
| Three months ended March 31, | |||||||||
---|---|---|---|---|---|---|---|---|---|---|
| 2005 | 2004 | ||||||||
| (in millions) | |||||||||
Operating Results(1) | ||||||||||
Revenues | ||||||||||
Tariff activities | $ | 89.6 | $ | 47.0 | ||||||
Pipeline margin activities(2) | 157.6 | 142.3 | ||||||||
Total pipeline operations revenues | 247.2 | 189.3 | ||||||||
Costs and Expenses | ||||||||||
Pipeline margin activities purchases | (151.7 | ) | (136.7 | ) | ||||||
Field operating costs (excluding LTIP charge) | (34.0 | ) | (19.3 | ) | ||||||
LTIP charge—operations | (0.1 | ) | (0.1 | ) | ||||||
Segment G&A expenses (excluding LTIP charge)(3) | (10.1 | ) | (6.0 | ) | ||||||
LTIP charge—general and administrative | (1.2 | ) | (1.7 | ) | ||||||
Segment profit | $ | 50.1 | $ | 25.5 | ||||||
Maintenance capital | $ | 2.8 | $ | 1.4 | ||||||
Average Daily Volumes (thousands of barrels per day)(4) | ||||||||||
Tariff activities | ||||||||||
All American | 54 | 55 | ||||||||
Basin | 277 | 275 | ||||||||
Capline(5) | 160 | 54 | ||||||||
West Texas/New Mexico Area Systems(6) | 401 | 209 | ||||||||
Canada | 268 | 240 | ||||||||
Other | 494 | 143 | ||||||||
Total tariff activities | 1,654 | 976 | ||||||||
Pipeline margin activities | 75 | 72 | ||||||||
Total | 1,729 | 1,048 | ||||||||
(1)
(2)
(3)
(4)
(5)
Total revenues fromfor our pipeline operations were approximately $247.2 million and $189.3 millionsegment increased for both the three and six months periods ended March 31,June 30, 2005, as compared to the same periods ended June 30, 2004. The revenue increase in the second quarter of 2005 is primarily related to our margin activities. The revenue increase in the first half of 2005 is related to both our tariff activities (see discussion below) and 2004, respectively. Anour margin activities. The increase in revenues from tariffour margin activities accounted for $42.6 million of the increase (see discussion below). Revenues from our margin
activities increased approximately $15.3 million between thein both periods as a decrease in buy/sell volumes was offset byis related to higher average prices for crude oil sold and transported on our SJVSan Joaquin Valley (“SJV”) gathering system.system partially offset by a decrease in buy/sell volumes. Because the barrels that we buy and sell are generally indexed to the same pricing
25
indices, revenues and purchases will increase and decrease with changes in market prices without significant changes to our margins related to those purchases and sales.
Increases in segmentSegment profit, our primary measure of segment performance, werewas driven by the following:
·Increased volumes and related tariff revenues—The increase in volumes and related tariff revenues during the first six months of 2005 is primarily related to the Link acquisition and other acquisitions completed during 2004.
·Increased revenues from our loss allowance oil—As is common in the industry, our crude oil tariffs incorporate a “loss allowance factor” that is intended to offset losses due to evaporation, measurement and other losses in transit. The loss allowance factor averages approximately 0.2%, by volume. We value the variance of allowance volumes to actual losses at the average market value at the time the variance occurred and the result is recorded as either an increase or decrease to tariff revenues. Gains or losses on sales of allowance oil barrels are also included in tariff revenues. Increased volumes and higher crude oil prices induring the second quarter and first quarterhalf of 2005 as compared to the second quarter and first quarterhalf of 2004 (the NYMEX average was $49.88 for the first quarter of 2005 compared to $35.21 for the first quarter of 2004) have resulted in increased revenues related to loss allowance oil.
·Increased field operating costs—Our continued growth, primarily from the Link acquisition and other acquisitions completed during 2004, is the principal driver of the increase in field operating costs, including the LTIP charge, of $14.7$20.8 million to $34.1$72.1 million for the first quarterhalf of 2005. The increased costs are primarily related to (i) payroll and benefits, (ii) emergency response and environmental remediation of pipeline releases, (iii) maintenance and (iii)(iv) utilities.
·Increased segment G&A expenses—The increase in segment G&A expenses in the first quarterhalf of 2005 is primarily related to the Link acquisition coupled with the percentage of indirect costs allocated to the pipeline operations segment increasing in the 2005 period as our pipeline operations have grown in relation to our GMT&S segment.
As discussed above, the increase in our pipeline operations segment profit for the first half of 2005 is largely related to our acquisition activities. We completed a number of acquisitions during the last nineten months of 2004 that have impacted the results of operations herein. The following presentation helps summarizetable summarizes the impact of recent acquisitions and expansions on volumes and revenues related to our tariff activities.activities (volumes in thousands of barrels per day and revenues in millions):
| Three Months Ended March 31, | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
| 2005 | 2004 | |||||||||
| Revenues | Volumes | Revenues | Volumes | |||||||
| (volumes in thousands of barrels per day and revenues in millions) | ||||||||||
Tariff activities revenues(1)(2)(3) | |||||||||||
2005 acquisitions/expansions | $ | 2.0 | 50 | $ | — | — | |||||
2004 acquisitions/expansions | 38.0 | 696 | 3.3 | 90 | |||||||
All other pipeline systems | 49.6 | 908 | 43.7 | 886 | |||||||
Total tariff activities | $ | 89.6 | 1,654 | $ | 47.0 | 976 | |||||
Three months ended | Six months ended | ||||||||||||||||||||||||||||||||
June 30, 2005 | June 30, 2004 | June 30, 2005 | June 30, 2004 | ||||||||||||||||||||||||||||||
Revenues | Volumes | Revenues | Volumes | Revenues | Volumes | Revenues | Volumes | ||||||||||||||||||||||||||
Tariff activities revenues(1)(2)(3) | |||||||||||||||||||||||||||||||||
2005 acquisitions/expansions |
|
| $ | 4.0 |
|
|
| 114 |
|
|
| $ | — |
|
|
| — |
|
|
| $ | 6.0 |
|
|
| 82 |
|
|
| $ | — |
|
|
| — |
|
|
2004 acquisitions/expansions |
|
| 33.4 |
|
|
| 694 |
|
|
| 38.6 |
|
|
| 702 |
|
|
| 71.4 |
|
|
| 695 |
|
|
| 41.9 |
|
|
| 396 |
|
| ||||
All other pipeline systems |
|
| 48.2 |
|
|
| 929 |
|
|
| 45.4 |
|
|
| 893 |
|
|
| 97.9 |
|
|
| 919 |
|
|
| 89.0 |
|
|
| 889 |
|
| ||||
Total tariff activities |
|
| $ | 85.6 |
|
|
| 1,737 |
|
|
| $ | 84.0 |
|
|
| 1,595 |
|
|
| $ | 175.3 |
|
|
| 1,696 |
|
|
| $ | 130.9 |
|
|
| 1,285 |
|
|
(1)
26
(2)
(3)
Average daily volumes from our tariff activities increased approximately 70%9% in the second quarter of 2005 as compared to the second quarter of 2004, while revenues were relatively flat. The increase is primarily related to the following:
· Pipeline systems that were acquired or brought into service during 2005 totaled approximately 114,000 barrels per day (approximately 84,000 barrels per day of which are attributable to our recently constructed Cushing to Broome pipeline system) and $4.0 million of revenues during the first half of 2005,
· Volumes and revenues from pipeline systems acquired in 2004 decreased in the second quarter of 2005 as compared to the second quarter of 2004, reflecting the following:
—An increase of 46,000 barrels per day and a decrease of $4.6 million in revenues from the pipelines acquired in the Link acquisition in 2005 as compared to 2004 as the volume increase was more than offset by tariff rates that were voluntarily lowered to encourage third-party shippers. Second quarter pipeline segment profit was reduced by approximately $5.0 million because of these market rate adjustments. As a result of these lower tariffs on barrels shipped by us in connection with our gathering and marketing activities, segment profit from GMT&S was increased by a comparable amount,
—A decrease of 60,000 barrels per day and $1.2 million of revenues from the pipelines acquired in the Capline acquisition in 2005 compared to 2004. Volumes on pipelines acquired in the Capline acquisition were higher than expected in the second quarter of 2004 as there was an increase in refiner demand. Volumes in the second quarter of 2005 returned to expected levels, and
—An increase in the first half of 2005 as compared to the first half of 2004 of 6,000 barrels per day and $0.6 million of revenues from other businesses acquired in the last nine months of 2004.
· All other pipeline systems (those acquired prior to 2004) reflect:
—Increased tariff rates on certain of our systems, partially related to the quality of crude oil shipped,
—The appreciation of Canadian currency (the Canadian to U.S. dollar exchange rate appreciated to an average of 1.24 to 1 for the second quarter of 2005 compared to an average of 1.36 to 1 in the second quarter of 2004), and
—Volume increases on certain of our systems.
In the first half of 2005, average daily volumes from our tariff activities increased approximately 32% to approximately 1.7 million barrels per day and revenues from our tariff activities increased over 90%34% to $89.6$175.3 million.
The increase in the first quarterhalf of 2005 is predominately related to the inclusion of pipeline systems acquired in 2004:2004 for the entire period versus only a portion of the period in 2004, as well as pipeline systems acquired or brought into service during 2005:
· Pipeline systems that were acquired or brought into service during 2005 totaled approximately 82,000 barrels per day and $26.0$6.0 million of revenues during the first half of 2005.
27
· Volumes and revenues from pipeline systems acquired in 2004 increased in the first half of 2005 as compared to the first half of 2004, reflecting the following:
—An increase in 2005 as compared to 2004 of 218,000 barrels per day and $21.5 million of revenues from the pipelines acquired in the Link acquisition,
—An increase of 70,000 barrels per day and $10.9$6.3 million of revenues in 2005 as compared to 2004 from the pipelines acquired in the Capline acquisition, and
—An increase of 11,000 barrels per day and $1.1$1.7 million of revenues in the first half of 2005 as compared to the first half of 2004 from other businesses acquired in the last nine months of 2004.
· Revenues from all other pipeline systems (those acquired prior to 2004) also increased in the first quarterhalf of 2005, along with a slight increase in volumes. The increase in revenues is related to several items including (i) increasedincluding:
—Increased tariff rates on certain of our systems, partially related to the quality of crude oil shipped, (ii) the
—The appreciation of Canadian currency (the Canadian to U.S. dollar exchange rate appreciated to an average of 1.231.24 to 1 for the first quarterhalf of 2005 compared to an average of 1.321.34 to 1 in the first quarterhalf of 2004), and (iii) volume
—Volume increases on certain of our systems.
Gathering, Marketing, Terminalling and Storage Operations
As of March 31,June 30, 2005, we owned approximately 37 million barrels of active above-ground crude oil terminalling and storage facilities, including a crude oil terminalling and storage facility at Cushing, Oklahoma. Cushing, which we refer to as the Cushing Interchange, is one of the largest crude oil market hubs in the United States and the designated delivery point for New York Mercantile Exchange, or NYMEX, crude oil futures contracts. Terminals are facilities where crude oil is transferred to or from storage or a transportation system, such as a pipeline, to another transportation system, such as trucks or another pipeline. The operation of these facilities is called "terminalling."“terminalling.” Approximately 14 million barrels of our 37 million barrels of tankage is used primarily in our GMT&S Operations segment and the balance is used in our Pipeline Operations segment.
On a stand-alone basis, segment profit from terminalling and storage activities is dependent on the throughput of volumes, the volume of crude oil stored and the level of fees generated from our terminalling and storage services. Our terminalling and storage activities are integrated with our gathering and marketing activities and thus the level of tankage that we allocate for our arbitrage activities (and therefore not available for lease to third parties) varies throughout crude oil price cycles. This integration enables us to use our storage tanks in an effort to counter-cyclically balance and hedge our gathering and marketing activities. In a contango market (when oil prices for future deliveries are higher than for current deliveries), we use our tankage to improve our gathering margins by storing crude oil we have purchased at lower prices in the current month for delivery at higher prices in future months. In a backwardated market (when oil prices for future deliveries are lower than for current deliveries), we use less storage capacity, but increased marketing margins (premiums for prompt delivery)delivery resulting from high demand) provide an offset to this reduced cash flow. In addition, we supplement the counter-cyclical balance of our asset base with derivative hedging activities. We believe that this combination of our terminalling and storage activities, and gathering and marketing activities and our hedging activities provides a counter-cyclical balance that has a stabilizing effect on our results of operations and cash flows. We also believe that this balance enables us to protect against downside risk while at the same time providing us with upside opportunities in volatile market conditions.
28
Our revenues from gathering and marketing activities reflect the sale of gathered and bulk-purchased crude oil and LPG volumes, plus the sale of additional barrels exchanged through buy/sell arrangements entered into to supplement the margins of the gathered and bulk-purchased volumes. Because the commodities that we buy and sell are generally indexed to the same pricing indices for both the purchase and the sale, revenues and costs related to purchases will increase and decrease with changes in market prices. However, the margins related to those purchases and sales will not necessarily have corresponding increases and decreases. For example, our revenues increased approximately 77% 40% and 56%in the second quarter and first quarterhalf of 2005, respectively, compared to the second quarter and first quarterhalf of 2004, whilerespectively. During the same time periods, our
segment profit decreasedincreased almost 42%300% and 68%, respectively. These increases are discussed further below.
The increase in revenues for both the same period. This decrease is related to the impactsecond quarter and first half of the SFAS 133 noncash mark-to-market adjustment which resulted in a decrease in segment profit of 74% (see discussion below).
Revenues from our GMT&S operations were approximately $6.4 billion and $3.6 billion for the quarters ended March 31, 2005 and 2004, respectively. Revenues and costs related to purchases for the 2005 period were impacted by higher average prices and higher volumes as compared to the same periods in 2004 period. Approximately 70%was primarily because of the increase in revenues resulted from higher averagecrude oil prices induring the 2005 period and the remainder was attributable to increased sales volumes.periods. The average NYMEX price for crude oil was $49.88$53.23 per barrel and $35.21$51.60 per barrel for the quarter and six months ended March 31,June 30, 2005, respectively, as compared to $38.28 per barrel and $36.78 per barrel for the same periods in 2004, respectively.
Generally, we expect our segment profit to increase or decrease directionally with increases or decreases in lease gathered volumes and LPG sales volumes. Although we believe that the combination of our lease gathering business and our storage assets provides a counter-cyclical balance that provides stability in our margins, these margins are not fixed and may vary from period to period. In order to evaluate the performance of this segment, management focuses on the following metrics: (i) segment profit (ii) crude oil lease gathered volumes and LPG sales volumes and (iii) segment profit per barrel calculated on these volumes. The following table sets forth our operating results from our GMT&S Operations segment for the comparative periods indicated:
|
| Three months ended |
| Six months ended |
| ||||||||
|
| June 30, |
| June 30, |
| ||||||||
|
| 2005 |
| 2004 |
| 2005 |
| 2004 |
| ||||
|
| (in millions) |
| ||||||||||
Operating Results(1) |
|
|
|
|
|
|
|
|
| ||||
Revenues(2)(3) |
| $ | 6,931.0 |
| $ | 4,941.3 |
| $ | 13,357.2 |
| $ | 8,572.6 |
|
Purchases and related costs(4) |
| (6,834.7 | ) | (4,891.3 | ) | (13,204.1 | ) | (8,464.2 | ) | ||||
Field operating costs (excluding LTIP charge) |
| (29.1 | ) | (27.2 | ) | (58.6 | ) | (45.7 | ) | ||||
LTIP charge—operations |
| (0.7 | ) | — |
| (0.9 | ) | (0.4 | ) | ||||
Segment G&A expenses (excluding LTIP charge)(5) |
| (9.9 | ) | (9.3 | ) | (20.0 | ) | (18.7 | ) | ||||
LTIP charge—general and administrative(5) |
| (2.9 | ) | — |
| (3.6 | ) | (2.0 | ) | ||||
Segment profit(3) |
| $ | 53.7 |
| $ | 13.5 |
| $ | 70.0 |
| $ | 41.6 |
|
SFAS 133 noncash mark-to-market adjustment(3) |
| $ | (12.9 | ) | $ | (6.9 | ) | $ | (26.3 | ) | $ | 0.5 |
|
Maintenance capital |
| $ | 1.5 |
| $ | 0.7 |
| $ | 2.7 |
| $ | 1.0 |
|
Segment profit per barrel(6) |
| $ | 0.91 |
| $ | 0.23 |
| $ | 0.57 |
| $ | 0.39 |
|
Average Daily Volumes (thousands of barrels per day)(7) |
|
|
|
|
|
|
|
|
| ||||
Crude oil lease gathering |
| 628 |
| 641 |
| 625 |
| 550 |
| ||||
LPG sales |
| 26 |
| 21 |
| 55 |
| 40 |
|
| Three months ended March 31, | |||||||
---|---|---|---|---|---|---|---|---|
| 2005 | 2004 | ||||||
| (in millions, except per barrel amounts) | |||||||
Operating Results(1) | ||||||||
Revenues(2)(4) | $ | 6,426.2 | $ | 3,631.3 | ||||
Purchases and related costs | (6,369.4 | ) | (3,572.9 | ) | ||||
Field operating costs (excluding LTIP charge) | (29.5 | ) | (18.5 | ) | ||||
LTIP charge—operations | (0.2 | ) | (0.4 | ) | ||||
Segment G&A expenses (excluding LTIP charge)(3) | (10.1 | ) | (9.4 | ) | ||||
LTIP charge—general and administrative | (0.7 | ) | (2.0 | ) | ||||
Segment profit(4) | $ | 16.3 | $ | 28.1 | ||||
SFAS 133 noncash mark-to-market adjustment(4) | $ | (13.4 | ) | $ | 7.5 | |||
Maintenance capital | $ | 1.2 | $ | 0.3 | ||||
Segment profit per barrel(5) | $ | 0.26 | $ | 0.60 | ||||
Average Daily Volumes (thousands of barrels per day)(6) | ||||||||
Crude oil lease gathering | 622 | 460 | ||||||
LPG sales | 84 | 59 | ||||||
(1)
(2)
29
months ended June 30, 2005 and 2004, respectively. The previously referenced amounts include certain estimates based on management'smanagement’s judgment; such estimates are not expected to have a material impact on the balances.
(3)
(4)Purchases and related costs include interest expense of $5.8 million and $0.3 million for the quarters ended June 30, 2005 and 2004, respectively, and $9.2 million and $0.4 million for the six month periods ended June 30, 2005 and 2004, respectively, on contango inventory purchases.
(5)Segment G&A expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments based on the business activities that existed at that time. The proportional allocations by segment require judgment by management and will continue to be based on the business activities that exist during each period.
(4)(6)
(6)(7)
Segment profit decreased 42%for the second quarter and first half of 2005 greatly exceeded the comparable 2004 periods. The increase in the 2005 periods is partially driven by increased volumes (for the six month period) and synergies realized from businesses acquired in the last eighteen months coupled with very favorable market conditions.
The primary drivers of the current periods results were:
· Favorable market conditions—These favorable market conditions include a shift in the market structure from a backwardated market of as wide as $1.14 per barrel in late 2004 to $16.3 milliona prolonged and pronounced contango market that has been as wide as $1.91 during the first half of 2005. The contango market structure averaged approximately $0.33 and $1.16 for the first quarterand second quarters of 2005, respectively. Although we are normally adversely impacted by the initial transition from a backwardated market to a contango market, the market has remained in contango throughout most of the first half of 2005 and we have been able to adjust our purchases at the wellhead to both maintain our margins and remain competitive in the gathering and marketing business. In addition, we have been able to use a portion of our tankage in our terminalling and storage business to capture a significant level of profits from contango-related strategies. We have been able to do this because the market has already transitioned to a contango market and has remained there for an extended period of time.
During the 2005 period, the market has also experienced significantly high volatility in price and market structure of crude oil. The NYMEX benchmark price of crude oil has ranged from $41.25 to $60.95 during the first half of 2005. This volatile market allowed us to utilize our hedging activities tooptimize and enhance the margins of both our gathering and marketing assets and our terminalling and storage assets at different times during the quarter. Increased receipts of foreign crude oil movements at our facilities also positively impacted our results.
· Increased crude oil lease gathered volumes and LPG sales volumes—The crude oil volumes gathered from producers, using our assets or third-party assets, have increased by approximately 14% during the first half of 2005 as compared to the first quarterhalf of 2004. The increase is primarily related to the Link acquisition. In addition, we marketed 38% more LPG during the first half of 2005 as compared to 2004. Crude oil lease gathered volumes and LPG sales volumes were both relatively flat in the second quarter of 2005 as compared to 2004.
· Increased tankage used in our GMT&S Operations—The positive impact of the favorable market conditions discussed above was further enhanced by the increase in the amount of tankage used in our GMT&S Operations to approximately 14 million barrels during 2005 as compared to 11 million and 12.6 million barrels in the first and second quarters of 2004, respectively.
30
· Decreased purchases and related costs—Lower tariffs on barrels shipped by us on certain pipelines acquired in the Link acquisition reduced purchases and related costs by approximately $5.0 million. Segment profit for our Pipeline segment was decreased by a comparable amount.
· Increased field operating costs—Our continued growth, primarily from the Link acquisition, is the primary reasondriver of the increase in field operating costs for the decrease from quarterfirst half of 2005 as compared to quarter is the impactfirst half of our2004. The increased costs are pimarily related to (i) payroll and benefits and (ii) fuel.
The 2005 period also includes a noncash mark-to-market adjustment for open derivative instrumentsloss of $12.9 million pursuant to SFAS 133. The noncash mark-to-market adjustment133 that was recognized in the second quarter compared to a net loss of $13.4$6.9 million in the currentsecond quarter of 2004. In addition, we recognized a net loss of $26.3 million in the first half of 2005 pursuant to SFAS 133 compared to a net gain of $7.5$0.5 million in the first quarterhalf of 2004. This adjustment resulted in a decrease in segment profit of 74%. The primary components of the $26.3 million noncash adjustment in the first quarter of 2005 were:
·A decrease in the mark-to-market of approximately $4.6$20.3 million resulting from the change in fair value for option and futures contracts that serve to reduce our lease gathering and tankage business exposures. Because the tankage arrangements will not necessarily result in physical delivery, they are not eligible for hedge accounting treatment under SFAS 133. In addition, because our option activity often involves option sales, these also do not receive hedge accounting treatment. While these derivatives do not qualify for hedge accounting, their purpose is to mitigate risk associated with our physical assets in our storage and terminalling activities and contractual arrangements in our lease gathering activities.
·A decrease in the mark-to-market of approximately $2.6$6.9 million resulting from the change in fair value of our Canadian and LPG derivative contracts, which do not consistently qualify for hedge accounting because the correlations tend to fluctuate;fluctuate. These positions primarily consist of hedges of stored inventory and
·An increase in the mark-to-market of $0.6$0.9 million primarily related to the change in fair value of certain derivative instruments used to minimize the risk of unfavorable changes in exchange rates.
The other primary drivers of current quarter results were:
During the first quarter of 2004, the NYMEX benchmark price of crude ranged from $32.20 to $38.50.
The impact Total settlements related to these derivatives during the first half of the items discussed above resulted in segment2005 were $1.3 million.
Segment profit per barrel (calculated based on our lease gathered crude oil and LPG barrels) of $0.26volumes) was $0.91 per barrel for the quarter ended March 31,June 30, 2005, compared to $0.60$0.23 for the quarter ended March 31,June 30, 2004. The SFAS 133 noncash mark-to-market adjustment had a negative $0.21 segmentSegment profit per barrel impact inwas $0.57 for the first quarterhalf of 2005, compared to a positive $0.16 segment profit$0.39 per barrel impact infor the first quarterhalf of 2004.
As discussed above, our current period results were strongly impacted by favorable market conditions. We are not able to predict with any reasonable level of accuracy whether market conditions will continue to remain as favorable as have recently been experienced, and operating results may not be indicative of sustainable performance.
Other Expenses
Depreciation and Amortization
Depreciation and amortization expense was $19.1increased approximately $9.5 million forto $38.6 million in the three months ended March 31, 2005, compared to $13.1 million for the three months ended March 31, 2004.first half of 2005. The increase relates primarily to the assets from our 2004 acquisitions being included for the full quarterentire period in 2005 versus only a part or none of the quarterperiod in 2004. Additionally, several capital projects
31
were completed during mid-to-late 2004 that were not included in first quarterhalf of 2004 depreciation expense. The increase of $3.4 million to $19.4 million in the second quarter of 2005 is primarily related to the capital projects completed in 2004, as previously mentioned. Amortization of debt issue costs was $0.6$0.7 million and $0.5$1.3 million in the second quarter and first quarterhalf of 2005, respectively, and 2004, respectively.was relatively flat compared to the corresponding periods in 2004.
Interest Expense
The amount of interestInterest expense we recognize is primarily impacted by:
·our average debt balances,
·the level and maturity of fixed rate debt, and
·interest rates associated therewith, market interest rates and our interest rate hedging activities on floating rate debt.
During the first quarter of 2005, our average debt balance was approximately $1.0 billion, compared to an average balance of approximately $0.6 billion for the first quarter of 2004. The following table summarizes the components of theseour average debt balances:
|
| For the three |
| For the six |
| ||||||||||||||||
|
| months ended June 30, |
| months ended June 30, |
| ||||||||||||||||
|
| 2005 |
| 2004 |
| 2005 |
| 2004 |
| ||||||||||||
|
| (average amount outstanding, in millions) |
| ||||||||||||||||||
Fixed rate senior notes(1) |
|
| $ | 863 |
|
|
| $ | 450 |
|
|
| $ | 832 |
|
|
| $ | 450 |
|
|
Borrowings under our |
|
| 163 |
|
|
| 493 |
|
|
| 187 |
|
|
| 321 |
|
| ||||
Total |
|
| $ | 1,026 |
|
|
| $ | 943 |
|
|
| $ | 1,019 |
|
|
| $ | 771 |
|
|
| For the three months ended March 31, | |||||
---|---|---|---|---|---|---|
| 2005 | 2004 | ||||
| (average amount outstanding, in millions) | |||||
Fixed rate senior notes(1) | $ | 800 | $ | 450 | ||
Borrowings under our revolving credit facilities | 211 | 149 | ||||
Total | $ | 1,011 | $ | 599 | ||
(1)
(2)Excludes borrowings under our senior secured hedged inventory facility and other contango inventory-related borrowings.
The higher average debt balance in both of the 2005 periodperiods was primarily related to the portion of our acquisitions that were not refinancedfinanced with equity, coupled with borrowings related to other capital projects. Our financial growth strategy is to fund our acquisitions using a balance of debt and equity. Our weighted average interest rate, excluding commitment and other fees, was approximately 6.1%6.2% for both periods.of the 2005 periods, compared to 4.2% and 4.9% for the second quarter and first half of 2004, respectively.
The net impact of the items discussed above was an increase in interest expense in the firstsecond quarter of 2005 of approximately $5.0$4.3 million to a total of $14.6$14.3 million. ThisIn the first half of 2005, interest expense increased $9.3 million to $28.8 million. The increase in interest expense in the second quarter of 2005 is primarily related to the riseincrease in our weighted average interest rate, along with the increase in our average debt balance. The increase in interest expense in the first half of 2005 is related to both the increase in our average debt balance partially offset by anand the increase in our weighted average interest capitalized.rate.
Interest costs attributable to borrowings for inventory stored inventoryin a contango market are included in purchases and related costs in our GMT&S segment profit for purposes of matching those costs withas we consider interest on these borrowings a direct cost to storing the profits realized on storing crude oil.inventory. These borrowings are primarily under our senior secured hedged inventory facility. These costs were approximately $3.4$5.8 million and $0.1$9.2 million for the quarters ended March 31,second quarter and first half of 2005, respectively. In 2004, these costs were approximately $0.3 million and 2004,$0.4 million for the second quarter and first half, respectively.
32
Outlook
This "Outlook"“Outlook” section and the section captioned "Forward“Forward Looking Statements and Associated Risks"Risks” identify certain matters of risk and uncertainty that may affect our financial performance and results of operations in the future.
Ongoing Acquisition Activities.Consistent with our business strategy, we are continuously engaged in discussions with potential sellers regarding the possible purchase by us of transportation, gathering, terminalling or storage assets and related midstream crude-oil businesses. These acquisition efforts often involve assets which, if acquired, would have a material effect on our financial condition and results of operations. In an effort to prudently and economically leverage our asset base, knowledge base and skill sets, management has also expanded its efforts to encompass other midstream businesses thatto which such resources effectively can be applied. We are closely related to, or significantly intertwinedpresently engaged in discussions and negotiations with various parties regarding the crude oil business. Weacquisition of assets and businesses described above, but we can give no assurance that our current or future acquisition efforts will be successful or that any such acquisition will be completed on terms considered favorable to us.
As a result of several factors including the tight supply and demand relationship for crude oil world-wide, we believe the crude oil market will continue to be volatile and subject to frequent short-term swings in market prices and shifts in market structure. Over the last seven months, crude oil prices ranged from a low of around $40.00 per barrel to a high of approximately $58.00 per barrel. During that same period, the spread between the futures contracts in the first two months ranged from nearly $1.00 backwardated to as much as $1.90 per barrel contango. While there can be no assurance that such volatile conditions will not have an unanticipated adverse effect on the partnership in the future, we believe the strategic nature of our asset base and our complementary business model position the partnership to benefit from such market conditions, subject to a number of inherent business risks, including our maintaining an attractive credit rating and our continuing ability to receive open credit from our suppliers and trade counter-parties.
Based on this outlook, we increased the capacity of our senior unsecured credit facility and intend to take various actions to further increase our liquidity and ensure that we are positioned to prudently optimize the use of our asset base in the event that prices rise significantly (see discussion in "Liquidity" below). These steps may include one or more of the following actions: increasing the size of our hedged inventory facility; accessing the long-term debt capital markets, and thus increasing the availability under our outstanding credit facility; and/or the issuance of equity.
Liquidity and Capital Resources
Liquidity
Cash generated from operations and our credit facilities are our primary sources of liquidity. At March 31,June 30, 2005, we had a working capital deficit of approximately $115.5$121.5 million, approximately $320.5$618.7 million of availability under our committed revolving credit facilities and no unused capacityapproximately $144.3 million of availability under our uncommitted hedged inventory facility (see "Capital Resources"“Capital Resources” below). Usage of the credit facilities is subject to compliance with covenants. We believe we are currently in compliance with all covenants.
Capital Resources
In FebruaryJuly 2005, we issued 575,000 common unitsfiled with the Securities and Exchange Commission a universal shelf registration statement that, subject to a subsidiaryeffectiveness at the time of Vulcan Energy Corporation. The sale price for the common units was $38.13 per unit resulting in net proceeds, including the general partner's proportionate capital contribution and expenses associated withuse, allows us to issue from time to time up to an aggregate of $2 billion of debt or equity securities.
During May 2005, we completed the sale of approximately $22.3 million.$150 million of 5.25% Senior Notes due 2015. The notes were sold at 99.518% of face value. We intend to useused the net proceeds from the private placement to fund a portion of our 2005 expansion capital program. Pending the incurrence of such expenditures, the net proceeds were usedapproximately $148 million, after deducting initial purchaser discounts and offering costs, to repay indebtednessamounts outstanding under our revolving credit facilities.facilities and for general partnership purposes.
In April 2005, we amended our senior secured hedged inventory facility to increase the capacity under the facility from $425 million to $500 million. We are in the process of negotiating an additional expansion of this facility to increase its capacity by up to $300 million. In addition, in May 2005, we amended our senior unsecured credit facility to increase the capacity from $750 million to $900 million and increased the sub-facility for Canadian borrowings to $360 million. The amended facility can be expanded to $1.25 billion.billion, subject to obtaining additional lender commitments. Additionally, in the second quarter of 2005, we amended our senior secured hedged inventory facility to increase the capacity under the facility from $425 million to $800 million.
In February 2005, we issued 575,000 common units to a subsidiary of Vulcan Energy Corporation. The sale price for the common units was $38.13 per unit resulting in net proceeds, including the general partner’s proportionate capital contribution and expenses associated with the sale, of approximately $22.3 million. Although the net proceeds were used to repay indebtedness under our revolving credit facilities at closing, they will ultimately be used to fund a portion of our 2005 expansion capital program as these expenditures are incurred.
33
Capital Expenditures
We have made and will continue to make capital expenditures for acquisitions, expansion capital and maintenance capital. Historically, we have financed these expenditures primarily with cash generated by operations, credit facility borrowings, the issuance of senior unsecured notes and the sale of additional common units.
We expect to spend approximately $190 million on expansion capital projects during 2005. This includes our original estimate of expansion capital and newly announced projects, the most notable of which is our recently announced construction of a St. James, Louisiana storage facility. The St. James facility has an estimated total project cost of approximately $85 million, of which approximately $21 million will be spent in 2005. Our 2005 expansion capital projects include the following notable projects with the estimated cost for the entire year.
|
| 2005 |
| |||
|
| Total |
| |||
|
| (in millions) |
| |||
St. James, Louisiana storage facility |
|
| $ | 21.0 |
|
|
Trenton pipeline expansion |
|
| $ | 34.0 |
|
|
Capital projects associated with the Link acquisition |
|
| $ | 18.0 |
|
|
NW Alberta fractionator |
|
| $ | 16.0 |
|
|
Cushing Phase V expansion |
|
| $ | 13.0 |
|
|
Kerrobert Tank expansion |
|
| $ | 9.0 |
|
|
Shell South Louisiana asset acquisition |
|
| $ | 8.0 |
|
|
Approximately $73 million of our forecasted expansion capital was incurred as of June 30, 2005. Capital expenditures for maintenance projects are forecast to be approximately $19 million during 2005, of which approximately $8 million was incurred in the first six months.
We believe that we have sufficient liquid assets, cash flow from operations and borrowing capacity under our credit agreements to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. However, we are subject to business and operational risks that could adversely affect our cash flow. A material decrease in our cash flows would likely produce an adverse effect on our borrowing capacity.
Cash Flows
| Three Months Ended March 31, | |||||||
---|---|---|---|---|---|---|---|---|
| 2005 | 2004 | ||||||
| (in millions) | |||||||
Cash provided by (used in): | ||||||||
Operating activities | $ | (271.8 | ) | $ | 133.0 | |||
Investing activities | (61.7 | ) | (155.9 | ) | ||||
Financing activities | 342.6 | (21.1 | ) |
|
| Six Months Ended |
| ||||
|
| 2005 |
| 2004 |
| ||
|
| (in millions) |
| ||||
Cash provided by (used in): |
|
|
|
|
| ||
Operating activities |
| $ | (453.4 | ) | $ | 147.1 |
|
Investing activities |
| (97.4 | ) | (474.6 | ) | ||
Financing activities |
| 576.6 |
| 334.0 |
| ||
Operating Activities.The primary drivers of our cash flow from operations are (i) the collection of amounts related to the sale of crude oil and LPG and the transportation of crude oil for a fee and (ii) the payment of amounts related to the purchase of crude oil and LPG and other expenses, principally field operating costs and general and administrative expenses. The cash settlement from the purchase and sale of crude oil during any particular month typically occurs within thirty days from the end of the month, except in the months that we store inventory because of contango market conditions or in months that we increase linefill. The storage of crude oil in periods of a contango market can have a material impact on our cash flows from operating activities for the period we pay for and store the crude oil and the
34
subsequent period that we receive proceeds from the sale of the crude oil. When we store the crude oil, we borrow on our credit facilities to pay for the crude oil so the impact on operating cash flow is negative. Conversely, cash flow from operating activities increases in the period we collect the cash from the sale of the stored crude oil. In addition,Similarly, our cash flow from operating activities is also impacted by the level of LPG inventory stored at period end. Cash flow used in operating activities was $271.8$453.4 million in 2005.the 2005 period. Cash flow provided by operating activities was $133.0$147.1 million in 2004.the 2004 period.
Cash flows from operating activities in 2005 reflects the purchase and storage of crude oil because of contango market conditions. During the first quarter,half of 2005, we purchased crude oil for storage. These purchases had a negative impact on cash flows from operating activities when the invoices for the crude oil were paid. The proceeds we received from our credit facilities to pay for the crude oil while stored are shown as financing activities in the cash flow statement. As such, until we deliver the crude oil and receive payment from our customers, operating activities in the cash flow statement will be negatively impacted by this activity. Crude oil stored is hedged against price risk.
Investing Activities.Net cash used in 2005 was $61.7$97.4 million and was predominantly related to additions to property and equipment comprised of (i) $15.4$22.6 million paid for our Trenton pipeline expansion, (ii) $10.2$12.1 million paid for our Cushing to Broome pipeline expansion, (iii) $3.1$6.0 million paid for our Cushing Phase V expansion, and (iv) various other projects oftotaling approximately $21.3$45.6 million. Additionally, approximately $13.5$14.5 million was paid for various acquisitions. Net cash used in 2004 was
$155.9 $474.6 million and was primarily comprised of (i) $142.3 million paid for the Capline and Capwood Pipeline Systems acquisition (a deposit had been paid in December 2003), (ii) approximately $280 million paid for the Link acquisition, (iii) approximately $19 million paid for the CalVen acquisition and (ii) $13.3(iv) $32.2 million paid for additions to property and equipment, including approximately $3.4 million related to the Cushing Phase IV expansion.equipment.
Financing Activities.Cash provided by financing activities in the first half of 2005 was approximately $342.6$576.6 million, primarily consisting of:
· approximately $149.3 million of proceeds from the sale of senior notes,
·approximately $22.3 million of proceeds from a private placement of common units,
·net short and long-term borrowingsrepayments under our revolving credit facility of approximately $23.5$71.8 million,
·net borrowings under our short-term letter of credit and hedged inventory facility of approximately $344.6$575.3 million for the purchase of crude oil inventory that was stored (see "Operating Activities"“Operating Activities” above), and
· $92.7 million of distributions paid to common unitholders and the general partner.
Cash provided by financing activities in the first half of 2004 was approximately $21.1$334.0 million, primarily consisting of:
· approximately $101.2 million of proceeds from the issuance of Class C common units,
·net short and long-term borrowings under our revolving credit facility of approximately $157.5$403.7 million used primarily to fund the purchase price of the Capline acquisition,
·net repayments under our short-term letter of credit and hedged inventory facility of approximately $100.5$96.1 million resulting from the collection of receivables related to prior year sales of inventory that was stored because of contango market conditions, and
· $72.7 million of distributions paid to common unitholders and the general partner.
35
Contingencies
See Note 9 "Commitments“Commitments and Contingencies"Contingencies” in "Notes“Notes to the Consolidated Financial Statements."”
Contractual Obligations.In the ordinary course of doing business we purchase crude oil and LPG from third parties under contracts, the majority of which range in term from thirty-day evergreen to three years. We establish a margin for these purchases by entering into various types of physical and financial sale and exchange transactions through which we seek to maintain a position that is substantially balanced between crude oil and LPG purchases and sales and future delivery obligations. The table below includes purchase obligations related to these activities. Where applicable, the amounts presented represent the net obligations associated with buy/sell contracts and those subject to a net settlement arrangement with the counterparty. We do not expect to use a significant amount of internal capital to meet these obligations, as the obligations will be funded by corresponding sales to credit worthy entities.
The following table includes our best estimate of the amount and timing of these payments as well as others due under the specified contractual obligations as of March 31,June 30, 2005.
| | 2005 | 2006 | 2007 | 2008 | 2009 | Thereafter |
| 2005 |
| 2006 |
| 2007 |
| 2008 |
| 2009 |
| Thereafter |
| ||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | (in millions) |
| (in millions) |
| |||||||||||||||||||||||||||||||||||
Long-term debt and interest payments(1) | Long-term debt and interest payments(1) | $ | 40.3 | $ | 53.8 | $ | 53.8 | $ | 53.8 | $ | 352.9 | $ | 799.7 |
| $ | 28.8 |
| $ | 57.5 |
| $ | 57.5 |
| $ | 57.5 |
| $ | 232.3 |
|
| $ | 997.0 |
|
| ||||||
Leases(2) | Leases(2) | 13.4 | 14.0 | 11.5 | 8.9 | 7.8 | 48.0 |
| 9.2 |
| 14.7 |
| 12.2 |
| 9.6 |
| 8.5 |
|
| 48.3 |
|
| ||||||||||||||||||
Capital expenditure obligations | Capital expenditure obligations | 23.4 | — | — | — | — | — |
| 15.0 |
| — |
| — |
| — |
| — |
|
| — |
|
| ||||||||||||||||||
Other long-term liabilities(3) | Other long-term liabilities(3) | 2.8 | 7.4 | 5.5 | 1.1 | 0.6 | 2.5 |
| — |
| 4.0 |
| 9.7 |
| 1.7 |
| 5.9 |
|
| 2.6 |
|
| ||||||||||||||||||
Subtotal |
| 53.0 |
| 76.2 |
| 79.4 |
| 68.8 |
| 246.7 |
|
| 1,047.9 |
|
| |||||||||||||||||||||||||
Crude oil and LPG purchases(3)(4) |
| 2,174.4 |
| 166.6 |
| 102.6 |
| 102.6 |
| 102.5 |
|
| 17.0 |
|
| |||||||||||||||||||||||||
Total |
| $ | 2,227.4 |
| $242.8 |
| $182.0 |
| $171.4 |
| $ | 349.2 |
|
| $ | 1,064.9 |
|
| ||||||||||||||||||||||
Subtotal | 79.9 | 75.2 | 70.8 | 63.8 | 361.3 | 850.2 | ||||||||||||||||||||||||||||||||||
Crude oil and LPG purchases(4) | 1,419.0 | 132.4 | 114.7 | 114.7 | 93.1 | — | ||||||||||||||||||||||||||||||||||
Total | $ | 1,498.9 | $ | 207.6 | $ | 185.5 | $ | 178.5 | $ | 454.4 | $ | 850.2 | ||||||||||||||||||||||||||||
(1)
(2)
(3)
(4)
Letters of Credit.In connection with our crude oil marketing, we provide certain suppliers and transporters with irrevocable standby letters of credit to secure our obligation for the purchase of crude oil. Our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the crude oil is purchased. Generally, these letters of credit are issued for up to seventy-day periods and are terminated upon completion of each transaction. At March 31,June 30, 2005, we had outstanding letters of credit under our various facilities of approximately $174.5$121.3 million.
Forward-Looking Statements and Associated Risks
All statements, other than statements of historical fact, included in this report are forward-looking statements, including, but not limited to, statements identified by the words "anticipate," "believe," "estimate," "expect," "plan," "intend"“anticipate,” “believe,” “estimate,” “expect,” “plan,” “intend” and "forecast,"“forecast,” and similar expressions and statements regarding our business strategy, plans and objectives of our management for future operations. These statements
36
reflect our current views with respect to future events, based on what we believe are reasonable assumptions. Certain factors could cause actual results to differ materially from results anticipated in the forward-looking statements. These factors include, but are not limited to:
·abrupt or severe production declines or production interruptions in outer continental shelf production located offshore California and transported on our pipeline system;
·the success of our risk management activities;
·the availability of, and our ability to consummate, acquisition or combination opportunities;
·our access to capital to fund additional acquisitions and our ability to obtain debt or equity financing on satisfactory terms;
·successful integration and future performance of acquired assets or businesses;
·environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;
·maintenance of our credit rating and ability to receive open credit from our suppliers;
·declines in volumes shipped on the Basin Pipeline, Capline Pipeline and our other pipelines by third party shippers;
·the availability of adequate third party production volumes for transportation and marketing in the areas in which we operate;
·successful third party drilling efforts in areas in which we operate pipelines or gather crude oil;
·demand for various grades of crude oil and resulting changes in pricing conditions or transmission throughput requirements;
·fluctuations in refinery capacity in areas supplied by our transmission lines;
·the effects of competition;
·continued creditworthiness of, and performance by, counter parties;
·the impact of crude oil price fluctuations;
·the impact of current and future laws, rulings and governmental regulations;
·shortages or cost increases of power supplies, materials or labor;
·weather interference with business operations or project construction;
·the currency exchange rate of the Canadian dollar;
·fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our Long-Term Incentive Plan; and
·general economic, market or business conditions.
Other factors, such as the "Risk“Risk Factors Related to Our Business"Business” in Item 7 of our most recent annual report on Form 10-K, or factors that are unknown or unpredictable, could also have a material adverse effect on future results. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.
37
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
The following should be read in conjunction with Quantitative and Qualitative Disclosures About Market Risks included in Item 7A in our 2004 Annual Report on Form 10-K. There have not been any material changes in that information other than those discussed below.
Commodity Price Risk
All of our open commodity price risk derivatives at March 31,June 30, 2005 were categorized as non-trading. The fair value of these instruments and the change in fair value that would be expected from a 10 percent price decrease are shown in the table below:
| Fair Value | Effect of 10% Price Decrease |
|
|
| Effect of 10% |
| |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (in millions) |
| Fair Value |
| Price Change |
| ||||||||||||
Crude oil: | ||||||||||||||||||
|
| (in millions) |
| |||||||||||||||
Crude oil: |
|
|
|
|
|
|
|
|
| |||||||||
Futures contracts | $ | (30.6 | ) | $ | (37.9 | ) |
|
| $ | (60.2 | ) |
|
| $ | (14.7 | ) |
| |
Swaps and options contracts | $ | (11.5 | ) | $ | 3.8 |
|
| $ | (12.2 | ) |
|
| $ | (7.8 | ) |
| ||
LPG: | ||||||||||||||||||
LPG: |
|
|
|
|
|
|
|
|
| |||||||||
Swaps and options contracts | $ | 0.8 | $ | (0.8 | ) |
|
| $ | (0.9 | ) |
|
| $ | 0.7 |
|
|
Interest Rate Risk
We utilize both fixed and variable rate debt, and are exposed to market risk due to the floating interest rates on our credit facilities. Therefore, from time to time we utilize interest rate swaps and collars to hedge interest obligations on specific debt issuances, including anticipated debt issuances. The table below presents principal payments and the related weighted average interest rates by expected maturity dates for variable rate debt outstanding at March 31,June 30, 2005. The 7.75%All of our outstanding senior notes issued during 2002, the 5.625% senior notes issued during 2003, the 4.75% senior notes issued during 2004, and the 5.88% senior notes issued during 2004 are fixed rate notes and their interest rates are not subject to market risk. Our variable rate debt bears interest at LIBOR, prime or the bankers acceptance rate plus the applicable margin. The average interest rates presented below are based upon rates in effect at March 31,June 30, 2005. The carrying values of the variable rate instruments in our credit facilities approximate fair value primarily because interest rates fluctuate with prevailing market rates.
| Expected Year of Maturity | |||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2005 | 2006 | 2007 | 2008 | 2009 | Thereafter | Total | |||||||||||||||||
| (in millions) | |||||||||||||||||||||||
Liabilities: | ||||||||||||||||||||||||
Short-term debt—variable rate | $ | 555.0 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 555.0 | ||||||||||
Average interest rate | 3.5 | % | — | — | — | — | — | 3.5 | % | |||||||||||||||
Long-term debt—variable rate | $ | — | $ | — | $ | — | $ | — | $ | 125.0 | $ | — | $ | 125.0 | ||||||||||
Average interest rate | — | — | — | — | 3.7 | % | — | 3.7 | % |
|
| Expected Year of Maturity |
| |||||||||||||||||||||||||||
|
| 2005 |
| 2006 |
| 2007 |
| 2008 |
| 2009 |
| Thereafter |
| Total |
| |||||||||||||||
|
| (in millions) |
| |||||||||||||||||||||||||||
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Short-term debt—variable rate |
| $ | 815.7 |
|
| $ | — |
|
|
| $ | — |
|
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $815.7 |
| |
Average interest rate |
| 4.0 | % |
| — |
|
|
| — |
|
|
| — |
|
| — |
|
| — |
|
| 4.0 | % | |||||||
Long-term debt—variable rate |
| $ | — |
|
| $ | — |
|
|
| $ | — |
|
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
Average interest rate |
| — |
|
| — |
|
|
| — |
|
|
| — |
|
| — |
|
| — |
|
| — |
| |||||||
Item 4. CONTROLS AND PROCEDURES
We maintain "disclosure“disclosure controls and procedures,"” which we refer to as our "DCP."“DCP.” The purpose of our DCP is to provide reasonable assurance that (i) information is recorded, processed, summarized and reported in time to allow for timely disclosure of such information in accordance with the securities laws and SEC regulations and (ii) information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow for timely decisions regarding required disclosure.
Applicable SEC rules require an evaluation of the effectiveness of the design and operation of our DCP. Management, under the supervision and with the participation of our Chief Executive Officer and
38
Chief Financial Officer, has evaluated the effectiveness of the design and operation of our DCP as of March 31,June 30, 2005, and has found our DCP to be effective in providing reasonable assurance of the timely recording, processing, summarization and reporting of information, and in accumulation and communication of information to management to allow for timely decisions with regard to required disclosure.
In addition to the information concerning our DCP, we are required to disclose certain changes in our internal control over financial reporting ("(“internal control"control”) that occurred during the firstsecond quarter and that has materially affected, or is reasonably likely to materially affect, our internal control. There are none. However, in the process of documenting and testing our internal control in connection with compliance with Rule 13a-15(c) under the Exchange Act of 1934, as amended (required by Section 404 of the Sarbanes-Oxley Act of 2002) we have made changes, and will continue to make changes, to refine and improve our internal control.
The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to Exchange Act rules 13a-14(a) and 15d-14(a) are filed with this report as Exhibits 31.1 and 31.2. The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. §1350 are furnished with this report as Exhibits 32.1 and 32.2.
39
Export License Matter.In our gathering and marketing activities, we import and export crude oil from and to Canada. Exports of crude oil are subject to the "short supply"“short supply” controls of the Export Administration Regulations ("EAR"(“EAR”) and must be licensed by the Bureau of Industry and Security (the "BIS"“BIS”) of the U.S. Commerce Department. In 2002, we determined that we may have violated the terms of our licenses with respect to the quantity of crude oil exported and the end-users in Canada. Export of crude oil except as authorized by license is a violation of the EAR. In October 2002, we submitted to the BIS an initial notification of voluntary disclosure. The BIS subsequently informed us that we could continue to export while previous exports were under review. We applied for and received several new licenses allowing for export volumes and end users that more accurately reflect our anticipated business and customer needs. We also conducted reviews of new and existing contracts and implemented new procedures and practices in order to monitor compliance with applicable laws regarding the export of crude oil to Canada. As a result, we subsequently submitted additional information to the BIS in October 2003 and May 2004. In August 2004, we received a request from the BIS for additional information. We have responded to this and subsequent requests, and continue to cooperate fully with BIS officials. At this time, we have received neither a warning letter nor a charging letter, which could involve the imposition of penalties, and no indication of what penalties the BIS might assess. As a result, we cannot reasonably estimate the ultimate impact of this matter.
Alfons Sperber v. Plains Resources Inc., et. al. On December 18, 2003, a putative class action lawsuit was filed in the Delaware Chancery Court, New Castle County, entitled Alfons Sperber v. Plains Resources Inc., et al. This suit, brought on behalf of a putative class of Plains All American Pipeline, L.P. common unitholders, asserted breach of fiduciary duty and breach of contract claims against us, Plains AAP, L.P., and Plains All American GP LLC and its directors, as well as breach of fiduciary duty claims against Plains Resources Inc. and its directors. (Plains Resources, Inc. is a unitholder and an interest owner in our general partner. See "Security Ownership of Certain Beneficial Owners and Management and Related Unitholders' Matters.") The complaint sought to enjoin or rescind a proposed acquisition of all of the outstanding stock of Plains Resources Inc., as well as declaratory relief, an accounting, disgorgement and the imposition of a constructive trust, and an award of damages, fees, expenses and costs, among other things. This lawsuit has been settled in principle. The court has approved the settlement and the settlement became final in March 2005.
Pipeline Releases.In December 2004 and January 2005, we experienced two unrelated releases of crude oil that reached rivers located near the sites where the releases originated. In late December 2004, one of our pipelines in West Texas experienced a rupture that resulted in the release of approximately 4,500 barrels of crude oil, a portion of which reached a remote location of the Pecos River. In early January 2005, an overflow from a temporary storage tank located in East Texas resulted in the release of approximately 1,200 barrels of crude oil, a portion of which reached the Sabine River. In both cases, emergency response personnel under the supervision of a unified command structure consisting of representatives of Plains Pipeline,our personnel, the U.S. Environmental Protection Agency, the Texas Commission on Environmental Quality and the Texas Railroad Commission conducted clean-up operations at each site. Approximately 4,200 barrels and 980 barrels were recovered from the two respective sites. The unrecovered oil has been or will be removed or otherwise addressed by PAAus in the course of site remediation. Aggregate costs associated with the releases, including estimated remediation costs, are estimated to be approximately $3.0$3.5 million to $3.5$4.0 million. We continue to work with the appropriate state and federal environmental authorities in respondingwith respect to the releasessite restoration and no enforcement proceedings have been instituted by any governmental authority at this time.
We, in the ordinary course of business, are a claimant and/or a defendant in various legal proceedings. We do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Securities Not Registered Under the Securities Act. On February 25, 2005, we issued 575,000 common units to a subsidiary of Vulcan Energy Corporation. The sale price for the common units was $38.13 per unit resulting in net proceeds, including the general partner's proportionate capital contribution and expenses associated with the sale, of approximately $22.3 million. We intend to use the net proceeds from the private placement to fund a portion of our 2005 expansion capital program. Pending the incurrence of such expenditures, the net proceeds will be used to repay indebtedness under our revolving credit facilities.None.
Item 3. DEFAULTS UPON SENIOR SECURITIES
None
40
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
See Item 4. "Submission“Submission of Matters to a Vote of Security Holders"Holders” in our 2004 Annual Report on Form 10-K.
NonePending Reallocation of General Partner Interest
One of the owners of our general partner has provided notice that it intends to sell its 19% interest in the general partner. The remaining owners have elected to exercise their right of first refusal, such that the 19% interest will be allocated prorata to all remaining owners. As a result, subject to consummation of the transaction, the interest of Vulcan Energy Corporation will increase from 44% to approximately 54%. We anticipate that, at closing, Vulcan will enter into a voting agreement that will restrict its ability to unilaterally elect or remove our independent directors, and our CEO and COO will agree to waive certain change-of-control payment rights that would otherwise be triggered by the increase in Vulcan’s ownership interest.
4. | 1 | Fifth Supplemental Indenture, dated as of May 27, 2005, to Indenture, dated as of September 25, 2002, among Plains All American Pipeline, L.P. and PAA Finance Corp. and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed May 31, 2005) |
10. | 1 | First Amendment to Restated Credit Agreement dated as of April 20, 2005, by and among Plains Marketing, L.P., Bank of America, N.A., as Administrative Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.1 to Form 8-K filed April 21, 2005) |
10. | 2 | Second Amendment to Restated Credit Agreement dated as of May 11, 2005, by and among Plains Marketing, L.P., Bank of America, N.A., as Administrative Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.1 to Form 8-K filed May 12, 2005) |
10. | 3 | Second Amendment, dated as of May 6, 2005, to the Credit Agreement dated November 2, 2004 among Plains All American Pipeline, L.P. (as US Borrower), PMC (Nova Scotia) Company and Plains Marketing Canada, L.P. (as Canadian Borrowers), and Bank of America, N.A. (incorporated by reference to Exhibit 10.2 to Form 10-Q for the period ended March 31, 2005) |
10. | 4 | Registration Rights Agreement, dated May 27, 2005, among Plains All American Pipeline, L.P., PAA Finance Corp. Plains Marketing, L.P., Plains Pipeline, L.P., Plains Marketing GP Inc., Plains Marketing Canada LLC, PMC (Nova Scotia) Company, Plains Marketing Canada, L.P., Basin Holdings GP LLC, Basin Pipeline Holdings, L.P., Rancho Holdings GP LLC, Rancho Pipeline Holdings, L.P., J.P. Morgan Securities Inc. and Wachovia Capital Markets, LLC, Citigroup Global Markets Inc., UBS Securities LLC, Banc of America Securities LLC, Scotia Capital (USA) Inc., SunTrust Capital Markets, Inc,. Fortis Securities LLC, Daiwa Securities America Inc., SG Americas Securities, LLC and RBC Capital Markets Corporation (incorporated by reference to Exhibit 4.1 to Form 8-K filed May 31, 2005) |
†31. | 1 | Certification of Principal Executive Officer pursuant to Exchange Act rules 13a-14(a) and 15d-14(a) |
†31. | 2 | Certification of Principal Financial Officer pursuant to Exchange Act rules 13a-14(a) and 15d-14(a) |
*32. | 1 | Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350. |
*32. | 2 | Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350 |
†
*SIGNATURES
Furnished herewith.
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Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned and thereunto duly authorized.
PLAINS ALL AMERICAN PIPELINE, L.P. | ||||
By: | PLAINS AAP, L.P., its general partner | |||
By: | PLAINS ALL AMERICAN GP LLC, | |||
Date: | By: | /s/ GREG L. ARMSTRONG | ||
Greg L. Armstrong, Chairman of the Board, Chief Executive Officer and Director of Plains | ||||
Date: | By: | /s/ PHIL KRAMER | ||
Phil Kramer, Executive Vice President and Chief Financial Officer of Plains All American |
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