0001104659-05-034576.txt : 20050728 0001104659-05-034576.hdr.sgml : 20050728 20050728085543 ACCESSION NUMBER: 0001104659-05-034576 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 20050728 ITEM INFORMATION: Results of Operations and Financial Condition ITEM INFORMATION: Regulation FD Disclosure ITEM INFORMATION: Financial Statements and Exhibits FILED AS OF DATE: 20050728 DATE AS OF CHANGE: 20050728 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PLAINS ALL AMERICAN PIPELINE LP CENTRAL INDEX KEY: 0001070423 STANDARD INDUSTRIAL CLASSIFICATION: PIPE LINES (NO NATURAL GAS) [4610] IRS NUMBER: 760582150 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-14569 FILM NUMBER: 05979141 BUSINESS ADDRESS: STREET 1: 333 CLAY STREET STREET 2: SUITE 1600 CITY: HOUSTON STATE: TX ZIP: 77002 BUSINESS PHONE: 7136544100 MAIL ADDRESS: STREET 1: 333 CLAY STREET STREET 2: SUITE 1600 CITY: HOUSTON STATE: TX ZIP: 77002 8-K 1 a05-12477_18k.htm 8-K

UNITED STATES
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)—July 28, 2005

Plains All American Pipeline, L.P.

(Exact name of registrant as specified in its charter)

DELAWARE	1-14569	76-0582150
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

333 Clay Street, Suite 1600, Houston, Texas 77002
(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code 713-646-4100

(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

Item 2.02 and Item 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 second quarter 2005 results. We are furnishing the press release, attached as Exhibit 99.1, pursuant to Item 2.02 and Item 7.01 of Form 8-K. Pursuant to Item 7.01 we are updating certain aspects of our previous guidance for financial performance for the third quarter, fourth quarter and full year of calendar 2005. In accordance with General Instruction B.2. of Form 8-K, the information presented herein under Item 2.02 and 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.

Update of Third Quarter, Fourth Quarter and Full Year 2005 Guidance

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 to EBIT and EBITDA. In Note 11 below, we reconcile EBITDA and EBIT to net income for the guidance periods presented. However, it is impractical to reconcile EBIT and EBITDA to cash flows from operating activities for forecasted periods. 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, Net Income and Net Income per Limited Partner Unit of our long-term incentive program, revaluations of foreign currency and, to the extent known, gains and losses related to SFAS 133 (primarily non-cash, mark-to-market adjustments).

The following guidance for the three months ending September 30, and December 31, 2005 and the twelve months ending December 31, 2005 is based on assumptions and estimates that we believe are reasonable given our assessment of historical trends, business cycles and other information reasonably available. However, our assumptions and future performance are both subject to a wide range of business risks and uncertainties so no assurance can be provided that actual performance will fall within the guidance ranges. Please refer to the information under the caption “Forward-Looking Statements and Associated Risks” below. These risks and uncertainties, as well as other unforeseeable 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 July 27, 2005. We undertake no obligation to publicly update or revise any forward-looking statements.

Plains All American Pipeline, L.P.
Operating and Financial Guidance
(in millions, except per unit data)

	Actual				Guidance(1)
	Six Months				Three Months Ended												Twelve Months Ended
	Ended				September 30, 2005						December 31, 2005						December 31, 2005
	June 30, 2005				Low			High			Low			High			Low			High
Pipeline
Net revenues		$	188.2		$	93.5		$	95.5		$	94.0		$	97.5		$	375.7		$	381.2
Field operating costs		(72.1		)	(36.7		)	(35.5		)	(36.0		)	(35.0		)	(144.8		)	(142.6		)
General and administrative expenses		(24.6		)	(14.0		)	(13.5		)	(13.9		)	(13.4		)	(52.5		)	(51.5		)
		91.5			42.8			46.5			44.1			49.1			178.4			187.1
Gathering, Marketing, Terminalling & Storage
Net revenues		153.1			89.0			94.0			67.4			75.9			309.5			323.0
Field operating costs		(59.5		)	(31.0		)	(30.2		)	(30.6		)	(29.6		)	(121.1		)	(119.3		)
General and administrative expenses		(23.6		)	(13.0		)	(12.5		)	(13.1		)	(12.6		)	(49.7		)	(48.7		)
		70.0			45.0			51.3			23.7			33.7			138.7			155.0
Segment Profit		161.5			87.8			97.8			67.8			82.8			317.1			342.1
Depreciation and amortization expense		(38.6		)	(20.3		)	(19.8		)	(20.8		)	(20.3		)	(79.7		)	(78.7		)
Interest expense		(28.8		)	(16.8		)	(16.2		)	(17.0		)	(16.6		)	(62.6		)	(61.6		)
Other Income (Expense)		1.0			—			—			—			—			1.0			1.0
Net Income		$	95.1		$	50.7		$	61.8		$	30.0		$	45.9		$	175.8		$	202.8
Net Income to Limited Partners (see Note 9)		$	86.9		$	46.0		$	56.9		$	25.7		$	41.3		$	158.6		$	185.0
Basic:
Weighted Average Units Outstanding		67.7			67.9			67.9			67.9			67.9			67.8			67.8
Net Income Per Limited Partner Unit (see Note 9)		$	1.27		$	0.67		$	0.75		$	0.38		$	0.61		$	2.34		$	2.69
Diluted:
Weighted Average Units Outstanding		68.7			69.5			69.5			69.5			69.5			69.1			69.1
Net Income Per Limited Partner Unit (see Note 9)		$	1.26		$	0.66		$	0.74		$	0.37		$	0.59		$	2.30		$	2.64
EBIT		$	123.9		$	67.5		$	78.0		$	47.0		$	62.5		$	238.4		$	264.4
EBITDA		$	162.5		$	87.8		$	97.8		$	67.8		$	82.8		$	318.1		$	343.1

*Selected Items Impacting Comparability*
LTIP charge		$	(10.2	)	$	(7.2	)	$	(7.2	)	$	(7.2	)	$	(7.2	)	$	(24.5	)	$	(24.5	)
SFAS 133 non-cash mark-to-market adjustment		(26.3		)	—			—			—			—			(26.3		)	(26.3		)
FX gain (loss)		0.2			—			—			—			—			0.2			0.2
		$	(36.3	)	$	(7.2	)	$	(7.2	)	$	(7.2	)	$	(7.2	)	$	(50.6	)	$	(50.6	)


*Excluding Selected Items Impacting Comparability*
Adjusted EBITDA		$	198.7		$	95.0		$	105.0		$	75.0		$	90.0		$	368.7		$	393.7
Adjusted Net Income		$	131.3		$	57.9		$	69.0		$	37.2		$	53.1		$	226.4		$	253.4
Adjusted Basic Net Income per Limited Partner Unit		$	1.81		$	0.78		$	0.94		$	0.48		$	0.71		$	3.07		$	3.46
Adjusted Diluted Net Income per Limited Partner Unit		$	1.78		$	0.76		$	0.92		$	0.47		$	0.70		$	3.01		$	3.40

(1) The projected average foreign exchange rate is $1.25 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		Liquefied petroleum gas and other petroleum products
FX		Foreign currency exchange
GMT&S		Gathering, Marketing, Terminalling & Storage

2. Pipeline Operations. Pipeline volume estimates are based on historical trends, anticipated future operating performance and completion of organic growth projects. Volumes are influenced by temporary market-driven storage and withdrawal of oil, end-user refinery maintenance schedules, field declines and other external factors beyond our control. Actual segment profit could vary materially depending on the level of volumes transported. The following table summarizes our pipeline volumes and breaks out the major systems that are significant either in total volumes transported or in contribution to total net revenue.

	Calendar 2005
	Actual			Guidance
	Six Months											Twelve Months
	Ended			Three Months Ended								Ended
	June 30			September 30				December 31				December 31
Average Daily Volumes (000’s Bbl/d)
All American		52			51				51				51
Basin		280			285				270				279
Capline		152			165				140				153
Cushing to Broome(4)		54			85				80				68
West Texas / New Mexico area systems(1)		406			380				380				393
Other		565			739				729				651
		1,509			1,705				1,650				1,595
Canada(2)		258			270				270				264
		1,767			1,975				1,920				1,859
Segment Profit ($/Bbl)
As Reported/Estimated		$	0.286		$	0.246	(3)		$	0.264	(3)		$	0.269	(3)
Excluding Selected Items Impacting Comparability		$	0.304		$	0.268	(3)		$	0.286	(3)		$	0.289	(3)

(1) The aggregate of 10 systems in the West Texas / New Mexico area.

(2) The aggregate of 8 systems.

(3) Mid-point of estimate.

(4) System became operational on March 1, 2005.

Segment profit is forecasted using the volume assumptions in the table above priced at tariff rates currently received, with adjustments where appropriate for estimated escalation in certain rates as allowed by contractual terms, less estimated field operating costs and G&A. Field operating costs do not include depreciation. Effective July 1, 2005, common carrier tariffs are permitted to escalate approximately 3.6% in accordance with FERC regulated guidelines. However, in certain instances, contractual arrangements or market forces may not allow us to realize the benefit of these permitted

escalations. To illustrate the impact volume changes may have on segment profit, the following table provides a volume sensitivity analysis of three systems representing approximately 30% of total pipeline net revenues.

Volume Sensitivity Analysis
			% of			Change
	Change		System			in Annualized
System	in Volume		Total			Segment Profit
	(Bbls/d)					(in millions)
All American		5,000		10	%		$	3.2
Basin		20,000		7	%		$	1.8
Capline		10,000		7	%		$	1.5

3. Gathering, Marketing, Terminalling and Storage Operations. The degree of volatility in the crude oil market influences the level of profit in the GMT&S segment. Our guidance for the second half of the year assumes that the favorable market conditions in the oil markets will subside over the remainder of the year.

LPG volumes are influenced by seasonal demands with higher volumes sold in the winter months, primarily for heating, and decreasing during the summer months.

	Calendar 2005
	Actual			Guidance
	Six Months											Twelve Months
	Ended			Three Months Ended								Ended
	June 30			September 30				December 31				December 31
Average Daily Volumes (000’s Bbl/d)
Crude Oil Lease Gathered		625			630				635				629
LPG		55			40				75				56
		680			670				710				685
Segment Profit ($/Bbl)
As Reported/Estimated		$	0.568		$	0.781	(1)		$	0.439	(1)		$	0.587	(1)
Excluding Selected Items Impacting Comparability		$	0.817		$	0.832	(1)		$	0.488	(1)		$	0.734	(1)

(1) Mid-point of estimate.

Segment profit is forecasted using the volume assumptions stated above and estimates of unit margins, field operating costs, G&A and carrying costs for contango inventory based on current and anticipated market conditions. Field operating costs do not include depreciation. 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 mid-point projected segment profit per barrel for the third quarter of 2005, a 15,000 Bbl/d variance in lease gathering volumes would impact segment profit by approximately $4.2 million on an annualized basis. A $0.01 variance in the aggregate average per-barrel margin would impact segment profit by approximately $2.5 million on an annualized basis.

4. Depreciation & Amortization. Depreciation and amortization is forecast based on our existing depreciable assets and forecasted 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).

5. Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133). The guidance presented above does not include assumptions or

projections with respect to potential gains or losses related to derivatives accounted for under SFAS 133, as there is no accurate way to forecast these potential gains or losses. The potential gains or losses related to these derivatives (primarily non-cash, mark-to-market adjustments) could cause actual net income to differ materially from our projections.

6. 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. Capital expenditures for expansion projects are forecast to be approximately $190 million during calendar 2005. Following are some of the more notable projects to be undertaken in 2005 and the estimated expenditures for the year.

	Calendar 2005
	(In Millions)
· St. James, Louisiana storage facility		$	21
· Trenton pipeline expansion		$	34
· Capital projects associated with the Link acquisition		$	18
· NW Alberta fractionator		$	16
· Cushing Phase V expansion		$	13
· Kerrobert Tank expansion		$	9
· Shell South Louisiana Asset Acquisition		$	8

During the six months ended June 30, 2005, approximately $73 million of the forecasted $190 million of expansion capital was incurred in accordance with the project commitments.

Capital expenditures for maintenance projects are forecast to be approximately $19 million during 2005, of which approximately $8 million was incurred in the first six months.

7. Capital Structure. The guidance is based on our capital structure as of June 30, 2005.

8. Interest Expense. Debt balances are projected based on estimated cash flows, current distribution rates, capital expenditures for maintenance and expansion projects, expected timing of collections and payments, and forecast levels of inventory and other working capital sources and uses.

Calendar 2005 interest expense is expected to be between $62.6 million and $61.6 million, assuming an average long-term debt balance of approximately $1.0 billion and an all-in average rate of approximately 6.3%. 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. While interest on floating rate debt is based on a forward one-year LIBOR index curve of approximately 4.1%, over 90% of our projected average long-term debt balance has an average fixed interest rate of 6.0%. 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). Approximately 70% of the non-cash interest expense amounts will be completely amortized by the fourth quarter of 2006. The remainder will be amortized over the next eleven years.

Interest expense does not include interest on borrowings for contango inventory. We treat these costs as carrying costs of the crude and reflect it as part of the purchase price of the crude.

Long-term debt at December 31, 2005 is projected to be approximately $1.02 billion.

9. Net Income per Unit. Basic net income per limited partner unit is calculated by dividing net income allocated to limited partners by the basic weighted average units outstanding during the period. Under Emerging Issues Task Force Issue 03-06: Participating Securities and the Two-Class Method under FASB Statement No. 128 (“EITF 03-06”), when the Partnership’s aggregate net income exceeds the aggregate distribution made during such period, earnings per limited partner unit are calculated as if all of the earnings for the period were distributed, regardless of the pro forma nature of the allocation and whether those earnings would actually be distributed during a particular period from an economic or practical perspective. Although EITF 03-06 does not impact overall net income or other financial results of the Partnership, for periods in which aggregate net income exceeds the aggregate distributions for such period, earnings per limited partner unit will be reduced. The following table reconciles net income to limited partners both before and after EITF 03-06.

	Guidance (in millions)
	Three Months Ended								Three Months Ended								Twelve Months Ended
	September 30, 2005								December 31, 2005								December 31, 2005
	Low				High				Low				High				Low				High
Net Income		$	50.7			$	61.8			$	30.0			$	45.9			$	175.8			$	202.8
Less:
General partners incentive distribution paid		(3.8		)		(3.8		)		(3.8		)		(3.8		)		(14.0		)		(14.0		)
		46.9				58.0				26.2				42.1				161.8				188.8
General partner 2% ownership		(0.9		)		(1.1		)		(0.5		)		(0.8		)		(3.2		)		(3.8		)
Net income available to limited partners		46.0				56.9				25.7				41.3				158.6				185.0
Pro forma additional general partner's incentive distribution		(0.4		)		(5.7		)		-				-				-				(2.8		)
Numerator for basic and diluted earnings per limited partner unit
Net Income available for limited partners under EITF 03-06		$	45.6			$	51.2			$	25.7			$	41.3			$	158.6			$	182.2
Denominator:
Denominator for basic earnings per limited partner unit-weighted average number of limited partner units		67.9				67.9				67.9				67.9				67.8				67.8
Effect of dilutive securities:
Weighted average 2005 LTIP units		1.6				1.6				1.6				1.6				1.3				1.3
Denominator for diluted earnings per limited partner unit-weighted average number of limited partner units		69.5				69.5				69.5				69.5				69.1				69.1
Basic net income per limited partner unit		$	0.67			$	0.75			$	0.38			$	0.61			$	2.34			$	2.69
Diluted net income per limited partner unit		$	0.66			$	0.74			$	0.37			$	0.59			$	2.30			$	2.64

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. Accordingly, when the aggregate distribution is greater than net income, for each $0.05 per unit annual increase in the distribution rate up to $2.70 per unit, net income available for limited partners decreases approximately $1.1 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 $2.60 per unit, our general partner’s distribution is forecast to be approximately $18.7 million annually, of

which $15.1 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.

10. Long-term Incentive Plans. The majority of phantom unit grants outstanding under our 1998 and 2005 Long-Term Incentive Plans contain vesting criteria that are based on a combination of performance benchmarks and service period. The phantom units under the 2005 plan generally vest on the later of 2 years, 4 years or 5 years, or achievement of annualized distribution levels of $2.60, $2.80 and $3.00 per unit, respectively, and the majority of the phantom units have a final service period vesting in 2011. Accordingly, guidance includes (i) for phantom units tied to the $2.60 and $2.80 performance levels, an accrual over the corresponding service period, as it has been deemed probable that the $2.80 performance level will be reached, and (ii) for the phantom units that vest when the $3.00 performance threshold is achieved but have a final service period vesting in 2011, a pro rata accrual associated with a six-year service period. For 2005, the guidance includes approximately $24.5 million of principally non-cash expense associated with these phantom units. The actual amount of LTIP expense amortization in any given year will be directly influenced by fluctuations in our unit price and the amount of amortization in the early years and will also be increased if a determination is made that achievement of any of the remaining performance thresholds is probable.

11. Reconciliation of EBITDA and EBIT to Net Income. The following table reconciles the guidance ranges for EBIT and EBITDA to net income.

	Guidance (in millions)
	Three Months Ended						Three Months Ended						Twelve Months Ended
	September 30, 2005						December 31, 2005						December 31, 2005
	Low			High			Low			High			Low			High
Reconciliation to Net Income
EBITDA		$	87.8		$	97.8		$	67.8		$	82.8		$	318.1		$343.1
Depreciation and amortization		20.3			19.8			20.8			20.3			79.7			78.7
EBIT		67.5			78.0			47.0			62.5			238.4			264.4
Interest expense		16.8			16.2			17.0			16.6			62.6			61.6
Net Income		$	50.7		$	61.8		$30.0			$45.9			$	175.8		$202.8

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 our 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 or events 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 and trade counter-parties;

· declines in volumes shipped on the Basin Pipeline, Capline 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, rulings 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 plan;

· general economic, market or business conditions; and

· other factors and uncertainties inherent in the marketing, transportation, terminalling, gathering and storage of crude oil and liquified petroleum gas.

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.

EX-99.1 2 a05-12477_1ex99d1.htm EX-99.1

Exhibit 99.1

Contacts:	Phillip D. Kramer	A. Patrick Diamond
	Executive VP and CFO	Director, Strategic Planning
	713/646-4560—800/564-3036	713/646-4487—800/564-3036

FOR IMMEDIATE RELEASE

Plains All American Pipeline, L.P. Reports
Record Financial Results for Second Quarter 2005—
Net Income Up 75%; Net Income Per Unit Up 37%;
EBITDA Up 56%

(Houston—July 28, 2005) Plains All American Pipeline, L.P. (NYSE: PAA) today reported net income of $62.3 million, or $0.74 per diluted limited partner unit, for the second quarter of 2005. These financial results represent an increase of 75% and 37%, respectively, over net income of $35.7 million, or $0.54 per diluted limited partner unit, for the second quarter of 2004. For the first six months of 2005, the Partnership reported net income of $95.1 million, or $1.26 per diluted limited partner unit, an increase of 50% and 29%, respectively, over net income of $63.6 million, or $0.98 per diluted limited partner unit, for the first six months of 2004.

As reported, earnings before interest, taxes, depreciation and amortization (“EBITDA”) for the second quarter of 2005 were $96.0 million, an increase of 56% as compared with EBITDA of $61.6 million for the second quarter of 2004. EBITDA for the first six months of 2005 was $162.5 million, an increase of 45% as compared with EBITDA of $112.2 million for the first six months of 2004. (See the section of this release entitled “Non-GAAP Financial Measures” and the attached tables for discussion of EBITDA and other non-GAAP financial measures, and reconciliations of such measures to the comparable GAAP measures.)

“In the second quarter, Plains All American delivered by a wide margin the strongest financial and operating performance in the history of the Partnership,” said Greg L. Armstrong, Chairman and CEO of the Partnership. “The primary drivers of the strong performance were solid pipeline volumes and continued favorable market conditions in our gathering, marketing, terminalling and storage segment, as well as the realization of additional operating and commercial synergies from assets and businesses that we have acquired in the last 18 months. These results highlight the proven ability of our asset base and business model to generate growing levels of sustainable cash flow while periodically capturing discrete profit opportunities derived from favorable crude oil market conditions.” Armstrong noted that based on its outlook for future performance, the Partnership is well positioned to generate sustainable cash flows that will support future distribution growth.

Reported results include the impact of various items that affect comparability between reporting periods. Adjusting for selected items impacting comparability, the Partnership’s second quarter 2005 adjusted net income, adjusted net income per limited partner unit and adjusted EBITDA were $82.1 million, $1.11 per diluted unit, and $115.8 million, respectively. Similarly, the Partnership’s second quarter 2004 adjusted net income, adjusted net income per limited partner unit and adjusted EBITDA were $41.6 million, $0.63 per diluted unit, and $67.6 million, respectively. On a comparable basis, second quarter 2005 adjusted net income, adjusted net income per diluted limited partner unit and adjusted EBITDA increased 97%, 76% and 71%, respectively, over second quarter 2004.

The Partnership’s adjusted net income, adjusted net income per limited partner unit and adjusted EBITDA for the first six months of 2005 were $131.3 million, $1.78 per diluted unit, and $198.7 million, respectively. Similarly, the Partnership’s adjusted net income, adjusted net income per limited partner unit and adjusted EBITDA for the first six months of 2004 were $69.8 million, $1.08 per diluted unit, and $118.4 million, respectively. On a comparable basis, adjusted net income, adjusted net income per diluted

limited partner unit and adjusted EBITDA for the first six months of 2005 increased 88%, 65% and 68%, respectively, over the first six months of 2004.

The following table summarizes selected items that the Partnership believes impact the comparability of financial results between reporting periods:

	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
	(Dollars in millions, except per unit data)
Long-Term Incentive Plan (“LTIP”) charge	$	(7.9	)	—			$	(10.2	)	(4.2		)
Cumulative effect of change in accounting principle	—			—			—			(3.1		)
Gain/(Loss) on foreign currency revaluation	1.1			1.0			0.2			0.6
Pro forma additional GP distribution under EITF 03-06⁽¹⁾	—			—			—			—
SFAS 133 noncash mark-to-market adjustment	(12.9		)	(6.9		)	(26.3		)	0.6
Total	$	(19.8	)	$	(6.0	)	$	(36.3	)	$	(6.2	)
Per Basic Limited Partner Unit⁽¹⁾	$	(0.37	)	$	(0.09	)	$	(0.54	)	$	(0.10	)
Per Diluted Limited Partner Unit⁽¹⁾	$	(0.37	)	$	(0.09	)	$	(0.52	)	$	(0.10	)

⁽¹⁾ In the second quarter 2005, the Partnership’s net income exceeded the cash distribution paid during the quarter, which required the application of Emerging Issues Task Force Issue No. 03-06: “Participating Securities and the Two-Class Method under FASB Statement No. 128” (“EITF 03-06”). This accounting literature dictates that earnings per unit must be calculated as if all of the Partnership’s earnings for the period were distributed. This theoretical calculation does not impact the Partnership’s aggregate net income or EBITDA, but does reduce the Partnership’s net income per limited partner unit. The application of EITF 03-06 negatively impacted net income to limited partners by $6.2 million and $0.6 million, and negatively impacted basic and diluted earnings per limited partner unit by $0.09 and $0.01 for the second quarter and first half of 2005, respectively.

The following table presents certain selected financial information by segment for the second quarter reporting periods:

					Gathering,
					Marketing,
					Terminalling
	Pipeline				& Storage
	Operations				Operations(4)
	(Dollars in millions)
Three Months Ended June 30, 2005
Revenues⁽¹⁾		$	260.5			$	6,931.0
Purchases⁽¹⁾		(167.8		)		(6,834.7		)
Field operating costs (excluding LTIP charge)		(37.7		)		(29.1		)
LTIP charge—operations		(0.3		)		(0.7		)
Segment general and administrative expenses (excluding LTIP charge)⁽²⁾		(9.2		)		(9.9		)
LTIP charge—general and administrative⁽²⁾		(4.1		)		(2.9		)
Segment profit		$	41.4			$	53.7
Noncash SFAS 133 impact⁽³⁾		$	—			$	(12.9	)
Maintenance capital		$	2.5			$	1.5
Three Months Ended June 30, 2004
Revenues⁽¹⁾		$	222.8			$	4,941.3
Purchases⁽¹⁾		(132.9		)		(4,891.3		)
Field operating costs (excluding LTIP charge)		(31.9		)		(27.2		)
LTIP charge—operations		—				—
Segment general and administrative expenses (excluding LTIP charge)⁽²⁾		(10.3		)		(9.3		)
LTIP charge—general and administrative⁽²⁾		—				—
Segment profit		$	47.7			$	13.5
Noncash SFAS 133 impact⁽³⁾		$	—			$	(6.9	)
Maintenance capital		$	0.6			$	0.7

⁽¹⁾ Include intersegment amounts.

⁽²⁾ Segment general and administrative (G&A) 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 profit. The SFAS 133 mark-to-market adjustment is primarily based upon crude oil prices at the end of the period and is related to the non-effective portion of our cash flow hedges, as well as certain derivative contracts that do not qualify under SFAS 133 as cash flow hedges. The net loss related to these derivative instruments is principally offset by physical positions in future periods.

⁽⁴⁾ Gains/losses on foreign currency revaluation are included in the Gathering, Marketing, Terminalling & Storage segment.

Excluding selected items impacting comparability in both periods, segment profit from pipeline operations in the second quarter of 2005 was $45.8 million versus $47.7 million for the second quarter of 2004 on average daily pipeline volumes of 1.8 million barrels per day versus 1.7 million barrels per day. Current period results reflect the adverse impact of a less favorable volume mix and increased environmental reserves. Additionally, second quarter pipeline segment profit was reduced by approximately $5.0 million due to voluntary market rate adjustments made by the Partnership to tariffs on certain pipelines formerly owned by Link Energy. As a result of these lower tariffs on barrels shipped by PAA in connection with its gathering and marketing activities, segment profit from gathering, marketing, terminalling and storage was increased by a comparable amount. Excluding selected items impacting

comparability in both periods, segment profit from gathering, marketing, terminalling and storage operations was up approximately 255% over the corresponding period in 2004 as a result of lower tariffs, continued favorable market conditions in our gathering, marketing, terminalling and storage segment and commercial synergies from assets and businesses that we have acquired in the last 18 months.

The following table presents certain selected financial information by segment for the first six-month reporting periods:

					Gathering,
					Marketing,
					Terminalling
	Pipeline				& Storage
	Operations				Operations(4)
	(Dollars in millions)
Six Months Ended June 30, 2005
Revenues⁽¹⁾		$	507.7			$	13,357.2
Purchases⁽¹⁾		(319.5		)		(13,204.1		)
Field operating costs (excluding LTIP charge)		(71.7		)		(58.6		)
LTIP charge—operations		(0.4		)		(0.9		)
Segment general and administrative expenses (excluding LTIP charge)⁽²⁾		(19.4		)		(20.0		)
LTIP charge—general and administrative⁽²⁾		(5.2		)		(3.6		)
Segment profit		$	91.5			$	70.0
Noncash SFAS 133 impact⁽³⁾		$	—			$	(26.3	)
Maintenance capital		$	5.3			$	2.7
Six Months Ended June 30, 2004
Revenues⁽¹⁾		$	412.1			$	8,572.6
Purchases⁽¹⁾		(269.6		)		(8,464.2		)
Field operating costs (excluding LTIP charge)		(51.2		)		(45.7		)
LTIP charge—operations		(0.1		)		(0.4		)
Segment general and administrative expenses (excluding LTIP charge)⁽²⁾		(16.3		)		(18.7		)
LTIP charge—general and administrative⁽²⁾		(1.7		)		(2.0		)
Segment profit		$	73.2			$	41.6
Noncash SFAS 133 impact⁽³⁾		$	—			$	0.5
Maintenance capital		$	2.1			$	1.0

⁽¹⁾ Include intersegment amounts.

⁽⁴⁾ Gains/losses on foreign currency revaluation are included in the Gathering, Marketing, Terminalling & Storage segment.

The Partnership’s basic weighted average units outstanding for the second quarter of 2005 totaled 67.9 million (69.3 million diluted) as compared to 61.6 million (61.6 million diluted) in last year’s second quarter. At June 30, 2005, the Partnership had approximately 67.9 million units outstanding, long-term debt of $953.2 million and a long-term debt-to-total capitalization ratio of approximately 49%.

On July 21, 2005, the Partnership declared a cash distribution of $0.65 per unit ($2.60 per unit on an annualized basis) on its outstanding limited partner units. The distribution will be paid on August 12, 2005, to holders of record of such units at the close of business on August 2, 2005. The distribution represents an increase of approximately 12.6% over the August 2004 distribution and approximately 2.0% over the May 2005 distribution. This represents the 12^th distribution increase for the Partnership in the last 18 quarters.

The Partnership today furnished a current report on Form 8-K, which included material in this press release and financial and operational guidance for the third and fourth quarters and full year 2005. 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, the Partnership’s 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 we believe 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. We also believe that debt holders commonly use EBITDA to analyze Partnership performance. In addition, we present selected items that impact the comparability of our operating results as additional information that may be helpful to your understanding of our financial results. We consider an understanding of these selected items impacting comparability to be material to its evaluation of our operating results and prospects. Although we present selected items that we consider in evaluating our performance, you should also be aware that the items presented do not represent all items that affect comparability between the periods presented. Variations in our operating results are also caused by changes in volumes, prices, exchange rates, mechanical interruptions, acquisitions and numerous other factors. These types of variations are not separately identified in this release, but will be discussed in management’s discussion and analysis of operating results in our Quarterly Report on Form 10-Q.

A reconciliation of EBITDA to net income and 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, that it reconciles 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 Reconciliation” 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 Thursday, July 28, 2005. Specific items to be addressed in this call include:

1. A brief review of the Partnership’s second quarter performance;

2. A status report on expansion and organic growth projects;

3. A discussion of capitalization and liquidity;

4. A review of financial and operating guidance for the third quarter and full year of 2005; and

5. Comments regarding the Partnership’s outlook for the future.

The call will begin at 10:00 AM (Central). To participate in the call, please call 800-473-6123, or, for international callers, 973-582-2706 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 # 6248081

The replay will be available beginning Thursday, July 28, 2005, at approximately 1:00 PM (Central) and continue until 11:59pm (Central) Monday, August 1, 2005.

Except for the historical information contained herein, the matters discussed in this news release are forward-looking statements that involve certain risks and uncertainties that could cause actual results to differ materially from results anticipated in the forward looking statements. 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 our pipeline systems; 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 or events 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 and trade counterparties; declines in volumes shipped on the Basin Pipeline, Capline Pipeline and our other pipelines by the Partnership or 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 credit worthiness of, and performance by, our counterparties; the impact of crude oil price fluctuations; the impact of current and future laws, rulings and government regulations; shortages or cost increases in power supplies, materials and labor; weather interference with business operations or project construction; the currency exchange rate of the Canadian dollar; fluctuation in the debt and equity capital markets (including the price of our units at the time of vesting under our LTIP); general economic, market or business conditions; 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 marketing and storage of liquefied petroleum gas and other petroleum products, in the United States and Canada. 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 (unaudited) (in thousands, except per unit data) (continued)

CONSOLIDATED STATEMENTS OF OPERATIONS

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
REVENUES	$	7,160,707		$	5,131,735		$	13,799,203		$	8,936,379
COSTS AND EXPENSES
Crude oil and LPG purchases and related costs	6,971,690			4,991,867			13,457,850			8,685,372
Field operating costs (excluding LTIP charge)	66,846			59,035			130,322			96,851
LTIP charge—operations	975			—			1,319			567
General and administrative expenses (excluding LTIP charge)	19,198			19,603			39,414			35,081
LTIP charge—general & administrative	6,951			—			8,846			3,661
Depreciation and amortization	19,448			15,998			38,566			29,118
Total costs and expenses	7,085,108			5,086,503			13,676,317			8,850,650
Gain on sale of assets	445			84			445			84
OPERATING INCOME	76,044			45,316			123,331			85,813
OTHER INCOME/(EXPENSE)
Interest expense	(14,253		)	(9,967		)	(28,811		)	(19,499		)
Interest and other income (expense), net	491			328			570			369
Income before cumulative effect of change in accounting principle	62,282			35,677			95,090			66,683
Cumulative effect of change in accounting principle	—			—			—			(3,130		)
NET INCOME	$	62,282		$	35,677		$	95,090		$	63,553
NET INCOME—LIMITED PARTNERS	$	57,602		$	33,247		$	86,867		$	58,954
NET INCOME—GENERAL PARTNER	$	4,680		$	2,430		$	8,223		$	4,599
BASIC NET INCOME PER LIMITED PARTNER UNIT
Income before cumulative effect of change in accounting principle	$	0.76		$	0.54		$	1.27		$	1.03
Cumulative effect of change in accounting principle	—			—			—			(0.05		)
Basic net income per limited partner unit	$	0.76		$	0.54		$	1.27		$	0.98
DILUTED NET INCOME PER LIMITED PARTNER UNIT
Income before cumulative effect of change in accounting principle	$	0.74		$	0.54		$	1.26		$	1.03
Cumulative effect of change in accounting principle	—			—			—			(0.05		)
Diluted net income per limited partner unit	$	0.74		$	0.54		$	1.26		$	0.98
BASIC WEIGHTED AVERAGE UNITS OUTSTANDING	67,893			61,556			67,706			59,985
DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING	69,274			61,556			68,719			59,985
OPERATING DATA (in thousands)(1)
Average Daily Volumes (barrels)
Pipeline activities:
Tariff activities
All American	50			59			52			57
Basin	283			271			280			273
Capline	143			169			152			112
West Texas/New Mexico Area Systems(2)	410			374			406			291
Canada	248			259			258			250
Other	603			463			548			302
Pipeline margin activities	67			74			71			73
Total	1,804			1,669			1,767			1,358
Crude oil lease gathering	628			641			625			550
LPG sales	26			21			55			40

⁽¹⁾ Volumes associated with acquisitions represent total volumes transported for the number of days we actually owned the assets divided by the number of days in the period.

⁽²⁾ The aggregate of ten systems in the West Texas/New Mexico area.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited) (in thousands, except per unit data) (continued)

CONDENSED CONSOLIDATED BALANCE SHEET DATA

	June 30,		December 31,
	2005		2004
ASSETS
Current assets	$	2,029,515		$	1,101,202
Property and equipment, net	1,794,051			1,727,622
Pipeline linefill in owned assets	165,957			168,352
Inventory in third party assets	61,351			59,279
Other long-term assets, net	83,664			103,956
Total Assets	$	4,134,538		$	3,160,411
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	2,151,042		$	1,113,717
Long-term debt under credit facilities and other	6,421			151,753
Senior notes, net of unamortized discount	946,733			797,271
Other long-term liabilities and deferred credits	30,365			27,466
Total Liabilities	3,134,561			2,090,207
Partners’ capital	999,977			1,070,204
Total Liabilities and Partners’ Capital	$	4,134,538		$	3,160,411

COMPUTATION OF BASIC AND DILUTED EARNINGS PER LIMITED PARTNER UNIT

	Three months ended June 30,						Six months ended June 30,
	2005			2004			2005			2004
Net income	$	62,282		$	35,677		$	95,090		$	63,553
Less:
General partner’s incentive distribution paid	(3,504		)	(1,752		)	(6,450		)	(3,396		)
Subtotal	58,778			33,925			88,640			60,157
General partner 2% ownership	(1,176		)	(679		)	(1,773		)	(1,203		)
Net income available to limited partners	57,602			33,247			86,867			58,954
Pro forma additional general partner’s incentive distribution⁽¹⁾	(6,174		)	—			(560		)	—
Numerator for basic and diluted earnings per limited partner unit
Net Income available for limited partners under EITF 03-06	$	51,428		$	33,247		$	86,307		$	58,954
Denominator:
Denominator for basic earnings per limited partner unit—weighted average number of limited partner units	67,893			61,556			67,706			59,985
Effect of dilutive securities:
Weighted average 2005 LTIP units	1,381			—			1,013			—
Denominator for diluted earnings per limited partner unit—weighted average number of limited partner units	69,274			61,556			68,719			59,985
Basic net income per limited partner unit⁽¹⁾	$	0.76		$	0.54		$	1.27		$	0.98
Diluted net income per limited partner unit⁽¹⁾	$	0.74		$	0.54		$	1.26		$	0.98

⁽¹⁾ Reflects pro forma full distribution of earnings under Emerging Issues Task Force Issue No. 03-06 (“EITF 03-06”). The application of EITF 03-06 negatively impacted basic and diluted earnings per limited partner unit by approximately $0.09 and $0.01 for the second quarter and first half of 2005, respectively.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited) (in thousands, except per unit data) (continued)

FINANCIAL DATA RECONCILIATIONS

	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
Earnings before interest, taxes, depreciation and amortization ("EBITDA")
Net income reconciliation
EBITDA	$	95,983		$	61,642		$	162,467		$	112,170
Depreciation and amortization	(19,448		)	(15,998		)	(38,566		)	(29,118		)
Earnings before interest and taxes ("EBIT")	76,535			45,644			123,901			83,052
Interest expense	(14,253		)	(9,967		)	(28,811		)	(19,499		)
Net Income	$	62,282		$	35,677		$	95,090		$	63,553
Cash flow from operating activities reconciliation
EBITDA	$	95,983		$	61,642		$	162,467		$	112,170
Interest expense	(14,253		)	(9,967		)	(28,811		)	(19,499		)
Net change in assets and liabilities, net of acquisitions	(282,196		)	(43,863		)	(622,547		)	47,496
Other items to reconcile to cash flows from operating activities:
Cumulative effect of change in accounting principle	—			—			—			3,130
Non-cash (gain)/loss on foreign currency revaluation	(1,462		)	(983		)	(918		)	(573		)
Net cash paid for terminated swaps	(865		)	—			(865		)	—
SFAS 133 noncash mark-to-market adjustment	12,921			6,943			26,327			(556		)
LTIP charge	7,926			—			10,165			4,228
Non-cash amortization of terminated interest rate hedging instruments	403			357			790			714
Net cash provided by (used in) operating activities	(181,543		)	14,129			(453,392		)	147,110
Funds flow from operations (FFO)
Net Income	$	62,282		$	35,677		$	95,090		$	63,553
Depreciation and amortization	19,448			15,998			38,566			29,118
Non-cash amortization of terminated interest rate hedging instruments	403			357			790			714
FFO	82,133			52,032			134,446			93,385
Maintenance capital expenditures	(4,065			(1,350			(8,039			(3,100
FFO after maintenance capital expenditures	$	78,068		$	50,682		$	126,407		$	90,285

FINANCIAL MEASURES EXCLUDING SELECTED ITEMS IMPACTING COMPARABILITY

	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
Selected items impacting comparability
Long-Term Incentive Plan (“LTIP”) charge	$	(7,926	)	$	—		$	(10,165	)	$	(4,228	)
Cumulative effect of change in accounting principle	—			—			—			(3,130		)
Gain/(Loss) on foreign currency revaluation	1,058			983			238			573
SFAS 133 noncash mark-to-market adjustment	(12,921		)	(6,943		)	(26,327		)	556
Pro forma additional GP distribution under EITF 03-06⁽¹⁾	—			—			—			—
Selected items impacting comparability	(19,789		)	(5,960		)	(36,254		)	(6,229		)
GP 2% portion of selected items impacting comparability	396			119			725			125
LP 98% portion of selected items impacting comparability	$	(19,393	)	$	(5,841	)	$	(35,529	)	$	(6,104	)
Impact to basic net income per limited partner unit⁽¹⁾	$	(0.37	)	$	(0.09	)	$	(0.54	)	$	(0.10	)
Impact to diluted net income per limited partner unit⁽¹⁾	$	(0.37	)	$	(0.09	)	$	(0.52	)	$	(0.10	)

⁽¹⁾ The application of EITF 03-06 negatively impacted basic and diluted earnings per limited partner unit by approximately $0.09 and $0.01 for the second quarter and first half of 2005, respectively.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited) (in thousands, except per unit data) (continued)

	Three Months Ended June 30,				Six Months Ended June 30,
	2005		2004		2005		2004
Net income and earnings per limited partner unit excluding selected items impacting comparability
Net Income	$	62,282	$	35,677	$	95,090	$	63,553
Selected items impacting comparability	19,789		5,960		36,254		6,229
Adjusted Net Income	$	82,071	$	41,637	$	131,344	$	69,782
Net Income available for limited partners under EITF 03-06	$	51,428	$	33,247	$	86,307	$	58,954
Limited partners 98% of selected items impacting comparability	19,393		5,841		35,529		6,104
Pro forma additional general partner distribution under EITF 03-06	6,174		—		560		—
Adjusted limited partners Net Income	$	76,995	$	39,088	$	122,396	$	65,058
Adjusted Basic Net Income per limited partner unit	$	1.13	$	0.63	$	1.81	$	1.08
Adjusted Diluted Net Income per limited partner unit	$	1.11	$	0.63	$	1.78	$	1.08
Basic weighted average units outstanding	67,893		61,556		67,706		59,985
Diluted weighted average units outstanding	69,274		61,556		68,719		59,985
EBITDA excluding selected items impacting comparability
EBITDA	$	95,983	$	61,642	$	162,467	$	112,170
Selected items impacting comparability	19,789		5,960		36,254		6,229
Adjusted EBITDA	$	115,772	$	67,602	$	198,721	$	118,399

	Three Months Ended					Six Months Ended
	June 30, 2005					June 30, 2005
	Pipeline		GMT&S			Pipeline		GMT&S
2005 Segment profit excluding selected items impacting comparability
Reported segment profit	$	41,351	$	53,701		$	91,438	$	70,017
Selected items impacting comparability of segment profit:
LTIP charge	4,402		3,524			5,701		4,464
(Gain)/Loss on foreign currency revaluation	—		(1,058		)	—		(238		)
SFAS 133 noncash mark-to-market adjustment	—		12,921			—		26,327
Segment profit excluding selected items impacting comparability	$	45,753	$	69,088		$	97,139	$	100,570

	Three Months Ended					Six Months Ended
	June 30, 2004					June 30, 2004
	Pipeline		GMT&S			Pipeline		GMT&S
2004 Segment profit excluding selected items impacting comparability
Reported segment profit	$	47,765	$	13,479		$	73,266	$	41,583
Selected items impacting comparability of segment profit:
LTIP charge	—		—			1,800		2,428
(Gain)/Loss on foreign currency revaluation	—		(983		)	—		(573		)
SFAS 133 noncash mark-to-market adjustment	—		6,943			—		(556		)
Segment profit excluding selected items impacting comparability	$	47,765	$	19,439		$	75,066	$	42,882

PLAINS ALL AMERICAN PIPELINE, L.P.

PLAINS AAP, L. P., its general partner

PLAINS ALL AMERICAN GP LLC,
its general partner

Date: July 28, 2005

/s/ PHIL KRAMER

Phil Kramer

Executive Vice President and Chief Financial Officer