Plains All American Pipeline (PAA) 10-Q 2005 Q3 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 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

PLAINS ALL AMERICAN PIPELINE, L.P.

(Exact name of registrant as specified in its charter)

Delaware	76-0582150
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

333 Clay Street, Suite 1600
Houston, Texas 77002

(Address of principal executive offices)

(Zip Code)

(713) 646-4100

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o Yes o No

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

At November 2, 2005, there were outstanding 73,768,576 Common Units.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

TABLE OF CONTENTS

	Page
PART I. FINANCIAL INFORMATION
Item 1. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS:
Consolidated Balance Sheets: September 30, 2005 and December 31, 2004		3
Consolidated Statements of Operations: For the three months and nine months ended September 30, 2005 and 2004		4
Consolidated Statements of Cash Flows: For the nine months ended September 30, 2005 and 2004		6
Consolidated Statement of Partners’ Capital: For the nine months ended September 30, 2005		7
Consolidated Statements of Comprehensive Income: For the three months and nine months ended September 30, 2005 and 2004		8
Consolidated Statement of Changes in Accumulated Other Comprehensive Income: For the nine months ended September 30, 2005		8
Notes to the Consolidated Financial Statements		9
Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		24
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS		44
Item 4. CONTROLS AND PROCEDURES		44
PART II. OTHER INFORMATION
Item 1. Legal Proceedings		46
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		46
Item 3. Defaults Upon Senior Securities		47
Item 4. Submission of Matters to a Vote of Security Holders		47
Item 5. Other Information		47
Item 6. Exhibits		48
Signatures		49

2

PART I. FINANCIAL INFORMATION

Item 1. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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

	September 30,				December 31,
	2005				2004
	(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	8,174			$	12,988
Trade accounts receivable, net		1,115,563				521,785
Inventory		963,567				498,200
Other current assets		40,830				68,229
Total current assets		2,128,134				1,101,202
PROPERTY AND EQUIPMENT		2,072,862				1,911,509
Accumulated depreciation		(240,524		)		(183,887		)
		1,832,338				1,727,622
OTHER ASSETS
Pipeline linefill in owned assets		167,100				168,352
Inventory in third party assets		70,171				59,279
Other, net		200,937				103,956
Total assets		$	4,398,680			$	3,160,411
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES
Accounts payable		$	1,234,621			$	850,912
Due to related parties		887				32,897
Short-term debt		774,356				175,472
Other current liabilities		91,153				54,436
Total current liabilities		2,101,017				1,113,717
LONG-TERM LIABILITIES
Long-term debt under credit facilities and other		5,603				151,753
Senior notes, net of unamortized discount of $3,159 and $2,729, respectively		946,841				797,271
Other long-term liabilities and deferred credits		36,153				27,466
Total liabilities		3,089,614				2,090,207
COMMITMENTS AND CONTINGENCIES (NOTE 10)
PARTNERS’ CAPITAL
Common unitholders (73,093,576 and 62,740,218 units outstanding at September 30, 2005, and December 31, 2004, respectively)		1,272,947				919,826
Class B common unitholder (1,307,190 units outstanding at December 31, 2004)		—				18,775
Class C common unitholders (3,245,700 units outstanding at December 31, 2004)		—				100,423
General partner		36,119				31,180
Total partners’ capital		1,309,066				1,070,204
		$	4,398,680			$	3,160,411

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

3

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
	(unaudited)						(unaudited)
REVENUES
Crude oil and LPG sales (includes approximately $4,442,842 and $3,096,320 for the three month periods, respectively and $11,629,965 and $8,381,848 for the nine month periods, respectively related to buy/sell transactions)	$	8,387,103		$	5,663,504		$	21,724,396		$	14,218,956
Other gathering, marketing, terminalling and storage revenues	8,433			11,193			27,929			27,920
Pipeline margin activities revenues (includes approximately $52,206 and $29,892 for the three month periods, respectively and $125,763 and $111,240 for the nine month periods, respectively related to buy/sell transactions)	209,847			142,999			542,332			424,165
Pipeline tariff activities revenues	58,981			49,309			168,910			132,343
Total revenues	8,664,364			5,867,005			22,463,567			14,803,384
COSTS AND EXPENSES
Crude oil and LPG purchases and related costs (includes approximately $4,425,422 and $3,139,363 for the three month periods, respectively and $11,426,018 and $8,305,564 for the nine month periods, respectively related to buy/sell transactions)	8,258,187			5,576,523			21,396,992			13,992,768
Pipeline margin activities purchases (includes approximately $47,125 and $29,902 for the three month periods, respectively and $115,923 and $107,588 for the nine month periods, respectively related to buy/sell transactions)	206,470			138,530			525,515			407,658
Field operating costs (excluding LTIP charge)	67,488			61,203			197,810			158,053
LTIP charge—operations	851			—			2,170			567
General and administrative expenses (excluding LTIP charge)	20,645			19,484			60,059			54,565
LTIP charge—general and administrative	5,871			—			14,717			3,661
Depreciation and amortization	19,946			16,768			58,512			45,887
Total costs and expenses	8,579,458			5,812,508			22,255,775			14,663,159
Gain/(loss) on sales of assets	(21		)	559			424			643
OPERATING INCOME	84,885			55,056			208,216			140,868
OTHER INCOME/(EXPENSE)
Interest expense (net of $492 and $32 capitalized for the three month periods, respectively, and $1,458 and $207 capitalized for the nine month periods, respectively)	(15,618		)	(12,702		)	(44,429		)	(32,201		)
Interest and other income (expense), net	(269		)	(620		)	301			(250		)
Income before cumulative effect of change in accounting principle	68,998			41,734			164,088			108,417
Cumulative effect of change in accounting principle	—			—			—			(3,130		)
NET INCOME	$	68,998		$	41,734		$	164,088		$	105,287
NET INCOME—LIMITED PARTNERS	$	63,922		$	38,738		$	150,790		$	97,692
NET INCOME—GENERAL PARTNER	$	5,076		$	2,996		$	13,298		$	7,595

4

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

BASIC NET INCOME PER LIMITED PARTNER UNIT
Income before cumulative effect of change in accounting principle	$	0.81	$	0.59	$	2.11	$	1.63
Cumulative effect of change in accounting principle	—		—		—		(0.05		)
Net income	$	0.81	$	0.59	$	2.11	$	1.58
DILUTED NET INCOME PER LIMITED PARTNER UNIT
Income before cumulative effect of change in accounting principle	$	0.79	$	0.59	$	2.07	$	1.63
Cumulative effect of change in accounting principle	—		—		—		(0.05		)
Net income	$	0.79	$	0.59	$	2.07	$	1.58
BASIC WEIGHTED AVERAGE UNITS OUTSTANDING	67,971		65,776		67,795		61,929
DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING	69,373		65,776		68,939		61,929

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

5

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

	Nine Months Ended
	September 30,
	2005			2004
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	164,088		$	105,287
Adjustments to reconcile to cash flows from operating activities:
Depreciation and amortization	58,512			45,887
Cumulative effect of change in accounting principle	—			3,130
SFAS 133 mark-to-market adjustment	20,042			(1,431		)
LTIP charge	16,887			4,228
Noncash amortization of terminated interest rate swap	1,201			1,092
Noncash (gain)/loss on foreign currency revaluation	1,379			(3,423		)
Gain on sales of assets	(424		)	(643		)
Loss on refinancing of debt	—			658
Net cash paid for terminated interest rate swaps	(865		)	(1,465		)
Changes in assets and liabilities, net of acquisitions:
Trade accounts receivable and other	(584,046		)	(285,123		)
Inventory	(470,860		)	(127,391		)
Accounts payable and other current liabilities	339,728			365,784
Due to related parties	4,883			6,461
Net cash provided by (used in) operating activities	(449,475		)	113,051
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions	(17,646		)	(495,715		)
Additions to property and equipment	(122,128		)	(63,596		)
Investment in unconsolidated affiliate (see Note 3)	(112,500		)	—
Cash paid for linefill in assets owned	—			(10,242		)
Proceeds from sales of assets	3,793			2,234
Net cash used in investing activities	(248,481		)	(567,319		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net repayments on long-term revolving credit facility	(143,730		)	(29,977		)
Net borrowings on working capital revolving credit facility	62,235			34,700
Net borrowings/(repayments) on short-term letter of credit and hedged inventory facility	538,500			(42,234		)
Proceeds from the issuance of senior notes	149,277			346,427
Net proceeds from the issuance of common units	236,157			262,132
Distributions paid to unitholders and general partner	(141,473		)	(114,468		)
Other financing activities	(6,833		)	(3,172		)
Net cash provided by financing activities	694,133			453,408
Effect of translation adjustment on cash	(991		)	1,270
Net increase/(decrease) in cash and cash equivalents	(4,814		)	410
Cash and cash equivalents, beginning of period	12,988			4,137
Cash and cash equivalents, end of period	$	8,174		$	4,547
Cash paid for interest, net of amounts capitalized	$	53,203		$	23,366

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

6

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
Issuance of common units	5,754	231,272			—		—			—		—			4,885			5,754	236,157
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		)	—			—	—
Issuance of common units under LTIP	47	1,863			—		—			—		—			38			47	1,901
Distributions	—	(125,838		)	—		(801		)	—		(1,988		)	(12,846		)	—	(141,473		)
Net income	—	148,881			—		548			—		1,361			13,298			—	164,088
Other comprehensive loss	—	(20,682		)	—		(199		)	—		(494		)	(436		)	—	(21,811		)
Balance at September 30, 2005	73,094	$	1,272,947		—		$	—		—		$	—		$	36,119		73,094	$	1,309,066

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

7

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

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

(in thousands)

Consolidated Statements of Comprehensive Income

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005			2004
	(unaudited)
Net income	$	68,998	$	41,734	$	164,088		$	105,287
Other comprehensive income (loss)	75,058		16,518		(21,811		)	19,751
Comprehensive income	$	144,056	$	58,252	$	142,277		$	125,038

Consolidated 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		135,156				—		135,156
Changes in fair value of outstanding hedge positions		(173,044		)		—		(173,044		)
Currency translation adjustment		—				16,077		16,077
Total period activity		(37,888		)		16,077		(21,811		)
Balance at September 30, 2005		$	(11,951	)		$	87,011	$	75,060

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

8

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

Note 1—Organization and Accounting Policies

Plains All American Pipeline, L.P. (“PAA”) is a Delaware limited partnership formed in September of 1998. Our operations are conducted directly and indirectly through our operating subsidiaries, Plains Marketing, L.P., Plains Pipeline, L.P. and Plains Marketing Canada, L.P. We are engaged in interstate and intrastate crude oil transportation, and crude oil gathering, marketing, terminalling and storage, as well as the marketing and storage of liquefied petroleum gas and other natural gas related petroleum products. We refer to liquified petroleum gas and other natural gas-related petroleum products collectively as “LPG.” We own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key oil producing basins, transportation corridors and at major market hubs in the United States and Canada. In addition, through our 50% equity ownership in PAA/Vulcan Gas Storage LLC, we are engaged in the development and operation of natural gas storage facilities.

The accompanying consolidated financial statements and related notes present (i) our consolidated financial position as of September 30, 2005, and December 31, 2004, (ii) the results of our consolidated operations for the three months and nine months ended September 30, 2005 and 2004, (iii) our consolidated cash flows for the nine months ended September 30, 2005 and 2004, (iv) our consolidated changes in partners’ capital for the nine months ended September 30, 2005, (v) our consolidated comprehensive income for the three months and nine months ended September 30, 2005 and 2004, and (vi) our changes in consolidated accumulated other comprehensive income for the nine months ended September 30, 2005. The financial statements have been prepared in accordance with the instructions for interim reporting as prescribed by the Securities and Exchange Commission. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods have been reflected. All significant intercompany transactions have been eliminated. Certain reclassifications are made to prior periods to conform to current period presentation. The results of operations for the nine months ended September 30, 2005 should not be taken as indicative of the results to be expected for the full year. The consolidated interim financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our 2004 Annual Report on Form 10-K.

Note 2—Trade Accounts Receivable

The majority of our trade accounts receivable relates to our gathering and marketing activities, which can generally be described as high volume and low margin activities. As is customary in the industry, a portion of these receivables is reflected net of payables to the same counterparty based on contractual agreements. We routinely review our trade accounts receivable balances to identify past due amounts and analyze the reasons such amounts have not been collected. In many instances, such uncollected amounts involve billing delays and discrepancies or disputes as to the appropriate price, volume or quality of crude oil delivered, received or exchanged. We also attempt to monitor changes in the creditworthiness of our customers as a result of developments related to each customer, the industry as a whole and the general economy. Based on these analyses, as well as our historical experience and the facts and circumstances surrounding certain aged balances, we have established an allowance for doubtful trade accounts receivable. At September 30, 2005, substantially all of our net trade accounts receivable were less than 60 days past the scheduled invoice date. The following is a summary of the changes in our allowance for doubtful trade accounts receivable balance (in millions):

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

9

We consider this reserve adequate; however, there is no assurance that actual amounts will not vary significantly from estimated amounts. The discovery of previously unknown facts or adverse developments affecting one of our counterparties or the industry as a whole could adversely impact our results of operations.

Note 3—Related Party Matters

Reallocation of General Partner Interest

In August 2005, one of the owners of our general partner sold its 19% interest in the general partner. The remaining owners elected to exercise their right of first refusal, such that the 19% interest was allocated prorata to all remaining owners. As a result of the transaction, the interest of Vulcan Energy Corporation (“VEC”) increased from 44% to approximately 54%. At closing, VEC entered into a voting agreement that restricts its ability to unilaterally elect or remove our independent directors, and separately, our CEO and COO agreed to waive certain change-of-control payment rights that would otherwise have been triggered by the increase in VEC’s ownership interest. These ownership changes to our general partner had no impact on us.

Administrative Services Agreement

On October 14, 2005, Plains All American GP LLC (“PAA GP”) and VEC entered into an Administrative Services Agreement, effective as of September 1, 2005 (the “Services Agreement”). Pursuant to the Services Agreement, PAA GP will provide administrative services to VEC for consideration of approximately $650,000 per year, plus certain expenses. The Services Agreement will be effective for a period of three years, at which time it will automatically renew for successive one-year periods unless either party provides written notice of its intention to terminate the Services Agreement. Pursuant to the agreement, VEC has appointed certain employees of PAA GP as officers of VEC for administrative efficiency. Under the Services Agreement, VEC acknowledges that conflicts may arise between itself and PAA GP. If PAA GP believes that a specific service is in conflict with the best interest of PAA GP or its affiliates then PAA GP is entitled to suspend the provision of that service and such a suspension will not constitute a breach of the Services Agreement. Vulcan Gas Storage LLC (discussed below) operates separately from VEC, and we do not provide any services to Vulcan Gas Storage LLC under the Services Agreement.

Investment in Unconsolidated Affiliate

In the third quarter of 2005, PAA/Vulcan Gas Storage, LLC (“PAA/Vulcan”), a limited liability company, was formed. PAA/Vulcan is owned 50% by us and 50% by Vulcan Gas Storage LLC, a subsidiary of Vulcan Capital, the investment arm of Paul G. Allen. The Board of Directors of PAA/Vulcan is comprised of an equal number of our representatives and representatives of Vulcan Gas Storage and is responsible for providing strategic direction and policy-making. We are responsible for the day-to-day operations. PAA/Vulcan is not a variable interest entity, and we do not have the ability to control the entity; therefore, we account for the investment under the equity method in accordance with Accounting Principles Board Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.” This investment is reflected in other long-term assets in our consolidated balance sheet.

In September 2005, PAA/Vulcan acquired Energy Center Investments LLC (“ECI”), an indirect subsidiary of Sempra Energy, for approximately $250 million. ECI develops and operates underground natural gas storage facilities. We and Vulcan Gas Storage LLC each made an initial cash investment of approximately $112.5 million, and a subsidiary of PAA/Vulcan entered into a $90 million credit facility contemporaneously with closing.

10

In conjunction with formation of PAA/Vulcan and the acquisition of ECI, PAA and Paul G. Allen provided performance and financial guarantees to the seller with respect to PAA/Vulcan’s performance under the purchase agreement, as well as in support of continuing guarantees of the seller with respect to ECI’s obligations under certain gas storage and other contracts. PAA and Paul G. Allen would be required to perform under these guarantees only if ECI was unable to perform. In addition, we provided a guarantee under one contract with an indefinite life for which neither Vulcan Capital nor Paul G. Allen provided a guarantee. In exchange for the disproportionate guarantee, PAA will receive preference distributions totaling $1.0 million over ten years from PAA/Vulcan (distributions that would otherwise have been paid to Vulcan Gas Storage LLC). We believe that the fair value of the obligation to stand ready to perform is minimal. In addition, we believe the probability that we would be required to perform under the guaranty is extremely remote; however, there is no dollar limitation on potential future payments that fall under this obligation.

PAA/Vulcan will reimburse us for the allocated costs of PAA’s non-officer staff associated with the management and day-to-day operations of PAA/Vulcan and all out-of-pocket costs. In addition, in the first fiscal year that EBITDA (as defined in the PAA/Vulcan LLC agreement) of PAA/Vulcan exceeds $75.0 million, we will receive a distribution from PAA/Vulcan equal to $6.0 million per year for each year since formation of the joint venture, subject to a maximum of 5 years or $30 million. Thereafter, we will receive annually a distribution equal to the greater of $2 million per year or two percent of the EBITDA of PAA/Vulcan.

Equity Offering

During September 2005, a privately negotiated, registered sale of 679,000 common units to Kayne Anderson Capital Advisors, L.P. (“KACALP”) was completed. KAFU Holdings, L.P. (“KAFU”), which owns a portion of our general partner and has a representative on our board of directors, is managed by KACALP. See Note 7 “Partners’ Capital and Distributions.”

Note 4—Inventory and Linefill

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

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

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At September 30, 2005 and December 31, 2004, inventory and linefill consisted of:

	September 30, 2005					December 31, 2004
				Dollar/					Dollar/
	Barrels	Dollars		barrel		Barrels	Dollars		barrel
	(Barrels in thousands and dollars in millions)
Inventory(1)
Crude oil	13,283	$	784.8	$	59.08	8,716	$	396.2	$	45.46
LPG	4,639	176.2		$	37.98	2,857	100.1		$	35.04
Parts and supplies	N/A	2.6		N/A		N/A	1.9		N/A
Inventory subtotal	17,922	963.6				11,573	498.2
Inventory in third-party assets
Crude oil	1,248	58.5		$	46.88	1,294	48.7		$	37.64
LPG	318	11.7		$	36.79	318	10.6		$	33.33
Inventory in third-party assets subtotal	1,566	70.2				1,612	59.3
Linefill
Crude oil linefill	5,931	166.3		$	28.04	6,015	168.4		$	28.00
LPG linefill	26	0.8		$	30.77	—	—		N/A
Linefill subtotal	5,957	167.1				6,015	168.4
Total	25,445	$	1,200.9			19,200	$	725.9

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

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Note 5—Debt

Debt consists of the following:

	September 30,			December 31,
	2005			2004
	(in millions)
Short-term debt:
Senior secured hedged inventory facility bearing interest at a rate of 4.5% and 3.0% at September 30, 2005 and December 31, 2004, respectively		$	618.9		$	80.4
Working capital borrowings, bearing interest at a rate of 4.7% and 3.7% at September 30, 2005 and December 31, 2004, respectively(1)		150.5			88.2
Other		5.0			6.9
Total short-term debt		774.4			175.5
Long-term debt:
4.75% senior notes due August 2009, net of unamortized discount of $0.6 million and $0.7 million at September 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 September 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 September 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 September 30, 2005.		149.3			—
5.88% senior notes due August 2016, net of unamortized discount of $1.0 million and $1.1 million at September 30, 2005 and December 31, 2004, respectively		174.0			173.9
Senior notes, net of unamortized discount		946.8			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		5.6			8.1
Long-term debt under credit facilities and other		5.6			151.7
Total long-term debt(1)(2)		952.4			949.0
Total debt		$	1,726.8		$	1,124.5

(1)At September 30, 2005 and December 31, 2004, we have classified $150.5 million and $88.2 million, respectively, of borrowings under our senior unsecured revolving credit facility as short-term. These borrowings are designated as working capital borrowings, must be repaid within one year, and are primarily for hedged LPG and crude oil inventory and New York Mercantile Exchange (“NYMEX”) margin deposits.

(2)At September 30, 2005, the aggregate fair value of our fixed rate senior notes is estimated to be approximately $1.0 billion.

During May 2005, we completed the issuance of $150 million of 5.25% Senior Notes due 2015. The notes were issued at 99.518% of face value. The notes were co-issued by us and a wholly 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 existing 100% owned subsidiaries, except for minor subsidiaries. We used the proceeds to repay amounts outstanding under our credit facilities and for general partnership purposes.

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In November 2005, we amended our senior unsecured credit facility to increase the aggregate capacity to $1 billion and the sub-facility for Canadian borrowings to $400 million. The amended facility can be expanded to $1.5 billion, subject to additional lender commitments, and has a final maturity of November 2010. 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 November 2005, we extended the maturity of the senior secured hedged inventory facility by one year.

Note 6—Earnings Per 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. Subject to applicability of Emerging Issues Task Force Issue No. 03-06 (“EITF 03-06’’), “Participating Securities and the Two-Class Method under FASB Statement No. 128,’’ as discussed below, 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.

EITF 03-06 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 is allocated to the incentive distribution rights held by our general partner, as if distributed, 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.

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The following sets forth the computation of basic and diluted earnings per 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 September 30, 2005 and 2004.

	Three months ended September 30,						Nine months ended September 30,
	2005			2004			2005			2004
	(in thousands, except per unit data)
Net income	$	68,998		$	41,734		$	164,088		$	105,287
Less:
General partner’s incentive distribution paid	(3,771		)	(2,205		)	(10,221		)	(5,601		)
Subtotal	65,227			39,529			153,867			99,686
General partner 2% ownership	(1,305		)	(791		)	(3,077		)	(1,994		)
Net income available to limited partners	63,922			38,738			150,790			97,692
Pro forma additional general partner’s incentive distribution	(9,118		)	—			(8,036		)	—
Net Income available to limited partners under EITF 03-06 (numerator for basic and diluted earnings per limited partner unit)	$	54,804		$	38,738		$	142,754		$	97,692
Denominator:
Denominator for basic earnings per limited partner unit-weighted average number of limited partner units	67,971			65,776			67,795			61,929
Effect of dilutive securities:
Weighted average LTIP units (see Note 8)	1,402			—			1,144			—
Denominator for diluted earnings per limited partner unit-weighted average number of limited partner units	69,373			65,776			68,939			61,929
Basic net income per limited partner unit	$	0.81		$	0.59		$	2.11		$	1.58
Diluted net income per limited partner unit	$	0.79		$	0.59		$	2.07		$	1.58

Note 7—Partners’ Capital and Distributions

Equity Offering

During September 2005, we completed a public offering of 4,500,000 common units for $42.20 per unit ($40.512 per unit, net of underwriting discounts and commissions). Concurrently with the closing of the public offering, we completed the sale of 679,000 common units to investment funds affiliated with Kayne Anderson Capital Advisors, L.P. in a privately negotiated, registered transaction for a purchase price of $40.512 per unit (the public offering price less underwriting discounts and commissions). See Note 3 “Related Party Matters.” The combined offering resulted in gross proceeds of approximately $217.4 million from the sale of units and additional proceeds of approximately $4.4 million from our general partner’s proportionate capital contribution. Total costs associated with the offering, including underwriter fees and other expenses, were approximately $8.0 million. Net proceeds totaled $213.8 million. During October 2005, the underwriters of the above mentioned public offering exercised their over-allotment option on 675,000 common units for $42.20 per unit. This resulted in gross proceeds of approximately $28.5 million from the sale of units and approximately $0.6 million from our general partner’s proportionate capital contribution. Total costs associated with the offering, including underwriter fees and other expenses, were approximately $1.1 million. Net proceeds totaled $28.0 million. The combined net proceeds from the offerings of $241.8 million were used to repay indebtedness under our senior unsecured revolving credit facility and for general partnership purposes.

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Private Placement of Common Units

On February 25, 2005, we issued 575,000 common units in a private placement 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. The net proceeds were used to repay indebtedness under our revolving credit facilities at closing, and to fund a portion of our 2005 expansion capital program as those expenditures were 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						Total
Distribution Payment Date	Partner Unit			Partners			Distribution			2% ownership			distribution
	(in millions, except per unit data)
November 14, 2005(1)		$	0.6750		$	49.8		$	4.7		$	1.0		$	55.5
August 12, 2005		$	0.6500		$	44.1		$	3.8		$	0.9		$	48.8
May 13, 2005		$	0.6375		$	43.3		$	3.5		$	0.9		$	47.7
February 14, 2005		$	0.6125		$	41.2		$	3.0		$	0.8		$	45.0

(1)The distribution we declared on October 25, 2005, is payable on November 14, 2005, to unitholders of record on November 4, 2005.

Note 8—Long-Term Incentive Plans

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

Approximately 97,000 of the phantom units outstanding under the 1998 LTIP vested in 2005. We paid cash in lieu of delivery of common units for approximately 25,000 of the phantom units and issued approximately 47,000 new common units (after netting for taxes) in connection with the vesting. As of September 30, 2005, there are approximately 50,000 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 performance criteria will be met.

Four of our non-employee directors each have received an LTIP award of 5,000 units. These awards vest annually in 25% increments (1,250 units each). The awards have an automatic re-grant feature such that as they vest, an equivalent 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 in lieu, an equivalent cash payment is made. In June 2005, 5,000 non-employee director units vested.

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

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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 September 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	558		150	708		363		150	513
$2.70	May 2008	—		—	—		136		75	211
$2.80	May 2009	419		150	569		136		75	211
$2.90	May 2010	—		—	—		136		100	236
$3.00	May 2010	419		200	619		136		100	236
		1,396		500	1,896		907		500	1,407

(1)Awards that vest in May 2011 at the latest. 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 thus 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. Until the performance criteria are met, these awards are not considered common stock equivalents 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 or considered probable of acceleration, the related compensation expense will also be accelerated. For those phantom units and DERs that vest only 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 $2.80 annualized distribution rate and therefore have accelerated the recognition of compensation expense related to the portion of the awards that vest up to that rate. We recognized total compensation expense of approximately $6.7 million in the third quarter of 2005 for a total of $16.9 million in the first nine months of 2005 related to the awards granted under our 1998 LTIP and our 2005 LTIP.

Note 9—Derivative Instruments and Hedging Activities

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

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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, 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”) 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 nine months of 2005, our earnings include a net gain of approximately $14.4 million resulting from all derivative activities, including the change in fair value of open derivatives and settled derivatives taken to earnings during the period. This gain includes:

a)a net mark-to-market loss on open positions of $20.0 million (a $26.3 million loss in the first half of the year and a $6.3 million gain in the third quarter), which is comprised of:

·the net change in fair value during the period of open derivatives used to hedge price exposure that do not qualify for hedge accounting (a loss of approximately $19.2 million) and

·the net change in fair value during the period 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 $0.8 million).

b)a net gain of $34.4 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 nine months 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 September 30, 2005:

Other current assets	$	23.5
Other long-term assets	5.0
Other current liabilities	(44.1		)
Other long-term liabilities and deferred credits	(8.2		)

The net liability as of September 30, 2005, relates mostly to unrealized losses on effective cash flow hedges that are deferred to OCI and Canadian futures contracts. The unrealized losses on Canadian futures are primarily related to derivative contracts used to hedge physical inventories or fixed-price physical contract exposures. These futures contracts do not qualify for hedge accounting due to the lack of consistent correlation between the hedged item and the derivative and are thus included in mark-to-market earnings.

At September 30, 2005, there is a total unrealized net loss of approximately $11.9 million deferred to OCI. This includes $6.2 million, which predominantly relates to unrealized losses on derivatives used to hedge physical inventory in storage that receive hedge accounting, and $5.8 million relating to terminated

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interest rate swaps, which are being amortized to interest expense over the original terms of the terminated instruments. The inventory hedges are mostly short derivative positions that will result in losses when prices rise. These hedge losses are offset by an increase in the physical inventory value and will be reclassed into earnings from OCI in the same period that the underlying physical inventory is sold. The total amount of deferred net losses recorded in OCI are expected to be reclassified to future earnings, contemporaneously with the related physical purchase or delivery of the underlying commodity or payments of interest.

Of the total net loss deferred in OCI at September 30, 2005, a net loss of $8.0 million will be reclassified into earnings in the next twelve months and the remaining net loss at various intervals (ending in 2016 for amounts related to our terminated interest rate swaps and 2007 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 nine months ended September 30, 2005, no amounts were reclassified to earnings from OCI in connection with forecasted transactions that were no longer considered probable of occurring.

Note 10—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” controls of the Export Administration Regulations (“EAR”) and must be licensed by the Bureau of Industry and Security (the “BIS”) of the U.S. Commerce Department. In 2002, we determined that we may have violated the terms of our licenses with respect to the quantity of crude oil exported and the end-users in Canada. Export of crude oil except as authorized by license is a violation of the EAR. In October 2002, we submitted to the BIS an initial notification of voluntary disclosure. The BIS subsequently informed us that we could continue to export while previous exports were under review. We applied for and received several new licenses allowing for export volumes and end users that more accurately reflect our anticipated business and customer needs. We also conducted reviews of new and existing contracts and implemented new procedures and practices in order to better 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.

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 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 us in the course of site remediation. Aggregate costs associated with the releases, including estimated remediation costs, are estimated to be approximately

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$4.0 million to $4.5 million. We continue to work with the appropriate state and federal environmental authorities with respect to 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.

Environmental

We may experience future releases of crude oil into the environment from our pipeline and storage operations. We also may 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 typically improve on (decrease) the rate of releases from such assets as we implement our standards and procedures, remove selected assets from service and spend capital to upgrade the assets. In the immediate post-acquisition period, however, the inclusion of additional miles of pipe in our operation may result in an increase in the absolute number of releases company-wide compared to prior periods. We have, in fact, experienced such an increase in connection with our purchase of assets from Link Energy LLC in April 2004, which added approximately 7,000 miles of pipeline to our operations. As a result, we have also received an increased number of requests for information from governmental agencies with respect to such releases of crude oil (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 September 30, 2005, our reserve for environmental liabilities totaled approximately $22.6 million. At September 30, 2005, we have recorded receivables totaling approximately $11.9 million ($6.4 million related to estimated future remediation costs) for amounts recoverable under insurance and from third parties under indemnification agreements. 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.

Hurricanes Katrina and Rita

During the third quarter of 2005 we experienced damage to various facilities and equipment resulting from hurricanes in the Gulf of Mexico. We have completed preliminary assessments of damages and repair efforts are underway. We believe that the majority of the repair costs will be recovered through our insurance policies. As of September 30, 2005, we have accrued approximately $5.8 million of receivables from our insurance carrier representing our estimate of costs recoverable from insurance.

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 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. Additionally, we choose to self-insure certain types of risks, including risks associated

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with gradual seepage and pollution and property damage for pipe in the ground, which we believe are cost prohibitive to 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.

Note 11—Operating Segments

Our operations consist of two operating segments: (i) pipeline transportation operations (“Pipeline”) and (ii) gathering, marketing, terminalling and storage operations (“GMT&S”). Through our pipeline segment, we engage in interstate and intrastate crude oil pipeline transportation and certain related margin activities. Through our GMT&S segment, we engage in purchases and resales of crude oil and LPG at various points along the distribution chain and we operate certain terminalling and storage assets. We believe that the combination of our terminalling and storage activities and gathering and marketing activities provides a counter-cyclical balance that has a stabilizing effect on our results of operations and cash flow. In a contango market (oil prices for future deliveries are higher than for current deliveries), we use our tankage to improve our gathering margins by storing crude oil we have purchased at lower prices in the current month for delivery at higher prices in future months. In a backwardated market (oil prices for future deliveries are lower than for current deliveries), we use and lease less storage capacity, but increased marketing margins (premiums for prompt delivery 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 maintenance capital. Repair and maintenance expenditures associated with existing assets that do not extend the useful life or expand the

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operating capacity are charged to expense as incurred. The following table reflects certain financial data for each segment for the periods indicated:

	Pipeline			GMT&S		Total
	(in millions)
Three Months Ended September 30, 2005(1)
Revenues:
External Customers (includes buy/sell revenues of $52.2 for Pipeline and $4,442.8 for GMT&S respectively)(2)		$	268.8	$	8,395.6	$	8,664.4
Intersegment(3)		34.5		0.2		34.7
Total revenues of reportable segments		$	303.3	$	8,395.8	$	8,699.1
Segment profit(2)(4)(5)		$	45.7	$	59.2	$	104.9
SFAS 133 impact(2)		$	—	$	6.3	$	6.3
Maintenance capital		$	2.9	$	1.3	$	4.2
Three Months Ended September 30, 2004
Revenues:
External Customers (includes buy/sell revenues of $29.9 for Pipeline and $3,096.3 for GMT&S respectively)(2)		$	192.3	$	5,674.7	$	5,867.0
Intersegment(3)		35.1		0.3		35.4
Total revenues of reportable segments		$	227.4	$	5,675.0	$	5,902.4
Segment profit(2)(4)(5)		$	44.0	$	27.3	$	71.3
SFAS 133 impact(2)		$	—	$	0.9	$	0.9
Maintenance capital		$	2.0	$	1.0	$	3.0

	Pipeline			GMT&S			Total
	(in millions)
Nine Months Ended September 30, 2005(1)
Revenues:
External Customers (includes buy/sell revenues of $125.8 for Pipeline and $11,630.0 for GMT&S respectively)(2)		$	711.3	$	21,752.3		$	22,463.6
Intersegment(3)		99.8		0.7			100.5
Total revenues of reportable segments		$	811.1	$	21,753.0		$	22,564.1
Segment profit(2)(4)(5)		$	137.1	$	129.2		$	266.3
SFAS 133 impact(2)		$	—	$	(20.0	)	$	(20.0	)
Maintenance capital		$	8.2	$	4.0		$	12.2
Nine Months Ended September 30, 2004
Revenues:
External Customers (includes buy/sell revenues of $111.2 for Pipeline and $8,381.8 for GMT&S respectively)(2)		$	556.5	$	14,246.9		$	14,803.4
Intersegment(3)		83.0		0.7			83.7
Total revenues of reportable segments		$	639.5	$	14,247.6		$	14,887.1
Segment profit(2)(4)(5)		$	117.2	$	68.9		$	186.1
SFAS 133 impact(2)		$	—	$	1.4		$	1.4
Maintenance capital		$	4.1	$	2.0		$	6.1

(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 impact to such periods was not material.

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

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(3)Intersegment sales are conducted at arms length.

(4)GMT&S segment profit includes interest expense of $7.2 million and $0.8 million for the quarters ended September 30, 2005 and 2004, respectively, and $16.4 million and $1.2 million for the nine month periods ended September 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 nine months
	ended September 30,								ended September 30,
	2005				2004				2005				2004
	(in millions)
Segment profit		$	104.9			$	71.3			$	266.3			$	186.1
Depreciation and amortization		(20.0		)		(16.8		)		(58.5		)		(45.9		)
Gain on sales of assets		—				0.6				0.4				0.6
Interest expense		(15.6		)		(12.7		)		(44.4		)		(32.2		)
Interest income and other, net		(0.3		)		(0.7		)		0.3				(0.2		)
Income before cumulative effect of change in accounting principle		$	69.0			$	41.7			$	164.1			$	108.4

Note 12—Recent Accounting Pronouncements

In June 2005, the Emerging Issues Task Force issued Issue No. 04-05 (“EITF 04-05”), “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights.” EITF 04-05 provides guidance in determining whether a general partner controls a limited partnership by determining the limited partners’ substantive ability to dissolve (liquidate) the limited partnership as well as assessing the substantive participating rights of the limited partners within the limited partnership. EITF 04-05 states that if the limited partners do not have substantive ability to dissolve (liquidate) or have substantive participating rights then the general partner is presumed to control that partnership and would be required to consolidate the limited partnership. This EITF is effective in fiscal periods beginning after December 15, 2005. Although this EITF does not directly impact us, it could potentially impact our general partner. We are currently reviewing the potential impact of EITF 04-05 on our general partner.

In September 2005, the Emerging Issues Task Force issued Issue No. 04-13 (“EITF 04-13”), “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” The EITF concluded that inventory purchases and sales transactions with the same counterparty should be combined for accounting purposes if they were entered into in contemplation of each other. The EITF provided indicators to be considered for purposes of determining whether such transactions are entered into in contemplation of each other. Guidance was also provided on the circumstances under which nonmonetary exchanges of inventory within the same line of business should be recognized at fair value. EITF 04-13 will be effective in reporting periods beginning after March 15, 2006. The adoption of EITF 04-13 will cause inventory purchases and sales under buy/sell transactions, which were recorded gross as purchases and sales, to be treated as inventory exchanges in our consolidated statement of operations. We have parenthetically disclosed buy/sell transactions in our Consolidated Statements of Operations. EITF 04-13 will reduce gross revenues and purchases, but is not expected to have a material impact on our financial position, net income, or liquidity.

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

Introduction

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

·Executive Summary

·Acquisition Activities

·Results of Operations

·Outlook

·Liquidity and Capital Resources

·Commitments

·  Recent Accounting Pronouncements

·Forward-Looking Statements and Associated Risks

Executive Summary

Company Overview

We are engaged in interstate and intrastate crude oil transportation and crude oil gathering, marketing, terminalling and storage, as well as the marketing and storage of liquefied petroleum gas and other natural gas related petroleum products. We refer to liquified petroleum gas and other natural gas related petroleum products collectively as “LPG.” We have an extensive network of pipeline transportation, terminalling, storage and gathering assets in key oil producing basins, transportation corridors and at major market hubs in the United States and Canada. In addition, through our 50% equity ownership in PAA/Vulcan Gas Storage LLC, we are engaged in the development and operation of natural gas storage facilities. We were formed in September of 1998, and our operations are conducted directly and indirectly through our operating subsidiaries, Plains Marketing, L.P., Plains Pipeline, L.P. and Plains Marketing Canada, L.P.

We are one of the largest midstream crude oil companies in North America. As of September 30, 2005, we owned approximately 15,000 miles of active crude oil pipelines, approximately 37 million barrels of active terminalling and storage capacity and approximately 500 transport trucks. Currently, we handle an average of approximately 3.0 million barrels per day of physical crude oil through our extensive network of assets located in major oil producing regions of the United States and Canada.

Our operations consist of two operating segments: (i) pipeline transportation operations (“Pipeline”) and (ii) gathering, marketing, terminalling and storage operations (“GMT&S”). Through our pipeline segment, we engage in interstate and intrastate crude oil pipeline transportation and certain related margin activities. Through our GMT&S segment, we engage in purchases and resales of crude oil and LPG at various points along the distribution chain and we operate certain terminalling and storage assets.

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2005 Operating Results Overview

During the third quarter of 2005, we reported net income of $69.0 million and earnings per diluted limited partner unit of $0.79, compared to $41.7 million and $0.59, respectively during the third quarter of 2004.

Key items in the third quarter of 2005 included:

·Favorable market conditions characterized by relatively strong contango market conditions and reasonably high volatility of crude oil.

·The impact of Hurricanes Katrina and Rita. Our preliminary estimates indicate that the negative effect of these hurricanes is approximately $5 million (including $2.8 million of operating costs, net of estimated insurance reimbursements). This includes disruptions to our operations and uninsured damage to some of our terminals and other facilities. On an overall basis, the hurricanes did not have a material impact on our revenue-generating capacity.

·The inclusion in the third quarter of 2005 of an aggregate charge of approximately $6.7 million related to both our 1998 Long-Term Incentive Plan (“1998 LTIP”) and our 2005 Long-Term Incentive Plan (“2005 LTIP”).

·A gain of approximately $6.3 million in the third quarter of 2005 resulting from the mark-to-market of open derivative instruments pursuant to Statement of Financial Accounting Standard No. 133, as amended (“SFAS 133”).

·A loss on foreign currency revaluation of approximately $1.6 million related to the impact of changes in the Canadian dollar to U.S. dollar exchange rate on U.S. dollar denominated assets and liabilities of our Canadian subsidiary.

During the first nine months of 2005, we reported net income of $164.1 million and earnings per diluted limited partner unit of $2.07, compared to $105.3 million and $1.58, respectively during the first nine months of 2004. The first nine months of 2005 were also characterized by relatively strong contango market conditions. Other items impacting the first nine months results were (i) the contributions from assets acquired during 2004, (ii) an aggregate charge of $16.9 million related to our 1998 and 2005 LTIP, (iii) a loss of approximately $20.0 million resulting from the mark-to-market of open derivative positions pursuant to SFAS 133, and (iv) a loss on foreign currency revaluation of approximately $1.4 million related to the impact of changes in the Canadian dollar to U.S. dollar exchange rate on U.S. dollar denominated assets and liabilities of our Canadian subsidiary.

Earnings per limited partner unit (both basic and diluted) for the 2005 periods were reduced by the application of Emerging Issues Task Force Issue No. 03-06 “Participating Securities and the Two-Class Method under FASB Statement No. 128.” See Note 6 “Earnings Per Limited Partner Unit” in “Notes to the Consolidated Financial Statements.”

Acquisition Activities

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

During the first nine months of 2005, we completed four small transactions for aggregate consideration of approximately $27.0 million. The transactions included several crude oil pipeline systems along the Gulf Coast as well as in Canada. We also acquired an LPG pipeline and terminal in Oklahoma. Additionally, in September 2005, PAA/Vulcan Gas Storage, LLC (“PAA/Vulcan”) acquired Energy Center Investments LLC (“ECI”), an indirect subsidiary of Sempra Energy, for approximately $250

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million. ECI develops and operates underground natural gas storage facilities. PAA/Vulcan is owned 50% by us and 50% by a subsidiary of Vulcan Capital. We account for the investment in PAA/Vulcan under the equity method in accordance with Accounting Principles Board Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.” These acquisitions did not materially impact our results of operations, either individually or in the aggregate.

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

Acquisition	Effective Date	Acquisition Price		Operating Segment
		(in millions)
Capline and Capwood Pipeline Systems (“Capline acquisition”)	03/01/04		$ 158.5	Pipeline
Link Energy LLC (“Link acquisition”)	04/01/04		332.3	Pipeline/GMT&S
Cal Ven Pipeline System	05/01/04		19.0	Pipeline
Schaefferstown Propane Storage Facility	08/25/04		32.0	GMT&S
Other	various		7.7	GMT&S
Total 2004 Acquisitions			$ 549.5

Results of Operations

Analysis of Operating Segments

Our operations consist of two operating segments: (i) Pipeline and (ii) GMT&S. Through our pipeline segment, we engage in interstate and intrastate crude oil pipeline transportation and certain related margin activities. Through our GMT&S segment, we engage in purchases and resales of crude oil and LPG at various points along the distribution chain, and we operate certain terminalling and storage assets. We believe that the combination of our terminalling and storage activities and gathering and marketing activities provides a counter-cyclical balance that has a stabilizing effect on our results of operations and cash flow. In a contango market (oil prices for future deliveries are higher than for current deliveries), we use our tankage to improve our margins by storing crude oil we have purchased at lower prices in the current month for delivery at higher prices in future months. In a backwardated market (oil prices for future deliveries are lower than for current deliveries), we use less storage capacity, but increased marketing margins (premiums for prompt delivery 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 (“G&A”) expenses. Each of the items above excludes depreciation and amortization. As a master limited partnership, we make quarterly distributions of our “available cash” (as defined in our partnership agreement) to our unitholders. Therefore, we look at each period’s earnings before non-cash depreciation and amortization as an important measure of segment performance. The exclusion of depreciation and amortization expense could be viewed as limiting the usefulness of segment profit as a performance measure because it does not account in current periods for the implied reduction in value of our capital assets, such as crude oil pipelines and facilities, caused by aging and wear and tear. Management compensates for this limitation by recognizing that depreciation and amortization are largely offset by repair and maintenance costs, which 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

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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 maintenance 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. See Note 11 “Operating Segments” in the “Notes to the Consolidated Financial Statements” for a reconciliation of segment profit to consolidated income before cumulative effect of change in accounting principle. The following table reflects our results of operations and maintenance capital for each segment.

	Pipeline		GMT&S
	(in millions)
Three Months Ended September 30, 2005(1)(2)
Revenues	$ 303.3		$ 8,395.8
Purchases and related costs(3)	(206.7	)	(8,292.7	)
Field operating costs (excluding LTIP charge)	(37.0	)	(30.4	)
LTIP charge—operations	(0.3	)	(0.6	)
Segment G&A expenses (excluding LTIP charge)(4)	(10.2	)	(10.5	)
LTIP charge—general and administrative(4)	(3.4	)	(2.4	)
Segment profit	$   45.7		$      59.2
SFAS 133 impact(5)	$      —		$        6.3
Maintenance capital	$     2.9		$        1.3
Three Months Ended September 30, 2004(2)
Revenues	$ 227.4		$ 5,675.0
Purchases and related costs(3)	(138.8	)	(5,611.6	)
Field operating costs	(33.6	)	(27.6	)
Segment G&A expenses(4)	(11.0	)	(8.5	)
Segment profit	$   44.0		$      27.3
SFAS 133 impact(5)	$      —		$        0.9
Maintenance capital	$     2.0		$        1.0

Table continued on following page

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	Pipeline		GMT&S
	(in millions)
Nine Months Ended September 30, 2005(1)(2)
Revenues	$ 811.1		$ 21,753.0
Purchases and related costs(3)	(526.2	)	(21,496.8	)
Field operating costs (excluding LTIP charge)	(108.8	)	(89.1	)
LTIP charge—operations	(0.7	)	(1.4	)
Segment G&A expenses (excluding LTIP charge)(4)	(29.6	)	(30.5	)
LTIP charge—general and administrative(4)	(8.7	)	(6.0	)
Segment profit	$ 137.1		$      129.2
SFAS 133 impact(5)	$      —		$       (20.0	)
Maintenance capital	$     8.2		$           4.0
Nine Months Ended September 30, 2004(2)
Revenues	$ 639.5		$ 14,247.6
Purchases and related costs(3)	(408.4	)	(14,075.8	)
Field operating costs (excluding LTIP charge)	(84.8	)	(73.3	)
LTIP charge—operations	(0.1	)	(0.4	)
Segment G&A expenses (excluding LTIP charge)(4)	(27.3	)	(27.2	)
LTIP charge—general and administrative(4)	(1.7	)	(2.0	)
Segment profit	$ 117.2		$        68.9
SFAS 133 impact(5)	$      —		$           1.4
Maintenance capital	$     4.1		$           2.0

(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 impact to such periods was not material.

(2)Revenues and purchases include intersegment amounts.

(3)GMT&S purchases include interest of $7.2 million and $0.8 million for the quarters ended September 30, 2005 and 2004, respectively, and $16.4 million and $1.2 million for the nine month periods ended September 30, 2005 and 2004, respectively, on contango inventory purchases.

(4)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 judgement by management and will continue to be based on the business activities that exist during each period.

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

Pipeline Operations

As of September 30, 2005, we owned approximately 15,000 miles (of which approximately 13,000 miles are included in our pipeline segment) of active gathering and mainline crude oil pipelines located throughout the United States and Canada. Our activities from pipeline operations generally consist of transporting volumes of crude oil for a fee and third party leases of pipeline capacity (collectively referred to as “tariff activities”), as well as barrel exchanges and buy/sell arrangements (collectively referred to as “pipeline margin activities”). In connection with certain of our merchant activities conducted under our gathering and marketing business, we are also shippers on certain of our own pipelines. These transactions are conducted at published tariff rates and eliminated in consolidation. Tariffs and other fees on our pipeline systems vary by receipt point and delivery point. The segment profit generated by our tariff and other fee-related activities depends on the volumes transported on the pipeline and the level of the tariff and other fees charged as well as the fixed and variable field costs of operating the pipeline. Segment profit from our pipeline capacity leases, barrel exchanges and buy/sell arrangements generally reflect a negotiated amount.

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

	Three months ended September 30,				Nine months ended September 30,
	2005		2004		2005		2004
	(in millions)
Operating Results(1)
Revenues
Tariff activities	$   93.5		$   84.4		$ 268.8		$ 215.3
Pipeline margin activities(2)	209.8		143.0		542.3		424.2
Total pipeline operations revenues	303.3		227.4		811.1		639.5
Costs and Expenses
Pipeline margin activities purchases(3)	(206.7	)	(138.8	)	(526.2	)	(408.4	)
Field operating costs (excluding LTIP charge)	(37.0	)	(33.6	)	(108.8	)	(84.8	)
LTIP charge—operations	(0.3	)	—		(0.7	)	(0.1	)
Segment G&A expenses (excluding LTIP charge)(4)	(10.2	)	(11.0	)	(29.6	)	(27.3	)
LTIP charge—general and administrative(4)	(3.4	)	—		(8.7	)	(1.7	)
Segment profit	$   45.7		$   44.0		$ 137.1		$ 117.2
Maintenance capital	$     2.9		$     2.0		$     8.2		$     4.1
Average Daily Volumes (thousands of barrels per day)(5)
Tariff activities
All American	51		52		51		55
Basin	290		279		283		275
Capline	129		122		144		115
West Texas/New Mexico Area Systems(6)	428		391		422		325
Canada	250		273		255		257
Other	601		418		559		343
Total tariff activities	1,749		1,535		1,714		1,370
Pipeline margin activities	65		72		69		72
Total	1,814		1,607		1,783		1,442

(1)Revenues and purchases include intersegment amounts.

(2)The three month periods include revenues associated with buy/sell arrangements of $52.2 million and $29.9 million for the quarters ended September 30, 2005 and 2004, respectively. Volumes associated with these arrangements were approximately 12,500 barrels per day and 10,200 barrels per day for the quarters ended September 30, 2005 and 2004, respectively. The nine month periods include revenues associated with buy/sell arrangements of $125.8 million and $111.2 million for the nine month periods ended September 30, 2005 and 2004, respectively. Volumes associated with these arrangements were approximately 11,800 barrels per day and 13,000 barrels per day for the nine month periods ended September 30, 2005 and 2004, respectively.

(3)The three month periods include purchases associated with buy/sell arrangements of $47.1 million and $29.9 million for the quarters ended September 30, 2005 and 2004, respectively. Volumes associated with these arrangements were approximately 11,100 barrels per day and 10,100 barrels per day for the quarters ended September 30, 2005 and 2004, respectively. The nine month periods include purchases associated with buy/sell arrangements of $115.9 million and $107.6 million for the nine month periods ended September 30, 2005 and 2004, respectively. Volumes associated with these arrangements were approximately 11,400 barrels per day and 13,000 barrels per day for the nine month periods ended September 30, 2005 and 2004, respectively.

(4)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.

(5)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.

(6)The aggregate of eleven systems in the West Texas/New Mexico area.

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Total revenues for our pipeline segment increased for both the three and nine months periods ended September 30, 2005, as compared to the same periods ended September 30, 2004. The revenue increase in the third quarter of 2005 primarily relates to our margin activities. The revenue increase in the first nine months of 2005 relates both to our tariff activities (see discussion below) and to our margin activities. The increase in revenues from our margin activities in both periods is related to higher average prices for crude oil sold and transported on our San Joaquin Valley (“SJV”) gathering system partially offset by a small decrease in buy/sell volumes for the nine month period. Because the barrels that we buy and sell are generally indexed to the same pricing indices, revenues and purchases will increase and decrease with changes in market prices without significant changes to our margins related to those purchases and sales.

Segment profit, our primary measure of segment performance, was driven by the following:

·Increased volumes and related tariff revenues—The increase in volumes and related tariff revenues during the first nine months of 2005 primarily relates to the Link acquisition and other acquisitions completed during 2004. This increase primarily resulted from the inclusion of the related assets for the entire 2005 period versus only a portion of the 2004 period. Tariff revenues for the third quarter of 2005 increased as compared to the same period in 2004 as volumes increased approximately 14% over 2004. See further discussion below.

·Increased revenues from our loss allowance oil—As is common in the industry, our crude oil tariffs incorporate a “loss allowance factor” intended to offset losses due to evaporation, measurement and other losses in transit. The loss allowance factor averages approximately 0.2%, by volume. We value the variance of allowance volumes to actual losses at the average market value at the time the variance occurred and the result is recorded as either an increase or decrease to tariff revenues. Gains or losses on sales of allowance oil barrels are also included in tariff revenues. Increased volumes and higher crude oil prices during the third quarter and first nine months of 2005 as compared to the third quarter and first nine months of 2004 have resulted in increased revenues related to loss allowance oil, somewhat offset by losses due to the settlement of grade imbalances. The NYMEX averages were $63.26 and $55.51 for the third quarter and first nine months of 2005, respectively as compared to $43.79 and $39.09 for the third quarter and first nine months of 2004, respectively.

·Increased field operating costs—Our continued growth, primarily from the Link acquisition and other acquisitions completed during 2004, is the principal cause of the $24.6 million increase in field operating costs to $109.5 million (including the LTIP charge) for the first nine months of 2005. The increased costs primarily relate to (i) payroll and benefits, (ii) emergency response and environmental remediation of pipeline releases, (iii) maintenance and (iv) utilities. In the third quarter of 2005, field operating costs increased slightly as compared to the third quarter of 2004. The increase primarily relates to increased payroll and benefits costs.

·Increased segment G&A expenses—The increase in segment G&A expenses in the first nine months of 2005 primarily relates to the Link acquisition. Additionally, expense related to our LTIP increased $7.0 million in the 2005 period as compared to the 2004 period. The increase in segment G&A expenses in the third quarter of 2005 as compared to the third quarter of 2004 primarily relates to the LTIP charge recognized in the 2005 period.

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As discussed above, the increase in our pipeline segment profit for the first nine months of 2005 largely relates to our acquisition activities. We completed a number of acquisitions during the last ten months of 2004 that have impacted the results of operations herein. The following table summarizes the impact of recent acquisitions and expansions on volumes and revenues related to our tariff activities (volumes in thousands of barrels per day and revenues in millions):

	Three months ended								Nine months ended
	September 30, 2005				September 30, 2004				September 30, 2005				September 30, 2004
	Revenues		Volumes		Revenues		Volumes		Revenues		Volumes		Revenues		Volumes
Tariff activities revenues(1)(2)(3)
2005 acquisitions/expansions		$ 3.9		110		$  —		—		$  9.9		91		$    —		—
2004 acquisitions/expansions		35.6		660		36.2		619		107.0		683		77.7		471
All other pipeline systems		54.0		979		48.2		916		151.9		940		137.6		899
Total tariff activities		$ 93.5		1,749		$ 84.4		1,535		$ 268.8		1,714		$ 215.3		1,370

(1)Revenues include intersegment amounts.

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

(3)To the extent there has been an expansion to one of our existing pipeline systems, any incremental revenues and volumes are included in the category for the period that pipeline was acquired. For new pipeline systems that we construct, incremental revenues and volumes are included in the period the system became operational.

Average daily volumes from our tariff activities increased approximately 14% in the third quarter of 2005 as compared to the third quarter of 2004, while revenues increased approximately 11% to approximately $93.5 million. The increase primarily relates to the following:

·Pipeline systems acquired or brought into service during 2005 contributed approximately 110,000 barrels per day and $3.9 million of revenues during the third quarter of 2005 (approximately 79,000 barrels per day and $2.2 million of revenues are attributable to our recently constructed Cushing to Broome pipeline system),

·Volumes from pipeline systems acquired in 2004 increased in the third quarter of 2005 as compared to the third quarter of 2004, while revenues were relatively flat, reflecting the following:

—An increase of 16,000 barrels per day and a decrease of $2.3 million in revenues from the pipelines acquired in the Link acquisition in 2005 as compared to 2004, as the volume increase was more than offset by tariff rates that were voluntarily lowered to encourage third-party shippers. Third quarter pipeline segment profit was reduced by approximately $3.0 million because of these market rate adjustments. As a result of these lower tariffs on barrels shipped by us in connection with our gathering and marketing activities, segment profit from GMT&S was increased by a comparable amount, and

—An increase of 27,000 barrels per day (however, 13,000 barrels per day of this increase were low revenue pump over volumes on a small pipeline system) and $1.3 million of revenues in 2005 compared to 2004 from the pipelines acquired in the Capline acquisition. The majority of the increased revenue in the 2005 period was related to the loss allowance factor included in our tariff and was caused by higher average crude oil prices during 2005.

·Volumes and revenues from all other pipeline systems (those acquired prior to 2004) increased in the third quarter of 2005 compared to the same period in 2004. The increases relate to several items, including:

—Increased tariff rates on certain of our systems, partially related to the quality of crude oil shipped,

—New connections to refineries,

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—The appreciation of Canadian currency (the Canadian to U.S. dollar exchange rate appreciated to an average of 1.20 to 1 for the third quarter of 2005 compared to an average of 1.31 to 1 in the third quarter of 2004), and

—A shift of certain minor pipeline systems from our GMT&S segment.

In the first nine months of 2005, average daily volumes from our tariff activities increased by approximately 25% to approximately 1.7 million barrels per day, and revenues from our tariff activities also increased by approximately 25% to approximately $268.8 million. The increase is attributable to:

·Pipeline systems acquired or brought into service during 2005 which contributed approximately 91,000 barrels per day and $9.9 million of revenues during the first nine months of 2005.

·Volumes and revenues from pipeline systems acquired in 2004 increased in the first nine months of 2005 as compared to the first nine months of 2004, reflecting the following:

—An increase in 2005 as compared to 2004 of 150,000 barrels per day and $19.6 million of revenues from the pipelines acquired in the Link acquisition, reflecting the inclusion of these systems for the entire 2005 period as compared to only a portion of the 2004 period. Partially offsetting this increase were tariff rates that were voluntarily lowered to encourage third-party shippers. Pipeline segment profit was reduced by approximately $8.0 million because of these market rate adjustments. As a result of these lower tariffs on barrels shipped by us in connection with our gathering and marketing activities, segment profit from GMT&S was increased by a comparable amount,

—An increase of 56,000 barrels per day and $7.6 million of revenues in 2005 as compared to 2004 from the pipelines acquired in the Capline acquisition, reflecting the inclusion of these systems for the entire 2005 period as compared to only a portion of the 2004 period,

—An increase of 7,000 barrels per day and $2.1 million of revenues in the first nine months of 2005 as compared to the first nine months of 2004 from other businesses acquired in the last nine months of 2004.

·Revenues from all other pipeline systems (those acquired prior to 2004) also increased in the first nine months of 2005, along with a slight increase in volumes. The increase in revenues is related to several items including:

—Increased tariff rates on certain of our systems, partially related to the quality of crude oil shipped,

—The appreciation of Canadian currency (the Canadian to U.S. dollar exchange rate appreciated to an average of 1.22 to 1 for the first nine months of 2005 compared to an average of 1.33 to 1 in the first nine months of 2004), and

—Volume increases on certain of our systems, partially related to a shift of certain minor pipeline systems from our GMT&S segment.

Gathering, Marketing, Terminalling and Storage Operations

As of September 30, 2005, we owned approximately 37 million barrels of active above-ground crude oil terminalling and storage facilities, including a crude oil terminalling and storage facility at Cushing, Oklahoma. Cushing, which we refer to as the Cushing Interchange, is one of the largest crude oil market hubs in the United States and the designated delivery point for New York Mercantile Exchange, or NYMEX, crude oil futures contracts. Terminals are facilities where crude oil is transferred to or from storage or a transportation system, such as a pipeline, to another transportation system, such as trucks or another pipeline. The operation of these facilities is called “terminalling.” Approximately 14 million

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barrels of our 37 million barrels of tankage is used primarily in our GMT&S segment and the balance is used in our Pipeline segment.

On a stand-alone basis, segment profit from terminalling and storage activities is dependent on the throughput of volumes, the volume of crude oil stored and the level of fees generated from our terminalling and storage services. Our terminalling and storage activities are integrated with our gathering and marketing activities and thus the level of tankage that we allocate for our arbitrage activities (and therefore not available for lease to third parties) varies throughout crude oil price cycles. This integration enables us to use our storage tanks in an effort to counter-cyclically balance and hedge our gathering and marketing activities. In a contango market (when oil prices for future deliveries are higher than for current deliveries), we use our tankage to improve our gathering margins by storing crude oil we have purchased at lower prices in the current month for delivery at higher prices in future months. In a backwardated market (when oil prices for future deliveries are lower than for current deliveries), we use less storage capacity, but increased marketing margins (premiums for prompt delivery 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 believe that this combination of our terminalling and storage activities, gathering and marketing activities and our hedging activities provides a counter-cyclical balance that has a stabilizing effect on our results of operations and cash flows. We also believe that this balance enables us to protect against downside risk while at the same time providing us with upside opportunities in volatile market conditions.

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. As an example of the lack of correlation between changes in revenues and changes in segment profit, our revenues increased approximately 48% and 53% in the third quarter and first nine months of 2005, respectively, compared to the third quarter and first nine months of 2004, respectively. During the same time periods, our segment profit increased almost 117% and 88%, respectively. These increases are discussed further below. We do not anticipate that future changes in revenues will be a primary driver of segment profit. Generally, we expect our segment profit to increase or decrease directionally with increases or decreases in lease gathered volumes and LPG sales volumes. However, certain market conditions create opportunities that may significantly impact segment profit. 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.

The increase in revenues for both the third quarter and first nine months of 2005 as compared to the same periods in 2004 was primarily because of higher crude oil prices during the 2005 periods. The average NYMEX price for crude oil was $63.26 per barrel and $55.51 per barrel for the quarter and nine months ended September 30, 2005, respectively, as compared to $43.79 per barrel and $39.09 per barrel for the same periods in 2004, respectively.

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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 segment for the comparative periods indicated:

	Three months ended September 30,						Nine months ended September 30,
	2005			2004			2005			2004
	(in millions, except per barrel data)
Operating Results(1)
Revenues(2)(3)	$	8,395.8		$	5,675.0		$	21,753.0		$	14,247.6
Purchases and related costs(4)(5)	(8,292.7		)	(5,611.6		)	(21,496.8		)	(14,075.8		)
Field operating costs (excluding LTIP charge)	(30.4		)	(27.6		)	(89.1		)	(73.3		)
LTIP charge—operations	(0.6		)	—			(1.4		)	(0.4		)
Segment G&A expenses (excluding LTIP charge)(6)	(10.5		)	(8.5		)	(30.5		)	(27.2		)
LTIP charge—general and administrative(6)	(2.4		)	—			(6.0		)	(2.0		)
Segment profit(3)	$	59.2		$	27.3		$	129.2		$	68.9
SFAS 133 mark-to-market adjustment(3)	$	6.3		$	0.9		$	(20.0	)	$	1.4
Maintenance capital	$	1.3		$	1.0		$	4.0		$	2.0
Segment profit per barrel(7)	$	1.01		$	0.46		$	0.71		$	0.41
Average Daily Volumes (thousands of barrels per day)(8)
Crude oil lease gathering	598			625			616			576
LPG sales	41			38			50			39

(1)Revenues and purchases and related costs include intersegment amounts.

(2)Includes revenues associated with buy/sell arrangements of $4,442.8 million and $3,096.3 million for the quarters ended September 30, 2005 and 2004, respectively. Volumes associated with these arrangements were approximately 810,000 barrels per day and 832,800 barrels per day for the quarters ended September 30, 2005 and 2004, respectively. Revenues associated with buy/sell arrangements were $11,630.0 million and $8,381.8 million for the nine months ended September 30, 2005 and 2004, respectively. Volumes associated with these arrangements were approximately 826,000 barrels per day and 704,000 barrels per day for the six months ended September 30, 2005 and 2004, respectively. The previously referenced amounts include certain estimates based on management’s judgment; such estimates are not expected to have a material impact on the balances.

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

(4)Includes purchases associated with buy/sell arrangements of $4,425.4 million and $3,139.4 million for the quarters ended September 30, 2005 and 2004, respectively. Volumes associated with these arrangements were approximately 831,000 barrels per day and 848,000 barrels per day for the quarters ended September 30, 2005 and 2004, respectively. Purchases associated with buy/sell arrangements of $11,426.0 million and $8,305.6 million for the nine month periods ended September 30, 2005 and 2004, respectively. Volumes associated with these arrangements were approximately 823,000 barrels per day and 699,000 barrels per day for the nine month periods ended September 30, 2005 and 2004, respectively. The previously referenced amounts include certain estimates based on management’s judgment; such estimates are not expected to have a material impact on the balances.

(5)Purchases and related costs include interest expense of $7.2 million and $0.8 million for the quarters ended September 30, 2005 and 2004, respectively, and $16.4 million and $1.2 million for the nine month periods ended September 30, 2005 and 2004, respectively, on contango inventory purchases.

(6)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.

(7)Calculated based on crude oil lease gathered volumes and LPG sales volumes.

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

Segment profit for the third quarter and first nine months of 2005 significantly exceeded the comparable 2004 periods. The increase in the 2005 periods is partially driven by increased volumes and synergies realized from businesses acquired in the last eighteen months coupled with very favorable market conditions.

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The primary factors affecting current period results were:

·Favorable market conditions—These favorable market conditions include a shift in the market structure from a backwardated market with a price differential of as much as $1.14 per barrel in late 2004 to a prolonged and pronounced contango market with a price differential of as much as $1.91 during the first nine months of 2005. The contango market structure had price differentials that averaged approximately $0.48, $1.22 and $0.69 over the first three 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 nine months 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 periods, 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 $70.85 during the first nine months 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—The crude oil volumes gathered from producers, using our assets or third-party assets, have increased by approximately 7% during the first nine months of 2005 as compared to the first nine months of 2004. The increase primarily relates to the Link acquisition. Crude oil lease gathered volumes decreased slightly in the third 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 average amount of tankage used in our GMT&S operations to approximately 13.5 million barrels during 2005 as compared to an average of 12.4 million barrels during the first nine months of 2004.

·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 $3.0 million and $8.0 million, respectively, for the three and nine months ended September 30, 2005. 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 driver of the increase in field operating costs for the first nine months of 2005 as compared to the same period in 2004. The increased costs pimarily relate to (i) payroll and benefits, (ii) fuel, (iii) maintenance and (iv) property taxes. In addition, the third quarter of 2005 includes approximately $2.2 million of costs, net of estimated insurance reimbursements, related to Hurricanes Katrina and Rita.

The 2005 periods also include a mark-to-market adjustment gain of $6.3 million pursuant to SFAS 133 that was recognized in the third quarter compared to a net gain of $0.9 million in the third quarter of 2004. In addition, we recognized a net loss of $20.0 million in the first nine months of 2005 pursuant to SFAS 133 compared to a net gain of $1.4 million in the first nine months of 2004. The primary components of the $20.0 million adjustment in 2005 were:

·A decrease in the mark-to-market of approximately $11.4 million resulting from the change in fair value for option and futures contracts that serve to reduce our lease gathering and tankage business

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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 current period relates to the settlement of mark-to-market gains from the previous period. Total settlements related to these strategies during the first nine months of 2005 were $17.6 million.

·A decrease in the mark-to-market of approximately $9.8 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. 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 change in fair value during the current period relates to the settlement of mark-to-market losses from the previous period. Total settlements related to these strategies during the first nine months of 2005 were $1.5 million.

·An increase in the mark-to-market of $1.2 million primarily related to the change in fair value of certain derivative instruments used to minimize the risk of unfavorable changes in exchange rates. A portion of the increase in fair value during the current period relates to the settlement of mark-to-market losses from the previous period. Total settlements related to these derivatives during the first nine months of 2005 were $1.0 million.

Segment profit per barrel (calculated based on our lease gathered crude oil and LPG volumes) was $1.01 per barrel for the quarter ended September 30, 2005, compared to $0.46 for the quarter ended September 30, 2004. Segment profit per barrel was $0.71 for the first nine months of 2005, compared to $0.41 per barrel for the first nine months 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 increased approximately $12.6 million to $58.5 million in the first nine months of 2005. The increase relates primarily to (i) capital projects completed either in 2005 or in late 2004, and (ii) assets from our 2004 acquisitions being included for the entire period in 2005 versus only a part of the period in 2004. The increase of $3.2 million to $19.9 million in the third quarter of 2005 primarily relates to the capital projects completed this year or in late 2004, as previously mentioned. Amortization of debt issue costs was $0.8 million and $2.1 million in the third quarter and first nine months of 2005, respectively, and was relatively flat compared to the corresponding periods in 2004.

Interest Expense

Interest expense is primarily impacted by:

·our average debt balances;

·the level and maturity of fixed rate debt and interest rates associated therewith; and

·market interest rates and our interest rate hedging activities on floating rate debt.

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The following table summarizes selected components of our average debt balances:

	For the three months ended September 30,						For the nine months ended September 30,
	2005			2004			2005			2004
	(average amount outstanding, in millions)
Fixed rate senior notes(1)		$	950		$	640		$	872		$	514
Borrowings under our revolving credit facilities(2)		192			259			132			205
Total		$	1,142		$	899		$	1,004		$	719

(1)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 periods was primarily related to the portion of our acquisitions that were not 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 5.5% and 6.0% for the third quarter and first nine months of the 2005, respectively, compared to 5.3% and 5.7% for the third quarter and first nine months of 2004, respectively.

The net impact of the items discussed above was an increase in interest expense in the third quarter of 2005 of approximately $2.9 million to a total of $15.6 million. In the first nine months of 2005, interest expense increased $12.2 million to $44.4 million. The increase in interest expense in both the third quarter and first nine months of 2005 is primarily related to the increase in our average debt balance. Also contributing to the increase was the increase in our weighted average interest rate.

Interest costs attributable to borrowings for inventory stored in a contango market are included in purchases and related costs in our GMT&S segment profit as we consider interest on these borrowings a direct cost to storing the inventory. These borrowings are primarily under our senior secured hedged inventory facility. These costs were approximately $7.2 million and $16.4 million for the third quarter and first nine months of 2005, respectively. In 2004, these costs were approximately $0.8 million and $1.2 million for the third quarter and first nine months, respectively.

Outlook

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

Our results for the first nine months of 2005 have been favorably impacted by several factors as discussed above in “Results of Operations”. Our operating and financial results for the fourth quarter of 2005 and the year 2006 will be subject to a number of factors, many of which are beyond our control. Depending on the severity of their impact, if any, these factors could adversely impact the favorable trend we have experienced. These potential factors include:

·  Overall crude oil market structure and market conditions that are less favorable than we have experienced in recent quarters and more in line with historical market conditions.

·  The continuing impact of hurricanes Katrina and Rita, which have resulted in increased natural gas prices and related fuel and power costs. In addition, we expect the hurricane related damage to certain production platforms in the Gulf of Mexico and offshore and onshore transportation infrastructure may curtail crude oil production relative to historical levels, which may in turn decrease our lease gathered barrels and impact the volumes transported on the Capline system. We

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also anticipate that the cost of oilfield services may increase as a result of increased demand for services and repairs following the hurricanes.

·  A decrease in crude oil prices would negatively impact our tariff revenue as our crude oil tariffs incorporate a loss allowance factor that is based on the average market value of crude oil during the period.

Although we believe our business strategy is designed to manage these trends, factors and potential developments, there can be no assurance that we will not be negatively affected.

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 to which such resources effectively can be applied. We are presently engaged in discussions and negotiations with various parties regarding the 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.

Liquidity and Capital Resources

Liquidity

Cash generated from operations and our credit facilities are our primary sources of liquidity. At September 30, 2005, we had working capital of approximately $27.1 million, approximately $664.8 million of availability under our committed revolving credit facilities and approximately $181.1 million of availability under our uncommitted hedged inventory facility (see “Capital Resources” below). Usage of the credit facilities is subject to compliance with covenants. We believe we are currently in compliance with all covenants.

Capital Resources

During September 2005, we completed a public offering of 4,500,000 common units for $42.20 per unit ($40.512 per unit net of underwriting discounts and commissions). Concurrently with the closing of the public offering, we completed the sale of 679,000 common units to investment funds affiliated with Kayne Anderson Capital Advisors, L.P. in a privately negotiated, registered transaction for a purchase price of $40.512 per unit (the public offering price less underwriting discounts and commissions). See Note 3 “Related Party Matters” in “Notes to the Consolidated Financial Statements.” The combined offering resulted in gross proceeds of approximately $217.4 million from the sale of units and additional proceeds of approximately $4.4 million from our general partner’s proportionate capital contribution. Total costs associated with the offering, including underwriter fees and other expenses, were approximately $8.0 million. Net proceeds totaled $213.8 million. During October 2005, the underwriters of the above mentioned public offering exercised their over-allotment option on 675,000 common units for $42.20 per unit. This resulted in gross proceeds of approximately $28.5 million from the sale of units and approximately $0.6 million from our general partner’s proportionate capital contribution. Total costs associated with the offering, including underwriter fees and other expenses, were approximately $1.1 million. Net proceeds totaled $28.0 million. The combined net proceeds from the offerings of $241.8 million were used to repay indebtedness under our senior unsecured revolving credit facility and for general partnership purposes.

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During May 2005, we completed the sale of $150 million of 5.25% Senior Notes due 2015. The notes were sold at 99.518% of face value. We used the net proceeds of approximately $148 million, after deducting initial purchaser discounts and offering costs, to repay amounts outstanding under our credit facilities and for general partnership purposes.

In November 2005, we amended our senior unsecured credit facility to increase the aggregate capacity to $1 billion and the sub-facility for Canadian borrowings to $400 million. The amended facility can be expanded to $1.5 billion, subject to additional lender commitments, and has a final maturity of November 2010. 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 November 2005, we extended the maturity of the senior secured hedged inventory facility by one year.

In February 2005, we issued 575,000 common units in a private placement 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. The net proceeds were used to repay indebtedness under our revolving credit facilities at closing, and to fund a portion of our 2005 expansion capital program as these expenditures were incurred.

We have filed with the Securities and Exchange Commission a universal shelf registration statement that, subject to effectiveness at the time of use, allows us to issue from time to time up to an aggregate of $2 billion of debt or equity securities. At September 30, 2005, we have approximately $1.8 billion remaining under this registration statement.

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 $170 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 $18 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		$	18.0
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		$	6.0
Capital projects associated with the Shell South Louisiana asset acquisition		$	8.0

Approximately $107 million of our forecasted expansion capital was incurred as of September 30, 2005. Capital expenditures for maintenance projects are forecast to be approximately $17 million during 2005, of which approximately $12 million was incurred in the first nine months.

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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

	Nine Months Ended September 30,
	2005			2004
	(in millions)
Cash provided by (used in):
Operating activities	$	(449.5	)	$	113.1
Investing activities	(248.5		)	(567.3		)
Financing activities	694.1			453.4

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 in which 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 in which we pay for and store the crude oil and the subsequent period in which we receive proceeds from the sale of the crude oil. When we store the crude oil, we borrow under 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 during the period in which we collect the cash from the sale of the stored crude oil. Similarly, the level of LPG inventory stored at period end affects our cash flow from operating activities. Cash flow used in operating activities was $449.5 million in the 2005 period. Cash flow provided by operating activities was $113.1 million in the 2004 period.

Cash flows from operating activities in 2005 reflect the purchase and storage of crude oil because of contango market conditions. During the first nine months 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. Because of shift in the market structure out of contango and into backwardation, we anticipate selling a significant portion of our stored inventory in the month of November 2005. We expect to receive the proceeds from those sales in December 2005, thus generating significant operating cash inflows that will offset the operating cash outflows earlier in the year, when the crude oil was purchased. We plan to use the receipts to reduce our borrowings under our credit facilities.

Investing Activities.Net cash used in 2005 was $248.5 million and was predominantly related to additions to property and equipment and our investment in PAA/Vulcan. Additions to property and equipment were comprised of (i) $24.7 million paid for our Trenton pipeline expansion, (ii) $12.3 million paid for our Cushing to Broome pipeline expansion, (iii) $9.2 million paid for our Cushing Phase V expansion, (iv) $14.2 million paid for our Alberta fractionator and (v) various other projects totaling approximately $61.8 million. We invested approximately $112.5 million in PAA/Vulcan. Additionally, approximately $17.6 million was paid for various acquisitions (a deposit of approximately $12.0 million was

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paid in 2004 on an acquisition completed in 2005). Net cash used in 2004 was $567.3 million and was primarily comprised of (i) $142.5 million paid for the Capline and Capwood Pipeline Systems acquisition (a deposit had been paid in December 2003), (ii) approximately $283 million paid for the Link acquisition, (iii) approximately $19 million paid for the CalVen acquisition, (iv) approximately $46.2 million paid for the Schaefferstown acquisition (including inventory of $14.2 million), (v) approximately $63.6 million paid for additions to property and equipment, and (vi) approximately $10.2 million paid for linefill in assets that we own.

Financing Activities.Cash provided by financing activities in the first nine months of 2005 was approximately $694.1 million, primarily consisting of:

·approximately $149.3 million of proceeds from the sale of senior notes,

·approximately $236.2 million of proceeds from the issuance of common units,

·net short and long-term repayments under our revolving credit facility of approximately $81.5 million,

·net borrowings under our short-term letter of credit and hedged inventory facility of approximately $538.5 million for the purchase of crude oil inventory that was stored (see “Operating Activities” above), and

·$141.5 million of distributions paid to common unitholders and the general partner.

Cash provided by financing activities in the first nine months of 2004 was approximately $453.4 million, primarily consisting of:

·approximately $101.2 million of proceeds from the issuance of Class C common units,

·approximately $160.9 million of proceeds from the issuance of common units,

·approximately $346.4 million of proceeds from the sale of senior notes

·net short and long-term borrowings under our revolving credit facility of approximately $4.7 million,

·net repayments under our short-term letter of credit and hedged inventory facility of approximately $42.2 million resulting from the collection of receivables related to prior year sales of inventory that was stored because of contango market conditions, and

·$114.5 million of distributions paid to common unitholders and the general partner.

Contingencies

See Note 10 “Commitments and Contingencies” in “Notes to the Consolidated Financial Statements.”

Commitments

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

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The following table includes our best estimate of the amount and timing of payments due under specified contractual obligations as of September 30, 2005.

	2005		2006		2007		2008		2009		Thereafter
	(in millions)
Long-term debt and interest payments(1)	$	14.4	$	57.5	$	57.5	$	57.5	$	232.3		$	997.0
Leases(2)	4.7		14.7		12.2		9.6		8.5			48.3
Capital expenditure obligations	1.3		1.0		—		—		—			—
Other long-term liabilities(3)	—		1.6		15.2		1.2		7.3			2.6
Subtotal	20.4		74.8		84.9		68.3		248.1			1,047.9
Crude oil and LPG purchases(3)(4)	1,886.4		438.6		143.2		136.3		136.3			109.6
Total	$	1,906.8	$	513.4	$	228.1	$	204.6	$	384.4		$	1,157.5

(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)Approximately $8.2 million of non-current liabilities related to SFAS 133 are included in the crude oil and LPG 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 September 30, 2005, we had outstanding letters of credit under our various facilities of approximately $84.8 million.

Recent Accounting Pronouncements

See Note 12 “Recent Accounting Pronouncements” in “Notes to the Consolidated Financial Statements.”

As discussed in Note 12, the treatment of buy/sell transactions under EITF 04-13 will reduce the relative amount of revenues on our income statement and thus on unitholders’ tax form K-1. Unitholders should consult their tax advisor with respect to the effect this might have on their tax situation. EITF 04-13 will be effective in reporting periods beginning after March 15, 2006.

Forward-Looking Statements and Associated Risks

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

·abrupt or severe production declines or production interruptions in outer continental shelf production located offshore California and transported on our pipeline system;

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·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 and the risks associated with operating in lines of business that are distinct and separate from our historical operations;

·environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;

·maintenance of our credit rating and ability to receive open credit from our suppliers and trade counterparties;

·declines in volumes shipped on the Basin Pipeline, Capline Pipeline and our other pipelines by us and 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 natural gas or 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;

·interruptions in service and fluctuations in rates of third-party pipelines;

·the effects of competition;

·continued creditworthiness of, and performance by, counter parties;

·the impact of crude oil and natural gas price fluctuations;

·the impact of current and future laws, rulings and governmental regulations;

·shortages or cost increases of power supplies, materials or labor (including the direct and indirect effects of Hurricanes Katrina and Rita on the availability of materials, the cost of natural gas and the demand for oil-field services);

·weather interference with business operations or project construction, including the continued impact of hurricanes Katrina and Rita;

·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;

·general economic, market or business conditions; and

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

Other factors, such as the “Risk Factors Related to Our Business” in Item 7 of our most recent annual report on Form 10-K, and those included as Exhibit 99.2 to our Current Report on Form 8-K filed September 21, 2005 or factors that are unknown or unpredictable, could also have a material adverse effect

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on future results. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

The following should be read in conjunction with Quantitative and Qualitative Disclosures About Market Risks included in Item 7A in our 2004 Annual Report on Form 10-K. There have not been any material changes in that information other than those discussed below.

Commodity Price Risk

The fair value of our open commodity price risk derivative instruments at September 30, 2005 and the change in fair value that would be expected from a 10 percent price decrease are shown in the table below:

					Effect of 10%
	Fair Value				Price Change
	(in millions)
Crude oil:
Futures contracts		$	(4.8	)		$	(3.8	)
Swaps and options contracts		$	(22.0	)		$	(17.7	)
LPG:
Swaps and options contracts		$	10.3			$	9.7

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 September 30, 2005. All of our outstanding senior notes are fixed rate notes. 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 September 30, 2005. The carrying values of the variable rate instruments in our credit facilities approximate fair value primarily because our interest rates are based on our credit rating and fluctuate with prevailing market rates.

	Expected Year of Maturity
	2005			2006			2007			2008			2009			Thereafter			Total
	(in millions)
Liabilities:
Short-term debt—variable rate		$	—	$	769.4			$	—		$	—		$	—		$	—	$	769.4
Average interest rate		—		4.5		%		—			—			—			—		4.5		%
Long-term debt—variable rate		$	—	$	—			$	—		$	—		$	—		$	—	$	—
Average interest rate		—		—				—			—			—			—		—

Item 4. CONTROLS AND PROCEDURES

We maintain “disclosure controls and procedures,” which we refer to as our “DCP.” The purpose of our DCP is to provide reasonable assurance that (i) information is recorded, processed, summarized and reported in time to allow for timely disclosure of such information in accordance with the securities laws and SEC regulations and (ii) information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow for timely decisions regarding required disclosure.

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Applicable SEC rules require an evaluation of the effectiveness of the design and operation of our DCP. Management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our DCP as of September 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”) that occurred during the third 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.

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PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

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

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 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 us in the course of site remediation. Aggregate costs associated with the releases, including estimated remediation costs, are estimated to be approximately $4.0 million to $4.5 million. We continue to work with the appropriate state and federal environmental authorities with respect to 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

On May 19, 2005, Plains All American GP LLC purchased 2,500 common units from Plains AAP, L.P. for $41.55 per unit. On June 8, 2005, Plains All American GP LLC purchased 5,000 common units from Plains AAP, L.P. for $42.33 per unit. The units were used by Plains All American GP LLC to satisfy unit delivery obligations upon vesting of rights under our LTIP. The purchases were not part of a publicly announced “plan” or “program” to purchase units; however, we have previously disclosed that Plains All American GP LLC may satisfy delivery obligations under the LTIP with units obtained by Plains All American GP LLC in open market or private transactions, units already owned by Plains AAP, L.P. or

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units issued by us. Plains All American GP LLC may continue to make occasional purchases of units from Plains AAP, L.P. as vesting events occur under the LTIP.

Item 3. DEFAULTS UPON SENIOR SECURITIES

None

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

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

Item 5. OTHER INFORMATION

Reallocation of General Partner Interest

One of the owners of our general partner sold its 19% interest in the general partner. The remaining owners elected to exercise their right of first refusal, such that the 19% interest was allocated prorata to all remaining owners. As a result, the interest of VEC increased from 44% to approximately 54%. At closing, VEC entered into a voting agreement that restricts its ability to unilaterally elect or remove our independent directors, and our CEO and COO have agreed to waive certain change-of-control payment rights that would otherwise have been triggered by the increase in VEC’s ownership interest.

Sale of Performance Option Plan Units

Our general partner, Plains AAP, L.P. (Plains AAP), and its general partner, Plains All American GP LLC (“GP LLC”), together sponsor a Performance Option Plan (the “Option Plan”) pursuant to which certain of our officers and members of senior management have been granted options to purchase common units. Units used to satisfy an option upon exercise are owned by Plains AAP and, unlike other compensation-related matters, PAA does not have a reimbursement obligation for the cost of such units when delivered.

Despite having an original exercise period extending to 2010, because of recent tax law changes, a substantial portion of the outstanding options must be exercised in 2005 or forfeited. This accelerates into a matter of months option exercises that could have been spread over several years. Because of certain structural features of the Option Plan, each officer/optionee is required to pay cash for withholding taxes at the time of exercise, creating a substantial and immediate liquidity need.

A special committee of the Board of Directors of GP LLC was formed to analyze and resolve issues related to the accelerated exercise of the options. On November 2, 2005, the committee approved a program pursuant to which Plains AAP will sell in the market a portion of the units subject to the Option Plan. The sales will be made pursuant to a “10b5-1 Plan” meeting the requirements for such a plan under Rule 10b5-1 of the Securities Exchange Act, and will take place in amounts and over a time period intended not to disrupt the market. Officers who are optionees may participate in the program by agreeing to cancel their options (limited to those options that must be exercised in 2005) in exchange for a cash payment from the proceeds of such sales. Officers who participate in the plan and who are Section 16 reporting persons will report the cancellation of their options through Form 4 filings. The participants in the program include Harry Pefanis, President and Chief Operating Officer, Phil Kramer, Executive Vice President and Chief Financial Officer and George Coiner, Senior Group Vice President. Approximately 170,000 units will be sold under the program.

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Item 6. EXHIBITS

3.1	Second Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC, dated August 12, 2005 (incorporated by reference to Exhibit 3.1 to Form 8-K filed September 16, 2005)
3.2	Second Amended and Restated Limited Partnership Agreement of Plains AAP, L.P., dated August 12, 2005 (incorporated by reference to Exhibit 3.2 to Form 8-K filed September 16, 2005)
†10.1	Amended and Restated Credit Agreement dated November 4, 2005 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	Administrative Services Agreement between Plains All American Pipeline Company and Vulcan Capital, dated October 14, 2005 (incorporated by reference to Exhibit 1.1 to Form 8-K filed October 19, 2005)
10.3	Amended And Restated Limited Liability Company Agreement of PAA/Vulcan Gas Storage, LLC, dated September 13, 2005 (incorporated by reference to Exhibit 1.1 to Form 8-K filed September 19, 2005)
10.4	Membership Interest Purchase Agreement by and between Sempra Energy Trading Corp. and PAA/Vulcan Gas Storage, LLC and Energy Center Investments Corporation, dated August 19, 2005 (incorporated by reference to Exhibit 1.2 to Form 8-K filed September 19, 2005)
10.5	Waiver Agreement dated as of August 12, 2005 between Plains All American GP LLC and Greg L. Armstrong (incorporated by reference to Exhibit 10.1 to Form 8-K filed August 16, 2005)
10.6	Waiver Agreement dated as of August 12, 2005 between Plains All American GP LLC and Harry N. Pefanis (incorporated by reference to Exhibit 10.2 to Form 8-K filed August 16, 2005)
10.7	Excess Voting Rights Agreement dated as of August 12, 2005 between Vulcan Energy Corporation and Plains All American GP LLC (incorporated by reference to Exhibit 10.3 to Form 8-K filed August 16, 2005)
10.8	Excess Voting Rights Agreement dated as of August 12, 2005 between Lynx Holdings I, LLC and Plains All American GP LLC (incorporated by reference to Exhibit 10.3 to Form 8-K filed August 16, 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

†Filed herewith.

*Furnished herewith.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned and thereunto duly authorized.

	PLAINS ALL AMERICAN PIPELINE, L.P.
	By:	PLAINS AAP, L.P., its general partner
	By:	PLAINS ALL AMERICAN GP LLC, its general partner
Date: November 7, 2005	By:	/s/ GREG L. ARMSTRONG
		Greg L. Armstrong, Chairman of the Board, Chief Executive Officer and Director of Plains All American GP LLC (Principal Executive Officer)
Date: November 7, 2005	By:	/s/ PHIL KRAMER
		Phil Kramer, Executive Vice President and Chief Financial Officer of Plains All American GP LLC (Principal Financial Officer)

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