================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2001 OR [_] 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 INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.) 333 CLAY STREET, SUITE 2900 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 No --- --- At November 14, 2001, there were outstanding 31,915,939 Common Units, 1,307,190 Class B Common Units and 10,029,619 Subordinated Units. ================================================================================
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES TABLE OF CONTENTS PAGE ---- PART I. FINANCIAL INFORMATION CONSOLIDATED FINANCIAL STATEMENTS: Consolidated Balance Sheets: September 30, 2001 and December 31, 2000.......................... 3 Consolidated Statements of Operations: For the three and nine months ended September 30, 2001 and 2000... 4 Consolidated Statements of Cash Flows: For the nine months ended September 30, 2001 and 2000............. 5 Consolidated Statement of Partners' Capital: For the nine months ended September 30, 2001...................... 6 Notes to Consolidated Financial Statements.......................... 7 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS............................... 16 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS...................................................... 24 PART II. OTHER INFORMATION.......................................... 26 2
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT UNIT DATA) <TABLE> <CAPTION> September 30, December 31, 2001 2000 --------------- --------------- (unaudited) <S> <C> <C> ASSETS CURRENT ASSETS Cash and cash equivalents $ 3,864 $ 3,426 Accounts receivable and other current assets 543,464 347,698 Inventory 85,980 46,780 --------------- --------------- Total current assets 633,308 397,904 --------------- --------------- PROPERTY AND EQUIPMENT 632,164 467,619 Less allowance for depreciation and amortization (42,256) (26,974) --------------- --------------- 589,908 440,645 --------------- --------------- OTHER ASSETS Pipeline linefill 44,674 34,312 Other, net 31,203 12,940 --------------- --------------- $ 1,299,093 $ 885,801 =============== =============== LIABILITIES AND PARTNERS' CAPITAL CURRENT LIABILITIES Accounts payable and other current liabilities $ 493,613 $ 328,542 Due to affiliates 17,272 20,951 Short-term debt and current portion of long-term debt 60,400 1,300 --------------- --------------- Total current liabilities 571,285 350,793 LONG-TERM LIABILITIES Bank debt 434,540 320,000 Other long-term liabilities and deferred credits 1,017 1,009 --------------- --------------- Total liabilities 1,006,842 671,802 --------------- --------------- COMMITMENTS AND CONTINGENCIES (NOTE 10) PARTNERS' CAPITAL Common unitholders (27,015,939 and 23,049,239 units outstanding at September 30, 2001 and December 31, 2000 respectively) 296,294 217,073 Class B common unitholders (1,307,190 units outstanding) 20,002 21,042 Subordinated unitholders (10,029,619 units outstanding) (35,296) (27,316) General partner 11,251 3,200 --------------- --------------- Total partners' capital 292,251 213,999 --------------- --------------- $ 1,299,093 $ 885,801 =============== =============== </TABLE> See notes to consolidated financial statements. 3
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS, EXCEPT PER UNIT DATA) (UNAUDITED) <TABLE> <CAPTION> THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, --------------------------- --------------------------- 2001 2000 2001 2000 ----------- ----------- ----------- ----------- <S> <C> <C> <C> <C> REVENUES $ 2,191,310 $ 1,555,863 $ 5,298,051 $ 5,040,204 COST OF SALES AND OPERATIONS 2,151,666 1,523,303 5,189,288 4,938,318 UNAUTHORIZED TRADING LOSSES AND RELATED EXPENSES - 6,600 - 6,600 ----------- ----------- ----------- ----------- Gross Margin 39,644 25,960 108,763 95,286 EXPENSES General and administrative 10,297 9,911 34,327 26,486 Depreciation and amortization 6,402 5,349 17,575 20,148 ----------- ----------- ----------- ----------- Total expenses 16,699 15,260 51,902 46,634 ----------- ----------- ----------- ----------- OPERATING INCOME 22,945 10,700 56,861 48,652 Interest expense (7,775) (6,478) (22,482) (18,518) Related party interest expense - - - (3,268) Gain on sale of assets - - - 48,188 Interest and other income (expense) (9) 294 356 10,825 ----------- ----------- ----------- ----------- Income before extraordinary item and cumulative effect of accounting change 15,161 4,516 34,735 85,879 Extraordinary item - - - (15,147) Cumulative effect of accounting change (Note 3) - - 508 - NET INCOME $ 15,161 $ 4,516 $ 35,243 $ 70,732 =========== =========== =========== =========== NET INCOME - LIMITED PARTNERS $ 14,536 $ 4,359 $ 34,019 $ 69,185 =========== =========== =========== =========== NET INCOME - GENERAL PARTNER $ 625 $ 157 $ 1,224 $ 1,547 =========== =========== =========== =========== BASIC AND DILUTED NET INCOME PER LIMITED PARTNER UNIT Income before extraordinary item and cumulative effect of accounting change $ 0.38 $ 0.13 $ 0.93 $ 2.45 Extraordinary item - - - (0.44) Cumulative effect of accounting change - - 0.01 - ----------- ----------- ----------- ----------- Net income $ 0.38 $ 0.13 $ 0.94 $ 2.01 =========== =========== =========== =========== WEIGHTED AVERAGE UNITS OUTSTANDING 38,353 34,386 36,156 34,386 =========== =========== =========== =========== </TABLE> See notes to consolidated financial statements. 4
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS) (UNAUDITED) <TABLE> <CAPTION> Nine Months Ended September 30, -------------------------- 2001 2000 ----------- ----------- CASH FLOWS FROM OPERATING ACTIVITIES <S> <C> <C> Net income $ 35,243 $ 70,732 Items not affecting cash flows from operating activities: Depreciation and amortization 17,575 20,148 Gain on the sale of assets - (48,188) Cumulative effect of accounting change (508) - Change in derivative fair value (712) - Other noncash items 5,583 6,843 Change in assets and liabilities, net of assets acquired and liabilities assumed: Accounts receivable and other current assets (189,394) 95,284 Inventory (8,037) 12,539 Pipeline linefill - (13,397) Due to affiliates (3,679) - Accounts payable and other current liabilities 149,408 (143,451) Other long-term liabilities and deferred credits - (8,000) ----------- ----------- Net cash provided by (used in) operating activities 5,479 (7,490) ----------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES Cash paid in connection with acquisitions (Note 5) (209,264) - Additions to property and equipment and other assets (13,804) (7,487) Proceeds from sales of assets 1,808 223,859 ----------- ----------- Net cash provided by (used in) investing activities (221,260) 216,372 ----------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES Advances (to) from affiliates - (18,790) Proceeds from long-term debt 1,655,475 794,800 Proceeds from short-term debt 258,655 47,750 Payment of subordinated debt - general partner - (114,000) Principal payments of long-term debt (1,537,935) (812,900) Principal payments of short-term debt (202,555) (106,469) Costs incurred in connection with financing arrangements (10,649) (6,500) Proceeds from issuance of units 106,209 - Distributions to unitholders (52,981) (43,269) ----------- ----------- Net cash provided by (used in) financing activities 216,219 (259,378) ----------- ----------- Net increase (decrease) in cash and cash equivalents 438 (50,496) Cash and cash equivalents, beginning of period 3,426 53,768 ----------- ----------- Cash and cash equivalents, end of period $ 3,864 $ 3,272 =========== =========== </TABLE> See notes to consolidated financial statements. 5
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL (IN THOUSANDS) (UNAUDITED) <TABLE> <CAPTION> TOTAL CLASS B GENERAL PARTNERS' COMMON UNITS COMMON UNITS SUBORDINATED UNITS PARTNER CAPITAL --------------------- -------------------- --------------------- --------- ---------- UNITS AMOUNT UNITS AMOUNT UNITS AMOUNT AMOUNT AMOUNT --------- -------- --------- -------- --------- -------- --------- ---------- <S> <C> <C> <C> <C> <C> <C> <C> <C> Balance at December 31, 2000 23,049 $217,073 1,307 $ 21,042 10,030 $(27,316) $ 3,200 $ 213,999 Issuance of units 3,967 98,606 - - - - 2,879 101,485 Noncash compensation expense - - - - - - 5,741 5,741 Distributions - (35,116) - (1,879) - (14,418) (1,568) (52,981) Other comprehensive income - (7,668) - (385) - (2,958) (225) (11,236) Net income - 23,399 - 1,224 - 9,396 1,224 35,243 --------- -------- --------- -------- --------- -------- --------- --------- Balance at September 30, 2001 27,016 $296,294 1,307 $ 20,002 10,030 $(35,296) $ 11,251 $ 292,251 ========= ======== ========= ======== ========= ======== ========= ========= </TABLE> See notes to consolidated financial statements. 6
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) NOTE 1 -- ORGANIZATION AND ACCOUNTING POLICIES We are a Delaware limited partnership that was formed in September of 1998 to acquire and operate the midstream crude oil business and assets of Plains Resources Inc. and its wholly owned subsidiaries. On November 23, 1998, we completed our initial public offering and the transactions whereby we became the successor to the business of the midstream subsidiaries of Plains Resources. Our operations are conducted through Plains Marketing, L.P., All American Pipeline, L.P. and Plains Marketing Canada, L.P. The terms "Plains All American" and the "Partnership" herein refer to Plains All American Pipeline, L.P. and its affiliated operating partnerships. We are engaged in interstate and intrastate transportation, marketing, and terminalling of crude oil. Our operations are conducted primarily in Texas, California, Oklahoma, Louisiana, the Gulf of Mexico and the Canadian Provinces of Alberta and Saskatchewan. The accompanying financial statements and related notes present our consolidated financial position as of September 30, 2001 and December 31, 2000; the results of our operations for the three and nine months ended September 30, 2001 and 2000; cash flows for the nine months ended September 30, 2001 and 2000; and changes in partners' capital for the nine months ended September 30, 2001. The financial statements have been prepared in accordance with the instructions to interim reporting as prescribed by the Securities and Exchange Commission ("SEC"). 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 have been made to prior period amounts to conform with current period presentation. The results of operations for the three and nine months ended September 30, 2001 should not be taken as indicative of the results to be expected for the full year. The interim financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our 2000 Annual Report on Form 10-K. NOTE 2 -- EQUITY OFFERINGS On October 31, 2001, we completed a public offering of 4,500,000 common units. Net cash proceeds from the offering, including our general partner's proportionate contribution, were approximately $116 million. On November 13, 2001, the underwriters in the offering exercised their overallotment option and purchased an additional 400,000 units for net cash proceeds of approximately $10.8 million. This offering is in addition to the 3,966,700 units issued in May and June, 2001 which resulted in net proceeds of $100.7 million, including our general partner's proportionate contribution. Proceeds from both offerings were used to repay borrowings under our revolving credit facility, a portion of which was used to finance our Canadian acquisitions (see Note 5). NOTE 3 -- DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES On January 1, 2001, we adopted Statement of Financial Accounting Standards ("SFAS") No. 133 "Accounting for Derivative Instruments and Hedging Activities" as amended by SFAS 137 and SFAS 138. Under SFAS 133, all derivative instruments are recorded on the balance sheet at fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. To qualify for hedge accounting, the derivative must qualify either as a fair value hedge, cash flow hedge or foreign currency hedge. With respect to fair value hedges, gains or losses for both the hedge and the hedged item are taken directly to earnings in the current period. Thus, earnings are impacted by the net change between the hedge and the underlying hedged transaction. With respect to cash flow hedges, gains or losses are deferred in accumulated Other Comprehensive Income ("OCI"), a component of Partners' Capital, to the extent the hedge is effective (discussed further below). Foreign currency hedges may be treated as either fair value hedges or cash flow hedges, depending on the specific characteristics of the hedge. As of September 30, 2001 our hedges consisted only of cash flow hedges or foreign currency hedges treated as cash flow hedges, and the remaining discussion relates exclusively to these types of hedges. The relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. Hedge accounting is discontinued prospectively when a hedge instrument becomes ineffective. Gains and losses deferred in OCI related to cash flow hedges that become ineffective remain unchanged until the related product is delivered. If it is determined that it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the hedging instrument are recognized in earnings immediately. 7
Gains and losses on hedging instruments related to OCI and adjustments to carrying amounts on hedged volumes are included in revenues in the period that the related volumes are delivered. Gains and losses of hedging instruments that represent hedge ineffectiveness are included in earnings in the period in which they occur. We utilize various derivative instruments, for purposes other than trading, to hedge our exposure to price fluctuations on crude oil in storage and expected purchases, sales and transportation of crude oil. The derivative instruments consist primarily of futures and option contracts traded on the New York Mercantile Exchange. We also utilize interest rate collars and interest rate swaps to manage the interest rate exposure on our long-term debt and foreign currency hedges to manage exchange rate exposure. On January 1, 2001, in accordance with the transition provisions of SFAS 133, we recorded a loss of $8.3 million in OCI, representing the cumulative effect of an accounting change to recognize, at fair value, all cash flow derivatives. We also recorded a noncash gain of $0.5 million in earnings as a cumulative effect adjustment. At September 30, 2001, an $11.1 million unrealized loss was recorded to OCI together with related assets and liabilities of $7.3 million and $17.7 million, respectively. Earnings included a noncash gain of $0.8 million related to the ineffective portion of our cash flow hedges, as well as certain derivative contracts that did not qualify as hedges relating to our Canadian businesses due to a low correlation between the futures contract and hedged item. Our hedge- related assets and liabilities are included in other current assets and other current liabilities in the balance sheet. As of September 30, 2001, the total amount of deferred net losses on derivative instruments recorded in OCI are expected to be reclassified to earnings during the next twelve-month period. The following table sets forth our open crude oil hedge positions at September 30, 2001. These are futures hedges and thus have offsetting physical exposures to the extent they are effective. 2001 2002 --------- --------------------------------- 4th Qtr 1st Qtr 2nd Qtr 3rd Qtr --------- --------- --------- --------- Volume (bbls) Short positions 1,302,000 - - - Long positions - 2,760,000 213,000 - Average price ($/bbl) $26.94 $27.37 $28.46 - At September 30, 2001, we had arrangements to protect interest rate fluctuations on a portion of our outstanding debt for an aggregate notional amount of $275.0 million. These instruments are based on LIBOR rates. Approximately $125 million notional amount is comprised of an interest rate collar that provides for a floor of 6.1% and a ceiling of 8.0% with an expiration date of August 2002. The remaining $150 million notional amount consists of interest rate swaps with an average LIBOR rate of approximately 3.8%. These swaps expire with respect to $100 million in September, 2003, and the remainder in March, 2004. During the third quarter of 2001, gains of $4.5 million were relieved from OCI and the fair value of open positions decreased $0.7 million. Additionally, certain derivative positions were terminated prior to maturity. As such, a $11.1 million loss related to all positions (open and closed hedges) was recorded in OCI at September 30, 2001. We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. Hedge effectiveness is measured on a quarterly basis. This process includes specific identification of the hedging instrument and the hedge transaction, the nature of the risk being hedged and how the hedging instrument'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 hedged items. No amounts were excluded from the computation of hedge effectiveness. NOTE 4 - COMPREHENSIVE INCOME Comprehensive income includes net income and certain items recorded directly to Partners' Capital and classified as OCI. Following the adoption of SFAS 133, we recorded a charge to OCI of $8.3 million related to the change in fair value of 8
certain derivative financial instruments that qualified for cash flow hedge accounting. The following table reflects comprehensive income for the nine months ended September 30, 2001 (in thousands): Total Comprehensive Income at January 1, 2001 $ - Cumulative effect of change in accounting principle (8,337) Reclassification adjustment for settled contracts 2,315 Changes in fair value of open hedging positions (5,056) Currency translation adjustment (158) ---------- Other Comprehensive Income at September 30, 2001 (11,236) Net income for the nine months ended September 30, 2001 35,243 ---------- Total Comprehensive Income at September 30, 2001 $ 24,007 ========== NOTE 5 -- ACQUISITIONS Murphy Oil Company Ltd. Midstream Operations In May 2001, we closed the acquisition of substantially all of the Canadian crude oil pipeline, gathering, storage and terminalling assets of Murphy Oil Company Ltd. for approximately $161 million in cash ("the Murphy Acquisition"), including financing and transaction costs. Financing for the acquisition was provided through borrowings under our bank credit facilities. The purchase included $6.5 million for excess inventory in the pipeline systems. The principal assets acquired include approximately 450 miles of crude oil and condensate transmission mainlines (including dual lines on which condensate is shipped for blending purposes and blended crude is shipped in the opposite direction) and associated gathering and lateral lines, approximately 1.1 million barrels of crude oil storage and terminalling capacity located primarily in Kerrobert, Saskatchewan, approximately 254,000 barrels of pipeline linefill and tank inventories, an inactive 108-mile mainline system and 121 trailers used primarily for crude oil transportation. We have reactivated the 108-mile mainline system and began shipping volumes in May of 2001. Murphy agreed to continue to transport production from fields previously delivering crude oil to these pipeline systems, under a long-term contract. The current volume under the contract is approximately 11,000 barrels per day. The pipeline systems currently transport approximately 225,000 barrels per day of light, medium and heavy crudes, as well as condensate. The Murphy Acquisition has been accounted for using the purchase method of accounting and the purchase price was allocated in accordance with Accounting Principles Board Opinion No. 16, Business Combinations, ("APB 16"). The purchase price allocation, which is preliminary and will likely have further refinements made to it, is as follows (in thousands): Crude oil pipeline, gathering and terminal assets $150,182 Pipeline linefill 7,602 Net working capital items 1,953 Other property and equipment 487 Other assets, including debt issue costs 360 ---------- Total $160,584 ========== CANPET Energy Group Inc. In July 2001, we acquired the assets of CANPET Energy Group Inc. ("CANPET"), a Calgary-based Canadian crude oil and liquefied petroleum gas marketing company, for approximately $42.0 million plus excess inventory at the closing date of approximately $25 million. Approximately $24.0 million of the purchase price plus the excess inventory was paid in cash at closing, and the remainder, which is subject to certain performance standards, will be paid in common units in April 2004 if such standards are met. CANPET activities include gathering approximately 75,000 barrels per day of crude oil and 9
marketing an average of approximately 26,000 barrels per day of natural gas liquids. Tangible assets acquired include a crude oil handling facility, a 130,000-barrel tank facility and working capital of approximately $8.6 million. Financing for the acquisition was provided through borrowings under our bank credit facility. The Canpet Acquisition has been accounted for using the purchase method of accounting and the purchase price was allocated in accordance with SFAS 141 (see Note 9). The purchase price allocation, which is preliminary and will likely have further refinements made to it, is as follows (in thousands): Inventory $28,895 Other assets, including debt issue costs 11,078 Pipeline linefill 4,144 Crude oil gathering and terminal assets 4,061 Other property and equipment 502 --------- Total $48,680 ========= Pro Forma Results for the Murphy and Canpet Acquisitions The following unaudited pro forma data is presented to show pro forma revenues, net income and basic and diluted net income per limited partner unit for the Partnership as if the Murphy and Canpet acquisitions and the issuance of 3,966,700 units in May and June, 2001 had occurred on January 1, 2000 (in thousands): NINE MONTHS ENDED SEPTEMBER 30, ------------------------- 2001 2000 ----------- ----------- Revenues $ 6,071,353 $ 6,454,750 =========== =========== Income before extraordinary item and cumulative effect of accounting change $ 47,848 $ 94,631 =========== =========== Net income $ 48,356 $ 79,484 =========== =========== Basic and diluted income before extraordinary item and cumulative effect of accounting change per limited partner unit $ 1.28 $ 2.69 =========== =========== Basic and diluted net income per limited partner unit $ 1.29 $ 2.26 =========== =========== NOTE 6 -- CREDIT AGREEMENTS In September 2001, we amended and expanded our existing credit facilities to include a six-year, $200 million term B loan. In connection with the amendment, we reduced the revolving portion of the facilities by $50 million. Our credit facilities currently consist of: . a $780.0 million senior secured revolving credit and term loan facility, which is secured by substantially all of our assets. The facility consists of a $450.0 million domestic revolving facility (reflecting the $50 million reduction in such facility in connection with the September amendment), with a $10.0 million letter of credit sublimit, a $30.0 million Canadian revolving facility (with a $5.0 million letter of credit sublimit), a $100.0 million term loan and a $200.0 million term B loan. The facility matures, as to the aggregate $480.0 million domestic and Canadian revolver portions, in April, 2005, as to the $100.0 million term portion, in May, 2006, and, as to the $200.0 million term B loan portion, September, 2007. On the revolver portions, no principal is scheduled for payment prior to maturity; however, if we issue privately-placed or public debt, the net proceeds of such debt must be used to repay then- outstanding loans under the 10
domestic revolver, and with the repayment and depending on the face amount of such indebtedness, the domestic revolver commitment will be reduced by a dollar amount equal to 40% to 50% of the face amount of such indebtedness, less the $50 million reduction in the revolver commitment in September 2001. The $100 million term loan portion of this facility has four scheduled annual payments of principal, commencing May 4, 2002, in the respective amounts of 1%, 7%, 8% and 8% of the original term principal amount, with the remaining principal balance scheduled for payment on the stated maturity date of May 5, 2006. If any part of the term portion is prepaid prior to its first anniversary, a 1% premium will be due on that portion. The $200 million term B loan has 1% payable yearly commencing on September 21, 2002, with the remaining principal balance scheduled for payment on the stated maturity date of September 26, 2007. The term B loan may be prepaid without penalty. The revolving credit and term loan facility bears interest at our option at either the base rate, as defined, plus an applicable margin, or LIBOR plus an applicable margin, and further, the Canadian revolver may effectively bear interest based upon bankers' acceptance rates. We incur a commitment fee on the unused portion of the revolver portion of this credit facility. . a $200.0 million senior secured letter of credit and borrowing facility, the purpose of which is to provide standby letters of credit to support the purchase and exchange of crude oil and other specified petroleum products for resale and borrowings to finance crude oil inventory and other specified petroleum products that have been hedged against future price risk. The letter of credit facility is secured by substantially all of our assets and has a sublimit for cash borrowings of $100.0 million to purchase crude oil and other petroleum products that have been hedged against future price risk and to fund margin requirements under NYMEX contracts used to facilitate our hedging activities. The letter of credit facility expires in April, 2004. Aggregate availability under the letter of credit facility for direct borrowings and letters of credit is limited to a borrowing base that is determined monthly based on certain of our current assets and current liabilities, primarily inventory and accounts receivable and accounts payable related to the purchase and sale of crude oil and other specified petroleum products. Our credit facilities prohibit distributions on, or purchases or redemptions of, units if any default or event of default is continuing. In addition, the agreements contain various covenants limiting our ability to, among other things: . incur indebtedness; . grant liens; . sell assets; . make investments; . engage in transactions with affiliates; . enter into prohibited contracts; and . enter into a merger or consolidation. Our credit facilities treat a change of control as an event of default and also require us to maintain: . a current ratio (as defined) of 1.0 to 1.0; . a debt coverage ratio which is not greater than 4.50 to 1 through June 29, 2002, 4.25 to 1.0 from June 30, 2002 through December 30, 2002 and 4.0 to 1.0 thereafter; . an interest coverage ratio which is not less than 2.75 to 1.0; and . a debt to capital ratio of not greater than 0.70 to 1.0 prior to December 31, 2002 and 0.65 to 1.0 thereafter. A default under our credit facilities would permit the lenders to accelerate the maturity of the outstanding debt and to foreclose on the assets securing the credit facilities. As long as we are in compliance with our commercial credit agreements, they do not restrict our ability to make distributions of "available cash" as defined in our partnership agreement. We are currently in compliance with the covenants contained in our credit agreements. NOTE 7 -- DISTRIBUTIONS On February 14, 2001, we paid a cash distribution of $0.4625 per unit on our outstanding common units, Class B units and subordinated units. The distribution was paid to unitholders of record on February 2, 2001 for the period October 1, 2000 through December 31, 2000. The total distribution paid was approximately $16.3 million, with approximately $7.5 million paid to our public unitholders and the remainder paid to our prior general partner for its limited partner, general partner and incentive distribution interests. The distribution was in excess of the minimum quarterly distribution specified in the Partnership Agreement. 11
On May 15, 2001, we paid a cash distribution of $0.475 per unit on our outstanding common units, Class B units and subordinated units. The distribution was paid to unitholders of record on May 3, 2001 for the period January 1, 2001 through March 31, 2001. The total distribution paid was approximately $16.8 million, with approximately $7.7 million paid to our public unitholders and the remainder to our prior general partner for its limited partner, general partner and incentive distribution interests. On August 14, 2001, we paid a cash distribution of $0.50 per unit on our outstanding common units, Class B units and subordinated units. The distribution was paid to unitholders of record on August 3, 2001, for the period April 1, 2001 through June 30, 2001. The total distribution paid was approximately $19.9 million, with approximately $13.5 million paid to our common unitholders, $0.7 million to our Class B common unitholders, $5.0 million to our subordinated unitholders (including approximately $0.2 million to our general partner), and the remainder to our general partner for its general partner and incentive distribution interests. On October 18, 2001, we declared a cash distribution of $0.5125 per unit on our outstanding common units, Class B units and subordinated units. The distribution is payable on November 14, 2001 to holders of record on November 2, 2001. The total distribution to be paid is approximately $22.9 million, with approximately $16.2 million to be paid to our common unitholders, $0.7 million to our Class B common unitholders, $5.1 million to our subordinated unitholders (including approximately $0.2 million to our general partner), and the remainder to be paid to our general partner for its general partner and incentive distribution interests. NOTE 8 -- OPERATING SEGMENTS Our operations consist of two operating segments: (1) Pipeline Operations - engages in interstate and intrastate crude oil pipeline transportation and related merchant activities; (2) Gathering, Marketing, Terminalling and Storage Operations - engages in purchases and resales of crude oil at various points along the distribution chain and the leasing of terminalling and storage facilities. <TABLE> <CAPTION> GATHERING, MARKETING, TERMINALLING, (IN THOUSANDS) (UNAUDITED) PIPELINE & STORAGE TOTAL - ----------------------------------------------------------------------------------------------- THREE MONTHS ENDED SEPTEMBER 30, 2001 <S> <C> <C> <C> Revenues: External Customers $ 88,829 $ 2,102,481 $2,191,310 Intersegment (a) 4,491 873 5,364 Other revenue (expense) - (9) (9) ----------- -------------- ------------- Total revenues of reportable segments $ 93,320 $ 2,103,345 $2,196,665 =========== ============== ============= Segment gross margin (b) $ 16,089 $ 23,555 $ 39,644 Segment gross profit (c) 13,971 15,376 29,347 Income allocated to reportable segments (d) 5,460 9,701 15,161 Noncash compensation expense n/a n/a - ----------- -------------- ------------- Income before extraordinary item and cumulative effect of accounting change n/a n/a $ 15,161 =========== ============== ============= Total assets $450,047 $ 849,046 $1,299,093 - ----------------------------------------------------------------------------------------------- THREE MONTHS ENDED SEPTEMBER 30, 2000 Revenues: External Customers $ 93,226 $ 1,462,637 $1,555,863 Intersegment (a) 4,752 - 4,752 Other revenue (expense) (6) 300 294 ----------- -------------- ------------- Total revenues of reportable segments $ 97,972 $ 1,462,937 $1,560,909 =========== ============== ============= Segment gross margin (b) $ 11,886 $ 14,074 $ 25,960 Segment gross profit (c) 11,865 6,322 18,187 Income (loss) allocated to reportable segments (d) 10,396 (3,742) 6,654 Noncash compensation expense n/a n/a 2,138 ----------- -------------- ------------- Income before extraordinary item and cumulative effect of accounting change n/a n/a $ 4,516 =========== ============== ============= Total assets $319,211 $ 567,630 $ 886,841 - ------------------------------------------------------------------------------------------------ Table continued on following page </TABLE> 12
<TABLE> <CAPTION> GATHERING, MARKETING, TERMINALLING, (IN THOUSANDS) (UNAUDITED) PIPELINE & STORAGE TOTAL - ----------------------------------------------------------------------------------------------- NINE MONTHS ENDED SEPTEMBER 30, 2001 <S> <C> <C> <C> Revenues: External Customers $268,682 $ 5,029,369 $5,298,051 Intersegment (a) 12,966 2,118 15,084 Other revenue - 356 356 ----------- -------------- ------------- Total revenues of reportable segments $281,648 $ 5,031,843 $5,313,491 =========== ============== ============= Segment gross margin (b) $ 48,247 $ 60,516 $ 108,763 Segment gross profit (c) 44,639 35,538 80,177 Income allocated to reportable segments (d) 26,439 14,037 40,476 Noncash compensation expense n/a n/a 5,741 ----------- -------------- ------------- Income before extraordinary item and cumulative effect of accounting change n/a n/a $ 34,735 =========== ============== ============= Total assets $450,047 $ 849,046 $1,299,093 - ----------------------------------------------------------------------------------------------- NINE MONTHS ENDED SEPTEMBER 30, 2000 Revenues: External Customers $379,806 $ 4,660,398 $5,040,204 Intersegment (a) 65,250 - 65,250 Other revenue 9,673 1,152 10,825 ----------- -------------- ------------- Total revenues of reportable segments $454,729 $ 4,661,550 $5,116,279 =========== ============== ============= Gain on sale of assets $ 48,188 $ - $ 48,188 Segment gross margin (b) 37,802 57,484 95,286 Segment gross profit (c) 36,158 34,911 71,069 Income allocated to reportable segments (d) 83,503 4,645 88,148 Noncash compensation expense n/a n/a 2,269 ----------- -------------- ------------- Income before extraordinary item and cumulative effect of accounting change n/a n/a $ 85,879 =========== ============== ============= Total assets $319,211 $ 567,630 $ 886,841 - ----------------------------------------------------------------------------------------------- </TABLE> a) Intersegment sales were conducted on an arm's length basis. b) Gross margin is calculated as revenues less cost of sales and operations expenses. c) Gross profit is calculated as revenues less costs of sales and operations expenses and general and administrative expenses, excluding noncash compensation expense. d) Excludes noncash compensation expense, as it is not allocated to the reportable segments. NOTE 9 -- ACCOUNTING PRONOUNCEMENTS In June 2001, the Financial Accounting Standards Board ("FASB") issued Statements of Financial Accounting Standards No. 141 "Business Combinations" ("SFAS 141") and No. 142 "Goodwill and Other Intangible Assets" ("SFAS 142"). SFAS 141 requires all business combinations initiated after June 30, 2001, to be accounted for under the purchase method. For all business combinations for which the date of acquisition is after June 30, 2001 (including the Canpet acquisition, see Note 5), this Standard also establishes specific criteria for the recognition of intangible assets separately from goodwill and requires unallocated negative goodwill to be written off immediately as an extraordinary gain, rather than deferred and amortized. SFAS 142 changes the accounting for goodwill and other intangible assets after an acquisition. The most significant changes made by SFAS 142 are: 1) goodwill and intangible assets with indefinite lives will no longer be amortized; 2) goodwill and intangible assets with indefinite lives must be tested for impairment at least annually; and 3) the amortization period for intangible assets with finite lives will no longer be limited to forty years. We believe that the adoption of this Standard will not have a material effect on either our financial position, results of operations, or cash flows. We will account for all future business combinations under SFAS 141. Effective January 1, 2002, we will adopt SFAS 142, as required. At that time, amortization will cease on the unamortized portion of the goodwill arising from the Scurlock acquisition. 13
In June 2001, the FASB also issued SFAS 143 "Asset Retirement Obligations". SFAS 143 establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including (1) the timing of the liability recognition, (2) initial measurement of the liability, (3) allocation of asset retirement cost to expense, (4) subsequent measurement of the liability and (5) financial statement disclosures. SFAS 143 requires that an asset retirement cost should be capitalized as part of the cost of the related long- lived asset and subsequently allocated to expense using a systematic and rational method. We will adopt the statement effective January 1, 2003, as required. The transition adjustment resulting from the adoption of SFAS 143 will be reported as a cumulative effect of a change in accounting principle. At this time, we cannot reasonably estimate the effect of the adoption of this statement on either our financial position, results of operations, or cash flows. In August 2001, the FASB approved SFAS No. 144, "Accounting for Impairment or Disposal of Long-Lived Assets". SFAS 144 establishes a single accounting model for long-lived assets to be disposed of by sale and provides additional implementation guidance for assets to be held and used and assets to be disposed of other than by sale. At this time, we cannot reasonably estimate the effect of the adoption of this statement on either our financial position, results of operations, or cash flows. We will adopt the Statement effective January 1, 2002. NOTE 10 -- CONTINGENCIES During 1997, the All American Pipeline experienced a leak in a segment of its pipeline in California that resulted in an estimated 12,000 barrels of crude oil being released into the soil. Immediate action was taken to repair the pipeline leak, contain the spill and to recover the released crude oil. We have expended approximately $400,000 to date in connection with this spill. We do not expect additional costs related to this site to exceed $350,000, although we can provide no assurances in that regard. Prior to being acquired by our predecessor in 1996, the Ingleside Terminal experienced releases of refined petroleum products into the soil and groundwater underlying the site due to activities on the property. We are undertaking a voluntary state-administered remediation of the contamination on the property. We have spent approximately $145,000 to date in investigating the contamination at this site. We do not anticipate the total additional costs related to this site to exceed $250,000, although no assurance can be given that the actual cost could not exceed such estimate. Litigation Texas Securities Litigation. On November 29, 1999, a class action lawsuit was filed in the United States District Court for the Southern District of Texas entitled Di Giacomo v. Plains All American Pipeline, L.P., et al. The suit alleged that Plains All American and certain of the officers and directors of Plains All American Inc. (our general partner at the time) violated federal securities laws, primarily in connection with unauthorized trading by a former employee. An additional nineteen cases were filed in the Southern District of Texas, some of which name Plains All American Inc. and Plains Resources as additional defendants. All of the federal securities claims have been consolidated into two actions. The first consolidated action is that filed by purchasers of Plains Resources' common stock and options, and is captioned Koplovitz v. Plains Resources Inc., et al. The second consolidated action is that filed by purchasers of our common units, and is captioned Di Giacomo v. Plains All American Pipeline, L.P., et al. Plaintiffs alleged that the defendants were liable for securities fraud violations under Rule 10b-5 and Section 20(a) of the Securities Exchange Act of 1934 and for making false registration statements under Sections 11 and 15 of the Securities Act of 1933. We and Plains Resources reached an agreement with representatives for the plaintiffs for the settlement of all of the class actions, and in January 2001, we deposited approximately $30.0 million under the terms of the settlement agreement into an escrow account on behalf of the class. The total cost of the settlement to us and Plains Resources, including interest and expenses and after insurance reimbursements, was $14.9 million. Of that amount, $1.0 million was allocated to Plains Resources by agreement between special independent committees of the board of directors of Plains All American Inc. and the board of directors of Plains Resources. The settlement is subject to final approval by the court. The settlement agreement does not affect the Texas Derivative Litigation and Delaware Derivative Litigation described below. Delaware Derivative Litigation. On December 3, 1999, two derivative lawsuits were filed in the Delaware Chancery Court, New Castle County, entitled Susser v. Plains All American Inc., et al and Senderowitz v. Plains All American Inc., et al. These suits, and three others which were filed in Delaware subsequently, named Plains All American Inc., its directors and certain of its officers as defendants, and allege that the defendants breached the fiduciary duties that they owed to Plains All American Pipeline, L.P. and its unitholders by failing to monitor properly the activities of its employees. The court has consolidated all of the cases under the caption In Re Plains All American Inc. Shareholders Litigation, and has designated the 14
complaint filed in Susser v. Plains All American Inc. as the complaint in the consolidated action. A motion to dismiss was filed on behalf of the defendants on August 11, 2000. The plaintiffs in the Delaware derivative litigation seek that the defendants . account for all losses and damages allegedly sustained by Plains All American from the unauthorized trading losses; . establish and maintain effective internal controls ensuring that our affiliates and persons responsible for our affairs do not engage in wrongful practices detrimental to Plains All American; . pay for the plaintiffs' costs and expenses in the litigation, including reasonable attorneys' fees, accountants' fees and experts' fees, and . provide the plaintiffs any additional relief as may be just and proper under the circumstances. We have reached an agreement in principle with the plaintiffs, subject to approval by the Delaware court, to settle the Delaware litigation for approximately $1.1 million. Texas Derivative Litigation. On July 11, 2000, a derivative lawsuit was filed in the United States District Court of the Southern District of Texas entitled Fernandes v. Plains All American Inc., et al, naming Plains All American Inc., its directors and certain of its officers as defendants. This lawsuit contains the same claims and seeks the same relief as the Delaware derivative litigation, described above. A motion to dismiss was filed on behalf of the defendants on August 14, 2000. We intend to vigorously defend the claims made in the Texas derivative litigation. We believe that Delaware court approval of the settlement of the Delaware derivative litigation will effectively preclude prosecution of the Texas derivative litigation. However, there can be no assurance that we will be successful in our defense or that this lawsuit will not have a material adverse effect on our financial condition, results of operations or cash flows. We, in the ordinary course of business, are a claimant and/or a defendant in various other legal proceedings. Management does not believe that the outcome of these other legal proceedings, individually and in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows. 15
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OVERVIEW We are a Delaware limited partnership that was formed in September of 1998 to acquire and operate the midstream crude oil business and assets of Plains Resources Inc. and its wholly owned subsidiaries. On November 23, 1998, we completed our initial public offering and the transactions whereby we became the successor to the business of the midstream subsidiaries of Plains Resources. Our operations are conducted through Plains Marketing, L.P., All American Pipeline, L.P. and Plains Marketing Canada, L.P. We are engaged in interstate and intrastate transportation, marketing, and terminalling of crude oil. Our operations are conducted primarily in Texas, California, Oklahoma, Louisiana, the Gulf of Mexico and the Canadian Provinces of Alberta and Saskatchewan. Pipeline Operations. Our activities from pipeline operations generally consist of transporting third-party volumes of crude oil for a tariff and merchant activities designed to capture price differentials between the cost to purchase and transport crude oil to a sales point and the price received for such crude oil at the sales point. Tariffs on our pipeline systems vary by receipt point and delivery point. The gross margin generated by our tariff activities depends on the volumes transported on the pipeline and the level of the tariff charged, as well as the fixed and variable costs of operating the pipeline. Our ability to generate a profit on margin activities is not tied to the absolute level of crude oil prices but is generated by the difference between an index-related price paid and other costs incurred in the purchase of crude oil and an index- related price at which we sell crude oil. We are well positioned to take advantage of these price differentials due to our ability to move purchased volumes on our pipeline systems. We combine reporting of gross margin for tariff activities and margin activities due to the sharing of fixed costs between the two activities. Terminalling and Storage Activities and Gathering and Marketing Activities. Gross margin from terminalling and storage activities is dependent on the throughput volume of crude oil stored and the level of fees generated at our terminalling and storage facilities. Gross margin from our gathering and marketing activities is dependent on our ability to sell crude oil at a price in excess of our aggregate cost. These operations are not directly affected by the absolute level of crude oil prices, but are affected by overall levels of supply and demand for crude oil and fluctuations in market related indices. RECENT EVENTS Murphy Oil Company Ltd. Midstream Operations. In May 2001, we closed the acquisition of substantially all of the Canadian crude oil pipeline, gathering, storage and terminalling assets of Murphy Oil Company Ltd. for approximately $161 million in cash (the "Murphy Acquisition"), including financing and transaction costs. The purchase included $6.5 million for excess inventory in the pipeline systems. The principal assets acquired included approximately 450 miles of crude oil and condensate transmission mainlines (including dual lines on which condensate is shipped for blending purposes and blended crude is shipped in the opposite direction) and associated gathering and lateral lines, approximately 1.1 million barrels of crude oil storage and terminalling capacity located primarily in Kerrobert, Saskatchewan, approximately 254,000 barrels of linefill and tank inventories, an inactive 108-mile mainline system and 121 trailers used primarily for crude oil transportation. We have reactivated the 108-mile mainline system and began shipping volumes in May of 2001. Murphy agreed to continue to transport production from fields currently delivering crude oil to these pipeline systems, under a long-term contract. The current volume under the contract is approximately 11,000 barrels per day. The pipeline systems currently transport approximately 225,000 barrels per day of light, medium and heavy crudes, as well as condensate. CANPET Energy Group Inc. In July 2001, we acquired the assets of CANPET Energy Group Inc. ("CANPET") a Calgary based Canadian crude oil and liquefied petroleum gas marketing company, for approximately $42.0 million plus excess inventory at the closing date of approximately $25 million. Approximately $24.0 million of the purchase price plus the excess inventory was paid in cash at closing and the remainder, which is subject to certain performance standards, will be paid in common units in April, 2004, if such standards are met. CANPET activities include gathering approximately 75,000 barrels per day of crude oil and marketing approximately 26,000 barrels per day of natural gas liquids. Tangible assets acquired included a crude oil handling facility, a 130,000- barrel tank facility and working capital of approximately $8.6 million. Financing for the acquisition was provided through borrowings under our bank credit facility. 16
RESULTS OF OPERATIONS Three Months Ended September 30, 2001 and 2000 For the three months ended September 30, 2001, we reported net income of $15.2 million on total revenue of $2.2 billion compared to net income for the same period in 2000 of $4.5 million on total revenues of $1.6 billion. The results for the three months ended September 30, 2000 included the following unusual items: . $6.6 million charge for litigation costs related to the unauthorized trading losses, and . $2.1 million of noncash compensation expense. Excluding the items noted above, we would have reported net income of $13.3 million for the three months ended September 30, 2000. The following table sets forth our operating results for the periods indicated and includes the impact of the items discussed above (in thousands): THREE MONTHS ENDED September 30, ---------------------- 2001 2000 ---------- --------- Operating Results: Revenues $2,191,310 $1,555,863 ========== ========== Gross margin: Pipeline $ 16,089 $ 11,886 Gathering and marketing and terminalling and storage 23,555 20,674 Unauthorized trading losses - (6,600) ---------- ---------- Total 39,644 25,960 General and administrative expense (10,297) (9,911) ---------- ---------- Gross profit $ 29,347 $ 16,049 ========== ========== Net income $ 15,161 $ 4,516 ========== ========== AVERAGE DAILY VOLUMES (MBBLS/DAY): Pipeline Activities: All American Tariff activities 68 76 Margin activities 53 55 Canada 225 - Other 113 100 ---------- ---------- Total 459 231 ========== ========== Lease gathering 391 258 Bulk purchases 55 28 ---------- ---------- Total 446 286 ========== ========== Terminal throughput 97 81 ========== ========== Storage leased to third parties, monthly average volumes 2,672 1,687 ========== ========== Revenues. Revenues increased to $2.2 billion for the third quarter of 2001 compared to the 2000 third quarter amount of $1.6 billion. The increase is primarily attributable to our Canadian acquisitions. Cost of Sales and Operations. Cost of sales and operations increased to $2.1 billion in the third quarter of 2001 compared to $1.5 billion in the same quarter of 2000. The increase is primarily due to our Canadian acquisitions and an increase in fuel and power expenses. 17
General and Administrative. General and administrative expenses were $10.3 million for the quarter ended September 30, 2001, compared to $9.9 million for the third quarter in 2000. The increase in 2001 is primarily due to our Canadian acquisitions as well as additional salary expenses related to the reorganization of our general partner. Depreciation and Amortization. Depreciation and amortization expense was $6.4 million for the quarter ended September 30, 2001, compared to $5.3 million for the third quarter of 2000. The increase is a result of our Canadian acquisitions. Interest expense. Interest expense was $7.8 million for the quarter ended September 30, 2001, compared to $6.5 million for the third quarter in 2000. An increased average debt balance in the current quarter, primarily due to our Canadian acquisitions, was partially offset by lower interest rates. Unauthorized trading losses. In the third quarter of 2000, we recognized a $6.6 million charge, in addition to prior accruals, for litigation expenses related to the unauthorized trading losses. Noncash compensation expense. We recognized noncash compensation expense of $2.1 million in the third quarter of 2000 related to the probable vesting of partnership units granted by our general partner to certain officers and key employees of our general partner and its affiliates. Segment Results Pipeline Operations. Gross margin from pipeline operations was $16.1 million for the quarter ended September 30, 2001 compared to $11.9 million for the prior year quarter. The majority of the increase is attributable to our recently acquired Canadian operations as well as an increase in tariffs and volumes shipped on our domestic pipelines. Because of increased fuel and power costs in 2001, we expect the tariff on the All American Pipeline to increase effective January 1, 2002, although we can make no assurance in that regard. Average daily pipeline volumes totaled 459,000 barrels per day and 231,000 barrels per day for the third quarter of 2001 and 2000, respectively. The volume increase is primarily due to our Canadian acquisitions. Tariff volumes on domestic pipelines increased a net 5,000 barrels per day. Volumes on the Scurlock and West Texas Gathering systems increased 13,000 barrels per day to 113,000 barrels per day from 100,000 barrels per day. Volumes on the All American Pipeline decreased approximately 8,000 barrels per day. Despite this decrease, revenues from the All American Pipeline volumes have remained approximately flat due to a tariff increase that was effective at the beginning of 2001. Gathering and Marketing Activities and Terminalling and Storage Activities. Gross margin from gathering, marketing, terminalling, and storage was adversely impacted by market conditions during the third quarter and higher operating costs, including fuel and power expenses. Despite this, gross margin from gathering, marketing, terminalling and storage activities was approximately $23.5 million for the quarter ended September 30, 2001, a 14% increase as compared to $20.7 million in the prior year quarter (excluding the unauthorized trading losses). This increase is primarily due to our Canadian acquisitions, as well as increased storage and throughput at our Cushing Terminal. Lease gathering volumes increased to approximately 391,000 barrels per day in the current year period from an average of 258,000 barrels per day in the third quarter of 2000. Bulk purchase volumes increased from approximately 28,000 barrels per day in the 2000 third quarter to approximately 55,000 barrels per day in the current year period. Our Canadian acquisitions accounted for 110,000 barrels per day and 34,000 barrels per day of the increase in lease gathered and bulk volumes, respectively. Terminal throughput, which includes both our Cushing and Ingleside terminals, increased to 97,200 barrels per day from 81,400 barrels per day in the third quarter of last year. Storage leased to third parties increased to 2.7 million barrels compared to 1.7 million barrels in the previous year's quarter. Nine Months Ended September 30, 2001 and 2000 For the nine months ended September 30, 2001, we reported net income of $35.2 million on total revenue of $5.3 billion, compared to net income for the same period in 2000 of $70.7 million on total revenues of $5.0 billion. The results for the nine months ended September 30, 2001 and 2000 include the following unusual items: 2001 . a $6.1 million charge associated with the vesting of phantom partnership units primarily as a result of the change in our general partner in June, 2001. Approximately $5.7 million of the charge 18
(included in general and administrative expenses) was noncash and was satisfied by units owned by our former general partner. This portion of the charge had no impact on equity or the number of outstanding units as it was offset by a deemed capital contribution by our former general partner and the units were satisfied by units owned by our former general partner, and . a $0.5 million cumulative effect gain as a result of the adoption of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"). 2000 . a $28.1 million gain on the sale of crude oil linefill; . a $20.1 million gain on the sale of the segment of the All American Pipeline that extends from Emidio, California, to McCamey, Texas; . $9.7 million of previously deferred gains on interest rate swap terminations recognized due to the early extinguishment of debt; . an extraordinary loss of $15.1 million related to the early extinguishment of debt; . $6.6 million charge for litigation related to the unauthorized trading losses; . amortization of $4.6 million of debt issue costs associated with facilities put in place during the fourth quarter of 1999, and . $2.3 million of noncash compensation expense. Excluding the items noted above, we would have reported net income of $40.8 million and $41.4 million for the nine months ended September 30, 2001 and 2000, respectively. The following table sets forth our operating results for the periods indicated and includes the impact of the items discussed above (in thousands): NINE MONTHS ENDED SEPTEMBER 30, ------------------- 2001 2000 ---- ---- OPERATING RESULTS: Revenues $5,298,051 $5,040,204 ========== ========== Gross margin: Pipeline $ 48,247 $ 37,802 Gathering and marketing and terminalling and storage 60,516 64,084 Unauthorized trading losses - (6,600) ---------- ---------- Total 108,763 95,286 General and administrative expense (34,327) (26,486) ---------- ---------- Gross profit $ 74,436 $ 68,800 ========== ========== Net income $ 35,243 $ 70,732 ========== ========== Table continued on following page 19
NINE MONTHS ENDED SEPTEMBER 30, ----------------- 2001 2000 ------ ------ AVERAGE DAILY VOLUMES (MBBLS/DAY): Pipeline Activities: All American Tariff activities 68 74 Margin activities 58 57 Canada (a) 217 - Other 128 106 ----- ----- Total 471 237 ===== ===== Lease gathering (a) 359 259 Bulk purchases 49 28 ----- ----- Total 408 287 ===== ===== Terminal throughput 103 64 ===== ===== Storage leased to third parties, monthly average volumes 2,337 1,489 ===== ===== ______________ a) Reflects the calculation of barrels per day applicable to our Canadian acquisitions as of the effective dates of those transactions. Revenues. Revenues increased to $5.3 billion from $5.0 billion in the first nine months of 2000. The increase is primarily due to our Canadian acquisitions, which was partially offset by lower crude oil prices. Cost of Sales and Operations. Cost of sales and operations increased to $5.2 billion from $4.9 billion in the first nine months of 2000. The increase is primarily due to the reasons discussed above under "Revenues". General and Administrative. General and administrative expenses were $34.3 million for the nine months ended September 30, 2001, compared to $26.5 million for the same period in 2000. The increase in 2001 is primarily due to the Canadian acquisitions and a $6.1 million charge attributable to the vesting of phantom partnership units in the second quarter as a result of the change in our general partner in June, 2001. Approximately $5.7 million of the charge was noncash and was satisfied by units owned by our former general partner. This portion of the charge had no impact on partners' capital or the number of outstanding units as it was offset by a deemed capital contribution by our former general partner. Approximately $2.3 million of similar charges were reported in the nine month period of 2000. Depreciation and Amortization. Depreciation and amortization expense was $17.6 million for the nine months ended September 30, 2001, compared to $20.1 million for the first nine months of 2000. The decrease is primarily due to the increased amortization of debt issue costs in the 2000 period associated with facilities put in place during the fourth quarter of 1999 as a result of the unauthorized trading losses. Approximately $3.8 million of depreciation and amortization in the current year period is attributable to our Canadian acquisitions. Interest expense. Interest expense was $22.5 million for the nine months ended September 30, 2001, compared to $21.8 million for the same period in 2000. The increase is primarily due to a higher average debt balance in 2001 resulting from our acquisitions. Unauthorized trading losses. In the third quarter of 2000, we recognized a $6.6 million charge, in addition to prior accruals, for litigation expenses related to the unauthorized trading losses. Gain on sale of linefill. We initiated the sale of 5.2 million barrels of crude oil linefill from the All American Pipeline in November 1999. The sale was completed in March 2000. We recognized a gain of $28.1 million in connection with the sale of the linefill in the first quarter of 2000. Gain on sale of pipeline segment. On March 24, 2000, we completed the sale of the segment of the All American Pipeline that extends from Emidio, California to McCamey, Texas to a unit of El Paso Energy Corporation for 20
proceeds of approximately $124.0 million, which are net of associated transaction costs and estimated costs to remove certain equipment. We recognized a total gain of $20.1 million in connection with the sale in the first quarter of 2000. Early extinguishment of debt. During the nine months ended September 30, 2000, we recognized extraordinary losses, consisting primarily of unamortized debt issue costs, totaling $15.1 million related to the permanent reduction of the All American Pipeline, L.P. term loan facility and the refinancing of our credit facilities. In addition, interest and other income for the nine months ended September 30, 2000, includes $9.7 million of previously deferred gains from terminated interest rate swaps as a result of the debt extinguishments. Cumulative effect of accounting change. During the first quarter of 2001, we recognized a $0.5 million cumulative effect gain as a result of the adoption of SFAS 133 effective January 1, 2001. Segment Results Pipeline Operations. Gross margin from pipeline operations was $48.2 million for the nine months ended September 30, 2001 compared to $37.8 million for the prior year period. The majority of the increase is attributable to our recently acquired Canadian operations. Average daily pipeline volumes totaled 471,000 barrels per day and 237,000 barrels per day for the first nine months of 2001 and 2000, respectively. Our Canadian acquisitions contributed 217,000 barrels per day of the increase. Canadian volumes are included from the effective date of the acquisition, which was April 1, 2001. All American's tariff volumes attributable to offshore California production were approximately 68,000 barrels per day for the nine months ended September 30, 2001 compared to 74,000 barrels per day in the prior year period, with the associated revenues remaining relatively flat due to the tariff increase that was effective January 1, 2001. Tariff volumes shipped on the Scurlock and West Texas gathering systems averaged 127,000 barrels per day and 106,000 barrels per day during the first nine months of 2001 and 2000, respectively. Gathering and Marketing Activities and Terminalling and Storage Activities. Gross margin from gathering, marketing, terminalling and storage activities was approximately $60.5 million for the nine months ended September 30, 2001 compared to $64.1 million (excluding the unauthorized trading losses) in the prior year period. Despite an increase in margin due to our Canadian operations, total margin decreased due to adverse market conditions and higher operating costs, including increased fuel and power costs. Lease gathering volumes increased from an average of 259,000 barrels per day for the first nine months of 2000 to approximately 359,000 barrels per day for the 2001 period due to our Canadian acquisitions, which contributed approximately 75,000 barrels per day. Canadian volumes are included from the effective dates of the Murphy and Canpet acquisitions. Bulk purchase volumes increased from approximately 28,000 barrels per day for the first nine months of 2000 to approximately 49,000 barrels per day in the current year period, also due to the Canadian acquisitions. Terminal throughput, which includes both our Cushing and Ingleside terminals, was 103,000 and 64,000 barrels per day for the nine months ended September 30, 2001 and 2000, respectively. Storage leased to third parties was 2.3 million barrels per month and 1.5 million barrels per month for the same periods, respectively. LIQUIDITY AND CAPITAL RESOURCES Credit Agreements In September 2001, we amended and expanded our existing credit facilities to include a six-year, $200 million term B loan. In connection with the amendment, we reduced the revolving portion of the facilities by $50 million. Our credit facilities currently consist of a $200 million senior secured letter of credit and borrowing facility, and a $780.0 million senior secured revolving credit and term loan facility, each of which is secured by substantially all of our assets. The revolving credit and term loan facility consists of a $450.0 million domestic revolving facility (with a $10.0 million letter of credit sublimit), a $30.0 million Canadian revolving facility (with a $5.0 million letter of credit sublimit), a $100.0 million term loan, and a $200.0 million term B loan. The facility matures, as to the aggregate $480.0 million domestic and Canadian revolver portions, in April, 2005, as to the $100.0 million term portion, in May, 2006 and as to the $200.0 million term B loan in September 2007. For a complete discussion of our credit facilities, see Note 6 to the Consolidated Financial Statements. Equity Offerings On October 31, 2001, we completed a public offering of 4,500,000 common units. Net cash proceeds from the offering, including our general partner's proportionate contribution, were approximately $116 million. On November 13, 2001, the underwriters in the offering exercised their overallotment option and purchased an additional 400,000 units for net cash proceeds of approximately $10.8 million. This offering is in addition to the 3,966,700 units issued in May and June 2001 which resulted in net proceeds of $100.7 million, including our general partner's proportionate contribution. Proceeds from both offerings were used to repay borrowings under our revolving credit facility, a portion of which was used to finance our Canadian acquisitions (see Note 5 to the Consolidated Financial Statements). Liquidity Cash generated from operations, credit facilities, and equity offerings are our primary sources of liquidity. At September 30, 2001, we had working capital of approximately $62.0 million. On November 7, 2001, PAA had approximately $350 million 21
outstanding under its $780 million of credit facilities (excluding the letter of credit and borrowing facility). Accordingly, our liquidity under our credit facilities is $430 million, subject to covenants contained in the agreement. We believe that we have sufficient liquid assets, cash from operations and borrowing capacity under our credit agreements to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. Cash Flows NINE MONTHS ENDED SEPTEMBER 30, ----------------- (IN MILLIONS) (UNAUDITED) 2001 2000 - ------------------------------------------------------------ Cash provided by (used in): Operating activities $ 5.5 $ (7.5) Investing activities (221.3) 216.4 Financing activities 216.2 (259.4) - ------------------------------------------------------------- Operating Activities. Net cash provided by operating activities for the first nine months of 2001 includes the effect of our normal operations, Canadian acquisitions and Contango inventory transactions. Investing Activities. Net cash used for investing activities for the first nine months of 2001 included approximately $209 million for the Canadian acquisitions which occurred in the second and third quarters. Financing activities. Net cash provided by financing activities for the first nine months of 2001 resulted from our credit facilities that were used to finance the Murphy and Canpet acquisitions and the issuance of additional units which raised approximately $100.7 million of equity capital. Proceeds from the equity offering were used to repay indebtedness under the credit facilities. Contingencies Following our announcement in November 1999 of our losses resulting from unauthorized trading by a former employee, numerous class action lawsuits were filed in the United States District Court of the Southern District of Texas against us, certain of the officers and directors of Plains All American Inc. (our general partner at the time) and in some of these cases, our former general partner and Plains Resources Inc., alleging violations of the federal securities laws. In addition, derivative lawsuits were filed in the Delaware Chancery Court and the United States District Court of the Southern District of Texas against our former general partner, its directors and certain of its officers alleging the defendants breached the fiduciary duties owed to us and our unitholders by failing to monitor properly the activities of our traders. The class actions and the Delaware derivative suits have been settled, subject to court approval. See Part II, Item 1 - "Legal Proceedings". We may experience future releases of crude oil into the environment from our pipeline and storage operations, or discover releases that were previously unidentified. Although we maintain an extensive inspection program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to any future environmental releases from our assets may substantially affect our business. ACCOUNTING PRONOUNCEMENTS In June 2001, the Financial Accounting Standards Board ("FASB") issued Statements of Financial Accounting Standards No. 141 "Business Combinations" ("SFAS 141") and No. 142 "Goodwill and Other Intangible Assets" ("SFAS 142"). SFAS 141 requires all business combinations initiated after June 30, 2001 (including the Canpet acquisition, see Note 5), to be accounted for under the purchase method. For all business combinations for which the date of acquisition is after June 30, 2001, this Standard also establishes specific criteria for the recognition of intangible assets separately from goodwill and requires unallocated negative goodwill to be written off immediately as an extraordinary gain, rather than deferred and amortized. SFAS 142 changes the accounting for goodwill and other intangible assets after an acquisition. The most significant changes made by SFAS 142 are: 1) goodwill and intangible assets with indefinite lives will no longer be amortized; 2) goodwill and intangible assets with indefinite lives must be tested for impairment at least annually; and 3) the amortization period for intangible assets with finite lives will no longer be limited to forty years. We believe that 22
the adoption of this Standard will not have a material effect on either our financial position, results of operations, or cash flows. We will account for all future business combinations under SFAS 141. Effective January 1, 2002, we will adopt SFAS 142, as required. At that time, amortization will cease on the unamortized portion of the goodwill arising from the Scurlock acquisition. In June 2001, the FASB also issued SFAS 143 "Asset Retirement Obligations". SFAS 143 establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including (1) the timing of the liability recognition, (2) initial measurement of the liability, (3) allocation of asset retirement cost to expense, (4) subsequent measurement of the liability and (5) financial statement disclosures. SFAS 143 requires that an asset retirement cost should be capitalized as part of the cost of the related long- lived asset and subsequently allocated to expense using a systematic and rational method. We will adopt the statement effective January 1, 2003, as required. The transition adjustment resulting from the adoption of SFAS 143 will be reported as a cumulative effect of a change in accounting principle. At this time, we cannot reasonably estimate the effect of the adoption of this statement on either our financial position, results of operations, or cash flows. In August 2001, the FASB approved SFAS No. 144, "Accounting for Impairment or Disposal of Long-Lived Assets". SAFS 144 establishes a single accounting model for long-lived assets to be disposed of by sale and provides additional implementation guidance for assets to be held and used and assets to be disposed of other than by sale. At this time, we cannot reasonably estimate the effect of the adoption of this Statement on either our financial position, results of operations, or cash flows. We will adopt the Statement effective January 1, 2002. 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" and "forecast" and similar expressions and statements regarding our business strategy, plans and objectives of our management for future operations. These statements reflect our current views and those of our general partner with respect to future events, based on what we believe are reasonable assumptions. These statements, however, are subject to certain risks, uncertainties and assumptions, including, but not limited to: . the availability of adequate supplies of and demand for crude oil in the areas in which we operate; . the impact of crude oil price fluctuations; . successful third-party drilling efforts and completion of announced oil- sands project; . the effects of competition; . the success of our risk management activities; . the availability of favorable acquisition or combination opportunities; . successful integration and future performance of recently acquired assets; . our ability to receive credit on satisfactory terms; . unanticipated shortages or cost increases of power supplies, materials or labor; . the impact of current and future laws and governmental regulations and rate-setting; . weather interference with business operations or project construction; . environmental liabilities not covered by indemnity or insurance, and . general economic, market or business conditions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual results may vary materially from the results anticipated in the forward-looking statements. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information. 23
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS We are exposed to various market risks, including volatility in crude oil commodity prices and interest rates. To manage such exposure, we monitor our inventory levels and our expectations of future commodity prices and interest rates when making decisions with respect to risk management. We do not enter into derivative transactions for speculative trading purposes that would expose us to price risk. Substantially all of our derivative contracts are exchanged or traded with major financial institutions and the risk of credit loss is considered remote. On January 1, 2001, we adopted SFAS 133 "Accounting for Derivative Instruments and Hedging Activities" as amended by SFAS 137 and SFAS 138. Under SFAS 133, all derivative instruments are recorded on the balance sheet at fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. To qualify for hedge accounting, the derivative must qualify either as a fair value hedge, cash flow hedge or foreign currency hedge. With respect to fair value hedges, gains or losses for both the hedge and the hedged item are taken directly to earnings in the current period. Thus, earnings are impacted by the net change between the hedge and the underlying hedged transaction. With respect to cash flow hedges, gains or losses are deferred in accumulated Other Comprehensive Income ("OCI"), a component of Partners' Capital, to the extent the hedge is effective (discussed further below). Foreign currency hedges may be treated as either fair value hedges or cash flow hedges, depending on the specific characteristics of the hedge. As of September 30, 2001 our hedges consisted only of cash flow hedges or foreign currency hedges treated as cash flow hedges, and the remaining discussion relates exclusively to these types of hedges. We utilize various derivative instruments, for purposes other than trading, to hedge our exposure to price fluctuations on crude in storage and expected purchases, sales and transportation of crude oil. The derivative instruments consist primarily of futures and option contracts traded on the New York Mercantile Exchange. We also utilize interest rate collars and interest rate swaps to manage the interest rate exposure on our long-term debt and foreign currency hedges to manage exchange rate exposure. At September 30, 2001, an $11.1 million unrealized loss was recorded to OCI together with related assets and liabilities of $7.3 million and $17.7 million, respectively. Earnings included a noncash gain of $0.8 million related to the ineffective portion of our cash flow hedges as well as certain derivative contracts that did not qualify as hedges relating to our Canadian businesses due to a low correlation between the futures contract and hedged item. Our hedge- related assets and liabilities are included in other current assets and other current liabilities in the balance sheet. As of September 30, 2001, the total amount of deferred net losses on derivative instruments recorded in OCI are expected to be reclassified to earnings during the next twelve-month period. The following table sets forth our open crude oil hedge positions at September 30, 2001. These are futures hedges and thus have offsetting physical exposures to the extent they are effective. 2001 2002 ---- ----------------------------- 4th Qtr 1st Qtr 2nd Qtr 3rd Qtr --------- ----------------------------- Volume (bbls) Short position 1,302,000 - - - Long position - 2,760,000 213,000 - Average price ($/bbl) $26.94 $27.37 $28.46 - At September 30, 2001, we had arrangements to protect interest rate fluctuations on a portion of our outstanding debt for an aggregate notional amount of $275.0 million. These instruments are based on LIBOR rates. Approximately $125 million notional amount is comprised of an interest rate collar, which provides for a floor of 6.1% and a ceiling of 8.0% with an expiration date of August 2002. The remaining $150 million notional amount consists of interest rate swaps with an average LIBOR rate of approximately 3.8%. These swaps expire with respect to $100 million in September, 2003, and the remainder in March, 2004. We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. Hedge effectiveness is measured on a quarterly basis. This process includes specific identification of the hedging instrument and the hedge transaction, the nature of the risk being hedged and how the hedging instrument's effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we 24
assess whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. No amounts were excluded from the computation of hedge effectiveness. 25
PART II. OTHER INFORMATION Item 1. LEGAL PROCEEDINGS Texas Securities Litigation. On November 29, 1999, a class action lawsuit was filed in the United States District Court for the Southern District of Texas entitled Di Giacomo v. Plains All American Pipeline, L.P., et al. The suit alleged that Plains All American and certain of the officers and directors of Plains All American Inc. (our general partner at the time) violated federal securities laws, primarily in connection with unauthorized trading by a former employee. An additional nineteen cases were filed in the Southern District of Texas, some of which name Plains All American Inc. and Plains Resources as additional defendants. All of the federal securities claims have been consolidated into two actions. The first consolidated action is that filed by purchasers of Plains Resources' common stock and options, and is captioned Koplovitz v. Plains Resources Inc., et al. The second consolidated action is that filed by purchasers of our common units, and is captioned Di Giacomo v. Plains All American Pipeline, L.P., et al. Plaintiffs alleged that the defendants were liable for securities fraud violations under Rule 10b-5 and Section 20(a) of the Securities Exchange Act of 1934 and for making false registration statements under Sections 11 and 15 of the Securities Act of 1933. We and Plains Resources reached an agreement with representatives for the plaintiffs for the settlement of all of the class actions, and in January 2001, we deposited approximately $30.0 million under the terms of the settlement agreement into an escrow account on behalf of the class. The total cost of the settlement to us and Plains Resources, including interest and expenses and after insurance reimbursements, was $14.9 million. Of that amount, $1.0 million was allocated to Plains Resources by agreement between special independent committees of the board of directors of Plains All American Inc. and the board of directors of Plains Resources. The settlement is subject to final approval by the court. The settlement agreement does not affect the Texas Derivative Litigation and Delaware Derivative Litigation described below. Delaware Derivative Litigation. On December 3, 1999, two derivative lawsuits were filed in the Delaware Chancery Court, New Castle County, entitled Susser v. Plains All American Inc., et al and Senderowitz v. Plains All American Inc., et al. These suits, and three others which were filed in Delaware subsequently, named Plains All American Inc., its directors and certain of its officers as defendants, and allege that the defendants breached the fiduciary duties that they owed to Plains All American Pipeline, L.P. and its unitholders by failing to monitor properly the activities of its employees. The court has consolidated all of the cases under the caption In Re Plains All American Inc. Shareholders Litigation, and has designated the complaint filed in Susser v. Plains All American Inc. as the complaint in the consolidated action. A motion to dismiss was filed on behalf of the defendants on August 11, 2000. The plaintiffs in the Delaware derivative litigation seek that the defendants: . account for all losses and damages allegedly sustained by Plains All American from the unauthorized trading losses; . establish and maintain effective internal controls ensuring that our affiliates and persons responsible for our affairs do not engage in wrongful practices detrimental to Plains All American; . pay for the plaintiffs' costs and expenses in the litigation, including reasonable attorneys' fees, accountants' fees and experts' fees; and . provide the plaintiffs any additional relief as may be just and proper under the circumstances. We have reached an agreement in principle with the plaintiffs, subject to approval by the Delaware court, to settle the Delaware litigation for approximately $1.1 million. Texas Derivative Litigation. On July 11, 2000, a derivative lawsuit was filed in the United States District Court of the Southern District of Texas entitled Fernandes v. Plains All American Inc., et al, naming Plains All American Inc., its directors and certain of its officers as defendants. This lawsuit contains the same claims and seeks the same relief as the Delaware derivative litigation, described above. A motion to dismiss was filed on behalf of the defendants on August 14, 2000. We intend to vigorously defend the claims made in the Texas derivative litigation. We believe that Delaware court approval of the settlement of the Delaware derivative litigation will effectively preclude prosecution of the Texas derivative litigation. However, there can be no assurance that we will be successful in our defense or that this lawsuit will not have a material adverse effect on our financial position or results of operation. 26
We, in the ordinary course of business, are a claimant and/or a defendant in various other legal proceedings. Management does not believe that the outcome of these other legal proceedings, individually and in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows. ITEMS 2, 3, 4 & 5 ARE NOT APPLICABLE AND HAVE BEEN OMITTED. ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K A. Exhibits 10.1 - Third Amendment to Amended and Restated Credit Agreement (Revolving Credit Facility) dated as of the 6th day of September, 2001, among Plains Marketing, L.P., All American Pipeline, L.P. and Plains All American Pipeline, L.P. and Fleet National Bank and certain other lenders. 10.2 - Third Amendment to Amended and Restated Credit Agreement (Letter of Credit and Hedged Inventory Facility) dated as of the 6th day of September, 2001, among Plains Marketing, L.P., All American Pipeline, L.P. and Plains All American Pipeline, L.P. and Fleet National Bank and certain other lenders. 10.3 - Amended and Restated Employment Agreement made as of the 30th day of June, 2001, between Plains All American GP LLC and Greg L Armstrong. 10.4 - Amended and Restated Employment Agreement made as of the 30th day of June, 2001, between Plains All American GP LLC and Harry N Pefanis. B. Reports on Form 8-K A Current Report on Form 8-K was filed on October 26, 2001 in connection with the execution of an underwriting agreement with Salomon Smith Barney Inc., in connection with the sale by the Partnership of 4,500,000 common units of the Partnership. A Current Report on Form 8-K/A was filed on October 25, 2001 amending the Partnership's Form 8-K dated June 22, 2001 in connection with the pro forma financial statements for the Partnership. A Current Report on Form 8-K was filed on October 23, 2001 in connection with the announcement of a $0.0125 per unit increase over the previous quarter's distribution. A Current Report on Form 8-K was filed September 27, 2001, in connection with a new six-year $200 Million Term Loan. A Current Report on Form 8-K was filed on August 27, 2001, relating to the amendments to the Partnership's and the operating limited partnership's partnership agreements and the restated financial statements of the Partnership and balance sheet for Plains AAP, L.P. 27
SIGNATURES 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 Its General Partner Date: November 14, 2001 By: /s/ PHILLIP D. KRAMER ______________________________________ Phillip D. Kramer, Executive Vice President and Chief Financial Officer 28