10-Q 1 a2156670z10-q.htm 10-Q
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2005
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number: 1-14569

PLAINS ALL AMERICAN PIPELINE, L.P.
(Exact name of registrant as specified in its charter)

Delaware		76-0582150
(State or other jurisdiction of incorporation or organization)		(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)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes /x/ No / /

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes ý No o

At May 2, 2005, there were outstanding 67,868,108 Common Units.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

TABLE OF CONTENTS

		Page
PART I. FINANCIAL INFORMATION
Item 1. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS:
Consolidated Balance Sheets:
	March 31, 2005 and December 31, 2004	3
Consolidated Statements of Operations:
	For the three months ended March 31, 2005 and 2004	4
Consolidated Statements of Cash Flows:
	For the three months ended March 31, 2005 and 2004	5
Consolidated Statement of Partners' Capital:
	For the three months ended March 31, 2005	6
Consolidated Statements of Comprehensive Income:
	For the three months ended March 31, 2005 and 2004	7
Consolidated Statement of Changes in Accumulated Other Comprehensive Income:
	For the three months ended March 31, 2005	7
Notes to the Consolidated Financial Statements		8
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		18
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS		33
Item 4. CONTROLS AND PROCEDURES		34
PART II. OTHER INFORMATION
Item 1. Legal Proceedings		36
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		37
Item 3. Defaults Upon Senior Securities		37
Item 4. Submission of Matters to a Vote of Security Holders		37
Item 5. Other Information		37
Item 6. Exhibits		37
Signatures		38

PART I. FINANCIAL INFORMATION

Item 1. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except unit data)

		March 31, 2005			December 31, 2004
		(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	21,839		$	12,988
Trade accounts receivable, net			1,030,139			521,785
Inventory			711,280			498,200
Other current assets			82,510			68,229

	Total current assets		1,845,768			1,101,202

PROPERTY AND EQUIPMENT			1,977,606			1,911,509
Accumulated depreciation			(201,657	)		(183,887	)

			1,775,949			1,727,622

OTHER ASSETS
Pipeline linefill in owned assets			166,147			168,352
Inventory in third party assets			55,271			59,279
Other, net			91,067			103,956

	Total assets	$	3,934,202		$	3,160,411

LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Accounts payable		$	1,270,276		$	850,912
Due to related parties			35,277			32,897
Short-term debt			560,962			175,472
Other current liabilities			94,801			54,436

	Total current liabilities		1,961,316			1,113,717

LONG-TERM LIABILITIES
Long-term debt under credit facilities and other			132,880			151,753
Senior notes, net of unamortized discount of $2,640 and $2,729, respectively			797,360			797,271
Other long-term liabilities and deferred credits			32,089			27,466

	Total liabilities		2,923,645			2,090,207

COMMITMENTS AND CONTINGENCIES (NOTE 9)
PARTNERS' CAPITAL
Common unitholders (67,868,108 and 62,740,218 units outstanding at March 31, 2005, and December 31, 2004, respectively)			980,569			919,826
Class B common unitholder (no units and 1,307,190 units outstanding at March 31, 2005 and December 31, 2004, respectively)			—			18,775
Class C common unitholders (no units and 3,245,700 units outstanding at March 31, 2005 and December 31, 2004, respectively)			—			100,423
General partner			29,988			31,180

	Total partners' capital		1,010,557			1,070,204

		$	3,934,202		$	3,160,411

The accompanying notes are an integral part of these consolidated financial statements.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit data)

		Three Months Ended March 31,
		2005			2004
		(unaudited)
REVENUES
Crude oil and LPG sales (includes approximately $3,419,049 and $1,834,857, respectively, related to buy/sell transactions)		$	6,417,789		$	3,623,482
Other gathering, marketing, terminalling and storage revenues			8,173			7,621
Pipeline margin activities revenues (includes approximately $33,508 and $46,424, respectively, related to buy/sell transactions)			157,627			142,335
Pipeline tariff activities revenues			54,907			31,206

	Total revenues		6,638,496			3,804,644
COSTS AND EXPENSES
Crude oil and LPG purchases and related costs (includes purchases of approximately $3,397,536 and $1,791,634, respectively, related to buy/sell transactions)			6,334,646			3,557,071
Pipeline margin activities purchases (includes approximately $31,499 and $44,343, respectively, related to buy/sell transactions)			151,514			136,434
Field operating costs (excluding LTIP charge)			63,476			37,816
LTIP charge—operations			344			567
General and administrative expenses (excluding LTIP charge)			20,216			15,478
LTIP charge—general and administrative			1,895			3,661
Depreciation and amortization			19,118			13,120

	Total costs and expenses		6,591,209			3,764,147

OPERATING INCOME			47,287			40,497

OTHER INCOME (EXPENSE)
Interest expense (net of capitalized interest of $620 and $178, respectively)			(14,558	)		(9,532	)
Interest and other income (expense), net			79			41

Income before cumulative effect of change in accounting principle			32,808			31,006
Cumulative effect of change in accounting principle			—			(3,130	)

NET INCOME		$	32,808		$	27,876

NET INCOME—LIMITED PARTNERS		$	29,265		$	25,707

NET INCOME—GENERAL PARTNER		$	3,543		$	2,169

BASIC NET INCOME PER LIMITED PARTNER UNIT
Income before cumulative effect of change in accounting principle		$	0.43		$	0.49
Cumulative effect of change in accounting principle			—			(0.05	)

Basic net income per limited partner unit		$	0.43		$	0.44

DILUTED NET INCOME PER LIMITED PARNTER UNIT
Income before cumulative effect of change in accounting principle		$	0.43		$	0.49
Cumulative effect of change in accounting principle			—			(0.05	)

Diluted net income per limited partner unit		$	0.43		$	0.44

BASIC WEIGHTED AVERAGE UNITS OUTSTANDING			67,517			58,414

DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING			68,156			59,017

The accompanying notes are an integral part of these consolidated financial statements.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)

			Three Months Ended March 31,
			2005			2004
			(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income			$	32,808			27,876
Adjustments to reconcile to cash flows from operating activities:
	Depreciation and amortization			19,118			13,120
	Cumulative effect of change in accounting principle			—			3,130
	Change in derivative fair value			13,406			(7,498	)
	LTIP charge			2,239			4,228
	Noncash amortization of terminated interest rate swap			387			357
	Noncash loss on foreign currency revaluation			544			410
Changes in assets and liabilities, net of acquisitions:
	Trade accounts receivable and other			(554,814	)		34,620
	Inventory			(208,035	)		32,473
	Accounts payable and other current liabilities			420,145			24,711
	Due to related parties			2,353			(446	)

		Net cash provided by (used in) operating activities		(271,849	)		132,981

CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions				(13,467	)		(143,228	)
Additions to property and equipment				(50,011	)		(13,325	)
Proceeds from sales of assets				1,758			650

		Net cash used in investing activities		(61,720	)		(155,903	)

CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings/(repayments) on long-term revolving credit facility				(18,290	)		168,720
Net borrowings/(repayments) on working capital revolving credit facility				41,800			(11,200	)
Net borrowings/(repayments) on short-term letter of credit and hedged inventory facility				344,600			(100,491	)
Net proceeds from the issuance of common units				22,308			88
Distributions paid to unitholders and general partner				(45,005	)		(35,174	)
Other financing activities				(2,849	)		(879	)

		Net cash provided by financing activities		342,564			21,064

Effect of translation adjustment on cash				(144	)		(242	)
Net increase (decrease) in cash and cash equivalents				8,851			(2,100	)
Cash and cash equivalents, beginning of period				12,988			4,137

Cash and cash equivalents, end of period			$	21,839		$	2,037

Cash paid for interest, net of amounts capitalized			$	13,198		$	2,150

The accompanying notes are an integral part of these consolidated financial statements.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL
(in thousands)

					Class B Common Units					Class C Common Units
	Common Units																		Total Partners' Capital Amount
	Common Units														General Partner Amount			Total Units
	Units	Amount			Units		Amount			Units		Amount			General Partner Amount			Total Units
	(unaudited)
Balance at December 31, 2004	62,740	$	919,826		1,307		$	18,775		3,246		$	100,423		$	31,180		67,293	$	1,070,204
Private placement of common units	575		21,860		—			—		—			—			448		575		22,308
Conversion of Class B Units	1,307		18,323		(1,307	)		(18,323	)	—			—			—		—		—
Conversion of Class C Units	3,246		99,302		—			—		(3,246	)		(99,302	)		—		—		—
Distributions	—		(38,428	)	—			(801	)	—			(1,988	)		(3,788	)	—		(45,005	)
Net income	—		27,356		—			548		—			1,361			3,543		—		32,808
Other comprehensive income	—		(67,670	)	—			(199	)	—			(494	)		(1,395	)	—		(69,758	)

Balance at March 31, 2005	67,868	$	980,569		—		$	—		—		$	—		$	29,988		67,868	$	1,010,557

The accompanying notes are an integral part of these consolidated financial statements.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME AND
CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME
(in thousands)

Statements of Comprehensive Income

	Three Months Ended March 31,
	2005			2004
	(unaudited)
Net income	$	32,808		$	27,876
Other comprehensive income (loss)		(69,758	)		(10,814	)

Comprehensive income (loss)	$	(36,950	)	$	17,062

Statement of Changes in Accumulated Other Comprehensive Income

			Net Deferred Gain (Loss) on Derivative Instruments			Currency Translation Adjustments			Total
			(unaudited)
Balance at December 31, 2004			$	25,937		$	70,934		$	96,871
	Current period activity:
		Reclassification adjustments for settled contracts		(1,496	)		—			(1,496	)
		Changes in fair value of outstanding hedge positions		(65,876	)		—			(65,876	)
		Currency translation adjustment		—			(2,386	)		(2,386	)

	Total period activity			(67,372	)		(2,386	)		(69,758	)

Balance at March 31, 2005			$	(41,435	)	$	68,548		$	27,113

The accompanying notes are an integral part of these consolidated financial statements.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

Note 1—Organization and Accounting Policies

Plains All American Pipeline, L.P. ("PAA") is a Delaware limited partnership formed in September of 1998. Our operations are conducted directly and indirectly through our operating subsidiaries, Plains Marketing, L.P., Plains Pipeline, L.P. and Plains Marketing Canada, L.P. We are engaged in interstate and intrastate crude oil transportation, and crude oil gathering, marketing, terminalling and storage, as well as the marketing and storage of liquefied petroleum gas and other natural gas related petroleum products. We refer to liquified petroleum gas and natural gas related petroleum products collectively as "LPG." We own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key oil producing basins and at major market hubs in the United States and Canada.

The accompanying consolidated financial statements and related notes present (i) our consolidated financial position as of March 31, 2005, and December 31, 2004, (ii) the results of our consolidated operations for the three months ended March 31, 2005 and 2004, (iii) our consolidated cash flows for the three months ended March 31, 2005 and 2004, (iv) our consolidated changes in partners' capital for the three months ended March 31, 2005, (v) our consolidated comprehensive income for the three months ended March 31, 2005 and 2004, and (vi) our changes in consolidated accumulated other comprehensive income for the three months ended March 31, 2005. The financial statements have been prepared in accordance with the instructions for interim reporting as prescribed by the Securities and Exchange Commission. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods have been reflected. All significant intercompany transactions have been eliminated. Certain reclassifications are made to prior periods to conform to current period presentation. The results of operations for the three months ended March 31, 2005 should not be taken as indicative of the results to be expected for the full year. The consolidated interim financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our 2004 Annual Report on Form 10-K.

Note 2—Trade Accounts Receivable

The majority of our trade accounts receivable relate to our gathering and marketing activities and can generally be described as high volume and low margin activities. As is customary in the industry, a portion of these receivables is reflected net of payables to the same counterparty based on contractual agreements. We routinely review our trade accounts receivable balances to identify past due amounts and analyze the reasons such amounts have not been collected. In many instances, such uncollected amounts involve billing delays and discrepancies or disputes as to the appropriate price, volume or quality of crude oil delivered, received or exchanged. We also attempt to monitor changes in the creditworthiness of our customers as a result of developments related to each customer, the industry as a whole and the general economy. Based on these analyses, as well as our historical experience and the facts and circumstances surrounding certain aged balances, we have established an allowance for doubtful trade accounts receivable. At March 31, 2005, substantially all of our net trade accounts receivable were less than 60 days past the scheduled invoice date. Our allowance for doubtful trade accounts receivable totaled $0.7 million. We consider this reserve adequate; however, there is no assurance that actual amounts will not vary significantly from estimated amounts. The discovery of previously unknown facts or adverse developments affecting one of our counterparties or the industry as a whole could adversely impact our results of operations.

Note 3—Inventory and Linefill

Inventory primarily consists of crude oil and LPG in pipelines, storage tanks and rail cars that is valued at the lower of cost or market, with cost determined using an average cost method. Linefill and minimum working inventory requirements in owned assets are recorded at historical cost and consist of crude oil and LPG used to pack our pipelines such that when an incremental barrel enters, it forces a barrel out at another location, as well as the minimum amount of crude oil and LPG necessary to operate our storage and terminalling facilities.

Linefill and minimum working inventory requirements in third party assets are included in "Inventory" (a current asset) in determining the average cost of operating inventory and applying the lower of cost or market analysis. At the end of each period, we reclassify the linefill in third party assets not expected to be liquidated within the succeeding twelve months out of "Inventory," at average cost, and into "Inventory in Third Party Assets" (a long-term asset), which is reflected as a separate line item within other assets on the consolidated balance sheet.

At March 31, 2005 and December 31, 2004, inventory and linefill consisted of:

		March 31, 2005					December 31, 2004
		Barrels	$		$/barrel		Barrels	$		$/barrel
		(Barrels in thousands and dollars in millions)
Inventory⁽¹⁾
Crude oil		14,131	$	679.6	$	48.09	8,716	$	396.2	$	45.46
LPG		845		29.4	$	34.79	2,857		100.1	$	35.04
Other		—		2.3		N/A	—		1.9		N/A

	Inventory subtotal	14,976		711.3			11,573		498.2

Inventory in third-party assets
Crude oil		1,249		44.9	$	35.95	1,294		48.7	$	37.64
LPG		318		10.4	$	32.70	318		10.6	$	33.33

	Inventory in third-party assets subtotal	1,567		55.3			1,612		59.3

Linefill
Crude oil		5,924		165.3	$	27.90	6,015		168.4	$	28.00
LPG		26		0.8	$	30.77	—		—		N/A

	Linefill subtotal	5,950		166.1			6,015		168.4

Total		22,493	$	932.7			19,200	$	725.9

⁽¹⁾: Dollars per barrel reflect the impact of inventory hedges on a portion of our volumes.

Note 4—Debt

Debt consists of the following:

		March 31, 2005		December 31, 2004
Short-term debt:
Senior secured hedged inventory borrowing facility bearing interest at a rate of 3.5% and 3.0% at March 31, 2005 and December 31, 2004, respectively		$	425.0	$	80.4
Working capital borrowings, bearing interest at a rate of 3.7% at March 31, 2005 and December 31, 2004⁽¹⁾			130.0		88.2
Other			6.0		6.9

	Total short-term debt		561.0		175.5

Long-term debt:
Senior unsecured revolving credit facility, bearing interest at 3.5% at March 31, 2005 and December 31, 2004⁽¹⁾		$	125.0	$	143.6
4.75% senior notes due August 2009, net of unamortized discount of $0.7 million at March 31, 2005 and December 31, 2004			174.3		174.3
7.75% senior notes due October 2012, net of unamortized discount of $0.3 million at March 31, 2005 and December 31, 2004			199.7		199.7
5.63% senior notes due December 2013, net of unamortized discount of $0.6 million at March 31, 2005 and December 31, 2004			249.4		249.4
5.88% senior notes due August 2016, net of unamortized discount of $1.1 million at March 31, 2005 and December 31, 2004			173.9		173.9
Other			7.9		8.1

	Total long-term debt⁽¹⁾		930.2		949.0

Total debt		$	1,491.2	$	1,124.5

⁽¹⁾: At March 31, 2005 and December 31, 2004, we have classified $130.0 million and $88.2 million, respectively, of borrowings under our senior unsecured revolving credit facility as short-term. These borrowings are designated as working capital borrowings, must be repaid within one year and are primarily for hedged LPG and crude oil inventory and New York Mercantile Exchange ("NYMEX") margin deposits.

In April 2005, we amended our senior secured hedged inventory facility to increase the capacity under the facility from $425 million to $500 million. We are in the process of negotiating an additional expansion of this facility to increase its capacity by up to $300 million. In addition, in May 2005, we amended our senior unsecured credit facility to increase the capacity from $750 million to $900 million and increased the sub-facility for Canadian borrowings to $360 million. The amended facility can be expanded to $1.25 billion.

During April 2005, we entered into a treasury lock with a large creditworthy financial institution. A treasury lock is a financial derivative instrument that enables the company to lock in the U.S. Treasury Note rate, typically in anticipation of a debt issuance. The treasury lock has a notional principal amount of $75 million and an effective rate of 4.18%. The treasury lock matures in May 2005.

Note 5—Earnings Per Common Unit

The following sets forth the computation of basic and diluted earnings per common unit. The net income available to limited partners and the weighted average limited partner units outstanding have been adjusted for instruments considered common unit equivalents at March 31, 2005 and 2004.

			Three months ended March 31,
			2005			2004
			(in thousands, except per unit data)
Net income			$	32,808		$	27,876
Less:
	General partner's incentive distribution right			(2,946	)		(1,644	)

	Subtotal			29,862			26,232
	General partner 2% ownership			(597	)		(525	)

Numerator for basic earnings per limited parner unit:
	Net income available for limited partners			29,265			25,707
Effect of dilutive securities:
	Increase in general partner's incentive distribution-contingent equity issuance			—			(16	)

Numerator for diluted earnings per limited partner unit			$	29,265		$	25,691

Denominator:
	Denominator for basic earnings per limited partner unit—weighted average number of limited partner units			67,517			58,414
	Effect of dilutive securities:
		2005 LTIP		639			—
		Contingent equity issuance		—			603

	Denominator for diluted earnings per limited partner unit—weighted average number of limited partner units			68,156			59,017

Basic net income per limited partner unit			$	0.43		$	0.44

Diluted net income per limited partner unit			$	0.43		$	0.44

Note 6—Partners' Capital and Distributions

Private Placement of Common Units.

On February 25, 2005, we issued 575,000 common units to a subsidiary of Vulcan Energy Corporation. The sale price for the common units was $38.13 per unit resulting in net proceeds, including the general partner's proportionate capital contribution and expenses associated with the sale, of approximately $22.3 million. We intend to use the net proceeds from the private placement to fund a portion of our 2005 expansion capital program. Pending the incurrence of these expenditures, the net proceeds were used to repay indebtedness under our revolving credit facilities.

Conversion of Class B and Class C Common Units.

In accordance with a common unitholder vote at a special meeting on January 20, 2005, each Class B common unit and Class C common unit became convertible into one common unit upon request of the holder. In February 2005, all of the Class B and Class C common units converted into common units.

Distributions

On April 22, 2005, we declared a cash distribution of $0.6375 per unit on our outstanding common units. The distribution is payable on May 13, 2005, to unitholders of record on May 3, 2005, for the period January 1, 2005, through March 31, 2005. The total distribution to be paid is approximately $47.7 million, with approximately $43.3 million to be paid to our common unitholders and $0.9 million and $3.5 million to be paid to our general partner for its general partner and incentive distribution interests, respectively.

On January 25, 2005, we declared a cash distribution of $0.6125 per unit on our outstanding common units, Class B common units and Class C common units. The distribution was paid on February 14, 2005, to unitholders of record on February 4, 2005, for the period October 1, 2004, through December 31, 2004. The total distribution paid was approximately $45.0 million, with approximately $41.2 million paid to our common unitholders and $0.8 million and $3.0 million paid to our general partner for its general partner and incentive distribution interests, respectively.

Note 7—Long-Term Incentive Plans

Our general partner has adopted the Plains All American GP LLC 1998 Long-Term Incentive Plan (the "1998 LTIP") and the 2005 Long-Term Incentive Plan (the "2005 LTIP") for employees and directors of our general partner and its affiliates who perform services for us.

As of March 31, 2005, there are approximately 150,000 phantom units outstanding under the 1998 LTIP, of which we expect approximately 93,000 to vest in May 2005. The majority of the awards outstanding under the 1998 LTIP have performance-based vesting terms and, therefore, we recognize expense when it is considered probable that the awards will vest.

In February 2005, our Board of Directors and Compensation Committee approved grants of approximately 1.9 million phantom units and 1.4 million distribution equivalent rights ("DERs) under the 2005 LTIP. Approximately 1.4 million of the phantom units vest over a six year period (with performance accelerators) while the remaining awards vest over time only if certain performance criteria are met and are forfeited after six years if the performance criteria are not met. No phantom units vest prior to the dates indicated below for each tranche. The DERs vest over time (with performance accelerators) and terminate with the vesting or forfeiture of the related phantom units. The following awards were outstanding under the 2005 LTIP at March 31, 2005.

		Phantom Units			DERs
Annualized Distribution Rate		Phantom Units			DERs
Annualized Distribution Rate	Date	A⁽¹⁾	B⁽²⁾	Total	A⁽¹⁾	B⁽²⁾	Total
$2.60	May 2007	549	150	699	353	150	503
$2.70	May 2008	—	—	—	132	75	207
$2.80	May 2009	411	150	561	132	75	207
$2.90	May 2010	—	—	—	132	100	232
$3.00	May 2010	411	200	611	132	100	232

		1,371	500	1,871	881	500	1,381

⁽¹⁾: Awards that vest over six years. Achievement of the indicated distribution rate performance criteria can accelerate the vesting to the date indicated. The phantom unit awards are common stock equivalents and are included in our dilutive earnings per unit calculation.
⁽²⁾: Awards that vest only upon the achievement of the distribution rate performance criteria and the date indicated. In addition, the awards will be forfeited if the performance criteria are not met in six years. These awards are not common stock equivalents and are not included in our dilutive earnings per unit calculation.

Compensation expense is recognized ratably over time for the phantom units and DERs that vest based on the passage of time. To the extent that the vesting of the awards or DERs is accelerated, the

related compensation expense will also be accelerated. For those phantom units and DERs that vest upon the achievement of performance criteria, expense is recognized when it is considered probable the criteria will be achieved.

In addition to the phantom units discussed above, four of our non-employee directors each have received LTIP awards of 5,000 units in the aggregate. These awards vest yearly in 25% increments (1,250 units). The awards have an automatic re-grant feature such that as they vest, a similar amount is granted. For the other two non-employee directors, any director compensation is assigned to the entity that designated them as directors. In those cases, no LTIP award was granted, but a cash payment is made.

We have concluded that it is probable that we will achieve a $2.60 annualized distribution rate and therefore have accelerated the vesting of the portion of the awards that vest based on that rate. We recognized total compensation expense of approximately $2.2 million in the first quarter of 2005 related to the awards granted under our 1998 LTIP and our 2005 LTIP.

Note 8—Derivative Instruments and Hedging Activities

We utilize various derivative instruments to (i) manage our exposure to commodity price risk, (ii) engage in a controlled trading program, (iii) manage our exposure to interest rate risk and (iv) manage our exposure to currency exchange rate risk. Our risk management policies and procedures are designed to monitor interest rates, currency exchange rates, NYMEX and over-the-counter positions, as well as physical volumes, grades, locations and delivery schedules, to ensure that our hedging activities address our market risks. We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. We calculate hedge effectiveness on a quarterly basis. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument's effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items.

Summary of Financial Impact

The majority of our derivative activity is related to our commodity price risk hedging activities. Through these activities we hedge our exposure to price fluctuations with respect to crude oil and LPG in storage, and expected purchases, sales and transportation of these commodities. The derivative instruments we use consist primarily of futures and options contracts traded on the NYMEX and over-the-counter transactions, including crude oil swap and option contracts entered into with financial institutions and other energy companies.

The majority of the instruments that qualify for hedge accounting are cash flow hedges. Therefore, the corresponding changes in fair value for the effective portion of the hedges are deferred to Accumulated Other Comprehensive Income ("OCI") and recognized in revenues or crude oil and LPG purchases and related costs in the periods during which the underlying physical transactions occur. Derivatives that do not qualify for hedge accounting and the portion of cash flow hedges that is not highly effective (as defined in Statement of Financial Accounting Standard No. 133) in offsetting changes in cash flows of hedged items are marked-to-market in revenues each period.

During the first quarter of 2005, our earnings include a net gain of approximately $35.5 million resulting from all derivative activities, including the change in fair value of open derivatives and settled derivatives taken to earnings during the quarter. This gain includes:

a)

a net mark-to-market loss of $13.4 million, which is comprised of:

•: the net change in fair value during the quarter of open derivatives used to hedge price exposure that do not qualify for hedge accounting (a loss of approximately $12.7 million) and
•: the net change in fair value during the quarter of the portion of cash flow hedges related to open derivatives that is not highly effective in offsetting changes in cash flows of hedged items (a loss of approximately $0.7 million).

b)

a net gain of $48.9 million related to settled derivatives taken to earnings during the period. The majority of this net gain is related to cash flow hedges that were recognized in earnings in conjunction with the underlying physical transactions that occurred during the first quarter of 2005.

The following table summarizes the net assets and liabilities related to the fair value of our open derivative positions on our consolidated balance sheet as of March 31, 2005:

Other current assets	$	21.6
Other long-term assets		9.6
Other current-liabilities		(65.8	)
Other long-term liabilities and deferred credits		(12.2	)

The net liability as of March 31, 2005, relates mostly to unrealized losses on effective cash flow hedges that are deferred to OCI. At March 31, 2005, there is a total unrealized net loss of approximately $41.4 million deferred to OCI. This includes $35.7 million, which predominantly relates to unrealized losses on derivatives used to hedge physical inventory in storage that receive hedge accounting, and $5.7 million relating to terminated interest rate swaps, which are being amortized to interest expense over the original terms of the terminated instruments. The inventory hedges are mostly short derivative positions that will result in losses when prices rise. These hedge losses are offset by an increase in the physical inventory value and will be reclassed into earnings from OCI in the same period that the underlying physical inventory is sold. The total amount of deferred net losses recorded in OCI are expected to be reclassified to future earnings, contemporaneously with the related physical purchase or delivery of the underlying commodity or payments of interest.

Of the total net loss deferred in OCI at March 31, 2005, a net loss of $36.0 million will be reclassified into earnings in the next twelve months and the remaining net loss at various intervals (ending in 2016 for amounts related to our terminated interest rate swaps and 2009 for amounts related to our commodity price-risk hedging). Because a portion of these amounts is based on market prices at the current period end, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

During the three months ended March 31, 2005, no amounts were reclassified to earnings from OCI in connection with forecasted transactions that were no longer considered probable of occurring.

Note 9—Commitments and Contingencies

Litigation

"BIS") of the U.S. Commerce Department. In 2002, we determined that we may have violated the terms of our licenses with respect to the quantity of crude oil exported and the end-users in Canada. Export of crude oil except as authorized by license is a violation of the EAR. In October 2002, we submitted to the BIS an initial notification of voluntary disclosure. The BIS subsequently informed us that we could continue to export while previous exports were under review. We applied for and received several new licenses allowing for export volumes and end users that more accurately reflect our anticipated business and customer needs. We also conducted reviews of new and existing contracts and implemented new procedures and practices in order to monitor compliance with applicable laws regarding the export of crude oil to Canada. As a result, we subsequently submitted additional information to the BIS in October 2003 and May 2004. In August 2004, we received a request from the BIS for additional information. We have responded to this and subsequent requests, and continue to cooperate fully with BIS officials. At this time, we have received neither a warning letter nor a charging letter, which could involve the imposition of penalties, and no indication of what penalties the BIS might assess. As a result, we cannot reasonably estimate the ultimate impact of this matter.

Alfons Sperber v. Plains Resources Inc., et al. On December 18, 2003, a putative class action lawsuit was filed in the Delaware Chancery Court, New Castle County, entitled Alfons Sperber v. Plains Resources Inc., et al. This suit, brought on behalf of a putative class of Plains All American Pipeline, L.P. common unitholders, asserted breach of fiduciary duty and breach of contract claims against us, Plains AAP, L.P., and Plains All American GP LLC and its directors, as well as breach of fiduciary duty claims against Plains Resources Inc. and its directors (Plains Resources, Inc. is a unitholder and an interest owner in our general partner). The complaint sought to enjoin or rescind a proposed acquisition of all of the outstanding stock of Plains Resources Inc., as well as declaratory relief, an accounting, disgorgement and the imposition of a constructive trust, and an award of damages, fees, expenses and costs, among other things. This lawsuit has been settled in principle. The court has approved the settlement and the settlement became final in March 2005.

Pipeline Releases. In December 2004 and January 2005, we experienced two unrelated releases of crude oil that reached rivers located near the sites where the releases originated. In late December 2004, one of our pipelines in West Texas experienced a rupture that resulted in the release of approximately 4,500 barrels of crude oil, a portion of which reached a remote location of the Pecos River. In early January 2005, an overflow from a temporary storage tank located in East Texas resulted in the release of approximately 1,200 barrels of crude oil, a portion of which reached the Sabine River. In both cases, emergency response personnel under the supervision of a unified command structure consisting of representatives of Plains Pipeline, the U.S. Environmental Protection Agency, the Texas Commission on Environmental Quality and the Texas Railroad Commission conducted clean-up operations at each site. Approximately 4,200 barrels and 980 barrels were recovered from the two respective sites. The unrecovered oil has been or will be removed or otherwise addressed by PAA in the course of site remediation. Aggregate costs associated with the releases, including estimated remediation costs, are estimated to be approximately $3.0 million to $3.5 million. We continue to work with the appropriate state and federal environmental authorities in responding to the releases and no enforcement proceedings have been instituted by any governmental authority at this time.

General. 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.

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. At March 31, 2005, our reserve for environmental liabilities totaled approximately $23.3 million. Approximately $16.3 million of the reserve is related to liabilities assumed as part of the Link acquisition. Although we believe our reserve is adequate, no assurance can be given that any costs incurred in excess of this reserve would not have a material adverse effect on our financial condition, results of operations or cash flows.

Other

A pipeline, terminal or other facility 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 insurance of various types that we consider adequate to cover our operations and properties. The insurance covers our assets in amounts considered reasonable. The insurance policies are subject to deductibles that we consider reasonable and not excessive. Our insurance does not cover every potential risk associated with operating pipelines, terminals and other facilities, including the potential loss of significant revenues. The overall trend in the environmental insurance industry appears to be a contraction in the breadth and depth of available coverage, while costs, deductibles and retention levels have increased. Absent a material favorable change in the insurance markets, this trend is expected to continue as we continue to grow and expand. As a result, we anticipate that we will elect to self-insure more of our activities or incorporate higher retention in our insurance arrangements.

The occurrence of a significant event not fully insured, indemnified or reserved against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial 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 that we have established adequate reserves to the extent that such risks are not insured.

Note 10—Operating Segments

Our operations consist of two operating segments: (i) pipeline transportation operations ("Pipeline Operations") and (ii) gathering, marketing, terminalling and storage operations ("GMT&S"). Through our pipeline segment, we engage in interstate and intrastate crude oil pipeline transportation and certain related margin activities. Through our GMT&S segment, we engage in purchases and resales of crude oil and LPG at various points along the distribution chain and we operate certain terminalling and storage assets. We believe that the combination of our terminalling and storage activities and gathering and marketing activities provides a counter-cyclical balance that has a stabilizing effect on our results of operations and cash flow. In a contango market (oil prices for future deliveries are higher than for current deliveries), we use our tankage to improve our gathering margins by storing crude oil we have purchased at lower prices in the current month for delivery at higher prices in future months. In a backwardated market (oil prices for future deliveries are lower than for current deliveries), we use and lease less storage capacity, but increased marketing margins (premiums for prompt delivery) provide an offset to this reduced cash flow.

We evaluate segment performance based on segment profit and maintenance capital. We define segment profit as revenues less (i) purchases, (ii) field operating costs, and (iii) segment general and administrative expenses. 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. The following table reflects certain financial data for each segment for the periods indicated (note that each of the items in the following table excludes depreciation and amortization):

			Pipeline		GMT&S			Total
			(in millions)
Three Months Ended March 31, 2005
Revenues:
	External Customers (includes buy/sell revenues in our Pipeline and GMT&S segments of $33.5 and $3,419.0, respectively)⁽²⁾		$	212.5	$	6,426.0		$	6,638.5
	Intersegment⁽¹⁾			34.7		0.2			34.9

		Total revenues of reportable segments	$	247.2	$	6,426.2		$	6,673.4

Segment profit⁽²⁾			$	50.1	$	16.3		$	66.4

SFAS 133 noncash mark-to-market adjustment⁽²⁾			$	—	$	(13.4	)	$	(13.4	)

Maintenance capital			$	2.8	$	1.2		$	4.0

Three Months Ended March 31, 2004
Revenues:
	External Customers (includes buy/sell revenues in our Pipeline and GMT&S segments of $46.4 and $1,834.9, respectively)⁽²⁾		$	173.5	$	3,631.1		$	3,804.6
	Intersegment⁽¹⁾			15.8		0.2			16.0

		Total revenues of reportable segments	$	189.3	$	3,631.3		$	3,820.6

Segment profit⁽²⁾			$	25.5	$	28.1		$	53.6

SFAS 133 noncash mark-to-market adjustment⁽²⁾			$	—	$	7.5		$	7.5

Maintenance capital			$	1.4	$	0.3		$	1.7

⁽¹⁾: Intersegment sales are conducted at arms length.
⁽²⁾: Amounts related to SFAS 133 are included in revenues and impact segment profit.
⁽³⁾: The following table reconciles segment profit to consolidated income before cumulative effect of change in accounting principle:

	For the three months ended March 31,
	2005			2004
	(in millions)
Segment profit	$	66.4		$	53.6
Depreciation and amortization		(19.1	)		(13.1	)
Interest expense		(14.6	)		(9.5	)
Interest and other income (expense), net		0.1			—

Income before cumulative effect of change in accounting principle	$	32.8		$	31.0

Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Introduction

The following discussion is intended to provide investors with an understanding of our financial condition and results of our operations and should be read in conjunction with our historical consolidated financial statements and accompanying notes. For more detailed information regarding the basis of presentation for the following financial information, see the "Notes to the Consolidated Financial Statements." Our discussion and analysis includes the following:

•: Executive Summary
•: Acquisition Activities
•: Results of Operations
•: Outlook
•: Liquidity and Capital Resources
•: Commitments
•: Forward-Looking Statements and Associated Risks

Executive Summary

Company Overview

We are engaged in interstate and intrastate crude oil transportation, and crude oil gathering, marketing, terminalling and storage, as well as the marketing and storage of liquefied petroleum gas and other petroleum products. We refer to liquified petroleum gas and other natural gas related petroleum products collectively as "LPG." We have an extensive network of pipeline transportation, terminalling, storage and gathering assets in key oil producing basins and at major market hubs in the United States and Canada. We were formed in September of 1998, and our operations are conducted directly and indirectly through our operating subsidiaries, Plains Marketing, L.P., Plains Pipeline, L.P. and Plains Marketing Canada, L.P.

We are one of the largest midstream crude oil companies in North America. As of March 31, 2005, we owned approximately 15,000 miles of active crude oil pipelines, approximately 37 million barrels of active terminalling and storage capacity and over 400 transport trucks. Currently, we handle an average of over 2.9 million barrels per day of physical crude oil through our extensive network of assets located in major oil producing regions of the United States and Canada.

First Quarter 2005 Operating Results Overview

During the first quarter of 2005, we recognized net income of $32.8 million and earnings per limited partner unit of $0.43, compared to $27.9 million and $0.44, respectively during the first quarter of 2004.

Key items in the first quarter of 2005 included:

•: The contribution in the current quarter of acquisitions completed during 2004 and the first quarter of 2005.
•: The inclusion in the first quarter of 2005 of an aggregate charge of approximately $2.2 million related to both our 1998 Long-Term Incentive Plan ("1998 LTIP") and our 2005 Long-Term Incentive Plan ("2005 LTIP").
•: A non-cash loss of approximately $13.4 million in the first quarter of 2005 resulting from the mark-to-market of open derivative instruments pursuant to Statement of Financial Accounting Standard No. 133, as amended ("SFAS 133").
•: Favorable market conditions characterized by relatively strong contango market conditions and reasonably high volatility and wide differentials in various grades of crude oil.

Acquisition Activities

We completed several acquisitions during 2005 and 2004 that have impacted the results of operations and liquidity discussed herein. The following acquisitions were accounted for, and the purchase prices were allocated, in accordance with SFAS 141 "Business Combinations." Our ongoing acquisition activity is discussed further in "Outlook" below.

During the first quarter of 2005, we completed several small transactions for aggregate consideration of approximately $24.3 million. The transactions included several crude oil pipeline systems along the Gulf Coast as well as in Canada. We also acquired an LPG pipeline and terminal in Oklahoma. These acquisitions did not materially impact our results of operations, either individually or in the aggregate.

During 2004, we completed several acquisitions for aggregate consideration of approximately $549.5 million. The aggregate consideration includes cash paid, estimated transaction costs and assumed liabilities and net working capital items. The following table summarizes our 2004 acquisitions:

Acquisition	Effective Date	Acquisition Price		Operating Segment
	(in millions)
Capline and Capwood Pipeline Systems ("Capline acquisition")	03/01/04	$	158.5	Pipeline
Link Energy LLC ("Link acquisition")	04/01/04		332.3	Pipeline/GMT&S
Cal Ven Pipeline System	05/01/04		19.0	Pipeline
Schaefferstown Propane Storage Facility	08/25/04		32.0	GMT&S
Other	various		7.7	GMT&S

Total 2004 Acquisitions		$	549.5

Results of Operations

Analysis of Operating Segments

Our operations consist of two operating segments: (i) Pipeline Operations and (ii) GMT&S Operations. Through our pipeline segment, we engage in interstate and intrastate crude oil pipeline transportation and certain related margin activities. Through our GMT&S segment, we engage in purchases and resales of crude oil and LPG at various points along the distribution chain and we operate certain terminalling and storage assets. We believe that the combination of our terminalling and storage activities and gathering and marketing activities provides a counter-cyclical balance that has a stabilizing effect on our results of operations and cash flow. In a contango market (oil prices for

future deliveries are higher than for current deliveries), we use our tankage to improve our gathering margins by storing crude oil we have purchased at lower prices in the current month for delivery at higher prices in future months. In a backwardated market (oil prices for future deliveries are lower than for current deliveries), we use less storage capacity, but increased marketing margins (premiums for prompt delivery) provide an offset to this reduced cash flow.

We evaluate segment performance based on segment profit and maintenance capital. We define segment profit as revenues less (i) purchases, (ii) field operating costs and (iii) segment general and administrative ("G&A") expenses. Each of the items above excludes depreciation and amortization. As a master limited partnership, we make quarterly distributions of our "available cash" (as defined in our partnership agreement) to our unitholders. Therefore, we look at each period's earnings before non-cash depreciation and amortization as an important measure of segment performance. The exclusion of depreciation and amortization expense could be viewed as limiting the usefulness of segment profit as a performance measure because it does not account in current periods for the implied reduction in value of our capital assets, such as crude oil pipelines and facilities, caused by aging and wear and tear. Management compensates for this limitation by recognizing that depreciation and amortization are largely offset by repair and maintenance costs, which keep the actual value of our principal fixed assets from declining. These maintenance costs are a component of field operating costs included in segment profit or in maintenance capital, depending on the nature of the cost. 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. See Note 10 "Operating Segments" in the "Notes to the Consolidated Financial Statements" for a reconciliation of segment profit to consolidated income before cumulative effect of change in accounting principle. The following table reflects our results of operations and maintenance capital for each segment.

Three Months Ended March 31, 2005 and 2004

	Pipeline			GMT&S
	(in millions)
Three Months Ended March 31, 2005⁽¹⁾
Revenues	$	247.2		$	6,426.2
Purchases		(151.7	)		(6,369.4	)
Field operating costs (excluding LTIP charge)		(34.0	)		(29.5	)
LTIP charge—operations		(0.1	)		(0.2	)
Segment G&A expenses (excluding LTIP charge)⁽²⁾		(10.1	)		(10.1	)
LTIP charge—general and administrative		(1.2	)		(0.7	)

Segment profit	$	50.1		$	16.3

SFAS 133 noncash mark-to-market adjustment⁽³⁾	$	—		$	(13.4	)

Maintenance capital	$	2.8		$	1.2

Three Months Ended March 31, 2004⁽¹⁾
Revenues	$	189.3		$	3,631.3
Purchases		(136.7	)		(3,572.9	)
Field operating costs (excluding LTIP charge)		(19.3	)		(18.5	)
LTIP charge—operations		(0.1	)		(0.4	)
Segment G&A expenses (excluding LTIP charge)⁽²⁾		(6.0	)		(9.4	)
LTIP charge—general and administrative		(1.7	)		(2.0	)

Segment profit	$	25.5		$	28.1

SFAS 133 noncash mark-to-market adjustment⁽³⁾	$	—		$	7.5

Maintenance capital	$	1.4		$	0.3

⁽¹⁾: Revenues and purchases include intersegment amounts.
⁽²⁾: Segment 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 judgement by management and will continue to be based on the business activities that exist during each period.
⁽³⁾: Amounts related to SFAS 133 are included in revenues and impact segment profit.

Pipeline Operations

As of March 31, 2005, we owned approximately 15,000 miles (of which approximately 13,000 miles are included in our pipeline segment) of active gathering and mainline crude oil pipelines located throughout the United States and Canada. Our activities from pipeline operations generally consist of transporting volumes of crude oil for a fee and third party leases of pipeline capacity (collectively referred to as "tariff activities"), as well as barrel exchanges and buy/sell arrangements (collectively referred to as "pipeline margin activities"). In connection with certain of our merchant activities conducted under our gathering and marketing business, we are also shippers on certain of our own pipelines. These transactions are conducted at published tariff rates and eliminated in consolidation. Tariffs and other fees on our pipeline systems vary by receipt point and delivery point. The segment profit 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 field costs of operating the pipeline. Segment profit 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 March 31,
				2005			2004
				(in millions)
Operating Results⁽¹⁾
	Revenues
		Tariff activities		$	89.6		$	47.0
		Pipeline margin activities⁽²⁾			157.6			142.3

	Total pipeline operations revenues				247.2			189.3
	Costs and Expenses
		Pipeline margin activities purchases			(151.7	)		(136.7	)
		Field operating costs (excluding LTIP charge)			(34.0	)		(19.3	)
		LTIP charge—operations			(0.1	)		(0.1	)
		Segment G&A expenses (excluding LTIP charge)⁽³⁾			(10.1	)		(6.0	)
		LTIP charge—general and administrative			(1.2	)		(1.7	)

	Segment profit			$	50.1		$	25.5

	Maintenance capital			$	2.8		$	1.4

Average Daily Volumes (thousands of barrels per day)⁽⁴⁾
	Tariff activities
		All American			54			55
		Basin			277			275
		Capline⁽⁵⁾			160			54
		West Texas/New Mexico Area Systems⁽⁶⁾			401			209
		Canada			268			240
		Other			494			143

	Total tariff activities				1,654			976
	Pipeline margin activities				75			72

			Total		1,729			1,048

⁽¹⁾: Revenues and purchases include intersegment amounts.
⁽²⁾: Includes revenues associated with buy/sell arrangements of $33.5 million and $46.4 million for the quarters ended March 31, 2005 and 2004, respectively. Volumes associated with these arrangements were approximately 11,500 barrels per day and 16,800 barrels per day for the quarters ended March 31, 2005 and 2004, respectively.
⁽³⁾: Segment 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.
⁽⁴⁾: Volumes associated with acquisitions represent total volumes transported for the number of days we actually owned the assets divided by the number of days in the period.
⁽⁵⁾: Capline volumes averaged approximately 160,000 barrels per day for March 2004, which is the only month during the first quarter of 2004 in which we owned the system.
⁽⁶⁾: The aggregate of ten systems in the West Texas/New Mexico area.

Total revenues from our pipeline operations were approximately $247.2 million and $189.3 million for the three months ended March 31, 2005 and 2004, respectively. An increase in revenues from tariff activities accounted for $42.6 million of the increase (see discussion below). Revenues from our margin

activities increased approximately $15.3 million between the periods as a decrease in buy/sell volumes was offset by higher average prices for crude oil sold and transported on our SJV gathering system. Because the barrels that we buy and sell are generally indexed to the same pricing indices, revenues and purchases will increase and decrease with changes in market prices without significant changes to our margins related to those purchases and sales.

Increases in segment profit, our primary measure of segment performance, were driven by the following:

•: Increased volumes and related tariff revenues—The increase in volumes and related tariff revenues is primarily related to the Link acquisition and other acquisitions completed during 2004.
•: Increased revenues from our loss allowance oil—Increased volumes and higher crude oil prices in the first quarter of 2005 as compared to the first quarter of 2004 (the NYMEX average was $49.88 for the first quarter of 2005 compared to $35.21 for the first quarter of 2004) have resulted in increased revenues related to loss allowance oil.
•: Increased field operating costs—Our continued growth, primarily from the Link acquisition and other acquisitions completed during 2004 is the principal driver of the increase in field operating costs of $14.7 million to $34.1 million for the first quarter of 2005. The increased costs are primarily related to (i) payroll and benefits, (ii) emergency response and environmental remediation of pipeline releases and (iii) utilities.
•: Increased segment G&A expenses—The increase in segment G&A expenses in the first quarter of 2005 is primarily related to the Link acquisition coupled with the percentage of indirect costs allocated to the pipeline operations segment increasing in the 2005 period as our pipeline operations have grown in relation to our GMT&S segment.

As discussed above, the increase in pipeline operations segment profit is largely related to our acquisition activities. We completed a number of acquisitions during the last nine months of 2004 that have impacted the results of operations herein. The following presentation helps summarize the impact of recent acquisitions and expansions on volumes and revenues related to our tariff activities.

		Three Months Ended March 31,
		2005			2004
		Revenues		Volumes	Revenues		Volumes
		(volumes in thousands of barrels per day and revenues in millions)
Tariff activities revenues^(1)(2)(3)
	2005 acquisitions/expansions	$	2.0	50	$	—	—
	2004 acquisitions/expansions		38.0	696		3.3	90
	All other pipeline systems		49.6	908		43.7	886

	Total tariff activities	$	89.6	1,654	$	47.0	976

⁽¹⁾: Revenues include intersegment amounts.
⁽²⁾: Volumes associated with acquisitions represent total volumes transported for the number of days we actually owned the assets divided by the number of days in the period.
⁽³⁾: To the extent there has been an expansion to one of our existing pipeline systems, any incremental revenues and volumes are included in the results for the period that pipeline was acquired. For new pipeline systems that we construct, incremental revenues and volumes are included in the period the system became operational.

Average daily volumes from our tariff activities increased approximately 70% to approximately 1.7 million barrels per day and revenues from our tariff activities increased over 90% to $89.6 million.

The increase in the first quarter of 2005 is predominately related to the inclusion of pipeline systems acquired in 2004:

•: 389,000 barrels per day and $26.0 million of revenues from the pipelines acquired in the Link acquisition,
•: 291,000 barrels per day and $10.9 million of revenues from the pipelines acquired in the Capline acquisition, and
•: 16,000 barrels per day and $1.1 million of revenues from other businesses acquired in the last nine months of 2004.

Revenues from all other pipeline systems also increased in the first quarter of 2005, along with a slight increase in volumes. The increase in revenues is related to several items including (i) increased tariff rates on certain of our systems, partially related to the quality of crude oil shipped, (ii) the appreciation of Canadian currency (the Canadian to U.S. dollar exchange rate appreciated to an average of 1.23 to 1 for the first quarter of 2005 compared to an average of 1.32 to 1 in the first quarter of 2004), and (iii) volume increases on certain of our systems.

Gathering, Marketing, Terminalling and Storage Operations

As of March 31, 2005, we owned approximately 37 million barrels of active 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 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." Approximately 14 million barrels of our 37 million barrels of tankage is used primarily in our GMT&S Operations segment and the balance is used in our Pipeline Operations segment.

On a stand-alone basis, segment profit 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. Our terminalling and storage activities are integrated with our gathering and marketing activities and thus 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 balance and hedge our gathering and marketing activities. In a contango market (when oil prices for future deliveries are higher than for current deliveries), we use our tankage to improve our gathering margins by storing crude oil we have purchased at lower prices in the current month for delivery at higher prices in future months. In a backwardated market (when oil prices for future deliveries are lower than for current deliveries), we use less storage capacity, but increased marketing margins (premiums for prompt delivery) provide an offset to this reduced cash flow. We believe that this combination of our terminalling and storage activities and gathering and marketing activities provides a counter-cyclical balance that has a stabilizing effect on our results of operations and cash flows.

Our revenues from gathering and marketing activities reflect the sale of gathered and bulk-purchased crude oil and LPG volumes, plus the sale of additional barrels exchanged through buy/sell arrangements entered into to supplement the margins of the gathered and bulk-purchased volumes. Because the commodities that we buy and sell are generally indexed to the same pricing indices for both the purchase and the sale, revenues and costs related to purchases will increase and decrease with changes in market prices. However, the margins related to those purchases and sales will not necessarily have corresponding increases and decreases. For example, our revenues increased approximately 77% in the first quarter of 2005 compared to the first quarter of 2004, while our

segment profit decreased almost 42% in the same period. This decrease is related to the impact of the SFAS 133 noncash mark-to-market adjustment which resulted in a decrease in segment profit of 74% (see discussion below).

Revenues from our GMT&S operations were approximately $6.4 billion and $3.6 billion for the quarters ended March 31, 2005 and 2004, respectively. Revenues and costs related to purchases for the 2005 period were impacted by higher average prices and higher volumes as compared to the 2004 period. Approximately 70% of the increase in revenues resulted from higher average prices in the 2005 period and the remainder was attributable to increased sales volumes. The average NYMEX price for crude oil was $49.88 per barrel and $35.21 per barrel for the quarter ended March 31, 2005 and 2004, respectively.

Generally, we expect our segment profit to increase or decrease directionally with increases or decreases in lease gathered volumes and LPG sales volumes. Although we believe that the combination of our lease gathering business and our storage assets provides a counter-cyclical balance that provides stability in our margins, these margins are not fixed and may vary from period to period. In order to evaluate the performance of this segment, management focuses on the following metrics: (i) segment profit (ii) crude oil lease gathered volumes and LPG sales volumes and (iii) segment profit per barrel calculated on these volumes. The following table sets forth our operating results from our GMT&S Operations segment for the comparative periods indicated:

		Three months ended March 31,
		2005			2004
		(in millions, except per barrel amounts)
Operating Results⁽¹⁾
	Revenues⁽²⁾⁽⁴⁾	$	6,426.2		$	3,631.3
	Purchases and related costs		(6,369.4	)		(3,572.9	)
	Field operating costs (excluding LTIP charge)		(29.5	)		(18.5	)
	LTIP charge—operations		(0.2	)		(0.4	)
	Segment G&A expenses (excluding LTIP charge)⁽³⁾		(10.1	)		(9.4	)
	LTIP charge—general and administrative		(0.7	)		(2.0	)

	Segment profit⁽⁴⁾	$	16.3		$	28.1

	SFAS 133 noncash mark-to-market adjustment⁽⁴⁾	$	(13.4	)	$	7.5

	Maintenance capital	$	1.2		$	0.3

	Segment profit per barrel⁽⁵⁾	$	0.26		$	0.60

Average Daily Volumes (thousands of barrels per day)⁽⁶⁾
Crude oil lease gathering			622			460

LPG sales			84			59

⁽¹⁾: Revenues and purchases and related costs include intersegment amounts.
⁽²⁾: Includes revenues associated with buy/sell arrangements of $3,419.0 million and $1,834.9 million for the quarters ended March 31, 2005 and 2004, respectively. Volumes associated with these arrangements were approximately 855,000 barrels per day and 597,000 barrels per day for the quarters ended March 31, 2005 and 2004, respectively. The previously referenced amounts include certain estimates based on management's judgment; such estimates are not expected to have a material impact on the balances.

⁽³⁾: Segment 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.
⁽⁴⁾: Amounts related to SFAS 133 are included in revenues and impact segment profit.
⁽⁵⁾: Calculated based on crude oil lease gathered barrels and LPG sales barrels.
⁽⁶⁾: Volumes associated with acquisitions represent total volumes transported for the number of days we actually owned the assets divided by the number of days in the period.

Segment profit decreased 42% to $16.3 million for the first quarter of 2005 as compared to the first quarter of 2004. The primary reason for the decrease from quarter to quarter is the impact of our noncash mark-to-market adjustment for open derivative instruments pursuant to SFAS 133. The noncash mark-to-market adjustment was a net loss of $13.4 million in the current quarter compared to a net gain of $7.5 million in the first quarter of 2004. This adjustment resulted in a decrease in segment profit of 74%. The primary components of the noncash adjustment in the first quarter of 2005 were:

•: A decrease in the mark-to-market of approximately $4.6 million resulting from the change in fair value for option and futures contracts that serve to reduce our lease gathering and tankage business exposures. Because the tankage arrangements will not necessarily result in physical delivery, they are not eligible for hedge accounting treatment under SFAS 133. In addition, because our option activity often involves option sales, these also do not receive hedge accounting treatment. While these derivatives do not qualify for hedge accounting, their purpose is to mitigate risk associated with our physical assets in our storage and terminalling activities and contractual arrangements in our lease gathering activities.
•: A decrease in the mark-to-market resulting from the settlement of approximately $6.8 million of derivatives relating to strategies that were included in our mark-to-market adjustment at December 31, 2004. These positions primarily related to options and futures contracts associated with our gathering and tankage business exposures.
•: A decrease in the mark-to-market of approximately $2.6 million resulting from the change in fair value of our Canadian and LPG derivative contracts, which do not consistently qualify for hedge accounting because the correlations tend to fluctuate; and
•: An increase in the mark-to-market of $0.6 million primarily related to the change in fair value of certain derivative instruments used to minimize the risk of unfavorable changes in exchange rates.

The other primary drivers of current quarter results were:

•: Increased crude oil lease gathered volumes and LPG sales volumes—The crude oil volumes gathered from producers, using our assets or third-party assets, have increased by approximately 35% to 622,000 barrels per day for the first quarter of 2005. The increase is primarily related to the Link acquisition. In addition, we marketed 84,000 barrels per day of LPG during the first quarter of 2005 compared to 59,000 barrels per day in the first quarter of 2004.
•: Favorable market conditions—During the first quarter of 2005, market conditions were favorable for this segment and were characterized by relatively strong contango market conditions throughout the quarter as well as reasonably high volatility and wide differentials on various grades of crude oil. The NYMEX benchmark price of crude ranged from $41.25 to $57.60 during the quarter. This volatile market allowed us to optimize and enhance the margins of both our gathering and marketing assets and our terminalling and storage assets at different times during the quarter. Also positively impacting our results were increased receipts of foreign crude oil movements at our facilities. The market conditions in the first quarter of 2004 were also favorable as there was relatively high volatility and strong backwardation throughout the quarter.

During the first quarter of 2004, the NYMEX benchmark price of crude ranged from $32.20 to $38.50.

•: Increased tankage used in our GMT&S Operations—The positive impact of the favorable market conditions discussed above was further enhanced by the increase in the amount of tankage used in our GMT&S Operations to approximately 14 million barrels in the first quarter of 2005 as compared to 11.0 million barrels in the first quarter of 2004.
•: Impact of change in Canadian dollar to U.S. dollar exchange rate—The first quarter of 2005 includes a foreign exchange loss of $0.8 million. The loss is related to the impact of changes in the Canadian dollar to U.S. dollar exchange rate on net U.S. dollar denominated liabilities in our Canadian subsidiary.
•: Increased field operating costs—Our continued growth, primarily from the Link acquisition is the primary driver of the increase in field operating costs for the 2005 period as compared to the 2004 period.

The impact of the items discussed above resulted in segment profit per barrel (calculated based on our lease gathered crude oil and LPG barrels) of $0.26 per barrel for the quarter ended March 31, 2005, compared to $0.60 for the quarter ended March 31, 2004. The SFAS 133 noncash mark-to-market adjustment had a negative $0.21 segment profit per barrel impact in the first quarter of 2005 compared to a positive $0.16 segment profit per barrel impact in the first quarter of 2004.

Other Expenses

Depreciation and Amortization

Depreciation and amortization expense was $19.1 million for the three months ended March 31, 2005, compared to $13.1 million for the three months ended March 31, 2004. The increase relates primarily to the assets from our 2004 acquisitions being included for the full quarter in 2005 versus only a part or none of the quarter in 2004. Additionally, several capital projects were completed during mid-to-late 2004 that were not included in first quarter 2004 depreciation expense. Amortization of debt issue costs was $0.6 million and $0.5 million in the first quarter of 2005 and 2004, respectively.

Interest Expense

The amount of interest expense we recognize is primarily impacted by:

•: our average debt balances,
•: the level and maturity of fixed rate debt, and
•: interest rates associated therewith, market interest rates and our interest rate hedging activities on floating rate debt.

During the first quarter of 2005, our average debt balance was approximately $1.0 billion, compared to an average balance of approximately $0.6 billion for the first quarter of 2004. The following table summarizes the components of these balances:

	For the three months ended March 31,
	2005		2004
	(average amount outstanding, in millions)
Fixed rate senior notes⁽¹⁾	$	800	$	450
Borrowings under our revolving credit facilities		211		149

Total	$	1,011	$	599

⁽¹⁾: Face amount of senior notes, exclusive of discounts.

The higher average debt balance in the 2005 period was primarily related to the portion of our acquisitions that were not refinanced with equity, coupled with borrowings related to other capital projects. Our financial growth strategy is to fund our acquisitions using a balance of debt and equity. Our weighted average interest rate, excluding commitment and other fees, was approximately 6.1% for both periods.

The net impact of the items discussed above was an increase in interest expense in the first quarter of 2005 of approximately $5.0 million to a total of $14.6 million. This increase is primarily related to the rise in our average debt balance, partially offset by an increase in interest capitalized.

Interest costs attributable to borrowings for stored inventory are included in our GMT&S segment profit for purposes of matching those costs with the profits realized on storing crude oil. These borrowings are primarily under our senior secured hedged inventory facility. These costs were approximately $3.4 million and $0.1 million for the quarters ended March 31, 2005 and 2004, respectively.

Outlook

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.

Ongoing Acquisition Activities. Consistent with our business strategy, we are continuously engaged in discussions with potential sellers regarding the possible purchase by us of transportation, gathering, terminalling or storage assets and related businesses. These acquisition efforts often involve assets which, if acquired, would have a material effect on our financial condition and results of operations. In an effort to prudently and economically leverage our asset base, knowledge base and skill sets, management has also expanded its efforts to encompass businesses that are closely related to, or significantly intertwined with, the crude oil business. We can give 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.

As a result of several factors including the tight supply and demand relationship for crude oil world-wide, we believe the crude oil market will continue to be volatile and subject to frequent short-term swings in market prices and shifts in market structure. Over the last seven months, crude oil prices ranged from a low of around $40.00 per barrel to a high of approximately $58.00 per barrel. During that same period, the spread between the futures contracts in the first two months ranged from nearly $1.00 backwardated to as much as $1.90 per barrel contango. While there can be no assurance that such volatile conditions will not have an unanticipated adverse effect on the partnership in the future, we believe the strategic nature of our asset base and our complementary business model position the partnership to benefit from such market conditions, subject to a number of inherent business risks, including our maintaining an attractive credit rating and our continuing ability to receive open credit from our suppliers and trade counter-parties.

Based on this outlook, we increased the capacity of our senior unsecured credit facility and intend to take various actions to further increase our liquidity and ensure that we are positioned to prudently optimize the use of our asset base in the event that prices rise significantly (see discussion in "Liquidity" below). These steps may include one or more of the following actions: increasing the size of our hedged inventory facility; accessing the long-term debt capital markets, and thus increasing the availability under our outstanding credit facility; and/or the issuance of equity.

Liquidity and Capital Resources

Liquidity

Cash generated from operations and our credit facilities are our primary sources of liquidity. At March 31, 2005, we had a working capital deficit of approximately $115.5 million, approximately $320.5 million of availability under our committed revolving credit facilities and no unused capacity under our uncommitted hedged inventory facility (see "Capital Resources" below). Usage of the credit facilities is subject to compliance with covenants. We believe we are currently in compliance with all covenants.

Capital Resources

In February 2005, we issued 575,000 common units to a subsidiary of Vulcan Energy Corporation. The sale price for the common units was $38.13 per unit resulting in net proceeds, including the general partner's proportionate capital contribution and expenses associated with the sale, of approximately $22.3 million. We intend to use the net proceeds from the private placement to fund a portion of our 2005 expansion capital program. Pending the incurrence of such expenditures, the net proceeds were used to repay indebtedness under our revolving credit facilities.

We believe that we have sufficient liquid assets, cash flow 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 affect our cash flow. A material decrease in our cash flows would likely produce an adverse effect on our borrowing capacity.

Cash Flows

		Three Months Ended March 31,
		2005			2004
		(in millions)
Cash provided by (used in):
	Operating activities	$	(271.8	)	$	133.0
	Investing activities		(61.7	)		(155.9	)
	Financing activities		342.6			(21.1	)

Operating Activities. The primary drivers of our cash flow from operations are (i) the collection of amounts related to the sale of crude oil and LPG and the transportation of crude oil for a fee and (ii) the payment of amounts related to the purchase of crude oil and LPG and other expenses, principally field operating costs and general and administrative expenses. The cash settlement from the purchase and sale of crude oil during any particular month typically occurs within thirty days from the end of the month, except in the months that we store inventory because of contango market conditions or in months that we increase linefill. The storage of crude oil in periods of a contango market can have a material impact on our cash flows from operating activities for the period we pay for and store the crude oil and the subsequent period that we receive proceeds from the sale of the crude oil. When we store the crude oil, we borrow on our credit facilities to pay for the crude oil so the impact on operating cash flow is negative. Conversely, cash flow from operating activities increases in the period we collect the cash from the sale of the stored crude oil. In addition, our cash flow from operating activities is also impacted by the level of LPG inventory stored at period end. Cash flow used in operating activities was $271.8 million in 2005. Cash flow provided by operating activities was $133.0 million in 2004.

Cash flows from operating activities in 2005 reflects the purchase and storage of crude oil because of contango market conditions. During the first quarter, we purchased crude oil for storage. These purchases had a negative impact on cash flows from operating activities when the invoices for the crude oil were paid. The proceeds we received from our credit facilities to pay for the crude oil while stored are shown as financing activities in the cash flow statement. As such, until we deliver the crude oil and receive payment from our customers, operating activities in the cash flow statement will be negatively impacted by this activity. Crude oil stored is hedged against price risk.

Investing Activities. Net cash used in 2005 was $61.7 million and was predominantly related to additions to property and equipment comprised of (i) $15.4 million paid for our Trenton pipeline expansion, (ii) $10.2 million paid for our Cushing to Broome pipeline expansion, (iii) $3.1 million paid for our Cushing Phase V expansion, and (iv) various other projects of approximately $21.3 million. Additionally, approximately $13.5 million was paid for various acquisitions. Net cash used in 2004 was

$155.9 million and was primarily comprised of (i) $142.3 million paid for the Capline and Capwood Pipeline Systems acquisition (a deposit had been paid in December 2003) and (ii) $13.3 million paid for additions to property and equipment, including approximately $3.4 million related to the Cushing Phase IV expansion.

Financing Activities. Cash provided by financing activities in 2005 was approximately $342.6 million, primarily consisting of:

•: approximately $22.3 million of proceeds from a private placement of common units,
•: net short and long-term borrowings under our revolving credit facility of approximately $23.5 million,
•: net borrowings under our short-term letter of credit and hedged inventory facility of approximately $344.6 million for the purchase of crude oil inventory that was stored (see "Operating Activities" above), and
•: $45.0 million of distributions paid to common unitholders and the general partner.

Cash provided by financing activities in 2004 was approximately $21.1 million, primarily consisting of:

•: net short and long-term borrowings under our revolving credit facility of approximately $157.5 million used primarily to fund the purchase price of the Capline acquisition,
•: net repayments under our short-term letter of credit and hedged inventory facility of approximately $100.5 million resulting from the collection of receivables related to prior year sales of inventory that was stored because of contango market conditions, and
•: $35.2 million of distributions paid to common unitholders and the general partner.

Contingencies

See Note 9 "Commitments and Contingencies" in "Notes to the Consolidated Financial Statements."

Commitments

Contractual Obligations. In the ordinary course of doing business we purchase crude oil and LPG from third parties under contracts, the majority of which range in term from thirty-day evergreen to three years. We establish a margin for these purchases by entering into various types of physical and financial sale and exchange transactions through which we seek to maintain a position that is substantially balanced between crude oil and LPG purchases and sales and future delivery obligations. The table below includes purchase obligations related to these activities. Where applicable the amounts presented represent the net obligations associated with buy/sell contracts and those subject to a net settlement arrangement with the counterparty. We do not expect to use a significant amount of internal capital to meet these obligations, as the obligations will be funded by corresponding sales to credit worthy entities.

The following table includes our best estimate of the amount and timing of these payments as well as others due under the specified contractual obligations as of March 31, 2005.

		2005		2006		2007		2008		2009		Thereafter
		(in millions)
Long-term debt and interest payments⁽¹⁾		$	40.3	$	53.8	$	53.8	$	53.8	$	352.9	$	799.7
Leases⁽²⁾			13.4		14.0		11.5		8.9		7.8		48.0
Capital expenditure obligations			23.4		—		—		—		—		—
Other long-term liabilities⁽³⁾			2.8		7.4		5.5		1.1		0.6		2.5

	Subtotal		79.9		75.2		70.8		63.8		361.3		850.2
Crude oil and LPG purchases⁽⁴⁾			1,419.0		132.4		114.7		114.7		93.1		—

	Total	$	1,498.9	$	207.6	$	185.5	$	178.5	$	454.4	$	850.2

⁽¹⁾: Includes debt service payments, interest payments due on our senior notes, interest payments due on the long-term portion of our revolving credit facility currently outstanding and the commitment fee on the portion of our revolving credit facility that is currently not utilized. The interest amount calculated on the long-term portion of our revolving credit facility is based on the assumption that the amount outstanding and the interest rate charged both remain at their current levels.
⁽²⁾: Leases are primarily for office rent and trucks used in our gathering activities.
⁽³⁾: Excludes approximately $12.2 million non-current liability related to SFAS 133 which are included in crude oil and LPG purchases.
⁽⁴⁾: Amounts are based on estimated volumes and market prices. The actual physical volume purchased and actual settlement prices may vary from the assumptions used in the table. Uncertainties involved in these estimates include levels of production at the wellhead, weather conditions, changes in market prices and other conditions beyond our control.

Letters of Credit. In connection with our crude oil marketing, we provide certain suppliers and transporters with irrevocable standby letters of credit to secure our obligation for the purchase of crude oil. Our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the crude oil is purchased. Generally, these letters of credit are issued for up to seventy-day periods and are terminated upon completion of each transaction. At March 31, 2005, we had outstanding letters of credit under our various facilities of approximately $174.5 million.

Forward-Looking Statements and Associated Risks

All statements, other than statements of historical fact, included in this report are forward-looking statements, including, but not limited to, statements identified by the words "anticipate," "believe," "estimate," "expect," "plan," "intend" and "forecast," and similar expressions and statements regarding our business strategy, plans and objectives of our management for future operations. These statements reflect our current views with respect to future events, based on what we believe are reasonable assumptions. Certain factors could cause actual results to differ materially from results anticipated in the forward-looking statements. These factors include, but are not limited to:

•: abrupt or severe production declines or production interruptions in outer continental shelf production located offshore California and transported on our pipeline system;
•: the success of our risk management activities;
•: the availability of, and our ability to consummate, acquisition or combination opportunities;
•: our access to capital to fund additional acquisitions and our ability to obtain debt or equity financing on satisfactory terms;
•: successful integration and future performance of acquired assets or businesses;

•: environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;
•: maintenance of our credit rating and ability to receive open credit from our suppliers;
•: declines in volumes shipped on the Basin Pipeline, Capline Pipeline and our other pipelines by third party shippers;
•: the availability of adequate third party production volumes for transportation and marketing in the areas in which we operate;
•: successful third party drilling efforts in areas in which we operate pipelines or gather crude oil;
•: demand for various grades of crude oil and resulting changes in pricing conditions or transmission throughput requirements;
•: fluctuations in refinery capacity in areas supplied by our transmission lines;
•: the effects of competition;
•: continued creditworthiness of, and performance by, counter parties;
•: the impact of crude oil price fluctuations;
•: the impact of current and future laws, rulings and governmental regulations;
•: shortages or cost increases of power supplies, materials or labor;
•: weather interference with business operations or project construction;
•: the currency exchange rate of the Canadian dollar;
•: fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our Long-Term Incentive Plan; and
•: general economic, market or business conditions.

Other factors, such as the "Risk Factors Related to Our Business" in 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 following should be read in conjunction with Quantitative and Qualitative Disclosures About Market Risks included in Item 7A in our 2004 Form 10-K. There have not been any material changes in that information other than those discussed below.

Commodity Price Risk

All of our open commodity price risk derivatives at March 31, 2005 were categorized as non-trading. The fair value of these instruments and the change in fair value that would be expected from a 10 percent price decrease are shown in the table below:

	Fair Value			Effect of 10% Price Decrease
	(in millions)
Crude oil:
Futures contracts	$	(30.6	)	$	(37.9	)
Swaps and options contracts	$	(11.5	)	$	3.8
LPG:
Swaps and options contracts	$	0.8		$	(0.8	)

Interest Rate Risk

We utilize both fixed and variable rate debt, and are exposed to market risk due to the floating interest rates on our credit facilities. Therefore, from time to time we utilize interest rate swaps and collars to hedge interest obligations on specific debt issuances, including anticipated debt issuances. The table below presents principal payments and the related weighted average interest rates by expected maturity dates for variable rate debt outstanding at March 31, 2005. The 7.75% senior notes issued during 2002, the 5.625% senior notes issued during 2003, the 4.75% senior notes issued during 2004, and the 5.88% senior notes issued during 2004 are fixed rate notes and their interest rates are not subject to market risk. Our variable rate debt bears interest at LIBOR, prime or the bankers acceptance plus the applicable margin. The average interest rates presented below are based upon rates in effect at March 31, 2005. The carrying values of the variable rate instruments in our credit facilities approximate fair value primarily because interest rates fluctuate with prevailing market rates.

			Expected Year of Maturity
			2005			2006		2007		2008		2009			Thereafter		Total
			(in millions)
Liabilities:
	Short-term debt—variable rate		$	555.0		$	—	$	—	$	—	$	—		$	—	$	555.0
		Average interest rate		3.5	%		—		—		—		—			—		3.5	%
	Long-term debt—variable rate		$	—		$	—	$	—	$	—	$	125.0		$	—	$	125.0
		Average interest rate		—			—		—		—		3.7	%		—		3.7	%

Item 4. CONTROLS AND PROCEDURES

We maintain "disclosure controls and procedures," which we refer to as our "DCP." The purpose of our DCP is to 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.

Applicable SEC rules require an evaluation of the effectiveness of the design and operation of our DCP. Management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our DCP as of March 31, 2005, and has found our DCP to be effective in 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.

In addition to the information concerning our DCP, we are required to disclose certain changes in our internal control over financial reporting ("internal control") that occurred during the first quarter and that has materially affected, or is reasonably likely to materially affect, our internal control. There are none. However, in the process of documenting and testing our internal control in connection with compliance with Rule 13a-15(c) under the Exchange Act of 1934, as amended (required by Section 404 of the Sarbanes-Oxley Act of 2002) we have made changes, and will continue to make changes, to refine and improve our internal control.

The certifications of our Chief Executive Officer and 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 our Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. §1350 are furnished with this report as Exhibits 32.1 and 32.2.

PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

Export License Matter. In our gathering and marketing activities, we import and export crude oil from and to Canada. Exports of crude oil are subject to the "short supply" controls of the Export Administration Regulations ("EAR") and must be licensed by the Bureau of Industry and Security (the "BIS") of the U.S. Commerce Department. In 2002, we determined that we may have violated the terms of our licenses with respect to the quantity of crude oil exported and the end-users in Canada. Export of crude oil except as authorized by license is a violation of the EAR. In October 2002, we submitted to the BIS an initial notification of voluntary disclosure. The BIS subsequently informed us that we could continue to export while previous exports were under review. We applied for and received several new licenses allowing for export volumes and end users that more accurately reflect our anticipated business and customer needs. We also conducted reviews of new and existing contracts and implemented new procedures and practices in order to monitor compliance with applicable laws regarding the export of crude oil to Canada. As a result, we subsequently submitted additional information to the BIS in October 2003 and May 2004. In August 2004, we received a request from the BIS for additional information. We have responded to this and subsequent requests, and continue to cooperate fully with BIS officials. At this time, we have received neither a warning letter nor a charging letter, which could involve the imposition of penalties, and no indication of what penalties the BIS might assess. As a result, we cannot reasonably estimate the ultimate impact of this matter.

Alfons Sperber v. Plains Resources Inc., et. al. On December 18, 2003, a putative class action lawsuit was filed in the Delaware Chancery Court, New Castle County, entitled Alfons Sperber v. Plains Resources Inc., et al. This suit, brought on behalf of a putative class of Plains All American Pipeline, L.P. common unitholders, asserted breach of fiduciary duty and breach of contract claims against us, Plains AAP, L.P., and Plains All American GP LLC and its directors, as well as breach of fiduciary duty claims against Plains Resources Inc. and its directors. (Plains Resources, Inc. is a unitholder and an interest owner in our general partner. See "Security Ownership of Certain Beneficial Owners and Management and Related Unitholders' Matters.") The complaint sought to enjoin or rescind a proposed acquisition of all of the outstanding stock of Plains Resources Inc., as well as declaratory relief, an accounting, disgorgement and the imposition of a constructive trust, and an award of damages, fees, expenses and costs, among other things. This lawsuit has been settled in principle. The court has approved the settlement and the settlement became final in March 2005.

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.

Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Securities Not Registered Under the Securities Act. On February 25, 2005, we issued 575,000 common units to a subsidiary of Vulcan Energy Corporation. The sale price for the common units was $38.13 per unit resulting in net proceeds, including the general partner's proportionate capital contribution and expenses associated with the sale, of approximately $22.3 million. We intend to use the net proceeds from the private placement to fund a portion of our 2005 expansion capital program. Pending the incurrence of such expenditures, the net proceeds will be used to repay indebtedness under our revolving credit facilities.

Item 3. DEFAULTS UPON SENIOR SECURITIES

None

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

See Item 4. "Submission of Matters to a Vote of Security Holders" in our 2004 Annual Report on Form 10-K.

Item 5. OTHER INFORMATION

None

Item 6. EXHIBITS

10.1		First Amendment, dated as of March 4, 2005, to the Credit Agreement dated November 2, 2004 among Plains All American Pipeline, L.P. (as US Borrower), PMC (Nova Scotia) Company and Plains Marketing Canada, L.P. (as Canadian Borrowers), and Bank of America, N.A.
†10.2		Second Amendment, dated as of May 6, 2005, to the Credit Agreement dated November 2, 2004 among Plains All American Pipeline, L.P. (as US Borrower), PMC (Nova Scotia) Company and Plains Marketing Canada, L.P. (as Canadian Borrowers), and Bank of America, N.A.
10.3		First Amendment to Restated Credit Agreement dated as of April 20, 2005, by and among Plains Marketing, L.P., Bank of America, N.A., as Administrative Agent, and the Lenders party thereto.
†31.1		Certification of 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)
*32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350.
*32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350

†: Filed herewith.
*: Furnished herewith.

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: May 9, 2005	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)
Date: May 9, 2005	By:	/s/ PHIL KRAMER Phil Kramer, Executive Vice President and Chief Financial Officer of Plains All American GP LLC (Principal Financial Officer)

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TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

Item 1. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (in thousands, except unit data)
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands, except per unit data)
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands)
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL (in thousands)
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME AND CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (in thousands)
Statements of Comprehensive Income
Statement of Changes in Accumulated Other Comprehensive Income
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

Item 4. CONTROLS AND PROCEDURES

PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Item 3. DEFAULTS UPON SENIOR SECURITIES

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Item 5. OTHER INFORMATION

Item 6. EXHIBITS

SIGNATURES