UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2006

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

PLAINS ALL AMERICAN PIPELINE, L.P.

(Exact name of registrant as specified in its charter)

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

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large Accelerated Filer þ            Accelerated Filer o            Non-Accelerated Filer o

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

     At November 1, 2006, there were outstanding 80,994,178 Common Units.

 

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION			3
Item 1. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS:			3
Consolidated Balance Sheets: September 30, 2006 and December 31, 2005			3
Consolidated Statements of Operations: For the three months and nine months ended September 30, 2006 and 2005			4
Consolidated Statements of Cash Flows: For the nine months ended September 30, 2006 and 2005			5
Consolidated Statement of Partners’ Capital: For the nine months ended September 30, 2006			6
Consolidated Statements of Comprehensive Income: For the three months and nine months ended September 30, 2006 and 2005			6
Consolidated Statement of Changes in Accumulated Other Comprehensive Income: For the nine months ended September 30, 2006			6
Notes to the Consolidated Financial Statements			7
Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			20
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			32
Item 4. CONTROLS AND PROCEDURES			32
PART II. OTHER INFORMATION			33
Item 1. LEGAL PROCEEDINGS			33
Item 1A. RISK FACTORS			33
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			34
Item 3. DEFAULTS UPON SENIOR SECURITIES			34
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS			34
Item 5. OTHER INFORMATION			34
Item 6. EXHIBITS			34
SIGNATURES			37
Registration Rights Agreement
Certification of Principal Executive Officer
Certification of Principal Financial Officer
Certification of Principal Executive Officer
Certification of Principal Financial Officer

PART I. FINANCIAL INFORMATION

Item 1. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in millions, except units)

		September 30,				December 31,
		2006				2005
		(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	10.3			$	9.6
Trade accounts receivable and other receivables, net			1,441.5				781.0
Inventory			1,351.5				910.3
Other current assets			188.9				104.3
Total current assets			2,992.2				1,805.2
PROPERTY AND EQUIPMENT			2,682.1				2,116.1
Accumulated depreciation			(323.1	)			(258.9	)
			2,359.0				1,857.2
OTHER ASSETS
Pipeline linefill in owned assets			204.1				180.2
Inventory in third party assets			77.0				71.5
Investment in PAA/Vulcan Gas Storage, LLC			125.7				113.5
Goodwill			183.3				47.4
Other, net			106.6				45.3
Total assets		$	6,047.9			$	4,120.3
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES
Accounts payable and accrued liabilities		$	1,822.9			$	1,293.6
Due to related parties			7.9				6.8
Short-term debt			993.7				378.4
Other current liabilities			116.7				114.5
Total current liabilities			2,941.2				1,793.3
LONG-TERM LIABILITIES
Long-term debt under credit facilities and other			3.6				4.7
Senior notes, net of unamortized discount of $3.2 and $3.0, respectively			1,196.8				947.0
Other long-term liabilities and deferred credits			66.9				44.6
Total liabilities			4,208.5				2,789.6
COMMITMENTS AND CONTINGENCIES (NOTE 11)
PARTNERS’ CAPITAL
Common unitholders (80,994,178 and 73,768,576 units outstanding at September 30, 2006 and December 31, 2005, respectively)			1,792.6				1,294.1
General partner			46.8				36.6
Total partners’ capital			1,839.4				1,330.7
		$	6,047.9			$	4,120.3

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

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per unit data)

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2006				2005				2006				2005
		(unaudited)								(unaudited)
REVENUES
Crude oil and LPG sales (includes buy/sell transactions of $4,442.8 million in the three months ended September 30, 2005 and $4,717.7 million and $11,630.0 million in the nine months ended September 30, 2006 and 2005, respectively)		$	4,264.7			$	8,387.1			$	17,272.5			$	21,724.4
Other gathering, marketing, terminalling and storage revenues			19.8				8.5				55.5				28.0
Pipeline margin activities revenues (includes buy/sell transactions of $52.2 million in the three months ended September 30, 2005 and $45.3 million and $125.8 million in the nine months ended September 30, 2006 and 2005, respectively)			174.6				209.8				542.3				542.3
Pipeline tariff activities revenues			66.7				59.0				183.3				168.9
Total revenues			4,525.8				8,664.4				18,053.6				22,463.6
COSTS AND EXPENSES
Crude oil and LPG purchases and related costs (includes buy/sell transactions of $4,425.4 million in the three months ended September 30, 2005 and $4,749.4 million and $11,426.0 million in the nine months ended September 30, 2006 and 2005, respectively)			4,096.4				8,258.2				16,830.1				21,397.0
Pipeline margin activities purchases (includes buy/sell transactions of $47.1 million in the three months ended September 30, 2005 and $45.7 million and $115.9 million in the nine months ended September 30, 2006 and 2005, respectively)			167.6				206.5				521.3				525.5
Field operating costs			91.6				68.3				260.5				200.0
General and administrative expenses			33.0				26.5				92.2				74.8
Depreciation and amortization			24.2				20.0				67.1				58.1
Total costs and expenses			4,412.8				8,579.5				17,771.2				22,255.4
OPERATING INCOME			113.0				84.9				282.4				208.2
OTHER INCOME/(EXPENSE)
Equity earnings in PAA/Vulcan Gas Storage, LLC			1.3				—				2.2				—
Interest expense (net of capitalized interest of $1.7 million and $0.5 million in the three months and $3.4 million and $1.5 million in the nine months ended September 30, 2006 and 2005, respectively)			(19.2	)			(15.6	)			(52.5	)			(44.4	)
Interest income and other income (expense), net			0.3				(0.3	)			0.7				0.3
Income before cumulative effect of change in accounting principle			95.4				69.0				232.8				164.1
Cumulative effect of change in accounting principle			—				—				6.3				—
NET INCOME		$	95.4			$	69.0			$	239.1			$	164.1
NET INCOME-LIMITED PARTNERS		$	84.6			$	63.9			$	212.7			$	150.8
NET INCOME-GENERAL PARTNER		$	10.8			$	5.1			$	26.4			$	13.3
BASIC NET INCOME PER LIMITED PARTNER UNIT
Income before cumulative effect of change in accounting principle		$	0.90			$	0.81			$	2.37			$	2.11
Cumulative effect of change in accounting principle			—				—				0.08				—
Net income		$	0.90			$	0.81			$	2.45			$	2.11
DILUTED NET INCOME PER LIMITED PARTNER UNIT
Income before cumulative effect of change in accounting principle		$	0.89			$	0.79			$	2.35			$	2.07
Cumulative effect of change in accounting principle			—				—				0.08				—
Net income		$	0.89			$	0.79			$	2.43			$	2.07
BASIC WEIGHTED AVERAGE UNITS OUTSTANDING			79.9				68.0				77.0				67.8
DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING			80.8				69.4				77.8				68.9

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

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

		Nine Months Ended
		September 30,
		2006				2005
		(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income		$	239.1			$	164.1
Adjustments to reconcile to cash flows from operating activities:
Depreciation and amortization			67.1				58.1
Cumulative effect of change in accounting principle			(6.3	)			—
SFAS 133 mark-to-market adjustment			(14.8	)			20.0
Long-Term Incentive Plan charge			27.1				16.9
Noncash amortization of terminated interest rate hedging instruments			1.2				1.2
Loss on foreign currency revaluation			2.1				1.4
Net cash paid for terminated interest rate hedging instruments			—				(0.9	)
Equity earnings in PAA/Vulcan Gas Storage, LLC			(2.2	)			—
Changes in assets and liabilities, net of acquisitions:
Trade accounts receivable and other			(595.3	)			(584.0	)
Inventory			(414.6	)			(470.9	)
Accounts payable and other current liabilities			512.4				339.7
Due to related parties			2.3				4.9
Net cash used in operating activities			(181.9	)			(449.5	)
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions (Note 3)			(560.2	)			(17.7	)
Additions to property and equipment			(223.1	)			(122.1	)
Investment in unconsolidated affiliates			(10.0	)			(112.5	)
Cash paid for linefill in assets owned			(4.8	)			—
Proceeds from sales of assets			3.8				3.8
Net cash used in investing activities			(794.3	)			(248.5	)
CASH FLOWS FROM FINANCING ACTIVITIES
Net repayments on long-term revolving credit facility			(7.7	)			(143.7	)
Net borrowings on working capital revolving credit facility			55.3				62.2
Net borrowings on short-term letter of credit and hedged inventory facility			559.5				538.5
Proceeds from the issuance of senior notes			249.5				149.3
Net proceeds from the issuance of common units (Note 7)			315.6				236.2
Distributions paid to unitholders and general partner (Note 7)			(189.4	)			(141.5	)
Other financing activities			(6.6	)			(6.9	)
Net cash provided by financing activities			976.2				694.1
Effect of translation adjustment on cash			0.7				(0.9	)
Net increase (decrease) in cash and cash equivalents			0.7				(4.8	)
Cash and cash equivalents, beginning of period			9.6				13.0
Cash and cash equivalents, end of period		$	10.3			$	8.2
Cash paid for interest, net of amounts capitalized		$	74.3			$	53.2

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

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(in millions)

														Total
										General				Partners’
		Common Units								Partner				Capital
		Units				Amount				Amount				Amount
		(unaudited)
Balance at December 31, 2005			73.8			$	1,294.1			$	36.6			$	1,330.7
Net Income			—				212.7				26.4				239.1
Distributions			—				(164.0	)			(25.4	)			(189.4	)
Issuance of common units			7.2				309.3				6.3				315.6
Other comprehensive income			—				140.5				2.9				143.4
Balance at September 30, 2006			81.0			$	1,792.6			$	46.8			$	1,839.4

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

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2006				2005				2006				2005
		(unaudited)								(unaudited)
Net income		$	95.4			$	69.0			$	239.1			$	164.1
Other comprehensive income/(loss)			123.8				75.1				143.4				(21.8	)
Comprehensive income		$	219.2			$	144.1			$	382.5			$	142.3

CONSOLIDATED STATEMENT OF

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME

(in millions)

		Net Deferred
		Gain/(Loss) on				Currency
		Derivative				Translation
		Instruments				Adjustments				Total
		(unaudited)
Balance at December 31, 2005		$	(16.6	)		$	87.1			$	70.5
Current period activity:
Reclassification adjustment for settled contracts			(5.4	)			—				(5.4	)
Changes in fair value of outstanding hedge positions			136.0				—				136.0
Currency translation adjustment			—				12.8				12.8
Total period activity			130.6				12.8				143.4
Balance at September 30, 2006		$	114.0			$	99.9			$	213.9

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

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1—Organization and Accounting Policies

     Plains All American Pipeline, L.P. (“PAA”) is a Delaware limited partnership formed in September 1998. Our operations are conducted directly and indirectly through our primary 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 liquefied 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 the third quarter of 2006 we completed an acquisition that represents our initial entry into the refined products transportation business (See Note 3). In addition, through our 50% equity ownership in PAA/Vulcan Gas Storage, LLC (“PAA/Vulcan”), we are engaged in the development and operation of natural gas storage facilities. Investments in 50% or less owned affiliates, over which we have significant influence, such as PAA/Vulcan, are accounted for by the equity method. We evaluate our equity investments for impairment in accordance with APB 18: The Equity Method of Accounting for Investments in Common Stock. An impairment of an equity investment results when factors indicate that the investment’s fair value is less than its carrying value and the reduction in value is other than temporary in nature.

     The accompanying consolidated financial statements and related notes present (i) our consolidated financial position as of September 30, 2006 and December 31, 2005, (ii) the results of our consolidated operations for the three months and nine months ended September 30, 2006 and 2005, (iii) our consolidated cash flows for the nine months ended September 30, 2006 and 2005, (iv) our consolidated changes in partners’ capital for the nine months ended September 30, 2006, (v) our consolidated comprehensive income for the three months and nine months ended September 30, 2006 and 2005, and (vi) our changes in consolidated accumulated other comprehensive income for the nine months ended September 30, 2006. 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, 2006 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 2005 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 as shown below. At September 30, 2006, 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, 2005		$	0.8
Applied to accounts receivable balances			(0.3	)
Charged to expense			0.1
Balance at September 30, 2006		$	0.6

     We consider this reserve adequate; however, actual amounts may vary significantly from estimated amounts. The discovery of previously unknown facts or adverse developments affecting one or more of our counterparties or the industry as a whole could adversely impact our results of operations.

Note 3—Acquisitions

     We completed six acquisitions during the first nine months of 2006 for aggregate consideration of approximately $567 million. The aggregate consideration includes cash paid, estimated transaction costs and assumed liabilities and net working capital items. The aggregate purchase price is preliminary pending the resolution of working capital adjustments and the finalization of certain estimated transaction related costs. These acquisitions include (i) 100% of the equity interests of Andrews Petroleum and Lone Star Trucking, which provide isomerization, fractionation, marketing and transportation services to producers and customers of natural gas liquids (collectively, the “Andrews Acquisition”), (ii) crude oil gathering and transportation assets and related contracts in South Louisiana, (iii) interests in various crude oil pipeline systems in Canada and the U.S. including a 100% interest in the Bay Marchand-to-Ostrica-to-Alliance (“BOA”) Pipeline, various interests in the High Island Pipeline System (“HIPS”), and a 64.35% interest in the Clovelly-to-Meraux (“CAM”) Pipeline system, and (iv) three refined products pipeline systems from Chevron Pipe Line Company. The preliminary purchase price allocation is as follows (in millions):

Inventory		$	35.1
Linefill			19.1
Inventory in third party assets			2.3
Property and equipment			327.4
Goodwill (1)			134.3
Intangibles			48.7
Net other assets and liabilities			(0.3	)
		$	566.6

     Pro Forma Data

     The following unaudited pro forma data is presented as if the acquisitions and related financings, in the aggregate, had occurred as of the beginning of the periods reported (in millions, except per unit amounts):

		Three Months Ended September 30,(1)								Nine Months Ended September 30,(1)
		2006				2005				2006				2005
		(unaudited)
Revenues		$	4,530.3			$	8,952.9			$	18,634.9			$	23,045.2
Income before cumulative effect of change in accounting principle		$	98.3			$	74.6			$	252.1			$	170.6
Net income		$	98.3			$	74.6			$	258.4			$	170.6
Basic income before cumulative effect of change in accounting principle per limited partner unit		$	0.91			$	0.79			$	2.44			$	2.03
Diluted income before cumulative effect of change in accounting principle per limited partner unit		$	0.90			$	0.78			$	242			$	2.00
Basic net income per limited partner unit		$	0.91			$	0.79			$	2.52			$	2.03
Diluted net income per limited partner unit		$	0.90			$	0.78			$	2.49			$	2.00

      In June 2006, Plains entered into a purchase agreement with LB Pacific, the owner of the general partner of Pacific Energy Partners, LP (“Pacific Energy”), pursuant to which Plains has agreed, subject to the terms and conditions set forth in the purchase agreement, to purchase from LB Pacific (i) all of the issued and outstanding limited partner interest in Pacific Energy GP, LP, a Delaware limited partnership and the general partner of Pacific Energy, (ii) the sole member interest in Pacific Energy Management LLC, a Delaware limited liability company and the general partner of Pacific Energy GP, LP, (iii) approximately 5.2 million Pacific Energy common units and (iv) approximately 5.2 million Pacific Energy subordinated units for an aggregate purchase price of $700 million in cash. This purchase and sale will occur immediately prior to the consummation of our merger with Pacific Energy pursuant to our Agreement and Plan of Merger dated June 11, 2006. As a result of the merger, we will acquire the balance of Pacific Energy’s equity through a unit-for-unit exchange in which each remaining unitholder of Pacific Energy will receive 0.77 newly issued PAA common units for each Pacific Energy common unit. The total value of the transaction is approximately $2.4 billion, including the assumption of debt and estimated transaction costs. The completion of the transaction remains subject to the approval of the unitholders of PAA and Pacific Energy. The unitholder meetings are scheduled for November 9, 2006. Assuming a favorable unitholder vote, we anticipate closing the transaction on November 15, 2006.

      In November 2006, we acquired a 50% interest in Settoon Towing, LLC (“Settoon Towing”) for approximately $33 million. Settoon Towing owns and operates a fleet of 57 transport and storage barges as well as 30 transport tugs. Its core business is the gathering and transportation of crude oil and produced water from inland production facilities across the Gulf Coast. We are currently Settoon’s largest customer with 22 tugs and 22 tank barges under a five-year chartering agreement, which commenced May 1, 2006.

Note 4—Inventory and Linefill

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

     In the third quarter 2006, we recognized a $5.2 million non-cash charge primarily associated with the significant decline in oil prices and other product prices during the quarter and the related decline in the valuation of working inventory volumes. Approximately $3.4 million of the charge relates to crude oil linefill in pipelines owned by third parties and the remainder relates to LPG and other products inventory.

     At September 30, 2006 and December 31, 2005, inventory and linefill consisted of :

		September 30, 2006												December 31, 2005
										Dollar/												Dollar/
		Barrels				Dollars				barrel				Barrels				Dollars				barrel
		(Barrels in thousands and dollars in millions)
Inventory
Crude oil			14,561			$	1,009.0			$	69.29				13,887			$	755.7			$	54.42
LPG			7,549				338.2			$	44.80				3,649				149.0			$	40.83
Parts and supplies			N/A				4.3				N/A				N/A				5.6				N/A
Inventory subtotal			22,110				1,351.5								17,536				910.3
Inventory in third-party assets
Crude oil			1,275				63.3			$	49.65				1,248				58.6			$	46.96
LPG			318				13.7			$	43.08				318				12.9			$	40.57
Inventory in third-party assets subtotal			1,593				77.0								1,566				71.5
Pipeline linefill in owned assets
Crude oil			6,578				203.0			$	30.86				6,207				179.3			$	28.89
LPG			31				1.1			$	35.48				27				0.9			$	33.33
Linefill subtotal			6,609				204.1								6,234				180.2
Total			30,312			$	1,632.6								25,336			$	1,162.0

Note 5—Debt

     In October 2006, we issued $400 million of 6.125% Senior Notes due 2017 and $600 million of 6.65% Senior Notes due 2037. The notes were sold at 99.56% and 99.17% of face value, respectively. Interest payments are due on January 15 and July 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 intend to use the proceeds to fund the cash portion of our proposed merger with Pacific Energy. Net proceeds in excess of the cash portion of the merger consideration will be used to repay amounts outstanding under our credit facilities and for general partnership purposes. If the merger with Pacific Energy is not closed on or prior to February 15, 2007 or the merger agreement relating to the Pacific Energy merger is terminated earlier, we will redeem the notes at 101% of the aggregate principal amount thereof plus accrued and unpaid interest to the date of redemption. In anticipation of the issuance of these notes, we had entered into $200 million notional principal amount of U.S. treasury locks to hedge the treasury rate portion of the interest rate on a portion of the notes. The treasury locks were entered into at an interest rate of 4.97%. See Note 9. Upon completion of the issuance of these notes, we terminated the $1.0 billion acquisition bridge facility that we entered into in July 2006 in contemplation of the Pacific Energy merger.

     During May 2006, we completed the sale of $250 million aggregate principal amount of 6.70% Senior Notes due 2036. The notes were sold at 99.82% of face value. Interest payments are due on May 15 and November 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.

     Below is a description of our debt as of:

		September 30,				December 31,
		2006				2005
		(in millions)
Short-term debt:
Senior secured hedged inventory facility bearing interest at a rate of 5.8% and 4.8% at September 30, 2006 and December 31, 2005, respectively		$	778.8			$	219.3
Working capital borrowings, bearing interest at a rate of 5.9% and 5.0% at September 30, 2006 and December 31, 2005, respectively (1)			212.0				155.4
Other			2.9				3.7
Total short-term debt			993.7				378.4
Long-term debt:
4.75% senior notes due August 2009, net of unamortized discount of $0.5 million and $0.6 million at September 30, 2006 and December 31, 2005, respectively			174.5				174.4
7.75% senior notes due October 2012, net of unamortized discount of $0.2 million and $0.2 million at September 30, 2006 and December 31, 2005, respectively			199.8				199.8
5.63% senior notes due December 2013, net of unamortized discount of $0.5 million and $0.5 million at September 30, 2006 and December 31, 2005, respectively			249.5				249.5
5.25% senior notes due June 2015, net of unamortized discount of $0.6 million and $0.7 million at September 30, 2006 and December 31, 2005, respectively			149.4				149.3
5.88% senior notes due August 2016, net of unamortized discount of $0.9 million and $1.0 million at September 30, 2006 and December 31, 2005, respectively			174.1				174.0
6.70% senior notes due May 2036, net of unamortized discount of $0.5 million at September 30, 2006			249.5				—
Senior notes, net of unamortized discount (2)			1,196.8				947.0
Long-term debt under credit facilities and other			3.6				4.7
Total long-term debt (1)(2)			1,200.4				951.7
Total debt		$	2,194.1			$	1,330.1

     In July 2006, we amended our senior unsecured revolving credit facility to increase the aggregate capacity from $1.0 billion to $1.6 billion and the sub-facility for Canadian borrowings from $400 million to $600 million. The amended facility can be expanded to $2.0 billion, subject to additional lender commitments, and has a final maturity of July 2011.

     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 periods of up to seventy days and are terminated upon completion of each transaction. At September 30, 2006, we had outstanding letters of credit under our credit facility of approximately $93 million.

Note 6—Earnings Per Limited Partner Unit

     Basic and diluted net income per limited partner unit is determined by dividing net income available to limited partners by the weighted average number of limited partner units outstanding during the period. To calculate net income available to limited partners, income is first allocated to the general partner based on the amount of incentive distributions and the remainder is allocated between the limited partners and the general partner based on percentage ownership in the Partnership. EITF No. 03-06 (“EITF 03-06”), “Participating Securities and the Two-Class Method under FASB Statement No. 128,” addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity when, and if, it declares dividends on its common stock. 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 period 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.

The following sets forth the computation of basic and diluted earnings per limited partner unit.

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2006				2005				2006				2005
		(in millions, except per unit data)
Numerator:
Net income		$	95.4			$	69.0			$	239.1			$	164.1
Less: General partner’s incentive distribution paid			(9.1	)			(3.8	)			(22.1	)			(10.2	)
Subtotal			86.3				65.2				217.0				153.9
General partner 2% ownership			(1.7	)			(1.3	)			(4.3	)			(3.1	)
Net income available to limited partners			84.6				63.9				212.7				150.8
EITF 03-06 additional general partner’s distribution			(12.6	)			(9.1	)			(23.8	)			(8.0	)
Net income available to limited partners under EITF 03-06		$	72.0			$	54.8			$	188.9			$	142.8
Less: Limited partner 98% portion of cumulative effect of change in accounting principle			—				—				(6.2	)			—
Limited partner net income before cumulative effect of change in accounting principle		$	72.0			$	54.8			$	182.7			$	142.8
Denominator:
Basic earnings per limited partner unit (weighted average number of limited partner units outstanding)			79.9				68.0				77.0				67.8
Effect of dilutive securities:
Weighted average LTIP units outstanding (1)			0.9				1.4				0.8				1.1
Diluted earnings per limited partner unit (weighted average number of limited partner units outstanding)			80.8				69.4				77.8				68.9
Basic net income per limited partner unit before cumulative effect of change in accounting principle		$	0.90			$	0.81			$	2.37			$	2.11
Cumulative effect of change in accounting principle per limited partner unit			—				—				0.08				—
Basic net income per limited partner unit		$	0.90			$	0.81			$	2.45			$	2.11
Diluted net income per limited partner unit before cumulative effect of change in accounting principle		$	0.89			$	0.79			$	2.35			$	2.07
Cumulative effect of change in accounting principle per limited partner unit			—				—				0.08				—
Diluted net income per limited partner unit		$	0.89			$	0.79			$	2.43			$	2.07

Note 7—Partners’ Capital and Distributions

     Direct Placements of Common Units

     We completed the following equity offerings of our common units during the nine months ended September 30, 2006 and 2005, respectively. See Note 10 “Related Party Transactions.”

						Gross Per				Proceeds				GP							Net
Period		Units				Unit Price				from Sale				Contribution				Costs			Proceeds
		(in millions, except unit amounts and per unit price)
July/August 2006			3,720,930			$	43.00			$	160.0			$	3.3			$	(0.1	)		$	163.2
March/April 2006			3,504,672			$	42.80			$	150.0			$	3.0			$	(0.6	)		$	152.4
September/October 2005			5,854,000			$	42.00			$	246.0			$	5.0			$	(9.1	)		$	241.9
February 2005			575,000			$	38.13			$	21.9			$	0.5			$	(0.1	)		$	22.3

     Distributions

     The following table details the distributions we have declared and paid in the nine months ended September 30, 2006 and 2005 (in millions, except per unit amounts):

		Distributions Paid
		Common				GP													Distribution
		Units				Incentive				2%					Total				per unit
August 14, 2006		$	58.7			$	9.1			$	1.2				$	69.0			$	0.7250
May 15, 2006			54.6				7.4				1.1					63.1			$	0.7075
February 14, 2006			50.7				5.6				1.0					57.3			$	0.6875
2006 Total		$	164.0			$	22.1			$	3.3				$	189.4

		Distributions Paid
		Common				GP													Distribution
		Units				Incentive				2%					Total				per unit
August 12, 2005		$	44.1			$	3.8			$	0.9				$	48.8			$	0.6500
May 13, 2005			43.3				3.5				0.9					47.7			$	0.6375
February 14, 2005			41.2				2.9				0.9					45.0			$	0.6125
2005 Total		$	128.6			$	10.2			$	2.7				$	141.5

     On October 24, 2006, we declared a cash distribution of $0.75 per unit on our outstanding common units. The distribution is payable on November 14, 2006, to unitholders of record on November 3, 2006, for the period July 1, 2006 through September 30, 2006. The total distribution to be paid is approximately $73 million, with approximately $61 million to be paid to our common unitholders and approximately $1 million and $11 million to be paid to our general partner for its general partner and incentive distribution interests, respectively.

Note 8—Long-Term Incentive Plans

     Our general partner has adopted the Plains All American GP LLC 1998 Long-Term Incentive Plan and the 2005 Long-Term Incentive Plan, collectively referred to as Long-Term Incentive Plans (“LTIP”), for employees and directors of our general partner and its affiliates who perform services for us. Awards contemplated by the LTIP include phantom units, restricted units, unit appreciation rights and unit options, as determined by the compensation committee or the board of directors of our general partner (each an “Award”). Under the LTIP, up to 4.4 million units may be issued in satisfaction of Awards. Certain Awards may also include distribution equivalent rights (“DERs”) at the discretion of the compensation committee or the board of directors of our general partner. Subject to applicable vesting criteria, a DER entitles the grantee to a cash payment equal to cash distributions paid on an outstanding common unit. Upon vesting, certain of the Awards may be settled in common units or equivalent cash value at the election of our general partner. Our general partner will be entitled to reimbursement by us for any costs incurred in settling obligations under the LTIP.

     As of September 30, 2006, there were approximately 2.2 million unvested phantom units outstanding with a weighted average grant-date fair value of approximately $32.22 per unit. In addition, approximately 1.6 million of these Awards include DERs. Approximately 1.5 million of the Awards vest over a six-year period from the grant date (with performance accelerators), while the remaining awards vest over time only if certain performance conditions are met and are forfeited after six years if the

performance conditions are not met. The DERs vest over time (with performance accelerators) and terminate with the vesting or forfeiture of the related phantom units.

      Our non-employee directors receive LTIP awards or cash equivalent awards as part of their compensation. These awards vest annually in 25% increments over a four-year period and have an automatic re-grant feature such that as they vest, an equivalent amount is granted. The three non-employee directors who serve on our audit committee each receive a grant of 10,000 units (vesting 2,500 units per year). The remaining three non-employee directors each receive 5,000 units (vesting 1,250 per year) or their cash equivalent.

     We adopted Statement of Financial Accounting Standards No. 123(R) (revised 2004), “Share Based Payment” (“SFAS 123(R)”) on January 1, 2006 (See Note 13 for a discussion of recent accounting pronouncements). Under SFAS 123(R) the fair value of the Awards, which are subject to liability classification, is calculated based on the market price of our units at the balance sheet date adjusted for (i) the present value of any distributions that are probable of occurring on the underlying units over the vesting period that will not be received by the award recipients and (ii) an estimated forfeiture rate when appropriate. This fair value is then expensed over the period the Awards are earned. In addition, we recognize compensation expense for DER payments in the period the payment is earned.

      We recognized expense related to the LTIP of approximately $10 million and $7 million during the third quarters of 2006 and 2005, respectively, and $27 million and $17 million during the first nine months, of 2006 and 2005, respectively. Additionally, as of September 30, 2006, we have an accrued liability of approximately $43 million associated with the LTIP, of which $12 million is current.

     As of September 30, 2006, the weighted average remaining contractual life of our outstanding Awards was approximately five years. Based on the September 30, 2006 fair value measurement, we expect to recognize an additional $54 million of expense over the life of our outstanding Awards related to the remaining unrecognized fair value. This estimate is based on the market price of our limited partner units at the end of the period and actual amounts may differ materially as a result of a change in market price. We estimate that the remaining fair value will be recognized in expense in the following years (in millions):

		LTIP
		Fair Value
Year		Amortization
2006 (1)		$	7.3
2007			21.0
2008			14.1
2009			9.2
2010			2.6
Total		$	54.2

     During October 2006, our general partner adopted the Plains All American GP LLC 2006 Long-Term Incentive Tracking Unit Plan (the “2006 Plan”) and subsequently granted approximately 0.8 million tracking units to non-executive employees. These awards contain performance related provisions that provide for vesting upon achieving distribution targets of $3.50, $3.75 and $4.00 per unit, subject to minimum service periods through 2010, but provides that 50% of the un-vested units will vest in 2012, subject to continued employment through such period. All remaining tracking units that have not vested by 2013 will terminate. Upon vesting, tracking units will be settled through cash payments based on the equivalent value of an equal number of common units. The aggregate grant date fair value of the tracking units awarded under the 2006 Plan is approximately $24.9 million.

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, ICE 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. Our policy is to 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.

     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, LPG and natural gas 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, ICE and over-the-counter, including commodity 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 SFAS No. 133, “Accounting For Derivative Instruments and Hedging Activities,” as amended (“SFAS 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 2006, our earnings include a net gain of approximately $80 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 gain of approximately $15 million (a $3 million loss in the first half of the year and a $18 million gain in the third quarter of 2006), which is primarily 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,
	b)		A net gain of approximately $66 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 2006, and
	c)		A net loss of approximately $1 million related to terminated interest rate swaps, which are being amortized to interest expense over the original terms of the terminated investments.

     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, 2006 and December 31, 2005, respectively (in millions):

		September 30,				December 31,
		2006				2005
Other current assets		$	165.9			$	45.7
Other long-term assets			13.5				5.5
Other current liabilities			(40.7	)			(72.5	)
Other long-term liabilities and deferred credits			(22.3	)			(6.5	)
Net asset (liability)		$	116.4			$	(27.8	)

     The net asset as of September 30, 2006 includes approximately $2 million of unrealized losses recognized in earnings and $118 million of unrealized gains on effective cash flow hedges that are deferred to OCI. The majority of the $2 million of unrealized losses that have been recognized in earnings relate to activities associated with our storage assets. In general, revenue from storing crude oil is reduced in a backwardated market (when oil prices for future deliveries are lower than for current deliveries) as there is less incentive to store crude oil from month to month. We enter into derivative contracts,

including futures and options, that will offset the reduction in revenue by generating offsetting gains in a backwardated market structure. These derivatives do not qualify for hedge accounting because the contracts will not necessarily result in physical delivery.

     At September 30, 2006, there was a total unrealized net gain of approximately $114 million deferred to OCI. This included approximately $118 million unrealized gains (referenced above), which predominantly related to unrealized gains on derivatives used to hedge physical inventory in storage that receive hedge accounting, and approximately $4 million deferred losses relating to terminated interest rate swaps, which are being amortized to interest expense over the original terms of the terminated instruments. The inventory hedges are mostly short futures positions that will result in gains when futures prices fall. These hedge gains are offset by a decrease 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 gains recorded in OCI is expected to be reclassified to future earnings contemporaneously with the related physical purchase or delivery of the underlying commodity or payments of interest.

     During August 2006, we entered into two treasury locks with large creditworthy financial institutions in anticipation of a debt issuance in conjunction with our acquisition of Pacific Energy. A treasury lock is a financial derivative instrument that enables a company to lock in the U.S. Treasury Note rate. The U.S. Treasury Note rate was the benchmark interest rate for our anticipated debt issuance. The two treasury locks had a combined notional principal amount of $200 million and an effective interest rate of 4.97%. Both treasury locks mature in November 2006. The treasury locks are qualified cash flow hedges and the changes in fair value of the treasury locks are therefore deferred in OCI. At September 30, 2006, we had a net loss of approximately $6 million deferred in OCI related to the treasury locks. In October 2006, both treasury locks were terminated prior to maturity for an aggregate cash payment of $2 million in connection with the debt issuance in October 2006.

     Of the total net gain deferred in OCI at September 30, 2006, a net gain of approximately $124 million will be reclassified into earnings in the next twelve months and the remaining net loss at various intervals (ending in 2016 for amounts related to our terminated interest rate swaps and 2009 for amounts related to our commodity price-risk hedging). Because a portion of these amounts is based on market prices at the current period end, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

     During the nine months ended September 30, 2006, no amounts were reclassified to earnings from OCI in connection with forecasted transactions that were no longer considered probable of occurring.

Note 10—Related Party Transactions

      Gas Hedges. PAA/Vulcan is developing a natural gas storage facility through its wholly owned subsidiary, Pine Prairie Energy Center, LLC (“Pine Prairie”). Proper functioning of the Pine Prairie storage caverns will require a minimum operating inventory contained in the caverns at all times (referred to as “base gas”). It is estimated that it will require approximately 7.3 billion cubic feet of base gas. During the first quarter of 2006, we arranged to provide the base gas for the storage facility to Pine Prairie at a price not to exceed $8.50 per million cubic feet. In conjunction with this arrangement, we executed hedges on the NYMEX for the relevant delivery periods of 2007, 2008 and 2009. We received a fee of approximately $1 million for our services to own and manage the hedge positions and to deliver the natural gas.

     Equity Offerings. In March and April of 2006, we sold 3,504,672 common units, approximately 20% of which were sold to investment funds affiliated with Kayne Anderson Capital Advisors, L.P. (“KACALP”). The net proceeds were used to fund a portion of the Andrews acquisition, to reduce indebtedness and for general partnership purposes. In addition, in July and August 2006, we sold a total of 3,720,930 common units, approximately 12.5% and 18.7% of which were sold to investment funds affiliated with KACALP and Vulcan Capital, respectively. KAFU Holdings, L.P., which owns 20.3% of our general partner and has a representative on our board of directors, is managed by KACALP. Vulcan Capital, the investment arm of Paul G. Allen, and its subsidiaries own approximately 54% of our general partner interest and has a representative on our board of directors. The proceeds from the third quarter offering were used to fund acquisition costs, repay indebtedness under our credit facilities and for general partnership purposes.

     On February 25, 2005, we issued 575,000 common units in a private placement to a subsidiary of Vulcan Energy Corporation (“Valcan Energy”). The sale price was $38.13 per unit, which represented a 2.8% discount to the closing price of the units on February 24, 2005. The sale resulted in net proceeds, including the general partner’s proportionate capital contribution ($0.5 million) and net of expenses associated with the sale, of approximately $22.3 million.

     Long-Term Incentive Plans. During the third quarter of 2006, we purchased 15,105 common units from our general partner for an average price of $46.03 per unit. The common units were used to satisfy our obligations with respect to awards that vested under our 1998 LTIP.

     Administrative Services Agreement. On October 14, 2005, Plains All American GP LLC (“GP LLC”) and Vulcan Energy entered into an Administrative Services Agreement, effective as of September 1, 2005 (the “Services Agreement”). Pursuant to the Services Agreement, GP LLC provides administrative services to Vulcan Energy for an annual fee plus reimbursement of 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. Effective October 1, 2006, the annual fee was increased from $650,000 to $1 million.

Note 11—Commitments and Contingencies

     Pipeline Releases. In January 2005 and December 2004, we experienced two unrelated releases of crude oil that reached rivers located near the sites where the releases originated. 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 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 both cases, emergency response personnel under the supervision of a unified command structure consisting of representatives of Plains Pipeline, the U.S. Environmental Protection Agency (“EPA”), the Texas Commission on Environmental Quality and the Texas Railroad Commission conducted clean-up operations at each site. Approximately 980 and 4,200 barrels were recovered from the two respective sites. The unrecovered oil was 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 $4.5 million to $5.0 million. In cooperation with the appropriate state and federal environmental authorities, we have substantially completed our work with respect to site restoration, subject to some ongoing remediation at the Pecos River site. EPA has referred these two crude oil releases, as well as several other smaller releases, to the U.S. Department of Justice for further investigation in connection with a possible civil penalty enforcement action under the Federal Clean Water Act. We are cooperating in the investigation. Our assessment is that it is probable we will pay penalties related to the two releases. We have accrued the estimated loss contingency, which is included in the estimated aggregate costs set forth above. It is reasonably possible that the loss contingency may exceed our estimate with respect to penalties assessed by EPA; however, we have no indication from EPA or the Department of Justice of what penalties might be sought. As a result, we are unable to estimate the range of a reasonably possible loss contingency in excess of our accrual.

     General. We, in the ordinary course of business, are a claimant and /or a defendant in various legal proceedings. To the extent we are able to assess the likelihood of a negative outcome for these proceedings, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue the estimated amount. We do not believe that the outcome of these legal proceedings, individually and in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.

     Other. A pipeline, terminal or other facility may experience damage as a result of an accident or natural disaster. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We maintain insurance of various types that we consider adequate to cover our operations and properties. The insurance covers our assets in amounts considered reasonable. The insurance policies are subject to deductibles that we consider reasonable and not excessive. Our insurance does not cover every potential risk associated with operating pipelines, terminals and other facilities, including the potential loss of significant revenues. The overall trend in the environmental insurance industry appears to be a contraction in the breadth and depth of available coverage, while costs, deductibles and retention levels have increased. As a result of the significant wind damage claims filed following hurricanes Katrina, Rita and Wilma, the insurance industry has indicated that it will materially reduce the amount of coverage available for windstorm damages. Absent a material favorable change in the insurance markets, these trends are expected to continue as we continue to grow and expand. As a result, we anticipate that we will elect to self-insure more of our activities or incorporate higher retention in our insurance arrangements.

     The occurrence of a significant event not fully insured, indemnified or reserved against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. We believe we are adequately insured for public liability and property damage to others with respect to our operations. 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.

     Long-term Contract. Effective May 1, 2006, we entered into a five-year agreement with Settoon Towing to charter 22 inland tugboats and 22 tank barges. Annual charter costs are projected to be approximately $22 million, subject to escalation limited by the increase in the Producer Price Index—Finished Goods. Also, see Note 3.

Note 12—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. The following tables reflect certain financial data for each segment for the periods indicated:

		Pipeline				GMT&S				Total
		(in millions)
Three Months Ended September 30, 2006
Revenues:
External Customers(1)		$	241.3			$	4,284.5			$	4,525.8
Intersegment(2)			40.2				0.3				40.5
Total revenues of reportable segments		$	281.5			$	4,284.8			$	4,566.3
Segment profit (3)(4)(5)		$	52.2			$	85.0			$	137.2
SFAS 133 impact (3)		$	—			$	17.9			$	17.9
Maintenance capital		$	5.3			$	2.9			$	8.2
Three Months Ended September 30, 2005
Revenues:
External Customers (includes buy/sell revenues of $52.2, $4,442.8, and $4,495.0 for Pipeline, GMT&S, and Total, respectively)		$	268.8			$	8,395.6			$	8,664.4
Intersegment(2)			34.5				0.2				34.7
Total revenues of reportable segments		$	303.3			$	8,395.8			$	8,699.1
Segment profit (3)(4)(5)		$	45.7			$	59.2			$	104.9
SFAS 133 impact (3)		$	—			$	6.3			$	6.3
Maintenance capital		$	2.9			$	1.3			$	4.2

		Pipeline				GMT&S				Total
		(in millions)
Nine Months Ended September 30, 2006
Revenues:
External Customers (includes buy/sell revenues of $45.3, $4,717.7, and $4,763.0 for Pipeline, GMT&S, and Total, respectively)		$	725.6			$	17,328.0			$	18,053.6
Intersegment(2)			115.8				0.7				116.5
Total revenues of reportable segments		$	841.4			$	17,328.7			$	18,170.1
Segment profit (3)(4)(5)		$	143.3			$	206.2			$	349.5
SFAS 133 impact (3)		$	—			$	14.8			$	14.8
Maintenance capital		$	11.5			$	5.8			$	17.3
Nine Months Ended September 30, 2005
Revenues:
External Customers (includes buy/sell revenues of $125.8, $11,630.0, and $11,755.8 for Pipeline, GMT&S, and Total, respectively)		$	711.3			$	21,752.3			$	22,463.6
Intersegment(2)			99.8				0.7				100.5
Total revenues of reportable segments		$	811.1			$	21,753.0			$	22,564.1
Segment profit (3)(4)(5)		$	137.1			$	129.2			$	266.3
SFAS 133 impact (3)		$	—			$	(20.0	)		$	(20.0	)
Maintenance capital		$	8.2			$	4.0			$	12.2

		For the three months								For the nine months
		ended September 30,								ended September 30,
		2006				2005				2006				2005
Segment profit		$	137.2			$	104.9			$	349.5			$	266.3
Depreciation and amortization			(24.2	)			(20.0	)			(67.1	)			(58.1	)
Equity earnings in PAA/Vulcan Gas Storage, LLC			1.3				—				2.2				—
Interest expense			(19.2	)			(15.6	)			(52.5	)			(44.4	)
Interest income and other income (expense), net			0.3				(0.3	)			0.7				0.3
Income before cumulative effect of change in accounting principle		$	95.4			$	69.0			$	232.8			$	164.1

Note 13—Recent Accounting Pronouncements

     In December 2004, SFAS 123(R) was issued, which amends SFAS No. 123, “Accounting for Stock-Based Compensation,” and establishes accounting for transactions in which an entity exchanges its equity instruments for goods or services. This statement requires that the cost resulting from all share-based payment transactions be recognized in the financial statements at fair value. Following our general partner’s adoption of Emerging Issues Task Force Issue No. 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,” we are part of the same consolidated group and thus SFAS 123 (R) will be applicable to our general partner’s long-term incentive plan. We adopted SFAS 123(R) on January 1, 2006 under the modified prospective transition method, as defined in SFAS 123(R), and recognized a cumulative effect of change in accounting principle of approximately $6 million. The cumulative effect adjustment represents a decrease to our LTIP life-to-date accrued expense and related liability under our previous cash-plan, probability-based accounting model and adjusts our aggregate liability to the appropriate fair-value based liability as calculated under a SFAS 123(R) methodology. Our LTIPs are administered by our general partner. We are required to reimburse all costs incurred by our general partner through LTIP settlements. As a result, our LTIP awards are classified as liabilities under SFAS 123(R). Under the modified prospective transition method, we are not required to adjust our prior period financial statements for our LTIP awards.

     In September 2005, the Emerging Issues Task Force (“EITF”) 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 became effective in reporting periods beginning after March 15, 2006.

     We adopted EITF 04-13 on April 1, 2006. The adoption of EITF 04-13 resulted in inventory purchases and sales under buy/sell transactions, which historically would have been recorded gross as purchases and sales, to be treated as inventory exchanges in our consolidated statement of operations. In conformity with EITF 04-13, prior periods are not affected, although we have parenthetically disclosed prior period buy/sell transactions in our consolidated statements of operations. The treatment of buy/sell transactions under EITF 04-13 reduces both revenues and purchases on our income statement but does not impact our financial position, net income, or liquidity.

      In September 2006, the SEC staff issued Staff Accounting Bulletin (SAB) Topic 1N, Financial Statements - Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements (SAB 108). SAB 108 addresses how the effects of prior-year uncorrected misstatements should be considered when quantifying misstatements in current-year financial statements. SAB 108 requires registrants to quantify misstatements using both the balance sheet and income statement approaches and to evaluate whether either approach results in quantifying an error that is material in light of relevant quantitative and qualitative factors. The provisions of SAB 108 will be effective for the fiscal years ending after November 15, 2006. Upon adoption, we do not expect SAB 108 to have a material impact on our financial position or results of operations.

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.”

Highlights – Third Quarter and First Nine Months of 2006

     Net income for the third quarter of 2006 was approximately $95 million, or $0.89 per diluted limited partner unit, which is an increase of 38% and 13%, respectively, over net income of $69 million, or $0.79 per diluted limited partner unit for the third quarter of 2005. For the first nine months of 2006, net income was approximately $239 million, or $2.43 per diluted limited partner unit, representing increases of 46% and 17%, respectively, over net income of approximately $164 million, or $2.07 per limited partner unit, for the first nine months of 2005.

     Earnings per limited partner unit (both basic and diluted) was reduced by $0.16 and $0.13 for the three months ended and $0.31 and $0.12 for the nine months ended September 30, 2006 and 2005, respectively, attributable to 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 to our Consolidated Financial Statements.

     Key items impacting the first nine months of 2006 include:

     Balance Sheet and Capital Structure

	•		An issuance of $250 million senior notes due 2036 for net proceeds of approximately $249.5 million.
	•		The sale of 7.2 million limited partner units for net proceeds of approximately $316 million.
	•		The completion of six acquisitions for aggregate consideration of $567 million.
	•		An increase in 2006 planned capital expenditures for internal growth projects by $80 million to $310 million, of which approximately $214 million has been incurred.

     Income Statement

	•		Favorable execution of our risk management strategies around our gathering, marketing, terminalling and storage assets in a pronounced contango market with a high level of overall crude oil volatility.
	•		Increased volumes and related tariff revenues on our pipeline systems.
	•		The inclusion in the third quarter and first nine months of 2006 of an aggregate charge of approximately $10 million and $27 million, respectively, related to our Long-Term Incentive Plans.
	•		An increase in costs and expenses primarily associated with our continued growth from internal growth projects and acquisitions.

Acquisitions and Internal Growth Projects

     The following table summarizes our capital expenditures incurred in the periods indicated (in millions):

		Nine Months Ended
		September 30,
		2006				2005
Acquisition capital (1)		$	566.6			$	129.1
Investment in PAA/Vulcan Gas Storage, LLC			10.0				—
Internal growth projects			213.6				106.9
Maintenance capital			17.3				12.2
		$	807.5			$	248.2

     Acquisitions

     We completed six transactions during the first nine months of 2006 for aggregate consideration of approximately $567 million. During the third quarter, we completed the acquisition of (i) a 64.35% interest in the CAM Pipeline system for a total purchase price of approximately $54 million and (ii) three refined products pipeline systems from Chevron Pipe Line Company for approximately $65 million. See Note 3 to our Consolidated Financial Statements.

      In addition, in June 2006, we entered into a definitive agreement to purchase Pacific Energy for approximately $2.4 billion, including the assumption of debt and estimated transaction costs. The completion of the transaction remains subject to the approval of the unitholders of PAA and Pacific Energy. The unitholder meetings are scheduled for November 9, 2006. Assuming a favorable unitholder vote, we anticipate closing the transaction on November 15, 2006.

      In November 2006, we acquired a 50% interest in Settoon Towing, LLC (“Settoon Towing”) for approximately $33 million. Settoon Towing owns and operates a fleet of 57 transport and storage barges as well as 30 transport tugs. Its core business is the gathering and transportation of crude oil and produced water from inland production facilities across the Gulf Coast. We are currently Settoon’s largest customer with 22 tugs and 22 tank barges under a five year chartering agreement.

     Internal Growth Projects

     Capital expenditures for expansion projects are forecast to be approximately $310 million during calendar 2006 of which approximately $214 million was incurred in the first nine months. These projects include the construction and expansion of pipeline systems and crude oil and LPG storage facilities. Following are some of the more notable projects to be undertaken in 2006 and the estimated expenditures for the year (in millions):

Projects		2006
St. James, Louisiana storage facility — Phase I		$	72
St. James, Louisiana storage facility — Phase II			12
Kerrobert tankage			31
East Texas/Louisiana tankage			17
Spraberry System expansion			15
Cushing Tankage — Phase VI			14
High Prairie rail terminals			13
Midale/Regina truck terminal			13
Truck trailers			9
Wichita Falls tankage			8
Basin connection — Oklahoma			8
Mobile/Ten Mile tankage and metering			6
Other Projects			92
Total		$	310

     St. James Terminal. On October 10, 2006, we announced we are proceeding with the Phase II development of the St. James Terminal facility. The initial construction of the St. James Terminal, referred to as the Phase I development, commenced in mid-2005 and is

anticipated to become operational during the first quarter of 2007 at a total cost of approximately $93 million. Phase I consists of seven crude oil storage tanks with an aggregate shell capacity of approximately 3.5 million barrels along with the manifold and pumping system. Under the Phase II project, we will construct approximately 2.7 million barrels of additional tankage at the facility. The Phase II project will expand the total capacity of the facility to 6.2 million barrels and is expected to cost approximately $64 million. We estimate that the Phase II tankage will become operational during the first quarter of 2008.

     Cushing Terminal Expansion. On September 19, 2006, we announced our Phase VI expansion of our Cushing Terminal facility. Under the Phase VI expansion, we will construct approximately 3.4 million barrels of additional tankage at our crude oil storage and terminalling facility in Cushing, Oklahoma. The Phase VI project will expand the total capacity of the facility to 10.8 million barrels and, including manifold modifications, is expected to cost approximately $48 million. We anticipate spending approximately $14 million of the $48 million in 2006 and the remainder in 2007. We estimate that the new tankage will become operational during the fourth quarter of 2007. The expansion is supported by multi-year lease agreements with customers.

Results of Operations

     Analysis of Operating Segments

     We evaluate segment performance based on segment profit and maintenance capital. We define segment profit as revenues less (i) purchases and related costs, (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 useful life 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 operating capacity are charged to expense as incurred. See Note 12 to our Consolidated Financial Statements for a reconciliation of segment profit to consolidated income before cumulative effect of change in accounting principle.

     Pipeline Operations

     As of September 30, 2006, we owned approximately 16,000 miles of active gathering and mainline crude oil pipelines located throughout the United States and Canada (of which approximately 14,000 miles are included in our Pipeline segment). 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 costs of operating the pipeline. Segment profit from our pipeline capacity leases, barrel exchanges and buy/sell arrangements generally reflect a negotiated amount.

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

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2006				2005				2006				2005
		(in millions)								(in millions)
Operating Results (1)
Tariff activities		$	106.9			$	93.5			$	299.1			$	268.8
Pipeline margin activities (2)			174.6				209.8				542.3				542.3
Total pipeline operations revenues			281.5				303.3				841.4				811.1
Costs and Expenses
Pipeline margin activities purchases (3)			(167.8	)			(206.7	)			(522.0	)			(526.2	)
Field operating costs (excluding LTIP charge)			(47.2	)			(37.0	)			(137.1	)			(108.8	)
LTIP charge — operations			(0.4	)			(0.3	)			(1.0	)			(0.7	)
Segment G&A expenses (excluding LTIP charge) (4)			(9.8	)			(10.2	)			(27.1	)			(29.6	)
LTIP charge — general and administrative (4)			(4.1	)			(3.4	)			(10.9	)			(8.7	)
Segment profit		$	52.2			$	45.7			$	143.3			$	137.1
Maintenance capital		$	5.3			$	2.9			$	11.5			$	8.2
Average Daily Volumes (thousands of barrels per day) (5)
Tariff activities
All American			50				51				49				51
Basin			324				290				323				283
BOA/CAM			168				—				57				—
Capline			183				129				149				144
Cushing to Broome			69				79				73				62
North Dakota/Trenton			94				85				88				73
West Texas/New Mexico Area Systems (6)			416				428				445				422
Canada			249				250				247				255
Other			486				437				464				424
Total tariff activities			2,039				1,749				1,895				1,714
Pipeline margin activities			93				65				89				69
Total			2,132				1,814				1,984				1,783