Item 3. LEGAL PROCEEDINGS
The Partnership, in the ordinary course of business, is a claimant and/or a defendant in various legal proceedings in which its exposure, individually and in the aggregate, is not considered material to the Partnership.
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, representing limited partner interests in the Partnership, are listed and traded on the New York Stock Exchange under the symbol "PAA". The Common Units began trading on November 18, 1998, at an initial public offering price of $20.00 per Common Unit. On March 22, 1999, the market price for the Common Units was $17.125 per unit and there were approximately 12,300 record holders and beneficial owners (held in street name) of the Partnership's Common Units.
The following table sets forth, for the portion of the fourth quarter 1998 in which the Common Units were traded, the range of high and low closing sales prices for the Common Units as reported on the New York Stock Exchange Composite Tape, and the amount of cash distribution paid per Common Unit for the portion of the fourth quarter 1998 commencing November 23, 1998, the date of closing of the IPO.
The Partnership has also issued Subordinated Units, all of which are held by an affiliate of the General Partner, for which there is no established public trading market. The Partnership will distribute to its partners (including holders of Subordinated Units), on a quarterly basis, all of its Available Cash in the manner described herein. Available Cash generally means, with respect to any quarter of the Partnership, all cash on hand at the end of such quarter less the amount of cash reserves that is necessary or appropriate in the reasonable discretion of the General Partner to (i) provide for the proper conduct of the Partnership's business, (ii) comply with applicable law or any Partnership debt instrument or other agreement, or (iii) provide funds for distributions to Unitholders and the General Partner in respect of any one or more of the next four quarters. Available Cash is defined in the Second Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. (the APartnership Agreement") listed as an exhibit to this report. The Partnership Agreement defines Minimum Quarterly Distributions as $ 0.45 for each full fiscal quarter (prorated for the initial partial fiscal quarter commencing November 23, 1998, the closing date of the IPO through year-end 1998). The Partnership made a cash distribution in the amount of $ 5.8 million on February 12, 1999, in respect to its Common Units and Subordinated Units for the period of November 23, 1998 through year-end 1998. This payment was based upon $ 0.193 per unit, which was the Minimum Quarterly Distribution prorated for the partial quarter in accordance with the Partnership Agreement. Distributions of Available Cash to the holder 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 the Partnership's Bank Credit Agreement and Letter of Credit Facility, the Partnership is prohibited from declaring or paying any distribution to Unitholders if a Default or Event of Default (as defined in such agreements) exists thereunder. See Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources, Liquidity and Financial Condition in Item 7 of this report.
Item 6.
Item 6. SELECTED FINANCIAL DATA
SELECTED FINANCIAL AND OPERATING DATA
On November 23, 1998, the Partnership completed the IPO and the Transactions whereby the Partnership became the successor to the business of the Predecessor. The following selected pro forma and historical financial information was derived from the audited consolidated financial statements of the Partnership as of December 31, 1998, and for the period from November 23, 1998 through December 31, 1998, and the audited combined financial statements of the Predecessor, as of December 31, 1997, 1996, 1995 and 1994 and for the period from January 1, 1998 through November 22, 1998 and for the years ended December 31, 1997, 1996, 1995 and 1994, including the notes thereto, certain of which appear elsewhere in this Report. The Predecessor operating data for all periods is derived from the records of the Partnership and the Predecessor. Commencing July 30, 1998, (the date of the 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. The selected financial data should be read in conjunction with the consolidated and combined financial statements, including the notes thereto, and Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations".
(Financial data continued on the next page. See footnotes on next page.)
(1) The unaudited selected pro forma financial and operating data for the year ended December 31, 1998, is based on the historical financial statements of the Partnership, the Predecessor and Wingfoot. 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, the Predecessor acquired the All American Pipeline and SJV Gathering system from Goodyear for approximately $400 million. The pro forma selected financial data reflects certain pro forma adjustments to the historical results of operations as if the Partnership had been formed and the Acquisition had taken place on January 1, 1998. The pro forma adjustments include: (i) pro forma depreciation and amortization expense based on the purchase price of the Wingfoot assets by the Predecessor; (ii) the elimination of interest expense on loans from Goodyear to Wingfoot as all such debt was extinguished in connection with the Acquisition; (iii) the reduction in compensation and benefits expense due to the termination of personnel in connection with the Acquisition; (iv) the elimination of interest expense of the Predecessor related to debt owed to Plains Resources as such debt was extinguished in connection with the Transactions; (v) pro forma interest on debt assumed by the Partnership on the closing date of the IPO; and (vi) the elimination of income tax expense as income taxes will be borne by the partners and not the Partnership. The pro forma adjustments do not include approximately $0.9 million of general and administrative expenses that the General Partner believes will be incurred by the Partnership as a result of its being a separate public entity. (2) Basic and diluted net income (loss) per Unit for the Partnership is computed by dividing the limited partners' 98% interest in net income by the number of outstanding Common and Subordinated Units. For periods prior to November 23, 1998, such units are equal to the Common and Subordinated Units received by the General Partner in exchange for the assets contributed to the Partnership (3) Excludes intercompany debt. (4) EBITDA means earnings before interest expense, income taxes, depreciation and amortization. EBITDA provides additional information for evaluating the Partnership's ability to make the Minimum Quarterly Distribution and is presented solely as a supplemental measure. EBITDA is not a measurement presented in accordance with generally accepted accounting principles ("GAAP") and is not intended to be used in lieu of GAAP presentations of results of operations and cash provided by operating activities. The Partnership's EBITDA may not be comparable to EBITDA of other entities as other entities may not calculate EBITDA in the same manner as the Partnership. (5) 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 the Partnership's 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. (6) Represents crude oil deliveries on the All American Pipeline for the account of third parties. (7) Represents crude oil deliveries on the All American Pipeline and the SJV Gathering System for the account of affiliated entities (8) Represents barrels of crude oil purchased at the wellhead, including volumes which would have been purchased under the Crude Oil Marketing Agreement. (9) Represents barrels of crude oil purchased at collection points, terminals and pipelines. (10) 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 the financial condition and results of operations for the Partnership and its predecessor entities should be read in conjunction with the historical consolidated and combined financial statements and notes thereto of the Partnership and the Plains Midstream Subsidiaries 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.
General
The Partnership is a limited partnership which was formed in the third quarter of 1998 to acquire and operate the midstream crude oil business and assets of Plains Resources. The Partnership is engaged in interstate and intrastate crude oil pipeline transportation and crude oil terminalling and storage activities and gathering and marketing activities. The Partnership's operations are primarily concentrated in California, Texas, Oklahoma, Louisiana and the Gulf of Mexico. The historical results of operations discussed below are derived from the historical financial statements of the Partnership and the Predecessor included elsewhere herein.
Pipeline Operations. The activities from pipeline operations generally consist of transporting third-party volumes of crude oil for a tariff ("Tariff Activities") 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 ("Margin Activities"). Tariffs on the All American Pipeline vary by receipt point and delivery point. Tariffs for OCS crude oil delivered to California markets averaged $1.41 per barrel and tariffs for OCS volumes delivered to West Texas were $2.96 per barrel as of December 31, 1998. Tariffs for San Joaquin Valley crude oil delivered to West Texas were $1.25 per barrel as of December 31, 1998. The gross margin generated by 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. As is common with most merchant activities, the ability of the Partnership 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 the price paid and other costs incurred in the purchase of crude oil and the price at which it sells crude oil. The Partnership is well positioned to take advantage of these price differentials due to its ability to move purchased volumes on the All American Pipeline. The Partnership combines 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 the Cushing Terminal. Gross margin from the Partnership's gathering and marketing activities is dependent on the Partnership's ability to sell crude oil at a price in excess of the 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.
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. The Partnership believes that the combination of its terminalling and storage activities and gathering and marketing activities provides a counter-cyclical balance which has a stabilizing effect on the Partnership's operations and cash flow.
As the Partnership purchases crude oil, it establishes 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, the Partnership seeks to maintain a position that is substantially balanced between crude oil purchases and sales and future delivery obligations. The Partnership purchases crude oil on both a fixed and floating price basis. As fixed price barrels are purchased, the Partnership enters 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, the Partnership matches those contracts with similar type sales agreements with its customers, or likewise establishes a hedge position using the NYMEX futures market. From time to time, the Partnership will enter into arrangements which will expose it 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. The Partnership's policy is only to purchase crude oil for which it has a market and to structure its sales contracts so that crude oil price fluctuations do not materially affect the gross margin which it receives. The Partnership does 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 the Partnership to indeterminable losses.
The Partnership
Analysis of Pro Forma Results of Operations
The pro forma results of operations discussed below are derived from the historical financial statements of the Partnership, Wingfoot (which reflect the historical operating results of the All American Pipeline and the SJV Gathering System) and the Predecessor, certain of which are included elsewhere herein. Commencing July 30, 1998, (the date of the 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. The pro forma results of operations reflect certain pro forma adjustments to the historical results of operations as if the Partnership had been formed and the acquisition of the All American Pipeline and the SJV Gathering System had taken place on January 1, 1997. The pro forma adjustments include: (i) pro forma depreciation and amortization expense based on the purchase price of the Wingfoot assets by the Predecessor; (ii) the elimination of interest expense on loans from Goodyear to Wingfoot as all such debt was extinguished in connection with the Acquisition, (iii) the reduction in compensation and benefits expense due to the termination of personnel in connection with the Acquisition; (iv) the elimination of interest expense of the Predecessor related to debt owed to Plains Resources as such debt was extinguished in connection with the Transactions; (v) pro forma interest on debt assumed by the Partnership on the Closing Date and (vi) the elimination of income tax expense as income taxes will be borne by the partners and not the Partnership. The pro forma adjustments do not include approximately $0.9 million of general and administrative expenses for the years ended December 31, 1998 and 1997, respectively, that the General Partner believes will be incurred by the Partnership as a result of its being a separate public entity.
Year Ended December 31, 1998 and 1997
The following table sets forth certain pro forma financial and operating information of the Partnership for the periods presented.
The following analysis compares the pro forma results of the Partnership for the years ended December 31, 1998 and 1997.
For the year ended December 31, 1998, the Partnership's net income was $43.9 million on total revenue of $1.6 billion compared to a net loss for the year ended December 31, 1997 of $10.1 million on total revenue of $1.7 billion. The pro forma net loss for the year ended December 31, 1997 includes a non-cash impairment charge of $64.2 million related to the writedown of pipeline assets and linefill by Wingfoot in connection with the sale of Wingfoot by Goodyear to the General Partner. Based on the Partnership's purchase price allocation to property and equipment and pipeline linefill, an impairment charge would not have been required had the Partnership actually acquired Wingfoot effective January 1, 1997. Excluding this impairment charge, the Partnership's pro forma net income for 1997 would have been $54.1 million. The Partnership reported gross margin (revenues less direct expenses of purchases, transportation, terminalling and storage and other operating and maintenance expenses) of $74.1 million for the year ended December 31, 1998, reflecting a 12% decrease from the $84.2 million reported for the same period in 1997. Gross profit (gross margin less general and administrative expense) decreased 13% to $67.6 million for the year ended December 31,1998 as compared to $78.0 million for the same period in 1997.
Pipeline Operations. Tariff revenues were $57.5 million for the year ended December 31, 1998, a 30% decline from the $82.1 million reported for the same period in 1997. This decrease in tariff revenues resulted primarily from a 24% decrease in tariff transport volumes from 165,000 barrels per day for the year ended December 31, 1997 to 125,000 barrels per day for the same period in 1998 due to a decline in average daily production from the Santa Ynez field. Most of the production loss from the Santa Ynez field was of volumes that had been previously transported to West Texas at an average tariff of $2.83 per barrel. Volumes related to Margin Activities increased by 63% to an average of approximately 49,000 barrels per day. The margin between revenue and direct cost of crude purchased decreased from $17.6 million for the year ended December 31, 1997 to $14.5 million for the same period in 1998 as a result of a decline in margins between prices paid in California and prices received in West Texas.
The following table sets forth All American Pipeline average deliveries per day within and outside California for the periods presented.
Year Ended December 31, ----------------------- 1998 1997 --------- --------- (in thousands) (pro forma) Deliveries: Average daily volumes (barrels): Within California 113 127 Outside California 61 68 --- --- Total 174 195 === ===
Terminalling and Storage Activities and Gathering and Marketing Activities. The Partnership reported gross margin of $23.2 million from its terminalling and storage activities and gathering and marketing activities for the year ended December 31, 1998, reflecting a 64% increase over the $14.1 million reported for the same period in 1997. Including interest expense associated with contango inventory transactions, gross margin for the year ended December 31, 1998 was $22.5 million, representing an increase of approximately 70% over the 1997 amount. The increase in gross margin was primarily attributable to an increase in the volumes gathered and marketed, principally in West Texas, Louisiana and the Gulf of Mexico of approximately 20% to 113,000 barrels per day for the year ended December 31, 1998 from 94,000 barrels per day during the same period in 1997. The balance of the increase in gross margin was a result of an increase in bulk purchases.
Expenses. Operations and maintenance expenses included in cost of sales and operations (generally property taxes, electricity, fuel, labor, repairs and certain other expenses) decreased to $24.9 million for the year ended December 31, 1998 from $32.5 million for the comparable period in 1997. This decrease was a function both of variable costs that decline with reduced transportation volumes and average miles transported per barrel. Operations and maintenance expenses are included in the determination of gross margin. General and administrative expenses increased approximately $0.3 million to $6.5 million for the year ended December 31, 1998 compared to $6.2 million for the same period in 1997. Such increase was primarily related to additional personnel hired to further expand marketing activities. Depreciation and amortization expense was $11.3 million for the year ended December 31, 1998 compared to $11.0 million for the 1997 comparative period. The increase is due primarily to the addition of trucking equipment. Interest expense was $13.0 million for the year ended December 31, 1998 compared to $13.1 million for 1997.
Analysis of Historical Results of Operations
On November 23, 1998, the Partnership completed the IPO and the Transactions whereby the Partnership became the successor to the business of the Predecessor. The historical results of operations discussed below are derived from the historical financial statements of the Partnership for the period from November 23, 1998, through December 31, 1998, and the combined financial statements of the Plains Midstream Subsidiaries 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 the 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. The Partnership and the Predecessor are referred to for purposes of this analysis of historical results as the "Partnership".
Three Years Ended December 31, 1998
For 1998, the Partnership reported net income before taxes of $15.8 million on total revenue of $1.1 billion compared to net income before taxes for 1997 of $3.4 million on total revenue of $752.5 million and net income before taxes for 1996 of $1.9 million on total revenue of $531.7 million. Results for the year ended December 31, 1998 include activities of the All American Pipeline and SJV Gathering System since July 30, 1998 (the date of acquisition from Goodyear).
The following table sets forth certain financial and operating information of the Partnership for the periods presented:
Pipeline Operations. As noted above, the results of operations of the Partnership includes approximately five months of operations of the All American Pipeline and the SJV Gathering System which were acquired effective July 30, 1998. Tariff revenues for this period were $19.0 million and are primarily attributable to transport volumes from the Santa Ynez field (approximately 65,300 barrels per day) and the Point Arguello field (approximately 24,300 barrels per day). The margin between revenue and direct cost of crude purchased was approximately $3.9 million. Operations and maintenance expenses were $6.1 million.
The following table sets forth the All American Pipeline average deliveries per day within and outside California from July 30, 1998 through December 31, 1998 (in thousands).
Deliveries: Average daily volumes (barrels): Within California 111 Outside California 52 --------- Total 163 =========
Terminalling and Storage Activities and Gathering and Marketing Activities. Gross margin from terminalling and storage and gathering and marketing activities was $21.7 million for the year ended December 31, 1998, reflecting a 74% increase over the $12.5 million reported for the 1997 period and an approximate 128% increase over the $9.5 million reported for 1996. Including interest expense associated with contango inventory transactions, gross margin for 1998 was $21.0 million, representing an increase
of approximately 81% over the 1997 amount. The Partnership did not have any material contango inventory transactions in 1996. The increase in gross margin was primarily attributable to an increase in the volumes gathered and marketed in West Texas, Louisiana and the Gulf of Mexico and activities at the Cushing Terminal.
Total general and administrative expenses were $5.3 million for the year ended December 31, 1998, compared to $3.5 million and $3.0 million for 1997 and 1996, respectively. Such increases were primarily attributable to increased personnel as a result of the continued expansion of the Partnership's terminalling and storage activities and gathering and marketing activities as well as general and administrative expenses associated with the addition of the All American Pipeline and the SJV Gathering System. Depreciation and amortization was $5.4 million in 1998, $1.2 million in 1997 and $1.1 million in 1996. The increase is due the acquisition of the All American Pipeline and the SJV Gathering System in 1998.
Interest expense was $12.6 million in 1998, $4.5 million in 1997 and $3.6 million in 1996. The increase in 1998 is due to interest associated with the debt incurred for the acquisition of the All American Pipeline and the SJV Gathering System. Interest expense in 1997 and 1996 is comprised principally of interest charged to the Predecessor by Plains Resources for amounts borrowed to construct the Cushing Terminal in 1993 and subsequent capital additions, including the Ingleside Terminal. The interest rate on the Cushing Terminal construction loan was 10.25%. Interest expense also includes interest incurred in connection with contango inventory transactions of $0.8 million in 1998 and $.9 million in 1997.
The Predecessor is included in the consolidated federal income tax return of Plains Resources. Federal income taxes are calculated as if the Predecessor had filed its return on a separate company basis utilizing a federal statutory rate of 35%. The Predecessor reported a total tax provision of approximately $4.6 million, $1.3 million and $0.7 million for the period from January 1, 1998 to November 22, 1998 and for the years ended December 31, 1997 and 1996, respectively.
Capital Resources, Liquidity and Financial Condition
Concurrently with the closing of the IPO, the Partnership entered into the Bank Credit Agreement that includes the Term Loan Facility and the Revolving Credit Facility. The Partnership may borrow up to $50 million under the Revolving Credit Facility for acquisitions, capital improvements, working capital and general business purposes.
The Term Loan Facility bears interest at the Partnership's option at either (i) the Base Rate, as defined, or (ii) reserve-adjusted LIBOR plus an applicable margin. Borrowings under the Revolving Credit Facility bear interest at the Partnership's option at either (i) the Base Rate, as defined, or (ii) reserve- adjusted LIBOR plus an applicable margin. The Partnership incurs a commitment fee on the unused portion of the Revolving Credit Facility.
At December 31, 1998, $175 million was outstanding under the Term Loan Facility, which amount represents indebtedness assumed from the General Partner. The Partnership has two 10-year interest rate swaps (each of which can be terminated by the counterparty at the end of the seventh year) aggregating $175 million which fix the LIBOR portion of the interest rate (not including the applicable margin) at a weighted average rate of approximately 5.24%. 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 2000. All borrowings for working capital purposes outstanding under the Revolving Credit Facility must be reduced to no more than $8 million for at least 15 consecutive days during each fiscal year. At December 31, 1998, there were no amounts outstanding under the Revolving Credit Facility. The Bank Credit Agreement is collateralized by a lien on substantially all of the assets of the Partnership.
Simultaneously with the IPO, Marketing entered into a $175 million letter of credit and borrowing facility which replaced an existing facility. The purpose of the Letter of Credit Facility is to provide (i) standby letters of credit to support the purchase and exchange of crude oil for resale and (ii) borrowings to finance crude oil inventory which has been hedged against future price risk or designated as working inventory. The Letter of Credit Facility is collateralized by a lien on substantially all of the assets of the Partnership. 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 current assets and current liabilities of the Partnership primarily crude oil inventory and accounts receivable and accounts payable related to the purchase and sale of crude oil. At December 31, 1998, the borrowing base under the Letter of Credit Facility was approximately $175 million.
The Letter of Credit Facility has a $40 million sublimit for borrowings to finance crude oil purchased in connection with operations at the Partnership's crude oil terminal and storage facilities. All purchases of crude oil inventory financed are required to be hedged against future price risk on terms acceptable to the lenders. At December 31, 1998, approximately $9.8 million was outstanding under the sublimit.
Letters of credit under the Letter of Credit Facility are generally issued for up to 70 day periods. Borrowings bear interest at the Partnership's option at either (i) the Base Rate (as defined) or (ii) reserve-adjusted LIBOR plus the applicable margin. The Partnership incurs a commitment fee on the unused portion of the borrowing sublimit under the Letter of Credit Facility and an issuance fee for each letter of credit issued. The Letter of Credit Facility expires July 31, 2001. At December 31, 1998, there were outstanding letters of credit of approximately $62 million issued under the Letter of Credit Facility.
Both the Letter of Credit Facility and the Bank Credit Agreement contain a prohibition on distributions on, or purchases or redemptions of, Units if any Default or Event of Default (as defined) is continuing. In addition, both facilities contain various covenants limiting the ability of the Partnership to (i) incur indebtedness, (ii) grant certain liens, (iii) sell assets in excess of certain limitations, (iv) engage in transactions with affiliates, (v) make investments, (vi) enter into hedging contracts and (vii) enter into a merger, consolidation or sale of its assets. In addition, the terms of the Letter of Credit Facility and the Bank Credit Agreement require the Partnership to maintain (i) a Current Ratio (as defined) of at least 1.0 to 1.0; (ii) a Debt Coverage Ratio (as defined) which is not greater than 5.0 to 1.0; (iii) an Interest Coverage Ratio (as defined) which is not less than 3.0 to 1.0; (iv) a Fixed Charge Coverage Ratio (as defined) which is not less than 1.25 to 1.0; and (v) a Debt to Capital Ratio (as defined) of not greater than .60 to 1.0. In both the Letter of Credit Facility and the Bank Credit Agreement, a Change in Control (as defined) of Plains Resources or the General Partner constitutes an Event of Default.
The Partnership will distribute 100% of its Available Cash within 45 days after the end of each quarter to Unitholders of record and to the General partner. Available Cash is generally defined as all cash and cash equivalents of the Partnership on hand at the end of each quarter less reserves established by the 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 Subordination 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 Subordination 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), the 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 the Partnership's 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.
On February 12, 1999, the Partnership paid a cash distribution of $0.193 per unit on its outstanding Common Units and Subordinated Units. The $5.8 million distribution was paid to Unitholders of record at the close of business on January 29, 1999. A distribution of approximately $118,000 was paid to the General Partner. The distributions represented a partial quarterly distribution for the 39-day period from November 23, 1998, the closing of the IPO, through December 31, 1998.
Commitments
Historically, capital expenditures for the Partnership have not been significant. Due to the relatively recent construction of the All American Pipeline, the SJV Gathering System and the Cushing Terminal, material maintenance capital expenditures have not been required, and the majority of capital expenditures have been associated with expansion opportunities. While the actual level of maintenance capital expenditures will vary from year to year, the Partnership expects such expenditures to average approximately $2 million to $4 million annually for the next several years. It is anticipated that such maintenance capital expenditures will be funded from cash flow generated by operating activities.
The Partnership has entered into a turnkey contract to construct an additional one million barrels of tankage at the Cushing Terminal, expanding its existing tank capacity by 50% to three million barrels. Construction of the expansion project began in September 1998 and is expected to be completed in the second quarter of 1999 at a total cost of approximately $10 million. Approximately $4.2 million of such cost was incurred in 1998. It is anticipated that the remaining expenditures for the expansion will be funded from borrowings under the Revolving Credit Facility. To date, the Partnership has no material commitments to fund additional capital expenditures.
The Partnership owns approximately 5.0 million barrels of crude oil that is used to maintain the All American Pipeline's linefill requirements. The Partnership has amended its tariff with the FERC to require third party shippers to buy linefill from the Partnership and replenish the linefill when their movement of crude oil on the All American Pipeline is completed. Accordingly, the Partnership does not anticipate large variations in the amounts of linefill provided by the Partnership in the future.
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 is effective for all fiscal years beginning after June 15, 1999. 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 it is, the type of hedge transaction. For fair-value hedge transactions in which the Partnership is 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 the Partnership is 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. SFAS 133 is required to be applied to financial statements issued by the Partnership beginning in 2000. The Partnership has not yet determined the effect that the adoption of SFAS 133 will have on its results of operations or financial position.
In November 1998, the Emerging Issues Task Force ("EITF") released Issue No. 98-10, "Accounting for Energy Trading and Risk Management Activities". EITF 98-10 deals with entities that enter into derivatives and other third-party contracts for the purchase and sale of a commodity in which they normally do business (for example, crude oil and natural gas). The EITF reached a consensus that energy trading contracts should be measured at fair value, determined as of the balance sheet date, with the gains and losses included in earnings and separately disclosed in the financial statements or footnotes thereto. The EITF acknowledged that determining whether or when an entity is involved in energy trading activities is a matter of judgment that depends on the relevant facts and circumstances. As such, certain factors or indicators have been identified by the EITF which should be considered in evaluating whether an operation's energy contracts are entered into for trading purposes. EITF 98-10 is required to be applied to financial statements issued by the Partnership beginning in 1999. The adoption of this consensus is not expected to have a material impact on the Partnership's results of operations or financial position.
Year 2000
Year 2000 Issue. Some software applications, hardware and equipment and embedded chip systems identify dates using only the last two digits of the year. These products may be unable to distinguish between dates in the Year 2000 and dates in the year 1900. That inability (referred to as the "Year 2000" issue), if not addressed, could cause applications, equipment or systems to fail or provide incorrect information after December 31, 1999, or when using dates after December 31, 1999. This in turn could have an adverse effect on the Partnership, because the Partnership directly depends on its own applications, equipment and systems and indirectly depends on those of other entities with which the Partnership must interact.
Compliance Program. In order to address the Year 2000 issues, the Partnership is participating in the Year 2000 project which Plains Resources has implemented for all of its business units. A project team has been established to coordinate the six phases of this Year 2000 project to assure that key automated systems and related processes will remain functional through Year 2000. Those phases include: (i) awareness, (ii) assessment, (iii) remediation, (iv) testing, (v) implementation of the necessary modifications and (vi) contingency planning. The key automated systems consist of (a) financial systems applications, (b) hardware and equipment, (c) embedded chip systems and (d) third-party developed software. The evaluation of the Year 2000 issue includes the evaluation of the Year 2000 exposure of third parties material to the operations of the Partnership or any of its business units. Plains Resources retained a Year 2000 consulting firm to review the operations of all of its business units and to assess the impact of the Year 2000 issue on such operations. Such review has been completed and the consultant's recommendations are being utilized in the Year 2000 project.
The Partnership's State of Readiness. The awareness phase of the Year 2000 project has begun with a company-wide awareness program which will continue to be updated throughout the life of the project. The portion of the assessment phase related to financial systems applications has been substantially completed and the necessary modifications and conversions are underway. The portion of the assessment phase which will determine the nature and impact of the Year 2000 issue for hardware and equipment, embedded chip systems, and third-party developed software is continuing. The Partnership has retained a Year 2000 consulting firm which is currently identifying and evaluating field equipment which has embedded chip systems. The assessment phase of the project involves, among other things, efforts to obtain representations and assurances from third parties, including third party vendors, that
their hardware and equipment, embedded chip systems, and software being used by or impacting the Partnership or any of its business units are or will be modified to be Year 2000 compliant. To date, the responses from such third parties are inconclusive. As a result, management cannot predict the potential consequences if these or other third parties are not Year 2000 compliant. The exposure associated with the Partnership's interaction with third parties is currently being evaluated. Management expects that the remediation, testing and implementation phases will be substantially completed by the third quarter of 1999.
Contingency Planning. As part of the Year 2000 project, the Partnership will seek to determine which of its business activities may be vulnerable to a Year 2000 disruption. Appropriate contingency plans will then be developed for each "at risk" business activity to provide an alternative means of functioning which minimizes the effect of the potential Year 2000 disruption, both internally and on those with whom it does business. Such contingency plans are expected to be completed by the fourth quarter of 1999.
Costs to Address Year 2000 Compliance Issues. Through December 31, 1998, the Partnership has borne approximately $264,000 as its share of expenses for the Year 2000 project. While the total cost to the Partnership of the Year 2000 project is still being evaluated, management currently estimates that the costs to be incurred in 1999 and 2000 associated with assessing, testing, modifying or replacing financial system applications, hardware and equipment, embedded chip systems and third party developed software is between $350,000 and $450,000. The Partnership expects to fund these expenditures with cash from operations or borrowings. Based upon these estimates, the Partnership does not expect the costs of its Year 2000 project to have a material adverse effect on its financial position, results of operation or cash flows.
Risk of Non-Compliance. The major applications that pose the greatest Year 2000 risks for the Partnership if implementation of the Year 2000 compliance program is not successful are the Partnership's financial systems applications and the Partnership's SCADA computer systems and embedded chip systems in field equipment. The potential problems if the Year 2000 compliance program is not successful are disruptions of the Partnership's revenue gathering from and distribution to its customers and vendors and the inability to perform its other financial and accounting functions. Failures of embedded chip systems in field equipment of the Partnership or its customers could disrupt the Partnership's crude oil transportation, terminalling and storage activities and gathering and marketing activities.
While the Partnership believes that its Year 2000 project will substantially reduce the risks associated with the Year 2000 issue, there can be no assurance that it will be successful in completing each and every aspect of the project on schedule, and if successful, the project will have the expected results. Due to the general uncertainty inherent in the Year 2000 issues, the Partnership cannot conclude that its failure or the failure of third parties to achieve Year 2000 compliance will not adversely affect its financial position, results of operations or cash flows.
Item 7a.
Item 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
The Partnership is exposed to various market risks, including volatility in crude oil commodity prices and interest rates. To manage such exposure, the Partnership monitors its inventory levels, current economic conditions and its expectations of future commodity prices and interest rates when making decisions with respect to risk management. The Partnership does not enter into derivative transactions for speculative trading purposes. Substantially all the Partnership's derivative contracts are exchanged or traded with major financial institutions and the risk of credit loss is considered remote.
As the Partnership purchases crude oil, it establishes 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, the Partnership seeks to maintain a position that is substantially balanced between crude oil purchases and sales and future delivery obligations. From time to time, the Partnership enters into fixed price delivery contracts, floating price collar arrangements, financial swaps and oil futures contracts as hedging devices. To hedge the price exposure related to crude oil that the Partnership is committed to purchase, the Partnership may sell futures contracts and thereafter either (i) make physical delivery of such purchased crude oil against the futures contract or (ii) buy a matching futures contract to unwind its futures position and sell its crude oil to a customer. Such contracts may expose the Partnership to the risk of financial loss in certain circumstances, including instances where production is less than expected, the Partnership's customers fail to purchase or deliver the contracted quantities of crude oil, or a sudden, unexpected event materially affects crude oil prices. Such contracts may also restrict the ability of the Partnership to benefit from unexpected increases in crude oil prices. The Partnership's policy is generally to purchase only crude oil for which it has a market and to structure its sales contracts so that crude oil price fluctuations do not materially affect the gross margin which it receives.
The Partnership has interest rate swaps for an aggregate notional principal amount of $175 million which fix the LIBOR portion of the interest rate (not including the applicable margin) on the Term Loan Facility. At December 31, 1998, the Partnership would be required to pay approximately $2.2 million to terminate the interest rate swaps as of such date.
Commodity Price Risk
The fair value of outstanding derivative commodity instruments and the change in fair value that would be expected from a 10 percent adverse price change are shown in the table below:
Change in Fair Fair Value from 10% At December 31, 1998 Value Adverse Price Change -------------------- ---------------- ----------------------- (in millions)
Crude oil futures contracts $ 1.8 $(0.3)
The fair values of the futures contracts are based on quoted market prices obtained from the NYMEX. 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 the Partnership's derivative portfolio would typically change less than that shown in the table due to lower volatility in out-month prices.
Additional details regarding accounting policy for these financial statements are set forth in Note 1 to the Consolidated and Combined Financial Statements.
Interest Rate Risk
The Partnership's debt instruments are sensitive to market fluctuations in interest rates. The table below presents principal cash flows and the related weighted average interest rates by expected maturity dates. The Partnership's 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, 1998. The carrying value of variable rate bank debt approximates fair value as interest rates are variable, based on prevailing market rates.
Item 8.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required to be provided in this item is included in the Consolidated and Combined Financial Statements of the Partnership and the Plains Midstream Subsidiaries, including the notes thereto, attached hereto as pages to and such information is incorporated herein by reference.
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 THE GENERAL PARTNER
Partnership Management
The General Partner manages and operates the activities of the Partnership. The Unitholders do not directly or indirectly participate in the management or operation of the Partnership or have actual or apparent authority to enter into contracts on behalf of, or to otherwise bind, the Partnership. Notwithstanding any limitation on its obligations or duties, the General Partner is liable, as general partner of the Partnership, for all debts of the Partnership (to the extent not paid by the Partnership), except to the extent that indebtedness or other obligations incurred by the Partnership are made specifically non-recourse to the General Partner. Whenever possible, the General Partner intends to make any such indebtedness or other obligations non-recourse to the General Partner.
The General Partner recently appointed Arthur L. Smith to its Board of Directors. Mr. Smith, who is neither an officer nor employee of the General Partner nor a director, officer or employee of any affiliate of the General Partner, serves on the Conflicts Committee, which has the authority to review specific matters as to which the Board of Directors believes there may be a conflict of interest in order to determine if the resolution of such conflict proposed by the General Partner is fair and reasonable to the Partnership. An additional independent director is expected to be appointed during the year to serve on the General Partner's Board of Directors and the Conflicts Committee. Any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to the Partnership, approved by all partners of the Partnership and not a breach by the General Partner or its Board of Directors of any duties they may owe the Partnership or the Unitholders. The Audit Committee, comprised of Messrs. Smith and Robert V. Sinnott, reviews the external financial reporting of the Partnership, recommends engagement of the Partnership's independent public accountants and reviews the Partnership's procedures for internal auditing and the adequacy of the Partnership's internal accounting controls. The Compensation Committee, comprised of Messrs. Smith and Sinnott, oversees compensation decisions for the officers of the General Partner as well as the compensation plans described below.
As is commonly the case with publicly traded limited partnerships, the Partnership does not directly employ any of the persons responsible for managing or operating the Partnership. These functions are provided by employees of the General Partner and Plains Resources.
Directors and Executive Officers of the General Partner
The following table sets forth certain information with respect to the executive officers and members of the Board of Directors of the General Partner. Executive officers and directors are elected annually and have held the following positions with the General Partner since its formation in February 1998, except for Messrs. Sinnott and Smith who were appointed to the Board in September 1998 and February 1999, respectively.
Greg L. Armstrong 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 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 is also President of the Plains Midstream Subsidiaries.
Phillip D. Kramer 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 been 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 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.
Cynthia A. Feeback has been Assistant Treasurer and Controller of Plains Resources since May 1998. She previously served Plains Resources as Controller and Principal Accounting Officer from 1993 to 1998; Controller from 1990 to 1993; and Accounting Manager from 1988 to 1990.
Robert V. Sinnott has been Senior 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 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. 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, executive officers and persons who beneficially own more than ten percent of a registered class of the Partnership's 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 the Partnership with copies of all Section 16(a) forms that they file. Based solely upon a review of the copies of the forms furnished to it, or written representations from certain reporting persons that no Forms 5 were required, the Partnership believes that during 1998 its officers and directors complied with all filing requirements with respect to the Partnership's equity securities.
Reimbursement of Expenses of the General Partner and its Affiliates
The General Partner does not receive any management fee or other compensation in connection with its management of the Partnership. The General Partner and its affiliates, including Plains Resources, performing services for the Partnership are reimbursed for all expenses incurred on behalf of the Partnership, including the costs of employee, officer and director compensation and benefits properly allocable to the Partnership, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, the Partnership. The Partnership Agreement provides that the General Partner will determine the expenses that are allocable to the Partnership in any reasonable manner determined by the General Partner in its sole discretion.
Item 11.
Item 11. EXECUTIVE COMPENSATION
The Partnership was formed in September 1998 but conducted no business until late November 1998. Mr. Armstrong, the General Partner's Chief Executive Officer received no compensation for services to the Partnership in 1998. No officer of the General Partner received compensation for services to the Partnership in 1998 in amounts greater than $100,000.
Employment Agreement
Mr. Pefanis has an employment agreement with Plains Resources. Pursuant to the employment agreement, Mr. Pefanis serves as President and Chief Operating Officer of the General Partner as well as an Executive Vice President of Plains Resources and is responsible for the overall operations of the General Partner and the marketing operations of Plains Resources. 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 the General Partner. The employment agreement has an initial term, commencing November 23, 1998, of three years subject to annual extensions and includes confidentiality, nonsolicitation and noncompete provisions, which, in general, will continue for 24 months following Mr. Pefanis' termination of employment. The agreement provides for an annual base salary of $235,000, subject to such increases as the Board of Directors of Plains Resources may authorize from time to time. In
addition, Mr. Pefanis is eligible to receive an annual cash bonus to be determined by the Board of Directors of Plains Resources. Mr. Pefanis participates in the Long-Term Incentive Plan of the General Partner as described below and is also entitled to participate in such other benefit plans and programs as the General Partner may provide for its employees in general. 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 (i) his highest rate of annual base salary and (ii) the largest annual bonus paid during the three preceding years.
Long-Term Incentive Plan
The General Partner has adopted the Plains All American Inc. 1998 Long-Term Incentive Plan (the "Long-Term Incentive Plan") for employees and directors of the General Partner and its affiliates who perform services for the Partnership. The Long-Term Incentive Plan consists of two components, a restricted unit plan (the "Restricted Unit Plan") and a unit option plan (the "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 the 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 22, 1999, an aggregate of approximately 500,000 Restricted Units have been granted to employees of the General Partner, including 60,000 and 30,000 units granted to Messrs. Pefanis and Coiner, respectively. The Compensation Committee may, in the future, determine to make additional grants under such 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 the 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 the General Partner in the open market, Common Units already owned by the General Partner, Common Units acquired by the General Partner directly from the Partnership or any other person, or any combination of the foregoing. The General Partner will be entitled to reimbursement by the Partnership for the cost incurred in acquiring such Common Units. If the Partnership issues 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 intended to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation in respect of the Common Units. Therefore, no consideration will be payable by the plan participants upon receipt of the Common Units, and the Partnership will receive no remuneration for such Units.
Unit Option Plan. The Unit Option Plan currently permits the grant of options ("Unit Options") covering Common Units. No grants have been made under the Unit Option Plan. The Compensation Committee may, in the future, determine to make grants under such plan to employees and directors containing such terms as the Committee shall determine.
Unit Options will 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, the General Partner will acquire Common Units in the open market at a price equal to the then-prevailing price on the principal national securities exchange upon which the Common Units are then traded, or directly from the Partnership or any other person, or use Common Units already owned by the General Partner, or any combination of the foregoing. The General Partner will be entitled to reimbursement by the Partnership for the difference between the cost incurred by the General Partner in acquiring such Common Units and the proceeds received by the General Partner from an optionee at the time of exercise. Thus, the cost of the Unit Options will be borne by the Partnership. If the Partnership issues new Common Units upon exercise of the Unit Options, the total number of Common Units outstanding will increase, and the General Partner will remit to the Partnership the proceeds it received from the optionee upon exercise of the Unit Option to the Partnership.
The Unit Option Plan has been designed to furnish additional compensation to employees and directors and to align their economic interests with those of Common Unitholders.
The 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 theretofore been made. The General Partner's Board of Directors also has the right to alter or amend the Long-Term Incentive Plan or any part thereof 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, the General Partner, at no cost to the Partnership, agreed to transfer approximately 325,000 of its affiliates' Common Units to certain key employees of the General Partner. Generally, approximately 72,000 of such Common Units will 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, such Common Units will vest at the time the Common Unit Arrearages for such year have been paid. In addition, approximately 36,000 of such Common Units will 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. Any Common Units remaining unvested shall vest upon, and in the same proportion as, the conversion of Subordinated Units to Common Units. Notwithstanding the foregoing, all Common Units become vested if Plains All American Inc. is removed as General Partner of the Partnership prior to January 1, 2002. The compensation expense incurred in connection with these grants will be funded by the General Partner, without reimbursement by the Partnership. Of the 325,000 Common Units, 75,000 were allocated to Mr. Pefanis and 50,000 were allocated to Mr. Coiner.
Management Incentive Plan
The General Partner has adopted the Plains All American Inc. Management Incentive Plan (the "Management Incentive Plan"). The Management Incentive Plan is designed to enhance the financial performance of the 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 the General Partner may amend or change the Management Incentive Plan at any time. The General Partner is entitled to reimbursement by the Partnership for payments and costs incurred under the plan.
Compensation of Directors
Each director of the General Partner who is not an employee of the General Partner (a "Non-employee Director") 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 the General Partner, are otherwise compensated for their services to the General Partner and therefore receive no separate compensation for their services as directors of the General Partner.
Item 12.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth certain information as of March 22, 1999, regarding the beneficial ownership of Units held by (i) each person known by the General Partner to be the beneficial owner of 5% or more of the Units, (ii) each director and executive officer of the General Partner and (iii) by all directors and executive officers of the General Partner as a group.
- --------------------- * Less than one percent (1) The record holder of such Common Units and Subordinated Units is PAAI LLC, a wholly owned subsidiary of Plains All American Inc., the General Partner of the Partnership. Plains All American Inc. is a wholly owned subsidiary of Plains Resources Inc. The address for each is 500 Dallas, Suite 700, Houston, Texas 77002. (2) Includes 325,000 Common Units to be transferred, subject to certain vesting conditions, to certain key employees of the General Partner pursuant to certain Transaction Grant Agreements.
Item 13.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Rights of the General Partner
The General Partner and its affiliates own 6,974,239 Common Units and 10,029,619 Subordinated Units, representing an aggregate 55.4% limited partner interest in the Partnership. In addition, the General Partner owns an aggregate 2% general partner interest in the Partnership and the Partnership on a combined basis. Through the General Partner's ability, as general partner, to manage and operate the Partnership and the ownership of 6,974,239 Common Units and all of the outstanding Subordinated Units by the General Partner and its affiliates (effectively giving the General Partner the ability to veto certain actions of the Partnership), the General Partner has the ability to control the management of the Partnership.
Agreements Governing the Transactions
In connection with the Transactions, the Partnership, the General Partner and certain other parties entered into the various documents and agreements to effect the Transactions, including the vesting of assets in, and the assumption of liabilities by, the Partnership, and the application of the proceeds of the IPO. See Item 1. "Business - Initial Public Offering and Concurrent Transactions".
Relationship with Plains Resources
General
The Partnership has extensive ongoing relationships with Plains Resources. These relationships include (i) Plains Resources' wholly owned subsidiary, Plains All American Inc., serving as General Partner of the Partnership, (ii) an Omnibus Agreement, providing for the resolution of certain conflicts arising from the conduct of the Partnership and Plains Resources of related businesses and for the General Partner's indemnification of the Partnership for certain matters and (iii) the Crude Oil Marketing Agreement with Plains Resources, providing for the marketing of Plains Resources' crude oil production.
Transactions with Affiliates
On the Closing Date, the Partnership and Plains Resources Inc. entered into the Crude Oil Marketing Agreement which provides for the marketing by the Partnership of Plains Resources' crude oil production for a fee of $0.20 per barrel. The Partnership paid Plains Resources approximately $4.1 for the purchase of crude oil under such agreement for the period from November 23, 1998 to December 31, 1998, and recognized approximately $120,000 of profit for such period.
Prior to the Crude Oil Marketing Agreement, the Plains Midstream Subsidiaries marketed crude oil production of Plains Resources, its subsidiaries and its royalty owners. The Plains Midstream Subsidiaries paid approximately $83.4 million, $101.2 million and $100.5 million for the purchase of these products for the period from January 1, 1998 to November 22, 1998 and the years ended December 31, 1997 and 1996, respectively. In management's opinion, such purchases were made at prevailing market rates. The Plains Midstream Subsidiaries did not recognize a profit on the sale of the crude oil purchased from Plains Resources.
The Partnership does not directly employ any persons to manage or operate its business. These functions are provided by employees of the General Partner and Plains Resources. The General partner does not receive a management fee or other compensation in connection with its management of the Partnership. The Partnership reimburses the 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 the Partnership, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to the Partnership. The Partnership Agreement provides that the General Partner will determine the expenses that are allocable to the Partnership in any reasonable manner determined by the General Partner in its sole discretion. Total costs reimbursed to the General Partner and Plains Resources by the Partnership were approximately $0.5 million for the period from November 23, 1998 to December 31, 1998. Such costs include, (I) allocated personnel costs (such as salaries and employee benefits) of the personnel providing such services, (ii) rent on office space allocated to the General partner in Plains Resources' offices in Houston, Texas and (iii) 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, 1997 and 1996. 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.
Indemnity from the General Partner
In connection with the acquisition of the All American Pipeline and the SJV Gathering System, Wingfoot agreed to indemnify the General Partner for certain environmental and other liabilities. The indemnity is subject to limits of (i) $10 million with respect to matters of corporate authorization and title to shares, (ii) $21.5 million with respect to condition of rights of way, lease rights and undisclosed liabilities and litigation and (iii) $30 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 limit, is in excess of $1 million. The indemnities will remain in effect for a two year period after the date of the acquisition, with the exception of the environmental indemnity, which will remain in effect for a period of three years after the date of the Acquisition. 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. The Partnership has also agreed to be solely responsible for the cumulative aggregate amount of losses resulting from an oil leak from the All American Pipeline that occurred in 1997 to the extent such losses do not exceed $350,000. Any costs in excess of $350,000 will be applied to the $1 million deductible for the Wingfoot environmental indemnity. The General Partner has agreed to indemnify the Partnership for environmental and other liabilities to the extent it is indemnified by Wingfoot.
Plains Resources has agreed to indemnify the Partnership for environmental liabilities related to the assets of the Plains Midstream Subsidiaries transferred to the Partnership 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 million.
PART IV
Item 14.
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(1) Financial Statements
The financial statements filed as part of this report are listed in the "Index to Consolidated Financial Statements" on Page hereof.
- --------------------- + Filed herewith * Management contract or compensatory plan or arrangement
(b) Reports on Form 8-K
None
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., Its General Partner
Date: March 31, 1999 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 31, 1999 By: /s/ Greg L. Armstrong ------------------------------------------ Greg L. Armstrong, Chairman of the Board, Chief Executive Officer and Director of the General Partner (Principal Executive Officer)
Date: March 31, 1999 By: /s/ Harry N. Pefanis ------------------------------------------ Harry N. Pefanis, President, Chief Operating Officer and Director of the General Partner
Date: March 31, 1999 By: /s/ Phillip D. Kramer ------------------------------------------ Phillip D. Kramer, Executive Vice President and Chief Financial Officer (Principal Financial Officer) of the General Partner
Date: March 31, 1999 By: /s/ Cynthia A. Feeback ------------------------------------------ Cynthia A. Feeback, Treasurer (Principal Accounting Officer) of the General Partner
Date: March 31, 1999 By: /s/ Robert V. Sinnott ------------------------------------------ Robert V. Sinnott, Director of the General Partner
Date: March 31, 1999 By: /s/ Arthur L. Smith ------------------------------------------ Arthur L. Smith, Director of the General Partner
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 sheet and the related consolidated statements of income, of changes in partners' equity and of cash flows present fairly, in all material respects, the consolidated financial position of Plains All American Pipeline, L.P. and subsidiaries (the "Partnership") at December 31, 1998 and the consolidated results of their operations and their cash flows for the period from inception (November 23, 1998) to December 31, 1998 in conformity with generally accepted accounting principles. 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 audit. We conducted our audit of these statements in accordance with generally accepted auditing standards 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 audit provides a reasonable basis for the opinion expressed above.
In our opinion, the accompanying combined balance sheet and related combined statements of income and of cash flows of the Plains Midstream Subsidiaries, the predecessor entity of the Partnership, present fairly, in all material respects, the combined financial position of the Plains Midstream Subsidiaries at December 31, 1997 and the combined results of their operations and their cash flows for the period from January 1, 1998 to November 22, 1998 and the years ended December 31, 1997 and 1996 in conformity with generally accepted accounting principles. 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 generally accepted auditing standards 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, 1999
PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (in thousands, except share data)
See notes to consolidated and combined financial statements.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED AND COMBINED STATEMENTS OF INCOME (in thousands, except unit and per unit data)
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' EQUITY FOR THE PERIOD FROM INCEPTION (NOVEMBER 23, 1998) TO DECEMBER 31, 1998 (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 Significant Accounting Policies
Organization
Plains All American Pipeline, L.P. (the "Partnership") is a Delaware limited partnership that was formed in the third quarter of 1998, to acquire and operate the midstream crude oil business and assets of Plains Resources Inc. ("Plains Resources") and its wholly owned subsidiaries (the "Plains Midstream Subsidiaries" or the "Predecessor"). The operations of the Partnership are conducted through Plains Marketing, L.P. and All American Pipeline, L.P. (collectively referred to as the "Operating Partnerships"). Plains All American Inc., one of the Plains Midstream Subsidiaries, is the general partner ("General Partner") of the Partnership and the Partnership. The Partnership is engaged in interstate and intrastate crude oil pipeline transportation and crude oil terminalling and storage activities and gathering and marketing activities. The Partnership's operations are concentrated in California, Texas, Oklahoma, Louisiana and the Gulf of Mexico.
The Partnership owns and operates a 1,233-mile seasonally heated, 30-inch, common carrier crude oil pipeline extending from California to West Texas (the "All American Pipeline") and a 45-mile, 16-inch, crude oil gathering system in the San Joaquin Valley of California (the "SJV Gathering System"), both of which the General Partner purchased from Wingfoot Ventures Seven, Inc. ("Wingfoot"), a wholly owned subsidiary of The Goodyear Tire & Rubber Company ("Goodyear") in July 1998 for approximately $400 million (the "Acquisition") (See Note 2). The Partnership also owns and operates a two million barrel, above-ground crude oil terminalling and storage facility in Cushing, Oklahoma, (the "Cushing Terminal").
Initial Public Offering and Concurrent Transactions
On November 23, 1998, the Partnership completed an initial public offering (the "IPO") of 13,085,000 common units representing limited partner interests (the "Common Units") and received therefrom net proceeds of approximately $244.7 million. Concurrently with the closing of the IPO, certain transactions described in the following paragraphs were consummated in connection with the formation of the Partnership. Such transactions and the transactions which occurred in conjunction with the IPO are referred to herein as the "Transactions."
Certain of the Plains Midstream Subsidiaries were merged into Plains Resources, which sold the assets of these subsidiaries to the Partnership in exchange for $64.1 million and the assumption of $11.0 million of related indebtedness. At the same time, the General Partner conveyed all of its interest in the All American Pipeline and the SJV Gathering System, which it acquired in July 1998 for approximately $400 million, to the Partnership in exchange for (i) 6,974,239 Common Units, 10,029,619 Subordinated Units and an aggregate 2% general partner interest in the Partnership, (ii) the right to receive Incentive Distributions as defined in the Partnership agreement; and (iii) the assumption by the Partnership of $175 million of indebtedness incurred by the General Partner in connection with the acquisition of the All American Pipeline and the SJV Gathering System.
In addition to the $64.1 million paid to Plains Resources, the Partnership distributed approximately $177.6 million to the General Partner and used approximately $3 million of the remaining proceeds to pay expenses incurred in connection with the Transactions. The General Partner used $121.0 million of the cash distributed to it to retire the remaining indebtedness incurred in connection with the acquisition of the All American Pipeline and the SJV Gathering System and to pay other costs associated with the Transactions. The balance, $56.6 million, was distributed to Plains Resources, which used the cash to repay indebtedness and for other general corporate purposes.
In addition, concurrently with the closing of the IPO, the Partnership entered into a $225 million bank credit agreement (the "Bank Credit Agreement") that includes a $175 million term loan facility (the "Term Loan Facility") and a $50 million revolving credit facility (the "Revolving Credit Facility"). The Partnership may borrow up to $50 million under the Revolving Credit Facility for acquisitions, capital improvements, working capital and general business purposes. At closing, the Partnership had $175 million outstanding under the Term Loan Facility, representing indebtedness assumed from the General Partner.
Basis of Consolidation and Presentation
The accompanying financial statements and related notes present the consolidated financial position as of December 31, 1998, of the Partnership and the results of its operations, cash flows and changes in partners' equity for the period from
November 23, 1998 to December 31, 1998. The combined financial statements of the Predecessor include the accounts of the Plains Midstream Subsidiaries. All significant intercompany transactions have been eliminated.
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 the Partnership, which typically occurs upon receipt of the product by the Partnership. Terminalling and storage revenues are recognized at the time service is performed. As a regulated interstate pipeline, revenues for the transportation of crude oil on the All American Pipeline are recognized based upon Federal Energy Regulatory Commission and the Public Utilities Commission of the State of California filed tariff rates and the related transported volumes. Tariff revenue is recognized at the time such volume is delivered.
Cost of Sales and Operations
Cost of sales consists of the cost of crude oil and field and pipeline operating 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.
Cash and Cash Equivalents
Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments. The Predecessor's cash management program resulted in book overdraft balances which have been reclassified to current liabilities.
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.
Property and Equipment and Pipeline Linefill
Property and equipment is stated at cost and consists primarily of (i) crude oil pipelines and pipeline facilities (primarily the All American Pipeline and SJV Gathering System), (ii) crude oil terminal and storage facilities (primarily the Cushing Terminal), and (iii) trucking equipment, injection stations and other. Other property and equipment consists primarily of office furniture and fixtures and computer equipment and software. Depreciation is computed using the straight-line method over estimated useful lives as follows: (i) crude oil pipelines - 40 years, (ii) crude oil pipeline facilities - 25 years, (iii) crude oil terminal and storage facilities - 30 to 40 years, (iv) trucking equipment, injection stations and other - 5 to 10 years and (v) 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 is 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 if forces a barrel out at another location. The Partnership owns approximately 5.0 million barrels of crude oil that is used to maintain the All American Pipeline's 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.
The following is a summary of the components of property and equipment:
Impairment of Long-Lived Assets
Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written-down to estimated fair value in accordance with Statement of Financial Accounting Standards No. 121. Fair value is generally determined from estimated discounted future net cash flows.
Other Assets
Other assets consist of the following:
December 31, ----------------------- 1998 1997 -------- ------- (in thousands) Debt issue costs $ 10,171 $ 232 Goodwill and other 1,134 2,096 ------- ------ $ 11,305 $ 2,328 Accumulated amortization $ (495) $ (522) ------- ------ $ 10,810 $ 1,806 ======= ======
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. The increase in debt issue costs is due to the IPO and the acquisition of the All American Pipeline and the SJV Gathering System. 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 the 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 the operations of the Partnership is included in the accompanying consolidated financial statements because, as a partnership, it is not subject to Federal or state income tax and the tax effect of it's 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 basis and his/her share of the net assets reported in the consolidated financial statements. The Partnership does not have access to information about each individual Unitholder's tax attributes in the Partnership, and the aggregate tax bases cannot be readily determined. Accordingly, management does not believe that, in the Partnership's circumstances, the aggregate difference would be meaningful information.
The Predecessor is included in the combined federal income tax return of Plains Resources. Income taxes are calculated as if the Predecessor had filed a return on a separate company basis utilizing a federal statutory rate of 35%. Payables in lieu of deferred taxes represent deferred tax liabilities which are recognized based on the temporary differences between the tax basis of the Predecessor's assets and liabilities and the amounts reported in the financial statements. These amounts were owed to Plains Resources. Current amounts payable were also owed to Plains Resources and are included in due to affiliates in the accompanying combined balance sheet of the Predecessor.
Hedging
The Partnership and Predecessor utilize various derivative instruments, for purposes other than trading, to hedge their 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 ("NYMEX") and crude oil swap contracts entered into with financial institutions. The Partnership also utilizes interest rate swaps to manage the interest rate exposure on its 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, the Partnership 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 the Partnership's and Predecessor's Statements of Income until the underlying hedged transaction occurs. The financial impacts of crude oil hedge contracts are included in the Partnership's and Predecessor's statements of income 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 accounts payable and accrued liabilities in the accompanying 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 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.
Net income per unit
Basic and diluted net income per unit is determined by dividing net income, after deducting the General Partner's 2% interest, by the weighted average number of outstanding Common Units and Subordinated Units (a total of 30,088,858 units as of December 31, 1998). For periods prior to November 23, 1998, such units are equal to the Common and Subordinated Units received by the General Partner in exchange for assets contributed to the Partnership.
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 is effective for fiscal years beginning after June 15, 1999. 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 it is, the type of hedge transaction. For fair value hedge transactions in which the Partnership is 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 the Partnership is 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. The Partnership is required to adopt this statement beginning in 2000. The Partnership has not yet determined the affect that the adoption of SFAS 133 will have on its financial position or results of operations
In November 1998, the Emerging Issues Task Force ("EITF") released Issue No. 98-10, "Accounting for Energy Trading and Risk Management Activities". EITF 98-10 deals with entities that enter into derivatives and other third-party contracts for the purchase and sale of a commodity in which they normally do business (for example, crude oil and natural gas). The EITF reached a consensus that energy trading contracts should be measured at fair value determined as of the balance sheet date with the gains and losses included in earnings and separately disclosed in the financial statements or footnotes thereto. The EITF acknowledged that determining whether or when an entity is involved in energy trading activities is a matter of judgment that depends on the relevant facts and circumstances. As such, certain factors or indicators have been identified by the EITF which should be considered in evaluating whether an operation's energy contracts are entered into for trading purposes. EITF 98-10 is
required to be applied to financial statements issued by the Partnership beginning in 1999. The adoption of this consensus is not expected to have a material impact on the Partnership's results of operations or financial position.
Note 2--Acquisition
On July 30, 1998, the 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 Goodyear, for approximately $400 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 following unaudited pro forma information is presented to show the pro forma revenues and net income had the acquisition been consummated on January 1, 1997.
January 1, Year 1998 to Ended November 22, December 31, 1998 1997 ----------- ----------- (in thousands)
Revenues $ 1,390,893 $ 1,744,840 =========== =========== Net income (loss) $ 14,448 $ (17,039) =========== =========== Basic and diluted net income (loss) per limited partner unit $ 0.83 $ (0.98) =========== ===========
The pro forma net loss for the year ended December 31, 1997, includes a non- cash impairment charge of $64.2 million related to the writedown of pipeline assets and linefill by Wingfoot in connection with the sale of the Celeron Companies by Goodyear to the Predecessor. Based on the Predecessor's purchase price allocation to property and equipment and pipeline linefill, an impairment charge would not have been required had the Predecessor actually acquired the Celeron Companies effective January 1, 1997. Excluding this impairment charge, the Predecessor's pro forma net income for 1997 would have been $23.4 million ($1.35 per basic and diluted limited partner unit).
The acquisition was accounted for utilizing the purchase method of accounting and the purchase price was allocated in accordance with Accounting Principles Board Opinion No. 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 -------- $ 400,164 ========
Financing for the acquisition was provided through (i) a $325 million, limited recourse bank facility and (ii) an approximate $114 million capital contribution by Plains Resources. Actual borrowings at closing were $300 million.
Note 3 - Credit Facilities
Bank Credit Agreement. The Partnership has a $225 million Bank Credit Agreement which consists of the $175 million Term Loan Facility and the $50 million Revolving Credit Facility. The $50 million Revolving Credit Facility is used for capital improvements and working capital and general business purposes and contains a $10 million sublimit for letters of credit issued for general corporate purposes. The Bank Credit Agreement is collateralized by a lien on substantially all of the assets of the Partnership.
The Term Loan Facility bears interest at the Partnership's option at either (i) the Base Rate, as defined, or (ii) reserve-adjusted LIBOR plus an applicable margin. The Partnership has two ten year interest rate swaps (subject to cancellation by the counterparty after seven years) aggregating $175 million notional principal amount which fix the LIBOR portion of the interest rate (not including the applicable margin) at a weighted average rate of approximately 5.24%. Borrowings under the Revolving Credit Facility bear interest at the Partnership's option at either (i) the Base Rate, as defined, or (ii) reserve- adjusted LIBOR plus an applicable margin. The Partnership incurs a commitment fee on the unused portion of the Revolving Credit Facility and, with respect to each issued letter of credit, an issuance fee.
At December 31, 1998, the Partnership had $175 million outstanding under the Term Loan Facility, which amount represents indebtedness assumed from the General Partner. The Term Loan Facility matures in seven years, 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 two years. All borrowings for working capital purposes outstanding under the Revolving Credit Facility must be reduced to no more than $8 million for at least 15 consecutive days during each fiscal year. At December 31, 1998, there are no amounts outstanding under the Revolving Credit Facility.
Letter of Credit Facility. In connection with the IPO, the Partnership entered into a $175 million letter of credit and borrowing facility with BankBoston, N.A. ("BankBoston"), ING (U.S.) Capital Corporation ("ING Baring") and certain other lenders (the "Letter of Credit Facility"), which replaced the Predecessor's similar facility. The purpose of the Letter of Credit Facility is to provide (i) standby letters of credit to support the purchase and exchange of crude oil for resale and (ii) borrowings to finance crude oil inventory which has been hedged against future price risk or has been designated as working inventory. The Letter of Credit Facility is collateralized by a lien on substantially all of the assets of the Partnership. 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 current assets and current liabilities of the Partnership, primarily crude oil inventory and accounts receivable and accounts payable related to the purchase and sale of crude oil. At December 31, 1998, the borrowing base under the Letter of Credit Facility was approximately $175 million.
The Letter of Credit Facility has a $40 million sublimit for borrowings to finance crude oil purchased in connection with operations at the Partnership's crude oil terminal and storage facilities. All purchases of crude oil inventory financed are required to be hedged against future price risk on terms acceptable to the lenders. At December 31, 1998, approximately $9.8 million was outstanding under the sublimit. The interest rate in effect at December 31, 1998 was 6.8%. At December 31, 1997, approximately $18 million in borrowings was outstanding under a similar sublimit under the Predecessor's credit facility.
Letters of credit under the Letter of Credit Facility are generally issued for up to 70 day periods. Borrowings bear interest at the Partnership's option at either (i) the Base Rate (as defined) or (ii) reserve-adjusted LIBOR plus the applicable margin. The Partnership incurs a commitment fee on the unused portion of the borrowing sublimit under the Letter of Credit Facility and an issuance fee for each letter of credit issued. The Letter of Credit Facility expires July 31, 2001.
At December 31, 1998 and 1997, there were outstanding letters of credit of approximately $62 million and $38 million, respectively, issued under the Letter of Credit Facility and the Predecessor's letter of credit facility, respectively. To date, no amounts have been drawn on such letters of credit issued by the Partnership or the Predecessor.
Both the Letter of Credit Facility and the Bank Credit Agreement contain a prohibition on distributions on, or purchases or redemptions of, Units if any Default or Event of Default (as defined) is continuing. In addition, both facilities contain various covenants limiting the ability of the Partnership to (i) incur indebtedness, (ii) grant certain liens, (iii) sell assets in excess of certain limitations, (iv) engage in transactions with affiliates, (v) make investments, (vi) enter into hedging contracts and (vii) enter into a merger, consolidation or sale of its assets. In addition, the terms of the Letter of Credit Facility and the Bank Credit Agreement require the Partnership to maintain (i) a Current Ratio (as defined) of at least 1.0 to 1.0; (ii) a Debt Coverage Ratio (as defined) which is not greater than 5.0 to 1.0; (iii) an Interest Coverage Ratio (as defined) which is not less than 3.0 to 1.0; (iv) a Fixed Charge Coverage Ratio (as defined) which is not less than 1.25 to 1.0; and (v) a Debt to Capital Ratio (as defined) of not greater than .60 to 1.0. In both the Letter of Credit Facility and the Bank Credit Agreement, a Change in Control (as defined) of Plains Resources constitutes an Event of Default.
Note 4 - Partnership Capital and Distributions
Partner's capital consists of 20,059,239 Common Units representing a 65.3% limited partner interest, (a subsidiary of the General Partner owns 6,974,239 of such Common Units), 10,029,619 Subordinated Units owned by a subsidiary of the General Partner representing a 32.7% limited partner interest and a 2% general partner interest. In the aggregate, the General Partner's interests represent an effective 57.4% ownership of the Partnership's equity.
The Partnership will distribute 100% of its Available Cash within 45 days after the end of each quarter to Unitholders of record and to the General Partner. Available Cash is generally defined as all cash and cash equivalents of the Partnership on hand at the end of each quarter less reserves established by the 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), the 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 the Partnership's 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.
On February 12, 1999, the Partnership paid a cash distribution of $0.193 per unit on its outstanding Common Units and Subordinated Units. The $5.8 million distribution was paid to Unitholders of record at the close of business on January 29, 1999. A distribution of approximately $118,000 was paid to the General Partner. The distribution represented the MQD prorated for the 39-day period from November 23, 1998, the closing of the IPO, through December 31, 1998.
Note 5 -- Major Customers and Concentration of Credit Risk
During the period from January 1, 1998 to November 22, 1998, Sempra Energy Trading Corporation ("Sempra") and Koch Oil Company ("Koch") accounted for 31% and 19%, respectively of the Plains Midstream Subsidiaries' total sales. During the period from November 23, 1998 to December 31, 1998, Sempra and Exxon Company USA accounted for 20% and 11%, respectively of the Partnership's sales. For 1997 and 1996, customers accounting for more than 10% of total sales are as follows: 1997 - Koch - 30%, Sempra - 12% and Basis Petroleum Inc. ("Basis"), formerly Phibro Energy U.S.A., Inc. - 11%; 1996 - Koch - 16% and Basis - 11%. No other customer accounted for as much as 10% of total sales during 1998, 1997 and 1996.
Financial instruments which potentially subject the Partnership to concentrations of credit risk consist principally of trade receivables. The Partnership's accounts receivable are primarily from purchasers and shippers of crude oil. This industry concentration has the potential to impact the Partnership's 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. The Partnership generally requires letters of credit for receivables from customers which are not considered investment grade, unless the credit risk can otherwise be reduced.
Note 6--Related Party Transactions
The Partnership does not directly employ any persons to manage or operate its business. These functions are provided by employees of the General Partner and Plains Resources. The General Partner does not receive a management fee or other compensation in connection with its management of the Partnership. The Partnership reimburses the 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 the Partnership, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to the Partnership. The Partnership Agreement provides that the General Partner will determine the expenses that are allocable to the Partnership in any reasonable manner determined by the General Partner in its sole discretion. Total costs reimbursed to the General Partner and Plains Resources by the Partnership were approximately $0.5 million for the period from November 23, 1998 to December 31, 1998. Such costs include, (i) allocated personnel costs (such as salaries and employee benefits) of the personnel providing such services, (ii) rent on office space allocated to the General Partner in Plains Resources' offices in Houston, Texas and (iii) out-of-pocket expenses related to the provision of such services.
In connection with the IPO, the Partnership and Plains Resources entered into the Crude Oil Marketing Agreement which provides for the marketing by Plains Marketing, L.P. of Plains Resources crude oil production for a fee of $0.20 per barrel. The Partnership paid Plains Resources approximately $4.1 million for the purchase of crude oil under such agreement for the period from November 23, 1998 to December 31, 1998, and recognized approximately $120,000 of profit for such period.
The Predecessor marketed certain crude oil production of Plains Resources, its subsidiaries and its royalty owners. The Predecessor paid approximately $83.4 million, $101.2 million and $100.5 million for the purchase of these products for the period from January 1, 1998 to November 22, 1998, and for the years ended December 31, 1997 and 1996, respectively. In management's opinion, such purchases were made at prevailing market rates. The Predecessor did not recognize a profit on the sale of the barrels purchased from Plains Resources.
Prior to the IPO, the Plains Midstream Subsidiaries were guarantors of Plains Resources' $225 million revolving credit facility and $200 million 10 1/4% Senior Subordinated Notes due 2006. The agreements under which such debt was issued contain
covenants which, among other things, restricted the Plains Midstream Subsidiaries' ability to make certain loans and investments and restricted additional borrowings by the Plains Midstream Subsidiaries.
Plains Resources allocated certain direct and indirect general and administrative expenses to the Predecessor during the period from January 1, 1998 to November 22, 1998, and for the years ended December 31, 1997 and 1996. Indirect costs were allocated based on the number of employees. The types of indirect expenses allocated to the Predecessor during these periods 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. Management believes that the method used to allocate expenses is reasonable.
Prior to the IPO, the Plains Midstream Subsidiaries funded the acquisition of certain asset and inventory purchases through borrowings from Plains Resources. In addition, the Plains Midstream Subsidiaries participated in a cash management arrangement with Plains Resources covering the funding of daily cash requirements and the investing of excess cash. Amounts due to Plains Resources under the arrangements bore interest at a rate of 10 1/4%. The balance due to Plains Resources as of December 31, 1997, was approximately $26.7 million, including $0.3 million of cumulative federal and state income taxes payable Amounts due to other subsidiaries of Plains Resources as of December 31, 1997 aggregated approximately $10.8 million.
Note 7 -- Financial Instruments
Derivatives
The Partnership utilizes derivative financial instruments, as defined in SFAS No. 119, "Disclosure About Derivative Financial Instruments and Fair Value of Financial Instruments," to hedge its exposure to price volatility on crude oil and does not use such instruments for speculative trading purposes. These arrangements expose the Partnership to credit risk (as to counterparties) and to risk of adverse price movements in certain cases where the Partnership's purchases are less than expected. In the event of non-performance of a counterparty, the Partnership 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 the non-performance of a counterparty, the Partnership enters into such contracts with counterparties that are considered investment grade, periodically reviews the financial condition of such counterparties and continually monitors the effectiveness of derivative financial instruments in achieving the Partnership's objectives. In view of the Partnership's criteria for selecting counterparties, its process for monitoring the financial strength of these counterparties and its experience to date in successfully completing these transactions, the Partnership believes that the risk of incurring significant financial statement loss due to the non- performance of counterparties to these transactions is minimal.
At December 31, 1998, the Partnership's hedging activities included crude oil futures contracts maturing in 1999, covering approximately 3.3 million barrels of crude oil. 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 the Partnerships hedged inventory or anticipated purchases of crude oil. Net deferred losses from the Partnership's hedging activities were approximately $1.8 million at December 31, 1998.
Fair Value of Financial Instruments
In accordance with the requirements of SFAS No. 107, "Disclosures About 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, as defined. 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 agreements are based on current termination values or quoted market prices of comparable contracts.
The Partnership has two 10-year interest rate swaps (subject to cancellation by the counterparty after seven years) aggregating a notional principal amount of $175 million which fix the LIBOR portion of the interest rate (not including the applicable margin) on the Term Loan Facility at a weighted average rate of approximately 5.24%. The carrying amounts and fair values of the Partnership's financial instruments are as follows:
December 31, -------------------------- -------------------------- Carrying Fair Amount Value ------------ ------------ (in thousands)
Unrealized loss or interest rate swaps $ - $ (2,164)
Note 8 -- Commitments and Contingencies
The Partnership leases office space under leases accounted for as operating leases. Rental expense amounted to $0.7 million and $0.1 million for the period from January 1, 1998 to November 22, 1998, and the period from November 23, 1998 to December 31, 1998, respectively. Minimum rental payments under operating leases are $3.0 million for 1999; $1.4 million annually for 2000 through 2002; $1.3 million for 2003 and thereafter $2.9 million.
The Partnership incurred costs associated with leased land, rights-of-way, permits and regulatory fees of $0.2 million and $0.1 million for the period from January 1, 1998 to November 22, 1998, and the period from November 23, 1998 to December 31, 1998, respectively. At December 31, 1998, minimum future payments, net of sublease income, associated with these contracts are approximately $0.3 million for the following year. Generally these contracts extend beyond one year but can be canceled at any time should they not be required for operations.
In order to receive electrical power service at certain remote locations, the Partnership has entered into facilities contracts with several utility companies. These facilities charges are calculated periodically based upon, among other factors, actual electricity energy used. Minimum future payments for these contracts at December 31, 1998, are approximately $0.8 million annually for each of the next five years.
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. The Partnership has submitted a closure plan to the Regional Water Quality Board ("RWQB"). At the request of the RWQB, groundwater monitoring wells have been installed from which water samples will be analyzed semi-annually. No hydrocarbon contamination was detected in initial analyses taken in January 1999. The RWQB approval of the Partnership's closure plan is not expected until subsequent semi-annual analyses have been performed. If the Partnership's closure plan is disapproved, a government mandated remediation of the spill could require significant expenditures, currently estimated to be approximately $350,000, provided however, no assurance can be given that the actual cost thereof will not exceed such estimate. The Partnership does not believe the ultimate resolution of this issue will have a material adverse affect on the Partnership's consolidated financial position, results of operations or cash flows.
Prior to being acquired by the Predecessor in 1996, the Partnership's terminal at Ingleside Texas (the "Ingleside Terminal") experienced releases of refined petroleum products into the soil and groundwater underlying the site due to activities on the property. The Partnership has proposed a voluntary state- administered remediation of the contamination on the property to determine whether the contamination extends outside the property boundaries. If the Partnership's plan is disapproved, a government mandated remediation of the spill could require more significant expenditures, currently estimated to approximate $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 the Partnership from Plains Resources. The Partnership does not believe the ultimate resolution of this issue will have a material adverse affect on the Partnership's consolidated financial position, results of operations or cash flows.
The Partnership may experience future releases of crude oil into the environment from its pipeline and storage operations, or discover releases that were previously unidentified. While the Partnership maintains 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 the All American Pipeline, the SJV Gathering System, the Cushing Terminal, the Ingleside Terminal or other Partnership assets may substantially affect the Partnership's business.
In March 1999, the Partnership signed a definitive agreement to acquire Scurlock Permian LLC and certain other pipeline assets (see Note 14).
The Partnership, in the ordinary course of business, is a defendant in various legal proceedings in which its exposure, individually and in the aggregate, is not considered material to the accompanying financial statements. At December 31, 1998, the Partnership had approximately $0.9 million accrued for its various environmental and litigation contingencies.
Note 9 -- Supplemental Disclosures of Cash Flow Information
In connection with the formation of the Partnership, certain investing and financial activities occurred. Effective November 23, 1998, substantially all of the assets and liabilities of the Predecessor were conveyed at historical cost to the Partnership. Net assets assumed by the Operating Partnership are as follows (in thousands):
Cash and cash equivalent $ 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 102,705 Due to affiliates 8,942 Bank debt 183,600 -------- Total liabilities assumed 295,247 -------- Net assets assumed by the Partnership $273,466 ========
Interest paid totaled $0.1 million for the period from November 23, 1998 to December 31, 1998, and $8.5 million, $4.5 million, and $3.6 million for the period from January 1, 1998 to November 22, 1998 and the years ended December 31, 1997 and 1996, respectively.
Note 10 -- Long-Term Incentive Plans
The General Partner adopted the Plains All American Inc. 1998 Long-Term Incentive Plan (the "Long-Term Incentive Plan") for employees and directors of the General Partner and its affiliates who perform services for the Partnership. The Long-Term Incentive Plan consists of two components, a restricted unit plan (the "Restricted Unit Plan") and a unit option plan (the "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 the 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. Approximately 500,000 Restricted Units were granted upon consummation of the IPO to employees of the General Partner at a weighted average grant date fair value of $20.00 per Unit. The Compensation Committee may, in the future, determine to make additional grants under such 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 the General Partner will be eligible to vest prior to termination of the Subordination Period. There have been no grants to nonemployee directors as of December 31, 1998.
If a grantee terminates employment or membership on the Board of Directors 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 the General Partner in the open market, Common Units already owned by the General Partner, Common Units acquired by the General Partner directly from the Partnership or any other person, or any combination of the foregoing. The General Partner will be entitled to reimbursement by the Partnership for the cost incurred in acquiring such Common Units. If the Partnership issues 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 intended to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation in respect of the Common Units. Therefore, no consideration will be payable by the plan participants upon receipt of the Common Units, and the Partnership will receive no remuneration for such Units.
Unit Option Plan. The Unit Option Plan currently permits the grant of options ("Unit Options") covering Common Units. No grants were initially made under the Unit Option Plan. The Compensation Committee may, in the future, determine to make grants under such plan to employees and directors containing such terms as the Committee shall determine.
Unit Options will 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, the General Partner will acquire Common Units in the open market at a price equal to the then-prevailing price on the principal national securities exchange upon which the Common Units are then traded, or directly from the partnership or any other person, or use Common Units already owned by the General Partner, or any combination of the foregoing. The General Partner will be entitled to reimbursement by the partnership for the difference between the cost incurred by the General Partner in acquiring such Common Units and the proceeds received by the General Partner from an optionee at the time of exercise. Thus, the cost of the Unit Options will be borne by the Partnership. If the Partnership issues new Common Units upon exercise of the Unit Options, the total number of Common Units outstanding will increase, and the General Partner will remit to the Partnership the proceeds it received from the optionee upon exercise of the Unit Option to the Partnership.
The Unit Option Plan has been designed to furnish additional compensation to employees and directors and to align their economic interests with those of Common Unitholders.
Transaction Grant Agreements. In addition to the grants made under the Restricted Unit Plan described above, the General Partner agreed to transfer approximately 325,000 of its affiliates' Common Units at a weighted average grant fair value of $20.00 per Unit to certain key employees of the General Partner (the "Transaction Grants"). Generally, approximately 72,000 of such Common Units will 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 MQD 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, such Common Units will vest at the time the Common Unit Arrearages for such year has been paid. In addition, approximately 36,000 of such Common Units will 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 MQD on all outstanding Common Units and Subordinated Units and the related distribution on the general partner interest. Any Common Units remaining unvested shall vest upon, and in the same proportion as, the conversion of Subordinated Units.
The Partnership will recognize compensation expense in the future for the Unit Options and Restricted Units described above when vesting becomes probable. In addition, although, the Partnership is not required to reimburse the General Partner for the Transaction Grants, accounting pronouncements will require the Partnership to record compensation expense for such Units and a corresponding capital contribution from the General Partner when vesting becomes probable.
Note 11 -- Operating Segments
The Partnership's operations consist of two operating segments: (1) Pipeline Operations - engages in the interstate and intrastate crude oil pipeline transportation and related gathering and marketing activities; (2) Marketing, Gathering, Terminalling and Storage Operations - engages in crude oil terminalling, storage, gathering and marketing activities other than related to Pipeline Operations. Prior to the July 1998 acquisition of the All American Pipeline and SJV Gathering System, the Predecessor had only marketing, gathering, terminalling and storage operations.
The accounting policies of the segments are the same as those described in Note 1. The Partnership evaluates segment performance based on gross margin, gross profit and income before income taxes and extraordinary items.
The following summarizes segment revenues, gross margin, gross profit and income before income taxes and extraordinary items.
(a) Differences between total segment revenues and consolidated revenues relate to intersegment revenues. (b) Intersegment sales and transfers were conducted on an arm's-length basis. (c) Gross margin is calculated as revenues less cost of sales and operations. (d) Gross profit is calculated as revenues less cost of sales and operations and general and administrative expenses.
Note 12 -- Income Taxes
As discussed in Note 1, the Predecessor's results are included in Plains Resources' combined federal income tax return. The amounts presented below were calculated as if the Predecessor filed a separate tax return.
Provision in lieu of income taxes of the Predecessor consists of the following components:
January 1, Year Ended 1998 To December 31, November 22, ----------------------------- 1998 1997 1996 ------------ -------------- ------------ (in thousands)
Federal Current $ 455 $ 38 $ 1 Deferred 3,390 1,131 706 State Current - 99 19 Deferred 718 - - ------- ------- ------ Total $ 4,563 $ 1,268 $ 726 ======= ======= ======
Actual provision in lieu of income taxes differs from provision in lieu of income taxes computed by applying the U.S. federal statutory corporate tax rate of 35% to income before such provision as follows:
January 1, Year Ended 1998 To December 31, November 22, ----------------------------- 1998 1997 1996 ------------ -------------- ------------ (in thousands)
Provision at statutory rate $ 4,056 $ 1,169 $ 682 State income tax, net of benefit for federal deduction 467 65 12 Permanent differences 40 34 32 -------- -------- -------- Total $ 4,563 $ 1,268 $ 726 ======== ======== ========
The Plains Midstream Subsidiaries' payable in lieu of deferred taxes at December 31, 1997 results from differences in depreciation methods used for financial purposes and for tax purposes.
Note 13 -- Combined Equity
The following is a reconciliation of the combined equity balance of the Plains Midstream Subsidiaries (in thousands):
Balance at December 31, 1995 $ 2,613 Net income for the year 1,222 ------- Balance at December 31, 1996 3,835 Net income for the year 2,140 ------- Balance at December 31, 1997 5,975 Capital contribution in connection with the acquisition of the Celeron Companies 113,700 Dividend to Plains Resources (3,557) Net income for the period from January 1, 1998 to November 22, 1998 7,025 ------- $123,143 =======
Note 14 -- Subsequent Events
On March 17, 1999, the Partnership signed a definitive agreement with Marathon Ashland Petroleum LLC to acquire Scurlock Permian LLC and certain other pipeline assets. The cash purchase price for the acquisition is approximately $138 million, plus associated closing and financing costs. The purchase price is subject to adjustment at closing for working capital on April 1, 1999, the effective date of the acquisition. Closing of the transaction is subject to regulatory review and approval,
consents from third parties, and customary due diligence. Subject to satisfaction of the foregoing conditions, the transaction is expected to close in the second quarter of 1999. The Partnership has received a financing commitment from one of its existing lenders, which in addition to other financial resources currently available to the Partnership, will provide the funds necessary to complete the transaction.
Scurlock Permian LLC, a wholly owned subsidiary of Marathon Ashland Petroleum LLC, is engaged in crude oil transportation, trading and marketing, operating in 14 states with more than 2,400 miles of active pipelines, numerous storage terminals and a fleet of more than 225 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, Howard, Martin, Midland, Regan, Upton and Irion Counties, Texas. The assets to be acquired also include approximately one million barrels of crude oil used for working inventory. The definitive agreement provides that if either party fails to perform its obligations thereunder through no fault of the other party, such defaulting party shall pay the nondefaulting party $7.5 million as liquidated damages.
In March 1999, the Partnership adopted a plan to reduce staff in its pipeline operations and to relocate certain functions. The Partnership estimates that it will incur a charge to first quarter earnings of approximately $400,000 in connection with such plan.