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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)—February 24, 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.)	

Item 7. Financial Statements and Exhibits 
(c)
Exhibit 99.1—Press Release dated February 24, 2004

Item 9 and 12. Regulation FD Disclosure; Results of Operations and Financial Condition 
        Today we issued a press release reporting our fourth quarter and full year 2003 results. We are furnishing the press release, attached as Exhibit 99.1, pursuant to Item 9 and Item 12 of Form 8-K. We are also furnishing pursuant to Item 9 our projections of certain operating and financial results for the first quarter of 2004 and modifying certain aspects of our preliminary guidance for financial performance for the full year of 2004. In accordance with General Instructions B.2. and B.6. of Form 8-K, the information presented herein under Item 9 or Item 12, including Exhibit 99.1, 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 First Quarter 2004 Estimates; Update of Full Year 2004 Guidance 
        EBIT and EBITDA (each as defined below in Note 1 to the "Operating and Financial Guidance" table) are non-GAAP financial measures, and are reconciled to Net Income in Note 3 below. EBIT and EBITDA are impractical to reconcile to cash flows from operating activities for forecasted periods. Net income and cash flows from operating activities are the most directly comparable GAAP measures for EBIT and EBITDA. We 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 non-GAAP financial measures that are commonly used, such as EBIT and EBITDA. EBIT and EBITDA are presented 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. 
        The following table reflects our current range of guidance for operating and financial results for the first quarter of 2004 and full year ending December 31, 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 our future performance are both subject to a wide range of business risks and uncertainties, 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 February 23, 2004. 
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Operating and Financial Guidance 
 	 	Quarter Ending
March 31, 2004
	 	Year Ending
December 31, 2004
	 	
 	 	Low
	 	High
	 	Low
	 	High
	 	
 	 	(in thousands, except per unit data)	 	
Pipeline segment margin	 	$	29,800	 	$	30,600	 	$	132,500	 	$	134,500	 	
Gathering, Marketing, Terminalling & Storage segment margin	 	 	29,200	 	 	31,100	 	 	119,400	 	 	122,800	 	
Long Term Incentive Plan (LTIP) Charge—Operations	 	 	(400	)	 	(400	)	 	(800	)	 	(800	)	
 	 		 		 		 		 	
Total Segment Margin	 	$	58,600	 	$	61,300	 	$	251,100	 	$	256,500	 	

General and Administrative (G&A) Expense	

(15,000	
)	
 	
(14,700	
)	
 	
(56,900	
)	
 	
(56,300	
)	
LTIP Charge—G&A	 	 	(1,500	)	 	(1,500	)	 	(3,700	)	 	(3,700	)	
 	 		 		 		 		 	
EBITDA	 	$	42,100	 	$	45,100	 	$	190,500	 	$	196,500	 	

Depreciation and Amortization Expense	

(13,400	
)	
 	
(13,200	
)	
 	
(57,300	
)	
 	
(56,900	
)	
 	 		 		 		 		 	
EBIT	 	$	28,700	 	$	31,900	 	$	133,200	 	$	139,600	 	

Interest Expense	

(9,400	
)	
 	
(9,200	
)	
 	
(39,350	
)	
 	
(38,850	
)	
 	 		 		 		 		 	
Net Income	 	$	19,300	 	$	22,700	 	$	93,850	 	$	100,750	 	
 	 		 		 		 		 	
Net Income to Limited Partners	 	$	17,303	 	$	20,635	 	$	85,475	 	$	92,237	 	
 	 		 		 		 		 	
Basic Weighted Avg Units Outstanding	 	 	58,424	 	 	58,424	 	 	58,895	 	 	58,895	 	
 	 		 		 		 		 	
Basic Net Income Per Limited Partner Unit	 	$	0.30	 	$	0.35	 	$	1.45	 	$	1.57	 	

Diluted Weighted Avg Units Outstanding	

58,833	

58,833	

N/A	

N/A	

Diluted Net Income per Limited Partner Unit	 	$	0.29	 	$	0.35	 	 	N/A	 	 	N/A	 	

Items Impacting Comparability (in thousands)	

 	

 	

 	

 	
 	
 	LTIP Charge	 	$	(1,900	)	$	(1,900	)	$	(4,500	)	$	(4,500	)	
 	SFAS 133 (See Note 2)	 	$	—	 	$	—	 	$	—	 	$	—	 	
 	 		 		 		 		 	
 	 	$	(1,900	)	$	(1,900	)	$	(4,500	)	$	(4,500	)	

	 	

 	

 	

 	

 	

 	

Excluding Items Impacting Comparability (in thousands)	

 	

 	

 	

 	
 	
EBITDA	 	$	44,000	 	$	47,000	 	$	195,000	 	$	201,000	 	
 	 		 		 		 		 	
Net Income	 	$	21,200	 	$	24,600	 	$	98,350	 	$	105,250	 	
 	 		 		 		 		 	
Net Income per Limited Partner Unit	 	$	0.33	 	$	0.39	 	$	1.53	 	$	1.64	 	
 	 		 		 		 		 	
Diluted Net Income per Limited Partner Unit	 	$	0.33	 	$	0.38	 	 	N/A	 	 	N/A	 	

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Notes and Significant Assumptions: 
1.
EBITDA means Earnings Before Interest, Taxes, Depreciation, and Amortization. EBIT means EBITDA less Depreciation and Amortization. Segment margin excludes depreciation. 
2.
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 could materially change reported net income (related primarily to non-cash, mark-to-market gains or losses). 
3.
Reconciliation of EBIT and EBITDA to Net Income. The following table reconciles forecasted EBIT and EBITDA to forecasted net income: 
        Net Income to EBITDA Reconciliation
 	 	Quarter Ending
March 31, 2004
	 	Year Ending
December 31, 2004
	
 	 	Low
	 	High
	 	Low
	 	High
	
 	 	(in thousands)	
Net Income	 	$	19,300	 	$	22,700	 	$	93,850	 	$	100,750	
Interest expense	 	 	9,400	 	 	9,200	 	 	39,350	 	 	38,850	
 	 		 		 		 		
Earnings before interest and taxes ("EBIT")	 	 	28,700	 	 	31,900	 	 	133,200	 	 	139,600	
Depreciation and amortization expense	 	 	13,400	 	 	13,200	 	 	57,300	 	 	56,900	
 	 		 		 		 		
EBITDA	 	$	42,100	 	$	45,100	 	$	190,500	 	$	196,500	
 	 		 		 		 		
4.
Pipeline Segment 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 1,070,000 barrels per day for the first quarter of 2004 (compared to average 4Q03 volumes of 973,000). Full year 2004 volumes are estimated to average 1,170,000 barrels per day. Major differences between 4Q03 and 1Q04 volumes include an average increase of approximately 70,000 barrels per day due to the anticipated completion of the March 1, 2004 acquisition of Shell's interest in the Capline and Capwood Pipelines (the "Capline Acquisition"). These pipelines are estimated to generate average volumes of approximately 210,000 barrels per day during a full quarter (See Note 15 for further assumptions regarding this acquisition). Other significant changes include the net effect of a complete quarter for both the South Saskatchewan (South Sask) and Atchafalaya Pipelines, which were purchased during the fourth quarter of 2003. Volumes on Basin Pipeline (our largest volume pipeline system) for the first quarter are forecast at approximately 270,000 barrels per day (compared to average 4Q03 volumes of approximately 262,000 barrels per day). All American Pipeline volumes (our highest per barrel tariff volumes), which transport Outer Continental Shelf (OCS) production, are estimated to make up approximately 5% of total daily volumes, or approximately 56,000 barrels per day (compared to average 4Q03 volumes of 58,000 barrels per day). Revenues are forecast using these volume assumptions, current tariffs and estimates of tariff escalation rates and operating expenses, each of which we believe are reasonable. A 5,000 barrel per day variance in OCS volumes would have an approximate $0.8 million effect on segment margin for each quarter and an approximate $3.2 million effect on an annualized basis. Within a reasonable range of forecasted levels, an average 10,000 barrel per day variance in the Basin Pipeline System, which is equivalent to an estimated 4% volume variance on that pipeline system, would have an approximate $0.2 million effect on segment margin for each quarter and an approximate $0.8 million effect on an annualized basis. 
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5.
Gathering, Marketing, Terminalling and Storage Segment Margin. Market conditions for Gathering & Marketing experienced in 2003 were strong due to the volatility caused by many different economic and geopolitical issues (e.g.. war with Iraq, strikes in Venezuela, uncertain global economic conditions, etc.). Our 2004 guidance assumes that crude oil markets return to normal conditions, which includes some volatility, but not the level experienced during 2003. Forecast volumes for Gathering & Marketing are approximately 540,000 barrels per day (including approximately 475,000 barrels per day of lease gathered barrels and 65,000 barrels per day of LPG volumes) for the first quarter of 2004 (compared to average 4Q03 volumes of 522,000 barrels per day including 459,000 barrels per day of lease gathered barrels and 63,000 barrels per day of LPG volumes). Volumes are estimated to average approximately 552,000 barrels per day for the full year of 2004 (comprising approximately 500,000 barrels per day of lease gathered barrels and 52,000 barrels per day of LPG volumes). Segment margin is forecast using these volume assumptions and estimates of unit margins and operating expenses, each of which we believe are reasonable, 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. However, based on our projected average margin for the first quarter of 2004, a 5,000 barrel per day variance in lease gathering volumes would have an approximate $0.3 million effect on segment margin for each quarter and an approximate $1.1 million effect on an annualized basis. A $0.01 per barrel variance in the aggregate average segment margin would have an approximate $0.5 million effect on segment margin for each quarter and an approximate $2.0 million effect on an annualized basis. 
6.
General and Administrative Expense. G&A expense excluding LTIP charge is forecast to be between $14.7 million and $15.0 million for the first quarter of 2004 and between $56.3 million and $56.9 million for the full year of 2004. Significant increases to general and administrative expenses are expected due to Sarbanes-Oxley requirements, corporate insurance, and increased personnel required as a result of acquisition activity and in anticipation of continued organic growth. We have forecast G&A expenses attributable to complying with requirements of the Sarbanes-Oxley Act using estimates we consider reasonable. However, given the relatively short history of the Act and the new requirements with respect to Section 404 of the Act, these expenses could increase significantly. Section 404 of the Act is effective for fiscal years ending after June 30, 2004 and requires management to make an assertion of the adequacy of internal controls, and our independent accountants to attest to management's assertion. 
7.
Interest Expense. First quarter interest expense is forecast to be between $9.2 million and $9.4 million assuming an average long-term debt balance of approximately $585.0 million and the current outlook for interest rate indices, which translates into an average interest rate for the partnership of approximately 6.4%, including our fixed rate debt, current interest rate hedges on floating rate debt and commitment fees. Approximately $0.4 million of forecast interest expense is non- cash and attributable to the amortization of interest rate hedges that were terminated in December 2003 at the time we issued senior unsecured notes. Interest expense for the full year of 2004 is forecast to be between $38.9 million and $39.4 million assuming an average long-term debt balance of approximately $694.0 million and the current outlook for interest rate indices, resulting in an average interest rate for the partnership of approximately 5.6%, including our fixed rate debt, current interest rate hedges on floating rate debt and commitment fees. The forecast is based on estimated cash flow, current distribution rates, the Capline Acquisition announced in December 2003, capital projects and linefill purchases, planned sales of surplus equipment, forecast timing of collections and payments, and forecast levels of inventory and other working capital sources and uses, each of which we believe are reasonable. Approximately $1.4 million of forecast interest expense for the year is non-cash and attributable to the amortization of the terminated interest rate hedges noted above. Approximately 35% of our expected average 2004 full year long-term debt balance is subject to floating interest rates, generally based on LIBOR. Accordingly, an 
5

increase in LIBOR will have a negative impact on our results. LIBOR rates are currently at or near a historical low level. 
8.
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 5 years for office property and equipment to 40 years for certain pipelines, crude oil terminals and facilities. The majority of our crude oil pipelines are depreciated over 30 years. 
9.
Units Outstanding. Basic weighted average units outstanding for the first quarter of 2004 are based on the 58,331,960 units outstanding as of December 31, 2003 plus the effect of approximately 138,000 common units issued in satisfaction of the vesting of restricted units in February 2004 related to the Long Term Incentive Plan ("LTIP"), see Note 14. Basic weighted average units for the full year of 2004 are based on the current units outstanding and include the effect of the issuance of approximately 319,000 units under our LTIP in the first and second quarters of 2004 and the anticipated issuance of approximately 409,000 units (two-thirds of the total potential units) in order to satisfy the contingent consideration associated with the Canpet acquisition (see Note 11). Diluted weighted average units outstanding in the first quarter of 2004 include the effect of the issuance of units in payment of the contingent consideration for the Canpet acquisition. There are currently no dilutive securities or obligations anticipated to be outstanding as of December 31, 2004. Approximately 30,000 units (net of cash payments) are expected to be issued in the second half of 2004 to satisfy the continued vesting of units under our LTIP. 
10.
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. Diluted net income per limited partner unit is calculated by dividing the net income allocated to limited partners by the diluted weighted average units outstanding during the period. As noted below, the 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 the forecasted number of units outstanding during the projection period and the current general partner incentive distribution level, 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. 
11.
Potential Effect of Changes in Capital Structure. Interest expense, net income and net income per unit estimates are based on our capital structure and known changes as of February 23, 2004. In December 2003, we raised approximately $88 million in a public equity offering in anticipation of consummating the pending Capline Acquisition. In addition, any future refinancing of our bank debt through the issuance of long-term, fixed rate debt would increase projected interest expense. To adhere to our established financial growth strategy, we anticipate that we will issue additional equity in connection with any future acquisitions not included in the current forecast. Depending on the terms, any such equity issuance may dilute the net income per unit forecasts included in the foregoing table. The foregoing financial results and per unit estimates will change, depending on the timing and the terms of any debt or equity we might issue. 
In connection with the CANPET acquisition in July 2001, approximately $26.5 million Canadian of the purchase price, payable in cash or common units, was deferred subject to various performance objectives being met. These objectives were met as of December 31, 2003 and the deferred amount is payable on April 30, 2004. The number of common units issued in satisfaction of the deferred payment will depend upon the average trading price of our common units for a ten-day trading period prior to the payment date and the Canadian and U.S. dollar exchange rate on the payment date. In addition, an amount will be paid equivalent to the distributions that would have been paid on the common units had they been outstanding since the acquisition was consummated. At our 
6

option, the deferred payment may be paid in cash rather than the issuance of units. Assuming one-third of the contingent purchase price and all past distributions are paid in cash and the remainder is satisfied with common units, based on the foreign exchange rate at December 31, 2003, (Canadian dollar to U.S. dollar exchange rate of 1.30 to 1) and a unit price of $33.35 per unit approximately 409,000 units would be issued, and are included in our forecast. 
12.
Net Income to Limited Partners. 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 a $2.25 annual distribution level and the units anticipated to be outstanding, our general partner's distribution is forecast to be approximately $9.3 million annually, of which $6.6 million is attributed to the incentive distribution rights. The relative amount of the incentive distribution increases with the number of units outstanding and the level of the distribution on the units. 
13.
Capital Expenditures. Expansion capital expenditures are forecast to be approximately $18.4 million for the first quarter and $51.2 million for the full year of 2004. Expansion projects planned in 2004 include the Cushing Phase IV Expansion—$10.0 million; upgrades related to prior acquisitions—$22.5 million (e.g. Red River, ArkLaTex, Atchafalaya, Eugene Island, Alto, and South Sask); the Iatan System Expansion—$6.0 million; Information Systems related projects—$4.5 million; and $8.2 million for various other operations projects. As described in Note 15 below, our forecast also includes $158.0 million (inclusive of a $15.8 million performance deposit paid in December 2003) of acquisition capital for the Capline Acquisition. Maintenance capital expenditures are forecast to be approximately $2.8 million for the first quarter and $11.7 million for the full year of 2004, of which $0.2 million and $1.8 million, respectively, is related to the Capline Acquisition. Unless otherwise known at the time, we forecast maintenance capital to be incurred ratably throughout the year. 
14.
Vesting under Long-Term Incentive Plan. In February 2004 we issued approximately 138,000 common units (after netting for taxes) in connection with the vesting of phantom units under our LTIP. In addition, we paid cash in lieu of issuing units with respect to approximately 104,000 phantom units. All the vesting requirements, other than continued employment, have been met with respect to an additional 473,000 phantom units that will vest in May 2004. We anticipate issuing approximately 181,000 common units after netting for taxes. We also anticipate paying the cash equivalent (in lieu of issuing units) with respect to approximately 202,000 phantom units. The LTIP charge is based on a unit price of $33.35 per unit. The actual expense associated with the May vesting (cash and non-cash) will depend upon the unit value at the time of vesting. An additional $2.0 million of expense is included in the second half of 2004 for the continuation of the LTIP. We currently anticipate 50% of this will be settled in cash and the remainder in units, resulting in the issuance of approximately 30,000 units. 
15.
Acquisitions. Although acquisitions constitute a key element of our growth strategy, these results and estimates include only one prospective acquisition, the Capline Acquisition, which is subject to a definitive purchase and sale agreement and is anticipated to close on or about March 1, 2004. No assumptions or forecasts for any other material acquisitions have been included. Based on the midpoint of our forecast annualized range of cash flow from operating activities for the Capline Acquisition ($17.0 million to $21.0 million), we expect it will increase cash flow from operating activities, net income and net income per limited partner unit by approximately $1.5 million, $0.8 million, $0.01 per limited partner unit, respectively for the first quarter and approximately $15.7 million, $8.3 million, $0.14 per limited partner unit, respectively for the full year of 2004. 
16.
Canadian Foreign Exchange Rate. An average Canadian dollar to U.S. dollar exchange rate of 1.35 to 1 has been utilized for both the first quarter and full year of 2004. 
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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 crude oil production located offshore California and transported on the All American Pipeline; 
•
declines in volumes shipped on the Basin Pipeline and our other pipelines by third party shippers; 
•
the availability of adequate third party production volumes in the areas in which we operate; 
•
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; 
•
the success of our risk management activities; 
•
the impact of crude oil price fluctuations; 
•
the availability (or lack thereof) of acquisition or combination opportunities and successful consummation thereof (including the Capline Acquisition); 
•
successful integration and future performance of acquired assets; 
•
continued creditworthiness of, and performance by, our counterparties; 
•
our levels of indebtedness and our ability to receive credit on satisfactory terms; 
•
successful third-party drilling efforts in areas in which we operate pipelines or gather crude oil; 
•
completion of announced oil sands projects; 
•
shortages or cost increases of power supplies, materials or labor; 
•
weather interference with business operations or project construction; 
•
the impact of current and future laws and governmental regulations; 
•
the currency exchange rate of the Canadian dollar; 
•
environmental liabilities that are not covered by an indemnity, insurance or existing reserves; 
•
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. 
8

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: February 24, 2004	
 	
By: Plains AAP, L. P., its general partner	

 	
By:	
/s/  PHIL KRAMER      
	
 	 	Name:	Phil Kramer	
 	 	Title:	Executive Vice President and Chief Financial Officer	
9

EXHIBIT INDEX 
Exhibit
Number
	 	Description
	
99.1	 	Press Release dated February 24, 2004	
# # # 

QuickLinks
Item 7. Financial Statements and Exhibits
Item 9 and 12. Regulation FD Disclosure; Results of Operations and Financial Condition
Operating and Financial Guidance
SIGNATURES
EXHIBIT INDEX

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Exhibit 99.1 
Contacts:	Phillip D. Kramer
Executive VP and CFO
713/646-4560 - 800/564-3036	 	A. Patrick Diamond
Manager, Special Projects
713/646-4487 - 800/564-3036	
FOR IMMEDIATE RELEASE 

Plains All American Pipeline, L.P. Reports
2003 Fourth Quarter and Annual Results 
        (Houston—February 24, 2004) Plains All American Pipeline, L.P. (NYSE: PAA) today reported operating and financial results for the fourth quarter and full year of 2003 in line with previously published guidance. Both periods were impacted by anticipated compensation charges, charges related to debt refinancings and other notable items that affected the comparability of results between reporting periods. Including the impact of these items, which aggregated approximately $22.4 million for the quarter, the Partnership reported a net loss of $0.2 million, or $0.03 per basic limited partner unit ($0.03 per diluted limited partner unit) for the fourth quarter. For the year, the Partnership reported net income of $59.4 million, or $1.01 per basic limited partner unit ($1.00 per diluted limited partner unit), including the impact of items affecting comparability totaling $31.7 million. The three notable items that affected the Partnership's results for the fourth quarter and full year of 2003 included: 
•
a compensation expense charge of $21.4 million in the fourth quarter and $28.8 million for the full year associated with the Partnership's long-term equity compensation plan. The majority of these amounts were accrued in 2003 as a result of management's assessment of the probable vesting in 2004 of phantom unit grants made over the last five years pursuant to the Partnership's long-term incentive plan ("LTIP"). Vesting of such equity compensation awards are conditioned upon achievement of long-term performance targets and termination of a five-year subordination period following the Partnership's initial public offering in November 1998. Approximately 40% of the awards are expected to be satisfied with the issuance of common units and the remaining 60% are expected to be withheld for required tax payments or paid in cash; 
•
a noncash loss on refinancing of debt of $3.1 million in the fourth quarter and $3.3 million for the full year as a result of the prepayment and refinancing of the Partnership's term debt and revolving credit facilities; and 
•
a noncash, mark-to-market gain of $2.1 million in the fourth quarter and $0.4 million for the full year due to the impact of Statement of Financial Accounting Standards ("SFAS") No. 133 "Accounting for Derivative Instruments and Hedging Activities". 

        The following table summarizes certain items that the Partnership believes affect the comparability of financial results between reporting periods: 
 	 	For the Three Months Ended December 31,
	 	For the Twelve Months Ended December 31,
	 	
 	 	2003
	 	2002
	 	2003
	 	2002
	 	
 	 	(Dollars in millions)	 	(Dollars in millions)	 	
LTIP charge	 	$	(21.4	)	$	—	 	$	(28.8	)	$	—	 	
Loss on refinancing of debt	 	 	(3.1	)	 	—	 	 	(3.3	)	 	—	 	
SFAS 133 noncash mark-to-market adjustment	 	 	2.1	 	 	2.3	 	 	0.4	 	 	0.3	 	
Noncash reserve for potential environmental obligations	 	 	—	 	 	(1.2	)	 	—	 	 	(1.2	)	
Write-off of deferred acquisition-related costs	 	 	—	 	 	(1.0	)	 	—	 	 	(1.0	)	
 	 		 		 		 		 	
Total	 	$	(22.4	)	$	0.1	 	$	(31.7	)	$	(1.9	)	
Per Basic Limited Partner Unit	 	$	(0.39	)	$	0.00	 	$	(0.59	)	$	(0.04	)	
Per Diluted Limited Partner Unit	 	$	(0.39	)	$	0.00	 	$	(0.58	)	$	(0.04	)	
        Collectively, these items affecting comparability reduced net income, net income per basic limited partner unit and net income per diluted limited partner unit for the fourth quarter by $22.4 million, $0.39 and $0.39, respectively, and for the full year of 2003 by $31.7 million, $0.59 and $0.58, respectively. Excluding these items affecting comparability, earnings before interest, taxes, depreciation and amortization ("EBITDA"), a non-GAAP financial measure, was $43.6 million for the fourth quarter of 2003 and $173.2 million for the full year of 2003. See the section of this release entitled "Non-GAAP Financial Measures" for information on required disclosures and reconciliations. 
        "By almost any measure, 2003 was a very productive and rewarding year for Plains All American and its stakeholders," said Greg L. Armstrong, Chairman and CEO of Plains All American. "We met or exceeded each of the goals established at the beginning of the year, despite absorbing unforeseen costs and time requirements associated with various corporate governance initiatives, homeland security mandates and other challenges. The Partnership was able to overcome these hurdles and entered 2004 positioned to continue its multi-year track record of improving its operating and financial results and growing its distribution to Unitholders. Looking forward, we are excited by our prospects for 2004 and beyond." 
        Armstrong noted that the Partnership would continue to optimize its existing asset base and pursue opportunities to consolidate and rationalize related aspects of the North American crude oil infrastructure. The Partnership's 2004 capital program includes several organic expansion projects that are being undertaken as a direct result of the Partnership's previous acquisition activities. The projects are designed to integrate the acquired assets into the Partnership's asset base, optimize regional crude oil flows and improve market alternatives for its producer customers. These projects include post-acquisition capital programs for the Red River and ArkLaTex pipeline systems, expansion of a segment of the Basin Pipeline System, construction of a 29-mile pipeline to connect the Iatan Gathering System to the Basin system and the Phase IV expansion of the Cushing Terminal. The Partnership's expansion capital program for 2004 approximates $51 million. The Partnership expects to complete the majority of these projects by year-end 2004. 

        The following table presents certain selected financial information by segment for the fourth quarter reporting periods: 
 	 	Pipeline
Operations
	 	Gathering,
Marketing,
Terminalling &
Storage
Operations
	
 	 	(Dollars in millions)	
Three Months Ended December 31, 2003(1)	 	 	 	 	 	 	
Revenues	 	$	169.5	 	$	3,390.8	
Purchases and related costs	 	 	124.2	 	 	3,342.6	
Operating expenses (excluding LTIP charge)	 	 	18.6	 	 	16.7	
LTIP charge—operations	 	 	1.0	 	 	3.3	
 	 		 		
Segment margin	 	 	25.7	 	 	28.2	
General and administrative expenses (excluding LTIP charge)(2)	 	 	4.6	 	 	7.9	
LTIP charge—general and administrative	 	 	7.0	 	 	10.1	
 	 		 		
Segment profit	 	$	14.1	 	$	10.2	
 	 		 		
Noncash SFAS 133 impact(3)	 	$	—	 	$	2.1	
 	 		 		
Maintenance capital	 	$	1.6	 	$	0.5	

Three Months Ended December 31, 2002(1)	

 	

 	
Revenues	 	$	152.2	 	$	2,367.2	
Purchases and related costs	 	 	114.4	 	 	2,323.6	
Operating expenses	 	 	14.2	 	 	17.3	
 	 		 		
Segment margin	 	 	23.6	 	 	26.3	
General and administrative expenses(2)	 	 	3.9	 	 	7.4	
 	 		 		
Segment profit	 	$	19.7	 	$	18.9	
 	 		 		
Noncash SFAS 133 impact(3)	 	$	—	 	$	2.3	
 	 		 		
Maintenance capital	 	$	0.6	 	$	1.3	

(1)
Revenues and purchases and related costs include inter-segment amounts. 
(2)
General and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments based on the business activities that existed at that time. The proportional allocations by segment require judgment by management and will continue to be based on the business activities that exist during each period. 
(3)
Amounts related to SFAS 133 are included in revenues, and impact segment margin and segment profit. 

        Excluding the LTIP charge, segment profit from pipeline operations was up 12% in the fourth quarter of 2003, when compared to the fourth quarter of 2002, while the segment profit from gathering, marketing, terminalling and storage operations, including the impact of SFAS 133 in both periods, was up 25%. However, excluding the impact of SFAS 133 in both periods, the gathering, marketing, terminalling and storage segment was up 30% in the fourth quarter of 2003, when compared to the fourth quarter of 2002. The relative increases primarily resulted from the impact of acquisitions completed in 2003, the contribution from our Phase III expansion of the Cushing Terminal, which was completed in January 2003, and the execution of our post-acquisition exploitation plans. 

        The following table presents certain selected financial information by segment for the full year reporting periods: 
 	 	Pipeline
Operations
	 	Gathering,
Marketing,
Terminalling &
Storage
Operations
	
 	 	(Dollars in millions)	
Twelve Months Ended December 31, 2003(1)	 	 	 	 	 	 	
Revenues	 	$	658.6	 	$	11,985.6	
Purchases and related costs	 	 	487.1	 	 	11,799.8	
Operating expenses (excluding LTIP charge)	 	 	60.9	 	 	73.3	
LTIP charge—operations	 	 	1.4	 	 	4.3	
 	 		 		
Segment margin	 	 	109.2	 	 	108.2	
General and administrative expenses (excluding LTIP charge)(2)	 	 	18.3	 	 	31.6	
LTIP charge—general and administrative	 	 	9.6	 	 	13.5	
 	 		 		
Segment profit	 	$	81.3	 	$	63.1	
 	 		 		
Noncash SFAS 133 impact(3)	 	$	—	 	$	0.4	
 	 		 		
Maintenance capital	 	$	6.4	 	$	1.2	

Twelve Months Ended December 31, 2002(1)	

 	

 	
Revenues	 	$	486.2	 	$	7,921.8	
Purchases and related costs	 	 	362.2	 	 	7,765.1	
Operating expenses	 	 	40.1	 	 	66.3	
 	 		 		
Segment margin	 	 	83.9	 	 	90.4	
General and administrative expenses(2)	 	 	13.2	 	 	31.5	
 	 		 		
Segment profit	 	$	70.7	 	$	58.9	
 	 		 		
Noncash SFAS 133 impact(3)	 	$	—	 	$	0.3	
 	 		 		
Maintenance capital	 	$	3.4	 	$	2.6	

(1)
Revenues and purchases and related costs include inter-segment amounts. 
(2)
General and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments based on the business activities that existed at that time. The proportional allocations by segment require judgment by management and will continue to be based on the business activities that exist during each period. 
(3)
Amounts related to SFAS 133 are included in revenues, and impact segment margin and segment profit. 
        The Partnership's basic weighted average units outstanding for the fourth quarter of 2003 totaled 55.7 million (56.3 million on a diluted basis) as compared to 49.6 million (49.6 million on a diluted basis) in last year's fourth quarter. The Partnership's basic weighted average units outstanding for the full year of 2003 totaled 52.7 million (53.4 million on a diluted basis) as compared to 45.5 million (45.5 million on a diluted basis) in 2002. At December 31, 2003, the Partnership had 58.3 million units outstanding. Including units issued in February in connection with the vesting of restricted units under the LTIP, the Partnership had approximately 58.5 million units outstanding as of February 23, 2004. 
        At December 31, 2003, the Partnership's long-term debt totaled $519 million and it's long-term debt-to-total capitalization ratio was approximately 41%. 
        On January 22, 2004, the Partnership declared a cash distribution of $0.5625 per unit on its outstanding limited partner units. The distribution was paid on February 13, 2004, to holders of record 

of such units at the close of business on February 3, 2004. The distribution represented a 4.7% increase over the February 2003 distribution. 
        The Partnership today furnished a current report on Form 8-K, which included material in this press release as well as financial and operational guidance for the first quarter and full year of 2004. A copy of the Form 8-K is available on the Partnership's website at www.paalp.com. 
Non-GAAP Financial Measures 
        In this release, our EBITDA disclosure is not presented in accordance with generally accepted accounting principles and is not intended to be used in lieu of GAAP presentations of results of operations or cash provided by operating activities. EBITDA is presented because management believes it provides additional information with respect to both the performance of our fundamental business activities as well as our ability to meet our future debt service, capital expenditures and working capital requirements. Management also believes that debt holders commonly use EBITDA to analyze Partnership performance. A reconciliation of EBITDA to net income and to cash flow from operating activities for the periods presented is included in the tables attached to this release. In addition, the Partnership maintains on its website (www.paalp.com) a reconciliation of all non-GAAP financial information, such as EBITDA, to the most comparable GAAP measures. To access the information, investors should click on the "Investor Relations" link on the Partnership's home page and then the "Non-GAAP Reconciliations" link on the Investor Relations page. 
Conference Call: 
        The Partnership will host a conference call to discuss the results and other forward-looking items on Tuesday, February 24, 2004. Specific items to be addressed in this call include: 
1.
A brief review of the Partnership's fourth quarter results; 
2.
An assessment of the Partnership's 2003 performance versus goals; 
3.
Fourth quarter crude oil market conditions, acquisition integration activities and activity update; 
3.
Capitalization and liquidity update and an update and review of financial and operating guidance for the first quarter and full year of 2004; and 
4.
Comments regarding the Partnership's outlook and 2004 goals. 

        The call will begin at 10:00 AM (Central). To participate in the call, please call 877-715-5321, or, for international callers, 973-582-2785 at approximately 9:55 AM (Central). No password or reservation number is required. 
Webcast Instructions: 
        To access the Internet webcast, please go to the Partnership's website at www.paalp.com, choose "Investor Relations", and then choose "Conference Calls". Following the live webcast, the call will be archived for a period of sixty (60) days on the Partnership's website. 
Telephonic Replay Instructions: 
        Call 877-519-4471 or international call 973-341-3080 and enter PIN # 4489409
        The replay will be available beginning Tuesday, February 24, 2004, at approximately 1:00 PM (Central) and continue until 11:59pm (Central) Monday, March 1, 2004. 
        Except for the historical information contained herein, the matters discussed in this news release are forward-looking statements that involve certain risks and uncertainties. These risks and uncertainties include, among other things, abrupt or severe production declines or production interruptions in outer continental shelf production located offshore California and transported on the 

All American Pipeline, declines in volumes shipped on the Basin Pipeline and our other pipelines by third party shippers, the availability of adequate supplies of and demand for crude oil in the areas in which we operate, the effects of competition, the success of our risk management activities, the impact of crude oil price fluctuations, the availability (or lack thereof) of acquisition opportunities on terms favorable to the Partnership, successful integration and future performance of assets acquired, continued credit worthiness of, and performance by, our counterparties, levels of indebtedness and ability to receive credit on satisfactory terms, successful third party drilling efforts in areas in which we operate pipelines or gather crude oil, regulatory changes, unanticipated shortages or cost increases in power supplies, materials and skilled labor, weather interference with business operations or project construction, the currency exchange rate of the Canadian dollar, environmental liabilities that are not covered by an indemnity or insurance, fluctuation in the debt and equity capital markets (including the price of our units at the time of vesting under our LTIP), and other factors and uncertainties inherent in the marketing, transportation, terminalling, gathering and storage of crude oil and liquefied petroleum gas ("LPG") discussed in the Partnership's filings with the Securities and Exchange Commission. 
        Plains All American Pipeline, L.P. is engaged in interstate and intrastate crude oil transportation and crude oil gathering, marketing, terminalling and storage as well as the gathering, marketing and storage of liquefied petroleum gas, primarily in Texas, California, Oklahoma and Louisiana and the Canadian Provinces of Alberta and Saskatchewan. The Partnership's common units are traded on the New York Stock Exchange under the symbol "PAA." The Partnership is headquartered in Houston, Texas. 
# # # 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES 

FINANCIAL SUMMARY 
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit data) (unaudited) 
 	 	Three Months Ended December 31,
	 	Twelve Months Ended December 31,
	 	
 	 	2003
	 	2002
	 	2003
	 	2002
	 	
REVENUES	 	$	3,545,075	 	$	2,509,464	 	$	12,589,849	 	$	8,384,223	 	

COSTS AND EXPENSES	

 	

 	

 	

 	
 	
Purchases and related costs	 	 	3,451,579	 	 	2,428,052	 	 	12,232,536	 	 	8,103,496	 	
Operating expenses (excluding LTIP charge)	 	 	35,267	 	 	31,482	 	 	134,177	 	 	106,436	 	
LTIP charge—operations	 	 	4,337	 	 	—	 	 	5,727	 	 	—	 	
General and administrative (excluding LTIP charge)	 	 	12,538	 	 	12,274	 	 	49,969	 	 	45,663	 	
LTIP charge—general & administrative	 	 	17,057	 	 	—	 	 	23,063	 	 	—	 	
Depreciation and amortization	 	 	12,657	 	 	10,943	 	 	46,821	 	 	34,068	 	
 	 		 		 		 		 	
Total costs and expenses	 	 	3,533,435	 	 	2,482,751	 	 	12,492,293	 	 	8,289,663	 	
 	 		 		 		 		 	
Gain on sale of assets	 	 	40	 	 	—	 	 	648	 	 	—	 	
 	 		 		 		 		 	
OPERATING INCOME	 	 	11,680	 	 	26,713	 	 	98,204	 	 	94,560	 	

OTHER INCOME/(EXPENSE)	

 	

 	

 	

 	
 	
Interest expense	 	 	(8,746	)	 	(8,882	)	 	(35,226	)	 	(29,057	)	
Interest income and other, net	 	 	(3,106	)	 	(88	)	 	(3,530	)	 	(211	)	
 	 		 		 		 		 	
NET INCOME (LOSS)	 	$	(172	)	$	17,743	 	$	59,448	 	$	65,292	 	

BASIC NET INCOME (LOSS) PER LIMITED PARTNER	
 	
$	
(0.03	
)	
$	
0.33	
 	
$	
1.01	
 	
$	
1.34	

DILUTED NET INCOME (LOSS) PER LIMITED PARTNER UNIT	
 	
$	
(0.03	
)	
$	
0.33	
 	
$	
1.00	
 	
$	
1.34	

BASIC WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING	

55,736	

49,578	

52,743	

45,546	

DILUTED WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING	

56,349	

49,578	

53,400	

45,546	

OPERATING DATA (in thousands)(1)(2)	

 	

 	

 	

 	

Average Daily Volumes (barrels)	

 	

 	

 	

 	
 	
 	Pipeline activities:	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Tariff activities	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	All American	 	 	58	 	 	65	 	 	59	 	 	65	 	
 	 	 	Basin	 	 	262	 	 	211	 	 	263	 	 	93	 	
 	 	 	Other domestic	 	 	341	 	 	307	 	 	299	 	 	219	 	
 	 	 	Canada	 	 	238	 	 	192	 	 	203	 	 	187	 	
 	 	Pipeline margin activities	 	 	74	 	 	77	 	 	78	 	 	73	 	
 	 		 		 		 		 	
 	 	Total	 	 	973	 	 	852	 	 	902	 	 	637	 	
 	 		 		 		 		 	
 	Crude oil lease gathering	 	 	459	 	 	424	 	 	437	 	 	410	 	
 	Crude oil bulk purchases	 	 	109	 	 	67	 	 	90	 	 	68	 	
 	 		 		 		 		 	
 	 	Total crude oil	 	 	568	 	 	491	 	 	527	 	 	478	 	
 	 		 		 		 		 	
 	LPG sales	 	 	63	 	 	63	 	 	48	 	 	46	 	
 	 		 		 		 		 	
Cushing terminal throughput	 	 	243	 	 	180	 	 	208	 	 	110	 	

(1)
Volumes associated with acquisitions represent weighted average daily amounts for the number of days we actually owned the assets over the total days in the period. 
(2)
2002 volume information has been adjusted for consistency of comparison with 2003 presentation. 

FINANCIAL DATA RECONCILIATIONS
(in thousands)(unaudited) 
 	 	Three Months Ended December 31,
	 	Twelve Months Ended December 31,
	 	
 	 	2003
	 	2002
	 	2003
	 	2002
	 	
Earnings before interest, taxes, depreciation and amortization ("EBITDA")	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income reconciliation	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Income (loss)	 	$	(172	)	$	17,743	 	$	59,448	 	$	65,292	 	
Interest expense	 	 	8,746	 	 	8,882	 	 	35,226	 	 	29,057	 	
 	 		 		 		 		 	
Earnings before interest and taxes ("EBIT")	 	 	8,574	 	 	26,625	 	 	94,674	 	 	94,349	 	
Depreciation and amortization	 	 	12,657	 	 	10,943	 	 	46,821	 	 	34,068	 	
 	 		 		 		 		 	
EBITDA	 	$	21,231	 	$	37,568	 	$	141,495	 	$	128,417	 	
 	 		 		 		 		 	
Cash flow from operating activities reconciliation	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net cash provided by (used in) operating activities	 	$	(127,362	)	$	46,507	 	$	68,518	 	$	173,894	 	
Net change in assets and liabilities, net of acquisitions	 	 	156,095	 	 	(20,048	)	 	62,272	 	 	(74,631	)	
Other items to reconcile from cash flows from operating activities:	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Allowance for doubtful accounts	 	 	(260	)	 	(146	)	 	(360	)	 	(146	)	
 	Gain on sale of assets	 	 	40	 	 	 	 	 	648	 	 	—	 	
 	Change in derivative fair value	 	 	2,093	 	 	2,373	 	 	363	 	 	243	 	
 	Loss on refinancing of debt	 	 	(3,072	)	 	—	 	 	(3,272	)	 	—	 	
 	Net cash paid for terminated interest rate hedging instruments	 	 	6,152	 	 	 	 	 	6,152	 	 	—	 	
 	Non-cash portion of LTIP charge	 	 	(21,201	)	 	—	 	 	(28,052	)	 	—	 	
Interest expense	 	 	8,746	 	 	8,882	 	 	35,226	 	 	29,057	 	
 	 		 		 		 		 	
EBITDA	 	 	21,231	 	 	37,568	 	 	141,495	 	 	128,417	 	
Depreciation and amortization	 	 	(12,657	)	 	(10,943	)	 	(46,821	)	 	(34,068	)	
 	 		 		 		 		 	
EBIT	 	$	8,574	 	$	26,625	 	$	94,674	 	$	94,349	 	

Funds flow from operations (FFO)	

 	

 	

 	

 	
 	
Net Income (loss)	 	$	(172	)	$	17,743	 	$	59,448	 	$	65,292	 	
Depreciation and amortization	 	 	12,657	 	 	10,943	 	 	46,821	 	 	34,068	 	
 	 		 		 		 		 	
FFO	 	 	12,485	 	 	28,686	 	 	106,269	 	 	99,360	 	
Maintenance capital expenditures	 	 	(2,142	)	 	(1,892	)	 	(7,596	)	 	(5,939	)	
 	 		 		 		 		 	
FFO after maintenance capital expenditures	 	$	10,343	 	$	26,794	 	$	98,673	 	$	93,421	 	

Items impacting comparability	

 	

 	

 	

 	
 	
LTIP charge	 	$	(21,394	)	$	—	 	$	(28,790	)	$	—	 	
Loss on refinancing of debt	 	 	(3,072	)	 	—	 	 	(3,272	)	 	—	 	
SFAS 133 noncash mark-to-market adjustment	 	 	2,093	 	 	2,373	 	 	363	 	 	243	 	
Noncash reserve for potential environmental obligations	 	 	—	 	 	(1,200	)	 	—	 	 	(1,200	)	
Write-off of deferred acquisition-related costs	 	 	—	 	 	(1,000	)	 	—	 	 	(1,000	)	
 	 		 		 		 		 	
Items impacting comparability	 	$	(22,373	)	$	173	 	$	(31,699	)	$	(1,957	)	

CONDENSED CONSOLIDATED BALANCE SHEET DATA
(in thousands) (unaudited) 
 	 	December 31,
2003
	 	December 31,
2002
	
ASSETS	 	 	 	 	 	 	
Current assets	 	$	732,974	 	$	602,935	
Property and equipment, net	 	 	1,151,039	 	 	952,753	
Pipeline linefill	 	 	122,653	 	 	62,558	
Other long-term assets, net	 	 	88,965	 	 	48,329	
 	 		 		
 	 	$	2,095,631	 	$	1,666,575	
 	 		 		
LIABILITIES AND PARTNERS' CAPITAL	 	 	 	 	 	 	
Current liabilities	 	$	801,919	 	$	637,249	
Long-term debt under credit facilities	 	 	70,000	 	 	310,126	
Senior notes, net of unamortized discount	 	 	448,991	 	 	199,610	
Other long-term liabilities and deferred credits	 	 	27,994	 	 	7,980	
 	 		 		
 	 	 	1,348,904	 	 	1,154,965	
Partners' capital	 	 	746,727	 	 	511,610	
 	 		 		
 	 	$	2,095,631	 	$	1,666,575	

QuickLinks
Exhibit 99.1
Plains All American Pipeline, L.P. Reports 2003 Fourth Quarter and Annual Results
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY