~~Item 2.~~

~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

For the three months ended September 30, 2002, we reported net income of $16.3 million on total revenues of $2.3 billion compared to net income for the same period in 2001 of $15.2 million on total revenues of $2.2 billion. For the nine months ended September 30, 2002, we reported net income of $47.5 million on total revenues of $5.9 billion compared to net income for the same period in 2001 of $35.2 million of total revenues of $5.3 billion. When evaluating our results,trend analysis, we exclude the noncash, mark-to-market impact of Statement of Financial Accounting Standards ~~(“SFAS”~~("SFAS") No. 133, ~~“Accounting~~"Accounting for Derivative Instruments and Hedging ~~Activities,”~~Activities" resulting from (i) derivatives characterized as fair value hedges, (ii) derivatives that do not qualify for hedge accounting and (iii) the portion of cash flow hedges that is not highly effective in offsetting changes in cash flows of hedged items. The majority of these instruments serve as economic hedges ~~which~~that offset future physical positions not reflected in current results. Therefore, the SFAS 133 adjustment to net income is not a complete depiction of the economic substance of the transaction, as it only represents the derivative side of these transactions and does not take into account the offsetting physical position. In addition, the impact will vary from quarter to quarter based on market prices at the end of the ~~quarter.~~quarter, which are impossible for us to control or forecast.

Internally, we also consider in our analysis of operating results the impact of other items that we believe impact comparability between periods. To comply with the new regulations, we have omitted certain adjustments and reconciliations related to these items that have been presented in the past. We have also changed the format of certain tables presented in the discussion of our results of operations. In addition, certain reclassifications have been made to prior period amounts to conform to current period presentation. Where appropriate, we have noted that reported results include the effects of items we consider to impact comparability between periods. Overall, we believe the discussion and presentation provides an accurate and thorough analysis of our results of operations and financial condition. Additionally, we maintain on our website (www.paalp.com) a reconciliation of all non-GAAP financial information that we disclose to the most comparable GAAP measures. To access the information, investors should click on the "Non-GAAP Reconciliation" link on our home page.

Acquisitions

We completed several acquisitions during 2002 and 2003 that have impacted the results of operations and liquidity discussed herein. The cash portion of these acquisitions was funded from cash on hand and borrowings under our revolving credit facility. These acquisitions are discussed below and our ongoing acquisition activity is discussed further in "Liquidity and Capital Resources."

ArkLaTex Pipeline System

In September 2003, we made a deposit (approximately $17.0 million) to acquire the ArkLaTex Pipeline System from Link Energy (formerly EOTT Energy). The ArkLaTex Pipeline System consists of 240 miles of active crude oil gathering and mainline pipelines and connects to our Red River Pipeline System near Sabine, Texas. Also included in the transaction were 470,000 barrels of active crude oil storage capacity, the assignment of certain of Link Energy's crude oil supply contracts and

crude oil linefill and working inventory comprised of approximately 108,000 barrels. The total purchase price of approximately $21.3 million is comprised of a) $14.0 million of cash paid to Link Energy for the pipeline system, b) $2.9 million of cash paid to Link Energy to purchase crude oil linefill and working inventory, c) $3.6 million for transaction costs and estimated near-term capital costs and d) $0.8 million associated with the satisfaction of outstanding claims for accounts receivable and inventory balances. The near-term capital costs are associated with modifications required to enhance the capacity and validate and improve the integrity of the pipeline (which are expected to extend the life and improve the usefulness of the pipeline system) and enable us to operate it in conformity with our policies and specifications and are expected to be incurred within the next year. A portion of the purchase price has been allocated to the crude oil supply contracts; however, we are in the process of evaluating certain estimates made in the purchase price allocation. Thus, the allocation is subject to refinements. The acquisition closed and was effective on October 1, 2003, and will be included in our Pipeline Operations and our Gathering, Marketing, Terminalling and Storage segments, as appropriate.

Other Acquisitions

During the first half of 2003, we made six acquisitions from various entities for an aggregate purchase price of $85.7 million. These acquisitions included mainline crude oil pipelines, crude oil gathering lines, terminal and storage facilities, and an underground LPG storage facility. With the exception of $3.0 million that was allocated to investment in affiliates and $0.5 million that was allocated to goodwill and other intangible assets, the aggregate purchase price was allocated to property and equipment.

2002 Acquisitions

In August 2002, we acquired interests in approximately 2,000 miles of gathering and mainline crude oil pipelines and approximately 8.9 million barrels (net to our interest) of above-ground crude oil terminalling and storage assets in West Texas from Shell Pipeline Company LP and Equilon Enterprises LLC (the "Shell acquisition") for approximately $324 million. During the remainder of 2002, we made two acquisitions consisting of domestic gathering and marketing assets and an equity interest in a pipeline system for an aggregate purchase price of approximately $15.9 million.

Results of Operations

Our operations consist of two operating segments: (1) our Pipeline Operations, through which we engage in interstate and intrastate crude oil pipeline transportation and certain related margin activities; and (2) our Gathering, Marketing, Terminalling and Storage Operations, through which we engage in purchases and resales of crude oil and LPG at various points along the distribution chain and the operation of certain terminalling and storage assets. We evaluate segment performance based on (i) gross margin (excluding depreciation), (ii) gross profit (excluding depreciation), which is gross margin (excluding depreciation) less general and administrative expenses and (iii) on an annual basis, maintenance capital. Maintenance capital consists of capital expenditures required either to maintain the existing operating capacity of partially or fully depreciated assets or to extend their useful lives. Capital expenditures made to expand our existing capacity, whether through construction or acquisition, are not considered maintenance capital expenditures. Repair and maintenance expenditures associated with existing assets that do not extend the useful life or expand the operating capacity are charged to expense as incurred. Our current estimate of maintenance capital expenditures for 2003 is approximately $6.9 million. We monitor maintenance capital expenditures on an annual basis, since these capital projects can overlap quarters and may be impacted by weather, permitting and other uncontrollable delays. Accordingly, no period-by-period analysis is provided, except on an annual basis.

Three Months Ended September 30, 2003 and 2002

For the three months ended September 30, 2003, we reported net income of $11.9 million on total revenues of $3.1 billion compared to net income for the same period in 2002 of $16.3 million on total revenues of $2.3 billion. Included in the results of operations for the third quarter of 2003 and 2002 are certain items that impact the comparability between periods. These items include amounts related to accruals for the probable vesting of restricted units granted under our Long-Term Incentive Plan ("LTIP"). Under generally accepted accounting principles, we are required to recognize an expense when vesting of LTIP units becomes probable as determined by management at the end of the period (See Outlook, Vesting of Unit Grants Under Long-Term Incentive Plan). The compensation expense accrued relates to many years of service (thus we have included this amount in the following table of items impacting comparability), and culminates with both the early conversion of 25% of our subordinated units to common units and the related 90-day "continued employment" period. (see Note 7 to the Consolidated Financial Statements). In addition, and as discussed previously, the majority of instruments we are required to mark-to-market at the end of each quarterly period pursuant to SFAS 133 do serve as economic hedges that offset future physical positions not reflected in current results. Therefore, we believe mark-to-market adjustments to net income required under SFAS 133 do not provide a complete depiction of the economic substance of the transaction, as it only represents the derivative side of these transactions and does not take into account the offsetting physical position. In addition, the impact will vary from quarter to quarter based on market prices at the end of the quarter, which are impossible for us to control or forecast, and the SFAS 133 adjustments will reverse in future periods. Accordingly, when we internally evaluate our results for performance against expectations, public guidance and trend analysis, we exclude the non-cash, mark-to-market impact of SFAS 133. Thus, we present the impact of the SFAS 133 adjustments because we believe such amounts affect the comparison of the fundamental operating results for the periods presented. Our third quarter 2003 net income also includes a $0.2 million loss related to unamortized debt issue costs on early extinguishment of debt. This loss relates to a $34 million prepayment on our Senior secured term B loan which was made in anticipation of restructuring our existing secured credit facilities into unsecured credit facilities during the fourth quarter (See Note 4 to the Consolidated Financial Statements).

The items discussed above are included in net income in the period indicated and impact the comparability between periods as shown below:

		Three months ended September 30,
		2003			2002
		(in millions)
Items Impacting Comparability
	LTIP accrual	$	(7.4	)	$	—
	SFAS 133 Loss		(2.9	)		(0.4	)
	Loss on early extinguishment of debt		(0.2	)		—

	Total of items impacting comparability	$	(10.5	)	$	(0.4	)

The following table reflects our results of operations for each segment:

	Pipeline Operations			Gathering, Marketing, Terminalling & Storage
	(in millions)
Three Months Ended September 30, 2003⁽¹⁾
Revenues	$	164.4		$	2,905.5
Cost of sales and operations (excluding depreciation and LTIP accrual)		(133.9	)		(2,883.9	)
LTIP accrual—operations		(0.4	)		(1.0	)

Gross margin (excluding depreciation)		30.1			20.6
General and administrative expenses (excluding LTIP accrual)⁽²⁾		(4.6	)		(7.6	)
LTIP accrual—general and administrative		(2.6	)		(3.4	)

Gross profit (excluding depreciation)	$	22.9		$	9.6

Noncash SFAS 133 impact⁽³⁾	$	—		$	(2.9	)

Maintenance capital	$	1.0		$	0.3

Three Months Ended September 30, 2002⁽¹⁾
Revenues	$	130.4		$	2,220.7
Cost of sales and operations (excluding depreciation)		(107.4	)		(2,199.4	)

Gross margin (excluding depreciation)		23.0			21.3
General and administrative expenses⁽²⁾		(3.3	)		(8.2	)

Gross profit (excluding depreciation)	$	19.7		$	13.1

Noncash SFAS 133 impact⁽³⁾	$	—		$	(0.4	)

Maintenance capital	$	0.5		$	0.7

(1): Revenues and costs of sales and operations include intersegment amounts.
(2): General and administrative expenses (G&A) 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, gross margin (excluding depreciation), and gross profit (excluding depreciation).

Pipeline Operations

~~We own~~

As of September 30, 2003, we owned and ~~operate~~operated over ~~5,500~~6,200 miles of gathering and mainline crude oil pipelines located throughout the United States and Canada. Our activities from pipeline operations generally consist of transporting ~~third-party~~ volumes of crude oil for a fee and third-party leases of pipeline capacity (tariff activities), as well as barrel exchanges and buy/sell ~~arrangements. We also use our pipelines in~~arrangements (margin activities). In connection with certain of our merchant activities conducted under our gathering and marketing ~~business.~~business, we are also shippers on certain of our own pipelines. Tariffs and other fees on our pipeline systems vary by receipt point and delivery point. The gross margin (excluding depreciation) generated by our tariff and other fee-related activities depends on the volumes transported on the pipeline and the level of the tariff and other fees charged as well as the fixed and variable costs of operating the pipeline. Gross margin (excluding depreciation) from our pipeline capacity leases, barrel exchanges and buy/sell arrangements generally reflect a negotiated amount.

The following table sets forth our operating results from our Pipeline Operations segment for the periods indicated:

Three Months Ended September 30,

Nine Months Ended September 30,

2002

2001

2002

2001
Operating Results (in millions):

Revenues (including intersegment)    $ 130.4    $ 93.3    $ 334.1    $ 281.6




Gross margin    $ 23.0    $ 16.1    $ 60.3    $ 48.3
General & administrative expenses    3.2    2.9    9.3    8.3




Gross profit    $ 19.8    $ 13.2    $ 51.0    $ 40.0




Average Daily Volumes (thousands of barrels per day) (1):

Tariff activities
All American    68    68    65    68
Basin    157    —      53    —
Other domestic    256    139    186    148
Canada (2)    201    191    186    118
Margin activities    71    53    72    58




Total    753    451    562    392

				Three months ended September 30,
				2003			2002
Operating Results (in millions)⁽¹⁾
	Tariff activities revenues			$	40.4		$	31.5
	Margin activities revenues				124.0			98.9

	Total pipeline operations revenues				164.4			130.4
	Cost of sales and operations (excluding depreciation and LTIP accrual)				(133.9	)		(107.4	)
	LTIP accrual—operations				(0.4	)		—

	Gross Margin (excluding depreciation)				30.1			23.0
	General and administrative expenses (excluding LTIP accrual)⁽²⁾				(4.6	)		(3.3	)
	LTIP accrual—general and administrative				(2.6	)		—

	Gross Profit (excluding depreciation)			$	22.9		$	19.7

	Maintenance capital			$	1.0		$	0.5

Average Daily Volumes (thousands of barrels per day)⁽³⁾
	Tariff activities
		All American			59			68
		Basin			301			157
		Other domestic			328			260
		Canada			210			201

	Total tariff activities				898			686
	Margin activities				77			71

			Total		975			757

~~(1)~~

~~Total volumes transported on assets acquired during the period have been divided by the total number of days in the period to get a daily average.~~

~~(2)~~

~~2001 volume information is adjusted for consistency of comparison with 2002 presentation.~~

~~Pipeline Operations~~
(1)
Revenues and cost of sales and operations include intersegment amounts.
(2)
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)
Volumes associated with acquisitions represent weighted average daily amounts for the ~~Three Months Ended~~number of days we actually owned the assets over the total days in the period.

Total average daily volumes transported were approximately 975,000 barrels per day and 757,000 barrels per day for the three months ended September 30, 2003 and 2002, respectively. As discussed above, we have completed a number of acquisitions during 2003 and ~~2001~~2002 that have impacted the

results of operations herein. The following table reflects our total average daily volumes from our tariff activities by year of acquisition for comparison purposes:

		Three months ended September 30,
		2003	2002
		(thousands of barrels per day)
Tariff activities⁽¹⁾
	2003 acquisitions	108	—
	2002 acquisitions	375	282
	All other pipeline systems	415	404

	Total tariff activities average daily volumes	898	686

(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.

Average daily volumes onfrom our ~~pipelines during the third quarter of this year~~tariff activities were approximately ~~753,000~~898,000 barrels per day compared to ~~451,000~~approximately 686,000 barrels per day for the prior year ~~quarter, which was an increase of approximately 302,000 barrels per day.~~quarter. Approximately ~~298,000~~201,000 barrels per day of the increase in the ~~third~~current year quarter is due to volumes transported on the pipelines acquired in 2003 and 2002, including an increase of ~~2002 resulted from the acquisition of various businesses during 2002 and late 2001, including~~ approximately ~~266,000~~94,000 barrels per day ~~related to~~on the ~~businesses~~assets acquired in the Shell ~~acquisition.~~

acquisition because of their inclusion for the entire period in 2003 compared to 2 months in 2002. Volumes on all other pipeline systems increased by approximately 11,000 barrels per day to approximately 415,000 barrels per day. The increase is primarily related to a 9,000 barrel per day increase in volumes from our Canadian pipelines and a 13,000 barrel per day increase in our West Texas Gathering System volumes, offset by a decrease of 9,000 barrels per day in our All American tariff volumes attributable to a decline in California outer continental shelf ("OCS") production. The increase in our Canadian volumes primarily resulted from the completion of capital expansion projects that allowed for additional volumes on certain of our Canadian pipelines, coupled with the impact of the completion of a refinery turnaround. Our West Texas Gathering System has benefited from the shutdown of the Rancho pipeline. In addition, during the third quarter of 2003, we also transported additional barrels as a result of refinery problems in West Texas that temporarily diverted crude oil from other systems.

Total revenues from our pipeline operations were approximately ~~$130.4~~$164.4 million and ~~$93.3~~$130.4 million for the three months ended September 30, 2003 and 2002, ~~and 2001,~~ respectively. ~~Excluding the~~The increase in revenues ~~of $11.1 million from businesses acquired during 2002 and late 2001, revenues from~~was primarily related to our pipeline operations would have been approximately $119.3 million for the three months ended September 30, 2002. That is an increase of approximately $26.0 million over the comparable 2001 revenues. Of this increase,margin activities, which increased by approximately $25.1 million ~~relates~~in the third quarter of 2003. This increase was related to higher volumes on our ~~merchant activities~~buy/sell arrangements in the current period, coupled with higher average prices on our margin activity on our San Joaquin Valley gathering ~~system. This increase was related~~system in the 2003 period as compared to ~~both increased volumes and higher average prices on our buy/sell arrangements in~~ the 2002 period. However, this business is a margin business and although revenues and cost of sales are impacted by the absolute level of crude oil prices, there is a limited impact on gross margin.

Revenues from our tariff activities increased approximately 28% or $8.9 million. The following table reflects our revenues from our tariff activities by year of acquisition from their date of acquisition for comparison purposes:

		Three months ended September 30,
		2003		2002
		(in millions)
Tariff activities revenues⁽¹⁾
	2003 acquisitions	$	4.1	$	—
	2002 acquisitions		14.8		10.4
	All other pipeline systems		21.5		21.1

	Total tariff activities	$	40.4	$	31.5

~~Gross margin~~

(1): Revenues include intersegment amounts.

Total revenues from our tariff activities were approximately $40.4 million and $31.5 million for the three months ended September 30, 2003 and 2002, respectively. The increase in the third quarter of 2003 is predominately related to the inclusion of $18.9 million of revenues from the businesses acquired in 2003 and 2002. Revenues from pipeline ~~operations~~systems acquired in 2002 have increased to $14.8 million from $10.4 million primarily the result of the inclusion of only two months' contribution in 2002 from the assets acquired in the Shell acquisition. Revenues from all other pipeline systems increased approximately ~~$23.0~~$0.4 million to $21.5 million. This increase resulted principally from our Canadian operations. Canadian revenues increased approximately $1.1 million in the 2003 period primarily due to expanded capacity, higher tariffs and a $0.9 million favorable exchange rate impact. The favorable exchange rate impact has resulted from a decrease in the Canadian to U.S. dollar exchange rate to an average rate of 1.38 for the three months ended September 30, 2003, from an average rate of 1.56 for the three months ended September 30, 2002. Higher volumes on the West Texas Gathering System also contributed to the increase in tariff revenues from all other systems. These increases were partially offset by lower revenues from the All American System, on which we receive the highest per barrel tariffs among our pipeline systems.

As a result of these factors, our pipeline operations gross margin (excluding depreciation) increased 31% to approximately $30.1 million for the quarter ended September 30, ~~2002,~~2003, from ~~$16.1 million for the prior year quarter, an increase of $6.9 million primarily related to the acquisition of various businesses during 2002 and late 2001.~~

General and administrative expense (“G&A”) related to pipeline operations was $3.2 million for the quarter ended September 30, 2002, compared to $2.9 million for the third quarter of 2001. The increase in 2002 is primarily due to expenses associated with our Canadian acquisitions.

~~Pipeline Operations for the Nine Months Ended September 30, 2002 and 2001~~

Average daily volumes on our pipelines during the nine months ended September 30, 2002, were approximately 562,000 barrels per day compared to an average of 392,000 barrels per day for the prior year period, which was an increase of approximately 170,000 barrels per day. Approximately 119,000 barrels per day of the increase resulted from the acquisition of various businesses in 2002 and late 2001, including an average of approximately 89,000 barrels per day related to the businesses acquired in the Shell acquisition. The remainder of the increase was primarily related to the inclusion of the average daily volumes from the pipeline assets included in the Canadian acquisitions for all of the 2002 period compared to only six months during the 2001 period.

Total revenues from our pipeline operations were approximately $334.1 million and $281.6 million for the nine months ended September 30, 2002 and 2001, respectively. Excluding revenues of approximately $12.7 million from various businesses acquired during 2002 and late 2001, revenues from our pipeline operations would have been approximately $321.4 million for the nine months ended September 30, 2002. This reflects an increase of approximately $39.8 million over the comparable 2001 revenues. Of this increase, approximately $33.3 million relates to our merchant activities on our SJV gathering system. The increase was related to both increased volumes and higher average prices on our buy/sell arrangements in the 2002 period. However, this business is a margin business and although revenues and cost of sales are impacted by the absolute level of crude oil prices, there is a limited impact on gross margin. The remainder of the increase in revenues is primarily related to the inclusion of the results of operations from the pipeline assets included in the Canadian acquisitions for all of the 2002 period compared to only six months during the 2001 period.

~~Gross margin from pipeline operations increased to approximately $60.3 million for the nine months ended September 30, 2002, from $48.3~~$23.0 million for the prior year period, an increase of ~~$12~~approximately $7.1 million. ~~The~~Such results incorporate an increase ~~primarily~~in operating expenses to $15.0 million in the 2003 period from $12.9 million in the 2002. This increase includes $0.4 million related to the ~~acquisition~~accrual made for the probable vesting of ~~various businesses during 2002 and late 2001 and the inclusion of the~~

~~results of operations~~unit grants under our LTIP. The remaining increase is predominately related to our continued growth, primarily from acquisitions, coupled with higher utility costs. In addition, gross margin (excluding depreciation) includes a $0.6 million favorable impact resulting from the ~~pipeline assets included~~decrease in the average Canadian ~~acquisitions~~dollar to U.S. dollar exchange rate for ~~all~~the 2003 period as compared to the 2002 period.

General and administrative expenses increased approximately $3.9 million between comparable periods, primarily as a result of a $2.6 million accrual related to the probable vesting of unit grants under our LTIP. Additionally, the percentage of indirect costs allocated to the pipeline operations segment has increased in the 2003 period as our pipeline operations have grown. Including the impact of the ~~2002 period~~items discussed above, gross profit (excluding depreciation) was approximately $22.9 million in the third quarter of 2003, an increase of 16% as compared to ~~only six months during~~ the ~~2001 period.~~

~~G&A expense related to pipeline operations was $9.3~~$19.7 million reported for the ~~nine months~~quarter ended September 30, ~~2002,~~2002. Gross profit (excluding depreciation) includes a $0.5 million favorable impact resulting from the decrease in the average Canadian-dollar to U.S.-dollar exchange rate for the 2003 period as compared to ~~$8.3 million for~~ the ~~first nine months of 2001. The increase in~~ 2002 ~~is primarily due to expenses associated with our Canadian acquisitions which were acquired in April and July of 2001.~~

period.

Gathering, Marketing, Terminalling and Storage Operations

Our revenues from gathering and marketing activities reflect the sale of gathered and bulk-purchased ~~barrels~~crude oil and liquefied petroleum gas ("LPG") plus the sale of additional barrels exchanged through buy/sell arrangements entered into to enhance the margins of the gathered and bulk-purchased ~~crude oil.~~volumes. Gross margin from our gathering and marketing activities is dependent on our ability to sell crude oil and LPG at a price in excess of our aggregate cost. These operations are margin businesses and are not directly affected by the absolute level of ~~crude oil~~ prices, but are affected by overall levels of supply and demand for crude oil and LPG and fluctuations in market-related indices. Accordingly, an increase or decrease in revenues is not necessarily an indication of segment performance.

We own and operate approximately ~~21.3~~23.2 million barrels of above-ground crude oil terminalling and storage facilities, including a crude oil terminalling and storage facility at Cushing, Oklahoma. Cushing, which we refer to as the Cushing Interchange, is one of the largest crude oil market ~~hub~~hubs in the United States and the designated delivery point for New York Mercantile Exchange, or NYMEX, crude oil futures contracts. Terminals are facilities where crude oil is transferred to or from storage or a transportation system, such as a pipeline, to another transportation system, such as trucks or another pipeline. The operation of these facilities is called ~~“terminalling.” Gross~~"terminalling." Approximately 11.0 million barrels of our 23.2 million barrels of tankage is used primarily in our Gathering, Marketing, Terminalling and Storage Operations and the balance is used in our Pipeline Operations segment. On a stand alone basis, gross margin from terminalling and storage activities is dependent on the throughput of volumes, the volume of crude oil stored and the level of fees generated from our terminalling and storage services. ~~We also~~Our terminalling and storage activities are integrated with our gathering and marketing activities and the level of tankage that we allocate for our arbitrage activities (and therefore not available for lease to third parties) varies throughout crude oil price cycles. This integration enables us to use our storage tanks in an effort to ~~counter cyclically~~counter-cyclically balance and hedge our gathering and marketing ~~operations~~activities.

Crude oil prices have historically been very volatile and cyclical. Over the last 13 years, the NYMEX benchmark price has ranged from as high as $40.00 per barrel to as low as $10.00 per barrel. Our business strategy recognizes this volatility and the inherent inefficiencies such conditions create. Accordingly, we have deliberately configured our assets and integrated our activities in this segment in an effort to provide a counter-cyclical balance between our gathering and marketing activities and our terminalling and storage activities, and execute different hedging strategies to stabilize and enhance margins and reduce the negative impact of crude oil market volatility.

The volatility in the market place continued as during this quarter the NYMEX benchmark price of crude oil ranged from as high as $32.85 per barrel to as low as $26.65 per barrel. This volatility, in conjunction with our hedging strategies, enhanced the returns of our gathering and marketing activities. Beginning in September 2003, the steep backwardation that existed in the crude oil markets for most of the first eight months of the year subsided. Market conditions during the third quarter of 2002 were less favorable as the crude oil market alternated between periods of weak contango and strong backwardation.

As a result of completing our Phase III expansion at our Cushing facility, total tankage dedicated to our Gathering, Marketing, Terminalling and Storage Operations was approximately 1.0 million barrels greater in the third quarter of 2003 relative to the third quarter of 2002. A portion of such tankage was employed in hedging activities related to our gathering and marketing activities in the third quarter of 2003.

The following table sets forth our operating results from our Gathering, Marketing, Terminalling and Storage ~~operations~~Operations segment for the periods indicated:

Three Months Ended September 30,

Nine Months Ended September 30,

2002

2001

2002

2001
Operating Results (in millions):

Revenues    $ 2,220.7    $ 2,102.5    $ 5,554.6    $ 5,029.4




Gross margin    $ 21.3    $ 23.5    $ 64.1    $ 60.5
General & administrative expenses    8.3    7.4    24.1    20.3




Gross profit    $ 13.0    $ 16.1    $ 40.0    $ 40.2




Average Daily Volumes (thousands of barrels per day) (1)(2):

Lease gathering    408    391    406    334
Bulk purchases    85    55    74    39




Total    493    446    480    373




Terminal throughput    123    97    92    103




Storage leased to third parties, monthly average volumes    811    2,672    1,323    2,337

			Three months ended September 30,
			2003			2002
Operating Results (in millions)⁽¹⁾
	Revenues		$	2,905.5		$	2,220.7
	Cost of sales and operations (excluding depreciation and LTIP accrual)			(2,883.9	)		(2,199.4	)
	LTIP accrual—operations			(1.0	)		—

	Gross Margin (excluding depreciation)			20.6			21.3
	General and administrative expenses (excluding LTIP accrual)⁽²⁾			(7.6	)		(8.2	)
	LTIP accrual—general and administrative			(3.4	)		—

	Gross Profit (excluding depreciation)		$	9.6		$	13.1

	Noncash SFAS 133 impact⁽³⁾		$	(2.9	)	$	(0.4	)

	Maintenance capital		$	0.3		$	0.7

Average Daily Volumes (thousands of barrels per day except as otherwise noted)⁽⁴⁾
	Crude oil lease gathering			429			408
	Crude oil bulk purchases			96			72

		Total		525			480

	LPG sales			37			32

	Cushing Terminal throughput			214			118

	Storage leased to third parties, monthly average volumes			1,099			591

~~(1)~~

~~Total volumes attributable to acquisitions during the period have been divided by the total number of days in the period to get a daily average.~~

~~(2)~~

~~2001 volume information is adjusted for consistency of comparison with 2002 presentation.~~

~~Gathering, Marketing, Terminalling~~
(1)
Revenues and ~~Storage Operations~~cost of sales and operations include intersegment amounts.
(2)
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, gross margin (excluding depreciation) and gross profit (excluding depreciation).
(4)
Volumes associated with acquisitions represent weighted averaged daily amounts for the ~~Three Months Ended~~number of days we actually owned the assets over the total days in the period.

Because of the overall counter-cyclical balance of our assets and the flexibility embedded in our business strategy, the benefit we received from backwardation in the market, the increase in lease gathering volumes, volatile market conditions and increased tankage available to our gathering and marketing business in the third quarter of 2003, more than offset the adverse impact of reduced storage activities. During much of the third quarter of 2002, the crude oil market was in contango. In addition, the Canadian dollar to U.S. dollar exchange rate decreased to an average rate of 1.38 for the three months ended September 30, ~~2002 and 2001~~

~~For~~2003, from an average rate of 1.56 for the three months ended September 30, 2002, which resulted in a favorable impact on the results reported for our Canadian operations.

The increase in earnings we realized from the factors discussed above was offset by the items impacting comparability listed in the table below. The resulting gross margin (excluding depreciation)

for the quarter was $20.6 million compared to $21.3 million in 2002. The following items impact the comparability of gross margin (excluding depreciation) for the periods presented:

		Three months ended September 30,
		2003			2002
		(in millions)
Items Impacting Comparability
	LTIP accrual	$	(1.0	)	$	—
	SFAS 133 Loss		(2.9	)		(0.4	)

	Total of items impacting comparability	$	(3.9	)	$	(0.4	)

Operating expenses included in gross margin (excluding depreciation) increased to approximately $19.6 million in the current period from $15.9 million in the prior year period. This increase included the $1.0 million LTIP accrual shown above. The remaining increase was partially related to our continued growth, primarily from acquisitions, coupled with increased regulatory compliance activities and higher fuel costs. These items were partially offset by the approximately $0.9 million favorable impact from the decrease in the Canadian dollar to U.S. dollar exchange rate in the 2003 period as compared to the 2002 period.

General and administrative expenses increased to $11.0 million in the current period from $8.2 million in the 2002 period. Included in the 2003 amount is $3.4 million related to the accrual for the probable vesting of unit grants under our LTIP. The percentage of indirect costs allocated to the Gathering, Marketing, Terminalling and Storage Operations segment has decreased from period to period as our pipeline operations have grown, partially offsetting the impact of the inclusion of the LTIP accrual. Current quarter gross profit (excluding depreciation) of $9.6 million includes $3.9 million related to the items impacting comparability listed above as well as an additional $3.4 million of expense related to the probable vesting of unit grants under our LTIP accrual included in general and administrative expenses. Partially offsetting these items is the approximately $0.5 million favorable impact from the decrease in the Canadian dollar to U.S. dollar exchange rate.

In addition to market conditions and our hedging activities, the primary drivers of the performance of our gathering, marketing, terminalling and storage operations segment are crude oil lease gathered volumes and LPG sales volumes. Crude oil bulk purchase volumes are not considered a driver as they are primarily used to enhance margins of lease gathered barrels. Gross profit per barrel (excluding depreciation) including the items impacting comparability for the quarters ended September 30, 2003 and 2002, was $0.22 per barrel and $0.32 per barrel, respectively.

For the quarter ended September 30, 2003, we gathered from producers, using our assets or third-party assets, approximately ~~408,000~~429,000 barrels of crude oil per ~~day.~~day, an increase of 5% over similar activities in the third quarter of 2002. In addition, we purchased in bulk, primarily at major trading locations, approximately ~~85,000~~96,000 barrels of crude oil per ~~day.~~day in the 2003 period and approximately 72,000 barrels per day in the 2002 period. Storage leased to third parties ~~decreased~~at our Cushing facility increased to an average of ~~0.8~~1.1 million barrels per ~~day~~month in the current year quarter from an average of ~~2.7~~0.6 million barrels per ~~day~~month in the ~~prior year~~third quarter ~~as we used an increased amount~~ of our capacity for our own account due to contango market activities in the current year period. A contango market exists when oil prices for future deliveries are higher than current prices thereby making it profitable to store crude oil for future delivery.2002. Cushing Terminal throughput volumes averaged approximately ~~123,000~~214,000 barrels per day and ~~97,000~~118,000 barrels per day for the ~~quarter~~quarters ended September 30, 2003 and 2002, ~~and 2001,~~ respectively.

Also during the quarter, we marketed approximately 37,000 barrels per day of LPG, an increase of approximately 16% over the approximately 32,000 barrels per day marketed in the third quarter of 2002.

Revenues from our gathering, marketing, terminalling and storage operations were approximately ~~$2.2~~$2.9 billion and ~~$2.1~~$2.2 billion for the ~~quarter~~quarters ended September 30, 2003 and 2002, respectively.

Revenues and ~~2001, respectively. Revenues~~cost of sales and operations (excluding depreciation) for ~~2002~~2003 were impacted ~~both~~ by ~~increased volumes over the comparative prior year quarter as well as~~ higher average ~~prices.~~prices and higher crude oil lease gathering volumes in the 2003 period as compared to the 2002 period. The average NYMEX price for crude oil was ~~$28.27~~$30.26 per barrel and ~~$26.78~~$28.27 per barrel for the third quarter of 2003 and 2002, respectively.

Other Expenses

Depreciation and ~~2001, respectively.~~

~~Gross margin from gathering, marketing, terminalling~~Amortization

Depreciation and ~~storage activities~~amortization expense related to operations was approximately ~~$21.3~~$10.5 million for the quarter ended September 30, ~~2002,~~2003, compared to ~~$23.5~~$7.7 million for the same period of 2002. The increase relates to an inclusion of a full quarter of depreciation for the Shell acquisition in 2003 compared to only two months in 2002, the completion of numerous smaller acquisitions in 2003 and various capital expansion projects. Depreciation and amortization expense related to general and administrative items increased to $1.5 million in the ~~prior year quarter. Excluding~~third quarter of 2003 from $1.3 million in the ~~impact~~third quarter of 2002. Debt amortization costs included in depreciation and amortization expense were $1.0 million in the ~~noncash fair value adjustments related~~third quarter of both 2003 and 2002.

Interest Expense

Interest expense increased approximately $1.4 million to ~~SFAS 133, gross margin for this segment would have been approximately $21.7~~$8.8 million for the quarter ended September 30, 2002, compared to $22.8 million in the prior year quarter. The 2002 results were negatively impacted by hurricanes Isidore and Lili that caused the temporary shut-in of oil production in the Gulf of Mexico during the third quarter.

~~G&A related to gathering, marketing, terminalling and storage operations was $8.3 million for the quarter ended September 30, 2002, compared to~~2003, from $7.4 million for the comparable 2002 period. The increase was primarily related to an increase in the average debt balance during the 2003 period to approximately $532.3 million from approximately $482.3 million in the 2002 period, which resulted in additional interest expense of approximately $0.7 million. The higher average debt balance was primarily due to the portion of the Shell acquisition that was not financed with equity. This debt was outstanding for the entire quarter in 2003 versus only a portion of the quarter in 2002. Also, increased commitment and other fees coupled with lower capitalized interest resulted in approximately $0.5 million of the increase in the 2003 period. In addition, our weighted average interest rate increased slightly during the current year quarter to 5.9% versus 5.8% in the third quarter of ~~2001. The~~2002, which increased our interest expense by approximately $0.2 million. Although the interest rate change was slight, it was the net result of various factors that included an increase in the amount of fixed rate, long-term debt, long-term interest rate hedges and declining short-term interest rates. In mid-September 2002, ~~is primarily due~~we issued $200 million of ten-year bonds bearing a fixed interest rate of 7.75%. In the fourth quarter of 2002 and the first quarter of 2003, the company entered into hedging arrangements to ~~expenses associated with our Canadian acquisitions, partially offset~~lock in interest rates on approximately $50 million of its floating rate debt. In addition, the average three-month LIBOR rate declined from approximately 1.8% during the third quarter of 2002 to approximately 1.1% during the three months ended September 30, 2003. The net impact of these factors, increased commitment fees and changes in average debt balances increased the average interest rate by ~~a decrease in other G&A expenses related to the domestic operations.~~

0.1%.

~~Gathering, Marketing, Terminalling and Storage Operations for the~~ Nine Months Ended September 30, ~~2002~~2003 and ~~2001~~2002

For the nine months ended September 30, 2003, we reported net income of $59.6 million on total revenues of $9.0 billion compared to net income for the same period in 2002 of $47.5 million on total revenues of $5.9 billion.

The items included in the following table are included in net income in the period indicated and impact the comparability between periods:

		Nine months ended September 30,
		2003			2002
		(in millions)
Items Impacting Comparability
	LTIP accrual	$	(7.4	)	$	—
	SFAS 133 Loss		(1.7	)		(2.1	)
	Loss on early extinguishment of debt		(0.2	)		—

	Total of items impacting comparability	$	(9.3	)	$	(2.1	)

The following table reflects our results of operations for each segment:

	Pipeline Operations			Gathering, Marketing, Terminalling & Storage
	(in millions)
Nine Months Ended September 30, 2003⁽¹⁾
Revenues	$	489.1		$	8,594.8
Cost of sales and operations (excluding depreciation and LTIP accrual)		(405.2	)		(8,513.8	)
LTIP accrual—operations		(0.4	)		(1.0	)

Gross margin (excluding depreciation)		83.5			80.0
General and administrative expenses (excluding LTIP accrual)⁽²⁾		(13.7	)		(23.7	)
LTIP accrual—general and administrative		(2.6	)		(3.4	)

Gross profit (excluding depreciation)	$	67.2		$	52.9

Noncash SFAS 133 impact⁽³⁾	$	—		$	(1.7	)

Maintenance capital	$	4.8		$	0.7

Nine Months Ended September 30, 2002⁽¹⁾
Revenues	$	334.1		$	5,554.6
Cost of sales and operations (excluding depreciation)		(273.8	)		(5,490.5	)

Gross margin (excluding depreciation)		60.3			64.1
General and administrative expenses⁽²⁾		(9.9	)		(23.5	)

Gross profit (excluding depreciation)	$	50.4		$	40.6

Noncash SFAS 133 impact⁽³⁾	$	—		$	(2.1	)

Maintenance capital	$	2.7		$	1.3

(1): Revenues and costs of sales and operations include intersegment amounts.
(2): General and administrative expenses (G&A) 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, gross margin (excluding depreciation), and gross profit (excluding depreciation).

Pipeline Operations

The following table sets forth our operating results from our Pipeline Operations segment for the periods indicated:

				Nine months ended September 30,
				2003			2002
Operating Results (in millions)⁽¹⁾
	Tariff activities revenues			$	112.4		$	72.2
	Margin activities revenues				376.7			261.9

	Total pipeline operations revenues				489.1			334.1
	Cost of sales and operations (excluding depreciation and LTIP accrual)				(405.2	)		(273.8	)
	LTIP accrual—operations				(0.4	)		—

	Gross Margin (excluding depreciation)				83.5			60.3
	General and administrative expenses (excluding LTIP accrual)⁽²⁾				(13.7	)		(9.9	)
	LTIP accrual—general and administrative				(2.6	)		—

	Gross Profit (excluding depreciation)			$	67.2		$	50.4

	Maintenance capital			$	4.8		$	2.7

Average Daily Volumes (thousands of barrels per day)⁽³⁾
	Tariff activities
		All American			60			65
		Basin			264			53
		Other domestic			283			189
		Canada			191			186

	Total tariff activities				798			493
	Margin activities				80			72

			Total		878			565

(1): Revenues and cost of sales and operations include intersegment amounts.
(2): 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): 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.

Total average daily volumes transported were approximately 878,000 barrels per day and 565,000 barrels per day for the nine months ended September 30, 2003 and 2002, respectively. As discussed above, we have completed a number of acquisitions during 2003 and 2002 that have impacted the

results of operations herein. The following table reflects our total average daily volumes from our tariff activities by year of acquisition from their date of acquisition for comparison purposes:

		Nine months ended September 30,
		2003	2002
		(thousands of barrels per day)
Tariff activities⁽¹⁾
	2003 acquisitions	58	—
	2002 acquisitions	348	103
	All other pipeline systems	392	390

	Total tariff activities average daily volumes	798	493

(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.

Average daily volumes from our tariff activities were approximately 798,000 barrels per day compared to approximately 493,000 barrels per day for the prior year period. Approximately 303,000 barrels per day of the increase in the current year period is due to volumes transported on the pipelines acquired in 2003 and 2002, including approximately 244,000 on the assets acquired in the Shell acquisition. Volumes transported on all other pipeline systems increased approximately 2,000 barrels per day to 392,000 barrels per day. This increase included approximately 5,000 barrels per day more on our Canadian pipelines in the first nine months of 2003 than in the first nine months of 2002, and approximately 7,000 barrels per day more on our West Texas Gathering System. Offsetting these increases is an approximate 5,000 barrel per day decrease in our All American tariff volumes attributable to a decline in OCS production and various smaller decreases on other systems. The increase in our Canadian volumes primarily resulted from the completion of capital expansion projects during 2002 that allowed for additional volumes. Concurrently, our West Texas Gathering System has benefited from the shutdown of the Rancho pipeline and also from temporary refinery problems that have diverted crude oil barrels from other systems.

Total revenues from our pipeline operations were approximately $489.1 million and $334.1 million for the nine months ended September 30, 2003 and 2002, respectively. The increase in revenues was primarily related to our margin activities, which increased by approximately $114.8 million in the 2003 period. This increase was primarily related to higher average prices on our margin activity on our San Joaquin Valley gathering system in the 2003 period as compared to the 2002 period, but was also positively impacted by higher volumes on our buy/sell arrangements in the current period. However, this business is a margin business and although revenues and cost of sales are impacted by the absolute level of crude oil prices, this factor had a limited impact on gross margin.

Revenues from our tariff activities increased approximately $40.2 million. The following table reflects our revenues from our tariff activities by year of acquisition for comparison purposes:

		Nine months ended September 30,
		2003		2002
		(in millions)
Tariff activities revenues⁽¹⁾
	2003 acquisitions	$	8.0	$	—
	2002 acquisitions		40.7		10.6
	All other pipeline systems		63.7		61.6

	Total tariff activities	$	112.4	$	72.2

(1): Revenues include intersegment amounts.

Total revenues from our tariff activities were approximately $112.4 million and $72.2 million for the nine months ended September 30, 2003 and 2002, respectively. The increase in 2003 of $40.2 million is predominately related to the inclusion of revenues from the businesses acquired in 2003 and an increase in revenues from the pipeline systems acquired in the Shell acquisition as they have been included for nine months of 2003 versus two months of 2002. Revenues from all other pipeline systems increased approximately $2.1 million to $63.7 million for the nine months ended September 30, 2003. Canadian revenues increased approximately $2.5 million primarily due to higher volumes and tariffs in the current period coupled with a $2.2 million favorable exchange rate impact. The favorable exchange rate impact resulted from a decrease in the Canadian to U.S. dollar exchange rate to an average rate of 1.43 for the nine months ended September 30, 2003, from an average rate of 1.57 for the nine months ended September 30, 2002. Revenues from our West Texas Gathering System also increased approximately $1.1 million. These increases were partially offset by decreased revenues from various of our U.S. pipeline systems, including a $2.1 million decrease on our All American system on which we receive the highest per barrel tariffs among our pipeline operations.

As a result of these factors, pipeline operations gross margin (excluding depreciation) increased 38% to approximately $83.5 million for the nine months ended September 30, 2003, from $60.3 million for the prior year period, an increase of approximately $23.2 million. Incorporated in this increase is approximately $1.4 million from a more favorable Canadian dollar to U.S. dollar exchange rate in the 2003 period as compared to the 2002 period. Such results also incorporate an increase in operating expenses to $42.7 million in the 2003 period from $25.9 million in the 2002 period. This increase includes $0.4 million related to the accrual made for the probable vesting of unit grants under our LTIP. The remaining increase is predominately related to our continued growth, primarily from acquisitions, coupled with higher utility costs and regulatory compliance activities.

General and administrative expenses increased approximately $6.4 million between comparable periods, partially as a result of a $2.6 million accrual related to the probable vesting of unit grants under our LTIP and our continued growth, primarily from acquisitions. Additionally, the percentage of indirect costs allocated to the pipeline operations segment has increased in the 2003 period as our pipeline operations have grown. Including the impact of the items discussed above, gross profit (excluding depreciation) was approximately $67.2 million in the first nine months of 2003, an increase of 33% as compared to the $50.4 million reported for the nine months ended September 30, 2002. Incorporated in this increase is approximately $1.3 million from a more favorable Canadian dollar to U.S. dollar exchange rate in the 2003 period as compared to the 2002 period.

Gathering, Marketing, Terminalling and Storage Operations

The following table sets forth our operating results from our Gathering, Marketing, Terminalling and Storage Operations segment for the periods indicated:

			Nine months ended September 30,
			2003			2002
Operating Results (in millions)⁽¹⁾
	Revenues		$	8,594.8		$	5,554.6
	Cost of sales and operations (excluding depreciation and LTIP accrual)			(8,513.8	)		(5,490.5	)
	LTIP accrual—operations			(1.0	)		—

	Gross Margin (excluding depreciation)		$	80.0		$	64.1
	General and administrative expenses (excluding LTIP accrual)⁽²⁾			(23.7	)		(23.5	)
	LTIP accrual—general and administrative			(3.4	)		—

	Gross Profit (excluding depreciation)		$	52.9		$	40.6

	Noncash SFAS 133 impact⁽³⁾		$	(1.7	)	$	(2.1	)

	Maintenance capital		$	0.7		$	1.3

Average Daily Volumes(thousands of barrels per day except as otherwise noted)⁽⁴⁾
	Crude oil lease gathering			430			406
	Crude oil bulk purchases			84			69

		Total		514			475

	LPG sales			43			40

	Cushing Terminal throughput			196			87

	Storage leased to third parties, monthly average volumes			1,124			1,103

(1): Revenues and cost of sales and operations include intersegment amounts.
(2): 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, gross margin (excluding depreciation) and gross profit (excluding depreciation).
(4): Volumes associated with acquisitions represent weighted averaged daily amounts for the number of days we actually owned the assets over the total days in the period.

During the first nine months of 2003, market conditions were extremely volatile as a confluence of several events caused the NYMEX benchmark price of crude oil to fluctuate widely, with periods of steep backwardation throughout the first eight months of 2003 (See Outlook—Other for additional discussion regarding our expectations for the remainder of the year). The NYMEX benchmark price of crude oil ranged from as high as $39.99 per barrel to as low as $25.04 per barrel during this nine month period. Additionally, results from the first quarter of 2003 were further enhanced by increased sales and higher margins in our LPG activities resulting from cold weather throughout the U.S. and Canada.

Because of the overall counter-cyclical balance of our assets and the flexibility embedded in our business strategy, the benefit we received from the periods of pronounced backwardation, volatile market conditions and increased tankage available to our gathering and marketing business in the first nine months of 2003 more than offset the adverse impact of reduced storage activities. In contrast,

during a substantial portion of the first nine months of 2002, the crude oil market was in contango, which enhances the economics of storing crude oil and increases demand for storage services from third parties, but is generally disadvantageous for our gathering and marketing activities.

As a result of these factors, our gross margin (excluding depreciation) increased approximately $15.9 million or 25% to $80.0 million as compared to $64.1 million in the first nine months of 2002. Included in these results is a $1.7 million non-cash, mark-to-market loss pursuant to SFAS 133 in the first nine months of 2003 and a $2.1 million, SFAS 133 non-cash mark-to-market loss in the comparable 2002 period. The impact of SFAS 133 adjustments accounted for $0.4 million or approximately 3% of the increase in gross margin (excluding depreciation). Also included in gross margin (excluding depreciation) is a favorable impact of $1.9 million resulting from a decrease in the average Canadian to U.S. dollar exchange rate to 1.43 in the 2003 period from 1.57 in the 2002 period.

These results incorporate an increase in operating expenses to $57.6 million in the 2003 period from $49.0 million in the 2002 period related to our continued growth, primarily from acquisitions, coupled with increased regulatory compliance activities and higher fuel costs. Operating expenses for the 2003 period also include $1.0 million related to the accrual for our LTIP.

General and administrative expenses increased approximately $3.6 million to $27.1 million in the current year period. Included in general and administrative expenses for the nine months ended September 30, 2003, is $3.4 million related to the accrual for the probable vesting of unit grants under our LTIP. General and administrative expenses also reflect a general decrease in the percentage of non-direct costs allocated to the Gathering, Marketing, Terminalling and Storage Operations segment as our pipeline operations have grown. Gross profit (excluding depreciation) was approximately $52.9 million in the first nine months of 2003, an increase of $12.3 million from the nine months ended September 30, 2002. This increase incorporates the favorable impacts of approximately $1.2 million resulting from a decrease in the Canadian dollar to U.S. dollar exchange rate in the 2003 period as compared to the 2002 period and a $0.4 million favorable difference in the impact of the SFAS 133 adjustments. Both of these items were partially offset by accruals for the probable vesting of unit grants under our LTIP totaling $4.4 million, as discussed above.

In addition to market conditions and our hedging activities, the primary drivers of the performance of our Gathering, Marketing, Terminalling and Storage Operations segment are crude oil lease gathered volumes and LPG sales volumes. Crude oil bulk purchase volumes are not considered a driver as they are primarily used to enhance margins of lease gathered barrels. Gross profit per barrel (excluding depreciation) for the nine months ended September 30, 2003 and 2002, was $0.41 per barrel and $0.33 per barrel, respectively.

For the nine months ended September 30, 2003, we gathered from producers, using our assets or third-party assets, approximately ~~406,000~~430,000 barrels of crude oil per ~~day.~~day, an increase of 6% over similar activities in the first nine months of 2002. In addition, we purchased in bulk, primarily at major trading locations, approximately ~~74,000~~84,000 barrels of crude oil per ~~day.~~day in the 2003 period and approximately 69,000 barrels per day in the 2002 period. Storage leased to third parties ~~decreased to an average of 1.3 million barrels per day from an average of 2.3 million barrels per day in~~at our Cushing facility was flat over the ~~prior year period as we used an increased amount of our capacity for our own account due to contango market activities in the current year period.~~two periods. Cushing Terminal throughput volumes averaged approximately ~~92,000~~196,000 barrels per day and ~~103,000~~87,000 barrels per day for the nine months ended September 30, 2003 and 2002, respectively. Also during the first nine months of 2003 and ~~2001,~~2002, we marketed approximately 43,000 and 40,000 barrels per day of LPG, respectively.

Revenues from our ~~gathering, marketing, terminalling~~Gathering, Marketing, Terminalling and ~~storage operations~~Storage Operations were approximately ~~$5.6~~$8.6 billion and ~~$5.0~~$5.6 billion for the nine months ended September 30, ~~2002~~2003 and ~~2001,~~2002, respectively. Revenues ~~from our Canadian~~and cost of sales and operations (excluding depreciation) for 2003 were ~~approximately $1.1 billion for~~primarily impacted by higher average prices and increased crude oil lease gathering volumes in the 2003 period as compared to the 2002 ~~period, which was an increase of approximately $0.6 billion over the prior year~~ period. The increase was partially related to the inclusion of the Canadian acquisitions for all of 2002 compared to a portion of 2001. This had the impact of increasing volumes by approximately 84,000 barrels per day. Domestic gathering volumes increased an average of approximately 22,000 barrels per day in the 2002 period from the comparable 2001 period, but the increased volumes were offset by decreased prices resulting in relatively flat revenues from our domestic operations. The average NYMEX price for crude oil was ~~$25.39~~$31.03 per barrel and ~~$27.86~~$25.39 per barrel for the first nine months ~~ended September 30,~~of 2003 and 2002, respectively.

Other Expenses

Depreciation and ~~2001, respectively.~~

Amortization

~~Gross margin from gathering, marketing, terminalling~~ Depreciation and ~~storage activities~~amortization expense related to operations was approximately ~~$64.1~~$29.5 million for the nine months ended September 30, ~~2002,~~2003, compared to $60.5 million in the prior year period. Excluding the impact of the noncash fair value adjustments related to SFAS 133, gross margin for this segment would have been approximately $66.2 million for the nine months ended September 30, 2002, compared to $59.7 million in the prior year period. The increase is partially related to the inclusion of the businesses acquired in the Canadian acquisitions for all of 2002 compared to the portion of 2001 subsequent to acquisition. In addition, higher domestic volumes contributed to higher gross margin in 2002.

G&A expense related to gathering, marketing, terminalling and storage operations was $24.1 million for the nine months ended September 30, 2002, compared to $20.3 million for the 2001 period. The increase in 2002 is primarily due to expenses associated with our Canadian acquisitions, partially offset by a decrease in other G&A expenses related to the domestic operations.

~~Other Expenses~~

~~Depreciation and Amortization~~

~~Depreciation and amortization expense was $9.0 million for the quarter ended September 30, 2002, compared to $6.4~~$19.7 million for the same period of ~~2001.~~2002. Approximately ~~$1.6~~$5.6 million of the increase is associated with the assets acquired in the Shell acquisition. For the nine months ended September 30, 2002, depreciation and amortization expense increased to $23.1 million, an increase of $5.5 million from the $17.6 million reported in the 2001 period. Approximately $4.0 million of the increase is attributable to our acquisitions completed in 2002, as well as those completed in 2001, but not outstanding the entire period. The remainder of the increase ~~for both periods~~ is primarily related to anthe completion of various capital expansion projects and other acquisitions. Depreciation and amortization expense related to general and administrative items increased approximately $1.3 million to $4.7 million in the first nine months of 2003 from the first nine months of 2002 because of higher debt issue costs, technology expenditures and various other smaller items. Debt amortization costs included in depreciation and amortization expense were $3.0 million and $2.5 million in the first nine months of 2003 and 2002, respectively. The increase inwas because of higher debt issue costs related to the amendment of our credit facilities during 2002 and ~~late 2001,~~ the sale of ~~the~~ senior unsecured notes in September ~~2002, and the completion of various capital expansion projects.~~

2002.

Interest Expense

Interest expense ~~decreased~~increased approximately $6.3 million to ~~$7.4~~$26.5 million for the ~~quarter~~nine months ended September 30, ~~2002,~~2003, from ~~$7.8~~$20.2 million for the ~~comparative 2001~~comparable 2002 period. ~~For~~The increase was primarily related to an increase in the average debt balance during the 2003 period to approximately $524.7 million from approximately $422.0 million in the 2002 period, which resulted in additional interest expense of approximately $4.7 million. The higher average debt balance was primarily due to the portion of the Shell acquisition that was not financed with equity. This debt was outstanding for the entire period in 2003 versus only a portion of the period in 2002. In addition, increased commitment and other fees coupled with lower capitalized interest resulted in approximately $2.2 million of the increase in the 2003 period. Our weighted average interest rate decreased slightly during the first nine months of 2003 to 6.0% versus 6.2% for the nine months ended September 30, 2002, which decreased our interest expense ~~decreased to $20.2 million from $22.5 million for~~by approximately $0.6 million. Although the ~~comparative 2001 period. The decreases are due to~~interest rate change was slight, it was the ~~capitalization~~net result of ~~interest and lower interest rates somewhat offset by higher average debt balances and increased commitment fees. Interest~~various factors that included an increase in the amount of ~~$0.2 million~~fixed rate, long-term debt, long-term interest rate hedges and ~~$0.6 million for the quarter and nine months, respectively was capitalized in conjunction with the construction of our Cushing terminal expansion. The lower~~declining short-term interest ~~rates are due to a decrease in LIBOR and prime rates in the current year. During the third quarter of 2001,~~rates. In mid-September 2002, we issued $200 million of ~~term B notes. Proceeds were used~~ten-year bonds bearing a fixed interest rate of 7.75%. In the fourth quarter of 2002 and the first quarter of 2003, the company entered into hedging arrangements to ~~reduce borrowings under~~lock in interest rates on approximately $50 million of its floating rate debt. In addition, the ~~revolver. As such, our~~average three-month LIBOR rate declined from approximately 1.9% during the first nine months of 2002 to approximately 1.2% during the first nine months of 2003. The net impact of these factors, increased commitment fees ~~on our revolver increased, as they are based on unused availability. The overall increased~~and changes in average debt ~~balance in 2002 is related to~~balances decreased the ~~Shell acquisition in August 2002.~~

average interest rate by 0.2%.

Outlook

On October 29, ~~2002,~~2003, we furnished ~~Item 9~~ information in aan amended current report on Form ~~8-K,~~8-K/A containing management's guidance for operating and financial performance for the fourth quarter of ~~2002~~2003 and ~~updated selected~~ preliminary guidance ~~information~~ for ~~2003.~~

2004, including a discussion of the significant factors and assumptions management considered in preparing our guidance, as well as a discussion of factors that could cause actual results to differ materially from results anticipated in the forward-looking statements. Information that is "furnished" in a Form 8-K is typically not included in a periodic report such as this quarterly report. As a result, the projections, assumptions and risk factors discussed in our 8-K/A furnished on October 29 are not incorporated by reference in this report.

This "Outlook" section and the section captioned "Forward Looking Statements and Associated Risks" identify certain matters of risk and uncertainty that may affect our financial performance and results of operations in the future.

Crude Oil Inventory

We value our crude oil inventory at the lower of cost or market, with cost determined using an average cost method. At September 30, 2003 we had approximately 574,000 barrels of inventory classified as unhedged operating inventory at a weighted average cost of $25.81 per barrel. The lower of cost or market method requires a write down of inventory to the market price at the end of a period in which our weighted average cost exceeds the market price. This method does not allow a write up of the inventory if the market price subsequently increases. We did not have an adjustment in this period. However, future fluctuations in crude oil prices could result in a period end lower of cost or market adjustment.

Acquisition ~~Activities.~~Activities

Consistent with our ~~acquisition~~business strategy, we are continuously engaged in discussions with potential sellers regarding the possible purchase by us of midstream crude oil assets. Such acquisition efforts involve participation by us in processes that have been made public, involve a number of potential buyers and are commonly referred to as ~~“auction”~~"auction" processes, as well as situations in which we believe we are the only party or one of a very limited number of potential buyers in negotiations with the potential seller. These acquisition efforts often involve assets which, if acquired, would have a material effect on our financial condition and results of operations. We are currently in advanced negotiations for a crude oil pipeline and storage acquisition that is complementary to our existing asset base. We have signed a letter of intent with the seller and are in advanced negotiations with respect to a definitive purchase and sale agreement. If consummated under current terms, the purchase price is expected to be approximately $50 million. Since 1998, we have completed 12numerous acquisitions for an aggregate purchase price of ~~$1.1~~approximately $1.3 billion. We can give you no assurance that our current or future acquisition efforts will be successful or that any such acquisition will be

completed on terms considered favorable to us. In connection with these activities, we routinely incur third party costs, which are capitalized and deferred pending final outcome of the transaction. Deferred costs associated with successful transactions are capitalized as part of the transaction, while deferred costs associated with unsuccessful transactions are expensed at the time of such final determination. At September 30, ~~2002,~~2003, the amount of costs deferred pending final outcome was ~~not material.~~

~~FERC Notice of Proposed Rulemaking.~~ On August 1, 2002, the Federal Energy Regulatory Commission (“FERC”) issued a Notice of Proposed Rulemaking that, if adopted, would amend its Uniform Systems of Accounts for oil pipeline companies with respect to participation of a FERC-Regulated subsidiary in the cash management arrangement of its non-FERC-regulated parent. Although it appears that, if adopted, the rule may affect the way in which we manage cash, we believe that the incremental costs will not be significant.

~~Sarbanes-Oxley Act and New SEC Rules~~. Several regulatory and legislative initiatives have been introduced over the past several months in response to recent events regarding accounting issues at large public companies, resulting disruptions in the capital markets and ensuing calls for action to prevent repetition of such events. We support the actions called for under these initiatives and believe these steps will ultimately be successful in accomplishing the stated objectives. However, implementation of reforms in connection with such initiatives will add to the costs of doing business for all publicly-traded entities, including the Partnership. Such costs will have an adverse impact on future income and cash flow, especially in the near term as legal, financial and consultant costs are incurred to analyze the new requirements, formalize current practices and implement required changes to ensure that we maintain compliance with these new rules. We are not able to estimate the magnitude of increase in our costs that will result from such reforms.

$0.3 million.

Vesting of Unit Grants ~~under LTIP.~~Under Long-Term Incentive Plan ~~In connection with our public offering in 1998, our general partner established a long-term incentive plan, which permits the grant~~

As of ~~restricted units and unit options~~September 30, 2003, there were grants covering ~~an aggregate of~~ approximately ~~1.4 million units. Approximately 1.0~~one million restricted units ~~(and no~~outstanding under our LTIP. Restricted unit ~~options) have been granted under the plan. A restricted unit grant entitles the grantee~~grants become eligible to ~~receive a common unit upon the vesting of the restricted unit. Subject to additional vesting requirements, restricted units may~~ vest in the same proportion as the conversion of our outstanding subordinated units into common ~~units. Certain~~units, subject to any additional vesting requirements.

The subordination period (as defined in the partnership agreement) for the 10,029,619 outstanding subordinated units will end if certain financial tests are met for three consecutive, non-overlapping four-quarter periods (the "testing period"). See Note 6 to the Consolidated Financial Statements. We are now in the testing period and, in connection with the payment of the quarterly distribution in November 2003, 25% of the outstanding subordinated units will convert into common units. In conjunction with this conversion, approximately 35,000 restricted ~~unit grants contain~~units vest, and a 90-day period will commence for approximately 220,000 additional restricted units that will not have any remaining vesting requirements ~~tied to~~except that the holder must continue employment with the Partnership ~~achieving targeted distribution thresholds, generally $2.10, $2.30 and $2.50 per unit, in equal proportions.~~for the remainder of the 90-day period.

Probable Vesting.

Under generally accepted accounting principles, we are required to recognize an expense when it is considered probable that the financial tests for conversion of subordinated units and required distribution levels ~~are met. The test associated~~will be met and that restricted unit grants will vest. At September 30, 2003 we concluded that the vesting of approximately 255,000 restricted units was probable and thus accrued

approximately $7.4 million of compensation expense based upon an estimated market price of $30.05 per unit (the unit price as of September 30, 2003), our share of employment taxes and other related costs. Under the LTIP, we may satisfy our obligations using a combination of cash, the issuance of new units and delivery of units purchased in the open market. Approximately $2.8 million of the $7.4 million accrued at September 30, 2003 is related to units granted to senior management of the partnership and will be settled almost exclusively with the delivery of units, net of taxes. We anticipate that in November 2003, to satisfy the vesting of those restricted units that vest substantially contemporaneously with the conversion of subordinated units, towe will issue approximately 18,000 common units ~~is set forth~~after netting for taxes and paying cash in lieu of a portion of the vested units. For those restricted units that require passage of time to vest, the 90-day period will expire and final vesting will occur in February 2004. We estimate we will issue approximately 100,000 common units in the ~~Partnership Agreement and involves GAAP accounting concepts as well as complex and esoteric cash receipts and disbursement concepts that are indexed to the minimum quarterly distribution rate~~first quarter of ~~$1.80 per limited partner unit.~~

~~Because of~~2004 in connection with this ~~complexity, it is difficult to forecast when the vesting of these restricted units will occur. However, at~~probable vesting.

Potential Vesting. At the current distribution level of ~~$2.15~~$2.20 per unit, assuming that the additional subordination conversion ~~test~~tests are met as of December 31, 2003, approximately 580,000 additional units will vest in connection with the payment of the quarterly distribution in February 2004. If at December 31, 2003, it is considered probable that this distribution level and tests will be met, the costs associated with the vesting of ~~up to approximately 820,000~~these additional units ~~would~~will be ~~incurred or~~estimated and accrued in the ~~second half of 2003 or the first~~fourth quarter of ~~2004.~~2003. At a distribution level of $2.30 to $2.49, the number of additional units that would bevest would increase by approximately ~~940,000.~~87,000. At a distribution level at or above $2.50, the number of additional units that would bevest would increase by approximately ~~1,030,000. We~~87,000. In all cases, vesting is subject to any applicable continuing employment requirements.

Subject to providing those holding less than a certain number of restricted units the option to receive cash, we are currently planning to issue units to satisfy the ~~first 975,000 vested, and~~majority of restricted unit obligations that vest in connection with the conversion of subordinated units. If all conditions to ~~purchase~~vesting are met, we currently project the issuance of units (approximately 100,000 common units in connection with the ~~open market~~probable vesting and approximately 239,000 common units in connection with the potential vesting) in the first half of 2004 to satisfy ~~any vesting obligations in excess of that amount. Issuance~~such obligations. Obligations satisfied by the issuance of units ~~would~~will result in a non-cash compensation expense. Purchase of units would result in a cash charge to compensation expense. In addition, the "company match" portion of payroll taxes, plus the value of any units withheld for taxes, will result in a cash charge. The aggregate amount of the potential charge to expense will be determined by the unit price on the date vesting occurs multiplied by the number of ~~units.~~

units, plus our share of associated employment taxes. The amount of the potential charge is subject to various factors, including the unit price on the date vesting occurs, and thus is not known at this time. As mentioned above, we have accrued approximately $7.4 million as of September 30, 2003 in connection with the probable vesting. At the current distribution level and based on an assumed market price of $30.05 per unit (the unit price as of September 30, 2003), the aggregate additional charge that would be triggered by the potential vesting (that is, if we determine it is probable that the additional units will vest) would be approximately $21 million, of which approximately $17 million would be accrued as of December 31, 2003 (although payment and issuance of units would not occur until the first and second quarters of 2004). Approximately $6.1 million of the potential charge is related to units granted to senior management of the partnership and will be settled almost exclusively with the delivery of units, net of taxes. We currently estimate that approximately one-third of the aggregate potential charge of $21 million will be settled with the delivery of units and the remainder in cash.

Contingent Equity Issuance

In connection with the CANPET acquisition in July 2001, approximately $26.5 million Canadian dollars of the purchase price, payable in common units, was deferred subject to various performance objectives being met. If these objectives are met as of December 31, 2003, 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 option, the deferred payment may be paid in cash rather than the issuance of units. We believe that it is probable that the objectives will be met and the deferred amount will be paid in April 2004, however, it is not determinable beyond a reasonable doubt. Assuming the tests are met as of December 31, 2003, and the entire obligation is satisfied with common units, based on the foreign exchange rate and the ten-day average unit price in effect at September 30, 2003, (1.35 Canadian to U.S. dollar exchange rate and $30.36 per unit price) approximately 650,000 units would be issued.

Basin Expansion

We are currently evaluating a potential expansion of a segment of the Basin Pipeline System that extends from Colorado City to Cushing, Oklahoma. At times, the pipeline has operated at levels that are close to its current maximum throughput and we would like to be positioned to handle increased volumes if market conditions warrant. We estimate the expected expansion investment to be approximately $1.5 million and would expect higher incremental operating costs as we would have to activate pump stations that are currently idled. However, we can give no assurances that our volumes transported would increase as a result of this expansion.

OCS production

In early October, Plains Exploration and Production announced that they had received all of the necessary permits to develop a portion of the Rocky Point structure that is accessible from the Point Arguello platforms and it appears that they will commence drilling activities in the first quarter of 2004. Such drilling activities, if successful, are not expected to have a significant impact on pipeline shipments on our All American Pipeline system in 2004. However, such incremental drilling activity, if successful, could lead to increased volumes on our All American Pipeline System in 2005 and beyond. However, we can give no assurances that our volumes transported would increase as a result of this drilling activity.

Pipeline Rate Regulation

Our interstate common carrier pipeline operations are subject to rate regulation by the Federal Energy Regulatory Commission ("FERC") under the Interstate Commerce Act. The Interstate Commerce Act requires that tariff rates for petroleum pipelines, which includes crude oil, as well as refined product and petrochemical pipelines, be just and reasonable and non-discriminatory. The Energy Policy Act of 1992 deemed petroleum pipeline rates in effect for the 365-day period ending on the date of enactment of the Energy Policy Act or that were in effect on the 365th day preceding enactment and had not been subject to complaint, protest or investigation during the 365-day period to be just and reasonable under the Interstate Commerce Act. Generally, complaints against such "grandfathered" rates may only be pursued if the complainant can show that a substantial change has occurred since enactment in either the economic circumstances or the nature of the services that were a basis for the rate or that a provision of the tariff is unduly discriminatory or preferential. In a FERC proceeding involving SFPP, L.P., certain shippers are challenging grandfathered rates on the basis of changed circumstances since the passage of the Energy Policy Act. The ultimate disposition of this challenge may define "substantial change" in such a way as to make grandfathered rates more vulnerable to challenge than has historically been the case. We are uncertain what effect, if any, an unfavorable determination in the FERC proceeding might have on our grandfathered tariffs.

On June 26, 2003, the FERC issued a Notice of Proposed Rulemaking that, if adopted, would impose substantial new reporting burdens on oil pipeline companies. Numerous regulated entities and

industry groups have commented on the proposal, and we cannot predict what the final provisions of the rulemaking might include, nor the impact the final rule would have on us.

Other

The following factors are likely to have a negative influence on our operating and financial results for the fourth quarter of 2003:

•: In August, a blackout of electrical systems occurred in the Midwestern and Northeastern portions of the United States and Eastern Canada. Our pipelines and facilities were not directly impacted by the blackout and there was minimal adverse impact on our operations in the third quarter. However, as a result of related refinery shutdowns that caused crude oil pipelines within these regions to run slower than normal and the related impact on differentials within our Canadian operations, we currently anticipate that the indirect impact of the blackout may reduce fourth quarter earnings and cash flow by approximately $1 million.
•: We are also expecting an increased level of operating expenses associated with a pipeline spill that occurred in October of 2003 in a remote area of Mississippi. On October 13, 2003, a raised pipeline crossing was struck and severed by a falling pine tree, which caused approximately 350 barrels of oil to escape the pipeline. We estimate that the costs related to containing the spill and clean up and recovery operations will increase operating expenses by approximately $1 million in the fourth quarter of 2003.
•: In addition, the steep backwardation in the crude oil forward market (see Results of Operations—Gathering, Marketing, Terminalling and Storage Operations) that existed for most of the first eight months of the year weakened in September and we expect these weaker market conditions to continue for the remainder of the year. As a result, market conditions for the gathering and marketing business are not expected to be as strong in the fourth quarter of 2003 as they were for the first three quarters of 2003.

Liquidity and Capital Resources

Liquidity

Cash generated from operations and our credit facilities are our primary sources of liquidity. At September 30, ~~2002,~~2003, we had a working capital deficit of approximately ~~$17.8~~$65.3 million, approximately ~~$437.5~~$441.9 million (net of $8.0 million to refinance term loan maturities due in the next twelve months) of availability under our revolving credit facility and ~~$53.3~~$125.7 million of availability under the letter of credit and hedged inventory facility. Usage of the credit facilities is subject to compliance with covenants. ~~In the past,~~We believe we have generally maintained a positive working capital position. During the third quarter of 2002, we reduced our working capital, primarily through the (i) collection of accounts receivable and certain prepayments and the application of those proceeds to reduce its long-term borrowings, and (ii) shifting borrowings to finance certain contango inventory and LPG purchase requirements from its long-term revolving credit facilities to its hedged inventory and letter of credit facility. The hedged inventory and letter of credit facility requires reductionare currently in outstanding amounts at the time proceeds from the sale of the inventory are collected. Accordingly, amounts drawn under this facility are reflected as a current liability for hedged inventory expected to be sold within one year. In addition, approximately $11.3 million of the company’s net liability under SFAS 133 is reflected as current.

compliance with all covenants.

We funded the purchase of the ~~Shell acquisition on August 1, 2002,~~acquisitions completed in the first nine months of the year with funds drawn on ~~its~~our revolving credit ~~facilities. Later in August,~~facilities and available cash on hand. In September 2003, we completed a public offering of ~~6,325,000~~3,250,000 common units priced at ~~$23.50~~$30.91 per unit. Net proceeds from the offering, including our general ~~partner’s~~partner's proportionate capital contribution and expenses associated with the offering, were approximately ~~$145.0~~$98.0 million and were used to pay down our revolving credit ~~facilities. During September 2002,~~facilities and term loan. In March 2003, we completed a public offering of 2,645,000 common units priced at $24.80 per unit. Net proceeds from the ~~sale of $200~~offering, including our general partner's proportionate capital contribution and expenses associated with the offering, were approximately $63.9 million ~~of 7.75% senior notes due in October 2012, which generated net proceeds of $196.3 million that we~~and were used to pay down our revolving credit facilities.

On October 27, 2003, we announced that we intend to replace our existing senior secured credit facilities with new senior unsecured credit facilities totaling $750 million and a $200 million, 364-day uncommitted facility for the purchase of hedged crude oil. The new senior unsecured facility will be

comprised of a $455 million, 4-year revolving credit facility, a $170 million 364-day facility (with a 5-year term out option), and a $125 million, 364-day revolving credit facility.

In conjunction with this transaction, we anticipate a non-cash charge of approximately $3.3 million attributable to a loss on the early extinguishment of debt. This expected loss consists of unamortized debt issue costs expected to be written off as a result of the completion of the new credit facility. However, the actual amount of the charge will depend on the final provisions and lenders of the new facility. Although we anticipate closing the refinancing in the fourth quarter of 2003, we can give no assurances that we will successfully consummate the transaction.

The following table reflects our long-term debt obligations as of September 30, 2003 (in millions):

Calendar Year		Payment
2004		$	8.0
2005			8.1
2006			76.0
2007			162.0
2008			—
Thereafter			200.0

	Total⁽¹⁾	$	454.1

(1): Includes unamortized discount on 7.75% senior notes of approximately $0.4 million.

We believe that we have sufficient liquid assets, cash from operations and borrowing capacity under our credit agreements to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. However, we are subject to business and operational risks that could adversely effect our cash flow. A material decrease in our cash flows would likely produce a corollary adverse effect on our borrowing capacity.

~~Recent Disruptions in Industry Credit Markets~~. As a result of business failures, revelations of material misrepresentations and related financial restatements by several large, well-known companies in various industries over the last year, there have been significant disruptions and extreme volatility in the financial markets and credit markets. Because of the credit-intensive nature of the energy industry and troubling disclosures by several large, diversified energy companies, the energy industry has been especially impacted by these developments, with the rating agencies downgrading a number of large energy related companies. Accordingly, in this environment we are exposed to an increased level of direct and indirect counterparty credit and performance risk.

The majority of our credit extensions and therefore our accounts receivable relate to our gathering and marketing activities that can generally be described as high volume and low margin activities, in many cases involving complex exchanges of crude oil volumes. In transacting business with our counterparties, we must determine the amount, if any, of open credit lines to extend to our counterparties and the form and amount of financial performance assurances we may require. The vast majority of such accounts receivable settle monthly and any collection delays generally involve discrepancies or disputes as to the appropriate price, volume or quality of crude oil delivered or exchanged and associated billing delays. Of our $357.6 million aggregate receivables balance included in current assets at December 31, 2001, approximately $330.9 million, or 93%, were less than sixty days past the scheduled invoice date. Of our $483.7 million aggregate receivables balance included in current assets at September 30, 2002, approximately $474.0 million, or 98%, were less than sixty days past the scheduled invoice date.

We have modified our credit arrangements with certain counterparties that have been adversely affected by these recent events, but a large portion of the balances more than sixty days past the invoice date, along with approximately $10.8 million of net receivables classified as long-term, are associated with an ongoing effort to bring substantially all balances to within sixty days of scheduled invoice date. In certain cases, this effort involves reconciling and resolving certain discrepancies, generally related to pricing, volumes, quality or crude oil exchange imbalances, and the majority of these receivables are related to monthly periods leading up to and immediately following the disclosure of our unauthorized trading losses in late 1999. Following that disclosure, a significant number of our suppliers and trading partners temporarily reduced or eliminated our open credit and demanded payments or withheld payments due us before disputed amounts or discrepancies associated with exchange imbalances, pricing issues and quality adjustments were reconciled in accordance with customary industry practices. Because these matters also arose in the midst of various software systems conversions and acquisition integration activities, our effort to resolve outstanding claims and discrepancies has included reprocessing and integrating historical information on numerous software platforms. We have made significant progress to date in this effort and intend to substantially complete this project by the end of 2002 and, based on the work performed to date and the scope of the remaining work to be performed, we believe these prior period balances are collectible or subject to offsets and consider our reserves adequate. However, in the event our counterparties experience an unanticipated deterioration in their credit-worthiness, any addition to existing reserves or write-offs in excess of such reserves would result in a noncash charge to earnings. We do not believe any such charge would have a material effect on our cash flow or liquidity.

To date, these market disruptions have not had a material adverse impact on our activities or on obtaining open credit for our account with counterparties. We are currently rated BB+ by Standard & Poor’s and on June 27, 2002, we were placed on Credit Watch with positive implications. On September 17, 2002, Moody’s Investor Services upgraded our senior implied credit rating to Ba1, stable outlook. You should note that a rating is not a recommendation to buy, sell, or hold securities, and may be subject to revision or withdrawal at any time.

Cash Flows

		Nine Months Ended September 30,
		2003			2002
		(in millions)
Cash provided by (used in):
	Operating activities	$	195.7		$	127.4
	Investing activities		(144.8	)		(349.8	)
	Financing activities		(51.0	)		223.3

Nine Months Ended September 30,


2002

2001


(in millions)

Cash provided by (used in):
Operating activities    $ 127.4    $ 5.5
Investing activities    (349.8 )    (221.3 )
Financing activities    223.3    216.2

Operating ~~Activities~~Activities.. Net cash provided by operating activities for the nine months ended September 30, ~~2002~~2003 was ~~$127.4~~$195.7 million as compared to ~~$5.5~~$127.4 million in the ~~2001~~2002 period. ~~Approximately $15.5~~Cash provided by operating activities in the current year period consisted primarily of (i) net income of $59.6 million, (ii) depreciation and amortization of $34.2 million, (iii) a change in derivative fair value related to SFAS 133 of $1.7 million and (iv) net changes in assets and liabilities of approximately $100.1 million. Cash provided by operating activities in the prior year period consisted primarily of (i) net income of $47.5 million, (ii) depreciation and amortization of $23.1 million, (iii) a change in derivative fair value related to SFAS 133 of $2.1 million and (iv) net changes in assets and liabilities of approximately $54.7 million. The net changes in assets and liabilities are generally the result of the ~~increase is due to an increase in earnings, adjusted for non-cash items, predominantly~~timing of cash receipts related to ~~our acquisitions completed in April~~sales and ~~July 2001 and August 2002. The remainder of the increase is due to changes in working capital items~~cash disbursements related to ~~the following: i) the collection~~purchases, inventory and other expenses. Inventory purchases and sales are accounted for as a use and source, respectively, of ~~accounts receivable related to prior period balances as discussed in “Recent Disruptions in Industry Credit Markets” above; ii) the collection~~cash provided by operating activities. Accordingly, during periods of ~~prepayments due to the increase in credit risk associated with certain counter-parties; and iii) the sale of hedged crude oil~~significant inventory ~~purchased in 2001 and 2002 and the correlated changes in accounts receivable and accounts payable. In addition to the hedged inventory transactions having a positive effect on~~builds or

draws, cash provided by operating activities will fluctuate significantly. Significant inventory activity is typically associated with periods when the market is transitioning into or out of contango, a market condition where prompt month crude oil prices trade at a discount to crude oil prices in one or more future months, and periods following acquisitions or expansion activities where the partnership builds working inventory to operate the expanded asset base.

Investing Activities. Net cash used in investing activities in 2003 includes an approximately $17.0 million deposit made for the ~~nine months ended September 30, 2002, similar transactions had a negative effect on~~ArkLaTex acquisition and an aggregate $82.9 million paid for acquisitions completed in the ~~nine months ended September 30, 2001 as~~first half of 2003 and before and approximately $52.2 million for additions to property and equipment. These additions consist of $18.2 million related to the ~~inventory was being purchased~~construction of crude oil gathering and ~~stored; thus, resulting~~transmission lines in ~~an even larger variance when comparing the two periods.~~

~~Investing Activities~~.West Texas and $34.0 million related to other capital projects. Net cash used in investing activities in 2002 includes ~~the payment of $310.1~~$309.5 million related to ~~the purchase of certain assets from~~our Shell ~~Pipeline Company as well as related transaction costs, $7.7~~acquisition, $14.3 million for ~~the Butte acquisition~~other acquisitions, and ~~$5.1 million for the Coast/Lantern acquisition. Investing activities also~~

~~includes~~ $27.4 million of capital expenditures ~~related to~~primarily for the Cushing expansion ~~the construction of the Marshall terminal in Canada~~ and other capital projects.

Financing ~~Activities~~Activities.. Cash ~~provided by~~used in financing activities in ~~2002~~2003 consisted of (i) approximately ~~$351.3~~$161.9 million of proceeds from the issuance of common units ~~and senior unsecured notes~~ used ~~primarily~~ to ~~fund capital projects and acquisitions and~~ pay down outstanding balances on the revolving credit ~~facility. In addition, $71.6~~facility and Senior secured term B loan, (ii) $89.3 million of distributions ~~were~~ paid to unitholders and the general partner, ~~during~~(iii) $43.0 million of principal repayments of our term loans, (iv) net repayments on our long-term revolving credit facilities of $13.1 million, and (v) net short-term debt repayments of $67.3 million primarily from the ~~nine months ended September 30, 2002.~~proceeds of inventory sales. Cash provided by financing activities in 2002 consisted primarily of (i) $199.6 million of proceeds from the issuance of senior unsecured notes, (ii) $145.3 million of proceeds from the issuance of common units, (iii) net repayments on our long-term revolving credit facilities of $42.3 million, (iv) $3.0 million of payments on our term loans, (v) $71.6 million of distributions paid to unitholders and the general partner, and (vi) a $5.4 million payment related to our financing arrangements.

Universal Shelf

We have filed with the Securities and Exchange Commission a universal shelf registration statement that, subject to effectiveness at the time of use, allows us to issue from time to time up to an aggregate of $700 million of debt or equity securities. At September 30, ~~2002,~~2003, we have approximately ~~$421~~$255 million remaining under this registration statement.

~~Credit Facilities~~Contingencies

Litigation. We, in the ordinary course of business, are a claimant and/or a defendant in various legal proceedings. We do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.

Indemnities. In November, 2002, the Financial Accounting Standards Board ("FASB") issued Interpretation No. 45, Guarantor's Accounting and ~~Long-term Debt~~

~~During September 2002, we completed~~Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others ("FIN 45"). FIN 45 elaborates on the ~~sale of $200 million of 7.75% senior notes due~~disclosures to be made by a guarantor in ~~October 2012. The notes were issued by Plains All American Pipeline, L.P.~~its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a ~~100% owned finance subsidiary (neither of which have independent assets or operations)~~guarantor is required to recognize, at a discount of $0.4 million, resulting in an effective interest rate of 7.78%. Interest payments are due on April 15 and October 15 of each year. The notes are fully and unconditionally guaranteed, jointly and severally, by all of our existing 100% owned subsidiaries, except for subsidiaries which are minor.

~~As amended in July 2002 and giving effect to~~ the ~~third quarter capital raising activities, our credit facilities consist~~inception of a ~~$350.0 million senior secured letter of credit and hedged inventory facility (with current lender commitments totaling $200.0 million), and~~guarantee, a ~~$747.0 million senior secured revolving credit and term loan facility, each of which is secured by substantially all of our assets. The terms of our credit facilities enable us to expand~~liability for the ~~size~~fair value of the letter of credit and hedged inventory facility from $200.0 million to $350.0 million without additional approval from existing lenders. The revolving credit and term loan facility consists of a $420.0 million domestic revolving facility (with a $10.0 million letter of credit sublimit), a $30.0 million Canadian revolving facility (with a $5.0 million letter of credit sublimit), a $99.0 million term loan, and a $198.0 million term B loan.

~~The facilities have final maturities as follows:~~

•

~~as to the $350.0 million senior secured letter of credit and hedged inventory facility and the aggregate $450.0 million domestic and Canadian revolver portions, in April 2005;~~

•

~~as to the $99.0 million term loan, in May 2006; and~~

•

~~as to the $198.0 million term B loan, in September 2007.~~

~~The financial covenants of these credit facilities require us to maintain:~~

•

~~a current ratio (as defined) of at least 1.0 to 1.0;~~

•

~~a debt coverage ratio which will not be greater than 5.25 to 1.0 on unsecured debt and 4.0 to 1.0 on secured debt;~~

•

~~an interest coverage ratio that is not less than 2.75 to 1.0; and~~

•

~~a debt to capital ratio of not greater than 0.7 to 1.0 through March 30, 2003, and 0.65 to 1.0 at any time thereafter.~~

~~For covenant compliance purposes, letters of credit and borrowings under~~obligation undertaken in issuing the ~~letter of credit and hedged inventory facility are excluded when calculating the debt coverage ratio.~~guarantee. We are ~~currently~~party to various contracts entered into in ~~compliance with~~ the ~~covenants contained~~ordinary course of business that contain indemnity provisions pursuant to which we indemnify the counterparties against various expenses. Our indemnity obligations are contingent upon the occurrence of events or circumstances specified in the contracts. No such events or circumstances have occurred at this time, and we do not consider our ~~credit agreements.~~

The amended facility permits us to issue up to an aggregate $400 million of senior unsecured debt having a maturity beyond the final maturity of the existing credit facility and provides a mechanism to reduce the amount of the domestic revolving credit facility. The foregoing description of the credit facility incorporates the reduction associated with the $200 million senior note offering completedliability under such indemnity provisions, individually or in September 2002. Depending on the amount of additional senior indebtedness incurred, the domestic revolving credit facility will be reduced by an amount equating to 40% to 63% of any incremental indebtedness, up to the aggregate, ~~$400 million limitation.~~

The average life of our debt capitalization at September 30, was approximately 6.5 years. At the end of the third quarter we had approximately $12 million outstanding under our $450 million of revolving credit facilities that mature in 2005, approximately $297 million of senior secured term loans with final maturity dates in 2006 and 2007 and $200 million of senior notes which mature in 2012. We have classified the $9 million of term loan payments due in 2003 as long term dueto be material to our ~~intent~~financial position or results of operations.

Operational Hazards and ~~ability to refinance those maturities using the revolving facility.~~

~~Term loan payments are as follows (in millions):~~

Calendar Year

Payment
2003    $ 9.0
2004    10.0
2005    10.0
2006    78.0
2007    190.0

Total    $ 297.0

We manage our exposure to increasing interest rates. Based on September 30, 2002, debt balances, floating rate indexes at the end of October 2002, our credit spread under our credit facilities and the combination of our fixed rate debt and current interest rate hedges, the average interest rate was approximately 6.2%, excluding non-use and facilities fees, which will vary based on usage and outstanding balance. Based on current amounts outstanding, we estimate these fees will average approximately $2.2 million per year. We have locked-in interest rates (excluding the credit spread under the credit facilities) for approximately 60% of our total debt for the next year, 50% for the next four years and 40% for the next ten years.

~~Contingencies~~Insurance.

~~Export License Matter~~. In our marketing and gathering activities, we import and export crude oil from and to Canada. Our exports of crude oil are licensed under two export licenses from the Bureau of Industry and Security (the “BIS”) of the U.S. Department of Commerce. We have determined that we may have exceeded the quantity of crude oil exports authorized by the licenses. Export of crude oil in excess of the authorized amounts is a violation of the Export Administration Regulations (“EAR”). On October 18, 2002, we submitted to the BIS an initial notification of voluntary disclosure. Upon completion of our internal inquiry, we will voluntarily submit additional information to the BIS. At this time, we have received no indication whether the BIS intends to charge us with a violation of the EAR or, if so, what penalties would be assessed. As a result, we cannot estimate the ultimate impact of these potential violations.

~~Pipeline and Storage Regulation.~~ We are subject to the U.S. Department of Transportation’s (the “DOT’s”) pipeline integrity rules, which require continual assessment of pipeline segments that could affect “high consequence areas.” Our compliance costs will vary from year to year based on the assessment priority placed on particular line segments. Based on currently available information, we estimate that such costs will average approximately $2.5 million per year in 2003 and 2004. Such amounts incorporate approximately $1 million per year associated with assets acquired in the Shell acquisition. We will continue to refine our estimates as data from initial assessments is collected.

The DOT has adopted API 653 as the standard for the inspection, repair, alteration and reconstruction of existing crude oil storage tanks subject to DOT jurisdiction (approximately 72% of our 21.3 million barrels). API 653 requires regularly scheduled inspection and repair of tanks remaining in service. Full compliance is required by 2009. We have commenced our compliance activities under the standard and, based on currently available information, we estimate that we will spend approximately $3 million per year in 2003 and 2004 in connection with these activities. Such amounts incorporate costs associated with assets acquired in the Shell acquisition. We will continue to refine our estimates as data from initial assessments is collected.

~~Other~~~~. A pipeline, terminal~~ Pipelines, terminals or other facilities may experience damage as a result of an accident or natural disaster. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. ~~We maintain~~Since the Partnership and its predecessors commenced midstream crude oil activities in the early 1990s, we have maintained insurance of various types and varying levels of coverage that we ~~consider~~considered adequate under the circumstances to cover our operations and properties. The insurance ~~covers all of our assets in amounts considered reasonable. The insurance~~ policies are subject to deductibles and retention levels that we consider reasonable and not excessive. ~~Our~~However, such insurance does not cover every potential risk associated with operating pipelines, terminals and other facilities, including the potential loss of significant revenues. ~~Consistent~~Over the last several years, our operations have expanded significantly, with total assets increasing approximately 200% since the end of 1998. At the same time that the scale and scope of our business activities have expanded, the breadth and depth of the available insurance ~~coverage generally available to~~markets have contracted. Notwithstanding what we believe is a favorable claims history, the ~~industry,~~overall cost of such insurance as well as the deductibles and overall retention levels that we maintain have increased. This trend was reinforced in connection with the renewal of our insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences. The events of September 11, 2001, and their overall effect on the insurance industry has had adverse impact on availability and cost of coverage. Due to these events, insurers have excluded acts of terrorism and sabotage from our insurance policies. On certain of our key assets, we purchased a separate insurance policy for acts of terrorism and sabotage.

Since the terrorist attacks, the United States Government has issued numerous warnings that energy assets (including our nation’s pipeline infrastructure) may be a future target of terrorist organizations. These developments expose our operations and assets to increased risks. Any future terrorist attacks on our facilities, those of our customers and,program in ~~some cases, those of our competitors, could have~~June 2003. Absent a material ~~adverse effect on our business whether insured or not.~~

~~The occurrence~~favorable change in available insurance markets, this trend of rising insurance-related costs is expected to continue as we continue to grow and expand. As a significant event not fully insured or indemnified against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. We believe that we are adequately insured for public liability and property damage to others with respect to our operations. With respect to all of our coverage, no assurance can be givenresult, it is anticipated that we will ~~be able~~elect to ~~maintain adequate insurance in the future at rates we consider reasonable.~~

self insure more activities against certain of these operating hazards.

Environmental.We may experience future releases of crude oil into the environment from our pipeline and storage operations, or discover past releases that were previously unidentified. Although we maintain an inspection program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to any such environmental releases from our assets may substantially affect our business.

~~Recent Accounting Pronouncements~~

In October 2002, the Emerging Issues Task Force (“EITF”) reached consensus on certain issues in EITF Issue No. 02-03, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts under Issues No. 98-10 and 00-17.” The consensus reached included i) rescinding EITF 98-10 and ii) the requirement that mark-to-market gains and losses on trading contracts (whether realized or unrealized and whether financially or physically settled) be shown net in the income statement. The EITF provided guidance that, beginning on October 25, 2002, all new contracts that would have been accounted for under EITF 98-10 should no longer be marked-to-market through earnings unless such contracts fall within the scope of SFAS 133. All of the contracts that we have accounted for under EITF 98-10 fall within the scope of SFAS 133 and therefore will continue to be marked-to-market through earnings under the provisions of that rule. Therefore, we do not We believe that ~~the adoption~~our reserve for environmental liabilities is adequate. However, no assurance can be given that any costs incurred in excess of this ~~rule will~~reserve would not have a material adverse effect on ~~either~~ our financial ~~position,~~condition, results of operations or cash flows.

~~In June 2002,~~ Other. Since the ~~Financial Accounting Standards Board (“FASB”~~terrorist attacks of September 11, 2001, the United States Government has issued numerous warnings that energy assets (including our nation's pipeline infrastructure) may be future targets of terrorist organizations. These developments expose our operations and assets to increased risks. We have instituted security measures and procedures in conformity with Department of Transportation ("DOT") ~~issued SFAS 146 “Accounting for Costs Associated with Exit~~guidance. We will institute, as appropriate, additional security measures or ~~Disposal Activities.” SFAS 146 requires that a liability for a cost associated with an exit~~procedures indicated by the DOT or ~~disposal activity be recognized when~~ the ~~obligation is incurred rather than at the date~~Transportation Safety Administration (an agency of the ~~exit plan. This Statement~~Department of Homeland Security, which is ~~effective for exit~~in the transitional phase of assuming responsibility from the DOT). We cannot assure you that these or ~~disposal activities that are initiated after December 31, 2002. We do not believe that the adoption~~any other security measures would protect our facilities from a concentrated attack. Any future terrorist attacks on our facilities, those of ~~SFAS 146 will~~our customers and, in some cases, those of our competitors, could have a material ~~effect on either our financial position, results of operations or cash flows.~~

In April 2002, the FASB issued SFAS 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” SFAS No. 145 rescinds, updates, clarifies and simplifies existing accounting pronouncements. Among other things, SFAS No. 145 rescinds SFAS No. 4, which required all gains and losses from extinguishment of debt to be aggregated and, if material, classified as an extraordinary item, net of related income tax effect. Under SFAS No. 145, the criteria in Accounting Principles Board No. 30 will now be used to classify those gains and losses. The adoption of this and the remaining provisions of SFAS 145 did not have a materialadverse effect on our business, whether insured or not.
The occurrence of a significant event not fully insured or indemnified against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial ~~position~~condition. We believe we are adequately insured for public liability and property damage to others with respect to our operations. We believe that our levels of coverage and retention are generally consistent with those of similarly situated companies in our industry. With respect to all of our coverage, no assurance can be given that we will be able to maintain adequate insurance in the future at rates we consider reasonable, or ~~results~~that we have established adequate reserves to the extent that such risks are not insured.
Industry Credit Markets and Accounts Receivable
Throughout the latter part of ~~operations. However, any future extinguishments~~2001 and all of ~~debt may impact income from continuing operations.~~

~~In June 2001,~~2002, there have been significant disruptions and extreme volatility in the ~~FASB issued SFAS 143 “Asset Retirement Obligations.” SFAS 143 establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including (1) the time~~financial markets and credit markets. Because of the ~~liability recognition, (2) initial measurement~~credit intensive nature of the ~~liability, (3) allocation~~energy industry and extreme financial distress at several large, diversified energy companies, the
46
energy industry has been especially impacted by these developments. Accordingly, we are exposed to an increased level of ~~asset retirement cost~~direct and indirect counterparty credit and performance risk.
The majority of our credit extensions relate to ~~expense, (4) subsequent measurement~~our gathering and marketing activities that can generally be described as high volume and low margin activities. In our credit approval process, we make a determination of the ~~liability and (5) financial statement disclosures. SFAS 143 requires that an asset retirement cost should be capitalized as part~~amount, if any, of the ~~cost~~line of credit to be extended to any given customer and the ~~related long-lived asset~~form and ~~subsequently allocated~~amount of financial performance assurances we require. Such financial assurances are commonly provided to expense using a systematic and rational method. We will adopt the statement effective January 1, 2003, as required. The transition adjustment resulting from the adoption of SFAS 143 will be reported as a cumulative effect of a change in accounting principle. Although we areus in the ~~process~~form of ~~evaluating the impact~~standby letters of ~~adoption,~~credit or advance cash payments. At September 30, 2003, we ~~cannot reasonably estimate the effect~~had received approximately $39.5 million of ~~the adoption~~advance cash payments from third parties to mitigate credit risk. These proceeds reduced our working capital requirements and were used to reduce long-term borrowings.
Recent Accounting Pronouncements
We continuously monitor and revise our accounting policies as our business and relevant accounting literature change. For further discussion of ~~this statement on either our financial position, results of operations or cash flows at this time.~~

new accounting rules, see Item 1. Consolidated Financial Statements—Note 11 "Recent Accounting Pronouncements."
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”~~"anticipate," "believe," "estimate," "expect," "plan," "intend" and ~~“forecast,”~~"forecast," and similar expressions and statements regarding our business strategy, plans and objectives 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 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 or combination opportunities;~~

•

~~successful integration and future performance of acquired assets;~~

•

~~continued creditworthiness of, and performance by, counterparties;~~

•

~~successful third party drilling efforts and completion of announced oil-sands projects;~~

•: 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 or combination opportunities;
•: successful integration and future performance of acquired assets;
•: continued creditworthiness of, and performance by, our counterparties;
•: conversion (or non-conversion) of our subordinated units into common units;
•: completion of the refinancing of our credit facilities;
•: 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;
•: shortages or cost increases of power supplies, materials or labor;
•: weather interference with business operations or project construction;

•

~~our levels of indebtedness and our ability to receive credit on satisfactory terms;~~

•

~~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 or insurance;~~

•

~~fluctuations in the debt and equity markets; and~~

•

~~general economic, market or business conditions.~~

47
•
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 or insurance;

•
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.
Other factors, ~~described herein,~~ such as the ~~recent disruption~~"Risk Factors Related to our Business" and the Recent Disruption in ~~industry credit markets~~Industry Credit Markets discussed in ~~Liquidity and Capital Resources and in Note 6 to the financial statements~~Item 7 of our most recent annual report on Form 10-K or factors that are unknown or unpredictable, could also have a material adverse effect on future results. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

The ~~information required herein is~~following should be read in conjunction with Quantitative and Qualitative Disclosures About Market Risks included in ~~Note 2~~Item 7A. in our 2002 Form 10-K. There have not been any material changes in that information other than those discussed below.

As of September 30, 2003 and December 31, 2002 the ~~Notes to~~fair value of our crude oil futures contracts was approximately $30.6 million and $0.6 million respectively. A 10% price decrease would result in a decrease in fair value of $12.0 million and $4.3 million at September 30, 2003 and December 31, 2002, respectively.

During the ~~Consolidated Financial Statements.~~

first quarter of 2003, we converted a $50.0 million treasury lock into a 10-year LIBOR based swap that becomes effective in March 2004, contemporaneously with the expiration of an existing $50.0 million LIBOR based swap. At September 30, 2003, the fair value of our interest rate risk hedging instruments was a liability of approximately $10.5 million with $0.7 million maturing in 2004, $4.5 million in 2006 and $5.3 million in 2014.
        As of September 30, 2003, the fair value of our currency exchange rate risk hedging instruments was a liability of approximately $4.0 million with $0.3 million maturing during 2003 and the remainder in 2006.

Item 4. CONTROLS AND PROCEDURES
~~Under Exchange Act Rule 13a-15, which became effective August 29, 2002, we are required to~~
        We maintain ~~“disclosure~~written "disclosure controls and procedures,~~” as defined in Exchange Act Rule 13a-14(c). As a result of the rule, we have formalized our disclosure practices into a written “disclosure controls and procedures,”~~" which we refer to as our ~~“DCP.”~~"DCP." The purpose of our DCP is to ~~ensure~~provide reasonable assurance that (i) information is recorded, processed, summarized and reported in time to allow for timely disclosure of such information in accordance with the securities laws and SEC regulations and (ii) information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow for timely decisions regarding required disclosure. Our DCP is incremental to our system of internal accounting controls designed to comply with the requirements of Section 13(b)(2) of the Exchange Act.
~~Exchange Act Rule 13a-15 also requires~~
        Applicable SEC rules require an evaluation of the effectiveness of the design and operation of our DCP, ~~within the 90-day period prior to filing any 10-Q or 10-K,~~as of September 30, 2003, under the supervision and with the participation of our management, including our Chief Executive ~~Office~~Officer and Chief Financial Officer. Management (including our Chief Executive Officer and Chief Financial Officer) has evaluated the effectiveness of the design and operation of our DCP ~~within the last 90 days,~~as of September 30, 2003, and ~~have~~has found our DCP to be effective in ~~producing~~providing reasonable assurance of the timely recording, processing, summarization and reporting of information, and in accumulation and communication of information to management to allow for timely decisions with regard to required disclosure.
48
In addition to the information concerning our DCP, we are required to ~~discuss significant~~disclose certain changes in our internal ~~controls.~~control over financial reporting. There ~~were~~was no ~~significant changes~~change in our internal ~~controls~~control over financial reporting that occurred during the third quarter and that has materially affected, or ~~in other factors that could significantly~~is reasonably likely to materially affect, ~~these controls subsequent to the last date of their evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.~~
~~We have recently commenced an effort to consolidate~~ our internal ~~auditing activities into a centralized function,~~control over financial reporting.
        The certifications of our Chief Executive Officer and ~~have hired a director~~Chief Financial Officer pursuant to Exchange Act rules 13a-14(a) and 15d-14(a) are filed with this report as exhibits 31.1 and 31.2. The certifications of ~~internal auditing~~our Chief Executive Officer and Chief Financial Officer pursuant to ~~oversee that function. As we complete the consolidation of these activities over the next several months, we will make any additional enhancements to our controls~~18 U.S.C. §1350 are furnished with this report as exhibits 32.1 and ~~procedures that are deemed appropriate.~~
32.2.

PART II. OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS
~~Export License Matter~~.    In our marketing and gathering activities, we import and export crude oil from and to Canada. Our exports of crude oil are licensed under two export licenses from the Bureau of Industry and Security (the “BIS”) of the U.S. Department of Commerce. We have determined that we may have exceeded the quantity of crude oil exports authorized by the licenses. Export of crude oil in excess of the authorized amounts is a violation of the Export Administration Regulations (“EAR”). On October 18, 2002, we submitted to the BIS an initial notification of voluntary disclosure. Upon completion of our internal inquiry, we will voluntarily submit additional information to the BIS. At this time, we have received no indication whether the BIS intends to charge us with a violation of the EAR or, if so, what penalties would be assessed. As a result, we cannot estimate the ultimate impact of these potential violations.
~~Other~~.
        We, in the ordinary course of business, are a claimant and/or a defendant in various ~~other~~ legal proceedings. We do not believe that the outcome of these ~~other~~ legal proceedings, individually ~~and~~or in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.

Item 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
None

~~Item.~~Item 3. DEFAULTS UPON SENIOR SECURITIES
None

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None

Item 5. OTHER INFORMATION
None
49

Item 6. EXHIBITS AND REPORTS ON FORM 8-K
A. Exhibits

3.1

Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC dated June 8, 2001, as amended by the First Amendment dated September 16, 2003
~~4.1~~

~~Indenture dated as~~
31.1

Certification of ~~September 25, 2002.~~Principal Executive Officer pursuant to Exchange Act rules 13a-14(a) and 15d-14(a)

31.2

Certification of Principal Financial Officer pursuant to Exchange Act rules 13a-14(a) and 15d-14(a)
~~4.2~~

~~First Supplemental Indenture dated as of September 25, 2002.~~
~~4.3~~
32.1
~~Registration Rights Agreement dated September 25, 2002.~~
~~99.1~~
Certification of Chief Executive Officer ~~of Plains All American Pipeline, L.P.~~ pursuant to 18 U.S.C. ~~Section~~§ 1350.
~~99.2~~

32.2

Certification of Chief Financial Officer ~~of Plains All American Pipeline, L.P.~~ pursuant to 18 U.S.C. ~~Section 1350.~~§ 1350
B. Reports on Form 8-K.
A current report on Form ~~8-K was filed on November 8, 2002, including as an exhibit the balance sheet of Plains AAP, L.P. as of June 30, 2002.~~
8-K/A ~~current report on Form 8-KA~~ was furnished on ~~November 5, 2002,~~October 29, 2003, to correct certain information in the Form 8-K furnished on October ~~29, 2002, 8-K.~~
28, 2003.
A current report on Form 8-K was furnished on October ~~29, 2002,~~28, 2003, in connection with disclosure of fourth quarter ~~estimates~~2003 projections and earnings ~~guidance.~~
guidance and preliminary guidance for certain aspects of financial performance for 2004.
        A current report on Form 8-K was furnished on October 7, 2003, in connection with the disclosure of our presentation at Independent Petroleum Association of America's 2003 Oil & Gas Investment Symposium West.
        A current report on Form 8-K was furnished on September 24, 2003, in connection with the disclosure of our presentation at Herold's 12^th Annual Pacesetters Energy Conference.
        A current report on Form 8-K was furnished on September 16, 2003, in connection with the disclosure of our presentation at the RBC Capital Markets 2003 North American Energy and Power Conference.
        A current report on Form 8-K was filed on September 10, 2003, including as an exhibit an underwriting agreement with Citigroup Global Markets Inc., Lehman Brothers Inc., UBS Securities LLC, A.G. Edwards & Sons, Inc., Wachovia Capital Markets, LLC and RBC Dain Rauscher Inc. in connection with the sale by the Partnership of 3,250,000 common units of the Partnership.
        A current report on Form 8-K was furnished on September 8, 2003, in connection with disclosure of our planned sale of common units pursuant to an effective shelf registration on Form S-3 previously filed with the Securities and Exchange Commission.
A current report on Form 8-K was filed on August 21, ~~2002,~~2003, including as an exhibit ~~an underwriting agreement with Goldman, Sachs & Co., Lehman Brothers Inc., Salomon Smith Barney Inc., UBS Warburg LLC, A.G. Edwards & Sons, Inc. and Wachovia Securities, Inc. in connection with~~ the ~~sale by the Partnership~~unaudited balance sheet of ~~5,500,000 common units~~Plains AAP, L.P. as of ~~the Partnership.~~
June 30, 2003.
A current report on Form 8-K was ~~filed~~furnished on August ~~15, 2002, including as exhibits consents of PricewaterhouseCoopers LLP.~~
~~A current report on Form 8-K was filed on August 9, 2002,~~5, 2003, in connection with disclosure of our presentation at the ~~certification by the Chief Executive Officer and the Chief Financial Officer pursuant to SEC Order 4-460.~~
~~A current report on Form 8-K was filed on August 9, 2002, in connection with the acquisition of assets from Shell Pipeline Company LP and Equilon Enterprises LLC.~~
Enercom 8th Annual Oil & Gas Conference.
A current report on Form 8-K was furnished on July ~~24, 2002,~~29, 2003, in connection with disclosure of third quarter ~~estimates~~and full year 2003 projections and earnings ~~guidance.~~
guidance and preliminary guidance for certain aspects of financial performance for 2004.
50

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 and thereunto duly authorized.
~~PLAINS ALL AMERICAN PIPELINE, L.P.~~
~~By:    PLAINS AAP, L.P., its general partner~~
~~By:    PLAINS ALL AMERICAN GP LLC,~~
          ~~its general partner~~
~~Date:    November 11, 2002~~
~~By:    /s/    PHILLIP~~ ~~D. KRAMER~~
~~Phillip D. Kramer, Executive Vice President and Chief Financial Officer~~
~~(Principal Financial and Accounting Officer)~~
~~Date:    November 11, 2002~~
~~By:    /s/    GREG~~ ~~L. ARMSTRONG~~
~~Greg L. Armstrong, Chairman of the Board, Chief Executive Officer and Director of Plains~~
~~All American GP LLC (Principal Executive~~
    ~~Officer)~~
~~CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER~~
~~PLAINS ALL AMERICAN PIPELINE, L.P.~~
~~I, Greg L. Armstrong, certify that:~~
1. PLAINS ALL AMERICAN PIPELINE, L.P.

~~I have reviewed this quarterly report on Form 10-Q~~

By:

PLAINS AAP, L.P., its general partner

By:

PLAINS ALL AMERICAN GP LLC,
its general partner

Date: November 7, 2003

By:

/s/ GREG L. ARMSTRONG
Greg L. Armstrong, Chairman of the Board,
Chief Executive Officer and Director of Plains
All American ~~Pipeline, L.P.;~~GP LLC
(Principal Executive Officer)

Date: November 7, 2003

By:

/s/ PHIL KRAMER
Phil Kramer, Executive Vice President
and Chief Financial Officer
(Principal Financial and Accounting Officer)

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
b) ~~evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and~~
c) ~~presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;~~
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) ~~any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and~~
6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
~~Date: November 11, 2002~~
~~/s/    GREG~~ ~~L. ARMSTRONG~~
~~Greg L. Armstrong~~
~~Chief Executive Officer~~
~~CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER~~
~~PLAINS ALL AMERICAN PIPELINE, L.P.~~
~~I, Phillip D. Kramer, certify that:~~
1. ~~I have reviewed this quarterly report on Form 10-Q of Plains All American Pipeline, L.P.;~~
2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;
4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
b) ~~evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and~~
c) ~~presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;~~
5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
b) ~~any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and~~
6. The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
~~Date: November 11, 2002~~
~~/s/    PHILLIP~~ ~~D. KRAMER~~
~~Phillip D. Kramer~~
~~Chief Financial Officer~~
35

Delaware		~~76-0582150~~
(State or other jurisdiction of incorporation or organization)		76-0582150 (I.R.S. Employer Identification No.)
333 Clay Street, Suite 1600 Houston, Texas 77002 (Address of principal executive offices) (Zip Code)
(713) 646-4100 (Registrant's telephone number, including area code)

			Page
PART I. FINANCIAL INFORMATION

Item 1. CONSOLIDATED FINANCIAL STATEMENTS:
Consolidated Balance Sheets:

September 30, ~~2002,~~2003, and December 31, ~~2001~~2002	3
Consolidated Statements of Operations:

For the three months and nine months ended September 30, ~~2002~~2003 and ~~2001~~2002	4
Consolidated Statements of Cash Flows:

For the nine months ended September 30, ~~2002~~2003 and ~~2001~~2002	5
Consolidated Statement of ~~Partners’~~Partners' Capital:

For the nine months ended September 30, ~~2002~~2003	6
Consolidated Statements of Comprehensive Income:

For the three months and nine months ended September 30, ~~2002~~2003 and ~~2001~~2002	7
Consolidated Statement of Changes in Accumulated Other Comprehensive Income:

For the nine months ended September 30, ~~2002~~2003	7
Notes to the Consolidated Financial Statements		8

Item 2. ~~MANAGEMENT’S~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	17 22

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS	30 48

Item 4. CONTROLS AND PROCEDURES	30 48

PART II. OTHER INFORMATION

Item 1. Legal Proceedings	31 49

Item 2. Changes in Securities and Use of Proceeds	31 49

Item 3. Defaults Upon Senior Securities	31 49

Item 4. Submission of Matters to a Vote of Security Holders	31 49

Item 5. Other Information	31 49

Item 6. Exhibits and Reports on Form 8-K	31 50

Signatures	33

~~Certification of Principal Executive Officer~~	34

~~Certification of Principal Financial Officer~~	35 51

	September 30, 2002			December 31, 2001
	(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	4,306		$	3,511
Accounts receivable and other current assets		496,857			365,697
Inventory		81,189			188,874

Total current assets		582,352			558,082

PROPERTY AND EQUIPMENT		1,012,814			653,050
Less allowance for depreciation and amortization		(67,900	)		(48,131	)

		944,914			604,919

OTHER ASSETS
Pipeline linefill		51,416			57,367
Other, net		52,808			40,883

		104,224			98,250

	$	1,631,490		$	1,261,251


LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES
Accounts payable and other current liabilities	$	468,988		$	386,993
Due to related parties		25,580			13,685
Short-term debt		105,577			101,482

Total current liabilities		600,145			502,160

LONG-TERM LIABILITIES
Long-term debt under credit facilities		309,453			354,677
Senior notes, net of unamortized discount of $400		199,600			—
Other long-term liabilities and deferred credits		4,317			1,617

Total liabilities		1,113,515			858,454

COMMITMENTS AND CONTINGENCIES (NOTE 8)

PARTNERS’ CAPITAL
Common unitholders (38,240,939 and 31,915,939 units outstanding at September 30, 2002, and December 31, 2001, respectively)		529,488			408,562
Class B common unitholders (1,307,190 units outstanding at each date )		18,621			19,534
Subordinated unitholders (10,029,619 units outstanding at each date)		(45,900	)		(38,891	)
General partner		15,766			13,592

Total partners’ capital		517,975			402,797

	$	1,631,490		$	1,261,251

		September 30, 2003			December 31, 2002
		(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	3,418		$	3,501
Trade accounts receivable, net			350,916			499,909
Inventory			162,202			81,849
Other current assets			47,692			17,676

	Total current assets		564,228			602,935

PROPERTY AND EQUIPMENT			1,181,944			1,030,303
Accumulated depreciation			(109,873	)		(77,550	)

			1,072,071			952,753

OTHER ASSETS
Pipeline linefill			109,481			62,558
Other, net			64,362			48,329

	Total assets	$	1,810,142		$	1,666,575

LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Accounts payable and accrued liabilities		$	524,866		$	488,922
Due to related parties			24,182			23,301
Short-term debt			35,141			99,249
Other current liabilities			45,342			25,777

	Total current liabilities		629,531			637,249

LONG-TERM LIABILITIES
Long-term debt under credit facilities, including current maturities of $8,000 and $9,000, respectively			254,100			310,126
Senior notes, net of unamortized discount of $360 and $390, respectively			199,640			199,610
Other long-term liabilities and deferred credits			21,483			7,980

	Total liabilities		1,104,754			1,154,965

COMMITMENTS AND CONTINGENCIES (NOTE 9)
PARTNERS' CAPITAL
Common unitholders (44,135,939 and 38,240,939 units outstanding at September 30, 2003, and December 31, 2002, respectively)			704,387			524,428
Class B common unitholder (1,307,190 units outstanding at each date)			19,171			18,463
Subordinated unitholders (10,029,619 units outstanding at each date)			(41,676	)		(47,103	)
General partner			23,506			15,822

	Total partners' capital		705,388			511,610

		$	1,810,142		$	1,666,575

	Three Months Ended September 30,						Nine Months Ended September 30,
	2002			2001			2002			2001
	(unaudited)
REVENUES	$	2,344,089		$	2,191,310		$	5,874,759		$	5,298,051
COST OF SALES AND OPERATIONS		2,299,823			2,151,666			5,750,398			5,189,288

Gross Margin		44,266			39,644			124,361			108,763

EXPENSES
General and administrative		11,512			10,297			33,389			34,327
Depreciation and amortization		8,981			6,402			23,125			17,575

Total expenses		20,493			16,699			56,514			51,902

OPERATING INCOME		23,773			22,945			67,847			56,861
Interest expense		(7,368	)		(7,775	)		(20,175	)		(22,482	)
Interest and other income (expense)		(88	)		(9	)		(123	)		356

Income before cumulative effect of accounting change		16,317			15,161			47,549			34,735
Cumulative effect of accounting change		—			—			—			508

NET INCOME	$	16,317		$	15,161		$	47,549		$	35,243

NET INCOME—LIMITED PARTNERS	$	15,159		$	14,536		$	44,515		$	34,019

NET INCOME—GENERAL PARTNER	$	1,158		$	625		$	3,034		$	1,224

BASIC AND DILUTED NET INCOME PER LIMITED PARTNER UNIT
Income before cumulative effect of accounting change	$	0.33		$	0.38		$	1.01		$	0.93
Cumulative effect of accounting change		—			—			—			0.01

Net income	$	0.33		$	0.38		$	1.01		$	0.94

WEIGHTED AVERAGE UNITS OUTSTANDING		46,027			38,353			44,188			36,156

¨For the quarterly period ended September 30, 2003
OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	Common Units				Class B Common Units				Subordinated Units				General Partner Amount			Total Partners’ Capital Amount
	Units	Amount			Units	Amount			Units	Amount			General Partner Amount			Total Partners’ Capital Amount
	(unaudited)
Balance at December 31, 2001	31,916	$	408,562		1,307	$	19,534		10,030	$	(38,891	)	$	13,592		$	402,797
Issuance of common units	6,325		142,013		—		—		—		—			3,033			145,046
Distributions	—		(50,267	)	—		(2,059	)	—		(15,797	)		(3,519	)		(71,642	)
Accumulated other comprehensive income	—		(4,030	)	—		(158	)	—		(1,213	)		(374	)		(5,775	)
Net income	—		33,210		—		1,304		—		10,001			3,034			47,549

Balance at September 30, 2002	38,241	$	529,488		1,307	$	18,621		10,030	$	(45,900	)	$	15,766		$	517,975

	Common Unitholders				Class B Common Unitholder				Subordinated Unitholders
																Total Partners' Capital Amount
													General Partner Amount
	Units	Amounts			Units	Amounts			Units	Amounts			General Partner Amount
	(unaudited)
Balance at December 31, 2002	38,241	$	524,428		1,307	$	18,463		10,030	$	(47,103	)	$	15,822		$	511,610
Issuance of common units	5,895		158,516		—		—		—		—			3,389			161,905
Distributions	—		(65,527	)	—		(2,141	)	—		(16,423	)		(5,255	)		(89,346	)
Other comprehensive income	—		44,168		—		1,446		—		11,097			4,888			61,599
Net income	—		42,802		—		1,403		—		10,753			4,662			59,620

Balance at September 30, 2003	44,136	$	704,387		1,307	$	19,171		10,030	$	(41,676	)	$	23,506		$	705,388

	Net Deferred Loss on Derivative Instruments			Currency Translation Adjustments			Total
	(unaudited)
Beginning balance at December 31, 2001	$	(4,740	)	$	(8,002	)	$	(12,742	)
Current year activity
Reclassification adjustments for settled contracts		3,185			—			3,185
Changes in fair value of outstanding hedge positions		(9,531	)		—			(9,531	)
Currency translation adjustment		—			571			571

Total current year activity		(6,346	)		571			(5,775	)

Ending balance at September 30, 2002	$	(11,086	)	$	(7,431	)	$	(18,517	)

			Net Deferred Gain (Loss) on Derivative Instruments			Currency Translation Adjustments			Total
			(unaudited)
Balance at December 31, 2002			$	(8,207	)	$	(6,219	)	$	(14,426	)
	Current period activity
		Reclassification adjustments for settled contracts		(6,570	)		—			(6,570	)
		Changes in fair value of outstanding hedge positions		32,784			—			32,784
		Currency translation adjustment		—			35,385			35,385

	Total period activity			26,214			35,385			61,599

Balance at September 30, 2003			$	18,007		$	29,166		$	47,173

	Pipeline		Gathering, Marketing, Terminalling & Storage		Total
	(in millions)
Three Months Ended September 30, 2002
Revenues:
External customers	$	123.4	$	2,220.7	$	2,344.1
Intersegment (a)		7.0		—		7.0

Total revenues	$	130.4	$	2,220.7	$	2,351.1

Gross margin (b)	$	23.0	$	21.3	$	44.3
General and administrative expenses (c)		3.2		8.3		11.5

Gross profit (d)	$	19.8	$	13.0	$	32.8

Maintenance capital	$	0.5	$	0.7	$	1.2


Three Months Ended September 30, 2001
Revenues:
External customers	$	88.8	$	2,102.5	$	2,191.3
Intersegment (a)		4.5		—		4.5

Total revenues	$	93.3	$	2,102.5	$	2,195.8

Gross margin (b)	$	16.1	$	23.5	$	39.6
General and administrative expenses (c)		2.9		7.4		10.3

Gross profit (d)	$	13.2	$	16.1	$	29.3

Maintenance capital	$	0.4	$	0.2	$	0.6


Nine Months Ended September 30, 2002
Revenues:
External customers	$	320.2	$	5,554.6	$	5,874.8
Intersegment (a)		13.9		—		13.9

Total revenues	$	334.1	$	5,554.6	$	5,888.7

Gross margin (b)	$	60.3	$	64.1	$	124.4
General and administrative expenses (c)		9.3		24.1		33.4

Gross profit (d)	$	51.0	$	40.0	$	91.0

Maintenance capital	$	2.7	$	1.3	$	4.0


Nine Months Ended September 30, 2001
Revenues:
External customers	$	268.7	$	5,029.4	$	5,298.1
Intersegment (a)		12.9		—		12.9

Total revenues	$	281.6	$	5,029.4	$	5,311.0

Gross margin (b)	$	48.3	$	60.5	$	108.8
General and administrative expenses (c)		8.3		20.3		28.6

Gross profit (d)	$	40.0	$	40.2	$	80.2

Maintenance capital	$	0.5	$	2.4	$	2.9

			Pipeline			Gathering, Marketing, Terminalling & Storage			Total
			(in millions)
Three Months Ended September 30, 2003
Revenues:
	External Customers		$	148.3		$	2,905.3		$	3,053.6
	Intersegment⁽¹⁾			16.1			0.2			16.3

		Total revenues of reportable segments		164.4			2,905.5			3,069.9

Gross margin (excluding depreciation)				30.1			20.6			50.7
General and administrative expenses⁽²⁾				(7.2	)		(11.0	)		(18.2	)

Gross profit (excluding depreciation)			$	22.9		$	9.6		$	32.5

LTIP accrual⁽³⁾			$	(3.0	)	$	(4.4	)	$	(7.4	)

Noncash SFAS 133 impact⁽⁴⁾			$	—		$	(2.9	)	$	(2.9	)

Maintenance capital			$	1.0		$	0.3		$	1.3

Three Months Ended September 30, 2002
Revenues:
	External Customers		$	123.4		$	2,220.7		$	2,344.1
	Intersegment⁽¹⁾			7.0			—			7.0

		Total revenues of reportable segments		130.4			2,220.7			2,351.1

Gross margin (excluding depreciation)				23.0			21.3			44.3
General and administrative expenses⁽²⁾				(3.3	)		(8.2	)		(11.5	)

Gross profit (excluding depreciation)			$	19.7		$	13.1		$	32.8

Noncash SFAS 133 impact⁽⁴⁾			$	—		$	(0.4	)	$	(0.4	)

Maintenance capital			$	0.5		$	0.7		$	1.2

			Pipeline			Gathering, Marketing, Terminalling & Storage			Total
			(in millions)
Nine Months Ended September 30, 2003
Revenues:
	External Customers		$	450.6		$	8,594.1		$	9,044.7
	Intersegment⁽¹⁾			38.5			0.7			39.2

		Total revenues of reportable segments		489.1			8,594.8			9,083.9

Gross margin (excluding depreciation)				83.5			80.0			163.5
General and administrative expenses⁽²⁾				(16.3	)		(27.1	)		(43.4	)

Gross profit (excluding depreciation)			$	67.2		$	52.9		$	120.1

LTIP accrual⁽³⁾			$	(3.0	)	$	(4.4	)	$	(7.4	)

Noncash SFAS 133 impact⁽⁴⁾			$	—		$	(1.7	)	$	(1.7	)

Maintenance capital			$	4.8		$	0.7		$	5.5

Nine Months Ended September 30, 2002
Revenues:
	External Customers		$	320.2		$	5,554.6		$	5,874.8
	Intersegment⁽¹⁾			13.9			—			13.9

		Total revenues of reportable segments		334.1			5,554.6			5,888.7

Gross margin (excluding depreciation)				60.3			64.1			124.4
General and administrative expenses⁽²⁾				(9.9	)		(23.5	)		(33.4	)

Gross profit (excluding depreciation)			$	50.4		$	40.6		$	91.0

Noncash SFAS 133 impact⁽⁴⁾			$	—		$	(2.1	)	$	(2.1	)

Maintenance capital			$	2.7		$	1.3		$	4.0

Calendar Year	Payment
2003	$	9.0
2004		10.0
2005		10.0
2006		78.0
2007		190.0

Total	$	297.0

	3.1	Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC dated June 8, 2001, as amended by the First Amendment dated September 16, 2003
~~4.1~~	~~Indenture dated as~~ 31.1	Certification of ~~September 25, 2002.~~Principal Executive Officer pursuant to Exchange Act rules 13a-14(a) and 15d-14(a)
	31.2	Certification of Principal Financial Officer pursuant to Exchange Act rules 13a-14(a) and 15d-14(a)
~~4.2~~	~~First Supplemental Indenture dated as of September 25, 2002.~~

~~4.3~~ 32.1	~~Registration Rights Agreement dated September 25, 2002.~~

~~99.1~~	Certification of Chief Executive Officer ~~of Plains All American Pipeline, L.P.~~ pursuant to 18 U.S.C. ~~Section~~§ 1350.

~~99.2~~	32.2	Certification of Chief Financial Officer ~~of Plains All American Pipeline, L.P.~~ pursuant to 18 U.S.C. ~~Section 1350.~~§ 1350

	1.	PLAINS ALL AMERICAN PIPELINE, L.P.
	~~I have reviewed this quarterly report on Form 10-Q~~	By:	PLAINS AAP, L.P., its general partner
		By:	PLAINS ALL AMERICAN GP LLC, its general partner
Date: November 7, 2003		By:	/s/ GREG L. ARMSTRONG Greg L. Armstrong, Chairman of the Board, Chief Executive Officer and Director of Plains All American ~~Pipeline, L.P.;~~GP LLC (Principal Executive Officer)
Date: November 7, 2003		By:	/s/ PHIL KRAMER Phil Kramer, Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)