================================================================================ 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 June 30, 2002 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 (I.R.S. Employer jurisdiction of Identification No.) incorporation or organization) 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] No [_] At August 5, 2002, 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 <TABLE> <CAPTION> Page ---- <S> <C> PART I. FINANCIAL INFORMATION CONSOLIDATED FINANCIAL STATEMENTS: Consolidated Balance Sheets: June 30, 2002, and December 31, 2001......................................... 3 Consolidated Statements of Operations: For the three and six months ended June 30, 2002 and 2001.................... 4 Consolidated Statements of Cash Flows: For the six months ended June 30, 2002 and 2001.............................. 5 Consolidated Statement of Partners' Capital: For the six months ended June 30, 2002....................................... 6 Consolidated Statements of Comprehensive Income and Changes in Accumulated Other Comprehensive Income: For the three and six months ended June 30, 2002 and 2001.................... 7 Notes to Consolidated Financial Statements...................................... 8 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS................................................................. 16 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS..................... 27 PART II. OTHER INFORMATION...................................................... 29 </TABLE> 2
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (in thousands, except unit data) <TABLE> <CAPTION> June 30, December 31, 2002 2001 ----------- ------------ (unaudited) <S> <C> <C> ASSETS CURRENT ASSETS Cash and cash equivalents............................................. $ 5,792 $ 3,511 Accounts receivable and other current assets.......................... 514,034 365,697 Inventory............................................................. 67,289 188,874 ---------- ---------- Total current assets.............................................. 587,115 558,082 ---------- ---------- PROPERTY AND EQUIPMENT................................................... 685,636 653,050 Less allowance for depreciation and amortization...................... (60,320) (48,131) ---------- ---------- 625,316 604,919 ---------- ---------- OTHER ASSETS Pipeline linefill..................................................... 58,242 57,367 Other, net............................................................ 67,331 40,883 ---------- ---------- 125,573 98,250 ---------- ---------- $1,338,004 $1,261,251 ========== ========== LIABILITIES AND PARTNERS' CAPITAL CURRENT LIABILITIES Accounts payable and other current liabilities........................ $ 476,675 $ 386,993 Due to affiliates..................................................... 19,170 13,685 Short-term debt....................................................... 57,847 104,482 ---------- ---------- Total current liabilities......................................... 553,692 505,160 LONG-TERM LIABILITIES Bank debt............................................................. 381,591 351,677 Other long-term liabilities........................................... 4,785 1,617 ---------- ---------- Total liabilities................................................. 940,068 858,454 ---------- ---------- COMMITMENTS AND CONTINGENCIES (Note 8) PARTNERS' CAPITAL Common unitholders (31,915,939 units outstanding at each date)........ 405,031 408,562 Class B common unitholders (1,307,190 units outstanding at each date). 19,389 19,534 Subordinated unitholders (10,029,619 units outstanding at each date).. (40,005) (38,891) General partner....................................................... 13,521 13,592 ---------- ---------- Total partners' capital........................................... 397,936 402,797 ---------- ---------- $1,338,004 $1,261,251 ========== ========== </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) <TABLE> <CAPTION> Three Months Ended Six Months Ended June 30, June 30, ---------------------- ---------------------- 2002 2001 2002 2001 ---------- ---------- ---------- ---------- (unaudited) <S> <C> <C> <C> <C> REVENUES......................................... $1,985,347 $1,586,617 $3,530,670 $3,106,741 COST OF SALES AND OPERATIONS..................... 1,943,640 1,550,230 3,450,575 3,037,624 ---------- ---------- ---------- ---------- Gross Margin.................................. 41,707 36,387 80,095 69,117 ---------- ---------- ---------- ---------- EXPENSES General and administrative.................... 11,119 15,041 21,877 24,030 Depreciation and amortization................. 7,177 6,503 14,144 11,173 ---------- ---------- ---------- ---------- Total expenses............................ 18,296 21,544 36,021 35,203 ---------- ---------- ---------- ---------- OPERATING INCOME................................. 23,411 14,843 44,074 33,914 Interest expense.............................. (6,354) (8,101) (12,807) (14,707) Interest and other income (expense)........... (106) 325 (35) 367 ---------- ---------- ---------- ---------- Income before cumulative effect of accounting change...................................... 16,951 7,067 31,232 19,574 Cumulative effect of accounting change........ -- -- -- 508 ---------- ---------- ---------- ---------- NET INCOME....................................... $ 16,951 $ 7,067 $ 31,232 $ 20,082 ========== ========== ========== ========== NET INCOME--LIMITED PARTNERS..................... $ 15,902 $ 6,794 $ 29,356 $ 19,483 ========== ========== ========== ========== NET INCOME--GENERAL PARTNER...................... $ 1,049 $ 273 $ 1,876 $ 599 ========== ========== ========== ========== BASIC AND DILUTED NET INCOME PER LIMITED PARTNER UNIT Income before cumulative effect of accounting change...................................... $ 0.37 $ 0.19 $ 0.68 $ 0.54 Cumulative effect of accounting change........ -- -- -- 0.02 ---------- ---------- ---------- ---------- Net income................................ $ 0.37 $ 0.19 $ 0.68 $ 0.56 ========== ========== ========== ========== WEIGHTED AVERAGE UNITS OUTSTANDING............... 43,253 35,685 43,253 35,039 ========== ========== ========== ========== </TABLE> See notes to consolidated financial statements. 4
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands) <TABLE> <CAPTION> Six Months Ended June 30, ------------------------ 2002 2001 --------- ----------- (unaudited) <S> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES Net income....................................................................... $ 31,232 $ 20,082 Adjustments to reconcile net income to net cash provided by (used in) operating activities: Depreciation and amortization................................................. 14,144 11,173 Cumulative effect of accounting change........................................ -- (508) Change in derivative fair value............................................... 1,718 (62) Noncash compensation expense.................................................. -- 5,741 Change in assets and liabilities, net of assets acquired and liabilities assumed: Accounts receivable and other................................................. (139,534) (84,763) Inventory..................................................................... 122,599 (77,119) Accounts payable and other current liabilities................................ 82,214 81,424 Due to affiliates............................................................. 5,485 (2,947) --------- ----------- Net cash provided by (used in) operating activities....................... 117,858 (46,979) --------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES Additions to property and equipment.............................................. (20,847) (9,412) Proceeds from sales of assets.................................................... 987 1,077 Cash paid in connection with acquisitions........................................ (30,279) (160,584) --------- ----------- Net cash used in investing activities..................................... (50,139) (168,919) --------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from long-term debt..................................................... 548,749 1,114,780 Proceeds from short-term debt.................................................... 248,247 193,150 Principal payments of long-term debt............................................. (512,989) (1,061,200) Principal payments of short-term debt............................................ (301,882) (98,345) Costs incurred in connection with financing arrangements......................... (654) (7,972) Proceeds from issuance of units.................................................. -- 106,209 Distributions to unitholders and general partners................................ (47,041) (33,096) --------- ----------- Net cash provided by (used in) financing activities....................... (65,570) 213,526 --------- ----------- Effect of translation adjustment on cash......................................... 132 -- Net increase (decrease) in cash and cash equivalents............................. 2,281 (2,372) Cash and cash equivalents, beginning of period................................... 3,511 3,426 --------- ----------- Cash and cash equivalents, end of period......................................... $ 5,792 $ 1,054 --------- ----------- </TABLE> See notes to consolidated financial statements. 5
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL (in thousands) <TABLE> <CAPTION> Class B Common Units Common Units Subordinated Units General Total --------------- ------------- ----------------- Partner Partners' Units Amount Units Amount Units Amount Amount Amount ------ -------- ----- ------- ------ -------- ------- --------- (unaudited) <S> <C> <C> <C> <C> <C> <C> <C> <C> Balance at December 31, 2001 31,916 $408,562 1,307 $19,534 10,030 $(38,891) $13,592 $402,797 Distributions............... -- (33,113) -- (1,356) -- (10,406) (2,166) (47,041) Other comprehensive income.. -- 7,594 -- 311 -- 2,385 658 10,948 Net income.................. -- 21,664 -- 887 -- 6,805 1,876 31,232 ------ -------- ----- ------- ------ -------- ------- -------- Balance at June 30, 2002.... 31,916 $404,707 1,307 $19,376 10,030 $(40,107) $13,960 $397,936 ====== ======== ===== ======= ====== ======== ======= ======== </TABLE> See notes to consolidated financial statements. 6
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME AND CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (in thousands) Statements of Comprehensive Income <TABLE> <CAPTION> Three Months Ended Six Months Ended June 30, June 30, ----------------- --------------- 2002 2001 2002 2001 ------- ------- ------- ------- (unaudited) <S> <C> <C> <C> <C> Net Income................ $16,951 $ 7,067 $31,232 $20,082 Other comprehensive income 13,899 (3,183) 10,948 (5,838) ------- ------- ------- ------- Total comprehensive income $30,850 $ 3,884 $42,180 $14,244 ======= ======= ======= ======= </TABLE> Statement of Accumulated Other Comprehensive Income <TABLE> <CAPTION> Net deferred loss on Currency derivative translation instruments adjustments Total ----------- ----------- -------- (unaudited) <S> <C> <C> <C> Beginning Balance at December 31, 2001.......................... $(4,740) $(8,002) $(12,742) Current year activity Reclassification adjustments for settled contracts....... 795 -- 795 Changes in fair value of outstanding hedge positions..... 121 -- 121 Currency translation adjustment.......................... -- 10,032 10,032 ------- ------- -------- Total current year activity.................................. 916 10,032 10,948 ------- ------- -------- Ending Balance at June 30, 2002................................. $(3,824) $ 2,030 $ (1,794) ======= ======= ======== </TABLE> See notes to consolidated financial statements. 7
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 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. The terms "Plains All American" and the "Partnership" herein refer to Plains All American Pipeline, L.P. and its affiliated operating partnerships. 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 and liquefied petroleum gas ("LPG"). Our operations are conducted primarily in Texas, California, Oklahoma, Louisiana and the Canadian provinces of Alberta, Saskatchewan and Manitoba. The accompanying financial statements and related notes present our consolidated financial position as of June 30, 2002, and December 31, 2001, the results of our operations for the three and six months ended June 30, 2002 and 2001, cash flows for the six months ended June 30, 2002 and 2001, changes in partners' capital for the six months ended June 30, 2002, total other comprehensive income for the three and six months ended June 30, 2002 and 2001, and accumulated other comprehensive income for the six months ended June 30, 2002. The financial statements have been prepared in accordance with the instructions to 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. When necessary, certain reclassifications are made to prior period amounts to conform to current period presentation. The results of operations for the three and six months ended June 30, 2002, 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 2001 Annual Report on Form 10-K. Note 2--Derivative Instruments and Hedging Activities We utilize various derivative instruments, for purposes other than trading, to hedge our exposure to price fluctuations with respect to crude oil and liquefied petroleum gas in storage and expected purchases, sales and transportation of those commodities. The derivative instruments consist primarily of futures and option contracts traded on the New York Mercantile Exchange and over-the-counter transactions, including crude oil swap contracts entered into with financial institutions and other counterparties. We also utilize interest rate and foreign exchange swaps and collars to manage the interest rate exposure on our long-term debt and foreign exchange exposure arising from our Canadian operations. All of the interest rate and foreign exchange instruments utilized are placed with large creditworthy financial institutions. In accordance with Statement of Financial Accounting Standards ("SFAS") No. 133 "Accounting for Derivative Instruments and Hedging Activities," gains and losses on derivative instruments are deferred to Other Comprehensive Income ("OCI") and are included in revenues in the period that the related volumes are delivered. Gains and losses on hedging instruments, which do not qualify for hedge accounting or which represent hedge ineffectiveness and changes in the time value component of the fair value, are included in earnings in the current period. The June 30, 2002, balance sheet includes a $3.8 million unrealized loss in OCI and related assets and liabilities of $6.7 million ($5.8 million current) and $11.5 million ($8.4 million current), respectively. Earnings for the six months ended June 30, 2002, included a noncash loss of $1.7 million related to the ineffective portion of our cash flow hedges, and certain derivative contracts that did not qualify as hedges due to a low correlation between the futures contract and hedged item (a $1.0 million noncash loss net of the reversal of the prior period 8
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) fair value adjustment related to contracts that settled during the current period). Our hedge-related assets and liabilities are included in other current and non-current assets and liabilities in the consolidated balance sheet. As of June 30, 2002, the total amount of deferred net losses on derivative instruments recorded in OCI are expected to be reclassified to earnings during 2002, 2003 and 2004. Of the amounts deferred to OCI, a loss of $1.1 million will be reclassified from OCI to earnings in the next twelve months. Interest rate swaps and collars are used to hedge underlying interest obligations. These instruments hedge interest rates on specific debt issuances and qualify for hedge accounting. The interest rate differential is reflected as an adjustment to interest expense over the life of the instruments. At June 30, 2002, we had interest rate swap and collar arrangements for an aggregate notional principal amount of $275.0 million. These instruments are based on LIBOR rates. The collar provides for a floor of 6.1% and a ceiling of 8.0% with an expiration date of August 19, 2002, for a $125.0 million notional principal amount. The fixed rate swaps provide for a rate of 3.6% for a $100.0 million notional principal amount expiring September 2003, and a rate of 4.3% for a $50.0 million notional principal amount expiring March 2004. Because substantially all of our Canadian business is conducted in Canadian dollars (CAD), we use certain financial instruments to minimize the risks of changes in the exchange rate. These instruments include forward exchange contracts, forward extra option contracts and cross currency swaps. At June 30, 2002, we had forward exchange contracts and forward extra option contracts that allow us to exchange $3.0 million Canadian for at least $1.9 million U. S. quarterly during 2002 and 2003 (based on a Canadian-U.S. dollar exchange rate of 1.54). At June 30, 2002, we also had a cross currency swap contract for an aggregate notional principal amount of $24.8 million, effectively converting this amount of our $99.0 million senior secured term loan (25% of the total) from U.S. dollars to $38.3 million of Canadian dollar debt (based on a Canadian-U.S. dollar exchange rate of 1.55). The terms of this contract mirror the term loan, matching the amortization schedule and final maturity in May 2006. Additionally, at June 30, 2002, $13.2 million of our long-term debt was denominated in Canadian dollars ($20.0 million CAD based on a Canadian-U.S. dollar exchange rate of 1.52). 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 hedged 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. Note 3--Acquisitions Shell's West Texas Interests In May 2002, we entered into a definitive purchase and sale agreement to purchase certain businesses from Shell Pipeline Company, including its interests in the Basin Pipeline System, the Rancho Pipeline System and the Permian Basin Gathering System, for approximately $315.0 million, excluding financing and related transaction costs. At execution, we deposited $15.7 million into an escrow account. This transaction was consummated on August 1, 2002, using proceeds from our revolving credit facilities. Net of interest earned on the deposit, approximately $9.1 million related to the settlement of pre-existing accounts receivable and inventory balances and purchase price adjustments as provided for in the amended purchase and sale agreement, the final amount paid to Shell at closing totaled approximately $288.2 million cash. Including approximately $9.6 million of estimated transaction and closing costs, the total purchase price is approximately $322.7 million. 9
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Coast/Lantern Acquisition In March 2002, we completed the acquisition of substantially all of the domestic crude oil pipeline, gathering, and marketing assets of Coast Energy Group and Lantern Petroleum, divisions of Cornerstone Propane Partners, L.P., for approximately $7.6 million in cash, including the deposit of $2.5 million made in December 2001, net of liabilities assumed and including transaction costs. The principal assets acquired, which are located in West Texas, include several gathering lines, crude oil contracts and a small truck and trailer fleet. This acquisition did not have a material effect on either our financial position, results of operations or cash flows. Butte Acquisition In February 2002, we acquired an approximate 22% equity interest in Butte Pipe Line Company from Murphy Ventures, a subsidiary of Murphy Oil Corporation. The total cost of the acquisition, including various transaction and related expenses, was approximately $8.0 million. Butte Pipe Line Company owns the 373-mile Butte Pipeline System that runs from Baker, Montana, to Guernsey, Wyoming. The remaining 78% interest in the Butte Pipe Line Company is owned by Equilon Pipeline Company LLC. This acquisition did not have a material effect on either our financial position, results of operations or cash flows. Note 4--Credit Agreements As amended, our credit facilities consist of a $350.0 million senior secured letter of credit and hedged inventory facility (with current lender commitments totaling $200.0 million), and a $779.0 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 $99.0 million term loan, and a $200.0 million term B loan. The facilities have final maturities as follows: . as to the $350.0 million senior secured letter of credit and hedged inventory facility, in April 2005; . as to the aggregate $480.0 million domestic and Canadian revolver portions, in April 2005; . as to the $99.0 million term loan, in May 2006; and . as to the $200.0 million term B loan, in September 2007. In July 2002, we amended our credit facilities to enable us to consummate the pending acquisition of certain businesses from Shell Pipeline Company and to accommodate the increased activity level associated with the expanded asset base, while preserving our ability to pursue additional acquisitions. The amended facilities enable us to expand the size of the letter of credit and hedged inventory facility from $200.0 million to $350.0 million without additional approval from existing lenders. As amended, the financial covenants require us to maintain: . a current ratio (as defined) of at least 1.0 to 1.0; . a debt coverage ratio which will not be greater than: (i) 5.0 to 1.0 through and including March 30, 2003, and 4.0 to 1.0 thereafter; and (ii) 5.25 to 1.0 on and after our issuing at least $150.0 million of unsecured debt and, in addition, our secured debt coverage ratio will not be greater than 4.0 to 1.0; . an interest coverage ratio that is not less than 2.75 to 1.0; and . a debt to capital ratio of not greater than 0.7 to 1.0 through March 30, 2003, and .65 to 1.0 at any time thereafter. For covenant compliance purposes, letters of credit and borrowings under the letter of credit and hedged inventory facility are excluded when calculating the debt coverage ratio. 10
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) The amended facility also permits us to issue up to $400 million of unsecured debt having a maturity beyond the final maturity of the existing credit facility. Upon the issuance of unsecured debt, the amount of the $450 million domestic revolving facility is reduced by an amount equal to the following: i) 40% of the face amount of the unsecured debt issued if the face amount is less than $350 million, less $50 million, or ii) 50% of the face amount of the unsecured debt issued if the face amount is equal to or greater than $350 million, less $50 million. In anticipation of a potential issuance of senior unsecured notes during the third quarter, we entered into a sixty day treasury lock on a $100 million principal amount with a base index rate of 4.37% and an all in basis at maturity of 4.47%. Note 5--Distributions On July 23, 2002, we declared a cash distribution of $0.5375 per unit on our outstanding common units, Class B common units and subordinated units. The distribution is payable on August 14, 2002, to unitholders of record on August 5, 2002, for the period April 1, 2002, through June 30, 2002. The total distribution to be paid is approximately $24.6 million, with approximately $17.8 million to be paid to our common unitholders, $5.4 million to be paid to our subordinated unitholders and $1.4 million to be paid to our general partner for its general partner and incentive distribution interests. The distribution is in excess of the minimum quarterly distribution specified in the Partnership Agreement. On May 15, 2002, we paid a cash distribution of $0.525 per unit on our outstanding common units, Class B common units and subordinated units. The distribution was paid to unitholders of record on May 6, 2002, for the period January 1, 2002, through March 31, 2002. The total distribution paid was approximately $23.9 million, with approximately $17.4 million paid to our common unitholders, $5.3 million paid to our subordinated unitholders and $1.2 million paid to our general partner for its general partner and incentive distribution interests. The distribution was in excess of the minimum quarterly distribution specified in the Partnership Agreement. Note 6--Recent Disruptions in Industry Credit Markets As a result of business failures, revelations of material misrepresentations and related financial restatements by several large, well-known companies in various industries over the last nine months, there have been significant disruptions and extreme volatility in the financial markets and credit markets. Because of the credit intensive nature of the energy industry and troubling disclosures by several large, diversified energy companies, the energy industry has been especially impacted by these developments, with the rating agencies downgrading a number of large, energy related companies. Accordingly, in this environment we are exposed to an increased level of direct and indirect counter-party credit and performance risk. The majority of our credit extensions and therefore our accounts receivable relate to our gathering and marketing activities that can generally be described as high volume and low margin activities, in many cases involving complex exchanges of crude oil volumes. In transacting business with our counter-parties, we must determine the amount, if any, of open credit lines to extend to our counter-parties and the form and amount of financial performance assurances we may require. The vast majority of such accounts receivable settle monthly and any collection delays generally involve discrepancies or disputes as to the appropriate price, volumes or quality of crude oil delivered or exchanged and associated billing delays. Of our $358 million aggregate receivables balance included in current assets at December 31, 2001, approximately $331 million, or 93%, were less than 60 days past the scheduled invoice date. Of our $499 million aggregate receivables balance included in current assets at June 30, 2002, approximately $489 million, or 98%, were less than 60 days past the scheduled invoice date. We have modified our credit arrangements with certain counter-parties that have been adversely affected by these recent events, but a large portion of the balances more than 60 days past the invoice date, along with 11
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) approximately $10.8 million of net receivables classified as long-term, are associated with an ongoing effort to bring substantially all balances to within sixty days of scheduled invoice date. In certain cases, this effort involves reconciling and resolving certain discrepancies, generally related to pricing, volumes, quality or crude oil exchange imbalances and the majority of these receivables are related to the period immediately following the disclosure of our unauthorized trading losses in late 1999. Following that disclosure, a significant number of our suppliers and trading partners temporarily reduced or eliminated our open credit and demanded payments or withheld payments due us before disputed amounts or discrepancies associated with exchange imbalances, pricing issues and quality adjustments were reconciled in accordance with customary industry practices. Because these matters also arose in the midst of various software systems conversions and acquisition integration activities, our effort to resolve outstanding claims and discrepancies has included reprocessing and integrating historical information on numerous software platforms. We have made significant progress to date in this effort and intend to substantially complete this project in the second half of 2002 and, based on the work performed to date and the scope of the remaining work to be performed, we believe these prior period balances are collectible and consider our reserves adequate. However, in the event our counter-parties experience an unanticipated deterioration in their credit-worthiness, any addition to existing reserves or write-offs in excess of such reserves would result in a noncash charge to earnings. We do not believe any such charge would have a material effect on our cash flow or liquidity. Note 7--Operating Segments Our operations consist of two operating segments: (1) Pipeline Operations--engages in interstate and intrastate crude oil pipeline transportation and certain related merchant activities; (2) Gathering, Marketing, Terminalling and Storage Operations--engages in purchases and resales of crude oil and LPG at various points along the distribution chain and the operation of certain terminalling and storage assets. We evaluate segment performance based on gross margin and gross profit. <TABLE> <CAPTION> Gathering, Marketing, Terminalling Pipeline & Storage Total -------- ------------ ---------- (in thousands) (unaudited) <S> <C> <C> <C> Three Months Ended June 30, 2002 Revenues: External Customers.......................... $111,471 $1,873,876 $1,985,347 Intersegment (a)............................ 3,687 -- 3,687 -------- ---------- ---------- Total revenues of reportable segments.... $115,158 $1,873,876 $1,989,034 ======== ========== ========== Segment gross margin (b)....................... $ 18,831 $ 22,876 $ 41,707 General and administrative expense............. (1,146) (9,973) (11,119) -------- ---------- ---------- Segment gross profit (c)....................... $ 17,685 $ 12,903 $ 30,588 ======== ========== ========== Maintenance capital............................ $ 850 $ 112 $ 962 - ---------------------------------------------------------------------------------- </TABLE> (Table continued on following page) 12
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) <TABLE> <CAPTION> Gathering, Marketing, Terminalling Pipeline & Storage Total -------- ------------ ---------- (in thousands) (unaudited) <S> <C> <C> <C> Three Months Ended June 30, 2001 Revenues: External Customers.......................... $ 91,815 $1,494,802 $1,586,617 Intersegment (a)............................ 5,166 -- 5,166 -------- ---------- ---------- Total revenues of reportable segments.... $ 96,981 $1,494,802 $1,591,783 ======== ========== ========== Segment gross margin (b)....................... $ 18,699 $ 17,688 $ 36,387 General and administrative expense............. (1,031) (8,390) (9,421) -------- ---------- ---------- Segment gross profit (c)....................... $ 17,668 $ 9,298 $ 26,966 ======== ========== ========== Maintenance capital............................ $ -- $ 1,879 $ 1,879 - ---------------------------------------------------------------------------------- Six Months Ended June 30, 2002 Revenues: External Customers.......................... $196,804 $3,333,866 $3,530,670 Intersegment (a)............................ 6,826 -- 6,826 -------- ---------- ---------- Total revenues of reportable segments.... $203,630 $3,333,866 $3,537,496 ======== ========== ========== Segment gross margin (b)....................... $ 37,285 $ 42,810 $ 80,095 General and administrative expense............. (2,089) (19,788) (21,877) -------- ---------- ---------- Segment gross profit (c)....................... $ 35,196 $ 23,022 $ 58,218 ======== ========== ========== Maintenance capital............................ $ 2,220 $ 615 $ 2,835 - ---------------------------------------------------------------------------------- Six Months Ended June 30, 2001 Revenues: External Customers.......................... $179,853 $2,926,888 $3,106,741 Intersegment (a)............................ 8,475 -- 8,475 -------- ---------- ---------- Total revenues of reportable segments.... $188,328 $2,926,888 $3,115,216 ======== ========== ========== Segment gross margin (b)....................... $ 32,591 $ 36,526 $ 69,117 General and administrative expense............. (1,491) (16,798) (18,289) -------- ---------- ---------- Segment gross profit (c)....................... $ 31,100 $ 19,728 $ 50,828 ======== ========== ========== Maintenance capital............................ $ 104 $ 2,184 $ 2,288 </TABLE> - -------- a) Intersegment sales were conducted on terms believed to be consistent with terms that would have been extended 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 gross margin less general and administrative expenses, excluding noncash compensation expense as it is not allocated to the reportable segments. 13
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Note 8--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 and do not expect any additional expenditure to be material, 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 to determine the extent of the contamination. We have proposed extending the scope of our study and are awaiting the state's response. We have spent approximately $140,000 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. 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. Litigation 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 our former general partner, its directors and certain of its officers as defendants, and alleged 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. We reached an agreement in principle with the plaintiffs to settle the Delaware litigation for approximately $1.1 million. On March 6, 2002, the Delaware court approved the settlement. The order became final in April of 2002 and the settlement amount has been paid. 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 our former general partner, its directors and certain of its officers as defendants. This lawsuit contained the same claims and sought the same relief as the Delaware derivative litigation, described above. We reached an agreement in principle with the plaintiffs to settle the Texas litigation for approximately $112,500. The court approved the settlement on March 18, 2002. The order became final in April of 2002 and the settlement amount has been paid. Other. We, in the ordinary course of business, are a claimant and/or a defendant in various other legal proceedings. We do 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. Note 9--Recent Accounting Pronouncements In June 2002, the Financial Accounting Standards Board ("FASB") issued SFAS No. 146 "Accounting for Costs Associated with Exit or Disposal Activities". SFAS 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred rather than at the date of the exit plan. 14
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) This Statement is effective for exit or disposal activities that are initiated after December 31, 2002. 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 May 2002, the FASB issued SFAS 145 "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections as of April 2002". SFAS 145 amends the treatment of gains and losses from the extinquishment of debt only allowing those items that are truly unusual and infrequent. The statement is effective for all transactions occurring after May 15, 2002. Effective with fiscal years beginning after May 15, 2002, any gain or loss on extinguishment of debt that was classified as an extraordinary item in prior periods presented that does not meet the criteria for classification as an extraordinary item shall be reclassified. We do not believe that the adoption of SFAS 145 will have a material effect on either our financial position or cash flows, however, future extinguishments of debt may impact income from continuing operations. 15
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Overview We are a Delaware limited partnership 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. The terms "Plains All American" and the "Partnership" herein refer to Plains All American Pipeline, L.P. and its affiliated operating partnerships. 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 and liquefied petroleum gas. Our operations are conducted primarily in Texas, California, Oklahoma, Louisiana and the Canadian provinces of Alberta, Saskatchewan and Manitoba and consist of two operating segments: (1) Pipeline Operations and (2) Gathering, Marketing, Terminalling and Storage Operations. We evaluate segment performance based on gross margin and gross profit. Pipeline Operations. Our activities from pipeline operations generally consist of transporting third-party volumes of crude oil for a fee, third party leases of pipeline capacity, barrel exchanges and buy/sell arrangements. We also utilize our pipelines in our merchant activities conducted under our gathering and marketing business. Tariffs and other fees on our pipeline systems vary by receipt point and delivery point. The gross margin 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 costs of operating the pipeline. Gross margin from our pipeline capacity leases, barrel exchanges and buy/sell arrangements generally reflect a negotiated amount. Gathering, Marketing, Terminalling and Storage Operations. 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 margin businesses, and 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. Accordingly, an increase in revenues is not necessarily an indication of a fundamental direction of the segment's activities. 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". Gross margin from terminalling and storage activities is dependent on the throughput volumes, the volume of crude oil stored and the level of fees generated from our terminalling and storage services. Results of Operations The following acquisitions impact the comparability of the 2002 and 2001 periods as noted in the discussion of the results of operations. In 2001, we acquired substantially all of the Canadian crude oil pipeline, gathering, marketing, terminalling and storage assets of Murphy Oil Company Ltd. and the assets of CANPET Energy Group Inc. ("CANPET"), a Calgary-based Canadian crude oil and liquefied petroleum gas marketing company, together the "Canadian acquisitions". The acquisitions were effective April 1, 2001, and July 1, 2001, respectively. Three Months Ended June 30, 2002 and 2001 For the three months ended June 30, 2002, we reported net income of $17.0 million on total revenues of $1.99 billion compared to net income for the same period in 2001 of $7.1 million on total revenues of $1.59 billion. When evaluating net income, we exclude the impact of Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities," resulting from derivative instruments that do not qualify for hedge accounting or which represent hedge ineffectiveness. The majority of 16
these instruments serve as economic hedges which offset future physical positions not reflected in current results. Therefore, the SFAS 133 adjustment to net income is not a complete depiction of the economic substance of the transaction as it only represents the derivative side of these transactions and does not take into account the offsetting physical position. In addition, the impact will vary from quarter to quarter based on market prices at the end of the quarter. The following table reconciles our reported net income to our net income before unusual or nonrecurring items and the impact of SFAS 133: <TABLE> <CAPTION> Three Months Ended June 30, ------------ 2002 2001 ----- ----- (millions) <S> <C> <C> Reported net income.............................................. $17.0 $ 7.1 Noncash compensation expense..................................... -- 5.6 Noncash SFAS 133 gain............................................ (1.1) (0.2) ----- ----- Net income before unusual or nonrecurring items and the impact of SFAS 133 (1)................................................... $15.8 $12.5 ===== ===== </TABLE> - -------- (1) Numbers in table may not sum exactly due to rounding. The following table sets forth our operating results for the periods indicated and includes the impact of the items discussed above: <TABLE> <CAPTION> Three Months Ended June 30, ------------------ 2002 2001 -------- -------- <S> <C> <C> Operating Results (in millions): Revenues................................................... $1,985.3 $1,586.6 ======== ======== Gross margin: Pipeline................................................. 18.8 18.7 Gathering, marketing, terminalling and storage........... 22.9 17.7 -------- -------- Total................................................ 41.7 36.4 General and administrative expense......................... (11.1) (15.1) -------- -------- Gross profit............................................... $ 30.6 $ 21.3 ======== ======== Net income................................................. $ 17.0 $ 7.1 ======== ======== Average Daily Volumes (thousands of barrels per day): Pipeline segment: Tariff activities All American........................................... 61 68 Other domestic......................................... 151 152 Canada (1)............................................. 182 161 Margin activities........................................ 73 56 -------- -------- Total................................................ 467 437 ======== ======== Gathering, marketing, terminalling and storage segment: Lease gathering.......................................... 410 322 Bulk purchases........................................... 65 17 -------- -------- Total................................................ 475 339 ======== ======== Terminal throughput (1).................................. 84 114 ======== ======== Storage leased to third parties, monthly average volumes. 1,620 2,427 ======== ======== </TABLE> - -------- (1) 2001 volume information is adjusted for consistency of comparison with 2002 presentation. 17
Revenues. Total revenues were $1.99 billion and $1.59 billion for the three months ended June 30, 2002 and 2001, respectively. The increase is primarily associated with higher gathering volumes primarily attributable to the acquisition of the assets of CANPET in July of 2001. The average NYMEX price for crude oil was $26.24 per barrel and $27.98 per barrel for the second quarter of 2002 and 2001, respectively. For the three months ended June 30, 2002, we gathered from producers, using our assets or third-party assets, approximately 410,000 barrels of crude oil per day. In addition, we purchased in bulk, primarily at major trading locations, approximately 65,000 barrels of crude oil per day. Our revenues reflect the sale of these barrels plus the sale of additional barrels exchanged through buy/sell arrangements entered into to enhance the margins of the gathered and bulk-purchased crude oil. Cost of Sales and Operations. Cost of sales and operations were $1.94 billion and $1.55 billion in the second quarter of 2002 and 2001, respectively, an increase of $0.39 million primarily due to the reasons discussed above with respect to revenues. General and Administrative. General and administrative expense ("G&A") was $11.1 million for the quarter ended June 30, 2002, compared to $15.1 million for the second quarter of 2001. Excluding the noncash compensation expense of $5.6 million related to the vesting of phantom units, G&A for the second quarter of 2001 would have been $9.4 million. The increase in 2002 is primarily due to $2.5 million of expenses associated with our Canadian acquisitions, partially offset by a decrease in other G&A expenses related to the domestic operations. Depreciation and Amortization. Depreciation and amortization expense was $7.2 million for the quarter ended June 30, 2002, compared to $6.5 million for the same period of 2001. The increase is primarily due to assets acquired and other capital expansion projects. Interest Expense. Interest expense decreased to $6.4 million for the quarter ended June 30, 2002, from $8.1 million for the comparative 2001 period. The decrease is due to the capitalization of $0.4 million of interest and lower interest rates somewhat offset by a higher average debt balance and increased commitment fees in the second quarter of 2002. Segment Results Pipeline Operations. Gross margin from pipeline operations increased to $18.8 million for the quarter ended June 30, 2002, from $18.7 million for the prior year quarter. Although total volumes increased, volumes transported from Outer Continental Shelf ("OCS") production, which are our highest margin barrels, declined. Therefore, gross margin did not increase in proportion to the increase in volumes. Average daily volumes on our pipelines during the second quarter of this year were 467,000 barrels per day compared to 437,000 barrels per day last year. Approximately 20,000 barrels per day of the increase is due to increased volumes on our Canadian pipelines, 10,000 barrels per day of which are due to the acquisition of the Wapella Pipeline in December 2001. The remainder of the increase was primarily related to volumes on the Butte Pipeline System acquired in February 2002, which were somewhat offset by a decrease in OCS volumes. Gathering, Marketing, Terminalling and Storage Operations. Gross margin from gathering, marketing, terminalling and storage activities was approximately $22.9 million for the quarter ended June 30, 2002, compared to $17.7 million in the prior year quarter. Excluding the impact of the noncash fair value adjustments related to SFAS 133, gross margin for this segment would have been approximately $21.8 million for the quarter ended June 30, 2002, compared to $17.5 million in the prior year quarter. The increase was primarily related to our Canadian acquisitions. Lease gathering volumes increased to approximately 410,000 barrels per day in 2002 from an average of 322,000 barrels per day for the second quarter of 2001, mostly due to our Canadian acquisitions. Bulk purchase volumes increased to approximately 65,000 barrels per day in the current period from approximately 17,000 barrels per day for the second quarter of 2001. Lease capacity decreased to an average of 1.6 million barrels per 18
month from an average of 2.4 million barrels per month in the prior year quarter and terminal throughput averaged approximately 84,000 barrels per day and 114,000 barrels per day in the second quarter of 2002 and 2001, respectively. Both the third party lease volumes and terminal throughput volumes are lower because we used more of our storage capacity for our contango activities during this year's quarter. Six Months Ended June 30, 2002 and 2001 For the six months ended June 30, 2002, we reported net income of $31.2 million on total revenues of $3.53 billion compared to net income for the same period in 2001 of $20.1 million on total revenues of $3.11 billion. When evaluating net income, we exclude the impact of SFAS 133 resulting from hedging instruments that do not qualify for hedge accounting or which represent hedge ineffectiveness. The majority of these instruments serve as economic hedges which offset future physical positions not reflected in current results. Therefore, the SFAS 133 adjustment to net income is not a complete depiction of the economic substance of the transaction as it only represents the derivative side of these transactions and does not take into account the offsetting physical position. In addition, the impact will vary from quarter to quarter based on market prices at the end of the quarter. The following table reconciles our reported net income to our net income before unusual or nonrecurring items and the impact of SFAS 133: <TABLE> <CAPTION> Six Months Ended June 30, ------------- 2002 2001 ----- ----- (millions) <S> <C> <C> Reported net income.............................................. $31.2 $20.1 Noncash compensation expense..................................... -- 5.7 Noncash cumulative effect of accounting change (1)............... -- (0.5) Noncash SFAS 133 (gain) loss..................................... 1.7 (0.1) ----- ----- Net income before unusual or nonrecurring items and the impact of SFAS 133 (2)................................................... $33.0 $25.2 ===== ===== </TABLE> - -------- (1) Related to the adoption of SFAS 133 on January 1, 2001. (2) Numbers in table may not sum exactly due to rounding. 19
The following table sets forth our operating results for the periods indicated and includes the impact of the items discussed above: <TABLE> <CAPTION> Six Months Ended June 30, ------------------ 2002 2001 -------- -------- <S> <C> <C> Operating Results (in millions): Revenues................................................ $3,530.7 $3,106.7 ======== ======== Gross margin: Pipeline.............................................. $ 37.3 $ 32.6 Gathering, marketing, terminalling and storage........ 42.8 36.5 -------- -------- Total............................................. 80.1 69.1 General and administrative expense...................... (21.9) (24.0) -------- -------- Gross profit............................................ $ 58.2 $ 45.1 ======== ======== Net income.............................................. $ 31.2 $ 20.1 ======== ======== Average Daily Volumes (thousands of barrels per day): Pipeline segment: Tariff activities All American........................................ 64 69 Other domestic...................................... 152 157 Canada (1).......................................... 178 161 Margin activities..................................... 72 61 -------- -------- Total............................................. 466 448 ======== ======== Gathering, marketing, terminalling and storage segment: Lease gathering....................................... 405 324 Bulk purchases........................................ 67 19 -------- -------- Total............................................. 472 343 ======== ======== Terminal throughput (1)................................. 76 105 ======== ======== Storage leased to third parties, monthly average volumes 1,583 2,165 ======== ======== </TABLE> - -------- (1) 2001 volume information is adjusted for consistency of comparison with 2002 presentation. Revenues. Total revenues were $3.53 billion and $3.11 billion for the six months ended June 30, 2002 and 2001, respectively. Excluding the impact of our Canadian acquisitions, total revenues for the first half of 2002 would have been $2.80 billion compared to $2.98 billion for the first half of 2001. The decrease is primarily attributable to the decrease in the average NYMEX price for crude oil to $23.95 per barrel for the first half of 2002 from $28.40 per barrel for the first half of 2001. For the six months ended June 30, 2002, we gathered from producers, using our assets or third-party assets, approximately 405,000 barrels of crude oil per day. In addition, we purchased in bulk, primarily at major trading locations, approximately 67,000 barrels of crude oil per day. Our revenues reflect the sale of these barrels plus the sale of additional barrels exchanged through buy/sell arrangements entered into to enhance the margins of the gathered and bulk-purchased crude oil. Cost of Sales and Operations. Cost of sales and operations were $3.45 billion and $3.04 billion in the first half of 2002 and 2001, respectively, a decrease of $0.41 million primarily due to the reasons discussed above with respect to revenues. General and Administrative. General and administrative expense was $21.9 million for the six months ended June 30, 2002, compared to $24.0 million for the first half of 2001. Excluding the noncash compensation expense of $5.7 million related to the vesting of phantom units, G&A for the six months ended June 30, 2001, would have been $18.3 million. Excluding this expense, the resulting increase in 2002 is primarily due to $4.8 million of expenses associated with our Canadian acquisitions, offset by a decrease in other G&A expenses related to the domestic operations. 20
Depreciation and Amortization. Depreciation and amortization expense was $14.1 million for the six months ended June 30, 2002, compared to $11.2 million for the same period of 2001. Approximately $2.4 million of the increase is attributable to our Canadian acquisitions and the remainder is due to other assets acquired and other capital expansion projects. Interest Expense. Interest expense decreased to $12.8 million for the six months ended June 30, 2002, from $14.7 million for the comparative 2001 period. The decrease is due to the capitalization of interest of $0.5 million and lower interest rates somewhat offset by a higher average debt balance and increased commitment fees in the first half of 2002. Segment Results Pipeline Operations. Gross margin from pipeline operations increased to $37.3 million for the six months ended June 30, 2002, from $32.6 million for the same period in 2001. The increase resulted primarily from the impact of our Canadian acquisitions. Average daily volumes on our pipelines during the first six months of this year were 466,000 barrels per day compared to 448,000 barrels per day last year. Approximately 10,000 barrels per day of the increase is due to our acquisition of the Wapella pipeline in December of 2001. Gathering, Marketing, Terminalling and Storage Activities. Gross margin from gathering, marketing, terminalling and storage activities was approximately $42.8 million for the six months ended June 30, 2002, compared to $36.5 million for the same period in 2001. Excluding the impact of the noncash fair value adjustments related to SFAS 133, gross margin for this segment would have been $44.5 million for the six months ended June 30, 2002, compared to $36.5 million in the prior year period. The increase was primarily related to our Canadian acquisitions partially offset by the weaker margins from our gathering and marketing activities as a result of the existence of a contango market. Lease gathering volumes increased to approximately 405,000 barrels per day in 2002 from an average of 324,000 barrels per day for the first six months of 2001, mostly due to our Canadian acquisitions. Bulk purchase volumes increased to approximately 67,000 barrels per day in the current period from approximately 19,000 barrels per day for the first six months of 2001. Lease capacity decreased to an average of 1.6 million barrels per month from an average of 2.2 million barrels per month in the prior year period and terminal throughput averaged approximately 76,000 barrels per day and 105,000 barrels per day in the first six months of 2002 and 2001, respectively. Both the third party lease volumes and terminal throughput volumes are lower because we used more of our storage capacity for contango activities during this year's period. Liquidity and Capital Resources Recent Events Acquisition of Shell's West Texas Interests. In May 2002, we entered into a definitive purchase and sale agreement to purchase certain businesses from Shell Pipeline Company, including its interests in the Basin Pipeline System, the Rancho Pipeline System and the Permian Basin Gathering System, for approximately $315.0 million, excluding financing and related transaction costs. At execution, we deposited $15.7 million into an escrow account. This transaction was consummated on August 1, 2002, using proceeds from our revolving credit facilities. Net of interest earned on the deposit, approximately $9.1 million related to the settlement of pre-existing accounts receivable and inventory balances and purchase price adjustments as provided for in the amended purchase and sale agreement, the final amount paid to Shell at closing totaled approximately $288.2 million cash. Including approximately $9.6 million of estimated transaction and closing costs, the total purchase price is approximately $322.7 million. FERC Notice of Proposed Rulemaking. On August 1, 2002, the Federal Energy Regulatory Commission ("FERC") issued a Notice of Proposed Rulemaking that, if adopted, would amend its Uniform Systems of Accounts for public utilities, natural gas companies and oil pipeline companies by requiring specific written 21
documentation concerning the management of funds from a FERC-regulated subsidiary by a non-FERC- regulated parent. Under the proposed rule, as a condition for participating in a cash management or money pool arrangement, the FERC-regulated entity would be required to maintain a minimum proprietary capital balance (stockholder's equity) of 30 percent, and the FERC regulated entity and its parent would be required to maintain investment grade credit ratings. If either of these conditions is not met, the FERC-regulated entity would not be eligible to participate in the cash management or money pool arrangement. This proposed rule is subject to a comment period of 15 days after its publication in the Federal Register. We do not know when or if the rule will be enacted. Although it appears that, if enacted, the rule may affect the way in which we manage cash, we are unable to predict the full impact of this proposed regulation on our business. Liquidity Cash generated from operations and our credit facilities are our primary sources of liquidity. At June 30, 2002, we had working capital of approximately $33.4 million, approximately $388.4 million of availability under our revolving credit facility and $124.6 million under the letter of credit and hedged inventory facility. Including the effect of the borrowings to fund the Shell acquisition the amount available under our revolving credit facility at June 30, 2002, would have been approximately $100.2 million. 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. However, we are subject to business and operational risks that could adversely effect our cash flow. A material decrease in our cash flows would likely produce a corollary adverse effect on our borrowing capacity. Recent Disruptions in Industry Credit Markets. As a result of business failures, revelations of material misrepresentations and related financial restatements by several large, well-known companies in various industries over the last nine months, there have been significant disruptions and extreme volatility in the financial markets and credit markets. Because of the credit intensive nature of the energy industry and troubling disclosures by several large, diversified energy companies, the energy industry has been especially impacted by these developments, with the rating agencies downgrading a number of large, energy related companies. Accordingly, in this environment we are exposed to an increased level of direct and indirect counter-party credit and performance risk. The majority of our credit extensions and therefore our accounts receivable relate to our gathering and marketing activities that can generally be described as high volume and low margin activities, in many cases involving complex exchanges of crude oil volumes. In transacting business with our counter-parties, we must determine the amount, if any, of open credit lines to extend to our counter-parties and the form and amount of financial performance assurances we may require. The vast majority of such accounts receivable settle monthly and any collection delays generally involve discrepancies or disputes as to the appropriate price, volumes or quality of crude oil delivered or exchanged and associated billing delays. Of our $358 million aggregate receivables balance included in current assets at December 31, 2001, approximately $331 million, or 93%, were less than 60 days past the scheduled invoice date. Of our $499 million aggregate receivables balance included in current assets at June 30, 2002, approximately $489 million, or 98%, were less than 60 days past the scheduled invoice date. We have modified our credit arrangements with certain counter-parties that have been adversely affected by these recent events, but a large portion of the balances more than 60 days past the invoice date, along with approximately $10.8 million of net receivables classified as long-term, are associated with an ongoing effort to bring substantially all balances to within sixty days of scheduled invoice date. In certain cases, this effort involves reconciling and resolving certain discrepancies, generally related to pricing, volumes, quality or crude oil exchange imbalances and the majority of these receivables are related to the period immediately following the disclosure of our unauthorized trading losses in late 1999. Following that disclosure, a significant number of our suppliers and trading partners temporarily reduced or eliminated our open credit and demanded payments or 22
withheld payments due us before disputed amounts or discrepancies associated with exchange imbalances, pricing issues and quality adjustments were reconciled in accordance with customary industry practices. Because these matters also arose in the midst of various software systems conversions and acquisition integration activities, our effort to resolve outstanding claims and discrepancies has included reprocessing and integrating historical information on numerous software platforms. We have made significant progress to date in this effort and intend to substantially complete this project in the second half of 2002 and, based on the work performed to date and the scope of the remaining work to be performed, we believe these prior period balances are collectible and consider our reserves adequate. However, in the event our counter-parties that experience an unanticipated deterioration in their credit-worthiness, any addition to existing reserves or write-offs in excess of such reserves would result in a noncash charge to earnings. We do not believe any such charge would have a material effect on our cash flow or liquidity. To date, these market disruptions have not had a material adverse impact on our activities or on obtaining open credit for our own account with counter-parties. During 2001, we received upgrades from the two rating agencies that cover the Partnership. We are currently rated BB+ by Standard & Poor's and on June 27, 2002, we were placed on CreditWatch with positive implications. We are currently rated Ba2 by Moody's Investor Services with a positive outlook. Acquisition Activity. Consistent with our acquisition strategy, we are continuously engaged in discussions with potential sellers regarding the possible purchase by us of midstream crude oil assets. Such acquisition efforts involve participation by us in processes that have been made public, involve a number of potential buyers and are commonly referred to as "auction" processes, as well as situations in which we believe we are the only party or one of a very limited number of potential buyers in negotiations with the potential seller. Since 1998, we have completed 12 acquisitions for an aggregate purchase price of $1.1 billion. We can give you 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. Cash Flows <TABLE> <CAPTION> Six Months Ended June 30, - -------------- 2002 2001 ------ ------ (in millions) <S> <C> <C> Cash provided by (used in): Operating activities.... $117.9 $(47.0) Investing activities.... $(50.1) $(168.9) Financing activities.... $(65.6) $213.5 </TABLE> Operating Activities. Net cash provided by operating activities for the six months ended June 30, 2002, was $117.9 million primarily due to the sale of crude oil inventory related to contango activities. Investing Activities. Net cash used in investing activities in 2002 includes the payment of a $15.7 million deposit related to the purchase of certain assets from Shell Pipeline Company, $7.7 million for the Butte acquisition and $5.1 million for the Coast/Lantern acquisition. Investing activities also includes $20.8 million of capital expenditures related to the Cushing expansion, the construction of the Marshall terminal in Canada and other capital projects. Financing Activities. Cash used in financing activities in 2002 consisted primarily of a net repayment of $53.6 million of short-term debt related to contango inventory transactions partially offset by net long-term borrowings of $35.8 million used primarily to fund capital projects and acquisitions including the deposit for the Shell acquisition. In addition, $47.0 million of distributions were paid to unitholders and the general partner during the six months ended June 30, 2002. 23
Universal Shelf We have filed with the Securities and Exchange Commission a universal shelf registration statement that, subject to effectiveness at the time of use, allows us to issue from time to time up to an aggregate of $700 million of debt or equity securities. In October 2001, we sold approximately $130 million of common units under the shelf. Accordingly, as of August 6, 2002, we have the ability to issue approximately $570 million of additional debt or equity securities under this registration statement. Credit Agreements As amended, our credit facilities consist of a $350.0 million senior secured letter of credit and hedged inventory facility (with current lender commitments totaling $200.0 million), and a $779.0 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 $99.0 million term loan, and a $200.0 million term B loan. The facilities have final maturities as follows: . as to the $350.0 million senior secured letter of credit and hedged inventory facility, in April 2005; . as to the aggregate $480.0 million domestic and Canadian revolver portions, in April 2005; . as to the $99.0 million term loan, in May 2006; and . as to the $200.0 million term B loan, in September 2007. In July 2002, we amended our credit facilities to enable us to consummate the pending acquisition of certain businesses from Shell Pipeline Company and to accommodate the increased activity level associated with the expanded asset base, while preserving our ability to pursue additional acquisitions. The amended facilities enable us to expand the size of the letter of credit and hedged inventory facility from $200.0 million to $350.0 million without additional approval from existing lenders. As amended, the financial covenants require us to maintain: . a current ratio (as defined) of at least 1.0 to 1.0; . a debt coverage ratio which will not be greater than: (i) 5.0 to 1.0 through and including March 30, 2003, and 4.0 to 1.0 thereafter; and (ii) 5.25 to 1.0 on and after our issuing at least $150.0 million of unsecured debt and, in addition, our secured debt coverage ratio will not be greater than 4.0 to 1.0; . an interest coverage ratio that is not less than 2.75 to 1.0; and . a debt to capital ratio of not greater than 0.7 to 1.0 through March 30, 2003, and .65 to 1.0 at any time thereafter. For covenant compliance purposes, letters of credit and borrowings under the letter of credit and hedged inventory facility are excluded when calculating the debt coverage ratio. The amended facility also permits us to issue up to $400 million of unsecured debt having a maturity beyond the final maturity of the existing credit facility. Upon the issuance of unsecured debt, the amount of the $450 million domestic revolving facility is reduced by an amount equal to the following: i) 40% of the face amount of the unsecured debt issued if the face amount is less than $350 million, less $50 million, or ii) 50% of the face amount of the unsecured debt issued if the face amount is equal to or greater than $350 million, less $50 million. In anticipation of a potential issuance of senior unsecured notes during the third quarter, we entered into a sixty day treasury lock on $100 million principal amount with a base index rate of 4.37% and an all in basis at maturity of 4.47%. Contingencies 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 24
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. A pipeline, terminal or other facilities 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 all of our assets in amounts considered 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. Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences. The events of September 11 and their overall effect on the insurance industry has had adverse impact on availability and cost of coverage. Due to these events, insurers have excluded acts of terrorism and sabotage from our insurance policies. On certain of our key assets, we purchased a separate insurance policy for acts of terrorism and sabotage. Since the terrorist attacks, the United States Government has issued warnings that energy assets (including our nation's pipeline infrastructure) may be a future target of terrorist organizations. These developments expose our operations and assets to increased risks. Any future terrorist attacks on our facilities, those of our customers and, in some cases, those of our competitors, could have a material adverse effect on our business. The occurrence of a significant event not fully insured or indemnified against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. We believe that we are adequately insured for public liability and property damage to others with respect to our operations. 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. Recent Accounting Pronouncements In June 2002, the Financial Accounting Standards Board ("FASB") issued SFAS No. 146 "Accounting for Costs Associated with Exit or Disposal Activities". SFAS 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the obligation is incurred rather than at the date of the exit plan. This Statement is effective for exit or disposal activities that are initiated after December 31, 2002. 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 May 2002, the FASB issued SFAS 145 "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections as of April 2002". SFAS 145 amends the treatment of gains and losses from the extinquishment of debt only allowing those items that are truly unusual and infrequent. The statement is effective for all transactions occurring after May 15, 2002. Effective with fiscal years beginning after May 15, 2002, any gain or loss on extinguishment of debt that was classified as an extraordinary item in prior periods presented that does not meet the criteria for classification as an extraordinary item shall be reclassified. We do not believe that the adoption of SFAS 145 will have a material effect on either our financial position or cash flows, however, future extinguishments of debt may impact income from continuing operations. 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. 25
Certain factors could cause actual results to differ materially from results anticipated in the forward-looking statements. The 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 the All American Pipeline; . the availability of adequate supplies of and demand for crude oil in the areas in which we operate; . the effects of competition; . the success of our risk management activities; . the availability (or lack thereof) of acquisition or combination opportunities; . successful integration and future performance of acquired assets; . continued creditworthiness and performance by our counterparties, . our ability to receive credit on satisfactory terms; . shortages or cost increases of power supplies, materials or labor; . the impact of current and future laws and governmental regulations; . environmental liabilities that are not covered by an indemnity or insurance; . fluctuations in the debt and equity markets; and . general economic, market or business conditions. Other factors described herein, such as the recent disruption in industry credit markets discussed in Liquidity and Capital Resources and in Note 6 to the financial statements 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. 26
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS We utilize various derivative instruments, for purposes other than trading, to hedge our exposure to price fluctuations with respect to crude oil and liquefied petroleum gas in storage and expected purchases, sales and transportation of those commodities. The derivative instruments consist primarily of futures and option contracts traded on the New York Mercantile Exchange and over-the-counter transactions, including crude oil swap contracts entered into with financial institutions and other counterparties. We also utilize interest rate and foreign exchange swaps and collars to manage the interest rate exposure on our long-term debt and foreign exchange exposure arising from our Canadian operations. All of the interest rate and foreign exchange instruments utilized are placed with large creditworthy financial institutions. In accordance with Statement of Financial Accounting Standards ("SFAS") No. 133 "Accounting for Derivative Instruments and Hedging Activities," gains and losses on derivative instruments are deferred to Other Comprehensive Income ("OCI") and are included in revenues in the period that the related volumes are delivered. Gains and losses on hedging instruments, which do not qualify for hedge accounting or which represent hedge ineffectiveness and changes in the time value component of the fair value, are included in earnings in the current period. The June 30, 2002, balance sheet includes a $3.8 million unrealized loss in OCI and related assets and liabilities of $6.7 million ($5.8 million current) and $11.5 million ($8.4 million current), respectively. Earnings for the six months ended June 30, 2002, included a noncash loss of $1.7 million related to the ineffective portion of our cash flow hedges, and certain derivative contracts that did not qualify as hedges due to a low correlation between the futures contract and hedged item (a $1.0 million noncash loss net of the reversal of the prior period fair value adjustment related to contracts that settled during the current period). Our hedge-related assets and liabilities are included in other current and non-current assets and liabilities in the consolidated balance sheet. As of June 30, 2002, the total amount of deferred net losses on derivative instruments recorded in OCI are expected to be reclassified to earnings during 2002, 2003 and 2004. Of the amounts deferred to OCI, a loss of $1.1 million will be reclassified to earnings in the next twelve months. Interest rate swaps and collars are used to hedge underlying interest obligations. These instruments hedge interest rates on specific debt issuances and qualify for hedge accounting. The interest rate differential is reflected as an adjustment to interest expense over the life of the instruments. At June 30, 2002, we had interest rate swap and collar arrangements for an aggregate notional principal amount of $275.0 million. These instruments are based on LIBOR rates. The collar provides for a floor of 6.1% and a ceiling of 8.0% with an expiration date of August 19, 2002, for a $125.0 million notional principal amount. The fixed rate swaps provide for a rate of 3.6% for a $100.0 million notional principal amount expiring September 2003, and a rate of 4.3% for a $50.0 million notional principal amount expiring March 2004. Since substantially all of our Canadian business is conducted in Canadian dollars (CAD), we use certain financial instruments to minimize the risks of changes in the exchange rate. These instruments include forward exchange contracts, forward extra option contracts and cross currency swaps. At June 30, 2002, we had forward exchange contracts and forward extra option contracts that allow us to exchange $3.0 million Canadian for at least $1.9 million U. S. (based on a Canadian-U.S. dollar exchange rate of 1.54) quarterly during 2002 and 2003. At June 30, 2002, we also had a cross currency swap contract for an aggregate notional principal amount of $24.8 million, effectively converting this amount of our $99.0 million senior secured term loan (25% of the total) from U.S. dollars to $38.3 million of Canadian dollar debt (based on a Canadian-U.S. dollar exchange rate of 1.55). The terms of this contract mirror the term loan, matching the amortization schedule and final maturity in May 2006. Additionally, at June 30, 2002, $13.2 million of our long-term debt was denominated in Canadian dollars ($20.0 million CAD based on a Canadian-U.S. dollar exchange rate of 1.52). 27
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 hedged 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. 28
PART II. OTHER INFORMATION Item 1. LEGAL PROCEEDINGS 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 our former general partner, its directors and certain of its officers as defendants, and alleged 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. We reached an agreement in principle with the plaintiffs to settle the Delaware litigation for approximately $1.1 million. On March 6, 2002, the Delaware court approved the settlement. The order became final in April of 2002 and the settlement amount has been paid. 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 our former general partner, its directors and certain of its officers as defendants. This lawsuit contained the same claims and sought the same relief as the Delaware derivative litigation, described above. We reached an agreement in principle with the plaintiffs to settle the Texas litigation for approximately $112,500. The court approved the settlement on March 18, 2002. The order became final in April of 2002 and the settlement amount has been paid. Other. We, in the ordinary course of business, are a claimant and/or a defendant in various other legal proceedings. We do 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 are not applicable and have been omitted. Item 5. OTHER Recent Initiatives Regarding Corporate Governance Practices. There have been several regulatory and legislative initiatives introduced over the past several months in response to recent events regarding accounting issues at large public companies, resulting disruptions in the capital markets and ensuing calls for action to prevent repetition of such events. Certain of these initiatives include: . On July 30, 2002, President Bush signed into law the Sarbanes--Oxley Act of 2002 ("Act"). The Act covers a variety of areas and seeks, among other things, to promote corporate responsibility, enhance public disclosure, improve the quality and transparency of financial reporting and auditing, create a Public Company Accounting Oversight Board, protect the objectivity of research analysts and strengthen penalties for securities law violations. Certain provisions of the Act are effective immediately, while others require the Securities and Exchange Commission ("SEC") to adopt relevant rules within specified periods, ranging from 30 days to one year. One of the immediately effective provisions of the Act requires, in connection with filing of periodic reports with the SEC that contain financial statements, the Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO") of every publicly traded company personally to certify that such report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 and the information contained in such report fairly presents, in all material respects, the financial condition and result of operations of the company. . The SEC has presented numerous proposed rules changes for public comment. In addition, on June 27, 2002, the SEC issued Order No. 4-460 requiring the filing of sworn statements by the CEO and the CFO of 945 of the largest publicly traded companies, attesting that each respective company's most recent periodic reports are materially truthful and complete or explain why such a statement would not be correct. Such Order was effective immediately and requires the certifications to be filed no later than August 14, 2002. Plains All American Pipeline, L.P. was among the entities included on this list. 29
. On June 6, 2002, the Corporate Accountability and Listing Standards Committee of the New York Stock Exchange ("NYSE") submitted recommendations to the NYSE Board of Directors designed to enhance accountability, integrity and transparency of listed companies on the NYSE. The committee also submitted for consideration by the NYSE Board certain recommendations to other institutions, including the SEC and the US Congress. On August 1, 2002, the NYSE Board adopted the final recommendations of the committee and stated its intention to promptly submit a rule filing with the SEC for review. Certain of the provisions of the Act were effective as of July 30, 2002, however, specific guidelines on how exactly to comply with certain of these provisions have yet to be promulgated and in other cases the methods to comply are unclear. However, Exhibits 99.1 and 99.2 to this filing include the CEO and CFO certification required by the Act. Contemporaneously with the filing of this document, an 8K was filed that includes the certification required by SEC Order 4-460. Certain other issues that are not specifically mentioned in the foregoing certifications, but which have been addressed or potentially will be addressed in the Act or the SEC/NYSE initiatives, are discussed below: Loans to Executives The Act prohibits any public company from making loans to directors or executive officers of the company. Neither the Partnership nor the general partner has ever made any loans to directors or executive officers of the general partner. In connection with the sale by Plains Resources Inc. of a portion of its ownership in the general partner to members of the senior management team in September 2001, Plains Resources Inc. loaned an aggregate of $382,500 to five members of the senior management team. Plains Resources Inc. is an independent entity that currently owns an approximate 29% ownership interest in Plains All American Pipeline, L.P. Neither the partnership nor the general partner participated in or provided any support for these loans. The individuals receiving these loans from Plains Resources Inc. did not include the Chief Executive Officer, Chief Operating Officer or the Chief Financial Officer of the general partner of the partnership. Such amounts loaned by Plains Resources Inc. represented approximately 50% of the total purchase price from Plains Resources Inc. for these individuals' respective interests and the balance was required to be funded with cash. Terms of the loan provide for security in the general partner interest being acquired, a five-year term and interest at 6% per annum, payable semi-annually. At the date of such loans, the three-month LIBOR rate was approximately 3.5% and the ten-year US Treasury yield was approximately 4.8%. Auditor Independence The Partnership's Audit Committee ("Committee") Charter complies with the current rules of the NYSE, including provision for the Committee to consult with management and recommend to the Board of Directors ("Board") the appointment of the Partnership's independent auditors. The Charter also provides for the Committee to review the activities and independence of the independent auditors and to communicate to the independent auditors that they are ultimately accountable to the Committee and the Board. The charter further provides that the Committee and the Board have the ultimate authority and responsibility to select, evaluate and, where appropriate, replace the independent auditors. In addition, the charter provides that the Committee actively engage in dialogue with the independent auditors with respect to any disclosed relationships or services that may impact the objectivity and independence of the independent auditors and recommend that the Board take appropriate action in response to the independent auditor's report to satisfy itself of the independent auditors' independence. As a practice, the Committee has also consulted with management regarding the retention of the independent auditors to perform any non-audit related services. The proposed changes to the NYSE rules include changes to the requirements for audit committee composition and charter. In addition the Act requires the SEC to promulgate rules with respect to audit 30
committees. One new aspect involves prior approval by the audit committee of any non-audit engagement of a company's independent auditors, and disclosure of such approval. Although we engaged PricewaterhouseCoopers LLP ("PWC"), the Partnership's independent auditors, prior to July 30, the Partnership's Audit Committee ratified the engagement of PWC to assist the Partnership in an assessment of the risk management activities related to its Canadian Operations. Through June 30, 2002, the Partnership paid to its independent auditors approximately $0.4 million and $0.4 million in audit and non-audit fees, respectively. Equity Compensation Significant attention has been focused on the accounting treatment for equity based compensation, specifically with respect to expensing compensation cost associated with options. In connection with the formation of the partnership in 1998 and its initial public offering in November 1998, the general partner adopted a long-term incentive plan for employees and directors of our general partner and its affiliates who perform services for the partnership. The long-term incentive plan consists of two components, a restricted unit plan and a unit option plan. As of June 30, 2002, restricted unit grants totaling approximately 1,050,000 units were outstanding under the restricted unit plan. No options have been granted under the unit option plan since inception. Upon vesting of grants under the restricted unit plan, the partnership will record a charge to earnings equal to the fair market value of such vested units. Separate from the partnership's long-term incentive program, certain owners of the general partner contributed an aggregate of 450,000 subordinated units to the general partner to provide a pool of units available for the grant of options to management and key employees. As of June 30, 2002, approximately 367,500 options have been granted to employees and such options generally vest in 25% increments upon achieving quarterly distribution levels on our units of $0.525, $0.575, $0.625 and $0.675 ($2.10, $2.30, $2.50 and $2.70, annualized). Because the exercise of the options will be satisfied out of units owned by the general partner and will not result in dilution of units outstanding or cost to the partnership, no expense will be recorded by the partnership upon vesting of such options. 31
Item 6 - Exhibits and Reports on Form 8-K <TABLE> <CAPTION> A. Exhibits <C> <S> 10.01 Second Amended and Restated Agreement [Revolving Credit Facility] dated July 2, 2002, among Plains Marketing, L.P., All American Pipeline, L.P., Plains All American Pipeline, L.P., and Fleet National Bank and certain other lenders. 10.02 Second Amended and Restated Agreement [Letter of Credit and Hedged Inventory Facility] dated July 2, 2002, among Plains Marketing, L.P., All American Pipeline, L.P., Plains All American Pipeline, L.P., and Fleet National Bank and certain other lenders. 99.1 Certification of Chief Executive Officer of Plains All American Pipeline, L.P. pursuant to 18 U.S.C. Section 1350. 99.2 Certification of Chief Financial Officer of Plains All American Pipeline, L.P. pursuant to 18 U.S.C. Section 1350. B. Reports on Form 8-K. A current report on Form 8-K was filed on August 9, 2002, in connection with the certification by the Chief Executive Officer and the Chief Financial Officer pursuant to SEC Order 4-460. A current report on Form 8-K was filed on August 9, 2002, in connection with the acquisition of assets from Shell Pipeline Company, L.P. and Equilon Enterprises LLC. A current report on Form 8-K was furnished on July 24, 2002, in connection with Item 9 disclosure of third-quarter estimates and earnings guidance. A current report on Form 8-K was filed on May 24, 2002, attaching as an exhibit the Audited Balance Sheet of Plains AAP, L.P. as of December 31, 2001. A current report on Form 8-K was filed and furnished on May 7, 2002, in connection with Item 5 and Item 9 disclosure of earnings and earnings guidance. A current report on Form 8-K was furnished on May 6, 2002, in connection with Item 9 disclosure of the execution of a purchase and sale agreement and related press release. A current report on Form 8-K was furnished on April 19, 2002, in connection with Item 9 disclosure of our IPAA presentation. A current report on Form 8-K was furnished on April 5, 2002, in connection Item 9 disclosure of acquisition negotiations. A current report on Form 8-K was filed on March 14, 2002, attaching our Audited 2001 Financial Statements. A current report on Form 8-K/A was furnished on March 8, 2002, correcting the Form 8-K filed and furnished on March 6, 2002. A current report on Form 8-K was filed and furnished on March 6, 2002, in connection with Item 5 and Item 9 disclosure of earnings and earnings guidance. A current report on Form 8-K was filed on March 1, 2002, attaching as an exhibit the Unaudited Balance Sheet of Plains AAP, L.P. as of September 30, 2001. </TABLE> 32
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: August 9, 2002 By: /s/ PHILLIP D. KRAMER ----------------------------------- Phillip D. Kramer, Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer) Date: August 9, 2002 By: /s/ GREG L. ARMSTRONG ----------------------------------- Greg L. Armstrong, Chairman of the Board, Chief Executive Officer and Director of Plains All American GP LLC (Principal Executive Officer) 33