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 March 31, 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 jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 333 Clay Street, Suite 2900 Houston, Texas 77002 (Address of principal executive offices) (Zip Code) (713) 646-4100 (Registrant's telephone number, including area code) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes |X| No [ ] At May 9, 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 Page ---- PART I. FINANCIAL INFORMATION CONSOLIDATED FINANCIAL STATEMENTS: Consolidated Balance Sheets: March 31, 2002, and December 31, 2001......................... 3 Consolidated Statements of Operations: For the three months ended March 31, 2002 and 2001............ 4 Consolidated Statements of Cash Flows: For the three months ended March 31, 2002 and 2001............ 5 Consolidated Statement of Partners' Capital: For the three months ended March 31, 2002..................... 6 Notes to Consolidated Financial Statements......................... 7 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS........................... 12 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS.................................................. 17 PART II. OTHER INFORMATION......................................... 18 2
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (in thousands, except unit data) <TABLE> <CAPTION> March 31, December 31, 2002 2001 ----------- ------------ (unaudited) ASSETS <S> <C> <C> CURRENT ASSETS Cash and cash equivalents $ 3,301 $ 3,511 Accounts receivable and other current assets 488,662 365,697 Inventory 151,442 188,874 ----------- ----------- Total current assets 643,405 558,082 ----------- ----------- PROPERTY AND EQUIPMENT 670,770 653,050 Less allowance for depreciation and amortization (54,292) (48,131) ----------- ----------- 616,478 604,919 ----------- ----------- OTHER ASSETS Pipeline linefill 57,559 57,367 Other 47,400 40,883 ----------- ----------- 104,959 98,250 ----------- ----------- $ 1,364,842 $ 1,261,251 =========== =========== LIABILITIES AND PARTNERS' CAPITAL CURRENT LIABILITIES Accounts payable and other current liabilities $ 457,637 $ 386,993 Due to affiliates 19,672 13,685 Short-term debt 103,954 104,482 ----------- ----------- Total current liabilities 581,263 505,160 LONG-TERM LIABILITIES Bank debt 390,995 351,677 Other long-term liabilities 1,617 1,617 ----------- ----------- Total liabilities 973,875 858,454 ----------- ----------- COMMITMENTS AND CONTINGENCIES (Note 8) PARTNERS' CAPITAL Common unitholders (31,915,939 units outstanding at each date) 399,999 408,562 Class B common unitholders (1,307,190 units outstanding at each date) 19,184 19,534 Subordinated unitholders (10,029,619 units outstanding at each date) (41,583) (38,891) General partner 13,367 13,592 ----------- ----------- Total partners' capital 390,967 402,797 ----------- ----------- $ 1,364,842 $ 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) (unaudited) <TABLE> <CAPTION> Three Months Ended March 31, --------------------------- 2002 2001 ----------- ----------- <S> <C> <C> REVENUES $ 1,545,323 $ 1,520,124 COST OF SALES AND OPERATIONS 1,506,935 1,487,394 ----------- ----------- Gross Margin 38,388 32,730 ----------- ----------- EXPENSES General and administrative 10,758 8,989 Depreciation and amortization 6,967 4,670 ----------- ----------- Total expenses 17,725 13,659 ----------- ----------- OPERATING INCOME 20,663 19,071 Interest expense (6,453) (6,606) Interest and other income (expense) 71 42 ----------- ----------- Income before cumulative effect of accounting change 14,281 12,507 Cumulative effect of accounting change -- 508 ----------- ----------- NET INCOME $ 14,281 $ 13,015 =========== =========== NET INCOME - LIMITED PARTNERS $ 13,454 $ 12,689 =========== =========== NET INCOME - GENERAL PARTNER $ 827 $ 326 =========== =========== BASIC AND DILUTED NET INCOME PER LIMITED PARTNER UNIT Income before cumulative effect of accounting change $ 0.31 $ 0.36 Cumulative effect of accounting change -- 0.01 ----------- ----------- Net income $ 0.31 $ 0.37 =========== =========== WEIGHTED AVERAGE UNITS OUTSTANDING 43,253 34,386 =========== =========== </TABLE> See notes to consolidated financial statements. 4
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands) (unaudited) <TABLE> <CAPTION> Three Months Ended March 31, ---------------------------- 2002 2001 --------- --------- <S> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 14,281 $ 13,015 Items not affecting cash flows from operating activities: Depreciation and amortization 6,967 4,670 Cumulative effect of accounting change -- (508) Change in derivative fair value 2,855 167 Noncash compensation expense -- 121 Change in assets and liabilities, net of assets acquired and liabilities assumed: Accounts receivable and other (121,581) 22,150 Inventory 37,412 (27,144) Accounts payable and other current liabilities 63,219 (2,225) Due to affiliates 5,987 322 --------- --------- Net cash provided by operating activities 9,140 10,568 --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES Additions to property and equipment (11,398) (1,466) Proceeds from sales of assets 26 434 Cash paid in connection with acquisitions (13,160) (1,215) --------- --------- Net cash used in investing activities (24,532) (2,247) --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from long-term debt 262,479 478,950 Proceeds from short-term debt 200,000 10,500 Principal payments of long-term debt (223,137) (482,400) Principal payments of short-term debt (200,528) (1,300) Costs incurred in connection with financing arrangements (544) -- Distributions to unitholders (23,160) (16,295) --------- --------- Net cash provided by (used in) financing activities 15,110 (10,545) --------- --------- Affect of translation adjustment on cash 72 -- Net decrease in cash and cash equivalents (210) (2,224) Cash and cash equivalents, beginning of period 3,511 3,426 --------- --------- Cash and cash equivalents, end of period $ 3,301 $ 1,202 ========= ========= </TABLE> See notes to consolidated financial statements. 5
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL (in thousands) (unaudited) <TABLE> <CAPTION> Total Class B General Partners' Common Units Common Units Subordinated Units Partner Capital ----------------- ----------------- ------------------ ------- --------- Units Amount Units Amount Units Amount Amount Amount ----- ------ ----- ------ ----- ------ ------ ------ <S> <C> <C> <C> <C> <C> <C> <C> <C> Balance at December 31, 2001 31,916 $ 408,562 1,307 $ 19,534 10,030 $ (38,891) $ 13,592 $ 402,797 Distributions -- (16,357) -- (670) -- (5,140) (993) (23,160) Other comprehensive income -- (2,134) -- (87) -- (671) (59) (2,951) Net income -- 9,928 -- 407 -- 3,119 827 14,281 ------ --------- --------- --------- ------ --------- --------- --------- Balance at March 31, 2002 31,916 $ 399,999 1,307 $ 19,184 10,030 $ (41,583) $ 13,367 $ 390,967 ====== ========= ========= ========= ====== ========= ========= ========= </TABLE> See notes to consolidated financial statements. 6
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) Note 1 -- Organization and Accounting Policies We are a Delaware limited partnership formed in September of 1998 to acquire and operate the midstream crude oil business and assets of Plains Resources Inc. and its wholly owned subsidiaries. On November 23, 1998, we completed our initial public offering and the transactions whereby we became the successor to the business of the midstream subsidiaries of Plains Resources. Our operations are conducted through Plains Marketing, L.P., All American Pipeline, L.P. and Plains Marketing Canada, L.P. The terms "Plains All American" and the "Partnership" herein refer to Plains All American Pipeline, L.P. and its affiliated operating partnerships. We are engaged in interstate and intrastate transportation, marketing and terminalling of crude oil and liquefied petroleum gas ("LPG"). Our operations are conducted primarily in Texas, California, Oklahoma, Louisiana and the Canadian provinces of Alberta and Saskatchewan. In May 2001, senior management of our general partner and a group of financial investors entered into a transaction with Plains Resources to acquire control of the general partner interest and a majority of the outstanding subordinated units. The transaction closed in June 2001. As a result of this transaction, Plains Resources' ownership in the general partner was reduced from 100% to 44%. Additionally, as a result of this transaction and various equity offerings conducted since the IPO, Plains Resources' overall effective ownership has been reduced to approximately 29%. The accompanying financial statements and related notes present our consolidated financial position as of March 31, 2002, and December 31, 2001, the results of our operations for the three months ended March 31, 2002 and 2001, cash flows for the three months ended March 31, 2002 and 2001, and changes in partners' capital for the three months ended March 31, 2002. The financial statements have been prepared in accordance with the instructions to interim reporting as prescribed by the Securities and Exchange Commission ("SEC"). All adjustments, consisting only of normal recurring adjustments, that in the opinion of management were necessary for a fair statement of the results for the interim periods, have been reflected. All significant intercompany transactions have been eliminated. When necessary, certain reclassifications are made to prior period amounts to conform to current period presentation. The results of operations for the three months ended March 31, 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 on 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. 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. In accordance with Statement of Financial Accounting Standards ("SFAS") No. 133 "Accounting for Derivative Instruments and Hedging Activities", gains and losses on hedging 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 period in which they occur. The March 31, 2002, balance sheet includes a $7.7 million unrealized loss in OCI and related assets and liabilities of $5.9 million and $15.7 million, respectively. Earnings included a noncash loss of $2.9 million related to the ineffective portion of our cash flow hedges, and certain derivative contracts primarily relating to our LPG activities that did not qualify as hedges due to a low correlation between the futures contract and hedged item ($2.1 million net of the reversal of the prior period fair value adjustment related to contracts that settled during the current period). Our hedge-related assets and liabilities are included in other current assets and other current liabilities in the consolidated balance sheet. 7
As of March 31, 2002, the total amount of deferred net losses on derivative instruments recorded in OCI are expected to be reclassified to earnings during 2002 and 2003. The following table sets forth our open commodity hedge positions at March 31, 2002. These derivative instruments have offsetting physical exposures to the extent they are effective. <TABLE> <CAPTION> 2002 2003 ------------------------------------ ---------------------------------- 2nd Qtr 3rd Qtr 4th Qtr 1st Qtr 2nd Qtr 3rd Qtr ------------ ------------ ---------- --------- ------------ ----------- <S> <C> <C> <C> <C> <C> <C> Volume (mbbls) Short positions 8,187 1,843 83 13 - - Long positions 5,358 1,859 326 - - 100 Average price ($/bbl) $25.63 $23.07 $25.13 $10.10 $ - $23.90 </TABLE> 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 March 31, 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 2002 for $125.0 million notional principal amount. The fixed rate swaps provide for a rate of 4.3% for $50.0 million notional principal amount expiring March 2004, and a rate of 3.6% for $100.0 million notional principal amount expiring September 2003. 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. Additionally, at March 31, 2002, $22.9 million ($36.5 million CAD based on a Canadian-U.S. dollar exchange rate of 1.59) of our long-term debt was denominated in Canadian dollars. All of the financial instruments utilized are placed with large creditworthy financial institutions and meet the criteria under SFAS 133 for hedge accounting treatment. At March 31, 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 March 31, 2002, we also had a cross currency swap contract for an aggregate notional principal amount of $25.0 million, effectively converting this amount of our $100.0 million senior secured term loan (25% of the total) from U.S. dollars to $38.7 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. We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. Hedge effectiveness is measured on a quarterly basis. This process includes specific identification of the hedging instrument and the hedge transaction, the nature of the risk being hedged and how the hedging instrument's effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. Note 3 - Comprehensive Income Comprehensive income includes net income and certain items recorded directly to Partners' Capital and classified as OCI. Such amounts are allocated in proportion to the limited partners' and general partner's interest. The following table reflects comprehensive income as of March 31, 2002 (in thousands): <TABLE> <CAPTION> Balance at 1st Qtr Balance at December 31, 2002 March 31, 2001 Activity 2002 ------------ -------- ---------- <S> <C> <C> <C> Cumulative effect of change in accounting principle $ (8,337) $ - $ (8,337) Reclassification adjustment for settled contracts (2,526) (3,271) (5,797) Changes in fair value of outstanding hedging positions 6,123 370 6,493 Currency translation adjustment (8,002) (50) (8,052) --------- -------- -------- Accumulated Other Comprehensive Income $ (12,742) $ (2,951) $(15,693) --------- -------- -------- Net Income 14,281 -------- Total Comprehensive Income $ 11,330 ======== </TABLE> 8
Note 4 -- Acquisitions 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 $8.2 million in cash plus 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 Butte Pipeline System, principally a mainline system, transported approximately 60,000 barrels per day of crude oil at the time of acquisition. 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 5 -- Credit Agreements Our credit facilities currently consist of a $200 million senior secured letter of credit and borrowing facility, and a $780.0 million senior secured revolving credit and term loan facility, each of which is secured by substantially all of our assets. The revolving credit and term loan facility consists of a $450.0 million domestic revolving facility (with a $10.0 million letter of credit sublimit), a $30.0 million Canadian revolving facility (with a $5.0 million letter of credit sublimit), a $100.0 million term loan, and a $200.0 million term B loan. The facilities mature as follows: . as to the $200 million senior secured letter of credit and borrowing facility, in April 2004; . as to the aggregate $480.0 million domestic and Canadian revolver portions, in April 2005; . as to the $100.0 million term loan, in May 2006; and . as to the $200.0 million term B loan, in September 2007. In January 2002, we amended our credit facility to provide the Partnership with greater structuring flexibility to finance larger acquisitions by amending the limitation and restrictions on asset sales, including the removal of a provision that required lender approval before making any acquisition greater than $50.0 million. Note 6 -- Distributions On February 14, 2002, we paid a cash distribution of $0.5125 per unit on our outstanding common units, Class B units and subordinated units. The distribution was paid to unitholders of record on February 4, 2002, for the period October 1, 2001, through December 31, 2001. The total distribution paid was approximately $23.2 million, with approximately $17.0 million paid to our common unitholders, $5.1 million paid to our subordinated unitholders and $1.0 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. On April 22, 2002, we declared a cash distribution of $0.525 per unit on our outstanding common units, Class B units and subordinated units. The distribution is payable on May 15, 2002, to unitholders of record on May 6, 2002, for the period January 1, 2002, through March 31, 2002. The total distribution to be paid is approximately $23.9 million, with approximately $17.4 million to be paid to our common unitholders, $5.3 million to be paid to our subordinated unitholders and $1.2 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. 9
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) Marketing, Gathering, Terminalling and Storage Operations - engages in purchases and resales of crude oil at various points along the distribution chain and the operation of certain terminalling and storage assets. <TABLE> <CAPTION> Marketing, Gathering, Terminalling (in thousands) (unaudited) Pipeline & Storage Total - ---------------------------------------------------------------------------------------------------- <S> <C> <C> <C> Three Months Ended March 31, 2002 Revenues: External Customers $ 84,894 $1,460,429 $1,545,323 Intersegment (a) 5,595 -- 5,595 Other revenue 9 61 70 ---------- ---------- ---------- Total revenues of reportable segments $ 90,498 $1,460,490 $1,550,988 ========== ========== ========== Segment gross margin (b) $ 18,620 $ 19,768 $ 38,388 Segment gross profit (c) 16,234 11,396 27,630 - ---------------------------------------------------------------------------------------------------- Three Months Ended March 31, 2001 Revenues: External Customers $ 88,038 $1,432,086 $1,520,124 Intersegment (a) 3,309 -- 3,309 Other revenue -- 42 42 ---------- ---------- ---------- Total revenues of reportable segments $ 91,347 $1,432,128 $1,523,475 ========== ========== ========== Segment gross margin (b) $ 13,892 $ 18,838 $ 32,730 Segment gross profit (c) 13,431 10,310 23,741 - ---------------------------------------------------------------------------------------------------- </TABLE> a) Intersegment sales were conducted on an arm's length basis. b) Gross margin is calculated as revenues less cost of sales and operations expenses. c) Gross profit is calculated as revenues less cost of sales and operations expenses and general and administrative expenses. 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. Litigation Texas Securities Litigation. On November 29, 1999, a class action lawsuit was filed in the United States District Court for the Southern District of Texas entitled Di Giacomo v. Plains All American Pipeline, L.P., et al. The suit alleged that Plains All American and certain of our former general partner's officers and directors violated federal securities laws, primarily in connection with unauthorized trading by a former employee. An additional nineteen cases were filed in the Southern District of Texas, some of which named our former general partner and Plains Resources as additional defendants. All of the federal securities claims were consolidated into two actions. The first consolidated action is that filed by purchasers of Plains Resources' common stock and options, and is captioned Koplovitz v. Plains Resources Inc., et al. The second consolidated action is that filed by purchasers of our common units, and is captioned Di Giacomo v. Plains All American 10
Pipeline, L.P., et al. Plaintiffs alleged that the defendants were liable for securities fraud violations under Rule 10b-5 and Section 20(a) of the Securities Exchange Act of 1934 and for making false registration statements under Sections 11 and 15 of the Securities Act of 1933. We and Plains Resources reached an agreement with representatives for the plaintiffs for the settlement of all of the class actions, and in January 2001, we deposited approximately $30.0 million under the terms of the settlement agreement. The total cost of the settlement to us and Plains Resources, including interest and expenses and after insurance reimbursements, was $14.9 million. Of that amount, $1.0 million was allocated to Plains Resources by agreement between special independent committees of the board of directors of our former general partner and the board of directors of Plains Resources. All such amounts were reflected in our financial statements at December 31, 2000. The settlement was approved by the court on December 19, 2001, and became final on January 18, 2002. 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 allege that the defendants breached the fiduciary duties that they owed to Plains All American Pipeline, L.P. and its unitholders by failing to monitor properly the activities of its employees. 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 contains the same claims and seeks 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 -- Subsequent Events Acquisition of Shell's West Texas Interests. In May 2002, we agreed to purchase certain assets 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 million, excluding financing and related transaction costs. The acquisition is expected to close early in the third quarter. Consistent with our financing strategy, we expect to finance this acquisition on a long-term basis using a balance of equity and long-term debt. Because it is difficult to predict the timing of accessing capital markets, we may initially fund the acquisition using proceeds from our revolving credit facility. 11
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. Our operations are conducted through Plains Marketing, L.P., All American Pipeline, L.P. and Plains Marketing Canada, L.P. The terms "Plains All American" and the "Partnership" herein refer to Plains All American Pipeline, L.P. and its affiliated operating partnerships. We are engaged in interstate and intrastate transportation, marketing and terminalling of crude oil and liquefied petroleum gas ("LPG"). Our operations are conducted primarily in Texas, California, Oklahoma, Louisiana and the Canadian provinces of Alberta and Saskatchewan. Pipeline Operations. Our activities from pipeline operations generally consist of transporting third-party volumes of crude oil for a 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. Utilization of our pipelines in our gathering and marketing business provides us with a competitive advantage over third party gatherers that do not have similarly located pipelines, because generally it costs less to transport crude oil on pipelines than alternative methods of transportation. 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. Terminalling and Storage Activities and Gathering and Marketing 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. 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. Results of Operations For the three months ended March 31, 2002, we reported net income of $14.3 million on total revenue of $1.5 billion compared to net income for the same period in 2001 of $13.0 million on total revenues of $1.5 billion. The results for the three months ended March 31, 2002, include $2.9 million in noncash fair value adjustments related to Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities ("SFAS 133"). The results for the period ended March 31, 2001, include (i) a $0.5 million cumulative effect gain as a result of the adoption of SFAS 133 (ii) a $0.2 million noncash fair value adjustment related to SFAS 133; and (iii) a $0.1 million charge for noncash compensation expenses. Excluding these items, we would have reported net income of $17.2 million and $12.8 million for the three months ended March 31, 2002 and 2001, respectively. 12
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 March 31, ---------------------------- 2002 2001 ------------- ------------- <S> <C> <C> Operating Results (in thousands): Revenues $ 1,545,323 $ 1,520,124 =========== =========== Gross margin: Pipeline $ 18,620 $ 13,892 Gathering and marketing and terminalling and storage 19,768 18,838 ----------- ----------- Total 38,388 32,730 General and administrative expense (10,758) (8,989) ----------- ----------- Gross profit $ 27,630 $ 23,741 =========== =========== Net income $ 14,281 $ 13,015 =========== =========== Average Daily Volumes (mbbls/day): Pipeline Activities: All American Tariff activities 67 70 Margin activities 71 65 Canada 201 -- Other 154 161 ----------- ----------- Total 493 296 =========== =========== Lease gathering 399 288 Bulk purchases 71 21 ----------- ----------- Total 470 309 =========== =========== Terminal throughput 68 97 =========== =========== Storage leased to third parties, monthly average volumes 1,545 1,931 =========== =========== </TABLE> Revenues. Total revenues were $1.5 billion for the three months ended March 31, 2002 and 2001. Excluding the impact of our Canadian acquisitions, total revenues for the first quarter of 2002 would have been $1.2 billion. The decrease is primarily attributable to lower crude oil prices in the 2002 quarter. Cost of Sales and Operations. Cost of sales and operations were $1.5 billion in the first quarter of 2002 and 2001 primarily due to the reasons discussed with respect to revenues. General and Administrative. General and administrative expense ("G&A") was $10.8 million for the quarter ended March 31, 2002, compared to $9.0 million for the first quarter of 2001. The increase in 2002 is primarily due to $2.3 million of expenses associated with our Canadian acquisitions, offset by a decrease in expenses related to outside consultants. Depreciation and Amortization. Depreciation and amortization expense was $7.0 million for the quarter ended March 31, 2002, compared to $4.7 million for the same period of 2001. Approximately $2.1 million of the increase is attributable to our Canadian acquisitions. Interest Expense. Interest expense decreased to $6.5 million for the quarter ended March 31, 2002, from $6.6 million for the comparative 2001 period. The decrease is due to lower interest rates somewhat offset by a higher average debt balance and increased commitment fees in the first quarter of 2002. Cumulative Effect of Accounting Change. During the first quarter of 2001, we recognized a $0.5 million cumulative effect gain as a result of the adoption of SFAS 133 effective January 1, 2001. 13
Segment Results Pipeline Operations. Gross margin from pipeline operations increased to $18.6 million for the quarter ended March 31, 2002, from $13.9 million for the prior year quarter. The increase resulted primarily from the impact of our Canadian acquisitions, which added $4.9 million to our pipeline margin. Average daily volumes on our pipelines during the first quarter of this year were 493,000 barrels per day compared to 296,000 barrels per day last year. Approximately 201,000 barrels per day of the increase is due to our Canadian acquisitions. Gathering and Marketing Activities and Terminalling and Storage Activities. Gross margin from gathering, marketing, terminalling and storage activities excluding the impact of the noncash fair value adjustments related to SFAS 133 of $2.9 million and $0.2 million, respectively, was approximately $22.7 million for the quarter ended March 31, 2002, compared to $19.0 million in the prior year quarter. The increase was primarily related to our Canadian acquisitions which contributed $5.6 million of gross margin partially offset by the weak market conditions for our gathering and marketing activities during this period due to the existence of a contango market. Gross margin including the impact of the noncash adjustments discussed above was approximately $19.8 million for the quarter ended March 31, 2002, compared to $18.8 million in the prior year quarter. Lease gathering volumes increased from an average of 288,000 barrels per day for the first quarter of 2001 to approximately 399,000 barrels per day in 2002, mostly due to our Canadian acquisitions. Bulk purchase volumes increased from approximately 21,000 barrels per day for the first quarter of 2001 to approximately 71,000 barrels per day in the current period. Lease capacity decreased to an average of 1.5 million barrels per month from an average of 1.9 million barrels per month in the prior year quarter due to an increase in our storage volumes at these locations related to the existence of a contango market. Terminal throughput averaged approximately 68,000 barrels per day and 97,000 barrels per day in the first quarter of 2002 and 2001, respectively. Liquidity and Capital Resources Recent Events Acquisition of Shell's West Texas Interests. In May 2002, we agreed to purchase certain assets 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 million, excluding financing and related transaction costs. The acquisition is expected to close early in the third quarter. Consistent with our financing strategy, we expect to finance this acquisition on a long-term basis using a balance of equity and long-term debt. Because it is difficult to predict the timing of accessing capital markets, we may initially fund the acquisition using proceeds from our revolving credit facility. Liquidity Cash generated from operations and our credit facilities are our primary sources of liquidity. At March 31, 2002, we had working capital of approximately $62.1 million and approximately $386.0 million of availability under our revolving credit facility. 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. Cash Flows Quarter Ended March 31, ------------------------- 2002 2001 ----------- ----------- (in millions) Cash provided by (used in): Operating activities $9.1 $ 10.6 Investing activities (24.5) (2.2) Financing activities 15.1 (10.5) Operating Activities. Net cash provided by operating activities was $9.1 million and $10.6 million for the three months ended March 31, 2002 and 2001, respectively. The decrease was primarily related to margin calls on financial derivatives that hedge future physical contracts, partially offset by cash flows from our Canadian acquisitions. Investing Activities. Net cash used in investing activities in 2002 includes $13.2 million for the Butte and Coast/Lantern acquisitions and $11.4 million of capital expenditures primarily for the Cushing expansion and other capital projects. Financing Activities. Cash provided by financing activities in 2002 consisted primarily of net long-term borrowings of $39.3 million used primarily to fund capital expenditures. In addition, $23.2 million of distributions were paid to unitholders during the current quarter. 14
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 May 10, 2002, we have the ability to issue approximately $570 million of additional debt or equity securities under this registration statement. Credit Agreements Our credit facilities currently consist of a $200 million senior secured letter of credit and borrowing facility, and a $780.0 million senior secured revolving credit and term loan facility, each of which is secured by substantially all of our assets. The revolving credit and term loan facility consists of a $450.0 million domestic revolving facility (with a $10.0 million letter of credit sublimit), a $30.0 million Canadian revolving facility (with a $5.0 million letter of credit sublimit), a $100.0 million term loan, and a $200.0 million term B loan. The facilities mature as follows: ... as to the $200 million senior secured letter of credit and borrowing facility, in April 2004; ... as to the aggregate $480.0 million domestic and Canadian revolver portions, in April 2005; ... as to the $100.0 million term loan, in May 2006; and ... as to the $200.0 million term B loan, in September 2007. In January 2002, we amended our credit facility to provide the Partnership with greater structuring flexibility to finance larger acquisitions by amending the limitation and restrictions on asset sales, including the removal of a provision that required lender approval before making any acquisition greater than $50.0 million. Contingencies We may experience future releases of crude oil into the environment from our pipeline and storage operations, or discover releases that were previously unidentified. Although we maintain an inspection program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to any future environmental releases from our assets may substantially affect our business. The events of September 11 and their overall effect on the insurance industry may have a general adverse impact on availability and cost of coverage. We currently maintain insurance for acts of terrorism on the majority of our assets and operations. Many of our current policies expire on June 1, 2002. Due to the events of September 11, 2001, we believe that many insurers will exclude acts of terrorism from future insurance policies or make the cost for this coverage prohibitive. Since the September 11 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. 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. 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; ... 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 15
... general economic, market or business conditions. Other factors described herein, 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. 16
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS We utilize various derivative instruments, for purposes other than trading, to hedge our exposure to price fluctuations on 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. 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. In accordance with Statement of Financial Accounting Standards ("SFAS") No. 133 "Accounting for Derivative Instruments and Hedging Activities", gains and losses on hedging instruments are deferred to 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 period in which they occur. The March 31, 2002, balance sheet included a $7.7 million unrealized loss in OCI and related assets and liabilities of $5.9 million and $15.7 million, respectively. Earnings included a noncash loss of $2.9 million related to the ineffective portion of our cash flow hedges, as well as certain derivative contracts primarily relating to our LPG activities that did not qualify as hedges due to a low correlation between the futures contract and hedged item ($2.1 million net of the reversal of the prior period fair value adjustment related to contracts that settled during the current period). Our hedge-related assets and liabilities are included in other current assets and other current liabilities in the consolidated balance sheet. As of March 31, 2002, the total amount of deferred net losses on derivative instruments recorded in OCI are expected to be reclassified to earnings during 2002 and 2003. The following table sets forth our open commodity hedge positions at March 31, 2002. These derivative instruments have offsetting physical exposures to the extent they are effective. <TABLE> <CAPTION> 2002 2003 ------------------------------------ ---------------------------------- 2nd Qtr 3rd Qtr 4th Qtr 1st Qtr 2nd Qtr 3rd Qtr ------------ ------------ ---------- --------- ------------ ----------- <S> <C> <C> <C> <C> <C> <C> Volume (mbbls) Short positions 8,187 1,843 83 13 - - Long positions 5,358 1,859 326 - - 100 Average price ($/bbl) $ 25.63 $ 23.07 $ 25.13 $ 10.10 $ - $ 23.90 </TABLE> 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 March 31, 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 2002 for $125.0 million notional principal amount. The fixed rate swaps provide for a rate of 4.3% for $50.0 million notional principal amount expiring March 2004, and a rate of 3.6% for $100.0 million notional principal amount expiring September 2003. 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. Additionally, at March 31, 2002, $22.9 million ($36.5 million CAD based on a Canadian-U.S. dollar exchange rate of 1.59) of our long-term debt was denominated in Canadian dollars. All of the financial instruments utilized are placed with large creditworthy financial institutions and meet the criteria under SFAS 133 for hedge accounting treatment. At March 31, 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 March 31, 2002, we also had a cross currency swap contract for an aggregate notional principal amount of $25.0 million, effectively converting this amount of our $100.0 million senior secured term loan (25% of the total) from U.S. dollars to $38.7 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. We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. Hedge effectiveness is measured on a quarterly basis. This process includes specific identification of the hedging instrument and the hedge transaction, the nature of the risk being hedged and how the hedging instrument's effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. 17
PART II. OTHER INFORMATION Item 1. LEGAL PROCEEDINGS Texas Securities Litigation. On November 29, 1999, a class action lawsuit was filed in the United States District Court for the Southern District of Texas entitled Di Giacomo v. Plains All American Pipeline, L.P., et al. The suit alleged that Plains All American and certain of our former general partner's officers and directors violated federal securities laws, primarily in connection with unauthorized trading by a former employee. An additional nineteen cases were filed in the Southern District of Texas, some of which named our former general partner and Plains Resources as additional defendants. All of the federal securities claims were consolidated into two actions. The first consolidated action is that filed by purchasers of Plains Resources' common stock and options, and is captioned Koplovitz v. Plains Resources Inc., et al. The second consolidated action is that filed by purchasers of our common units, and is captioned Di Giacomo v. Plains All American Pipeline, L.P., et al. Plaintiffs alleged that the defendants were liable for securities fraud violations under Rule 10b-5 and Section 20(a) of the Securities Exchange Act of 1934 and for making false registration statements under Sections 11 and 15 of the Securities Act of 1933. We and Plains Resources reached an agreement with representatives for the plaintiffs for the settlement of all of the class actions, and in January 2001, we deposited approximately $30.0 million under the terms of the settlement agreement. The total cost of the settlement to us and Plains Resources, including interest and expenses and after insurance reimbursements, was $14.9 million. Of that amount, $1.0 million was allocated to Plains Resources by agreement between special independent committees of the board of directors of our former general partner and the board of directors of Plains Resources. All such amounts were reflected in our financial statements at December 31, 2000. The settlement was approved by the court on December 19, 2001, and became final on January 18, 2002. 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 allege that the defendants breached the fiduciary duties that they owed to Plains All American Pipeline, L.P. and its unitholders by failing to monitor properly the activities of its employees. 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 contains the same claims and seeks 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 & 5 are not applicable and have been omitted. 18
Item 6 - Exhibits and Reports on Form 8-K A. Exhibits None B. Reports on Form 8-K. 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. 19
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. general partner By: PLAINS ALL AMERICAN GP LLC, general partner Date: May 10, 2002 By: /s/ Phillip D. Kramer ------------------------------------------- Phillip D. Kramer, Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer) 20