Plains All American Pipeline 8K Results of Operations and Financial Condition

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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)—November 3, 2004

Plains All American Pipeline, L.P.
(Name of Registrant as specified in its charter)

DELAWARE
(State or other jurisdiction of
incorporation or organization)

1-14569
(Commission File Number)

76-0582150
(I.R.S. Employer
Identification No.)

333 Clay Street, Suite 1600
Houston, Texas 77002
(713) 646-4100
(Address, including zip code, and telephone number,
including area code, of Registrants principal executive offices)

N/A
(Former name or former address, if changed since last report.)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o: Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
o: Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
o: Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
o: Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 9.01 Financial Statements and Exhibits

(c): Exhibit 99.1—Press Release dated November 3, 2004

Item 2.02 and 7.01. Regulation FD Disclosure; Results of Operations and Financial Condition

Plains All American Pipeline, L.P. (the "Partnership") today issued a press release reporting its third quarter results. The Partnership is furnishing the press release, attached as Exhibit 99.1, pursuant to Item 2.02 and Item 7.01 of Form 8-K. The Partnership is also furnishing pursuant to Item 7.01 its projections of certain operating and financial results for the fourth quarter of 2004 and preliminary projections of certain operating and financial results for calendar year 2005. In accordance with General Instruction B.2. of Form 8-K, the information presented herein under Item 7.01 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 2004 Estimates

EBIT and EBITDA (each as defined below in Note 1 to the "Operating and Financial Guidance" table) are non-GAAP financial measures. Net income and cash flows from operating activities are the most directly comparable GAAP measures for EBIT and EBITDA. However, it is impractical to reconcile EBIT and EBITDA to cash flows from operating activities for forecasted periods. As a result, for forecasted periods in the operating and financial guidance table below, we have reconciled EBIT and EBITDA to net income, but not to cash flows from operating activities. In Note 13 below, we reconcile historical EBIT and EBITDA to historical net income and to cash flow from operating activities for the periods presented. We also encourage you to visit our website at www.paalp.com, in particular the section entitled "Non-GAAP Reconciliation," which presents a historical reconciliation of certain commonly used non-GAAP financial measures, including EBIT and EBITDA. We present EBIT and EBITDA because we believe they provide additional information with respect to both the performance of our fundamental business activities and our ability to meet our future debt service, capital expenditures and working capital requirements. We also believe that debt holders commonly use EBITDA to analyze partnership performance. In addition, we have highlighted the impact on EBITDA and EBIT of our long-term incentive program, the cumulative effect of a change in accounting principle, the impact of current and potential future revaluations of foreign currency and, to the extent known at the time of preparation, items related to SFAS 133.

The following table reflects our actual results for the first nine months of 2004 and our current range of guidance for operating and financial results for the fourth quarter of 2004. Our guidance is based on assumptions and estimates that we believe are reasonable based on our assessment of historical trends and business cycles and currently available information. However, our assumptions and future performance are both subject to a wide range of business risks and uncertainties and also include projections for several recent acquisitions, so we cannot assure you that actual performance will fall within these guidance ranges. 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 operating and financial guidance provided below is given as of the date hereof, based on information known to us as of November 2, 2004. We undertake no obligation to publicly update or revise any forward-looking statements.

Operating and Financial Guidance
(in millions, except per unit data)

					Guidance(1)
					Three Months Ended December 31, 2004						Twelve Months Ended December 31, 2004
		Actual Nine Months Ended Sept. 30, 2004			Three Months Ended December 31, 2004						Twelve Months Ended December 31, 2004
		Actual Nine Months Ended Sept. 30, 2004			Low			High			Low			High
Pipeline
	Net revenues	$	231.1		$	84.5		$	86.5		$	315.6		$	317.6
	Field operating costs		(84.9	)		(31.5	)		(30.9	)		(116.4	)		(115.8	)
	General and administrative expenses		(29.0	)		(11.0	)		(10.6	)		(40.0	)		(39.6	)

	Segment profit		117.2			42.0			45.0			159.2			162.2

Gathering, Marketing, Terminalling & Storage
	Net revenues		171.8			56.0			60.4			227.8			232.2
	Field operating costs		(73.7	)		(29.2	)		(28.8	)		(102.9	)		(102.5	)
	General and administrative expenses		(29.2	)		(8.8	)		(8.6	)		(38.0	)		(37.8	)

	Segment profit		68.9			18.0			23.0			86.9			91.9

Depreciation and amortization expense			(45.9	)		(17.0	)		(16.8	)		(62.9	)		(62.7	)
Interest expense			(32.2	)		(14.0	)		(13.7	)		(46.2	)		(45.9	)
Other Income (Expense)			0.4			—			—			0.4			0.4

Income before cumulative effect of change in accounting principle			108.4			29.0			37.5			137.4			145.9
Cumulative effect of change in accounting principle			(3.1	)		—			—			(3.1	)		(3.1	)

Net Income		$	105.3		$	29.0		$	37.5		$	134.3		$	142.8

Net Income to Limited Partners		$	97.7		$	25.8		$	34.1		$	123.5		$	131.8
Basic and Diluted:
	Average Units Outstanding		61.9			67.3			67.3			63.3			63.3
	Net Income Per Limited Partner Unit	$	1.58		$	0.38		$	0.51		$	1.95		$	2.08
EBIT		$	137.5		$	43.0		$	51.2		$	180.5		$	188.7

EBITDA		$	183.4		$	60.0		$	68.0		$	243.4		$	251.4


Selected Items Impacting Comparability
LTIP charge		$	(4.2	)	$	—		$	—		$	(4.2	)	$	(4.2	)
Cumulative effect of change in accounting principle			(3.1	)		—			—			(3.1	)		(3.1	)
Gain (Loss) on foreign currency revaluation			3.4			(2.0	)		(1.0	)		1.4			2.4
SFAS 133 non-cash mark-to-market adjustment			1.4			—			—			1.4			1.4
Other			(0.1	)		—			—			(0.1	)		(0.1	)

		$	(2.6	)	$	(2.0	)	$	(1.0	)	$	(4.6	)	$	(3.6	)


Excluding Selected Items Impacting Comparability
EBITDA		$	186.0		$	62.0		$	69.0		$	248.0		$	255.0

Net Income		$	107.9		$	31.0		$	38.5		$	138.9		$	146.4

Net Income per Limited Partner Unit		$	1.62		$	0.41		$	0.52		$	2.02		$	2.14

(1): Assumes a foreign exchange rate for the fourth quarter of $1.30 CAD to $1 USD.

Notes and Significant Assumptions:

1.: Definitions.

EBIT		Earnings before interest and taxes
EBITDA		Earnings before interest, taxes and depreciation and amortization expense
Bbl/d		Barrels per day
Segment Profit		Net revenues less purchases, field operating costs, and segment general and administrative expenses
LTIP		Long-Term Incentive Plan
LPG		Liquified petroleum gas and other petroleum products
FX		Foreign Exchange

2.: Pipeline Operations. Pipeline volume estimates are based on historical and anticipated future operating performance. Actual segment profit could vary materially depending on the level of volumes transported. The following table summarizes our pipeline volumes and specifically breaks out the major systems that are significant either in total volumes transported or in contribution to total net revenue.

		Calendar 2004
		Actual
		Three Months Ended			Guidance
		March 31	June 30	September 30	Three Months Ended December 31	Twelve Months Ended December 31
Average Daily Volumes (000's Bbl/d) (4)
	All American	55	59	52	52	54
	Basin	275	271	279	255	270
	Capline (2)	54	169	122	137	121
	West Texas/New Mexico area systems (1)(3)	209	374	392	365	335
	Other	215	536	489	516	438

		808	1,409	1,334	1,325	1,218
	Canada	240	260	273	250	256

		1,048	1,669	1,607	1,575	1,474


(1) Includes the Link acquisition effective April 1, 2004
(2) Effective March 1, 2004
(3) The aggregate of 10 systems in the West Texas/New Mexico area.
(4) Volumes associated with acquisitions represent total volumes transported for the number of days the assets were owned divided by the number of days in the period.

Average volumes for the fourth quarter are expected to be in the range of 1,575,000 Bbl/d, approximately 32,000 Bbl/d or 2% lower than the third quarter of 2004. This decrease is primarily attributable to a redirection of sweet crude oil flows as a result of Gulf of Mexico production disruptions in the third quarter due to hurricanes and some moderate seasonal fluctuation.

Net revenues were forecasted using the above volume assumptions priced at tariff rates currently received, with adjustments where appropriate for estimated escalation rates as allowed by contractual terms. To illustrate the impact volume changes may have on segment profit, the following table provides a volume sensitivity analysis of three systems representing approximately 27% of total pipeline segment net revenues.

Volume Sensitivity Analysis

System	Increase/(Decrease) in Volume (Bbls/d)	% of System Total		Increase/(Decrease) in Annualized Segment Profit
				(in millions)
All American	5,000	10	%	$	3.1
Basin	10,000	4	%		1.0
Capline	10,000	7	%		1.5

3.: Gathering, Marketing, Terminalling and Storage Operations. Our guidance for the remainder of the year assumes continued volatility in the crude oil market. Average volumes for gathering and marketing are estimated to be approximately 700,000 Bbl/d for the fourth quarter of 2004 compared to average third quarter volumes of 663,000 Bbl/d. Although volumes from crude oil gathered at the lease in the fourth quarter of 2004 are expected to remain relatively consistent with the third quarter, the increase in fourth quarter LPG volumes is principally attributable to the Schaefferstown acquisition and seasonal demands.

		Calendar 2004
		Actual
		Three Months Ended			Guidance
		March 31	June 30	September 30	Three Months Ended December 31	Twelve Months Ended December 31
Average Daily Volumes (000's Bbl/d)
	Crude Oil Lease Gathering(1)	460	641	625	640	592
	LPG(2)	59	21	38	60	44

		519	662	663	700	636


(1) Includes Link Acquisition effective April 1, 2004
(2) Includes Schaefferstown acquisition effective August 25, 2004.

Segment profit is forecast using the volume assumptions stated above and estimates of unit margins, operating expenses and G&A based on current and anticipated market conditions. Realized unit margins for any given lease-gathered barrel could vary significantly based on a variety of factors including location, quality and contract structure. Based on our projected segment profit per barrel for the fourth quarter of 2004, a 5,000 Bbl/d variance in lease gathering volumes would impact segment profit by an approximate $0.9 million on an annualized basis. A $0.01 variance in the aggregate average per-barrel margin would impact segment profit by an approximate $2.6 million on an annualized basis.

4.: General and Administrative (G&A) Expense. G&A expense totaled $19.5 million for the third quarter of 2004 and is projected to remain relatively flat in the fourth quarter. While we expect the benefit of continued decreases in duplicative administrative costs associated with the Link acquisition, it is anticipated that increases in costs associated with Sarbanes-Oxley requirements, corporate insurance, health insurance and increased personnel required due to continued organic growth will offset these savings.

5.

EBITDA Guidance Range. Our fourth quarter 2004 EBITDA (excluding selected items impacting comparability) guidance ranges from $62 million to $69 million, approximately a 10% range from high to low. This wider range is intended to reflect the uncertainties normally associated with forecasts and more specifically considers the following potential variables with respect to the fourth quarter of 2004:

a.: crude oil market volatility,
b.: potential seasonal impacts of weather on our business activities, including our LPG business,
c.: FX levels and potential reversals of foreign currency revaluations primarily associated with LPG inventory builds and subsequent draws,
d.: prices realized on our crude oil pipeline loss allowance,
e.: potential shifting of costs between quarters related to our operational integrity programs, and
f.: the amount and timing of costs associated with implementing Sarbanes-Oxley requirements.

For more information, please refer to our website at www.paalp.com in the section "Investor Relations—Partnership Presentations" for information regarding our approach to financial guidance and the section "Investor Relations—Conference Calls" for a discussion of the third quarter results and fourth quarter forecast included in the conference call script dated November 3, 2004.

6.

Depreciation & Amortization. Depreciation and amortization is forecast based on our existing depreciable assets and forecast capital expenditures. Depreciation is computed using the straight-line method over estimated useful lives, which range from 3 years (for office property and equipment) to 50 years (for certain pipelines, crude oil terminals and facilities).

7.

Statement of Financial Accounting Standards No. 133 "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133). The forecast presented above does not include assumptions or projections with respect to potential gains or losses related to SFAS 133, as there is no accurate way to forecast these potential gains or losses. The potential gains or losses related to SFAS 133 (primarily non-cash, mark-to-market adjustments) could cause actual net income to differ materially from our projections.

8.

Acquisitions and Capital Expenditures. Although acquisitions constitute a key element of our growth strategy, the forecasted results and associated estimates do not include any assumptions or forecasts for any material acquisition that may be made after the date hereof. Expansion capital expenditures are forecast to be approximately $72.0 million for the fourth quarter of 2004. Some of the more notable projects to be completed include:

•

Coffeyville pipeline construction project—$27.4 million,

•

Trenton pipeline expansion project—$18.6 million,

•

Cal Ven fractionator expansion project—$6.0 million; and

•

Capital projects associated with the Link acquisition—$4.2 million.

Maintenance capital expenditures are forecast to be approximately $4.0 million for the fourth quarter of 2004.

9.: Capital Structure. The fourth quarter forecast assumes no change to the capital structure.

10.: Interest Expense. Debt balances are projected based on estimated cash flows, current distribution rates, capital expenditures for maintenance and expansion projects, linefill purchases, planned sales of surplus equipment, expected timing of collections and payments, and forecast levels of inventory and other working capital sources and uses.

Fourth quarter interest expense is expected to be between $13.7 million and $14.0 million, assuming an average long-term debt balance of approximately $900 million and an all-in average rate of approximately 6.2%. Approximately 89% of our projected average debt balance has an average fixed interest rate of 6.0%. Included in the effective cost of debt are not only current cash payments, but also commitment fees, amortization of long-term debt discounts, and deferred amounts associated with terminated interest rate hedges. The amortization of deferred amounts associated with terminated interest rate hedges results in a non-cash component to interest expense of approximately $1.6 million per year (approximately $400,000 per quarter). The majority of this amount (approximately 74%) will be completely amortized in two years. The remainder will be amortized over the next ten years.

11.: Net Income per Unit. Basic net income per limited partner unit is calculated by dividing the net income allocated to limited partners by the basic weighted average units outstanding during the period. Basic weighted average units outstanding are projected to be approximately 67.3 million units for the fourth quarter. Currently, there are no dilutive securities.

Net income allocated to limited partners is impacted by the income allocated to the general partner and the amount of the incentive distribution paid to the general partner. Based on (i) the forecasted number of units outstanding during the projection period, (ii) the current general partner incentive distribution level and (iii) forecasted net income, for each $0.05 per unit annual increase in the distribution rate, net income available for limited partners will be decreased by approximately $1.0 million ($0.02 per unit) on an annualized basis. The amount of income allocated to our limited partnership interests is 98% of the total partnership income after deducting the amount of the general partner's incentive distribution. Based on our current annualized distribution rate of $2.40 per unit, our general partner's distribution is forecast to be approximately $14.0 million annually, of which $10.7 million is attributed to the incentive distribution rights. The relative amount of the incentive distribution varies directionally with the number of units outstanding and the level of the distribution on the units.

12.: Long-term Incentive Plan. Our fourth quarter of 2004 forecast does not include a charge related to our LTIP plan. A relatively small number of grants will vest with the passage of time, but the next significant vesting event under the LTIP plan is the achievement of a $2.50 per unit annualized distribution level. If the $2.50 distribution level is met in 2005, approximately 100,000 incremental units will vest resulting in a charge to earnings of approximately $3.8 million at current market prices. GAAP requires that we accrue the earned portion of LTIP vesting award when it isprobable the performance level (i.e. $2.50 distribution) will be achieved. We expect to have the information to properly make this assessment after we complete our financial projections for calendar 2005 (as discussed in the Preliminary 2005 Guidance section below).

13.: Reconciliation of EBITDA and EBIT to Net Income and Cash Flows from Operating Activities. The following table reconciles historical EBIT and EBITDA to historical net income and EBITDA to cash flows from operating activities as of September 30, 2004:

			Nine Months Ended Sept. 30, 2004
			(in millions)
Reconciliation to Net Income
	EBITDA		$	183.4
	Depreciation and amortization			(45.9	)

	EBIT			137.5
	Interest expense			(32.2	)

	Net Income		$	105.3

Reconciliation to Cash Flows from Operating Activities
	EBITDA		$	183.4
	Interest expense			(32.2	)
	Net change in assets and liabilities, net of acquisitions			(40.3	)
	Other items not affecting cash flows from operating activities
		Cumulative effect of change in accounting principle		3.1
		Gain on foreign currency revaluation		(3.4	)
		Net cash paid for terminated swaps		(1.5	)
		Change in derivative fair value		(1.4	)
		Non-cash portion of LTIP charge		4.2
		Non-cash amortization of terminated interest rate swap		1.1

	Net cash provided by operating activities		$	113.0

Preliminary 2005 Guidance

In our August 4, 2004 guidance, we provided a preliminary estimate for 2005 with the qualification that final estimates would not be available until after the completion of our formal detailed business plan in February 2005. Although we have not attempted to update the following information since the August 2004 guidance and it accordingly should be considered preliminary and subject to refinement, this forward-looking information for 2005 was prepared based on information we consider to be reasonable.

This preliminary guidance is based on continued operating and financial performance of our existing assets under normalized market conditions, continuation of current pipeline shipments and anticipated natural field declines. In that regard, we would expect average daily pipeline shipments to average approximately 270,000 Bbl/d for Basin, 50,000 Bbl/d for All American and 125,000 Bbl/d for Capline. Similarly, we would expect gathering and marketing volumes to average approximately 700,000 Bbl/d, and that realized margins would be consistent with historical results adjusted slightly for lower oil price volatility. The overall guidance also assumes the inclusion of recent acquisitions along with the successful integration and realization of cost savings and revenue synergies identified in our acquisition analyses, as well as completion of our current capital projects.

The following table summarizes the range of selected key financial data from our preliminary projections for calendar year 2005.

Preliminary Calendar 2005 Guidance (in millions)

	Low			High
EBITDA	$	265		$	275
Interest Expense		(58	)		(54	)
Depreciation and Amortization		(70	)		(65	)
Maintenance Capital Expenditures		18			15

Based on the data provided above, we expect EBIT for 2005 to range from $195 million to $210 million. The potential effects of any gains or losses from SFAS 133 (see Note 7 above) are not included in the guidance for 2005.

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:

•: abrupt or severe production declines or production interruptions in outer continental shelf production located offshore California and transported on our pipeline system;
•: the success of our risk management activities;
•: the availability of, and ability to consummate, acquisition or combination opportunities;
•: our access to capital to fund additional acquisitions and our ability to obtain debt or equity financing on satisfactory terms;
•: successful integration and future performance of acquired assets or businesses;
•: environmental liabilities that are not covered by an indemnity, insurance or existing reserves;
•: maintenance of our credit rating and ability to receive open credit from our suppliers;
•: declines in volumes shipped on the Basin Pipeline and our other pipelines by third party shippers;
•: the availability of adequate third party production volumes for transportation and marketing in the areas in which we operate;
•: successful third-party drilling efforts in areas in which we operate pipelines or gather crude oil;
•: demand for various grades of crude oil and resulting changes in pricing conditions or transmission throughput requirements;
•: fluctuations in refinery capacity in areas supplied by our transmission lines;
•: the effects of competition;

•: continued creditworthiness of, and performance by, our counterparties;
•: the impact of crude oil price fluctuations;
•: the impact of current and future laws and governmental regulations;
•: shortages or cost increases of power supplies, materials or labor;
•: weather interference with business operations or project construction;
•: the currency exchange rate of the Canadian dollar;
•: fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our LTIP; and
•: 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 our filings with the Securities and Exchange Commission, which information is 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.
	By:	PLAINS AAP, L. P., its general partner
	By:	PLAINS ALL AMERICAN GP LLC, its general partner
Date: November 3, 2004	By:	/s/ PHIL KRAMER
		Name:	Phil Kramer
		Title:	Executive Vice President and Chief Financial Officer

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Plains All American Pipeline (PAA) 8-KResults of Operations and Financial Condition