ITEM 3. 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, et al. The suit alleged that Plains All American Pipeline, L.P. and certain of our 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 name our general partner and Plains Resources as additional defendants. Plaintiffs allege that the defendants are 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. The court has consolidated all subsequently filed cases under the first filed action described above. Two unopposed motions are currently pending to appoint lead plaintiffs. These motions ask the court to appoint two distinct lead plaintiffs to represent two different plaintiff classes: (1) purchasers of Plains Resources common stock and options and (2) purchasers of our common units. Once lead plaintiffs have been appointed, the plaintiffs will file their consolidated amended complaints. No answer or responsive pleading is due until thirty days after a consolidated amended complaint is filed.
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 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. The derivative complaints allege, among other things, that Plains All American Pipeline has been harmed due to the negligence or breach of loyalty of the officers and directors that are named in the lawsuits. These cases are currently in the process of being consolidated. No answer or responsive pleading is due until these cases have been consolidated and a consolidated complaint has been filed.
We intend to vigorously defend the claims made in the Texas securities litigation and the Delaware derivative litigation. However, there can be no assurance that we will be successful in our defense or that these lawsuits will not have a material adverse effect on our financial position or results of operation.
We, in the ordinary course of business, are a claimant and/or a defendant in various other legal proceedings. Management does not believe that the outcome of these other legal proceedings, individually and in the aggregate, will have a materially adverse effect on our financial condition or results of operation.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of the security holders, through solicitation of proxies or otherwise, during the fourth quarter of the fiscal year covered by this report.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON UNITS AND RELATED UNITHOLDER MATTERS
The common units, excluding the Class B common units, are listed and traded on the New York Stock Exchange under the symbol "PAA". On March 22, 2000, the market price for the common units was $16 3/8 per unit and there were approximately 11,700 recordholders and beneficial owners (held in street name).
The following table sets forth high and low sales prices for the common units as reported on the New York Stock Exchange Composite Tape, and the cash distributions paid per common unit for the periods indicated:
Common Unit Price Range ------------------------------ Cash High Low Distributions ---------- --------------- ------------- 1999: 1st Quarter $ 19 $ 15 7/8 $ 0.450 2nd Quarter 19 15/16 16 5/16 0.463 3rd Quarter 20 17 3/8 0.481 4th Quarter 20 1/4 9 5/8 0.450 (1)
1998: 4th Quarter $ 20 3/16 $ 16 1/4 $ 0.193 (2)
- ------------ (1) A distribution was not made on the subordinated units for the fourth quarter of 1999. (2) Represents a partial quarterly distribution for the period from November 23, 1998, the date of our initial public offering, to December 31, 1998.
The Class B common units are pari passu with common units with respect to quarterly distributions, and are convertible into common units upon approval of a majority of the common unitholders. The Class B unitholders may request that we call a meeting of common unitholders to consider approval of the conversion of Class B units into common units. If the approval of a conversion by the common unitholders is not obtained within 120 days of a request, each Class B unitholder will be entitled to receive distributions, on a per unit basis, equal to 110% of the amount of distributions paid on a common unit, with such distribution right increasing to 115% if such approval is not secured within 90 days after the end of the 120-day period. Except for the vote to approve the conversion, the Class B units have the same voting rights as the common units.
We have also issued subordinated units, all of which are held by an affiliate of our general partner, for which there is no established public trading market. Subject to the consent of our lenders, we will distribute to our partners (including holders of subordinated units), on a quarterly basis, all of our available cash in the manner described herein. Available cash generally means, for any of our fiscal quarters, all cash on hand at the end of the quarter less the amount of cash reserves that is necessary or appropriate in the reasonable discretion of our general partner to:
. provide for the proper conduct of our business; . comply with applicable law, any of our debt instruments or other agreements; or . provide funds for distributions to unitholders and our general partner for any one or more of the next four quarters.
Minimum quarterly distributions are $0.45 for each full fiscal quarter (prorated for the initial partial fiscal quarter commencing November 23, 1998, the closing date of our initial public offering through year-end 1998). Distributions of available cash to the holders of subordinated units are subject to the prior rights of the holders of common units to receive the minimum quarterly distributions for each quarter during the subordination period, and to receive any arrearages in the distribution of minimum quarterly distributions on the common units for prior quarters during the subordination period. The expiration of the subordination period will generally not occur prior to December 31, 2003.
Under the terms of our amended bank credit agreement and letter of credit and borrowing facility, we are required to have lender approval to declare or pay distributions to unitholders and are prohibited from declaring or paying any distribution to unitholders if a default or event of default (as defined in such agreements) exists. See Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources, Liquidity and Financial Condition".
ITEM 6.
ITEM 6. SELECTED FINANCIAL AND OPERATING DATA (in thousands, except unit and operating data)
On November 23, 1998, we completed our initial public offering and the transactions whereby we became the successor to the business of our predecessor. The historical financial information below for Plains All American Pipeline was derived from our audited consolidated financial statements as of December 31, 1999 and 1998, and for the year ended December 31, 1999 and for the period from November 23, 1998 through December 31, 1998. The pro forma financial information for the year ended December 31, 1998 was derived from our audited consolidated financial statements for the period from November 23, 1998 through December 31, 1998 and from the audited combined financial statements of our predecessor for the period from January 1, 1998 through November 22, 1998. The financial information below for our predecessor was derived from the audited combined financial statements of our predecessor, as of December 31, 1997, 1996, and 1995 and for the period from January 1, 1998 through November 22, 1998 and for the years ended December 31, 1997, 1996, and 1995, including the notes thereto. The operating data for all periods is derived from our records as well as those of our predecessor. Commencing May 1, 1999, the results of operations of the Scurlock Permian businesses are included in our results of operations. Commencing July 30, 1998, the results of operations of the All American Pipeline and the SJV Gathering System are included in the results of operations of our predecessor and Plains All American Pipeline. The selected financial data should be read in conjunction with the consolidated and combined financial statements, including the notes thereto, included elsewhere in this report, and Item 7, - "Management's Discussion and Analysis of Financial Condition and Results of Operations".
- --------- (1) In November 1999, we discovered that a former employee had engaged in unauthorized trading activity, resulting in losses of approximately $162.0 million ($174.0 million, including estimated associated costs and legal expenses). Approximately $7.1 million of the unauthorized trading losses was recognized in 1998 and as a result, we have restated our 1998 financial information. See Item 1. - "Business - Unauthorized Trading Losses". (2) The unaudited selected pro forma financial and operating data for the year ended December 31, 1998, is based on our historical financial statements and those of our predecessor and Wingfoot Ventures Seven, Inc., a wholly- owned subsidiary of Goodyear. The historical financial statements of Wingfoot reflect the historical operating results of the All American Pipeline and the SJV Gathering System through July 30, 1998. Effective July 30 1998, our predecessor acquired the All American Pipeline and SJV Gathering system from Goodyear for approximately $400.0 million. The pro forma selected financial data reflects certain pro forma adjustments to the historical results of operations as if we had been formed and the acquisition had taken place on January 1, 1998. (3) Basic and diluted net income (loss) per unit is computed by dividing the limited partners' interest in net income by the number of outstanding common and subordinated units. For periods prior to November 23, 1998, the number of units are equal to the common and subordinated units received by our general partner in exchange for the assets contributed to the partnership. (4) At December 31, 1999, working capital includes $37.9 million of pipeline linefill and $103.6 million for the segment of the All American Pipeline that were both sold in the first quarter of 2000. See Item 1. - "Acquisitions and Dispositions - All American Pipeline Linefill and Asset Disposition". (5) Excludes related party debt. (6) EBITDA means earnings before interest expense, income taxes, depreciation and amortization. Our EBITDA calculation also excludes the unauthorized trading losses, noncash compensation, restructuring expense, linefill gain and extraordinary loss from extinguishment of debt. EBITDA is not a measurement presented in accordance with GAAP and is not intended to be used in lieu of GAAP presentations of results of operations and cash provided by operating activities. Our EBITDA may not be comparable to EBITDA of other entities, as other entities may not calculate EBITDA in the same manner as we do. (7) Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets to maintain the existing operating capacity of existing assets or extend their useful lives. Capital expenditures made to expand our existing capacity, whether through construction or acquisition, are not considered maintenance capital expenditures. Repair and maintenance expenditures associated with existing assets that do not extend the useful life or expand operating capacity are charged to expense as incurred. (8) Represents crude oil deliveries on the All American Pipeline for the account of third parties. (9) Represents crude oil deliveries on the All American Pipeline and the SJV Gathering System for the account of affiliated entities. These volumes were transported on the segment of the line that was sold. See "All American Pipeline Linefill Sale and Asset Disposition." (10) Represents barrels of crude oil purchased at the wellhead, including volumes which would have been purchased under the Marketing Agreement. (11) Represents barrels of crude oil purchased at collection points, terminals and pipelines. (12) Represents total crude oil barrels delivered from the Cushing Terminal and the Ingleside Terminal.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion of our financial condition and results of our operations and those of the midstream subsidiaries of Plains Resources (our "predecessor") should be read in conjunction with our historical consolidated and combined financial statements and accompanying notes and those of our predecessor included elsewhere in this report. For more detailed information regarding the basis of presentation for the following financial information, see the notes to the historical consolidated and combined financial statements.
OVERVIEW
We were 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 our predecessor. Our operations are conducted through Plains Marketing, L.P., All American Pipeline, L.P. and Plains Scurlock Permian, L.P. Plains All American Inc., a wholly owned subsidiary of Plains Resources, is our general partner. We are engaged in interstate and intrastate crude oil transportation, gathering and marketing as well as crude oil terminalling and storage activities. Our operations are conducted primarily in California, Texas, Oklahoma, Louisiana and the Gulf of Mexico.
Pipeline Operations. Our activities from pipeline operations generally consist of transporting third-party volumes of crude oil for a tariff and merchant activities designed to capture price differentials between the cost to purchase and transport crude oil to a sales point and the price received for such crude oil at the sales point. Tariffs on our pipeline systems vary by receipt point and delivery point. The gross margin generated by our tariff activities depends on the volumes transported on the pipeline and the level of the tariff charged, as well as the fixed and variable costs of operating the pipeline. Our ability to generate a profit on margin activities is not tied to the absolute level of crude oil prices but is generated by the difference between an index related price paid and other costs incurred in the purchase of crude oil and an index related price at which we sell crude oil. We are well positioned to take advantage of these price differentials due to our ability to move purchased volumes on our pipeline systems. We combine reporting of gross margin for tariff activities and margin activities due to the sharing of fixed costs between the two activities.
Terminalling and Storage Activities and Gathering and Marketing Activities. Gross margin from terminalling and storage activities is dependent on the throughput volume of crude oil stored and the level of fees generated at our terminalling and storage facilities. Gross margin from our gathering and marketing activities is dependent on our ability to sell crude oil at a price in excess of our aggregate cost. These operations are not directly affected by the absolute level of crude oil prices, but are affected by overall levels of supply and demand for crude oil and fluctuations in market related indices.
During periods when the demand for crude oil is weak (as was the case in late 1997, 1998 and the first quarter of 1999), the market for crude oil is often in contango, meaning that the price of crude oil in a given month is less than the price of crude oil in a subsequent month. A contango market has a generally negative impact on marketing margins, but is favorable to the storage business, because storage owners at major trading locations (such as the Cushing Interchange) can simultaneously purchase production at low current prices for storage and sell at higher prices for future delivery. When there is a higher demand than supply of crude oil in the near term, the market is backward, meaning that the price of crude oil in a given month exceeds the price of crude oil in a subsequent month. A backward market has a positive impact on marketing margins because crude oil gatherers can capture a premium for prompt deliveries. We believe that the combination of our terminalling and storage activities and gathering and marketing activities provides a counter-cyclical balance which has a stabilizing effect on our operations and cash flow.
As we purchase crude oil, we establish a margin by selling crude oil for physical delivery to third party users, such as independent refiners or major oil companies, or by entering into a future delivery obligation with respect to futures contracts on the NYMEX. Through these transactions, we seek to maintain a position that is substantially balanced between crude oil purchases and sales and future delivery obligations. We purchase crude oil on both a fixed and floating price basis. As fixed price barrels are purchased, we enter into sales arrangements with refiners, trade partners or on the NYMEX, which establishes a margin and protects it against future price fluctuations. When floating price barrels are purchased, we match those contracts with similar type sales agreements with our customers, or likewise establish a hedge position using the NYMEX futures market. From time to time, we enter into arrangements which will expose us to basis risk. Basis risk occurs when crude oil is purchased based on a crude oil specification and location which is different from the countervailing sales arrangement. Our policy is only to purchase crude oil for which we have a market and to structure our sales contracts so that crude oil price fluctuations do not materially affect the gross margin which we receive. In November 1999, we discovered that this policy was violated, and we incurred $174.0 million in unauthorized trading losses, including associated costs and
legal expenses. See -"Unauthorized Trading Losses". We do not acquire and hold crude oil futures contracts or other derivative products for the purpose of speculating on crude oil price changes that might expose us to indeterminable losses.
UNAUTHORIZED TRADING LOSSES
In November 1999, we discovered that a former employee had engaged in unauthorized trading activity, resulting in losses of approximately $162.0 million ($174.0 million, including estimated associated costs and legal expenses). Approximately $7.1 million of the unauthorized trading losses was recognized in 1998 and the remainder in 1999. As a result, we have restated our 1998 financial information. Normally, as we purchase crude oil, we establish a margin by selling crude oil for physical delivery to third-party users or by entering into a future delivery obligation with respect to futures contracts. The employee in question violated our policy of maintaining a position that is substantially balanced between crude oil purchases and sales or future delivery obligations. The unauthorized trading and associated losses resulted in a default of certain covenants under our credit facilities and significant short- term cash and letter of credit requirements. See "Capital Resources, Liquidity and Financial Condition".
RESULTS OF OPERATIONS
Pro Forma Comparison of the Years Ended December 31, 1999 and 1998
In the discussion that follows, we are presenting a comparison of our historical results for 1999 and pro forma results for 1998. The pro forma adjustments to the historical results of operations for 1998 assume we had been formed and the acquisition of the All American Pipeline and the SJV Gathering System had taken place January 1, 1998. The following table sets forth certain historical and pro forma financial and operating information of Plains All American Pipeline for the periods presented. The following pro forma financial and operating information does not include pro forma adjustments related to the Scurlock acquisition which was effective May 1, 1999 (in thousands).
Year Ended December 31, ------------------------------- 1999 1998 -------------- -------------- (historical) (pro forma) (restated) OPERATING RESULTS: Revenues $ 4,701,921 $ 1,568,853 ============== ============== Gross margin Pipeline $ 58,001 $ 50,893 Terminalling and storage and gathering and marketing 52,313 23,228 Unauthorized trading losses (166,440) (7,100) -------------- -------------- Total (56,126) 67,021 General and administrative expense (22,198) (6,501) -------------- -------------- Gross profit $ (78,324) $ 60,520 ============== ============== Net income (loss) $ (103,360) $ 36,810 ============== ==============
Table continued on following page
Year Ended December 31, ------------------------------- 1999 1998 -------------- -------------- (historical) (pro forma) AVERAGE DAILY VOLUMES (BARRELS): Pipeline Activities: All American Tariff activities 101 125 Margin activities 56 49 Other 61 - -------------- -------------- Total 218 174 ============== ============== Lease gathering 265 108 Bulk purchases 138 98 -------------- -------------- Total 403 206 ============== ============== Terminal throughput 83 80 ============== ============== Storage leased to third parties, monthly average volumes 1,975 1,150 ============== ==============
For the year ended December 31, 1999, we reported a net loss of $103.4 million on total revenue of $4.7 billion compared to net income for the year ended December 31, 1998 of $36.8 million on total revenue of $1.6 billion. The results for the years ended December 31, 1999 and 1998 include the following nonrecurring items:
. $166.4 million of unauthorized trading losses; . a $16.5 million gain on the portion of the All American Pipeline linefill that was sold in 1999; . restructuring expense of $1.4 million; and . an extraordinary loss of $1.5 million related to the early extinguishment of debt.
. $7.1 million of unauthorized trading losses.
Excluding these items, we would have reported net income of $49.6 million and $43.9 million for the years ended December 31, 1999 and 1998, respectively. Excluding the unauthorized trading losses, we reported gross margin (revenues less direct expenses of purchases, transportation, terminalling and storage and other operating and maintenance expenses) of $110.3 million for the year ended December 31, 1999 compared to $74.1 million reported for 1998. Gross profit (gross margin less general and administrative expense), also excluding the unauthorized trading losses, was $88.1 million for the year ended December 31, 1999 as compared to $67.6 million for 1998.
Pipeline Operations. Gross margin from pipeline operations was $58.0 million for the year ended December 31, 1999 compared to $50.9 million for the prior year on a pro forma basis. The increase resulted from increased margins from our pipeline merchant activities, a reduction in operating costs attributable to the All American Pipeline and to the two 1999 acquisitions which contributed approximately $4.8 million of pipeline gross margin. The increase was partially offset by lower tariff transport volumes, due to lower production from Exxon's Santa Ynez Field and the Point Arguello Field, both offshore California.
The margin between revenue and direct cost of crude purchased was $33.5 million for the year ended December 31, 1999 compared to $14.5 million on a pro forma basis for 1998. Pipeline tariff revenues were approximately $46.4 million for the year ended December 31, 1999 compared to approximately $57.5 million on a pro forma basis in 1998. Pipeline operations and maintenance expenses were approximately $24.0 million for the year ended December 31, 1999 as compared to $26.1 million on a pro forma basis for 1998.
Tariff transport volumes on the All American Pipeline decreased from an average of 125,000 barrels per day for the year ended December 31, 1998 on a pro forma basis to 101,000 barrels per day in 1999 due primarily to a decrease in shipments of offshore California production, which decreased from 94,000 barrels per day on a pro forma basis in 1998 to 79,000 barrels per day in 1999. Barrels associated with our merchant activities on the All American Pipeline increased from 49,000 barrels per day on a pro forma basis to 56,000 barrels per day for the year ended December 31, 1999. Tariff volumes shipped on the Scurlock and West Texas Systems averaged 61,000 barrels per day during 1999.
In March 2000, we sold the segment of the All American Pipeline that extends from Emidio, California to McCamey, Texas. We initiated the sale of approximately 5.2 million barrels of crude oil linefill from the All American Pipeline in November 1999. The sale of the linefill was substantially complete in February 2000. We estimate that we will recognize a total gain of approximately $44.0 million in connection with the sale of the linefill. As of December 31, 1999, we have delivered approximately 1.8 million barrels of linefill and recognized a gain of $16.5 million. During 1999, we reported gross margin of approximately $5.0 million associated with operating the segment of the All American Pipeline that was sold. See "Capital Resources, Liquidity and Financial Condition".
The following table sets forth All American Pipeline average deliveries per day within and outside California for the periods presented (in thousands).
Year Ended December 31, ------------------ 1999 1998 ---- ---- (historical) (pro forma) Deliveries: Average daily volumes (barrels): Within California 101 115 Outside California 56 59 ---- ---- Total 157 174 ==== ====
Gathering and Marketing Activities and Terminalling and Storage Activities. Excluding the unauthorized trading losses, gross margin from gathering, marketing, terminalling and storage activities was approximately $52.3 million for the year ended December 31, 1999 compared to $23.2 million in the prior year on a pro forma basis. The increase in gross margin is due to an increase in lease gathering and bulk purchase volumes, primarily as a result of the Scurlock acquisition which contributed approximately $26.3 million of 1999 gross margin, and an increase in storage capacity leased at our Cushing Terminal. Lease gathering volumes increased from an average of 108,000 barrels per day on a pro forma basis for the year ended December 31, 1998 to approximately 265,000 barrels per day in 1999. Bulk purchase volumes increased from approximately 98,000 barrels per day for 1998 to approximately 138,000 barrels per day this year. Leased terminal capacity increased significantly from approximately 1.1 million barrels per month in 1998 to 2.0 million barrels per month during 1999. The 1.1 million barrel expansion of our Cushing Terminal was placed in service in the second quarter of 1999. Throughput volumes at our terminals increased approximately 3,000 barrels per day in the current year period.
In the period immediately following the disclosure of the unauthorized trading losses, a significant number of our suppliers and trading partners reduced or eliminated the open credit previously extended to us. Consequently, the amount of letters of credit we needed to support the level of our crude oil purchases then in effect increased significantly. In addition, the cost to us of obtaining letters of credit increased under the amended credit facility. In many instances we arranged for letters of credit to secure our obligations to purchase crude oil from our customers, which increased our letter of credit costs and decreased our unit margins. In other instances, primarily involving lower margin wellhead and bulk purchases, our purchase contracts were terminated. As a result of these changes, aggregate volumes purchased are expected to decrease by 150,000 barrels per day, consisting primarily of lower unit margin purchases. Approximately 50,000 barrels per day of the decrease is related to barrels gathered at producer lease locations and 100,000 barrels per day is attributable to bulk purchases. As a result of the increase in letter of credit costs and reduced volumes, annual EBITDA is expected to be adversely affected by approximately $5.0 million, excluding the positive impact of current favorable market conditions.
General and administrative expenses were $22.2 million for the year ended December 31, 1999, compared to $6.5 million for 1998 on a pro forma basis. The increase in 1999 as compared to the 1998 pro forma amount is due to the Scurlock and West Texas Gathering System acquisitions in 1999, continued expansion of our business activities and expenses related to the operation of Plains All American Pipeline as a public entity. As a result of the unauthorized trading losses, we will incur additional expenses in 2000.
Depreciation and amortization expense was $17.3 million for the year ended December 31, 1999, compared to $11.3 million on a pro forma basis for 1998. The increase is primarily due to the Scurlock acquisition and the West Texas Gathering System acquisition.
Interest expense was $21.1 million for the year ended December 31, 1999, compared to $13.0 million on a pro forma basis for 1998. The increase is due to (1) interest associated with the debt incurred for the Scurlock acquisition, (2) the West Texas Gathering System acquisition, (3) an increase in interest related to hedged inventory transactions and (4) an increase in interest rates as a result of the unauthorized trading losses. The 1999 extraordinary item of $1.5 million relates to the write-
In 1999, we terminated 24 employees and paid approximately $1.4 million in connection therewith.
off of certain debt issue costs and penalties associated with the prepayment of debt. The prepayment of debt was made with proceeds from our equity offering in October 1999. See "Capital Resources, Liquidity and Financial Condition".
Historical Analysis of Three Years Ended December 31, 1999.
The historical results of operations for the year ended December 31, 1999 include the results of the Scurlock acquisition effective May 1, 1999 and the West Texas Gathering System acquisition effective July 1, 1999. The combined historical results of operations for the year ended December 31, 1998 are derived from our historical statements for the period from November 23, 1998 through December 31, 1998, and the combined financial statements of our predecessor for the period from January 1, 1998 through November 22, 1998, which in the following discussion are combined and referred to as the year ended December 31, 1998. Commencing July 30, 1998 (the date of acquisition of the All American Pipeline and the SJV Gathering System from Goodyear), the results of operations of the All American Pipeline and the SJV Gathering System are included in the results of operations of the predecessor.
For 1999, we reported a net loss of $103.4 million on total revenue of $4.7 billion compared to net income for 1998 of $6.0 million on total revenue of $1.1 billion and net income for 1997 of $2.1 million on total revenue of $752.5 million. The results for the years ended December 31, 1999 and 1998 include the following nonrecurring items:
. $166.4 million of unauthorized trading losses; . a $16.5 million gain on the portion of the All American Pipeline linefill that was sold in 1999; . restructuring expense of $1.4 million; and . an extraordinary loss of $1.5 million related to the early extinguishment of debt.
. $7.1 million of unauthorized trading losses.
The following table sets forth historical and combined historical financial and operating information of Plains All American Pipeline for the periods presented and includes the impact of the nonrecurring items discussed above (in thousands)
Year Ended December 31, ----------------------------------------- 1999 1998 1997 ----------- ----------- ----------- (restated) (predecessor) OPERATING RESULTS: Revenues $ 4,701,921 $ 1,129,689 $ 752,522 =========== ============= =========== Gross margin Pipeline $ 58,001 $ 16,768 $ - Terminalling and storage and gathering and marketing 52,313 21,712 12,480 Unauthorized trading losses (166,440) (7,100) - ----------- ------------- ----------- Total (56,126) 31,380 12,480 General and administrative expense (22,198) (5,297) (3,529) ----------- ------------- ----------- Gross profit $ (78,324) $ 26,083 $ 8,951 =========== ============= =========== Net income (loss) $ (103,360) $ 5,979 $ 2,140 =========== ============= ===========
Table continued on following page
Year Ended December 31, ----------------------------------------- 1999 1998 1997 ----------- ----------- ----------- (predecessor) AVERAGE DAILY VOLUMES (BARRELS): Pipeline Activities: All American Tariff activities 101 113 - Margin activities 56 50 - Other 61 - - ----------- ----------- ---------- Total 218 163 - =========== =========== ========== Lease gathering 265 88 71 Bulk purchases 138 98 49 ----------- ----------- ---------- Total 403 186 120 =========== =========== ========== Terminal throughput 83 80 77 =========== =========== ========== Storage leased to third parties, monthly average volumes 1,975 1,150 668 =========== =========== ==========
Pipeline Operations. Gross margin from pipeline operations was $58.0 million for the year ended December 31, 1999 compared to $16.8 million for 1998. The increase resulted from twelve months of results from the All American Pipeline in 1999 versus five months in 1998, increased margins from our pipeline merchant activities, and to the two 1999 acquisitions which contributed approximately $4.8 million of pipeline gross margin. The increase was partially offset by lower tariff transport volumes, due to lower production from Exxon's Santa Ynez Field and the Point Arguello Field, both offshore California.
The margin between revenue and direct cost of crude purchased was $33.5 million for the year ended December 31, 1999 compared to $3.9 million for 1998. Pipeline tariff revenues were approximately $46.4 million for the year ended December 31, 1999 compared to approximately $19.0 million for 1998. Pipeline operations and maintenance expenses were approximately $24.0 million for the year ended December 31, 1999 as compared to $6.1 million for 1998.
Tariff transport volumes on the All American Pipeline decreased from an average of 113,000 barrels per day for the year ended December 31, 1998 to 101,000 barrels per day in 1999 due primarily to a decrease in shipments of offshore California production, which decreased from 90,000 barrels per day in 1998 to 79,000 barrels per day in 1999. Barrels associated with our merchant activities on the All American Pipeline increased from 50,000 barrels per day in 1998 to 56,000 barrels per day for the year ended December 31, 1999. Tariff volumes shipped on the Scurlock and West Texas Gathering systems averaged 61,000 barrels per day during 1999.
In March 2000, we sold the segment of the All American Pipeline that extends from Emidio, California to McCamey, Texas. We initiated the sale of approximately 5.2 million barrels of crude oil linefill from the All American Pipeline in November 1999. The sale of the linefill was substantially complete in February 2000. We estimate that we will recognize a total gain of approximately $44.0 million in connection with the sale of the linefill. As of December 31, 1999, we had delivered approximately 1.8 million barrels of linefill and recognized a gain of $16.5 million. During 1999, we reported gross margin of approximately $5.0 million associated with operating the segment of the All American Pipeline that was sold. See "Capital Resources, Liquidity and Financial Condition".
The following table sets forth the All American Pipeline average deliveries per day within and outside California (in thousands):
Year Ended December 31, -------------- 1999 1998 ------ ------ Deliveries: Average daily volumes (barrels): Within California 101 111 Outside California 56 52 ------ ------ Total 157 163 ====== ======
Gathering and Marketing Activities and Terminalling and Storage Activities. Excluding the unauthorized trading losses, gross margin from terminalling and storage and gathering and marketing activities was approximately $52.3 million for the year ended December 31, 1999, reflecting a 141% increase over the $21.7 million reported for 1998 and a 319% increase over the $12.5 million reported for 1997. The increase in gross margin is due to an increase in lease gathering and bulk purchase volumes, primarily as a result of the Scurlock acquisition, which contributed approximately $26.3 million of 1999 gross margin, and an increase in storage capacity leased at our Cushing Terminal. Lease gathering volumes increased from an average of 88,000 and 71,000 barrels per day in 1998 and 1997, respectively, to approximately 265,000 barrels per day in 1999. Bulk purchase volumes increased from approximately 98,000 and 49,000 barrels per day for 1998 and 1997, respectively, to approximately 138,000 barrels per day this year. Leased terminal capacity increased significantly from approximately 1.1 and 0.7 million barrels per month in 1998 and 1997, respectively, to 2.0 million barrels per month during 1999. The 1.1 million barrel expansion of our Cushing Terminal was placed in service in the second quarter of 1999. Throughput volumes at our terminals increased approximately 3,000 and 6,000 barrels per day in the current year period from 1998 and 1997, respectively.
In the period immediately following the disclosure of the unauthorized trading losses, a significant number of our suppliers and trading partners reduced or eliminated the open credit previously extended to us. Consequently, the amount of letters of credit we needed to support the level of our crude oil purchases then in effect increased significantly. In addition, the cost to us of obtaining letters of credit increased under the amended credit facility. In many instances we arranged for letters of credit to secure our obligations to purchase crude oil from our customers, which increased our letter of credit costs and decreased our unit margins. In other instances, primarily involving lower margin wellhead and bulk purchases, our purchase contracts were terminated. As a result of these changes, aggregate volumes purchased are expected to decrease by 150,000 barrels per day, consisting primarily of lower unit margin purchases. Approximately 50,000 barrels per day of the decrease is related to barrels gathered at producer lease locations and 100,000 barrels per day is attributable to bulk purchases. As a result of the increase in letter of credit costs and reduced volumes, annual EBITDA is expected to be adversely affected by approximately $5.0 million, excluding the positive impact of current favorable market conditions.
General and administrative expenses were $22.2 million for the year ended December 31, 1999, compared to $5.3 million and $3.5 million for 1998 and 1997, respectively. Such increases were primarily attributable to the Scurlock and West Texas Gathering System acquisitions in 1999, the All American Pipeline acquisition in July 1998, continued expansion of our business activities and expenses related to the operation of the Plains All American Pipeline as a public entity. As a result of the unauthorized trading losses, we will incur additional expenses in 2000.
Depreciation and amortization expense was $17.3 million in 1999, $5.4 million in 1998 and $1.2 million in 1997. The increase in 1999 is due primarily to the Scurlock and West Texas Gathering System acquisitions in 1999 and the All American Pipeline acquisition in July 1998. The increase in 1998 is due to the All American Pipeline acquisition.
Interest expense was $21.1 million in 1999, $12.6 million in 1998 and $4.5 million in 1997. The increase in 1999 is due to (1) interest associated with the debt incurred for the Scurlock and West Texas Gathering System acquisitions, (2) a full year of interest for the All American Pipeline acquisition, (3) an increase in interest related to hedged inventory transactions and (4) an increase in interest rates as a result of the unauthorized trading losses. The increase in interest expense in 1998 is associated with the debt incurred for the acquisition of the All American Pipeline and the SJV Gathering System. Interest expense in 1997 is comprised principally of interest charged to our predecessor by Plains Resources for amounts borrowed to construct the Cushing Terminal and subsequent capital additions, including the Ingleside Terminal.
The extraordinary item of $1.5 million in 1999 relates to the write-off of certain debt issue costs and penalties incurred associated with the prepayment of debt. The prepayment of debt was made from the proceeds of our equity offering in October 1999. See - "Capital Resources, Liquidity and Financial Condition".
In 1999, we terminated 24 employees and paid approximately $1.4 million in connection therewith.
CAPITAL RESOURCES, LIQUIDITY AND FINANCIAL CONDITION
Unauthorized Trading Losses
In November 1999, we discovered that a former employee had engaged in unauthorized trading activity, resulting in losses of approximately $162.0 million ($174.0 million, including estimated associated costs and legal expenses). A full investigation into the unauthorized trading activities by outside legal counsel and independent accountants and consultants determined that the vast majority of the losses occurred from March through November 1999, and the impact warranted a restatement of previously reported financial information for 1999 and 1998 (see Note 3 in Notes to our consolidated and combined financial statements appearing elsewhere in this report).
Normally, as we purchase crude oil, we establish a margin by selling crude oil for physical delivery to third-party users or by entering into a future delivery obligation with respect to futures contracts. The employee in question violated our policy of maintaining a position that is substantially balanced between crude oil purchases and sales or future delivery obligations. The unauthorized trading and associated losses resulted in a default of certain covenants under our credit facilities and significant short-term cash and letter of credit requirements.
In December 1999, we executed amended credit facilities and obtained default waivers from all of our lenders. The amended credit facilities:
. waived defaults under covenants contained in the existing credit facilities; . increased availability under our letter of credit and borrowing facility from $175.0 million in November 1999 to $295.0 million in December 1999, $315.0 million in January 2000, and thereafter decreasing to $239.0 million in February through April 2000, to $225.0 million in May and June 2000 and to $200.0 million in July 2000 through July 2001; . required the lenders' consent prior to the payment of distributions to unitholders; . prohibited contango inventory transactions subsequent to January 20, 2000; and . increased interest rates and fees under certain of the facilities.
We paid approximately $13.7 million to our lenders in connection with the amended credit facilities. This amount was capitalized as debt issue costs and will be amortized over the remaining term of the amended facilities. In connection with the amendments, our general partner loaned us approximately $114.0 million. This subordinated debt is due not later than November 30, 2005.
We have taken appropriate and aggressive steps within our organization to enhance our processes and procedures to prevent future unauthorized trading. One of such steps includes the creation of a new professional risk management position. This risk manager has direct responsibility and authority for our trading controls and procedures and other aspects of corporate risk management. However, we can give no assurance that such steps will detect and prevent all violations of our trading policies and procedures, particularly if deception or other intentional misconduct is involved.
Public Offering
In October 1999, we completed a public offering of an additional 2,990,000 common units, representing limited partner interests, at $18.00 per unit. Net proceeds, including our general partners' contribution, were approximately $51.3 million after deducting underwriters' discounts and commissions and offering expenses of approximately $3.1 million. The proceeds, together with our general partner's capital contribution of approximately $0.5 million to maintain its 2% general partner interest, were used to reduce outstanding debt. Approximately $44.0 million was used to reduce the term loan portion of the Plains Scurlock bank credit agreement and the remainder was used to reduce the balance outstanding on our other revolving credit facility.
All American Pipeline Linefill Sale and Asset Disposition
We initiated the sale of approximately 5.2 million barrels of crude oil linefill from the All American Pipeline in November 1999. This sale was substantially completed in February 2000. The linefill was located in the segment of the All American Pipeline that extends from Emidio, California, to McCamey, Texas. Except for minor third party volumes, one of our subsidiaries has been the sole shipper on this segment of the pipeline since its predecessor acquired the line from the Goodyear Tire & Rubber Company in July 1998. Proceeds from the sale of the linefill were approximately $100.0 million, net of associated costs, and were used for working capital purposes. We estimate that we will recognize a total gain of approximately $44.0 million in connection with the sale of linefill. As of December 31, 1999, we had delivered approximately 1.8 million barrels of linefill and recognized a gain of $16.5 million.
On March 24, 2000, we completed the sale of the above referenced segment of the All American Pipeline to a unit of El Paso Energy Corporation for total proceeds of $129.0 million. The proceeds from the sale were used to reduce outstanding debt. Our net proceeds are expected to be approximately $124.0 million, net of associated transaction costs and estimated costs to remove certain equipment. We estimate that we will recognize a gain of approximately $20.0 million in connection with the sale. During 1999, we reported gross margin of approximately $5.0 million from volumes transported on the segment of the line that was sold.
Scurlock Acquisition
On May 12, 1999, Plains Scurlock Permian, L.P., a limited partnership of which Plains All American Inc. is the general partner and Plains Marketing, L.P. is the limited partner, completed the Scurlock acquisition. Including working capital adjustments and closing and financing costs, the cash purchase price was approximately $141.7 million. Financing for the Scurlock acquisition was provided through:
. borrowings of approximately $92.0 million under Plains Scurlock's limited recourse bank facility with BankBoston, N.A.; . the sale to our general partner of 1.3 million of our Class B common units for a total cash consideration of $25.0 million, or $19.125 per unit, the price equal to the market value of our common units on May 12, 1999; and . a $25.0 million draw under our existing revolving credit agreement.
The Class B common units are pari passu with common units with respect to quarterly distributions, and are convertible into common units upon approval of a majority of the common unitholders. The Class B unitholders may request that we call a meeting of common unitholders to consider approval of the conversion of Class B units into common units. If the approval of a conversion by the common unitholders is not obtained within 120 days of a request, each Class B unitholder will be entitled to receive distributions, on a per unit basis, equal to 110% of the amount of distributions paid on a common unit, with such distribution right increasing to 115% if such approval is not secured within 90 days after the end of the 120-day period. Except for the vote to approve the conversion, the Class B units have the same voting rights as the common units.
West Texas Gathering System Acquisition
On July 15, 1999, Plains Scurlock Permian, L.P. completed the acquisition of a West Texas crude oil pipeline and gathering system from Chevron Pipe Line Company for approximately $36.0 million, including transaction costs. Our total acquisition cost was approximately $38.9 million including costs to address certain issues identified in the due diligence process. The principal assets acquired include approximately 450 miles of crude oil transmission mainlines, approximately 400 miles of associated gathering and lateral lines and approximately 2.9 million barrels of crude oil storage and terminalling capacity in Crane, Ector, Midland, Upton, Ward and Winkler Counties, Texas. Financing for the amounts paid at closing was provided by a draw under the term loan portion of the Plains Scurlock credit facility.
Credit Agreements
Amounts outstanding under our credit agreements at December 31, 1999 were as follows (in thousands):
All American Pipeline, L.P. bank credit agreement $ 225,000 Plains Scurlock bank credit agreement 85,100 Plains Marketing, L.P. letter of credit and borrowing facility 13,719 Secured term credit facility 45,000 Subordinated note payable - general partner 114,000 --------- $ 482,819 =========
Concurrently with the closing of our initial public offering in November 1998, we entered into a $225.0 million bank credit agreement that includes a $175.0 million term loan facility and a $50.0 million revolving credit facility. As a result of the unauthorized trading losses discovered in November 1999, the facility was in default of certain covenants, with those defaults being subsequently waived and the facility amended in December. The bank credit agreement is secured by a lien on substantially all of our assets except the assets which secure the Plains Scurlock credit facility. We may borrow up to $50.0 million under the revolving credit facility for acquisitions, capital improvements, working capital and general business purposes. At December 31, 1999, we had $175.0 million outstanding under the term loan facility and $50.0 million outstanding under the revolving credit facility. The term loan facility matures in 2005, and no principal is scheduled for payment prior to maturity. The term loan facility may be prepaid at any time without penalty. The revolving credit facility expires in November 2000. The term loan and revolving credit facility bear interest at our option at either the base rate, as defined, plus an applicable margin, or reserve adjusted LIBOR plus an applicable margin. We incur a commitment fee on the unused portion of the revolving credit facility.
Plains Scurlock has a bank credit agreement which consists of a five-year $82.6 million term loan facility and a three-year $35.0 million revolving credit facility. The Plains Scurlock credit facility is nonrecourse to Plains All American Pipeline, Plains Marketing, L.P. and All American Pipeline, L.P. and is secured by substantially all of the assets of Plains Scurlock Permian, L.P. and its subsidiaries, including the Scurlock assets and the West Texas Gathering System. Borrowings
under the term loan and revolving credit facility bear interest at LIBOR plus the applicable margin. A commitment fee equal to 0.5% per year is charged on the unused portion of the revolving credit facility. The revolving credit facility, which may be used for borrowings or letters of credit to support crude oil purchases, matures in May 2002. The term loan provides for principal amortization of $0.7 million annually beginning May 2000, with a final maturity in May 2004. As of December 31, 1999, letters of credit of approximately $29.5 million were outstanding under the revolver and borrowings of $82.6 million and $2.5 million were outstanding under the term loan and revolver, respectively. The term loan was reduced to $82.6 million from $126.6 million with proceeds from our October 1999 public unit offering.
We have a letter of credit and borrowing facility, the purpose of which is to provide standby letters of credit to support the purchase and exchange of crude oil for resale and borrowings to finance crude oil inventory which has been hedged against future price risk or designated as working inventory. As a result of the unauthorized trading losses discovered in November 1999, the facility was in default of certain covenants, with those defaults being subsequently waived and the facility amended in December 1999. As amended, the letter of credit facility has a sublimit for cash borrowings of $40.0 million at December 31, 1999, with decreasing amounts thereafter through April 30, 2000, at which time the sublimit is eliminated. The letter of credit and borrowing facility provides for an aggregate letter of credit availability of $295.0 million in December 1999, $315.0 million in January 2000, and thereafter decreasing to $239.0 million in February through April 2000, to $225.0 million in May and June 2000, and to $200.0 million in July 2000 through July 2001. Aggregate availability under the letter of credit facility for direct borrowings and letters of credit is limited to a borrowing base which is determined monthly based on certain of our current assets and current liabilities, primarily accounts receivable and accounts payable related to the purchase and sale of crude oil. This facility is secured by a lien on substantially all of our assets except the assets which secure the Plains Scurlock credit facility. At December 31, 1999, there were letters of credit of approximately $292.0 million and borrowings of $13.7 million outstanding under this facility.
On December 30, 1999, we entered into a $65.0 million senior secured term credit facility to fund short-term working capital requirements resulting from the unauthorized trading losses. The facility was secured by a portion of the 5.2 million barrels of linefill that was sold and receivables from certain sales contracts applicable to the linefill. The facility had a maturity date of March 24, 2000 and was repaid with the proceeds from the sale of the linefill securing the facility. At December 31, 1999, there were borrowings of $45.0 million outstanding.
All of our credit agreements contain prohibitions on distributions on, or purchases or redemptions of, units if any default or event of default is continuing. In addition, our facilities contain various covenants limiting our ability to:
. incur indebtedness; . grant liens; . sell assets in excess of certain limitations; . engage in transactions with affiliates; . make investments; . enter into hedging contracts; and . enter into a merger, consolidation or sale of assets.
Each of our facilities treats a change of control as an event of default. In addition, the terms of our letter of credit and borrowing facility and our bank credit agreement require lenders' consent prior to the payment of distributions to unitholders and require us to maintain:
. a current ratio of 1.0 to 1.0: . a debt coverage ratio which is not greater than 5.0 to 1.0; . an interest coverage ratio which is not less than 3.0 to 1.0; . a fixed charge coverage ratio which is not less than 1.25 to 1.0; and . a debt to capital ratio of not greater than 0.60 to 1.0.
The terms of the Plains Scurlock bank credit agreement require Plains Scurlock to maintain at the end of each quarter:
. a debt coverage ratio of 6.0 to 1.0 from October 1, 1999 through June 30, 2000; 5.0 to 1.0 from July 1, 2000 through June 30, 2001; and 4.0 to 1.0 thereafter; and . an interest coverage ratio of 2.0 to 1.0 from October 1, 1999 through June 30, 2000 and 2.5 to 1.0 thereafter.
In addition, the Plains Scurlock bank credit agreement contains limitations on the Plains Scurlock operating partnership's ability to make distributions to us if its indebtedness and current liabilities exceed certain levels as well as the amount of expansion capital it may expend.
In December 1999, our general partner loaned us $114.0 million. This subordinated debt is due not later than November 30, 2005. Proceeds from the notes were used for working capital requirements created by the unauthorized trading losses. The notes are subordinated in right of payment to all existing senior indebtedness and bear interest at the same LIBOR rate as our letter of credit and borrowing facility. Interest on the notes is payable monthly, but payment of interest requires the permission of certain of our lenders. Any interest not paid when due is added to the principal of the notes, at the option of our general partner.
We are currently in discussions with our lenders to restructure and consolidate our various credit facilities. If completed, this will enable us to increase our current bank credit facilities (excluding short-term credit facility and the letter of credit and borrowing facility) from total capacity of approximately $342.6 million to approximately $350.0 million. In addition, we are in discussions to restructure and increase the size of our letter of credit and borrowing facility, which will provide us the ability to enter into contango inventory transactions. Although there can be no assurance we will be successful in restructuring the facilities, we believe these facilities, combined with cash flow from operating activities and the sale of the linefill and segment of the All American Pipeline, will provide us with additional flexibility and liquidity, including liquidity required to meet our obligations and to make distributions to our unitholders.
Cash Flows Year Ended December 31, ---------------------------------------- (in millions) 1999 1998 1997 ----------------------------------------------------------------- (restated) (predecessor) (combined) (unaudited) Cash provided by (used in): Operating activities $ (106.2) $ 29.8 $ (12.9) Investing activities (186.1) (402.7) (1.9) Financing activities 340.5 386.4 14.3 -----------------------------------------------------------------
Operating Activities. Net cash used in operating activities in 1999 resulted from the unauthorized trading losses. The losses were partially offset by increased margins due to the Scurlock and West Texas Gathering System acquisitions.
Investing Activities. Net cash used in investing activities for 1999 included approximately $177.0 million for acquisitions, primarily for the Scurlock and West Texas gathering system, $10.9 million for expansion capital and $1.7 million for maintenance capital. Approximately $5.0 million and $4.2 million, respectively, related to the Cushing terminal expansion is included in expansion capital expenditures for 1999 and 1998, respectively. Net cash used in investing activities for 1998 consisted primarily of approximately $394.0 million for the purchase of the All American Pipeline and SJV Gathering System. We estimate that capital expenditures necessary to maintain our existing asset base at current operating levels will be approximately $4.0 million to $5.0 million each year.
Financing activities. Cash provided by financing activities in 1999 was generated from net issuances of (1) $76.5 million in common and Class B units, (2) $184.1 million of short-term and long-term debt and (3) $114.0 million of two subordinated notes to our general partner. Cash inflows from financing activities during 1998 included (1) $283.8 million from the net issuance of short-term and long-term debt and (2) a capital contribution of approximately $113.7 million from our general partner primarily in connection with the acquisition of the All American Pipeline and SJV Gathering System.
Subject to the consent of our lenders, we will distribute 100% of our available cash within 45 days after the end of each quarter to unitholders of record and to our general partner. Available cash is generally defined as all of our cash and cash equivalents on hand at the end of the quarter less reserves established by our general partner for future requirements. Minimum quarterly distributions are $0.45 for each full fiscal quarter. Distributions of available cash to the holders of subordinated units are subject to the prior rights of the holders of common units to receive the minimum quarterly distributions for each quarter during the subordination period, and to receive any arrearages in the distribution of minimum quarterly distributions on the common units for prior quarters during the subordination period. The expiration of the subordination period will generally not occur prior to December 31, 2003.
Cash distributions paid to unitholders on our outstanding common units, Class B units and subordinated units in 1999 were $51.7 million. Included in this amount is $5.9 million representing distributions for the period from our inception, November 23, 1998 through December 31, 1998. On February 14, 2000, we paid a cash distribution of $0.45 per unit on our outstanding common units and Class B units. The distribution was paid to unitholders of record on February 7, 2000 for the period covering October 1, 1999 through December 31, 1999. The total distribution paid was approximately $11.2 million, with approximately $7.2 million paid to our public unitholders and the remainder paid to our general partner for its limited and general partner interests. We received the requisite consent from our lenders to pay the fourth quarter distribution. No distribution was declared on the subordinated units owned by our general partner.
Contingencies
Since our announcement in November 1999 of our losses resulting from unauthorized trading by a former employee, numerous class action lawsuits have been filed against us, certain of our general partner's officers and directors and in some of these cases, our general partner and Plains Resources Inc. alleging violations of the federal securities laws. In addition, derivative lawsuits were filed in the Delaware Chancery Court against our general partner, its directors and certain of its officers alleging the defendants breached the fiduciary duties owed to us and our unitholders by failing to monitor properly the activities of our traders. See Item 3. - "Legal Proceedings".
We may experience future releases of crude oil into the environment from our pipeline and storage operations, or discover releases that were previously unidentified. While we maintain an extensive inspection program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to any future environmental releases from our assets may substantially affect our business.
RECENT ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities ("SFAS 133"). SFAS 133 requires that all derivative instruments be recorded on the balance sheet at their fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and, if so, the type of hedge transaction. For fair value hedge transactions in which we are hedging changes in an asset's, liability's, or firm commitment's fair value, changes in the fair value of the derivative instrument will generally be offset in the income statement by changes in the hedged item's fair value. For cash flow hedge transactions, in which we are hedging the variability of cash flows related to a variable-rate asset, liability, or a forecasted transaction, changes in the fair value of the derivative instrument will be reported in other comprehensive income. The gains and losses on the derivative instrument that are reported in other comprehensive income will be reclassified as earnings in the periods in which earnings are affected by the variability of the cash flows of the hedged item. This statement was amended by Statement of Financial Accounting Standards No. 137, Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133 ("SFAS 137") issued in June 1999. SFAS 137 defers the effective date of SFAS 133 to fiscal years beginning after June 15, 2000. We are required to adopt this statement beginning in 2001. We have not yet determined the effect that the adoption of SFAS 133 will have on our financial position or results of operations.
YEAR 2000
Year 2000 Project. In order to address the Year 2000 issue, we initiated a Year 2000 project. We incurred approximately $0.8 million through December 31, 1999, in connection with our Year 2000 project, approximately $0.4 million of which were costs paid to third parties. We did not encounter any critical system application, hardware or equipment failures during the date roll over to the Year 2000, and have not experienced any disruptions of business activities as a result of Year 2000 failures by our customers, suppliers, service providers or business partners.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
We are exposed to various market risks, including volatility in crude oil commodity prices and interest rates. To manage such exposure, we monitor our inventory levels, current economic conditions and our expectations of future commodity prices and interest rates when making decisions with respect to risk management. We do not enter into derivative transactions for speculative trading purposes. Substantially all of our derivative contracts are exchanged or traded with major financial institutions and the risk of credit loss is considered remote.
Commodity Price Risk. The fair value of outstanding derivative instruments and the change in fair value that would be expected from a 10 percent adverse price change are shown in the table below (in millions):
DECEMBER 31, ------------------------------------------------ 1999 1998 --------------------- --------------------- 10% 10% Adverse Adverse Fair Price Fair Price Value Change Value Change ------- -------- --------- ------- Crude oil : Futures contracts $ - $ (2.8) $ 1.8 $ (0.3) Swaps and options contracts (0.6) (0.1) - -
The fair values of the futures contracts are based on quoted market prices obtained from the NYMEX. The fair value of the swaps are estimated based on quoted prices from independent reporting services compared to the contract price of the swap which approximate the gain or loss that would have been realized if the contracts had been closed out at year end. All hedge positions offset physical positions exposed to the cash market; none of these offsetting physical positions are included in the above table. Price-risk sensitivities were calculated by assuming an across-the-board 10 percent adverse change in prices regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of an actual 10 percent change in prompt month crude prices, the fair value of our derivative portfolio would typically change less than that shown in the table due to lower volatility in out-month prices.
Interest Rate Risk. Our debt instruments are sensitive to market fluctuations in interest rates. The table below presents principal payments and the related weighted average interest rates by expected maturity dates for debt outstanding at December 31, 1999. Our variable rate debt bears interest at LIBOR plus the applicable margin. The average interest rates presented below are based upon rates in effect at December 31, 1999. The carrying value of variable rate bank debt approximates fair value as interest rates are variable, based on prevailing market rates (dollars in millions).
At December 31, 1998, the carrying value of short-term and long-term debt of $9.7 million and $175.0 million, respectively, approximated fair value.
Interest rate swaps and collars are used to hedge underlying debt obligations. These instruments hedge 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 December 31, 1999, we had interest rate swap and collar arrangements for an aggregate notional principal amount of $215.0 million, which positions had an aggregate value of approximately $0.4 million as of such date. These instruments are based on LIBOR margins and generally provide for a floor of 5% and a ceiling of 6.5% for $90.0 million of debt and a floor of 6% and a ceiling of 8% for $125.0 million of debt. In August 1999, we terminated our swap arrangements on an aggregate notional principal amount of $175.0 million and we received consideration in the amount of approximately $10.8 million.
At December 31, 1998, we had an interest rate swap arrangement for an aggregate notional principal amount of $175.0 million and would have been required to pay approximately $2.2 million to terminate the instrument at that date.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required here is included in the report as set forth in that "Index to Financial Statements" on page.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF OUR GENERAL PARTNER
PARTNERSHIP MANAGEMENT
Our general partner manages our operations and activities. Unitholders do not directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to the unitholders. As a general partner, our general partner is liable for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically non-recourse to it. Whenever possible, our general partner intends to incur indebtedness or other obligations on a non-recourse basis.
Two members of the board of directors of our general partner serve on a conflicts committee that reviews specific matters that the board believes may involve conflicts of interest between our general partner and Plains All American Pipeline. The conflicts committee determines if the resolution of a conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties owed to us. In addition, the members of the conflicts committee also serve on an audit committee which reviews our external financial reporting, recommends engagement of our independent auditors and reviews procedures for internal auditing and the adequacy of our internal accounting controls.
As is commonly the case with publicly-traded limited partnerships, we are managed and operated by the officers and are subject to the oversight of the directors of our general partner. Most of our operational personnel are employees of our general partner.
Some officers of our general partner may spend a substantial amount of time managing the business and affairs of Plains Resources and its affiliates. These officers may face a conflict regarding the allocation of their time between our business and the other business interests of Plains Resources. Our general partner intends to cause its officers to devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs.
DIRECTORS AND EXECUTIVE OFFICERS OF OUR GENERAL PARTNER
The following table sets forth certain information with respect to the executive officers and members of the Board of Directors of our general partner. Executive officers and directors are elected for one year terms.
Greg L. Armstrong has served as Chairman of the Board, Chief Executive Officer and Director of our general partner since its formation. In addition, he has been President, Chief Executive Officer and Director of Plains Resources since 1992. He previously served Plains Resources as: President and Chief Operating Officer from October to December 1992; Executive Vice President and Chief Financial Officer from June to October 1992; Senior Vice President and Chief Financial Officer from 1991 to 1992; Vice President and Chief Financial Officer from 1984 to 1991; Corporate Secretary from 1981 to 1988; and Treasurer from 1984 to 1987.
Harry N. Pefanis has served as President, Chief Operating Officer and Director of our general partner since its formation. In addition, he has been Executive Vice President - Midstream of Plains Resources since May 1998. He previously served Plains Resources as: Senior Vice President from February 1996 until May 1998; Vice President - Products Marketing from 1988 to February 1996; Manager of Products Marketing from 1987 to 1988; and Special Assistant for Corporate Planning from 1983 to 1987. Mr. Pefanis was also President of the Plains Midstream Subsidiaries until the formation of Plains All American Pipeline.
Phillip D. Kramer has served as Executive Vice President and Chief Financial Officer of our general partner since its formation. In addition, he has been Executive Vice President, Chief Financial Officer and Treasurer of Plains Resources since May 1998. He previously served Plains Resources as: Senior Vice President, Chief Financial Officer and Treasurer from May 1997 until May 1998; Vice President, Chief Financial Officer and Treasurer from 1992 to 1997; Vice President and Treasurer from 1988 to 1992; Treasurer from 1987 to 1988; and Controller from 1983 to 1987.
George R. Coiner has served as Senior Vice President of our general partner since its formation. In addition, he was Vice President of Plains Marketing & Transportation Inc., a Plains Midstream Subsidiary, since November 1995. Prior to joining Plains Marketing & Transportation Inc., he was Senior Vice President, Marketing with Scurlock Permian Corp.
Michael R. Patterson has served as Senior Vice President, General Counsel and Secretary of our general partner since its formation. In addition, he has been Vice President, General Counsel and Secretary of Plains Resources since 1988. He previously served Plains Resources as Vice President and General Counsel from 1985 to 1988.
Michael J. Latiolais has served as Vice President - Administration of our general partner since August 1999 and as Controller of our general partner from July 1998 through August 1999. In addition, he was Vice President and Controller for All American Pipeline Company, Celeron Gathering Corporation and Celeron Trading & Transportation Company from 1994 until such companies were merged into the operating partnerships of Plains All American Pipeline. He served as Controller of such companies from 1985 to 1994.
Mark F. Shires has served as Vice President - Operations of our general partner since August 1999. He served as Manager of Operations for our general partner from April 1999 until August 1999 when he was elected to his current position. In addition, he was a business consultant from 1996 until April 1999. He served as a consultant to Plains Marketing & Transportation Inc. and Plains All American Pipeline from May 1998 until April 1999. He previously served as President of Plains Terminal & Transfer Corporation, a Plains Midstream Subsidiary, from 1993 to 1996.
Cynthia A. Feeback has served as Treasurer of our general partner since its formation. In addition, she has been Vice President - Accounting and Assistant Treasurer of Plains Resources since May 1999. She previously served Plains Resources as Assistant Treasurer, Controller and Principal Accounting Officer from May 1998 to May 1999; Controller and Principal Accounting Officer from 1993 to 1998; Controller from 1990 to 1993; and Accounting Manager from 1988 to 1990.
Everardo Goyanes has served as a Director and a member of Audit and Conflicts Committees since May 1999. Mr. Goyanes is a financial consultant specializing in natural resources. From 1989 to 1998, he was Managing Director of the Natural Resources Group of ING Baring Furman Selz (a commercial banking firm). He was a financial consultant from 1987 to 1989 and was Vice President - Finance of Forest Oil Corporation from 1983 to 1987.
Robert V. Sinnott has served as a Director and a member of Audit and Compensation Committees since September 1998. Mr. Sinnott has been Vice President of Kayne Anderson Investment Management, Inc. (an investment management firm) since 1992. He was Vice President and Senior Securities Officer of the Investment Banking Division of Citibank from 1986 to 1992. He is also a director of Plains Resources and Glacier Water Services, Inc. (a vended water company).
Arthur L. Smith has served as a Director and a member of Audit, Conflicts and Compensation Committees since February 1999. Mr. Smith is Chairman of John S. Herold, Inc. (a petroleum research and consulting firm), a position he has held since 1984. For the period from May 1998 to October 1998, he served as Chairman and Chief Executive Officer of Torch Energy Advisors Incorporated. He is also a director of Cabot Oil & Gas Corporation. Mr. Smith served as a director of Pioneer Natural Resources Company from 1997 to 1998 and of Parker & Parsley Petroleum Company from 1991 to 1997.
SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Securities and Exchange Act of 1934 requires directors, officers and persons who beneficially own more than ten percent of a registered class of our equity securities to file with the SEC and the New York Stock Exchange initial reports of ownership and reports of changes in ownership of such equity securities. Such persons are also required to
furnish us with copies of all Section 16(a) forms that they file. Based solely upon a review of the copies of Forms 3, 4 and 5 furnished to us, or written representations from certain reporting persons that no Forms 5 were required, we believe that during 1999 our officers and directors complied with all filing requirements with respect to our equity securities.
REIMBURSEMENT OF EXPENSES OF OUR GENERAL PARTNER AND ITS AFFILIATES
Our general partner does not receive any management fee or other compensation in connection with its management of Plains All American Pipeline. However, our general partner and its affiliates, including Plains Resources, perform services for us and are reimbursed by us for all expenses incurred on our behalf, including the costs of employee, officer and director compensation and benefits properly allocable to us, as well as all other expenses necessary or appropriate to the conduct of our business and properly allocable to us. The partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
We were formed in September 1998 but conducted no business until late November 1998. Accordingly, prior to 1999, no officer of our general partner received salary and bonus compensation for services to the partnership in excess of $100,000. Messrs. Armstrong, Pefanis, Kramer and Patterson and Ms. Feeback are compensated by Plains Resources and do not receive compensation from our general partner with the exceptions of awards to Messrs. Armstrong and Pefanis under the Long-Term Incentive Plan and the Transaction Grant Agreements described below. However, we reimburse our general partner and its affiliates, including Plains Resources for expenses incurred on our behalf, including the costs of officer compensation properly allocable to us. See Item 13. - "Certain Relationships and Related Transactions - Relationship with Plains Resources". The following table sets forth certain compensation information for all executive officers of our general partner who received salary and bonus compensation from our general partner in excess of $100,000 in 1999 (the "Named Executive Officers").
- ---------- (1) Paid under Management Incentive Plan. See " - Management Incentive Plan" below. (2) Represents the value of 11,111 common units as of December 31, 1999 plus distribution equivalent rights with respect to such units, which vested under the Transaction Grant Agreement. See - "Transaction Grant Agreements" below. (3) Plains Resources matches 100% of an employee's contribution to its 401(k) Plan (subject to certain limitations in the plan), with such matching contribution being made 50% in cash and 50% in Plains Resources Common Stock (the number of shares for the stock match being based on the market value of the Common Stock at the time the shares are granted). (4) Represents reimbursement of moving and relocation expenses. (5) Includes $51,000 for consulting fees we paid to Mr. Shires prior to his becoming an employee of our general partner in April 1999.
EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT AND CHANGE-IN-CONTROL ARRANGEMENTS
Plains Resources has an employment agreement with Mr. Armstrong which expires on March 1, 2002 (unless extended pursuant to the terms thereof) and provides for a current base salary of $330,000 per year, subject to annual review. If Mr. Armstrong's employment is terminated without cause, he will be entitled to receive an amount equal to two times his annual base salary. If his employment is terminated as a result of a change in control of Plains Resources, he will be entitled to receive an amount equal to three times the aggregate of his annual base salary and bonus. In either event, Mr. Armstrong will be entitled to receive medical benefits for two years following the date of his termination. Under Mr. Armstrong's agreement, a change in control of Plains Resources is defined as the directors in office on the date of the agreement ceasing to constitute a majority of the Board of Directors of Plains Resources.
Plains Resources also has an employment agreement with Mr. Pefanis, under which Mr. Pefanis serves as Executive Vice President of Plains Resources as well as President and Chief Operating Officer of our general partner and is responsible for our overall operations. The employment agreement provides that Plains Resources will not require Mr. Pefanis to engage in activities that materially detract from his duties and responsibilities as an officer of our general partner. The initial term of the employment agreement runs through November 23, 2001, subject to annual extensions and includes confidentiality, nonsolicitation and noncompete provisions, which, in general, will continue for two years following termination of Mr. Pefanis' employment. The employment agreement provides for an annual base salary of $235,000, subject to annual review. If Mr. Pefanis' employment is terminated without cause, he will be entitled to receive an amount equal to two times his base salary. Upon a Change in Control of Plains Resources or a Marketing Operations Disposition (as such terms are defined in the employment agreement), the term of the employment agreement will be automatically extended for three years, and if Mr. Pefanis' employment is terminated during the one-year period following either event by him for a Good Reason or by Plains Resources other than for death, disability or Cause (as such terms are defined in the employment agreement), he will be entitled to a lump sum severance amount equal to three times the sum of (1) his highest rate of annual base salary and (2) the largest annual bonus paid during the three preceding years.
Long-Term Incentive Plan
Our general partner has adopted the Plains All American Inc. 1998 Long-Term Incentive Plan for employees and directors of our general partner and its affiliates who perform services for us. The Long-Term Incentive Plan consists of two components, a restricted unit plan and a unit option plan. The Long-Term Incentive Plan currently permits the grant of restricted units and unit options covering an aggregate of 975,000 common units. The plan is administered by the Compensation Committee of our general partner's board of directors.
Restricted Unit Plan. A restricted unit is a "phantom" unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit. As of March 15, 2000, an aggregate of approximately 500,000 restricted units have been authorized for grants to employees of our general partner, 170,000 of which have been granted with the remaining 330,000 to be granted in the near future. Grants made include 60,000, 30,000 and 12,500 units to Messrs. Pefanis, Coiner and Latiolais, respectively. The Compensation Committee may, in the future, make additional grants under the plan to employees and directors containing such terms as the Compensation Committee shall determine. In general, restricted units granted to employees during the subordination period will vest only upon, and in the same proportions as, the conversion of the subordinated units to common units. Grants made to non-employee directors of our general partner will be eligible to vest prior to termination of the subordination period.
If a grantee terminates employment or membership on the board for any reason, the grantee's restricted units will be automatically forfeited unless, and to the extent, the Compensation Committee provides otherwise. Common units to be delivered upon the vesting of rights may be common units acquired by our general partner in the open market, common units already owned by our general partner, common units acquired by our general partner directly from us or any other person, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units upon vesting of the restricted units, the total number of common units outstanding will increase. Following the subordination period, the Compensation Committee, in its discretion, may grant tandem distribution equivalent rights with respect to restricted units.
The issuance of the common units pursuant to the restricted unit plan is primarily intended to serve as a means of incentive compensation for performance. Therefore, no consideration will be paid to us by the plan participants upon receipt of the common units.
Unit Option Plan. The Unit Option Plan currently permits the grant of options covering common units. No grants have been made under the Unit Option Plan to date. However, the Compensation Committee may, in the future, make grants under the plan to employees and directors containing such terms as the committee shall determine, provided that unit options have an exercise price equal to the fair market value of the units on the date of grant. Unit options granted during the subordination period will become exercisable automatically upon, and in the same proportions as, the conversion of the subordinated units to common units, unless a later vesting date is provided.
Upon exercise of a unit option, our general partner will deliver common units acquired by it in the open market, purchased directly from us or any other person, or use common units already owned by our general partner, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the difference between the cost incurred by our general partner in acquiring such common units and the proceeds received by our general partner from an optionee at the time of exercise. Thus, the cost of the unit options will be borne by us. If we issue new common units upon
exercise of the unit options, the total number of common units outstanding will increase, and our general partner will remit to us the proceeds received by it from the optionee upon exercise of the unit option.
The unit option plan has been designed to furnish additional compensation to employees and directors and to align their economic interests with those of the common unitholders. Our general partner's board of directors in its discretion may terminate the Long-Term Incentive Plan at any time with respect to any common units for which a grant has not yet been made. Our general partner's board of directors also has the right to alter or amend the Long-Term Incentive Plan or any part of the plan from time to time, including increasing the number of common units with respect to which awards may be granted; provided, however, that no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of such participant.
TRANSACTION GRANT AGREEMENTS
In addition to the grants made under the Restricted Unit Plan described above, our general partner, at no cost to us, agreed to transfer approximately 400,000 of its affiliates' common units (including distribution equivalent rights attributable to such units) to certain key employees of our general partner. A grant covering 50,000 of such common units was terminated in 1999. Generally, approximately 69,444 of the remaining common units vest in each of the years ending December 31, 1999, 2000 and 2001 if the operating surplus generated in such year equals or exceeds the amount necessary to pay the minimum quarterly distribution on all outstanding common units and the related distribution on the general partner interest. If a tranche of common units does not vest in a particular year due to a common unit arrearage, such common units will vest at the time the common unit arrearages for such year have been paid. In addition, approximately 47,224 of the remaining common units vest in each of the years ending December 31, 1999, 2000 and 2001 if the operating surplus generated in such year exceeds the amount necessary to pay the minimum quarterly distribution on all outstanding common units and subordinated units and the related distribution on the general partner interest. In 1999, approximately 69,444 of such common units vested and 47,224 of such common units remain unvested as no distribution on the subordinated units was made for the fourth quarter of 1999. Any common units remaining unvested shall vest upon, and in the same proportion as, the conversion of subordinated units to common units. Distribution equivalent rights are paid in cash at the time of the vesting of the associated common units. Notwithstanding the foregoing, all common units become vested if Plains All American Inc. is removed as our general partner prior to January 1, 2002.
The compensation expense incurred in connection with these grants will be funded by our general partner, without reimbursement by us. Under these grants, 75,000 common units were allocated to each of Messrs. Armstrong and Pefanis and 50,000 common units were allocated to Mr. Coiner.
MANAGEMENT INCENTIVE PLAN
Our general partner has adopted the Plains All American Inc. Management Incentive Plan. The Management Incentive Plan is designed to enhance the performance of our general partner's key employees by rewarding them with cash awards for achieving quarterly and/or annual financial performance objectives. The Management Incentive Plan is administered by the Compensation Committee. Individual participants and payments, if any, for each fiscal quarter and year are determined by and in the discretion of the Compensation Committee. Any incentive payments are at the discretion of the Compensation Committee, and our general partner may amend or change the Management Incentive Plan at any time. Our general partner is entitled to reimbursement by us for payments and costs incurred under the plan.
COMPENSATION OF DIRECTORS
Each director of our general partner who is not an employee of our general partner is paid an annual retainer fee of $20,000, an attendance fee of $2,000 for each board meeting he attends (excluding telephonic meetings), an attendance fee of $500 for each committee meeting or telephonic board meeting he attends plus reimbursement for related out-of-pocket expenses. Messrs. Armstrong and Pefanis, as officers of our general partner, are otherwise compensated for their services to our general partner and therefore receive no separate compensation for their services as directors of our general partner.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth the beneficial ownership of units held by beneficial owners of 5% or more of the units, by directors and officers of our general partner and by all directors and executive officers of our general partner as a group as of March 15, 2000.
(1) Plains Resources Inc. is the sole stockholder of Plains All American Inc., our general partner. The address of Plains Resources Inc. is 500 Dallas, Suite 700, Houston, Texas 77002. (2) The address of Plains All American Inc. is 500 Dallas, Suite 700, Houston, Texas 77002. The record holder of such common units and subordinated units is PAAI LLC, a wholly-owned subsidiary of Plains All American Inc., whose address is 500 Dallas, Suite 700, Houston, Texas 77002. (3) Includes 280,556 common units owned by affiliates of our general partner to be transferred to employees pursuant to transaction grant agreements, subject to certain vesting conditions. The recipients and their initial grants included: Mr. Armstrong - 75,000 (8,333 units currently vested); Mr. Pefanis - 75,000 (16,667 units currently vested); and Mr. Coiner - 50,000 (11,111 units currently vested). See Item 11. - "Executive Compensation - Transaction Grant Agreements". (4) The address for Goldman, Sachs & Co. and its parent, the Goldman Sachs Group, Inc., is 85 Broad Street, New York, New York 10004. Goldman, Sachs & Co., a broker/dealer, and its parent, the Goldman Sachs Group, Inc., are deemed to have shared voting power and shared disposition power over 1,278,325 common units owned by their customers. (5) Includes the following unvested common units issuable under the Long-Term Incentive Plan to: Mr. Pefanis - 60,000; Mr. Coiner - 30,000; and Mr. Latiolais - 12,500. See Item 11. - "Executive Compensation - Long-Term Incentive Plan." (6) Less than one percent. (7) Assumes the vesting of the units granted pursuant to the transaction grant agreements and under the long-term incentive plan as described in footnotes (3) and (5) above to the named officers and directors. See Item 11. - "Executive Compensation - Long-Term Incentive Plan" for vesting conditions of these grants.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
RIGHTS OF OUR GENERAL PARTNER
Our general partner and its affiliates own 8,211,985 common units, including 1,307,190 Class B common units, and 10,029,619 subordinated units, representing an aggregate 52.5% limited partner interest in the Plains All American Pipeline. In addition, our general partner owns an aggregate 2% general partner interest in Plains All American Pipeline and the operating partnerships on a combined basis. Through our general partner's ability, as general partner, to manage and operate Plains All American Pipeline and the ownership of 8,211,985 common units, including 1,307,190 Class B common units, and all of the outstanding subordinated units by our general partner and its affiliates (effectively giving our general partner the ability to veto certain actions of Plains All American Pipeline), our general partner has the ability to control the management of Plains All American Pipeline.
RELATIONSHIP WITH PLAINS RESOURCES
General
Plains Resources controls our general partner, which is its wholly-owned subsidiary. We have extensive ongoing relationships with Plains Resources. These relationships include but are not limited to:
. an Omnibus Agreement that provides for (1) the resolution of certain conflicts arising from the fact that we and Plains Resources conduct related businesses and (2) our general partner's indemnification of us for certain matters; and . a Marketing Agreement with Plains Resources that provides for the marketing of Plains Resources' equity crude oil production.
Transactions with Affiliates
On May 12, 1999, Plains Scurlock Permian, L.P., a limited partnership of which Plains All American Inc. is our general partner and Plains Marketing, L.P. is the limited partner, completed the acquisition of Scurlock Permian LLC from Marathon Ashland Petroleum LLC. See Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources, Liquidity and Financial Condition". To finance a portion of the purchase price, we sold 1.3 million Class B common units to our general partner at $19.125 per unit, the market value of our common units on May 12, 1999.
The Class B units are initially pari passu with common units with respect to distributions, and are convertible into common units upon approval of a majority of the common unitholders. The Class B unitholders may request that we call a meeting of common unitholders to consider approval of the conversion of Class B units into common units. If the approval of a conversion by the common unitholders is not obtained within 120 days of a request, each Class B unitholder will be entitled to receive distributions, on a per unit basis, equal to 110% of the amount of distributions paid on a common unit, with such distribution right increasing to 115% if such approval is not secured within 90 days after the end of the 120-day period. Except for the vote to approve the conversion, Class B units have the same voting rights as the common units.
For the year ended December 31, 1999, Plains Resources produced approximately 20,400 barrels per day which were subject to the Marketing Agreement. We paid approximately $131.5 million for such production and recognized profits of approximately $1.5 million under the terms of that agreement.
Our general partner has sole responsibility for conducting our business and managing our operations and owns all of the incentive distribution rights. Some of the senior executives who currently manage our business also manage and operate the business of Plains Resources. Our general partner does not receive any management fee or other compensation in connection with its management of our business, but it is reimbursed for all direct and indirect expenses incurred on our behalf. For the year ended December 31, 1999, our general partner and its affiliates incurred $44.7 million of direct and indirect expenses on our behalf. Of this amount, $142,000 and $212,000 represented reimbursement for the services of Messrs. Armstrong and Pefanis, respectively, as officers of our general partner.
In December 1999, following the losses we incurred as a result of the unauthorized trading activity by a former employee, our general partner loaned us approximately $114.0 million. This subordinated debt is due not later than November 30, 2005. Funding to our general partner for these loans was provided by Plains Resources. See Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources, Liquidity and Financial Condition".
Indemnity from Our General Partner
In connection with the acquisition of the All American Pipeline and the SJV Gathering System in July 1998, Wingfoot agreed to indemnify our general partner for certain environmental and other liabilities. The indemnity is subject to limits of:
. $10.0 million with respect to matters of corporate authorization and title to shares; . $21.5 million with respect to condition of rights-of-way, lease rights and undisclosed liabilities and litigation; and . $30.0 million with respect to environmental liabilities resulting from certain undisclosed and pre-existing conditions.
Wingfoot has no liability, however, until the aggregate amount of losses, with respect to each such category exceeds $1.0 million. These indemnities will remain in effect until July 2000, with the exception of the environmental indemnity, which will remain in effect until July 2001. However, upon the transfer to an unaffiliated third party of a major portion of the assets acquired from Wingfoot, the indemnities automatically terminate. The environmental indemnity is also subject to certain sharing ratios which change based on whether the claim is made in the first, second or third year of the indemnity as well as the amount of such claim. We have also agreed to be solely responsible for the cumulative aggregate amount of losses resulting from the oil leak from the All American Pipeline to the extent such losses do not exceed $350,000. Any costs in excess of $350,000 will be applied to the $1.0 million deductible for the Wingfoot environmental indemnity. Our general partner has agreed to indemnify us for environmental and other liabilities to the extent it is indemnified by Wingfoot. However, if the sale of the linefill from the All American Pipeline and the subsequent sale of such pipeline to EPNG Pipeline Company are construed to constitute a sale of a major portion of the assets acquired from Wingfoot, the indemnities by Wingfoot will terminate. See Items 1. and 2. - "Business and Properties - Acquisitions and Dispositions - All American Pipeline Linefill Sale and Asset Disposition".
Plains Resources has agreed to indemnify us for environmental liabilities related to the assets of the our predecessor transferred to us that arose prior to closing and are discovered within three years after closing (excluding liabilities resulting from a change in law after closing). Plains Resources' indemnification obligation is capped at $3.0 million.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) (1) AND (2) FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
See "Index to Consolidated Financial Statements" set forth on Page.
(a)(3) EXHIBITS
3.1 -- Second Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. dated as of November 23, 1998 (incorporated by reference to Exhibit 3.1 to Annual Report on Form 10-K for the Year Ended December 31, 1998).
3.2 -- Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. dated as of November 23, 1998 (incorporated by reference to Exhibit 3.2 to Annual Report on Form 10-K for the Year Ended December 31, 1998).
3.3 -- Amended and Restated Agreement of Limited Partnership of All American Pipeline, L.P. dated as of November 23, 1998 (incorporated by reference to Exhibit 3.3 to Annual Report on Form 10-K for the Year Ended December 31, 1998).
3.4 -- Certificate of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.4 to Registration Statement, file No. 333-64107).
3.5 -- Certificate of Limited Partnership of Plains Marketing, L.P. dated as of November 10, 1998 (incorporated by reference to Exhibit 3.5 to Annual Report on Form 10-K for the Year Ended December 31, 1998).
3.6 -- Articles of Conversion of All American Pipeline Company dated as of November 10, 1998 (incorporated by reference to Exhibit 3.5 to Annual Report on Form 10-K for the Year Ended December 31, 1998).
3.7 -- Agreement of Limited Partnership of Plains Scurlock Permian, L.P. dated as of April 29, 1999 (incorporated by reference to Exhibit 3.7 to Quarterly Report on Form 10-Q for the Quarter Ended March 31, 1999).
3.8 -- Amendment No. 1 to the Second Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline L.P. dated as of May 12, 1999 (incorporated by reference to Exhibit 3.8 to Quarterly Report on Form 10-Q for the Quarter Ended June 30, 1999).
10.01 -- Credit Agreement among All American Pipeline, L.P., Plains All American Pipeline, L.P., Plains Marketing, L.P., ING (U.S.) Capital Corporation and certain other banks dated as of November 17, 1998 (incorporated by reference to Exhibit 10.01 to Annual Report on Form 10-K for the Year Ended December 31, 1998).
10.02 -- Amended and Restated Credit Agreement among Plains Marketing, L.P., Plains All American Pipeline, L.P., BankBoston, N.A., and certain other banks dated as of November 17, 1998 (incorporated by reference to Exhibit 10.01 to Annual Report on Form 10-K for the Year Ended December 31, 1998).
10.03 -- Contribution, Conveyance and Assumption Agreement among Plains All American Pipeline, L.P. and certain other parties dated as of November 23, 1998 (incorporated by reference to Exhibit 10.03 to Annual Report on Form 10-K for the Year Ended December 31, 1998).
**10.04 -- Plains All American Inc., 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.04 to Annual Report on Form 10-K for the Year Ended December 31, 1998).
**10.05 -- Plains All American Inc., 1998 Management Incentive Plan Plains All American Inc., 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.05 to Annual Report on Form 10-K for the Year Ended December 31, 1998).
**10.06 -- Employment Agreement between Plains Resources Inc. and Harry N. Pefanis dated as of November 23, 1998 (incorporated by reference to Exhibit 10.06 to Annual Report on Form 10-K for the Year Ended December 31, 1998).
10.07 -- Crude Oil Marketing Agreement among Plains Resources Inc., Plains Illinois Inc., Stocker Resources, L.P., Calumet Florida, Inc. and Plains Marketing, L.P. dated as of November 23, 1998 (incorporated by reference to Exhibit 10.07 to Annual Report on Form 10-K for the Year Ended December 31, 1998).
10.08 -- Omnibus Agreement among Plains Resources Inc., Plains All American Pipeline, L.P., Plains Marketing, L.P., All American Pipeline, L.P., and Plains All American Inc. dated as of November 23, 1998 (incorporated by reference to Exhibit 10.08 to Annual Report on Form 10-K for the Year Ended December 31, 1998).
10.09 -- Transportation Agreement dated July 30, 1993, between All American Pipeline Company and Exxon Company, U.S.A. (incorporated by reference to Exhibit 10.9 to Registration Statement, file No. 333-64107).
10.10 -- Transportation Agreement dated August 2, 1993, between All American Pipeline Company and Texaco Trading and Transportation Inc., Chevron U.S.A. and Sun Operating Limited Partnership (incorporated by reference to Exhibit 10.10 to Registration Statement, file No. 333-64107).
**10.11 -- Form of Transaction Grant Agreement (Payment on Vesting) (incorporated by reference to Exhibit 10.12 to Registration Statement, file No. 333-64107).
10.12 -- First Amendment to Contribution, Conveyance and Assumption Agreement dated as of December 15, 1998 (incorporated by reference to Exhibit 10.13 to Annual Report on Form 10-K for the Year Ended December 31, 1998).
10.13 -- First Amendment dated as of March 18, 1999, to Credit Agreement among All American Pipeline, L.P., Plains All American Pipeline, L.P., Plains Marketing, L.P., ING (U.S.) Capital Corporation and certain other banks (incorporated by reference to Exhibit 10.14 to Annual Report on Form 10-K for the Year Ended December 31, 1998).
10.14 -- First Amendment dated as of March 18, 1999, to Amended and Restated Credit Agreement among Plains Marketing, L.P., Plains All American Pipeline, L.P., All American Pipeline, L.P., BankBoston, N.A. and certain other banks (incorporated by reference to Exhibit 10.15 to Annual Report on Form 10-K for the Year Ended December 31, 1998).
10.15 -- Agreement for Purchase and Sale of Membership Interest in Scurlock Permian LLC between Marathon Ashland LLC and Plains Marketing, L.P. dated as of March 17, 1999 (incorporated by reference to Exhibit 10.16 to Annual Report on Form 10-K for the Year Ended December 31, 1998).
10.16 -- Asset Sales Agreement between Chevron Pipe Line Company and Plains Marketing, L.P. dated as of April 16, 1999 (incorporated by reference to Exhibit 10.17 to Quarterly Report on Form 10-Q for the Quarter Ended March 31, 1999).
10.17 -- Credit Agreement dated as of May 12, 1999, between Plains Scurlock Permian, L.P., BankBoston, N.A. and certain other financial institutions (incorporated by reference to Exhibit 10.18 to Quarterly Report on Form 10-Q for the Quarter Ended March 31, 1999).
10.18 -- First Amendment to Plains Scurlock Credit Agreement dated as of July 29, 1999, between Plains Scurlock Permian, L.P., BankBoston, N.A. and certain other financial institutions (incorporated by reference to Exhibit 10.19 to Quarterly Report on Form 10-Q for the Quarter Ended June 30, 1999).
**10.19 -- Transaction Grant Agreement with Greg L. Armstrong (incorporated by reference to Exhibit 10.20 to Registration Statement on Form S-1, file no. 333-86907)
10.20 -- Second Amendment dated as of August 19, 1999, to Plains Scurlock Credit Agreement between Plains Scurlock Permian, L.P., BankBoston, N.A. and certain other financial institutions (incorporated by reference to Exhibit 10.21 to Quarterly Report on Form 10-Q for the Quarter Ended September 30, 1999).
10.21 -- Second Amendment dated September 24, 1999, to Credit Agreement among All American Pipeline, L.P., Plains Marketing, L.P., Plains All American Pipeline, L.P. and BankBoston, N.A. and certain other financial institutions (incorporated by reference to Exhibit 10.22 to Quarterly Report on Form 10-Q for the Quarter Ended September 30, 1999).
10.22 -- Second Amendment dated September 24, 1999, to Amended and Restated Credit Agreement among Plains Marketing, L.P., Plains All American Pipeline, L.P., All American Pipeline, L.P. and BankBoston, N.A. and certain other financial institutions (incorporated by reference to Exhibit 10.23 to Quarterly Report on Form 10-Q for the Quarter Ended September 30, 1999).
*10.23 -- Amended and Restated Credit Agreement dated as of December 1, 1999, among All American Pipeline, L.P., Plains Marketing, L.P., Plains All American Pipeline, L.P. and BankBoston, N.A. and certain other financial institutions.
*10.24 -- Second Amended and Restated Credit Agreement dated as of December 1, 1999, among Plains Marketing, L.P., Plains All American Pipeline, L.P., All American Pipeline, L.P. and BankBoston, N.A. and certain other financial institutions.
*10.25 -- Amendment and Limited Consent dated as of December 1, 1999, among All American Pipeline, L.P., Plains Marketing, L.P., Plains All American Pipeline, L.P. and BankBoston, N.A. and certain other financial institutions.
*10.26 -- Amendment and Limited Consent dated as of December 1, 1999, among Plains Marketing, L.P., Plains All American Pipeline, L.P., All American Pipeline, L.P. and BankBoston, N.A. and certain other financial institutions.
*10.27 -- Pipeline Sale and Purchase Agreement dated January 31, 2000, among Plains All American Pipeline, L.P., All American Pipeline, L.P., El Paso Natural Gas Company and El Paso Pipeline Company.
21.1 -- Subsidiaries of the Registrant (incorporated by reference to Exhibit 21.1 to Registration Statement on Form S-1, file no. 333- 86907).
*23.1 -- Consent of PricewaterhouseCooper, LLP.
*27.1 -- Financial Data Schedule
- --------- * Filed herewith ** Management contract or compensatory plan or arrangement
(B) REPORTS ON FORM 8-K
A Current Report on Form 8-K was filed on November 29, 1999, regarding the discovery of unauthorized trading activity by a former employee which was expected to result in losses to us of approximately $160.0 million.
A Current Report on Form 8-K was filed on December 1, 1999, regarding the execution of agreements with our lenders to provide for a $300.0 million credit facility and the waiver of defaults under certain covenants in our credit facilities which resulted from our unauthorized trading losses, as well as the execution by Plains Resources of commitment letters for the sale of up to $50.0 million of a new series of preferred stock, the proceeds of which would constitute a portion of the $114.0 million in debt financing which Plains Resources agreed to provide to us.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
PLAINS ALL AMERICAN PIPELINE, L.P..
By: PLAINS ALL AMERICAN INC., Our General Partner
Date: March 30, 2000 By: /s/ Phillip D. Kramer ------------------------------------ Phillip D. Kramer, Executive Vice President and Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Date: March 30, 2000 By: /s/ Greg L. Armstrong ------------------------------------ Greg L. Armstrong, Chairman of the Board, Chief Executive Officer and Director of our General Partner (Principal Executive Officer)
Date: March 30, 2000 By: /s/ Harry N. Pefanis ------------------------------------ Harry N. Pefanis, President, Chief Operating Officer and Director of our General Partner
Date: March 30, 2000 By: /s/ Phillip D. Kramer ------------------------------------ Phillip D. Kramer, Executive Vice President and Chief Financial Officer (Principal Financial Officer) of our General Partner
Date: March 30, 2000 By: /s/ Cynthia A. Feeback ------------------------------------ Cynthia A. Feeback, Treasurer (Principal Accounting Officer) of our General Partner
Date: March 30, 2000 By: /s/ Everardo Goyanes ------------------------------------ Everardo Goyanes, Director of our General Partner
Date: March 30, 2000 By: /s/ Robert V. Sinnott ------------------------------------ Robert V. Sinnott, Director of our General Partner
Date: March 30, 2000 By: /s/ Arthur L. Smith ------------------------------------ Arthur L. Smith, Director of our General Partner
PLAINS ALL AMERICAN PIPELINE, L.P. INDEX TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
All other schedules are omitted because they are not applicable or the required information is shown in the financial statements or notes thereto.
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors of the General Partner and the Unitholders of Plains All American Pipeline, L.P.
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of changes in partners' capital and of cash flows, after the restatement described in Note 3, present fairly, in all material respects, the financial position of Plains All American Pipeline, L.P. and subsidiaries (the "Partnership") at December 31, 1999 and 1998, and the results of their operations and their cash flows for the year ended December 31, 1999 and the period from inception (November 23, 1998) to December 31, 1998 in conformity with accounting principles generally accepted in the United States. These financial statements are the responsibility of the Partnership's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP
Houston, Texas March 29, 2000
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors of the General Partner and the Unitholders of Plains All American Pipeline, L.P.
In our opinion, the accompanying combined statements of operations and of cash flows of the Plains Midstream Subsidiaries, the predecessor entity of the Partnership, after the restatement described in Note 3, present fairly, in all material respects, the combined results of their operations and their cash flows for the period from January 1, 1998 to November 22, 1998 and the year ended December 31, 1997 in conformity with accounting principles generally accepted in the United States. These financial statements are the responsibility of the Plains Midstream Subsidiaries' management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP
Houston, Texas March 29, 2000
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (in thousands, except unit data)
See notes to consolidated and combined financial statements.
See notes to consolidated and combined financial statements.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS (in thousands)
See notes to consolidated and combined financial statements.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL FOR THE PERIOD FROM INCEPTION (NOVEMBER 23, 1998) TO DECEMBER 31, 1998 AND THE YEAR ENDED DECEMBER 31, 1999 (IN THOUSANDS)
See notes to consolidated and combined financial statements.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Note 1 -- Organization and Basis of Presentation
Organization
We are a Delaware limited partnership that was formed in September of 1998 to acquire and operate the midstream crude oil business and assets of Plains Resources Inc. and its wholly-owned subsidiaries. On November 23, 1998, we completed our initial public offering and the transactions whereby we became the successor to the business of the midstream subsidiaries of Plains Resources, also referred to as our predecessor or the Plains Midstream Subsidiaries. Our operations are conducted through Plains Marketing, L.P., All American Pipeline, L.P. and Plains Scurlock Permian, L.P. Our general partner, Plains All American Inc., is a wholly-owned subsidiary of Plains Resources. We are engaged in interstate and intrastate crude oil transportation, gathering and marketing as well as crude oil terminalling and storage activities. Our operations are conducted primarily in California, Texas, Oklahoma, Louisiana and the Gulf of Mexico.
Formation and Offering
On November 23, 1998, we completed an initial public offering of 13,085,000 common units at $20.00 per unit, representing limited partner interests and received net proceeds of approximately $244.7 million. Concurrently with the closing of the initial public offering, certain of the Plains Midstream subsidiaries were merged into Plains Resources, which sold the assets of these subsidiaries to us in exchange for $64.1 million and the assumption of $11.0 million of related indebtedness. At the same time, our general partner conveyed all of its interest in the All American Pipeline and the SJV Gathering System to us in exchange for:
. 6,974,239 common units, 10,029,619 subordinated units and an aggregate 2% general partner interest; . the right to receive incentive distributions as defined in the partnership agreement; and . our assumption of $175.0 million of indebtedness incurred by our general partner in connection with the acquisition of the All American Pipeline and the SJV Gathering System.
In addition to the $64.1 million discussed above, we distributed approximately $177.6 million of the offering proceeds to our general partner and used approximately $3.0 million of the remaining proceeds to pay expenses incurred in connection with the initial public offering.
Basis of Consolidation and Presentation
The accompanying financial statements and related notes present our consolidated financial position as of December 31, 1999 and 1998, and the results of our operations, cash flows and changes in partners' capital for the year ended December 31, 1999 and the period from inception (November 23, 1998) to December 31, 1998, and the results of operations and cash flows of our predecessor for the period from January 1, 1998 to November 22, 1998 and the year ended December 31, 1997. All significant intercompany transactions have been eliminated. Certain reclassifications have been made to prior period amounts to conform with current period presentation.
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ from these estimates.
Revenue Recognition. Gathering and marketing revenues are accrued at the time title to the product sold transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser, and purchases are accrued at the time title to the product purchased transfers to us, which typically occurs upon our receipt of the product. Terminalling and storage revenues are recognized at the time service is performed. Revenues for the transportation of crude oil are recognized based upon regulated and non-regulated tariff rates and the related transported volumes.
Cost of Sales and Operations. Cost of sales consists of the cost of crude oil, transportation fees, field and pipeline operating expenses and letter of credit expenses. Field and pipeline operating expenses consist primarily of fuel and power costs, telecommunications, labor costs for pipeline field personnel, maintenance, utilities, insurance and property taxes. Crude oil exchanges whereby like volumes are purchased and sold with the same customers with little effect on gross margin are netted in cost of sales and operations.
Cash and Cash Equivalents. Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of three months or less.
Inventory. Inventory consists of crude oil in pipelines and in storage tanks which is valued at the lower of cost or market, with cost determined using the average cost method. Inventory at December 31, 1999 includes approximately $37.9 million of crude oil linefill which we began selling in November 1999 (see Note 5).
Property and Equipment and Pipeline Linefill. Property and equipment is stated at cost and consists of:
Depreciation is computed using the straight-line method over estimated useful lives as follows:
. crude oil pipelines - 40 years; . crude oil pipeline facilities - 25 years; . crude oil terminal and storage facilities - 30 to 40 years; . trucking equipment, injection stations and other - 5 to 10 years; and . other property and equipment - 5 to 7 years.
Acquisitions and improvements are capitalized; maintenance and repairs are expensed as incurred. Net gains or losses on property and equipment disposed of are included in interest and other income.
Pipeline linefill is recorded at cost and consists of crude oil linefill used to pack a pipeline such that when an incremental barrel enters a pipeline it forces a barrel out at another location. After the sale of linefill discussed below, we own approximately 1.2 million barrels of crude oil that is used to maintain the vast majority of our minimum operating linefill requirements. Proceeds from the sale and repurchase of pipeline linefill are reflected as cash flows from operating activities in the accompanying consolidated and combined statements of cash flows. Proceeds from the sale of linefill in connection with the segment of the All American Pipeline that is being sold are included in investing activities in the accompanying consolidated and combined statements of cash flows. In November 1999, we initiated the sale of 5.2 million barrels of crude oil linefill (see Note 5).
Impairment of Long-Lived Assets. Long-lived assets, including any related goodwill, with recorded values that are not expected to be recovered through future cash flows are written-down to estimated fair value. Fair value is generally determined from estimated discounted future net cash flows.
Other Assets. Other assets consist of the following (in thousands):
DECEMBER 31, ------------------------- 1999 1998 --------- --------- Debt issue costs $ 24,776 $ 10,171 Goodwill and other 1,994 1,134 --------- --------- 26,770 11,305 Accumulated amortization (3,663) (495) --------- --------- $ 23,107 $ 10,810 ========= =========
Costs incurred in connection with the issuance of long-term debt are capitalized and amortized using the straight-line method over the term of the related debt. Debt issue costs at December 31, 1999, include approximately $13.7 million paid to amend our credit facilities as a result of defaults caused by unauthorized trading losses (see Note 3). Goodwill was recorded as the amount of the purchase price in excess of the fair value of certain transportation and crude oil gathering assets purchased by our predecessor and is amortized using the straight-line method over a period of twenty years.
Federal Income Taxes. No provision for income taxes related to our operations is included in the accompanying consolidated financial statements because as a partnership, we are not subject to federal or state income tax and the tax effect of our activities accrues to the unitholders. Net earnings for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement. Individual unitholders will have different investment bases depending upon the timing and price of acquisition of partnership units. Further, each unitholder's tax accounting, which is partially dependent upon his/her tax position, may differ from the accounting followed in the consolidated financial statements. Accordingly, there could be significant differences between each individual unitholder's tax bases and his/her share of the net assets reported in the consolidated financial statements. We do not have access to information about each individual unitholder's tax attributes, and the aggregate tax bases cannot be readily determined. Accordingly, management does not believe that in our circumstances, the aggregate difference would be meaningful information.
Our predecessor is included in the consolidated federal income tax return of Plains Resources. Income taxes are calculated as if our predecessor had filed a return on a separate company basis utilizing a federal statutory rate of 35%.
Hedging. We utilize various derivative instruments, for purposes other than trading, to hedge our exposure to price fluctuations on crude in storage and expected purchases, sales and transportation of crude oil. The derivative instruments consist primarily of futures and option contracts traded on the New York Mercantile Exchange and crude oil swap contracts entered into with financial institutions. We also utilize interest rate swaps and collars to manage the interest rate exposure on our long-term debt.
These derivative instruments qualify for hedge accounting as they reduce the price risk of the underlying hedged item and are designated as a hedge at inception. Additionally, the derivatives result in financial impacts which are inversely correlated to those of the items being hedged. This correlation, generally in excess of 80%, (a measure of hedge effectiveness) is measured both at the inception of the hedge and on an ongoing basis. If correlation ceases to exist, we would discontinue hedge accounting and apply mark to market accounting. Gains and losses on the termination of hedging instruments are deferred and recognized in income as the impact of the hedged item is recorded.
Unrealized changes in the market value of crude oil hedge contracts are not generally recognized in our statement of operations or our predecessor's statements of operations until the underlying hedged transaction occurs. The financial impacts of crude oil hedge contracts are included in our and our predecessor's statements of operations as a component of revenues. Such financial impacts are offset by gains or losses realized in the physical market. Cash flows from crude oil hedging activities are included in operating activities in the accompanying statements of cash flows. Net deferred gains and losses on futures contracts, including closed futures contracts, entered into to hedge anticipated crude oil purchases and sales are included in current assets or current liabilities in the accompanying consolidated balance sheets. Deferred gains or losses from inventory hedges are included as part of the inventory costs and recognized when the related inventory is sold.
Amounts paid or received from interest rate swaps and collars are charged or credited to interest expense and matched with the cash flows and interest expense of the long-term debt being hedged, resulting in an adjustment to the effective interest rate. Deferred gains of $10.8 million received upon the termination of an interest rate swap are included in other long-term liabilities and deferred credits, net of accumulated amortization, in the accompanying balance sheet at December 31, 1999.
Net income per unit. Basic and diluted net income (loss) per unit is determined by dividing net income (loss) after deducting the amount allocated to our general partner, by the weighted average number of outstanding common units and subordinated units. Partnership income (loss) is allocated first according to cash distributions, and the remainder according to percentage ownership in the partnership. For periods prior to November 23, 1998, outstanding units are assumed to equal the common and subordinated units received by our general partner in exchange for assets contributed to us.
Unit Options. We have elected to follow Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees ("APB 25") and related interpretations in accounting for our employee unit options and awards. Under APB 25, no compensation expense is recognized when the exercise price of options equals the fair value (market price) of the underlying units on the date of grant (see Note 14).
Recent Accounting Pronouncements. In June 1998, the FASB issued Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities ("SFAS 133"). SFAS 133 requires that all derivative instruments be recorded on the balance sheet at their fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and, if so, the type of hedge transaction. For fair value hedge transactions in which we are hedging changes in an asset's, liability's, or firm commitment's fair value, changes in the fair value of the derivative instrument will generally be offset in the income statement by changes in the hedged item's fair value. For cash flow hedge transactions, in which we are hedging the variability of cash flows related to a variable-rate asset, liability, or a forecasted transaction, changes in the fair value of the derivative instrument will be reported in other comprehensive income. The gains and losses on the derivative instrument that are reported in other comprehensive income will be reclassified as earnings in the periods in which earnings are affected by the variability of the cash flows of the hedged item. This statement was amended by Statement of Financial Accounting Standards No. 137, Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133 ("SFAS 137") issued in June 1999. SFAS 137 defers the effective date of SFAS 133 to fiscal years beginning after June 15, 2000. We are required to adopt this statement beginning in 2001. We have not yet determined the effect that the adoption of SFAS 133 will have on our financial position or results of operations.
NOTE 3 -- UNAUTHORIZED TRADING LOSSES AND RESTATED FINANCIAL STATEMENTS
In November 1999, we discovered that a former employee had engaged in unauthorized trading activity, resulting in losses of approximately $162.0 million ($174.0 million, including estimated associated costs and legal expenses). A full investigation into the unauthorized trading activities by outside legal counsel and independent accountants and consultants determined that the vast majority of the losses occurred from March through November 1999, and the impact warranted a restatement of previously reported financial information for 1999 and 1998. Approximately $7.1 million of the unauthorized trading losses was recognized in 1998 and the remainder in 1999.
Normally, as we purchase crude oil, we establish a margin by selling crude oil for physical delivery to third-party users or by entering into a future delivery obligation with respect to futures contracts. The employee in question violated our policy of maintaining a position that is substantially balanced between crude oil purchases and sales or future delivery obligations. The unauthorized trading and associated losses resulted in a default of certain covenants under our credit facilities and significant short-term cash and letter of credit requirements.
In December 1999, we executed amended credit facilities and obtained default waivers from all of our lenders. The amended credit facilities:
. waived defaults under covenants contained in the existing credit facilities; . increased availability under our letter of credit and borrowing facility from $175.0 million in November 1999 to $295.0 million in December 1999, $315.0 million in January 2000, and thereafter decreasing to $239.0 million in February through April 2000, to $225.0 million in May and June 2000 and to $200.0 million in July 2000 through July 2001; . required the lenders' consent prior to the payment of distributions to unitholders; . prohibited contango inventory transactions subsequent to January 20, 2000; and . increased interest rates and fees under certain of the facilities.
We paid approximately $13.7 million to our lenders in connection with the amended credit facilities. This amount was capitalized as debt issue costs and will be amortized over the remaining term of the amended facilities. In connection with the amendments, our general partner loaned us approximately $114.0 million. This subordinated debt is due not later than November 30, 2005.
In the period immediately following the disclosure of the unauthorized trading losses, a significant number of our suppliers and trading partners reduced or eliminated the open credit previously extended to us. Consequently, the amount of letters of credit we needed to support the level of our crude oil purchases then in effect increased significantly. In addition, the cost to us of obtaining letters of credit increased under the amended credit facility. In many instances we arranged for letters of credit to secure our obligations to purchase crude oil from our customers, which increased our letter of credit costs and decreased our unit margins. In other instances, primarily involving lower margin wellhead and bulk purchases, certain of our purchase contracts were terminated.
The summarized restated results for the periods ended and financial position as of March 31, June 30, and September 30, 1999 are as follows: (in thousands, except unit data) (unaudited).
RESTATED -------------------------------------------------------- THREE PERIOD ENDED PERIOD ENDED MONTHS JUNE 30, 1999 SEPTEMBER 30, 1999 ENDED -------------------- ---------------------- MARCH 31, THREE SIX THREE NINE 1999 MONTHS MONTHS MONTHS MONTHS --------- -------- --------- --------- ---------- STATEMENT OF OPERATIONS DATA:
Gross margin $ (1,546) $ 4,985 $ 3,439 $ (38,922) $ (35,483) Operating loss (6,965) (4,624) (11,589) (51,892) (63,481) Net loss (10,061) (9,154) (19,215) (60,131) (79,346) Net loss per limited partner unit (0.33) (0.29) (0.62) (1.88) (2.53)
BALANCE SHEET DATA:
Current assets $186,846 $ 413,418 $ 522,332 Current liabilities 190,331 452,307 622,394 Partners' capital 261,657 263,939 190,877
CASH FLOW DATA:
Net cash provided by operating activities $ 4,445 $ 15,397 $ 1,380
The summarized previously reported results for the periods ended and financial position as of March 31, June 30, and September 30, 1999 are as follows: (in thousands, except unit data) (unaudited).
PREVIOUSLY REPORTED -------------------------------------------------------- THREE PERIOD ENDED PERIOD ENDED MONTHS JUNE 30, 1999 SEPTEMBER 30, 1999 ENDED -------------------- ---------------------- MARCH 31, THREE SIX THREE NINE 1999 MONTHS MONTHS MONTHS MONTHS --------- -------- --------- --------- ---------- STATEMENT OF OPERATIONS DATA:
Gross margin $ 19,828 $ 26,212 $ 46,040 $ 33,304 $ 79,344 Operating income 14,409 16,603 31,422 20,334 51,346 Net income 11,313 12,073 23,386 12,095 35,481 Net income per limited partner unit 0.37 0.38 0.75 0.38 1.13
BALANCE SHEET DATA:
Current assets $187,015 $ 413,344 $522,234 Current liabilities 169,126 409,632 507,469 Partners' capital 283,031 306,540 305,704
CASH FLOW DATA:
Net cash provided by operating activities $ 4,276 $ 15,471 $ 1,478
Below is the summarized restated and previously reported results for the three and nine months ending September 30, 1998 (in thousands, except unit data) (unaudited).
THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, 1998 SEPTEMBER 30, 1998 ------------------- ------------------- PREVIOUSLY PREVIOUSLY RESTATED REPORTED RESTATED REPORTED -------- ---------- -------- ---------- STATEMENT OF OPERATIONS DATA:
Gross margin $ 6,914 $13,914 $16,114 $23,114 Operating income 3,410 10,410 9,948 16,948 Net income (loss) (1,212) 3,258 2,042 6,512 Net income (loss) per limited partner unit (0.07) 0.19 0.12 0.38
The summarized restated and previously reported results for the periods of November 23, 1998 to December 31, 1998 and January 1, 1998 to November 22, 1998 and financial position as of Decvember 31, 1998 are as follows (in thousands, except unit data): November 23, 1998 January 1, 1998 to December 31, 1998 to November 22, 1998 -------------------- -------------------- Previously Previously Restated Reported Restated Reported -------- --------- -------- ---------- Statement of Operations Data: Gross margin $ 5,099 $ 7,499 $ 26,281 $ 30,981 Operating income 3,136 5,536 17,576 22,276 Net income 1,777 4,177 4,257 7,025 Net income per limited partner unit 0.06 0.14 0.25 0.40
Balance Sheet Data: Current assets $ 163,829 $ 166,851 $ - $ - Current liabilities 161,598 157,520 - - Partners' capital 270,543 277,643 - -
NOTE 4 -- ACQUISITIONS
Scurlock Acquisition
On May 12, 1999, we completed the acquisition of Scurlock Permian LLC and certain other pipeline assets from Marathon Ashland Petroleum LLC. Including working capital adjustments and closing and financing costs, the cash purchase price was approximately $141.7 million.
Scurlock, previously a wholly-owned subsidiary of Marathon Ashland Petroleum, is engaged in crude oil transportation, gathering and marketing, and owns approximately 2,300 miles of active pipelines, numerous storage terminals and a fleet of more than 250 trucks. Its largest asset is an 800-mile pipeline and gathering system located in the Spraberry Trend in West Texas that extends into Andrews, Glasscock, Martin, Midland, Regan and Upton Counties, Texas. The assets we acquired also included approximately one million barrels of crude oil linefill.
Financing for the Scurlock acquisition was provided through:
. borrowings of approximately $92.0 million under Plains Scurlock's limited recourse bank facility with BankBoston, N.A.; . the sale to our general partner of 1.3 million of our Class B common units for a total cash consideration of $25.0 million, or $19.125 per unit, the price equal to the market value of our common units on May 12, 1999; and . a $25.0 million draw under our existing revolving credit agreement.
The purchase price allocation was based on preliminary estimates of fair value and is subject to adjustment as additional information becomes available and is evaluated. The purchase accounting entries include a $1.0 million accrual for estimated environmental remediation costs. Under the agreement for the sale of Scurlock by Marathon Ashland Petroleum to Plains Scurlock, Marathon Ashland Petroleum has agreed to indemnify and hold harmless Scurlock and Plains Scurlock for claims, liabilities and losses resulting from any act or omission attributable to Scurlock's business or properties occurring prior to the date of the closing of such sale to the extent the aggregate amount of such losses exceed $1.0 million; provided, however, that claims for such losses must individually exceed $25,000 and must be asserted by Scurlock against Marathon Ashland Petroleum on or before May 15, 2003.
The assets, liabilities and results of operations of Scurlock are included in our consolidated financial statements effective May 1, 1999. The Scurlock acquisition has been accounted for using the purchase method of accounting and the purchase price was allocated in accordance with Accounting Principles Board Opinion No. 16, Business Combinations, ("APB 16") as follows (in thousands):
Crude oil pipeline, gathering and terminal assets $125,120 Other property and equipment 1,546 Pipeline linefill 16,057 Other assets (debt issue costs) 3,100 Other long-term liabilities (environmental accrual) (1,000) Net working capital items (3,090) -------- Cash paid $141,733 ========
Pro Forma Results for the Scurlock Acquisition
The following unaudited pro forma data is presented to show pro forma revenues, net income and basic and diluted net income (loss) per limited partner unit as if the Scurlock acquisition, which was effective May 1, 1999, had occurred on January 1, 1998 (in thousands).
YEAR NOVEMBER 23, JANUARY 1, ENDED 1998 TO 1998 TO DECEMBER 31, DECEMBER 31, NOVEMBER 22, 1999 1998 1998 ----------- --------- ----------- (restated) (restated)
Revenues $ 5,089,223 $ 278,424 $ 2,099,463 =========== ========= =========== Net income (loss) $ (97,012) $ (7,957) $ 3,063 =========== ========= =========== Basic and diluted net income (loss) per limited partner unit $ (3.01) $ (0.25) $ 0.18 =========== ========= ===========
West Texas Gathering System Acquisition
On July 15, 1999, Plains Scurlock Permian, L.P. completed the acquisition of a West Texas crude oil pipeline and gathering system from Chevron Pipe Line Company for approximately $36.0 million, including transaction costs. Our total acquisition cost was approximately $38.9 million including costs to address certain issues identified in the due diligence process. The principal assets acquired include approximately 450 miles of crude oil transmission mainlines, approximately 400 miles of associated gathering and lateral lines and approximately 2.9 million barrels of crude oil storage and terminalling capacity in Crane, Ector, Midland, Upton, Ward and Winkler Counties, Texas. Financing for the amounts paid at closing was provided by a draw under the term loan portion of the Plains Scurlock credit facility.
Venice Terminal Acquisition
On September 3, 1999, we completed the acquisition of a Louisiana crude oil terminal facility and associated pipeline system from Marathon Ashland Petroleum LLC for approximately $1.5 million. The principal assets acquired include approximately 300,000 barrels of crude oil storage and terminalling capacity and a six-mile crude oil transmission system near Venice, Louisiana.
All American Pipeline Acquisition
On July 30, 1998, our predecessor acquired all of the outstanding capital stock of the All American Pipeline Company, Celeron Gathering Corporation and Celeron Trading & Transportation Company (collectively the "Celeron Companies") from Wingfoot, a wholly-owned subsidiary of the Goodyear Tire and Rubber Company ("Goodyear"), for approximately $400.0 million, including transaction costs. The principal assets of the entities acquired include the All American Pipeline and the SJV Gathering System, as well as other assets related to such operations. The acquisition was accounted for utilizing the purchase method of accounting with the assets, liabilities and results of operations included in the combined financial statements of the predecessor effective July 30, 1998.
The acquisition was accounted for utilizing the purchase method of accounting and the purchase price was allocated in accordance with APB 16 as follows (in thousands):
Crude oil pipeline, gathering and terminal assets $ 392,528 Other assets (debt issue costs) 6,138 Net working capital items (excluding cash received of $7,481) 1,498 --------- Cash paid $ 400,164 =========
Financing for the acquisition was provided through a $325.0 million, limited recourse bank facility and an approximate $114.0 million capital contribution by Plains All American Inc. Actual borrowings at closing were $300.0 million.
In 1999, we terminated 24 employees and paid approximately $1.4 million in connection therewith.
NOTE 5 -- ASSET DISPOSITIONS
We initiated the sale of approximately 5.2 million barrels of crude oil linefill from the All American Pipeline in November 1999. This sale was substantially completed in February 2000. The linefill was located in the segment of the All American Pipeline that extends from Emidio, California, to McCamey, Texas. Except for minor third party volumes, one of our subsidiaries has been the sole shipper on this segment of the pipeline since its predecessor acquired the line from Goodyear on July 30, 1998. Proceeds from the sale of the linefill were approximately $100.0 million, net of associated costs, and were used for working capital purposes. We estimate that we will recognize a total gain of approximately $44.0 million in connection with the sale of linefill. As of December 31, 1999, we had delivered approximately 1.8 million barrels of linefill and recognized a gain of $16.5 million. The amount of crude oil linefill for sale at December 31, 1999 was $37.9 million and is included in inventory on the consolidated balance sheet.
On March 24, 2000, we completed the sale of the above referenced segment of the All American Pipeline to a unit of El Paso Energy Corporation for total proceeds of $129.0 million. The proceeds from the sale were used to reduce outstanding debt. Our net proceeds are expected to be approximately $124.0 million, net of associated transaction costs and estimated costs to remove certain equipment. We estimate that we will recognize a gain of approximately $20.0 million in connection with the sale. During 1999, we reported gross margin of approximately $5.0 million from volumes transported on the segment of the line that was sold.
NOTE 6 --CREDIT AGREEMENTS AND LONG-TERM DEBT
Short-term debt and current portion of long-term debt consists of the following:
We have a letter of credit and borrowing facility, the purpose of which is to provide standby letters of credit to support the purchase and exchange of crude oil for resale and borrowings to finance crude oil inventory which has been hedged against future price risk or designated as working inventory. As a result of the unauthorized trading losses discovered in November 1999, the facility was in default of certain covenants, with those defaults being subsequently waived and the facility amended in December 1999. As amended, the letter of credit facility has a sublimit for cash borrowings of $40.0 million at December 31, 1999, with decreasing amounts thereafter through April 30, 2000, at which time the sublimit is eliminated. The letter of credit and borrowing facility provides for an aggregate letter of credit availability of $295.0 million in December 1999, $315.0 million in January 2000, and thereafter decreasing to $239.0 million in February through April 2000, to $225.0 million in May and June 2000 and to $200.0 million in July 2000 through July 2001. Aggregate availability under the letter of credit facility for direct borrowings and letters of credit is limited to a borrowing base which is determined monthly based on certain of our current assets and current liabilities, primarily accounts receivable and accounts payable related to the purchase and sale of crude oil. This facility is secured by a lien on substantially all of our assets except the assets which secure the Plains Scurlock credit facility. At December 31, 1999, there were letters of credit of approximately $292.0 million and borrowings of $13.7 million outstanding under this facility.
On December 30, 1999, we entered into a $65.0 million senior secured term credit facility to fund short-term working capital requirements resulting from the unauthorized trading losses. The facility was secured by a portion of the 5.2 million barrels of linefill that was sold and receivables from certain sales contracts applicable to the linefill. The facility had a maturity date of March 24, 2000 and was repaid with the proceeds from the sale of the linefill securing the facility. At December 31, 1999, there were borrowings of $45.0 million outstanding.
Long-term debt consists of the following:
Concurrently with the closing of our initial public offering in November 1998, we entered into a $225.0 million bank credit agreement that includes a $175.0 million term loan facility and a $50.0 million revolving credit facility. As a result of the unauthorized trading losses discovered in November 1999, the facility was in default of certain covenants, with those defaults being subsequently waived and the facility amended in December. The bank credit agreement is secured by a lien on substantially all of our assets except the assets which secure the Plains Scurlock bank credit agreement. We may borrow up to $50.0 million under the revolving credit facility for acquisitions, capital improvements, working capital and general business purposes. At December 31, 1999, we had $175.0 million outstanding under the term loan facility and $50.0 million outstanding under the revolving credit facility. The term loan facility matures in 2005, and no principal is scheduled for payment prior to maturity. The term loan facility may be prepaid at any time without penalty. The revolving credit facility expires in November 2000. The term loan and revolving credit facility bear interest at our option at either the base rate, as defined, plus an applicable margin, or reserve adjusted LIBOR plus an applicable margin. We incur a commitment fee on the unused portion of the revolving credit facility.
Plains Scurlock has a bank credit agreement which consists of a five-year $82.6 million term loan facility and a three-year $35.0 million revolving credit facility. The Plains Scurlock bank credit agreement is nonrecourse to Plains All American Pipeline, Plains Marketing, L.P. and All American Pipeline, L.P. and is secured by substantially all of the assets of Plains Scurlock Permian, L.P. and its subsidiaries, including the Scurlock assets and the West Texas gathering system. Borrowings under the term loan and the revolving credit facility bear interest at LIBOR plus the applicable margin. A commitment fee equal to 0.5% per year is charged on the unused portion of the revolving credit facility. The revolving credit facility, which may be used for borrowings or letters of credit to support crude oil purchases, matures in May 2002. The term loan provides for principal amortization of $0.7 million annually beginning May 2000, with a final maturity in May 2004. As of December 31, 1999, letters of credit of approximately $29.5 million were outstanding under the revolver and borrowings of $82.6 million and $2.5 million were outstanding under the term loan and revolver, respectively. The term loan was reduced to $82.6 million from $126.6 million with proceeds from our October 1999 public unit offering.
All of our credit facilities contain prohibitions on distributions on, or purchases or redemptions of, units if any default or event of default is continuing. In addition, our facilities contain various covenants limiting our ability to:
. incur indebtedness; . grant liens; . sell assets in excess of certain limitations; . engage in transactions with affiliates; . make investments; . enter into hedging contracts; and . enter into a merger, consolidation or sale of assets.
Each of our facilities treats a change of control as an event of default. In addition, the terms of our letter of credit and borrowing facility and our bank credit agreement require lenders' consent prior to the payment of distributions to unitholders and require us to maintain:
. a current ratio of 1.0 to 1.0, as defined in our credit agreement; . a debt coverage ratio which is not greater than 5.0 to 1.0;
. an interest coverage ratio which is not less than 3.0 to 1.0; . a fixed charge coverage ratio which is not less than 1.25 to 1.0; and . debt to capital ratio of not greater than 0.60 to 1.0.
The terms of the Plains Scurlock bank credit agreement requires Plains Scurlock to maintain at the end of each quarter:
. a debt coverage ratio of 6.0 to 1.0 from October 1, 1999 through June 30, 2000; 5.0 to 1.0 from July 1, 2000 through June 30, 2001; and 4.0 to 1.0 thereafter; and . an interest coverage ratio of 2.0 to 1.0 from October 1, 1999 through June 30, 2000 and 2.5 to 1.0 thereafter.
In addition, the Plains Scurlock bank credit agreement contains limitations on the Plains Scurlock operating partnership's ability to make distributions to us if its indebtedness and current liabilities exceed certain levels as well as the amount of expansion capital it may expend.
In December 1999, our general partner loaned us $114.0 million. This subordinated debt is due not later than November 30, 2005. Proceeds from the notes were used for working capital requirements created by the unauthorized trading losses (see Note 3). The notes are subordinated in right of payment to all existing senior indebtedness and bear interest at the same LIBOR rate as our letter of credit and borrowing facility. Interest on the notes is payable monthly, but payment of interest requires the permission of certain of our lenders. Any interest not paid when due is added to the principal of the notes, at the option of our general partner.
At December 31, 1999, we had interest rate collar agreements aggregating a notional principal amount of $215.0 million which hedge the interest rate on our underlying debt obligations. These instruments are based on LIBOR rates before the applicable margins and generally provide for a floor of 5% and a ceiling of 6.5% for $90.0 million of debt and a floor of 6.1% and a ceiling of 8% for $125.0 million of debt.
The aggregate amount of maturities of all long-term indebtedness for the next five years is: 2000 - $50.6 million, 2001 - $0.6 million, 2002 - $3.2 million, 2003 - $0.7 million and 2004 - $80.0 million.
NOTE 7 -- PARTNERSHIP CAPITAL AND DISTRIBUTIONS
Partner's capital consists of 24,356,429 common units, including 1,307,190 Class B common units, representing a 69.4% limited partner interest, (a subsidiary of our general partner owns 6,904,795 of such common units), 10,029,619 Subordinated units owned by a subsidiary of our general partner representing a 28.6% limited partner interest and a 2% general partner interest. In the aggregate, our general partner's interests represent an effective 54.0% ownership of our equity at December 31, 1999.
All of the subordinated units and 20,059,239 of the common units were issued in connection with our November 1998 initial public offering. In October 1999, we completed a public offering of an additional 2,990,000 common units representing limited partner interests at $18.00 per unit. Net proceeds, including our general partners' contribution, from the offering were approximately $51.3 million after deducting underwriters' discounts and commissions and offering expenses of approximately $3.1 million. These proceeds were used to reduce outstanding debt. The Class B common units were issued in May 1999 to our general partner at $19.125 per unit for total proceeds of $25.0 million in connection with the Scurlock acquisition (see Note 4).
Subject to the consent of our lenders, we will distribute 100% of our available cash within 45 days after the end of each quarter to unitholders of record and to our general partner. Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter less reserves established by our general partner for future requirements. Distributions of available cash to holders of subordinated units are subject to the prior rights of holders of common units to receive the minimum quarterly distribution ("MQD") for each quarter during the subordinated period (which will not end earlier than December 31, 2003) and to receive any arrearages in the distribution of the MQD on the common units for the prior quarters during the subordinated period. The MQD is $0.45 per unit ($1.80 per unit on an annual basis). Upon expiration of the subordination period, all subordinated units will be converted on a one-for- one basis into common units and will participate pro rata with all other common units in future distributions of available cash. Under certain circumstances, up to 50% of the subordinated units may convert into common units prior to the expiration of the subordination period. Common units will not accrue arrearages with respect to distributions for any quarter after the subordination period and subordinated units will not accrue any arrearages with respect to distributions for any quarter.
If quarterly distributions of available cash exceed the MQD or the Target Distribution Levels (as defined), our general partner will receive distributions which are generally equal to 15%, then 25% and then 50% of the distributions of available
cash that exceed the MQD or Target Distribution Level. The Target Distribution Levels are based on the amounts of available cash from our Operating Surplus (as defined) distributed with respect to a given quarter that exceed distributions made with respect to the MQD and common unit arrearages, if any.
The Class B common units are initially pari passu with common units with respect to distributions, and are convertible into common units upon approval of a majority of the common unitholders. The Class B unitholders may request that we call a meeting of common unitholders to consider approval of the conversion of Class B units into common units. If the approval of a conversion by the common unitholders is not obtained within 120 days of a request, each Class B common unitholder will be entitled to receive distributions, on a per unit basis, equal to 110% of the amount of distributions paid on a common unit, with such distribution right increasing to 115% if such approval is not secured within 90 days after the end of the 120-day period. Except for the vote to approve the conversion, Class B common units have the same voting rights as the common units.
Our 1999 and 1998 distributions declared, which were paid in the quarter following declaration are summarized in the following table:
The fourth quarter 1998 distribution represents a partial quarterly distribution for the period from November 23, 1998, the date of our initial public offering, to December 31, 1998.
NOTE 8 -- FINANCIAL INSTRUMENTS
Derivatives
We utilize derivative financial instruments to hedge our exposure to price volatility on crude oil and do not use such instruments for speculative trading purposes. These arrangements expose us to credit risk (as to counterparties) and to risk of adverse price movements in certain cases where our purchases are less than expected. In the event of non-performance of a counterparty, we might be forced to acquire alternative hedging arrangements or be required to honor the underlying commitment at then-current market prices. In order to minimize credit risk relating to the non-performance of a counterparty, we enter into such contracts with counterparties that are considered investment grade, periodically review the financial condition of such counterparties and continually monitor the effectiveness of derivative financial instruments in achieving our objectives. In view of our criteria for selecting counterparties, our process for monitoring the financial strength of these counterparties and our experience to date in successfully completing these transactions, we believe that the risk of incurring significant financial statement loss due to the non-performance of counterparties to these transactions is minimal.
At December 31, 1999, our hedging activities included crude oil futures contracts maturing in 2000 through 2002, covering approximately 7.4 million barrels of crude oil including the portion of the linefill sold in January and February 2000. Since such contracts are designated as hedges and correlate to price movements of crude oil, any gains or losses resulting from market changes will be largely offset by losses or gains on our hedged inventory or anticipated purchases of crude oil.
Fair Value of Financial Instruments
The carrying values of items comprising current assets and current liabilities approximate fair value due to the short-term maturities of these instruments. Crude oil futures contracts permit settlement by delivery of the crude oil and, therefore, are not financial instruments. The carrying value of bank debt approximates fair value as interest rates are variable, based on prevailing market rates. The fair value of crude oil and interest rate swap and collar agreements are based on current termination values or quoted market prices of comparable contracts.
We utilize interest rate swap and collar agreements to hedge the interest rate on our underlying debt obligations. The carrying amounts and fair values of our financial instruments are as follows (in thousands):
NOTE 9 -- EXTRAORDINARY ITEM
For the year ended December 31, 1999, we recognized an extraordinary loss related to the early extinguishment of debt. The loss is related to the reduction of the Plains Scurlock term loan facility with proceeds from our 1999 public offering and the restructuring of our letter of credit and borrowing facility as a result of the unauthorized trading losses (see Notes 3 and 7).
NOTE 10 -- INCOME TAXES
As discussed in Note 2, our predecessor's results are included in Plains Resources' combined federal income tax return. The amounts presented below were calculated as if our predecessor filed a separate tax return.
Provision in lieu of income taxes of our predecessor consists of the following components (in thousands):
A reconciliation of the provision in lieu of income taxes to the federal statutory tax rate of 35% is as follows (in thousands):
NOTE 11 -- SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
In connection with our formation, certain investing and financial activities occurred. Effective November 23, 1998, substantially all of the assets and liabilities of our predecessor were conveyed to us at historical cost. Net assets assumed by the operating partnership are as follows (restated) (in thousands):
Cash and cash equivalents $ 224 Accounts receivable 109,311 Inventory 22,906 Prepaid expenses and other current assets 1,059 Property and equipment, net 375,948 Pipeline linefill 48,264 Intangible assets, net 11,001 --------- Total assets conveyed 568,713 --------- Accounts payable and other current liabilities 107,405 Due to affiliates 8,942 Bank debt 183,600 --------- Total liabilities assumed 299,947 --------- Net assets assumed by the Partnership $ 268,766 =========
Interest paid totaled $22.3 million, $0.1 million, $8.5 million and $4.5 million for the year ended December 31, 1999, the period from November 23, 1998 to December 31, 1998, the period from January 1, 1998 through November 23, 1998 and the year ended December 31, 1997, respectively.
NOTE 12 -- MAJOR CUSTOMERS AND CONCENTRATION OF CREDIT RISK
Customers accounting for 10% or more of revenues were as follows for the periods indicated:
Financial instruments which potentially subject us to concentrations of credit risk consist principally of trade receivables. Our accounts receivable are primarily from purchasers and shippers of crude oil. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. We generally require letters of credit for receivables from customers which are not considered investment grade, unless the credit risk can otherwise be reduced. We believe that the loss of an individual customer would not have a material adverse effect.
NOTE 13 -- RELATED PARTY TRANSACTIONS
Reimbursement of Expenses of Our General Partner and Its Affiliates
We do not directly employ any persons to manage or operate our business. These functions are provided by employees of our general partner and Plains Resources. Our general partner does not receive a management fee or other compensation in connection with its management of us. We reimburse our general partner and Plains Resources for all direct and indirect costs of services provided, including the costs of employee, officer and director compensation and benefits properly allocable to us, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to us. Our agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. Total costs reimbursed to our general partner and Plains Resources by us were approximately $44.7 million and $0.5 million for the year ended December 31, 1999 and for period from November 23, 1998
to December 31, 1998, respectively. Such costs include, (1) allocated personnel costs (such as salaries and employee benefits) of the personnel providing such services, (2) rent on office space allocated to our general partner in Plains Resources' offices in Houston, Texas (3) property and casualty insurance premiums and (4) out-of-pocket expenses related to the provision of such services.
Plains Resources allocated certain general and administrative expenses to the Plains Midstream Subsidiaries during 1998 and 1997. The types of indirect expenses allocated to the Plains Midstream Subsidiaries during this period were office rent, utilities, telephone services, data processing services, office supplies and equipment maintenance. Direct expenses allocated by Plains Resources were primarily salaries and benefits of employees engaged in the business activities of the Plains Midstream Subsidiaries.
Crude Oil Marketing Agreement
We are the exclusive marketer/purchaser for all of Plains Resources' equity crude oil production. The marketing agreement with Plains Resources provides that we will purchase for resale at market prices all of Plains Resources' crude oil production for which we charge a fee of $0.20 per barrel. For the year ended December 31, 1999 and the period from November 23, 1998 to December 31, 1998, we paid Plains Resources approximately $131.5 million and $4.1 million, respectively, for the purchase of crude oil under the agreement and recognized profits of approximately $1.5 million and $0.1 million from the marketing fee for the same periods, respectively. Prior to the marketing agreement, our predecessor marketed crude oil production of Plains Resources, its subsidiaries and its royalty owners. Our predecessor paid approximately $83.4 million and $101.2 million for the purchase of these products for the period from January 1, 1998 to November 22, 1998 and the year ended December 31, 1997, respectively. In management's opinion, these purchases were made at prevailing market prices. Our predecessor did not recognize a profit on the sale of the crude oil purchased from Plains Resources.
Financing
In December 1999, our general partner loaned us $114.0 million. This subordinated debt is due not later than November 30, 2005 (see Note 6). Interest expense related to the notes was $0.6 million for the year ended December 31, 1999.
To finance a portion of the purchase price of the Scurlock acquisition, we sold to our general partner 1.3 million Class B common units at $19.125 per unit, the market value of our common units on May 12, 1999 (see Note 4).
The balance of amounts due to affiliates at December 31, 1999 and 1998 was $42.7 million and $7.8 million, respectively, and was related to the transactions discussed above.
NOTE 14 -- LONG-TERM INCENTIVE PLANS
Our general partner has adopted the Plains All American Inc. 1998 Long-Term Incentive Plan for employees and directors of our general partner and its affiliates who perform services for us. The Long-Term Incentive Plan consists of two components, a restricted unit plan and a unit option plan. The Long-Term Incentive Plan currently permits the grant of restricted units and unit options covering an aggregate of 975,000 common units. The plan is administered by the Compensation Committee of our general partner's board of directors.
Restricted Unit Plan. A restricted unit is a "phantom" unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit. As of March 15, 2000, an aggregate of approximately 500,000 restricted units have been authorized for grants to employees of our general partner, 170,000 of which have been granted with the remaining 330,000 to be granted in the near future. The Compensation Committee may, in the future, make additional grants under the plan to employees and directors containing such terms as the Compensation Committee shall determine. In general, restricted units granted to employees during the subordination period will vest only upon, and in the same proportions as, the conversion of the subordinated units to common units. Grants made to non- employee directors of our general partner will be eligible to vest prior to termination of the subordination period.
If a grantee terminates employment or membership on the board for any reason, the grantee's restricted units will be automatically forfeited unless, and to the extent, the Compensation Committee provides otherwise. Common units to be delivered upon the vesting of rights may be common units acquired by our general partner in the open market, common units already owned by our general partner, common units acquired by our general partner directly from us or any other person, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units upon vesting of the restricted units, the total number of common
units outstanding will increase. Following the subordination period, the Compensation Committee, in its discretion, may grant tandem distribution equivalent rights with respect to restricted units.
The issuance of the common units pursuant to the restricted unit plan is primarily intended to serve as a means of incentive compensation for performance. Therefore, no consideration will be paid to us by the plan participants upon receipt of the common units.
Unit Option Plan. The Unit Option Plan currently permits the grant of options covering common units. No grants have been made under the Unit Option Plan to date. However, the Compensation Committee may, in the future, make grants under the plan to employees and directors containing such terms as the committee shall determine, provided that unit options have an exercise price equal to the fair market value of the units on the date of grant. Unit options granted during the subordination period will become exercisable automatically upon, and in the same proportions as, the conversion of the subordinated units to common units, unless a later vesting date is provided.
Upon exercise of a unit option, our general partner will deliver common units acquired by it in the open market, purchased directly from us or any other person, or use common units already owned by our general partner, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the difference between the cost incurred by our general partner in acquiring such common units and the proceeds received by our general partner from an optionee at the time of exercise. Thus, the cost of the unit options will be borne by us. If we issue new common units upon exercise of the unit options, the total number of common units outstanding will increase, and our general partner will remit to us the proceeds received by it from the optionee upon exercise of the unit option.
We apply APB 25 and related interpretations in accounting for unit option plans. In accordance with APB 25, no compensation expense has been recognized for the unit option plan. Since no options have been granted to date, there is no pro forma effect of a fair value based method of accounting in accordance with Statement of Financial Accounting Standards No. 123 "Accounting for Stock- Based Compensation" ("SFAS 123").
Transaction Grant Agreements. In addition to the grants made under the Restricted Unit Plan described above, our general partner, at no cost to us, agreed to transfer approximately 400,000 of its affiliates' common units (including distribution equivalent rights attributable to such units) to certain key employees of our general partner. A grant covering 50,000 of such common units was terminated in 1999. Generally, approximately 69,444 of the remaining common units vest in each of the years ending December 31, 1999, 2000 and 2001 if the operating surplus generated in such year equals or exceeds the amount necessary to pay the minimum quarterly distribution on all outstanding common units and the related distribution on our general partner interest. If a tranche of common units does not vest in a particular year, such common units will vest at the time the common unit arrearages for such year have been paid. In addition, approximately 47,224 of the remaining common units vest in each of the years ending December 31, 1999, 2000 and 2001 if the operating surplus generated in such year exceeds the amount necessary to pay the minimum quarterly distribution on all outstanding common units and subordinated units and the related distribution on our general partner interest. In 1999, approximately 69,444 of such common units vested and 47,224 of such common units remain unvested as no distribution on the subordinated units was made for the fourth quarter of 1999. Any common units remaining unvested shall vest upon, and in the same proportion as, the conversion of subordinated units to common units. Distribution equivalent rights are paid in cash at the time of the vesting of the associated common units. Notwithstanding the foregoing, all common units become vested if Plains All American Inc. is removed as our general partner prior to January 1, 2002.
We recognized noncash compensation expense of approximately $1.0 million for the year ended December 31, 1999 related to the transaction grants which vested in 1999. We reflected a capital contribution from our general partner for a like amount.
NOTE 15 -- COMMITMENTS AND CONTINGENCIES
We lease certain real property, equipment and operating facilities under various operating leases. We also incur costs associated with leased land, rights-of-way, permits and regulatory fees whose contracts generally extend beyond one year but can be canceled at any time should they not be required for operations. Future non-cancelable commitments related to these items at December 31, 1999, are summarized below (in thousands):
2000 $ 7,484 2001 5,158 2002 1,706 2003 1,033 2004 933 Later years 1,528
Total lease expense incurred for 1999 was $8.9 million. Lease expense incurred for the period from November 23, 1998 to December 31, 1998 and from January 1, 1998 to November 22, 1998 was $0.2 million and $0.9 million, respectively.
During 1997, the All American Pipeline experienced a leak in a segment of its pipeline in California which 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 expenditures 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 $130,000 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. In addition, a portion of any such costs may be reimbursed to us from Plains Resources.
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, et al. The suit alleged that Plains All American Pipeline, L.P. and certain of our general partner's officers and directors violated federal securities laws, primarily in connection with unauthorized trading by a former employee. An additional nineteen cases have been filed in the Southern District of Texas, some of which name our general partner and Plains Resources as additional defendants. Plaintiffs allege that the defendants are 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. The court has consolidated all subsequently filed cases under the first filed action described above. Two unopposed motions are currently pending to appoint lead plaintiffs. These motions ask the court to appoint two distinct lead plaintiffs to represent two different plaintiff classes: (1) purchasers of Plains Resources common stock and options and (2) purchasers of our common units. Once lead plaintiffs have been appointed, the plaintiffs will file their consolidated amended complaints. No answer or responsive pleading is due until thirty days after a consolidated amended complaint is filed.
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 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. The derivative complaints allege, among other things, that Plains All American Pipeline has been harmed due to the negligence or breach of loyalty of the officers and directors that are named in the lawsuits. These cases are currently in the process of being consolidated. No answer or responsive pleading is due until these cases have been consolidated and a consolidated complaint has been filed.
We are a defendant, in the ordinary course of business, in various other legal proceedings in which our exposure, individually and in the aggregate, is not considered material to the accompanying financial statements.
We may experience future releases of crude oil into the environment from our pipeline and storage operations, or discover releases that were previously unidentified. While we maintain an extensive inspection program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to any future environmental releases from our assets may substantially affect our business.
NOTE 16 -- QUARTERLY FINANCIAL DATA (UNAUDITED)
- --------- (1) As indicated in Note 3, quarterly results have been restated from amounts previously reported due to the unauthorized trading losses. (2) Represents cash distributions declared per common unit for the period indicated. Distributions are paid in the quarter following declaration.
NOTE 17 -- 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 leasing of certain terminalling and storage assets. Prior to the July 1998 acquisition of the All American Pipeline and SJV Gathering System, our predecessor had only marketing, gathering, terminalling and storage operations. We evaluate segment performance based on gross margin, gross profit and income before provision in lieu of income taxes and extraordinary items.
The following table summarizes segment revenues, gross margin, gross profit and income (loss) before provision in lieu of income taxes and extraordinary items:
a) Intersegment sales were conducted on an arm's length basis. b) Gross margin is calculated as revenues less cost of sales and operations expenses. c) Gross profit is calculated as revenues less costs of sales and operations expenses and general and administrative expenses.