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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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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.)
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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
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Name: Phillip D. Kramer
Title: Executive Vice President and Chief
Financial Officer