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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

ýx		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended ~~March 31,~~June 30, 2005
OR

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
~~Commission file number: 1-14569~~

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)~~

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/~~x No ~~/ /~~o

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

At ~~May~~August 2, 2005, there were outstanding ~~67,868,108~~67,914,576 Common Units.

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
	(unaudited)						(unaudited)
REVENUES
Crude oil and LPG sales (includes buy/sell transactions of approximately $3,706,119 and $3,450,671 for the three month periods, and $7,125,168 and $5,285,528 for the six month periods, respectively)	$	6,919,504		$	4,931,969		$	13,337,293		$	8,555,451
Other gathering, marketing, terminalling and storage revenues	11,323			9,106			19,496			16,727
Pipeline margin activities revenues (includes buy/sell transactions of approximately $40,049 and $34,924 for the three month periods, and $73,557 and $81,347 for the six month periods, respectively)	174,858			138,831			332,485			281,166
Pipeline tariff activities revenues	55,022			51,829			109,929			83,035
Total revenues	7,160,707			5,131,735			13,799,203			8,936,379
COSTS AND EXPENSES
Crude oil and LPG purchases and related costs (includes buy/sell transactions of approximately $3,583,578 and $3,374,566 for the three month periods, and $6,984,505 and $5,166,200 for the six month periods, respectively)	6,804,159			4,859,173			13,138,805			8,417,244
Pipeline margin activities purchases (includes buy/sell transactions of approximately $37,299 and $33,343 for the three month periods, and $68,798 and $77,686 for the six month periods, respectively)	167,531			132,694			319,045			269,128
Field operating costs (excluding LTIP charge)	66,846			59,035			130,322			95,851
LTIP charge—operations	975			—			1,319			567
General and administrative expenses (excluding LTIP charge)	19,198			19,603			39,414			35,081
LTIP charge—general and administrative	6,951			—			8,846			3,661
Depreciation and amortization	19,448			15,998			38,566			29,118
Total costs and expenses	7,085,108			5,086,503			13,676,317			8,850,650
Gain on sales of assets	445			84			445			84
OPERATING INCOME	76,044			45,316			123,331			85,813
OTHER INCOME/(EXPENSE)
Interest expense (net of $346 and $219 capitalized for the three month periods, respectively, and $966 and $397 capitalized for the six month periods, respectively)	(14,253		)	(9,967		)	(28,811		)	(19,499		)
Interest and other income (expense), net	491			328			570			369
Income before cumulative effect of change in accounting principle	62,282			35,677			95,090			66,683
Cumulative effect of change in accounting principle	—			—			—			(3,130		)
NET INCOME	$	62,282		$	35,677		$	95,090		$	63,553
NET INCOME—LIMITED PARTNERS	$	57,602		$	33,247		$	86,867		$	58,954
NET INCOME—GENERAL PARTNER	$	4,680		$	2,430		$	8,223		$	4,599
BASIC NET INCOME PER LIMITED PARTNER UNIT
Income before cumulative effect of change in accounting principle	$	0.76		$	0.54		$	1.27		$	1.03
Cumulative effect of change in accounting principle	—			—			—			(0.05		)
Net income	$	0.76		$	0.54		$	1.27		$	0.98
DILUTED NET INCOME PER LIMITED PARTNER UNIT
Income before cumulative effect of change in accounting principle	$	0.74		$	0.54		$	1.26		$	1.03
Cumulative effect of change in accounting principle	—			—			—			(0.05		)
Net income	$	0.74		$	0.54		$	1.26		$	0.98
BASIC WEIGHTED AVERAGE UNITS OUTSTANDING	67,893			61,556			67,706			59,985
DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING	69,274			61,556			68,719			59,985

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)

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

	Six Months Ended June 30,
	2005			2004
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	95,090		$	63,553
Adjustments to reconcile to cash flows from operating activities:
Depreciation and amortization	38,566			29,118
Cumulative effect of change in accounting principle	—			3,130
Change in derivative fair value	26,327			(556		)
Long-Term Incentive Plan charge	10,165			4,228
Noncash amortization of terminated interest rate swap	790			714
Noncash loss on foreign currency revaluation	(918		)	(573		)
Net cash paid for terminated swaps	(865		)	—
Gain on sales of assets	(445		)	(84		)
Changes in assets and liabilities, net of acquisitions:
Trade accounts receivable and other	(589,411		)	(27,918		)
Inventory	(351,461		)	(24,135		)
Accounts payable and other current liabilities	311,073			99,423
Due to related parties	7,697			210
Net cash provided by (used in) operating activities	(453,392		)	147,110
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions	(14,545		)	(443,210		)
Additions to property and equipment	(86,254		)	(32,170		)
Proceeds from sales of assets	3,380			737
Net cash used in investing activities	(97,419		)	(474,643		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings/(repayments) on long-term revolving credit facility	(143,639		)	415,827
Net borrowings/(repayments) on working capital revolving credit facility	71,800			(12,100		)
Net borrowings/(repayments) on short-term letter of credit and hedged inventory facility	575,300			(96,091		)
Proceeds from the issuance of senior notes	149,277			—
Net proceeds from the issuance of common units	22,308			101,213
Distributions paid to unitholders and general partner	(92,657		)	(72,673		)
Other financing activities	(5,826		)	(2,141		)
Net cash provided by financing activities	576,563			334,035
Effect of translation adjustment on cash	(740		)	1,417
Net increase in cash and cash equivalents	25,012			7,919
Cash and cash equivalents, beginning of period	12,988			4,137
Cash and cash equivalents, end of period	$	38,000		$	12,056
Cash paid for interest, net of amounts capitalized	$	35,825		$	20,547

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)

																			Total
					Class B					Class C					General				Partners'
	Common Units				Common Units					Common Units					Partner			Total	Capital
	Units	Amount			Units		Amount			Units		Amount			Amount			Units	Amount
	(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		)	—			—	—
LTIP Issuance	47	1,863			—		—			—		—			38			47	1,901
Distributions	—	(81,694		)	—		(801		)	—		(1,988		)	(8,174		)	—	(92,657		)
Net income	—	84,958			—		548			—		1,361			8,223			—	95,090
Other comprehensive income	—	(94,239		)	—		(199		)	—		(494		)	(1,937		)	—	(96,869		)
Balance at June 30, 2005	67,915	$	970,199		—		$	—		—		$	—		$	29,778		67,915	$	999,977

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

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF ~~OPERATIONS~~COMPREHENSIVE INCOME AND
CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME

(in ~~thousands, except per unit data)~~
thousands)

Statements of Comprehensive Income

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

Three Months Ended

Six Months Ended

June 30,

June 30,

2005

2004

2005

2004

(unaudited)

Net income

$
62,282

$
35,677

$
95,090

$
63,553

Other comprehensive income (loss)

(27,111
)

14,047

(96,869
)

3,233

Comprehensive income (loss)

$
35,171

$
49,724

$
(1,779
)

$
66,786

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

(568
)

—

(568
)
Changes in fair value of outstanding hedge positions

(88,082
)

—

(88,082
)
Currency translation adjustment

—

(8,219
)

(8,219
)
Total period activity

(88,650
)

(8,219
)

(96,869
)
Balance at June 30, 2005

$
(62,713
)

$
62,715

$
2

The accompanying notes are an integral part of these consolidated financial statements.
7

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

During May 2005, we ~~amended~~completed the sale of $150 million of 5.25% Senior Notes due 2015. The notes were sold at 99.518% of face value. The notes were co-issued by us and a 100% owned consolidated finance subsidiary (neither of which have independent assets or operations). Interest payments are due on June 15 and December 15 of each year. The notes are fully and unconditionally guaranteed, jointly and severally, by all of our ~~senior secured hedged inventory facility~~existing 100% owned subsidiaries, except for subsidiaries which are minor. We used the proceeds to ~~increase the capacity~~repay amounts outstanding 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.~~ our credit facilities and for general partnership purposes.

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~~billion, subject to obtaining additional lender commitments. Additionally, in the second quarter of 2005, we ~~entered into a treasury lock with a large creditworthy financial institution. A treasury lock is a financial derivative instrument that enables~~amended our senior secured hedged inventory facility to increase the ~~company~~capacity under the facility from $425 million 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.$800 million.

Note 5—Earnings Per ~~Common~~Limited Partner Unit

Except as discussed in the following paragraph, basic and diluted net income per limited partner unit is determined by dividing net income after deducting the amount allocated to the general partner interest, (including its incentive distribution in excess of its 2% interest), by the weighted average number of outstanding limited partner units during the period. Partnership income is first allocated to the general partner based on the amount of incentive distributions. The remainder is then allocated between the limited partners and general partner based on percentage ownership in the Partnership.

Emerging Issues Task Force Issue No. 03-06 (“EITF 03-06”), “Participating Securities and the Two-Class Method under FASB Statement No. 128” addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity when, and if, it declares dividends on its common stock. Essentially, EITF 03-06 provides that in any accounting period where our aggregate net income exceeds our aggregate distribution for such period, we are required to present earnings per unit as if all of the earnings for the periods were distributed, regardless of the pro forma nature of this allocation and whether those earnings would actually be distributed during a particular period from an economic or practical perspective. EITF 03-06 does not impact our overall net income or other financial results, however, for periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing the earnings per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights held by our general partner, even though we make cash distributions on the basis of cash available for distributions, not earnings, in any given accounting period. In accounting periods where aggregate net income does not exceed our aggregate distributions for such period, EITF 03-06 does not have any impact on our earnings per unit calculation.

The following sets forth the computation of basic and diluted earnings per ~~common~~limited partner 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,~~June 30, 2005 and 2004.

			Three months ended March 31,						Three months ended June 30,						Six months ended June 30,
			2005			2004			2005			2004			2005			2004
			(in thousands, except per unit data)						(in thousands, except per unit data)
Net income	Net income		$	32,808		$	27,876		$	62,282		$	35,677		$	95,090		$	63,553
Less:	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
General partner’s incentive distribution paid									(3,504		)	(1,752		)	(6,450		)	(3,396		)
Subtotal									58,778			33,925			88,640			60,157
General partner 2% ownership									(1,176		)	(678		)	(1,773		)	(1,203		)
Net income available to limited partners									57,602			33,247			86,867			58,954
Pro forma additional general partner’s incentive distribution									(6,174		)	—			(560		)	—
Net income available to limited partners under EITF 03-06 (numerator for basic and diluted earnings per limited partner unit)									$	51,428		$	33,247		$	86,307		$	58,954
Denominator:
Denominator for basic earnings per limited partner unit-weighted average number of limited partner units									67,893			61,556			67,706			59,985
Effect of dilutive securities:	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

Weighted average LTIP units (see Note 7)									1,381			—			1,013			—
Denominator for diluted earnings per limited partner unit-weighted average number of limited partner units									69,274			61,556			68,719			59,985
Basic net income per limited partner unit	Basic net income per limited partner unit		$	0.43		$	0.44		$	0.76		$	0.54		$	1.27		$	0.98

Diluted net income per limited partner unit	Diluted net income per limited partner unit		$	0.43		$	0.44		$	0.74		$	0.54		$	1.26		$	0.98

Note 6—~~Partners'~~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~~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,~~Although the net proceeds were used to repay indebtedness under our revolving credit ~~facilities.~~facilities at closing, they will ultimately be used to fund a portion of our 2005 expansion capital program as those expenditures are incurred.

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
The following table details the distributions we have declared and paid in 2005:

Total of distribution paid to:

Distribution

General partner:

per Limited

Limited

Incentive

Distribution Payment Date

Partner Unit

Partners

Distribution

2% ownership

(in millions, except per unit data)

August 12, 2005⁽¹⁾

$
0.6500

$
44.1

$
3.8

$
0.9

May 13, 2005

$
0.6375

$
43.3

$
3.5

$
0.9

February 14, 2005

$
0.6125

$
41.2

$
3.0

$
0.8

~~Distributions~~(1)
        ~~On April~~The distribution we declared on July 22, 2005, ~~we declared a cash distribution of $0.6375 per unit on our outstanding common units. The distribution~~ is payable on ~~May 13,~~August 12, 2005, to unitholders of record on ~~May 3, 2005, for the period January 1, 2005, through March 31,~~August 2, 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"~~“1998 LTIP”) and the 2005 Long-Term Incentive Plan (the ~~"2005 LTIP"~~“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~~Approximately 92,000 phantom units outstanding under the 1998 LTIP ~~of which we expect approximately 93,000 to vest~~vested in May 2005. We paid cash in lieu of delivery of common units for approximately 20,000 of the phantom units and issued approximately 47,000 new common units (after netting for taxes) in connection with the vesting. As of June 30, 2005, there are approximately 57,000 phantom units outstanding under the 1998 LTIP, which have vesting terms over the next four years, if certain performance criteria are met. 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

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.~~met.
        ~~In addition to the phantom units discussed above, four~~Four of our non-employee directors each have received an LTIP ~~awards~~award of 5,000 ~~units in the aggregate.~~units. These awards vest yearly in 25% increments (1,250 ~~units)~~units each). 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. In June 2005, 5,000 director units vested.
13

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 seven 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 and terminate with the vesting or forfeiture of the related phantom units. The following awards were outstanding under the 2005 LTIP at June 30, 2005:
Annualized

Phantom Units

DERs

Distribution Rate

Date

A(1)

B(2)

Total

A(1)

B(2)

Total

(in thousands)

$2.60

May 2007

561

150

711

363

150

513

$2.70

May 2008

—

—

—

136

75

211

$2.80

May 2009

421

150

571

136

75

211

$2.90

May 2010

—

—

—

136

100

211

$3.00

May 2010

421

200

622

136

100

211

1,403

500

1,903

907

500

1,407

(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 as they will vest at the end of a determinant time and are included in our diluted 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 seven years. These awards are not common stock equivalents as they may never vest and are not included in our diluted 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.
We have concluded that it is probable that we will achieve a ~~$2.60~~$2.80 annualized distribution rate and therefore have accelerated the vesting of the portion of the awards that vest ~~based on~~up to that rate. We recognized total compensation expense of approximately ~~$2.2~~$7.9 million in the second quarter of 2005 for a total of $10.2 million in the first ~~quarter~~half 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~~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 the hedged items.
14

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~~as well as with respect to 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"~~(“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 the hedged items are marked-to-market in revenues each period.

During the first ~~quarter~~half of 2005, our earnings include a net gain of approximately ~~$35.5~~$77.8 million resulting from all derivative activities, including the change in fair value of open derivatives and settled derivatives taken to earnings during the ~~quarter.~~period. This gain includes:
a)
a net mark-to-market loss of $26.3 million (a $13.4 million loss in the first quarter and a $12.9 million loss in the second quarter), which is comprised of:

·
•
the net change in fair value during the ~~quarter~~period of open derivatives used to hedge price exposure that do not qualify for hedge accounting (a loss of approximately ~~$12.7~~$25.9 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~~$0.4 million).

b)
a net gain of ~~$48.9~~$104.1 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~~half 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,~~June 30, 2005:
Other current assets $ 21.6

$
25.5

Other long-term assets 9.6

0.9

Other current-liabilities (65.8 )

(100.4
)
Other long-term liabilities and deferred credits (12.2 )

(6.5
)

The net liability as of ~~March 31,~~June 30, 2005, relates mostly to unrealized losses on effective cash flow hedges that are deferred to OCI. At ~~March 31,~~June 30, 2005, there is a total unrealized net loss of approximately ~~$41.4~~$62.7 million deferred to OCI. This includes ~~$35.7~~$56.5 million, which predominantly relates to unrealized losses on derivatives used to hedge physical inventory in storage that receive hedge accounting, and ~~$5.7~~$6.2 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.
15

Of the total net loss deferred in OCI at ~~March 31,~~June 30, 2005, a net loss of ~~$36.0~~$57.8 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~~six months ended ~~March 31,~~June 30, 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
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"~~“short supply” controls of the Export Administration Regulations ~~("EAR"~~(“EAR”) and must be licensed by the Bureau of Industry and Security (the

~~"BIS"~~ “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,~~our personnel, the U.S. Environmental Protection Agency (“EPA”), 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~~us in the course of site remediation. Aggregate costs associated with the releases, including estimated remediation costs, are estimated to be approximately ~~$3.0~~$3.5 million to ~~$3.5~~$4.0 million. We continue to work with the appropriate state and federal environmental authorities ~~in responding~~with respect to ~~the releases~~site restoration 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.
16

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. As we expand our pipeline assets through acquisitions, we expect the absolute number of releases during a given period to increase and we have, in fact, experienced such an increase in connection with our purchase of the Link assets. As a result, we have also received an increased number of requests for information from governmental agencies with respect to such leaks (such as EPA requests under Clean Water Act Section 308), commensurate with the scale and scope of our pipeline operations. We cannot predict the effect, if any, of increased scrutiny by governmental authorities of the crude oil pipeline business.
At ~~March 31,~~June 30, 2005, our reserve for environmental liabilities totaled approximately ~~$23.3~~$23.7 million. Approximately ~~$16.3~~$14.9 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~~we consider 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~~Additionally, we choose to self-insure certain types of risks, including risks associated with gradual seepage and pollution and property damage for pipe in the ~~environmental insurance industry appears~~ground, which we believe are cost prohibitive 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.insure.
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.
17

Note 10—Operating Segments

Our operations consist of two operating segments: (i) pipeline transportation operations ~~("Pipeline Operations"~~(“Pipeline”) and (ii) gathering, marketing, terminalling and storage operations ("(“GMT~~&S"~~&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)~~delivery resulting from high demand) provide an offset to this reduced cash flow. In addition, we supplement the counter-cyclical balance of our asset base with derivative hedging activities.

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. 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 mitigate the actual decline in the value of our principal fixed assets. 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, which is deducted in determining “available cash”, 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 considered expansion capital expenditures, not ~~considered~~ maintenance ~~capital expenditures.~~capital. 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~~indicated:

	Pipeline			GMT&S			Total
Three Months Ended June 30, 2005(1)	(in millions)
Revenues:
External Customers (includes buy/sell revenues of $40.0 and $3,706.1, respectively)(2)		$	229.9	$	6,930.8		$	7,160.7
Intersegment(3)		30.6		0.2			30.8
Total revenues of reportable segments		$	260.5	$	6,931.0		$	7,191.5
Segment profit(2)(4)(5)		$	41.4	$	53.7		$	95.1
Non-cash SFAS 133 impact(2)		$	—	$	(12.9	)	$	(12.9	)
Maintenance capital		$	2.5	$	1.5		$	4.0

	Pipeline		GMT&S			Total
	(in millions)
Three Months Ended June 30, 2004
Revenues:
External Customers (includes buy/sell revenues of $34.9 and $3,450.7, respectively)(2)	$	190.7	$	4,941.1		$	5,131.8
Intersegment(3)	32.1		0.2			32.3
Total revenues of reportable segments	$	222.8	$	4,941.3		$	5,164.1
Segment profit(2)(4)(5)	$	47.7	$	13.5		$	61.2
Non-cash SFAS 133 impact(2)	$	—	$	(6.9	)	$	(6.9	)
Maintenance capital	$	0.6	$	0.7		$	1.3

Six Months Ended June 30, 2005(1)
Revenues:
External Customers (includes buy/sell revenues of $73.6 and $7,125.2, respectively)(2)	$	442.4	$	13,356.8		$	13,799.2
Intersegment(3)	65.3		0.4			65.7
Total revenues of reportable segments	$	507.7	$	13,357.2		$	13,864.9
Segment profit(2)(4)(5)	$	91.5	$	70.0		$	161.5
Non-cash SFAS 133 impact(2)	$	—	$	(26.3	)	$	(26.3	)
Maintenance capital	$	5.3	$	2.7		$	8.0
Six Months Ended June 30, 2004
Revenues:
External Customers (includes buy/sell revenues of $81.3 and $5,285.5, respectively)(2)	$	364.2	$	8,572.2		$	8,936.4
Intersegment(3)	47.9		0.4			48.3
Total revenues of reportable segments	$	412.1	$	8,572.6		$	8,984.7
Segment profit(2)(4)(5)	$	73.2	$	41.6		$	114.8
Non-cash SFAS 133 impact(2)	$	—	$	0.5		$	0.5
Maintenance capital	$	2.1	$	1.0		$	3.1

(1)In May 2005, we reclassified certain minor pipeline gathering assets from the GMT&S segment to the Pipeline segment. Historically, we have been the sole shipper on these assets as part of our gathering and marketing operations. Prior period segment information has not been restated for this change since the ~~items in the following table excludes depreciation and amortization):~~impact to such periods was not material.

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⁾(2)

~~Intersegment sales are conducted at arms length.~~

⁽²⁾

Amounts related to SFAS 133 are included in revenues and impact segment profit.

⁽³⁾

Intersegment sales are conducted at arms length.

(4)GMT&S segment profit includes interest expense of $5.8 million and $0.3 million for the quarters ended June 30, 2005 and 2004, respectively, and $9.2 million and $0.4 million for the six month periods ended June 30, 2005 and 2004, respectively, on contango inventory purchases.

(5)The following table reconciles segment profit to consolidated income before cumulative effect of change in accounting principle:

	For the three months								For the six months
	ended June 30,								ended June 30,
	2005				2004				2005			2004
	(in millions)
Segment profit		$	95.1			$	61.2		$	161.5		$	114.8
Depreciation and amortization		(19.4		)		(16.0		)	(38.6		)	(29.1		)
Gain on sales of assets		0.4				0.1			0.4			0.1
Interest expense		(14.3		)		(10.0		)	(28.8		)	(19.5		)
Interest income and other, net		0.5				0.4			0.6			0.4
Income before cumulative effect of change in accounting principle		$	62.3			$	35.7		$	95.1		$	66.7

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

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

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%~~ 40% and 56%in the second quarter and first ~~quarter~~half of 2005, respectively, compared to the second quarter and first ~~quarter~~half of 2004, ~~while~~respectively. During the same time periods, our

segment profit ~~decreased~~increased almost ~~42%~~300% and 68%, respectively. These increases are discussed further below.

The increase in revenues for both the ~~same period. This decrease is related to the impact~~second quarter and first half 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 same periods in 2004 ~~period. Approximately 70%~~was primarily because of ~~the increase in revenues resulted from~~ higher ~~average~~crude oil prices induring the 2005 ~~period and the remainder was attributable to increased sales volumes.~~periods. The average NYMEX price for crude oil was ~~$49.88~~$53.23 per barrel and ~~$35.21~~$51.60 per barrel for the quarter and six months ended ~~March 31,~~June 30, 2005, respectively, as compared to $38.28 per barrel and $36.78 per barrel for the same periods in 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						Six months ended
	June 30,						June 30,
	2005			2004			2005			2004
	(in millions)
Operating Results(1)
Revenues(2)(3)	$	6,931.0		$	4,941.3		$	13,357.2		$	8,572.6
Purchases and related costs(4)	(6,834.7		)	(4,891.3		)	(13,204.1		)	(8,464.2		)
Field operating costs (excluding LTIP charge)	(29.1		)	(27.2		)	(58.6		)	(45.7		)
LTIP charge—operations	(0.7		)	—			(0.9		)	(0.4		)
Segment G&A expenses (excluding LTIP charge)(5)	(9.9		)	(9.3		)	(20.0		)	(18.7		)
LTIP charge—general and administrative(5)	(2.9		)	—			(3.6		)	(2.0		)
Segment profit(3)	$	53.7		$	13.5		$	70.0		$	41.6
SFAS 133 noncash mark-to-market adjustment(3)	$	(12.9	)	$	(6.9	)	$	(26.3	)	$	0.5
Maintenance capital	$	1.5		$	0.7		$	2.7		$	1.0
Segment profit per barrel(6)	$	0.91		$	0.23		$	0.57		$	0.39
Average Daily Volumes (thousands of barrels per day)(7)
Crude oil lease gathering	628			641			625			550
LPG sales	26			21			55			40

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~~$3,706.1 million and ~~$1,834.9~~$3,450.7 million for the quarters ended ~~March 31,~~June 30, 2005 and 2004, respectively. Volumes associated with these arrangements were approximately ~~855,000~~825,000 barrels per day and ~~597,000~~1,065,000 barrels per day for the quarters ended ~~March 31,~~June 30, 2005 and 2004, respectively. Revenues associated with buy/sell arrangements were $7,125.2 million and $5,285.5 million for the six months ended June 30, 2005 and 2004, respectively. Volumes associated with these arrangements were approximately 829,000 barrels per day and 659,000 barrels per day for the six

months ended June 30, 2005 and 2004, respectively. The previously referenced amounts include certain estimates based on ~~management's~~management’s judgment; such estimates are not expected to have a material impact on the balances.

⁽³⁾

Amounts related to SFAS 133 are included in revenues and impact segment profit.

(4)Purchases and related costs include interest expense of $5.8 million and $0.3 million for the quarters ended June 30, 2005 and 2004, respectively, and $9.2 million and $0.4 million for the six month periods ended June 30, 2005 and 2004, respectively, on contango inventory purchases.

(5)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⁾(6)

~~Amounts related to SFAS 133 are included in revenues and impact segment profit.~~

⁽⁵⁾

Calculated based on crude oil lease gathered ~~barrels~~volumes and LPG sales ~~barrels.~~

volumes. ⁽⁶⁾(7)

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%~~for the second quarter and first half of 2005 greatly exceeded the comparable 2004 periods. The increase in the 2005 periods is partially driven by increased volumes (for the six month period) and synergies realized from businesses acquired in the last eighteen months coupled with very favorable market conditions.

The primary drivers of the current periods results were:

· Favorable market conditions—These favorable market conditions include a shift in the market structure from a backwardated market of as wide as $1.14 per barrel in late 2004 to ~~$16.3 million~~a prolonged and pronounced contango market that has been as wide as $1.91 during the first half of 2005. The contango market structure averaged approximately $0.33 and $1.16 for the first ~~quarter~~and second quarters of 2005, respectively. Although we are normally adversely impacted by the initial transition from a backwardated market to a contango market, the market has remained in contango throughout most of the first half of 2005 and we have been able to adjust our purchases at the wellhead to both maintain our margins and remain competitive in the gathering and marketing business. In addition, we have been able to use a portion of our tankage in our terminalling and storage business to capture a significant level of profits from contango-related strategies. We have been able to do this because the market has already transitioned to a contango market and has remained there for an extended period of time.

During the 2005 period, the market has also experienced significantly high volatility in price and market structure of crude oil. The NYMEX benchmark price of crude oil has ranged from $41.25 to $60.95 during the first half of 2005. This volatile market allowed us to utilize our hedging activities tooptimize and enhance the margins of both our gathering and marketing assets and our terminalling and storage assets at different times during the quarter. Increased receipts of foreign crude oil movements at our facilities also positively impacted our results.

· 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 14% during the first half of 2005 as compared to the first ~~quarter~~half of 2004. The increase is primarily related to the Link acquisition. In addition, we marketed 38% more LPG during the first half of 2005 as compared to 2004. Crude oil lease gathered volumes and LPG sales volumes were both relatively flat in the second quarter of 2005 as compared to 2004.

· 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 during 2005 as compared to 11 million and 12.6 million barrels in the first and second quarters of 2004, respectively.

· Decreased purchases and related costs—Lower tariffs on barrels shipped by us on certain pipelines acquired in the Link acquisition reduced purchases and related costs by approximately $5.0 million. Segment profit for our Pipeline segment was decreased by a comparable amount.

· Increased field operating costs—Our continued growth, primarily from the Link acquisition, is the primary ~~reason~~driver of the increase in field operating costs for the ~~decrease from quarter~~first half of 2005 as compared to ~~quarter is~~ the ~~impact~~first half of ~~our~~2004. The increased costs are pimarily related to (i) payroll and benefits and (ii) fuel.

The 2005 period also includes a noncash mark-to-market adjustment ~~for open derivative instruments~~loss of $12.9 million pursuant to SFAS ~~133. The noncash mark-to-market adjustment~~133 that was recognized in the second quarter compared to a net loss of ~~$13.4~~$6.9 million in the ~~current~~second quarter of 2004. In addition, we recognized a net loss of $26.3 million in the first half of 2005 pursuant to SFAS 133 compared to a net gain of ~~$7.5~~$0.5 million in the first ~~quarter~~half of 2004. ~~This adjustment resulted in a decrease in segment profit of 74%.~~ The primary components of the $26.3 million noncash adjustment in ~~the first quarter of~~ 2005 were:

•

·A decrease in the mark-to-market of approximately ~~$4.6~~$20.3 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 portion of the decrease in fair value during the ~~mark-to-market resulting from~~current period relates to 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~~gains from the previous period. Total settlements related to ~~options and futures contracts associated with our gathering and tankage business exposures.~~

•

these strategies during the first half of 2005 were $11.7 million.

·A decrease in the mark-to-market of approximately ~~$2.6~~$6.9 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;~~fluctuate. These positions primarily consist of hedges of stored inventory and

•

purchase commitments. The loss in the current period primarily results from the impact of rising prices. A portion of the decrease in fair value during the current period relates to the settlement of mark-to-market gains from the previous period. Total settlements related to these strategies during the first half of 2005 were $1.0 million.

·An increase in the mark-to-market of ~~$0.6~~$0.9 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~~ A portion of the increase in ~~field operating costs for~~fair value during the ~~2005~~current period ~~as compared~~relates to the ~~2004~~settlement of mark-to-market losses from the previous period.

~~The impact~~ Total settlements related to these derivatives during the first half of ~~the items discussed above resulted in segment~~2005 were $1.3 million.

Segment profit per barrel (calculated based on our lease gathered crude oil and LPG ~~barrels) of $0.26~~volumes) was $0.91 per barrel for the quarter ended ~~March 31,~~June 30, 2005, compared to ~~$0.60~~$0.23 for the quarter ended ~~March 31,~~June 30, 2004. ~~The SFAS 133 noncash mark-to-market adjustment had a negative $0.21 segment~~Segment profit per barrel ~~impact in~~was $0.57 for the first ~~quarter~~half of 2005, compared to ~~a positive $0.16 segment profit~~$0.39 per barrel ~~impact in~~for the first ~~quarter~~half of 2004.

As discussed above, our current period results were strongly impacted by favorable market conditions. We are not able to predict with any reasonable level of accuracy whether market conditions will continue to remain as favorable as have recently been experienced, and operating results may not be indicative of sustainable performance.

Other Expenses

Depreciation and Amortization

Depreciation and amortization expense ~~was $19.1~~increased approximately $9.5 million ~~for~~to $38.6 million in the ~~three months ended March 31, 2005, compared to $13.1 million for the three months ended March 31, 2004.~~first half of 2005. The increase relates primarily to the assets from our 2004 acquisitions being included for the ~~full quarter~~entire period in 2005 versus only a part ~~or none~~ of the ~~quarter~~period in 2004. Additionally, several capital projects

were completed during mid-to-late 2004 that were not included in first ~~quarter~~half of 2004 depreciation expense. The increase of $3.4 million to $19.4 million in the second quarter of 2005 is primarily related to the capital projects completed in 2004, as previously mentioned. Amortization of debt issue costs was ~~$0.6~~$0.7 million and ~~$0.5~~$1.3 million in the second quarter and first ~~quarter~~half of 2005, respectively, and ~~2004, respectively.~~was relatively flat compared to the corresponding periods in 2004.
Interest Expense
        ~~The amount of interest~~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~~our average debt balances:

For the three

For the six

months ended June 30,

months ended June 30,

2005

2004

2005

2004

(average amount outstanding, in millions)

Fixed rate senior notes(1)

$
863

$
450

$
832

$
450

Borrowings under our
revolving credit facilities⁽²⁾

163

493

187

321

Total

$
1,026

$
943

$
1,019

$
771

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~~Weighted average face amount of senior notes, exclusive of discounts.
⁽²⁾Excludes borrowings under our senior secured hedged inventory facility and other contango inventory-related borrowings.
The higher average debt balance in both of the 2005 ~~period~~periods was primarily related to the portion of our acquisitions that were not ~~refinanced~~financed 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%~~6.2% for both ~~periods.~~of the 2005 periods, compared to 4.2% and 4.9% for the second quarter and first half of 2004, respectively.
The net impact of the items discussed above was an increase in interest expense in the ~~first~~second quarter of 2005 of approximately ~~$5.0~~$4.3 million to a total of ~~$14.6~~$14.3 million. ~~This~~In the first half of 2005, interest expense increased $9.3 million to $28.8 million. The increase in interest expense in the second quarter of 2005 is primarily related to the ~~rise~~increase in our weighted average interest rate, along with the increase in our average debt balance. The increase in interest expense in the first half of 2005 is related to both the increase in our average debt balance ~~partially offset by an~~and the increase in our weighted average interest ~~capitalized.~~rate.
Interest costs attributable to borrowings for inventory stored ~~inventory~~in a contango market are included in purchases and related costs in our GMT&S segment profit ~~for purposes of matching those costs with~~as we consider interest on these borrowings a direct cost to storing the ~~profits realized on storing crude oil.~~inventory. These borrowings are primarily under our senior secured hedged inventory facility. These costs were approximately ~~$3.4~~$5.8 million and ~~$0.1~~$9.2 million for the ~~quarters ended March 31,~~second quarter and first half of 2005, respectively. In 2004, these costs were approximately $0.3 million and ~~2004,~~$0.4 million for the second quarter and first half, respectively.
32

Outlook
This ~~"Outlook"~~“Outlook” section and the section captioned ~~"Forward~~“Forward Looking Statements and Associated ~~Risks"~~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 midstream crude-oil 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 other midstream businesses ~~that~~to which such resources effectively can be applied. We are ~~closely related to, or significantly intertwined~~presently engaged in discussions and negotiations with various parties regarding the ~~crude oil business. We~~acquisition of assets and businesses described above, but 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,~~June 30, 2005, we had a working capital deficit of approximately ~~$115.5~~$121.5 million, approximately ~~$320.5~~$618.7 million of availability under our committed revolving credit facilities and ~~no unused capacity~~approximately $144.3 million of availability under our uncommitted hedged inventory facility (see ~~"Capital Resources"~~“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~~July 2005, we ~~issued 575,000 common units~~filed with the Securities and Exchange Commission a universal shelf registration statement that, subject to ~~a subsidiary~~effectiveness at the time 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 withuse, allows us to issue from time to time up to an aggregate of $2 billion of debt or equity securities.
During May 2005, we completed the sale of ~~approximately $22.3 million.~~$150 million of 5.25% Senior Notes due 2015. The notes were sold at 99.518% of face value. We ~~intend to use~~used 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~~approximately $148 million, after deducting initial purchaser discounts and offering costs, to repay ~~indebtedness~~amounts outstanding under our ~~revolving~~ credit ~~facilities.~~facilities and for general partnership purposes.

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.~~billion, subject to obtaining additional lender commitments. Additionally, in the second quarter of 2005, we amended our senior secured hedged inventory facility to increase the capacity under the facility from $425 million to $800 million.
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. Although the net proceeds were used to repay indebtedness under our revolving credit facilities at closing, they will ultimately be used to fund a portion of our 2005 expansion capital program as these expenditures are incurred.
33

Capital Expenditures
We have made and will continue to make capital expenditures for acquisitions, expansion capital and maintenance capital. Historically, we have financed these expenditures primarily with cash generated by operations, credit facility borrowings, the issuance of senior unsecured notes and the sale of additional common units.
We expect to spend approximately $190 million on expansion capital projects during 2005. This includes our original estimate of expansion capital and newly announced projects, the most notable of which is our recently announced construction of a St. James, Louisiana storage facility. The St. James facility has an estimated total project cost of approximately $85 million, of which approximately $21 million will be spent in 2005. Our 2005 expansion capital projects include the following notable projects with the estimated cost for the entire year.

2005

Total

(in millions)

St. James, Louisiana storage facility

$
21.0

Trenton pipeline expansion

$
34.0

Capital projects associated with the Link acquisition

$
18.0

NW Alberta fractionator

$
16.0

Cushing Phase V expansion

$
13.0

Kerrobert Tank expansion

$
9.0

Shell South Louisiana asset acquisition

$
8.0

Approximately $73 million of our forecasted expansion capital was incurred as of June 30, 2005. Capital expenditures for maintenance projects are forecast to be approximately $19 million during 2005, of which approximately $8 million was incurred in the first six months.
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 )

Six Months Ended
June 30,

2005

2004

(in millions)

Cash provided by (used in):

Operating activities

$
(453.4
)
$
147.1

Investing activities

(97.4
)
(474.6
)
Financing activities

576.6

334.0

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
34

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,~~Similarly, 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~~$453.4 million in ~~2005.~~the 2005 period. Cash flow provided by operating activities was ~~$133.0~~$147.1 million in ~~2004.~~the 2004 period.
Cash flows from operating activities in 2005 reflects the purchase and storage of crude oil because of contango market conditions. During the first ~~quarter,~~half of 2005, 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~~$97.4 million and was predominantly related to additions to property and equipment comprised of (i) ~~$15.4~~$22.6 million paid for our Trenton pipeline expansion, (ii) ~~$10.2~~$12.1 million paid for our Cushing to Broome pipeline expansion, (iii) ~~$3.1~~$6.0 million paid for our Cushing Phase V expansion, and (iv) various other projects oftotaling approximately ~~$21.3~~$45.6 million. Additionally, approximately ~~$13.5~~$14.5 million was paid for various acquisitions. Net cash used in 2004 was

~~$155.9~~ $474.6 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), (ii) approximately $280 million paid for the Link acquisition, (iii) approximately $19 million paid for the CalVen acquisition and ~~(ii) $13.3~~(iv) $32.2 million paid for additions to property and ~~equipment, including approximately $3.4 million related to the Cushing Phase IV expansion.~~equipment.
Financing Activities.Cash provided by financing activities in the first half of 2005 was approximately ~~$342.6~~$576.6 million, primarily consisting of:
·       approximately $149.3 million of proceeds from the sale of senior notes,
•
·approximately $22.3 million of proceeds from a private placement of common units,

•
·net short and long-term ~~borrowings~~repayments under our revolving credit facility of approximately ~~$23.5~~$71.8 million,

•
·net borrowings under our short-term letter of credit and hedged inventory facility of approximately ~~$344.6~~$575.3 million for the purchase of crude oil inventory that was stored (see ~~"Operating Activities"~~“Operating Activities” above), and

•
~~$45.0~~
·       $92.7 million of distributions paid to common unitholders and the general partner.
Cash provided by financing activities in the first half of 2004 was approximately ~~$21.1~~$334.0 million, primarily consisting of:
•
·       approximately $101.2 million of proceeds from the issuance of Class C common units,
·net short and long-term borrowings under our revolving credit facility of approximately ~~$157.5~~$403.7 million used primarily to fund the purchase price of the Capline ~~acquisition,~~

•
and Link acquisitions,
·net repayments under our short-term letter of credit and hedged inventory facility of approximately ~~$100.5~~$96.1 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~~
·       $72.7 million of distributions paid to common unitholders and the general partner.
35

Contingencies

See Note 9 ~~"Commitments~~“Commitments and ~~Contingencies"~~Contingencies” in ~~"Notes~~“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,~~June 30, 2005.

2005
2006
2007
2008
2009
Thereafter

2005

2006

2007

2008

2009

Thereafter

(in millions)

(in millions)

Long-term debt and interest payments⁽¹⁾ Long-term debt and interest payments⁽¹⁾ $ 40.3 $ 53.8 $ 53.8 $ 53.8 $ 352.9 $ 799.7

$
28.8

$
57.5

$
57.5

$
57.5

$
232.3

$
997.0

Leases⁽²⁾ Leases⁽²⁾ 13.4 14.0 11.5 8.9 7.8 48.0

9.2

14.7

12.2

9.6

8.5

48.3

Capital expenditure obligations Capital expenditure obligations 23.4 — — — — —

15.0

—

—

—

—

—

Other long-term liabilities⁽³⁾ Other long-term liabilities⁽³⁾ 2.8 7.4 5.5 1.1 0.6 2.5

—

4.0

9.7

1.7

5.9

2.6

Subtotal

53.0

76.2

79.4

68.8

246.7

1,047.9

Crude oil and LPG purchases(3)(4)

2,174.4

166.6

102.6

102.6

102.5

17.0

Total

$
2,227.4

$242.8

$182.0

$171.4

$
349.2

$
1,064.9

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~~Approximately $6.5 million of non-current ~~liability~~liabilities related to SFAS 133 ~~which~~ are included in the crude oil and LPG ~~purchases.~~

purchases section of this table.
⁽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,~~June 30, 2005, we had outstanding letters of credit under our various facilities of approximately ~~$174.5~~$121.3 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"~~“anticipate,” “believe,” “estimate,” “expect,” “plan,” “intend” and ~~"forecast,"~~“forecast,” and similar expressions and statements regarding our business strategy, plans and objectives of our management for future operations. These statements
36

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;~~

•
suppliers and trade counterparties;
·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~~“Risk Factors Related to Our ~~Business"~~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.
37

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 Annual Report on 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,~~June 30, 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

Effect of 10%

(in millions)

Fair Value

Price Change

Crude oil:

(in millions)

Crude oil:

Futures contracts $ (30.6 ) $ (37.9 )

$
(60.2
)

$
(14.7
)

Swaps and options contracts $ (11.5 ) $ 3.8

$
(12.2
)

$
(7.8
)

LPG:
LPG:

Swaps and options contracts $ 0.8 $ (0.8 )

$
(0.9
)

$
0.7

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,~~June 30, 2005. ~~The 7.75%~~All of our outstanding 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 rate plus the applicable margin. The average interest rates presented below are based upon rates in effect at ~~March 31,~~June 30, 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 %

Expected Year of Maturity

2005

2006

2007

2008

2009

Thereafter

Total

(in millions)

Liabilities:

Short-term debt—variable rate

$
815.7

$
—

$
—

$
—

$
—

$
—

$815.7

Average interest rate

4.0
%

—

—

—

—

—

4.0
%
Long-term debt—variable rate

$
—

$
—

$
—

$
—

$
—

$
—

$
—

Average interest rate

—

—

—

—

—

—

—

Item 4. CONTROLS AND PROCEDURES
We maintain ~~"disclosure~~“disclosure controls and procedures,"” which we refer to as our ~~"DCP."~~“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
38

Chief Financial Officer, has evaluated the effectiveness of the design and operation of our DCP as of ~~March 31,~~June 30, 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"~~control”) that occurred during the ~~first~~second 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.
39

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"~~“short supply” controls of the Export Administration Regulations ~~("EAR"~~(“EAR”) and must be licensed by the Bureau of Industry and Security (the ~~"BIS"~~“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.
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,~~our personnel, 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~~us in the course of site remediation. Aggregate costs associated with the releases, including estimated remediation costs, are estimated to be approximately ~~$3.0~~$3.5 million to ~~$3.5~~$4.0 million. We continue to work with the appropriate state and federal environmental authorities ~~in responding~~with respect to ~~the releases~~site restoration and no enforcement proceedings have been instituted by any governmental authority at this time.

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.None.

Item 3. DEFAULTS UPON SENIOR SECURITIES
None
40

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
See Item 4. ~~"Submission~~“Submission of Matters to a Vote of Security ~~Holders"~~Holders” in our 2004 Annual Report on Form 10-K.

Item 5. OTHER INFORMATION
        ~~None~~Pending Reallocation of General Partner Interest
One of the owners of our general partner has provided notice that it intends to sell its 19% interest in the general partner. The remaining owners have elected to exercise their right of first refusal, such that the 19% interest will be allocated prorata to all remaining owners. As a result, subject to consummation of the transaction, the interest of Vulcan Energy Corporation will increase from 44% to approximately 54%. We anticipate that, at closing, Vulcan will enter into a voting agreement that will restrict its ability to unilaterally elect or remove our independent directors, and our CEO and COO will agree to waive certain change-of-control payment rights that would otherwise be triggered by the increase in Vulcan’s ownership interest.

Item 6. EXHIBITS
4.
1
Fifth Supplemental Indenture, dated as of May 27, 2005, to Indenture, dated as of September 25, 2002, among Plains All American Pipeline, L.P. and PAA Finance Corp. and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed May 31, 2005)
10.
1
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 (incorporated by reference to Exhibit 10.1 to Form 8-K filed April 21, 2005)
10.
2
Second Amendment to Restated Credit Agreement dated as of May 11, 2005, by and among Plains Marketing, L.P., Bank of America, N.A., as Administrative Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.1 to Form 8-K filed May 12, 2005)
10.
3
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. (incorporated by reference to Exhibit 10.2 to Form 10-Q for the period ended March 31, 2005)
10.
4
Registration Rights Agreement, dated May 27, 2005, among Plains All American Pipeline, L.P., PAA Finance Corp. Plains Marketing, L.P., Plains Pipeline, L.P., Plains Marketing GP Inc., Plains Marketing Canada LLC, PMC (Nova Scotia) Company, Plains Marketing Canada, L.P., Basin Holdings GP LLC, Basin Pipeline Holdings, L.P., Rancho Holdings GP LLC, Rancho Pipeline Holdings, L.P., J.P. Morgan Securities Inc. and Wachovia Capital Markets, LLC, Citigroup Global Markets Inc., UBS Securities LLC, Banc of America Securities LLC, Scotia Capital (USA) Inc., SunTrust Capital Markets, Inc,. Fortis Securities LLC, Daiwa Securities America Inc., SG Americas Securities, LLC and RBC Capital Markets Corporation (incorporated by reference to Exhibit 4.1 to Form 8-K filed May 31, 2005)
†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
†
~~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~~
Furnished herewith.
41

				Page
PART I. FINANCIAL INFORMATION
Item 1. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS:
Consolidated Balance Sheets:
	~~March 31,~~ June 30, 2005 and December 31, 2004		3
Consolidated Statements of Operations:
	For the three months and six months ended ~~March 31,~~June 30, 2005 and 2004		4
Consolidated Statements of Cash Flows:
	For the ~~three~~six months ended ~~March 31,~~June 30, 2005 and 2004		5
Consolidated Statement of ~~Partners' Capital:~~Partners’ Capital: For the six months ended June 30, 2005		6
	~~For the three months ended March 31, 2005~~		6
Consolidated Statements of Comprehensive Income:
	For the three months and six months ended ~~March 31,~~June 30, 2005 and 2004		7
Consolidated Statement of Changes in Accumulated Other Comprehensive Income: For the six months ended June 30, 2005		7
	~~For the three months ended March 31, 2005~~		7
Notes to the Consolidated Financial Statements			8
Item 2. ~~MANAGEMENT'S~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		18 20
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS		33 38
Item 4. CONTROLS AND PROCEDURES		34 38
PART II. OTHER INFORMATION
Item 1. Legal Proceedings		36 40
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		37 40
Item 3. Defaults Upon Senior Securities		37 40
Item 4. Submission of Matters to a Vote of Security Holders		37 41
Item 5. Other Information		37 41
Item 6. Exhibits		37 41
Signatures		38 42

												June 30, 2005					December 31, 2004
		March 31, 2005					December 31, 2004								Dollar/					Dollar/
		Barrels	$		$/barrel		Barrels	$		$/barrel		Barrels	Dollars		barrel		Barrels	Dollars		barrel
		(Barrels in thousands and dollars in millions)										(Barrels in thousands and dollars in millions)
Inventory⁽¹⁾	Inventory⁽¹⁾
Crude oil	Crude oil	14,131	$	679.6	$	48.09	8,716	$	396.2	$	45.46	14,959	$	737.2	$	49.28	8,716	$	396.2	$	45.46
LPG	LPG	845		29.4	$	34.79	2,857		100.1	$	35.04	3,132	108.5		$	34.64	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

Parts and supplies												N/A	2.5		N/A		N/A	1.9		N/A
Inventory subtotal												18,091	848.2				11,573	498.2
Inventory in third-party assets	Inventory in third-party assets
Crude oil	Crude oil	1,249		44.9	$	35.95	1,294		48.7	$	37.64	1,248	50.5		$	40.38	1,294	48.7		$	37.64
LPG	LPG	318		10.4	$	32.70	318		10.6	$	33.33	318	10.9		$	34.28	318	10.6		$	33.33

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

Inventory in third-party assets subtotal												1,566	61.4				1,612	59.3
Linefill	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

Crude oil linefill												5,924	165.1		$	27.87	6,015	168.4		$	28.00
LPG linefill												26	0.9		$	30.77	—	—		N/A
Linefill subtotal												5,950	166.0				6,015	168.4
Total	Total	22,493	$	932.7			19,200	$	725.9			25,607	$	1,075.6			19,200	$	725.9

		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

	June 30,			December 31,
	2005			2004
	(in millions)
Short-term debt:
Senior secured hedged inventory facility bearing interest at a rate of 4.0% and 3.0% at June 30, 2005 and December 31, 2004, respectively		$	655.7		$	80.4
Working capital borrowings, bearing interest at a rate of 4.2% and 3.7% at June 30, 2005 and December 31, 2004, respectively(1)		160.0			88.2
Other		5.1			6.9
Total short-term debt		820.8			175.5
Long-term debt:
Senior notes—
4.75% senior notes due August 2009, net of unamortized discount of $0.6 million and $0.7 million at June 30, 2005 and December 31, 2004, respectively		$	174.4		$	174.3
7.75% senior notes due October 2012, net of unamortized discount of $0.3 million and $0.3 million at June 30, 2005 and December 31, 2004, respectively		199.7			199.7
5.63% senior notes due December 2013, net of unamortized discount of $0.6 million and $0.6 million at June 30, 2005 and December 31, 2004, respectively		249.4			249.4
5.25% senior notes due June 2015, net of unamortized discount of $0.7 million at June 30, 2005		149.3			—
5.88% senior notes due August 2016, net of unamortized discount of $1.1 million and $1.1 million at June 30, 2005 and December 31, 2004, respectively		173.9			173.9
Senior notes, net of unamortized discount		946.7			797.3
Long-term debt under credit facilities and other—
Senior unsecured revolving credit facility, bearing interest at 3.5% at December 31, 2004(1)		—			143.6
Other		6.5			8.1
Long-term debt under credit facilities and other		6.5			151.7
Total long-term debt(1)(2)		953.2			949.0
Total debt		$	1,774.0		$	1,124.5

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

Total 2004 Acquisitions		$	549.5		Total 2004 Acquisitions			$	549.5

		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

	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		(568		)		—			(568		)
Changes in fair value of outstanding hedge positions		(88,082		)		—			(88,082		)
Currency translation adjustment		—				(8,219		)	(8,219		)
Total period activity		(88,650		)		(8,219		)	(96,869		)
Balance at June 30, 2005		$	(62,713	)		$	62,715		$	2

					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

Balance at December 31, 2004	$	0.6
Applied to accounts receivable balances	(0.7		)
Increase in reserve charged to expense	0.8
Balance at June 30, 2005	$	0.7

				Total of distribution paid to:
	Distribution						General partner:
	per Limited			Limited			Incentive
Distribution Payment Date	Partner Unit			Partners			Distribution			2% ownership
	(in millions, except per unit data)
August 12, 2005⁽¹⁾		$	0.6500		$	44.1		$	3.8		$	0.9
May 13, 2005		$	0.6375		$	43.3		$	3.5		$	0.9
February 14, 2005		$	0.6125		$	41.2		$	3.0		$	0.8

		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

Annualized		Phantom Units				DERs
Distribution Rate	Date	A(1)	B(2)		Total	A(1)		B(2)		Total
		(in thousands)
$2.60	May 2007	561		150	711		363		150	513
$2.70	May 2008	—		—	—		136		75	211
$2.80	May 2009	421		150	571		136		75	211
$2.90	May 2010	—		—	—		136		100	211
$3.00	May 2010	421		200	622		136		100	211
		1,403		500	1,903		907		500	1,407

Other current assets	$	21.6		$	25.5
Other long-term assets		9.6		0.9
Other current-liabilities		(65.8	)	(100.4		)
Other long-term liabilities and deferred credits		(12.2	)	(6.5		)

			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

	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

2005 acquisitions/expansions	$	4.0	114	$	—	—	$	6.0	82	$	—	—
2004 acquisitions/expansions	33.4		694	38.6		702	71.4		695	41.9		396
All other pipeline systems	48.2		929	45.4		893	97.9		919	89.0		889
Total tariff activities	$	85.6	1,737	$	84.0	1,595	$	175.3	1,696	$	130.9	1,285

		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

	For the three						For the six
	months ended June 30,						months ended June 30,
	2005			2004			2005			2004
	(average amount outstanding, in millions)
Fixed rate senior notes(1)		$	863		$	450		$	832		$	450
Borrowings under our revolving credit facilities⁽²⁾		163			493			187			321
Total		$	1,026		$	943		$	1,019		$	771

	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

		2005		2006		2007		2008		2009		Thereafter		2005		2006		2007		2008		2009		Thereafter
		(in millions)												(in millions)
Long-term debt and interest payments⁽¹⁾	Long-term debt and interest payments⁽¹⁾	$	40.3	$	53.8	$	53.8	$	53.8	$	352.9	$	799.7	$	28.8	$	57.5	$	57.5	$	57.5	$	232.3		$	997.0
Leases⁽²⁾	Leases⁽²⁾		13.4		14.0		11.5		8.9		7.8		48.0	9.2		14.7		12.2		9.6		8.5			48.3
Capital expenditure obligations	Capital expenditure obligations		23.4		—		—		—		—		—	15.0		—		—		—		—			—
Other long-term liabilities⁽³⁾	Other long-term liabilities⁽³⁾		2.8		7.4		5.5		1.1		0.6		2.5	—		4.0		9.7		1.7		5.9			2.6
Subtotal														53.0		76.2		79.4		68.8		246.7			1,047.9
Crude oil and LPG purchases(3)(4)														2,174.4		166.6		102.6		102.6		102.5			17.0
Total														$	2,227.4	$242.8		$182.0		$171.4		$	349.2		$	1,064.9

	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

	Fair Value			Effect of 10% Price Decrease							Effect of 10%
	(in millions)						Fair Value				Price Change
Crude oil:
							(in millions)
Crude oil:
Futures contracts	$	(30.6	)	$	(37.9	)		$	(60.2	)		$	(14.7	)
Swaps and options contracts	$	(11.5	)	$	3.8			$	(12.2	)		$	(7.8	)
LPG:
LPG:
Swaps and options contracts	$	0.8		$	(0.8	)		$	(0.9	)		$	0.7

	Expected Year of Maturity
	2005			2006			2007			2008			2009		Thereafter			Total
	(in millions)
Liabilities:
Short-term debt—variable rate	$	815.7			$	—		$	—		$	—	$	—		$	—	$815.7
Average interest rate	4.0		%		—			—			—		—			—		4.0		%
Long-term debt—variable rate	$	—			$	—		$	—		$	—	$	—		$	—	$	—
Average interest rate	—				—			—			—		—			—		—

4.	1	Fifth Supplemental Indenture, dated as of May 27, 2005, to Indenture, dated as of September 25, 2002, among Plains All American Pipeline, L.P. and PAA Finance Corp. and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed May 31, 2005)
10.	1	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 (incorporated by reference to Exhibit 10.1 to Form 8-K filed April 21, 2005)
10.	2	Second Amendment to Restated Credit Agreement dated as of May 11, 2005, by and among Plains Marketing, L.P., Bank of America, N.A., as Administrative Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.1 to Form 8-K filed May 12, 2005)
10.	3	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. (incorporated by reference to Exhibit 10.2 to Form 10-Q for the period ended March 31, 2005)
10.	4	Registration Rights Agreement, dated May 27, 2005, among Plains All American Pipeline, L.P., PAA Finance Corp. Plains Marketing, L.P., Plains Pipeline, L.P., Plains Marketing GP Inc., Plains Marketing Canada LLC, PMC (Nova Scotia) Company, Plains Marketing Canada, L.P., Basin Holdings GP LLC, Basin Pipeline Holdings, L.P., Rancho Holdings GP LLC, Rancho Pipeline Holdings, L.P., J.P. Morgan Securities Inc. and Wachovia Capital Markets, LLC, Citigroup Global Markets Inc., UBS Securities LLC, Banc of America Securities LLC, Scotia Capital (USA) Inc., SunTrust Capital Markets, Inc,. Fortis Securities LLC, Daiwa Securities America Inc., SG Americas Securities, LLC and RBC Capital Markets Corporation (incorporated by reference to Exhibit 4.1 to Form 8-K filed May 31, 2005)
†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

~~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~~

			PLAINS ALL AMERICAN PIPELINE, L.P.
	By:	~~By:~~	PLAINS AAP, L.P., its general partner
	By:	~~By:~~	PLAINS ALL AMERICAN GP LLC, its general partner
Date: ~~May 9,~~August 5, 2005	By:	~~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,~~August 5, 2005	By:	~~By:~~	/s/ PHIL KRAMER
		Phil Kramer, Executive Vice President and Chief Financial Officer of Plains All American GP LLC (Principal Financial Officer)