8-K 1 d8k.txt CURRENT REPORT ON FORM 8-K ================================================================================ SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 ----------------------- FORM 8-K CURRENT REPORT Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 Date of Report (Date of earliest event reported) - October 29, 2002 Plains All American Pipeline, L.P. (Name of Registrant as specified in its charter) DELAWARE 0-9808 76-0582150 (State or other jurisdiction (Commission File Number) (I.R.S. Employer of incorporation or organization) Identification No.)
333 Clay Street, Suite 1600 Houston, Texas 77002 (713) 646-4100 (Address, including zip code, and telephone number, including area code, of Registrant's principal executive offices) N/A (Former name or former address, if changed since last report.) ================================================================================ Item 9. Regulation FD Disclosure In accordance with General Instruction B.2. of Form 8-K, the information presented under this Item 9 shall not be deemed "filed" for purposes of Section 18 of the Securities Act of 1934, as amended, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such a filing. Disclosure of Fourth Quarter 2002 Estimates; Update of Year 2002 Estimates The following table reflects actual results for the first nine months of 2002 and a current estimate of results for the fourth quarter and full year 2002. These estimates are based on assumptions and estimates that management believes are reasonable based on currently available information; however, management's assumptions and our future performance are both subject to a wide range of business risks and uncertainties, so we cannot assure you that these goals and estimates can or will be met. Please refer to the information under the caption "Forward-Looking Statements and Associated Risks" below. These risks and uncertainties could cause our actual results to differ materially from those in the following table. The estimates set forth below are given as of the date hereof, based only on information known to us as of October 28, 2002. Operating and Financial Guidance (in thousands except per unit data)
YTD Quarter Ended Year Ended September 30, 2002 December 31, 2002 December 31, 2002 ------------------ ------------------------ ------------------------ Actuals Low High Low High -------- -------- -------- -------- -------- Gross Margin: Pipeline $ 60,269 $ 24,400 $ 25,400 $ 84,669 $ 85,669 Gathering, Marketing, Terminalling, & Storage 66,222 24,400 25,300 90,622 91,522 -------- -------- -------- -------- -------- Total Gross Margin 126,491 48,800 50,700 175,291 177,191 G&A / Other Expenses 33,512 11,800 11,700 45,312 45,212 -------- -------- -------- -------- -------- EBITDA $ 92,979 $ 37,000 $ 39,000 $ 129,979 $ 131,979 Depreciation & Amortization 23,125 10,200 10,200 33,325 33,325 -------- -------- -------- -------- -------- EBIT 69,854 26,800 28,800 96,654 98,654 Interest Expense 20,175 9,000 8,700 29,175 28,875 -------- -------- -------- -------- -------- Adjusted Income $ 49,679 $ 17,800 $ 20,100 $ 67,479 $ 69,779 Adjusted Income to Limited Partners $ 46,559 $ 16,437 $ 18,691 $ 65,142 $ 67,396 Weighted Average Units Outstanding 44,188 49,578 49,578 45,546 45,546 Adjusted Income Per Unit $ 1.05 $ 0.33 $ 0.38 $ 1.43 $ 1.48
Notes and Assumptions: 1. EBITDA means Earnings Before Interest, Taxes, Depreciation, Amortization and other non-cash items. EBIT means EBITDA less Depreciation and Amortization. Adjusted income means net income before unusual or non-recurring items and the impact of Standards of Financial Accounting Statement (SFAS) 133, "Accounting for Derivative Instruments and Hedging Activities." The historical results presented in the table do not include the impact of any unusual or non-recurring items or SFAS 133. The effect of these excluded items would be to reduce adjusted income, EBITDA and EBIT by approximately $2.1 million, and would reduce adjusted income per unit by $0.04.The forecast presented above does not include any assumptions or projections with respect to any potential gains or losses related to SFAS 133 or EITF 98-10. The potential gains or losses related to SFAS 133 or EITF 98-10 could materially change reported net income. 2. Pipeline Gross Margin. Pipeline volume and tariff estimates are based on historical operating performance and our outlook for future performance. Actual results could vary materially depending on volumes that are shipped. Average pipeline volumes are estimated to be approximately 900,000 barrels per day for the fourth quarter of 2002, with Outer Continental Shelf (OCS) volumes estimated to make up approximately 7% of these volumes, or approximately 68,000 barrels per day. Revenues are forecast using these volume assumptions, current tariffs and estimates of operating expenses, each of which management believes are reasonable. A 5,000 barrel per day variance in OCS volumes (approximately 7%) would have an approximate $800,000 effect on EBITDA for the fourth quarter and an approximate $3.2 million effect on an annualized basis. An average 25,000 barrel per day variance in the Basin Pipeline System, equivalent to an approximate 10% volume reduction on that pipeline system, would have an approximate $850,000 effect on EBITDA for the fourth quarter and an approximate $3.4 million effect on an annualized basis. 3. Gathering, Marketing, Terminalling and Storage Gross Margin. Forecast volumes for Gathering & Marketing are approximately 485,000 barrels per day for the fourth quarter of 2002, consistent with our current volumes. Gross margin is forecast using these volume assumptions and estimates of unit margins and operating expenses, each of which management believes are reasonable. 4. General and Administrative Expense. G&A expense is forecast to be between $11.7 million and $11.8 million for the fourth quarter of 2002. Excluding acquisition related increases, the fourth quarter of 2002 includes approximately $600,000 of consultant and contractor related expenses attributable to accounting system enhancements and increased resources associated with an ongoing project to reprocess, validate and collect certain prior-year accounts receivable, which we expect to substantially complete over the next three months. 5. Interest Expense. Fourth quarter interest expense is forecast to be between $8.7 million and $9.0 million assuming an average debt balance in the fourth quarter of 2002 of approximately $525 million and an average interest rate of approximately 6.8%, including our current interest rate hedges and commitment fees. The forecast is based on estimated cash flow, current distribution rates, planned capital projects, planned sales of surplus equipment, and forecast levels of inventory and other working capital sources and uses, each of which management believes is reasonable. 6. Depreciation & Amortization. Depreciation and amortization is forecast based on our existing assets and forecast capital expenditures. Depreciation is computed using the straight-line method over estimated useful lives which range from 5 years for office property and equipment to 40 years for certain crude oil terminals and facilities. Crude oil pipelines are depreciated over 30 years. 7. Units Outstanding. Our forecast is based on the 49,577,748 units that are currently outstanding. 8. Adjusted Income per Unit. Adjusted income per limited partner unit is calculated by dividing the adjusted income allocated to limited partners by the weighted average units outstanding during the period. As noted in number 10 below, the adjusted income allocated to limited partners is impacted by the amount of the incentive distribution paid to the general partner. 9. Potential Effect of Changes in Capital Structure. Interest expense, adjusted income and adjusted income per unit estimates are based on our capital structure as of October 28, 2002. In keeping with our established financial growth strategy of financing acquisitions using a balance of equity and debt, we anticipate that we will issue equity in order to reduce debt associated with any future acquisitions. Depending on the terms, any such equity issuance may dilute the adjusted income per unit forecasts included in the foregoing table. In addition, we have recently issued $200 million of senior unsecured notes. We intend to monitor debt capital market conditions and may in the future issue additional senior unsecured notes, which may bear interest costs greater than the amount included in the foregoing guidance. Accordingly, the foregoing financial results and per unit estimates will change, depending on the timing and the terms of any debt or equity we actually issue. Additionally, financing transactions may result in our retiring some of our outstanding debt, which could result in a charge to earnings of unamortized debt issuance costs associated with the retired debt. We have not included any such potential charge in our forecast. 10. Adjusted Income to Limited Partners. The forecast is based on our current annual distribution of $2.15 per unit. The amount of adjusted income allocated to our limited partnership interests is 98% of the total partnership adjusted income less the amount of the general partner's incentive distribution. Based on a $2.15 annual distribution level and the current units outstanding, our general partner's incentive distribution is forecast to be approximately $4.0 million annually. The amount of the incentive distribution changes based on the number of units outstanding and the level of the distribution on the units. 11. Capital Expenditures. Total capital expenditures are estimated to be $8.3 million for the fourth quarter of 2002. Of this amount, expansion capital is estimated to be $6.5 million during the fourth quarter. The expansion capital estimates are primarily attributable to the Phase III expansion at our Cushing Terminal and a pipeline loop on a portion of the Manito System in Canada. Maintenance capital is estimated to be $1.8 million for the fourth quarter. 12. Although acquisitions comprise a key element of our growth strategy, these results and estimates do not include any assumptions or forecasts for any acquisitions that may be made after the date hereof. 13. The results for the year are based on the year-to-date September 30, 2002 actuals and our fourth quarter estimates. Preliminary Estimates for Year 2003 On July 24, 2002, we provided preliminary guidance for 2003 for EBITDA and EBIT, which guidance incorporated information for the Shell West Texas assets. We are currently in the process of developing our 2003 plan. We intend to update this guidance upon completion of our annual plan for 2003. Pending that update the following information updates our estimate of 2003 depreciation and amortization resulting from an updated purchase price allocation for the Shell West Texas assets. Such information also incorporates the impact of recent changes in our capital structure resulting from equity and debt offerings completed in the third quarter. Operating and Financial Guidance (in thousands except per unit data)
Year Ended December 31, 2003 -------------------------- Low High --------- -------- EBITDA $155,000 $162,000 Depreciation & Amortization 41,000 41,000 -------- -------- EBIT 114,000 121,000 Interest Expense 36,000 36,000 -------- -------- Adjusted Income $ 78,000 $ 85,000 Adjusted Income to Limited Partners $ 72,492 $ 79,352 Weighted Average Units Outstanding 49,578 49,578 Adjusted Income Per Unit $1.46 $1.60
The table above reflects the estimated EBITDA range as well as estimated depreciation, amortization and interest expense for the full year 2003. Adjusted income per unit is calculated assuming no change in units outstanding or distribution ($2.15 per unit), as of October 28, 2002. We have not included in this table the effect of potential vesting of unit grants under our Long-Term Incentive Plan, which permits the grant of restricted units and unit options covering an aggregate of approximately 1.4 million units. Approximately 1.0 million restricted units (and no unit options) have been granted. A restricted unit grant entitles the grantee to receive a common unit upon the vesting of the phantom unit. Subject to additional vesting requirements, restricted units may vest in the same proportion as the conversion of the partnership's outstanding subordinated units into common units. Certain of the restricted unit grants contain additional vesting requirements tied to the partnership achieving targeted distribution thresholds, generally $2.10, $2.30 and $2.50 per unit, in equal proportions. Under generally accepted accounting principles, we are required to recognize an expense when the financial tests for conversion of subordinated units and required distribution levels are met. The test associated with the conversion of subordinated units to common units is set forth in the partnership agreement and involves GAAP accounting concepts as well as complex and esoteric cash receipts and disbursement concepts that are indexed to the minimum quarterly distribution rate of $1.80 per limited partner unit. Because of this complexity, it is difficult to forecast when the vesting of these phantom units will occur. However, at the current distribution level of $2.15 per unit, assuming the subordination conversion test is met, the costs associated with the vesting of up to approximately 820,000 units would be incurred or accrued in the second half of 2003 or the first quarter of 2004. At a distribution level of $2.30 to $2.49, the number of units would be approximately 940,000. At a distribution level at or above $2.50, the number of units would be approximately 1,030,000. We are currently planning to issue units to satisfy the first 975,000 vested, and to purchase units in the open market to satisfy any vesting obligations in excess of that amount. Issuance of units would result in a non-cash compensation expense. Purchase of units would result in a cash charge to compensation expense. The amount of the charge to expense will be determined by the unit price on the date vesting occurs multiplied by the number of units. Consistent with our acquisition strategy, we are continuously engaged in discussions with potential sellers regarding the possible purchase by us of midstream crude oil assets. Since 1998, we have completed 12 acquisitions for an aggregate purchase price of $1.1 billion. We can give you no assurance that our current or future acquisition efforts will be successful or that any such acquisition will be completed on terms considered favorable to us. In addition, the partnership routine incurs third party costs in connection with these activities, which are capitalized and deferred pending final outcome of the transaction. Deferred costs associated with successful transactions are capitalized as part of the transaction, while deferred costs associated with unsuccessful transactions are expensed at the time of such final determination. We have not included any such potential charge in our forecast. Several regulatory and legislative initiatives have been introduced over the past several months in response to recent events regarding accounting issues at large public companies, resulting disruptions in the capital markets and ensuing calls for action to prevent repetition of such events. The partnership supports the actions called for under these initiatives and believes these steps will ultimately be successful in accomplishing the stated objectives. However, implementation of reforms in connection with such initiatives will add to the costs of doing business for all publicly-traded entities, including the partnership. Such costs will have an adverse impact on future income and cash flow, especially in the near term as legal, financial and consultant costs are incurred to analyze the new requirements, formalize current practices and implement required changes to ensure the partnership maintains compliance with these new rules. We are not able to estimate the magnitude of increase in our costs that will result from such reforms. Our current capital structure is expected to change as a result of issuing equity to fund subsequent future acquisitions, if any, and from the possible issuance of additional senior unsecured notes. These financing transactions may have a dilutive effect on adjusted income per unit. Additionally, financing transactions may result in our retiring some of our outstanding debt, which could result in a charge to earnings of unamortized debt issuance costs. We have not included any such potential charge in our forecast. Forward-Looking Statements And Associated Risks All statements, other than statements of historical fact, included in this report are forward-looking statements, including, but not limited to, statements identified by the words "anticipate," "believe," "estimate," "expect," "plan," "intend" and "forecast" and similar expressions and statements regarding our business strategy, plans and objectives of our management for future operations. These statements reflect our current views with respect to future events, based on what we believe are reasonable assumptions. Certain factors could cause actual results to differ materially from results anticipated in the forward-looking statements. These factors include, but are not limited to: o abrupt or severe production declines or production interruptions in outer continental shelf crude oil production located offshore California and transported on the All American Pipeline; o declines in volumes shipped on the Basin and our other pipelines by third party shippers; o the availability of adequate supplies of and demand for crude oil in the areas in which we operate; o the effects of competition; o the success of our risk management activities; o the impact of crude oil price fluctuations; o the availability (or lack thereof) of acquisition or combination opportunities; o successful integration and future performance of acquired assets; o successful third-party drilling efforts and completion of announced oil-sands projects; o continued creditworthiness of, and performance by, our counter parties; o our levels of indebtedness and our ability to receive credit on satisfactory terms; o shortages or cost increases of power supplies, materials or labor; o weather interference with business operations or project construction; o the impact of current and future laws and governmental regulations; o the currency exchange rate of the Canadian dollar; o environmental liabilities that are not covered by an indemnity or insurance; o fluctuations in the debt and equity markets; and o general economic, market or business conditions. We undertake no obligation to publicly update or revise any forward-looking statements. Further information on risks and uncertainties is available in Item 7 of our Annual Report Form 10-K for the year 2001, and Part I, Item 2 of our Form 10-Q for the quarter ended June 30, 2002. Such sections are incorporated by reference herein. SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. PLAINS ALL AMERICAN PIPELINE, L.P. Date: October 29, 2002 By: Plains AAP, L. P., its general partner By: Plains All American GP LLC, its general partner By: /s/ Phillip D. Kramer --------------------------------------- Name: Phillip D. Kramer Title: Executive Vice President and Chief Financial Officer