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 March 31, 2007

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

333 Clay Street, Suite 1600, Houston, Texas 77002
(Address of principal executive offices) (Zip Code)

(713) 646-4100
(Registrant’s telephone number, including area code)

     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 May 1, 2007, there were outstanding 109,405,178 Common Units.

 

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

TABLE OF CONTENTS

		Page
PART I. FINANCIAL INFORMATION			3
Item 1. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS:			3
Consolidated Balance Sheets: March 31, 2007 and December 31, 2006			3
Consolidated Statements of Operations: For the three months ended March 31, 2007 and 2006			4
Consolidated Statements of Cash Flows: For the three months ended March 31, 2007 and 2006			5
Consolidated Statement of Partners’ Capital: For the three months ended March 31, 2007			6
Consolidated Statements of Comprehensive Income: For the three months ended March 31, 2007 and 2006			6
Consolidated Statement of Changes in Accumulated Other Comprehensive Income: For the three months ended March 31, 2007			6
Notes to the Consolidated Financial Statements			7
Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			23
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			37
Item 4. CONTROLS AND PROCEDURES			38
PART II. OTHER INFORMATION			39
Item 1. LEGAL PROCEEDINGS			39
Item 1A. RISK FACTORS			39
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			39
Item 3. DEFAULTS UPON SENIOR SECURITIES			39
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS			39
Item 5. OTHER INFORMATION			39
Item 6. EXHIBITS			40
SIGNATURES			43
Form of LTIP Grant Letters
Certification of PEO Pursuant to Rule 13a-14(a)
Certification of PFO Pursuant to Rule 13a-14(a)
Certification of PEO Pursuant to Section 1350
Certification of PFO Pursuant to Section 1350

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)

		March 31,				December 31,
		2007				2006
		(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	16.6			$	11.3
Trade accounts receivable and other receivables, net			1,665.3				1,725.4
Inventory			968.2				1,290.0
Other current assets			159.4				130.9
Total current assets			2,809.5				3,157.6
PROPERTY AND EQUIPMENT			4,343.5				4,190.1
Accumulated depreciation			(384.8	)			(348.1	)
			3,958.7				3,842.0
OTHER ASSETS
Pipeline linefill in owned assets			271.0				265.5
Inventory in third-party assets			76.0				75.7
Investment in unconsolidated entities			195.7				183.0
Goodwill			1,035.1				1,026.2
Other, net			167.0				164.9
Total assets		$	8,513.0			$	8,714.9
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES
Accounts payable and accrued liabilities		$	1,723.3			$	1,846.6
Short-term debt			900.9				1,001.2
Other current liabilities			226.4				176.9
Total current liabilities			2,850.6				3,024.7
LONG-TERM LIABILITIES
Long-term debt under credit facilities and other			3.0				3.1
Senior notes, net of unamortized net discount of $1.9 and $1.8, respectively			2,623.1				2,623.2
Other long-term liabilities and deferred credits			92.7				87.1
Total long-term liabilities			2,718.8				2,713.4
COMMITMENTS AND CONTINGENCIES (NOTE 12)
PARTNERS’ CAPITAL
Common unitholders (109,405,178 units outstanding at March 31, 2007 and December 31, 2006)			2,873.5				2,906.1
General partner			70.1				70.7
Total partners’ capital			2,943.6				2,976.8
Total liabilities and partners’ capital		$	8,513.0			$	8,714.9

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
		March 31,
		2007				2006
		(unaudited)
REVENUES
Crude oil, refined products and LPG sales and related revenues (includes buy/sell transactions of $4,761.9 in the first quarter of 2006)		$	4,116.7			$	8,575.3
Pipeline tariff activities revenues			86.7				57.4
Other revenues			26.1				2.4
Total revenues			4,229.5				8,635.1
COSTS AND EXPENSES
Crude oil, refined products and LPG purchases and related costs (includes buy/sell transactions of $4,795.1 in the first quarter of 2006)			3,899.6				8,424.5
Field operating costs			125.7				85.2
General and administrative expenses			46.8				31.8
Depreciation and amortization			39.9				21.6
Total costs and expenses			4,112.0				8,563.1
OPERATING INCOME			117.5				72.0
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities			3.6				0.1
Interest expense (net of capitalized interest of $2.8 and $0.6)			(41.1	)			(15.3	)
Interest income and other income (expense), net			4.8				0.3
Income tax expense			(0.1	)			—
Income before cumulative effect of change in accounting principle			84.7				57.1
Cumulative effect of change in accounting principle			—				6.3
NET INCOME		$	84.7			$	63.4
NET INCOME-LIMITED PARTNERS		$	67.9			$	56.7
NET INCOME-GENERAL PARTNER		$	16.8			$	6.7
BASIC NET INCOME PER LIMITED PARTNER UNIT
Income before cumulative effect of change in accounting principle		$	0.62			$	0.65
Cumulative effect of change in accounting principle			—				0.08
Net income		$	0.62			$	0.73
DILUTED NET INCOME PER LIMITED PARTNER UNIT
Income before cumulative effect of change in accounting principle		$	0.61			$	0.63
Cumulative effect of change in accounting principle			—				0.08
Net income		$	0.61			$	0.71
BASIC WEIGHTED AVERAGE UNITS OUTSTANDING			109.4				74.0
DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING			110.7				75.7

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)

		Three Months Ended
		March 31,
		2007				2006
		(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income		$	84.7			$	63.4
Adjustments to reconcile to cash flows from operating activities:
Depreciation and amortization			39.9				21.6
Cumulative effect of change in accounting principle			—				(6.3	)
SFAS 133 mark-to-market adjustment			17.0				0.7
Inventory valuation adjustment			1.0				—
Gain on sale of investment assets			(3.9	)			—
Long-Term Incentive Plan charge			18.6				10.6
Noncash amortization of terminated interest rate hedging instruments			0.2				0.4
(Gain)/loss on foreign currency revaluation			(0.2	)			0.9
Equity earnings in unconsolidated entities			(3.6	)			(0.1	)
Changes in assets and liabilities, net of acquisitions:
Trade accounts receivable and other			60.7				(430.9	)
Inventory			323.3				(116.0	)
Accounts payable and other liabilities			(173.1	)			(3.2	)
Due to related parties			7.1				1.3
Net cash provided by (used in) operating activities			371.7				(457.6	)
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions (Note 3)			(17.3	)			(17.5	)
Additions to property and equipment			(134.1	)			(62.7	)
Investment in unconsolidated entities			(9.1	)			—
Cash paid for linefill in assets owned			(4.5	)			(4.3	)
Proceeds from sales of assets			4.3				0.2
Net cash used in investing activities			(160.7	)			(84.3	)
CASH FLOWS FROM FINANCING ACTIVITIES
Net repayments on working capital revolving credit facility			(69.9	)			(5.1	)
Net borrowings/(repayments) on short-term letter of credit and hedged inventory facility			(32.1	)			503.4
Net proceeds from the issuance of common units (Note 7)			—				101.4
Distributions paid to unitholders and general partner (Note 7)			(104.6	)			(57.3	)
Other financing activities			(0.2	)			(0.9	)
Net cash provided by (used in) financing activities			(206.8	)			541.5
Effect of translation adjustment on cash			1.1				0.1
Net increase (decrease) in cash and cash equivalents			5.3				(0.3	)
Cash and cash equivalents, beginning of period			11.3				9.6
Cash and cash equivalents, end of period		$	16.6			$	9.3
Cash paid for interest, net of amounts capitalized		$	26.3			$	17.5
Cash paid for income taxes		$	1.6			$	—

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, 2006			109.4			$	2,906.1			$	70.7			$	2,976.8
Net income			—				67.9				16.8			$	84.7
Distributions			—				(87.5	)			(17.1	)		$	(104.6	)
Other comprehensive income			—				(13.0	)			(0.3	)		$	(13.3	)
Balance at March 31, 2007			109.4			$	2,873.5			$	70.1			$	2,943.6

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

		Three Months Ended
		March 31,
		2007				2006
		(unaudited)
Net income		$	84.7			$	63.4
Other comprehensive income/(loss)			(13.3	)			0.5
Comprehensive income		$	71.4			$	63.9

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, 2006		$	(19.8	)		$	69.5			$	49.7
Reclassification adjustments for settled contracts			(23.5	)			—				(23.5	)
Changes in fair value of outstanding hedge positions			4.6				—				4.6
Currency translation adjustment			—				5.6				5.6
Total period activity			(18.9	)			5.6				(13.3	)
Balance at March 31, 2007		$	(38.7	)		$	75.1			$	36.4

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. is a Delaware limited partnership formed in September 1998. Our operations are conducted directly and indirectly through our primary operating subsidiaries. As used in this Form 10-Q, the terms “Partnership,” “Plains,” “we,” “us,” “our,” “ours” and similar terms refer to Plains All American Pipeline, L.P. and its subsidiaries, unless the context indicates otherwise.

     We are engaged in the transportation, storage, terminalling and marketing of crude oil, refined products and 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.” Through our 50% equity ownership in PAA/Vulcan Gas Storage, LLC (“PAA/Vulcan”), we develop and operate natural gas storage facilities.

     Our 2% general partner interest is held by Plains AAP, L.P., a Delaware limited partnership. Plains All American GP LLC, a Delaware limited liability company, is Plains AAP, L.P.’s general partner. Plains All American GP LLC manages our operations and activities and employs our domestic officers and personnel. Our Canadian officers and employees are employed by our subsidiary PMC (Nova Scotia) Company, the general partner of Plains Marketing Canada, L.P. Unless the context otherwise requires, we use the term “general partner” to refer to both Plains AAP, L.P. and Plains All American GP LLC. Plains AAP, L.P. and Plains All American GP LLC are essentially held by seven owners with interests ranging from 54.3% to 1.2%.

     The consolidated interim financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our 2006 Annual Report on Form 10-K. The accompanying financial statements and related notes present (i) our consolidated financial position as of March 31, 2007 and December 31, 2006, (ii) the results of our consolidated operations for the three months ended March 31, 2007 and 2006, (iii) our consolidated cash flows for the three months ended March 31, 2007 and 2006, (iv) our consolidated changes in partners’ capital for the three months ended March 31, 2007, (v) our consolidated comprehensive income for the three months ended March 31, 2007 and 2006, and (vi) our changes in consolidated accumulated other comprehensive income for the three months ended March 31, 2007. The financial statements have been prepared in accordance with the instructions for interim reporting as prescribed by the Securities and Exchange Commission. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods have been reflected. All significant intercompany transactions have been eliminated. Certain reclassifications are made to prior periods to conform to current period presentation. The results of operations for the three months ended March 31, 2007 should not be taken as indicative of the results to be expected for the full year.

     The accompanying consolidated financial statements of PAA include PAA and all of its subsidiaries, which are wholly owned. Investments in 50% or less owned entities over which we have significant influence but not control are accounted for by the equity method. During the first quarter of 2007 we made an additional contribution of approximately $9 million to PAA/Vulcan. We evaluate our equity investments for impairment in accordance with Accounting Principles Board (“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.

Note 2—Trade Accounts Receivable

     Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of LPG. The majority of our accounts receivable relate to our marketing activities, which can generally be described as high volume and low margin activities, in many cases involving exchanges of crude oil volumes. We make a determination of the amount, if any, of the line of credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of standby letters of credit, advance cash payments or “parental” guarantees. At March 31, 2007 and December 31, 2006, we had received approximately $16.8 million and $28.3 million, respectively, of advance cash payments and prepayments from third parties to mitigate credit risk. In addition, we enter into netting arrangements with our counterparties. These arrangements cover a significant part of our transactions and also serve to mitigate credit risk.

     We review all outstanding accounts receivable balances on a monthly basis and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. At March 31, 2007 and December 31, 2006, substantially all of our net accounts receivable classified as current were less than 60 days past their scheduled invoice date. Although we consider our allowance for doubtful trade accounts receivable to be adequate, there is no assurance that actual amounts will not vary significantly from estimated amounts. Our allowance for doubtful accounts balance was $0.7 million at March 31, 2007 and at December 31, 2006.

Note 3—Acquisitions

     During the first quarter of 2007, we acquired (i) certain commercial refined products supply and marketing businesses (which is reflected in our marketing segment) for approximately $8 million in cash (including approximately $7 million of goodwill) and (ii) a trucking business (which is reflected in our transportation segment) for approximately $9 million in cash (including approximately $4 million of goodwill). Also, during the first quarter of 2007, we signed an agreement to acquire the Bumstead LPG storage facility located near Phoenix, Arizona for approximately $52 million. The acquisition is expected to close early in the second half of 2007 and will be reflected in our facilities segment.

Note 4—Inventory and Linefill

     Inventory primarily consists of crude oil, refined products and LPG in pipelines, storage tanks and rail cars that is valued at the lower of cost or market, with cost determined using an average cost method. Linefill and minimum working inventory requirements in assets we own are recorded at historical cost and consist of crude oil and LPG used to pack the pipeline 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.

     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 inventory in third party assets not expected to be liquidated within the succeeding twelve months out of “Inventory,” at average cost, and into “Inventory in third-party assets” (a long-term asset), which is reflected as a separate line item within other assets on the consolidated balance sheet.

     At March 31, 2007 and December 31, 2006, inventory and linefill consisted of :

		March 31, 2007												December 31, 2006
										Dollar/												Dollar/
		Barrels				Dollars				barrel				Barrels				Dollars				barrel
		(Barrels in thousands and dollars in millions)
Inventory (1)
Crude oil			15,470			$	871.0			$	56.30				18,331			$	1,029.1			$	56.14
LPG			1,919				81.9			$	42.68				5,818				250.7			$	43.09
Refined products			84				6.1			$	72.62				81				3.8			$	46.91
Parts and supplies			N/A				9.2				N/A				N/A				6.4				N/A
Inventory subtotal			17,473				968.2								24,230				1,290.0
Inventory in third-party assets
Crude oil			1,241				63.0			$	50.77				1,212				62.5			$	51.57
LPG			318				13.0			$	40.88				318				13.2			$	41.51
Inventory in third-party assets subtotal			1,559				76.0								1,530				75.7
Pipeline linefill in owned assets
Crude oil			7,867				269.0			$	34.19				7,831				264.4			$	33.76
LPG			53				2.0			$	37.74				31				1.1			$	35.48
Pipeline linefill in owned assets subtotal			7,920				271.0								7,862				265.5
Total			26,952			$	1,315.2								33,622			$	1,631.2

Note 5—Debt

     Below is a description of our debt as of March 31, 2007:

		March 31,				December 31,
		2007				2006
		(in millions)
Short-term debt:
Senior secured hedged inventory facility bearing interest at a rate of 5.8% and 5.8% at March 31, 2007 and December 31, 2006, respectively		$	803.2			$	835.3
Working capital borrowings, bearing interest at a rate of 6.0% and 5.9% at March 31, 2007 and December 31, 2006, respectively (1)			90.2				158.2
Other			7.5				7.7
Total short-term debt			900.9				1,001.2
Long-term debt:
4.75% senior notes due August 2009, net of unamortized discount of $0.4 million and $0.4 million at March 31, 2007 and December 31, 2006, respectively			174.6				174.6
7.75% senior notes due October 2012, net of unamortized discount of $0.2 million and $0.2 million at March 31, 2007 and December 31, 2006, respectively			199.8				199.8
5.63% senior notes due December 2013, net of unamortized discount of $0.4 million and $0.5 million at March 31, 2007 and December 31, 2006, respectively			249.6				249.5
7.13% senior notes due June 2014, net of unamortized premium of $8.4 million and $8.8 million at March 31, 2007 and December 31, 2006, respectively			258.4				258.8
5.25% senior notes due June 2015, net of unamortized discount of $0.6 million and $0.6 million at March 31, 2007 and December 31, 2006, respectively			149.4				149.4
6.25% senior notes due September 2015, net of unamortized discount of $0.8 million and $0.8 million at March 31, 2007 and December 31, 2006, respectively			174.2				174.2
5.88% senior notes due August 2016, net of unamortized discount of $0.9 million and $0.9 million at March 31, 2007 and December 31, 2006, respectively			174.1				174.1
6.13% senior notes due January 2017, net of unamortized discount of $1.7 million and $1.8 million at March 31, 2007 and December 31, 2006, respectively			398.3				398.2
6.70% senior notes due May 2036, net of unamortized discount of $0.4 million and $0.4 million at March 31, 2007 and December 31, 2006, respectively			249.6				249.6
6.65% senior notes due January 2037, net of unamortized discount of $4.9 million and $5.0 million at March 31, 2007 and December 31, 2006, respectively			595.1				595.0
Senior notes, net of unamortized discount (2)			2,623.1				2,623.2
Long-term debt under credit facilities and other			3.0				3.1
Total long-term debt (1)(2)			2,626.1				2,626.3
Total debt		$	3,527.0			$	3,627.5

     Letters of Credit. In connection with our crude oil marketing business and as is customary in our industry, we provide certain suppliers and transporters with irrevocable standby letters of credit to secure our obligation for the purchase of crude oil. These letters of credit are issued under our credit facility, and 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 March 31, 2007, approximately $120.0 million of letters of credit under our credit facility were outstanding.

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 Financial Accounting Standards Board (“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 (or partnership distributions to unitholders). 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 (as if distributed) to our general partner, even though we make cash distributions on the basis of cash available for distributions, not earnings, in any given accounting period. In accounting periods where aggregate net income does not exceed our aggregate distributions for such period, EITF 03-06 does not have any impact on our earnings per unit calculation.

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

		Three Months Ended
		March 31,
		2007				2006
Numerator:
Net income		$	84.7			$	63.4
Less: General partner’s incentive distribution paid			(15.3	)			(5.5	)
Subtotal			69.4				57.9
Less: General partner 2% ownership			(1.5	)			(1.2	)
Net income available to limited partners			67.9				56.7
Less: EITF 03-06 additional general partner’s distribution			—				(2.9	)
Net income available to limited partners under EITF 03-06		$	67.9			$	53.8
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		$	67.9			$	47.6
Denominator:
Basic earnings per limited partner unit (weighted average number of limited partner units outstanding)			109.4				74.0
Effect of dilutive securities:
LTIP units outstanding (1)			1.3				1.7
Diluted earnings per limited partner unit (weighted average number of limited partner units outstanding)			110.7				75.7
Basic net income per limited partner unit before cumulative effect of change in accounting principle		$	0.62			$	0.65
Cumulative effect of change in accounting principle per limited partner unit			—				0.08
Basic net income per limited partner unit		$	0.62			$	0.73
Diluted net income per limited partner unit before cumulative effect of change in accounting principle		$	0.61			$	0.63
Cumulative effect of change in accounting principle per limited partner unit			—				0.08
Diluted net income per limited partner unit		$	0.61			$	0.71

Note 7—Partners’ Capital and Distributions

     On April 17, 2007, we declared a cash distribution of $0.8125 per unit on our outstanding common units. The distribution is payable on May 15, 2007, to unitholders of record on May 4, 2007, for the period January 1, 2007 through March 31, 2007. The total distribution to be paid is approximately $107.4 million, with approximately $88.9 million to be paid to our common unitholders and approximately $1.8 million and $16.7 million to be paid to our general partner for its general partner and incentive distribution interests, respectively.

     On January 16, 2007, we declared a cash distribution of $0.80 per unit on our outstanding common units. The distribution was paid on February 14, 2007 to unitholders of record on February 2, 2007, for the period October 1, 2006 through December 31, 2006. The total distribution paid was approximately $104.6 million, with approximately $87.5 million paid to our common unitholders and $1.8 million and $15.3 million paid to our general partner for its general partner and incentive distribution interests, respectively.

     Upon closing of the acquisition of Pacific Energy Partners L.P. (“Pacific”) in November 2006, our general partner agreed to reduce the amount of its incentive distributions as follows: (i) $5 million per quarter for the first four quarters, (ii) $3.75 million per quarter for the next eight quarters, (iii) $2.5 million per quarter for the next four quarters, and (iv) $1.25 million per quarter for the final four quarters. Pursuant to this agreement, the first quarterly reduction of $5 million occurred with the incentive distribution paid to the general partner on February 14, 2007. The incentive distribution to be paid in May 2007 also reflects a reduction of $5 million. The total reduction in incentive distributions will be $65 million.

Note 8—Long-Term Incentive Plans

     Our general partner has adopted the Plains All American GP LLC 1998 Long-Term Incentive Plan, the 2005 Long-Term Incentive Plan and the PPX Successor Long-Term Incentive Plan for employees and directors and the Plains All American GP LLC 2006 Long-Term Incentive Tracking Unit Plan for non-officer employees, collectively referred to as Long-Term Incentive Plans (“LTIP”). The 1998 Plan, 2005 Plan and PPX Successor Plan authorize the grant of an aggregate of 5.4 million common units deliverable upon vesting. Although other types of awards are contemplated under the plans, currently outstanding awards are limited to “phantom” units, which mature into the right to receive common units (or cash equivalent) upon vesting. Some awards also include distribution equivalent rights (“DERs”). Subject to applicable vesting criteria, a DER entitles the grantee to a cash payment equal to cash distributions paid on an outstanding common unit prior to the vesting date of the underlying award. The 2006 Plan authorizes the grant of approximately 1.4 million “tracking units” which, upon vesting, represent the right to receive a cash payment in an amount based upon the market value of a Common Unit at the time of vesting. Our general partner is entitled to reimbursement by us for any costs incurred in settling obligations under the plans.

     We adopted SFAS 123(R) on January 1, 2006. 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 estimated to occur 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 recognized as compensation expense over the period the awards are earned. For awards with performance conditions, we recognize LTIP compensation expense only if the achievement of the performance condition is considered probable. When awards with performance conditions that were previously considered improbable of occurring become probable of occurring, we incur additional LTIP compensation expense necessary to adjust the life-to-date accrued liability associated with these awards. In addition, we recognize compensation expense for DER payments in the period the payment is earned.

     As of March 31, 2007, there were outstanding awards of approximately 4.4 million phantom units and tracking units with a weighted average grant-date fair value of approximately $36.92 per unit. Our LTIP awards typically contain performance conditions relative to our annualized distribution level and vest upon the latter of a certain date or upon the attainment of a certain annualized distribution level. Upon our February 2007 annualized distribution of $3.20, approximately 2.2 million of our outstanding awards satisfied all performance conditions necessary for vesting and will vest in various increments over the next 5 years. Approximately 0.7 million of these awards will vest in May 2007. Approximately 2.2 million of our remaining outstanding awards have performance conditions requiring the attainment of an annualized distribution of between $3.50 and $4.00, which is not yet considered probable of occurring. Provided the performance conditions associated with these awards are ultimately attained, these awards will vest in various increments between 2010 and 2014. However, subject to continued employment, approximately 0.4 million of these awards still outstanding in 2012 will vest regardless of whether or not the performance condition is attained. Approximately 3.0 million of our outstanding awards include DERs, of which 1.6 million are currently vested. Our DER awards typically contain performance conditions relative to our annualized distribution level and vest upon the earlier of a certain date or a certain annualized distribution level. The DERs terminate with the vesting or forfeiture of the underlying award.

     Our LTIP activity is summarized in the following table (in millions except weighted average grant date fair values per unit):

						Weighted
						Average
						Grant Date
		Units				Fair Value per unit
Outstanding at December 31, 2006			3.0			$	31.94
Granted			1.4			$	47.42
Vested			—			$	—
Cancelled or forfeited			—			$	—
Outstanding at March 31, 2007			4.4			$	36.92

     We recognized expense related to our LTIP of approximately $19 million and $10 million during the first quarter of 2007 and 2006, respectively. Approximately $8.4 million of the charge for the first quarter of 2007 is associated with the Partnership’s unit price increasing from $51.20 at December 31, 2006 to $57.61 at March 31, 2007. As of March 31, 2007, we have an accrued liability of approximately $74.8 million associated with our LTIP. Cash payments associated with LTIP vestings were approximately $1 million in the first quarter of 2006. There were no material payments in the first quarter of 2007. Cash payments associated with DER awards were approximately $1 million and $1 million in the first quarter of 2007 and 2006, respectively. No units were issued during the first quarter of 2007 in connection with the settlement of vested awards.

     As of March 31, 2007, the weighted average remaining contractual life of our outstanding awards (that are currently considered probable of vesting) was approximately 2.5 years based on expected vesting dates. Based on the March 31, 2007 fair value measurement and probability assessment regarding future distributions, we expect to recognize an additional $65 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 of $57.61 at March 31, 2007. 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 as shown below (in millions):

		LTIP
		Fair Value
Year		Amortization(1)
2007 (2)		$	19.4
2008			20.3
2009			14.1
2010			5.9
2011			2.7
2012			2.4
Total		$	64.8

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 commodity 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, and NYMEX, ICE and over-the-counter positions, as well as physical volumes, grades, locations and delivery schedules to help 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 or the fair value of hedged items.

     Summary of Financial Impact

     The majority of our derivative activity is related to our commodity price-risk hedging activities. Through these activities, we hedge our exposure to price fluctuations with respect to crude oil, refined products, LPG and natural gas as well as with respect to expected purchases, sales and transportation of these commodities. 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 (“AOCI”) 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.

     The derivative instruments we use consist primarily of futures and options contracts traded on the NYMEX, the ICE and over-the-counter, including commodity swap and option contracts entered into with financial institutions and other energy companies.

     A summary of the earnings impact of all derivative activities, including the change in fair value of open derivatives and settled derivatives taken to earnings during the first quarter of 2007 and the first quarter of 2006, is as follows (in millions, losses designated in brackets):

		For the Three Months Ended												For the Three Months Ended
		March 31, 2007												March 31, 2006
		Mark-to-												Mark-to-
		market, net				Settled				Total				market, net				Settled				Total
Commodity price-risk hedging		$	(19.1	)		$	69.8			$	50.7			$	(0.7	)		$	6.2			$	5.5
Controlled trading program			—				0.1				0.1				—				—				—
Interest rate risk hedging			—				(0.2	)			(0.2	)			—				(0.4	)			(0.4	)
Currency exchange rate risk hedging			2.1				(1.0	)			1.1				—				0.6				0.6
Total		$	(17.0	)		$	68.7			$	51.7			$	(0.7	)		$	6.4			$	5.7

     The breakdown of the net mark-to-market impact to earnings between derivatives that do not qualify for hedge accounting and the ineffective portion of cash flow hedges is as follows (in millions, losses designated in brackets):

		For the Three Months Ended
		March 31,				March 31,
		2007				2006
Derivatives that do not qualify for hedge accounting		$	(16.5	)		$	(0.8	)
Ineffective portion of cash flow hedges			(0.5	)			0.1
Total		$	(17.0	)		$	(0.7	)

     Derivatives that do not qualify for hedge accounting consist of (i) derivatives that are an effective element of our risk management strategy but are not consistently effective to qualify for hedge accounting pursuant to SFAS 133 and (ii) derivatives associated with our storage assets as these contracts will not necessarily result in physical delivery.

     The following table summarizes the net assets and liabilities on our consolidated balance sheet that are related to the fair value of our open derivative positions (in millions):

		March 31,				December 31,
		2007				2006
Other current assets		$	89.2			$	55.2
Other long-term assets			6.4				9.0
Other current liabilities			(143.6	)			(77.3	)
Other long-term liabilities and deferred credits			(22.6	)			(21.4	)
Net asset (liability)		$	(70.6	)		$	(34.5	)

     The net liability related to the fair value of our open derivative positions consists of cumulative unrealized gains/losses recognized in earnings and cumulative unrealized gains/losses deferred to AOCI as follows, by category (in millions, losses designated in brackets):

		March 31, 2007												December 31, 2006
		Net asset												Net asset
		(liability)				Earnings				AOCI				(liability)				Earnings				AOCI
Commodity price-risk hedging		$	(70.7	)		$	(38.0	)		$	(32.7	)		$	(32.5	)		$	(18.9	)		$	(13.6	)
Controlled trading program			—				—				—				—				—				—
Interest rate risk hedging			—				—				—				—				—				—
Currency exchange rate risk hedging			0.1				0.1				—				(2.0	)			(2.0	)			—
		$	(70.6	)		$	(37.9	)		$	(32.7	)		$	(34.5	)		$	(20.9	)		$	(13.6	)

     In addition to the $32.7 million of unrealized losses deferred to AOCI for open derivative positions, AOCI also includes a deferred loss of approximately $6.1 million that relates to terminated interest rate swaps that were cash settled in connection with the refinancing of debt agreements over the past five years. The deferred loss related to these instruments is being amortized to interest expense over the original terms of the terminated instruments.

     The total amount of deferred net losses recorded in AOCI is 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 AOCI at March 31, 2007, a net loss of $32.4 million will be reclassified into earnings in the next twelve months; the remaining net loss will be reclassified at various intervals (ending in 2016 for amounts related to our terminated interest rate swaps and 2008 for amounts related to our commodity price-risk hedging). Because a portion of these amounts is based on market prices at the current period end, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions. During the three months ended March 31, 2007 no amounts were reclassified to earnings from AOCI in connection with forecasted transactions that were no longer considered probable of occurring.

Note 10—Related Party Transactions

     Crude Oil Purchases and Hedges. Until August 12, 2005, Vulcan Energy owned 100% of Calumet Florida L.L.C. (“Calumet”). Calumet is now owned by Vulcan Resources Florida, Inc., the majority of which is owned by Paul G. Allen. We purchased crude oil from Calumet for approximately $11.3 million and $11.3 million in the first quarter of 2007 and 2006, respectively. Calumet may request from time to time that we provide fixed pricing or a range of pricing for a portion of its production. When we offer such an arrangement, we protect our position by placing hedges on equivalent amounts, and charge Calumet a fee of $0.20 per barrel.

     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”). 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 2008, 2009 and 2010. We recorded deferred revenue for receipt of a one-time fee of approximately $1 million for our services to own and manage the hedge positions and to deliver the natural gas.

Note 11—Income Taxes

     Our U.S. and Canadian subsidiaries are not taxable entities in the U.S. and are not subject to U.S. federal or state income taxes as the tax effect of operations is passed through to our unitholders. However, certain of our Canadian subsidiaries are taxable entities in Canada and are subject to Canadian federal and provincial income taxes.

     We adopted the provisions of FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes” (“FIN 48”), an interpretation of SFAS No. 109 on January 1, 2007. As a result of the implementation of FIN 48, we recognized no material adjustment in the liability for unrecognized income tax benefits and at March 31, 2007, we have no material adjustments for unrecognized tax benefits.

     We recognize interest and penalties related to uncertain tax positions in income tax expense. As of March 31, 2007, we have no material adjustments for accrued interest related to uncertain tax positions.

     We file income tax returns in the Canadian federal and various provincial jurisdictions. Generally, we are no longer subject to Canadian federal and provincial income tax examinations for years before 2004.

Note 12—Commitments and Contingencies

Litigation

     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, the U.S. Environmental Protection Agency (the “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 $3.0 million to $3.5 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 (the “DOJ”) 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 the DOJ; however, we have no indication from EPA or the DOJ 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.

     On November 15, 2006, we completed the acquisition of Pacific. The following is a summary of the more significant matters that relate to Pacific, its assets or operations.

     The People of the State of California v. Pacific Pipeline System, LLC (“PPS”). In March 2005, a release of approximately 3,400 barrels of crude oil occurred on Line 63, subsequently acquired by us in the Pacific merger. The release occurred when Line 63 was severed as a result of a landslide caused by heavy rainfall in the Pyramid Lake area of Los Angeles County. Total projected emergency response, remediation and restoration costs are approximately $26 million, substantially all of which had been incurred as of March 31, 2007. We expect to incur the remaining costs before the end of 2007. We anticipate that the majority of costs associated with this release will be covered under a pre-existing PPS pollution liability insurance policy.

     In March 2006, PPS, a subsidiary acquired in the Pacific merger, was served with a four count misdemeanor criminal action in the Los Angeles Superior Court Case No. 6NW01020, which alleges the violation by PPS of two strict liability statutes under the California Fish and Game Code for the unlawful deposit of oil or substances harmful to wildlife into the environment, and violations of two sections of the California Water Code for the willful and intentional discharge of pollution into state waters. The fines that can be assessed against PPS for the violations of the strict liability statutes are based, in large measure, on the volume of unrecovered crude oil that was released into the environment, and, therefore, the maximum state fine, if any, that can be assessed is estimated to be approximately $1,100,000 in the aggregate. This amount is subject to a downward adjustment with respect to actual volumes of recovered crude oil, and the State of California has the discretion to further reduce the fine, if any, after considering other mitigating factors. Because of the uncertainty associated with these factors, the final amount of the fine that will be assessed for the strict liability offenses cannot be ascertained. We will defend against these charges. In addition to these fines, the State of California has indicated that it may seek to recover approximately $150,000 in natural resource damages against PPS in connection with this matter. The mitigating factors may also serve as a basis for a downward adjustment of the natural resource damages amount. We believe that certain of the alleged violations are without merit and intend to defend against them, and that mitigating factors should apply.

     The EPA has referred this matter to the DOJ for the initiation of proceedings to assess civil penalties against PPS. We understand that the maximum permissible penalty, if any, that the EPA could assess under relevant statutes would be approximately $3.7 million. We believe that several mitigating circumstances and factors exist that could substantially reduce any penalty that might be imposed by the EPA, and intend to pursue discussions with the EPA regarding such mitigating circumstances and factors. Because of the uncertainty associated with these factors, the final amount of the penalty that will be assessed by the EPA cannot be ascertained. Discussions with the DOJ to resolve this matter have commenced.

     Kosseff v. Pacific Energy, et al, case no. BC 3544016. On June 15, 2006, a lawsuit was filed in the Superior Court of California, County of Los Angeles, in which the plaintiff alleged that he was a unitholder of Pacific and he sought to represent a class comprising all of Pacific’s unitholders. The complaint named as defendants Pacific and certain of the officers and directors of Pacific’s general partner, and asserted claims of self-dealing and breach of fiduciary duty in connection with the pending merger with us and related transactions. The plaintiff sought injunctive relief against completing the merger or, if the merger was completed, rescission of the merger, other equitable relief, and recovery of the plaintiff’s costs and attorneys’ fees. On September 14, 2006, Pacific and the other defendants entered into a memorandum of settlement with the plaintiff to settle the lawsuit. As part of the settlement, Pacific and the other defendants deny all allegations of wrongdoing and express willingness to settle the lawsuit solely because the settlement would eliminate the burden and expense of further litigation. The settlement is subject to customary conditions, including court approval. As part of the settlement, we (as successor to Pacific) will pay approximately $0.5 million to the plaintiff’s counsel for their fees and expenses, and incur the cost of mailing materials to former Pacific unitholders. The court has preliminarily approved the settlement and a notice of settlement has been sent to the class members. If finally approved by the court, the settlement will resolve all claims that were or could have been brought on behalf of the proposed settlement class in the actions being settled, including all claims relating to the merger, the merger agreement and any disclosure made by Pacific in connection with the merger. The settlement did not change any of the terms or conditions of the merger.

     Pacific Atlantic Terminals. In connection with the Pacific merger, we acquired Pacific Atlantic Terminals LLC (“PAT”), which is now one of our subsidiaries. PAT owns crude oil and refined products terminals in northern California and in the Philadelphia metropolitan area. In the process of integrating PAT’s assets into our operations, we identified certain aspects of the operations at the California terminals that appeared to be out of compliance with specifications under the relevant air quality permit. We conducted a prompt review of the circumstances and self-reported the apparent historical occurrences of non-compliance to the Bay Area Air Quality Management District. We are cooperating with the District’s review of these matters.

     Other Pacific-Legacy Matters. Pacific had completed a number of acquisitions that had not been fully integrated prior to the merger with Plains. Accordingly, we have and may become aware of other matters involving the assets and operations acquired in the Pacific merger as they relate to compliance with environmental and safety regulations, which matters may result in the imposition of fines and penalties. For example, we have been informed by the EPA that terminals owned by Rocky Mountain Pipeline Systems LLC, one of the subsidiaries acquired in the Pacific merger, are purportedly out of compliance with certain regulatory documentation requirements.

     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.

     Environmental. We have in the past experienced and in the future likely will experience releases of crude oil into the environment from our pipeline and storage operations. We also may discover environmental impacts from 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 experienced such an increase in connection with the Pacific acquisition, which added approximately 5,000 miles of pipeline to our operations, and in connection with the 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. See “— Pipeline Releases” above.

     At March 31, 2007, our reserve for environmental liabilities totaled approximately $36.6 million. At March 31, 2007, we have recorded receivables totaling approximately $9.7 million for amounts which are probable of recovery 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.

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

Note 13—Operating Segments

     In the fourth quarter of 2006, we revised the manner in which we internally evaluate our segment performance and decide how to allocate resources to our segments. Prior period disclosures have been revised to reflect our change in segments. Our operations are conducted through three operating segments: (i) Transportation, (ii) Facilities and (iii) Marketing. We evaluate segment performance based on segment profit and maintenance capital. We define segment profit as revenues and equity in earnings of unconsolidated entities 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 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 operating capacity are charged to expense as incurred. The following tables reflect certain financial data for each segment for the periods indicated:

		Transportation				Facilities				Marketing				Total
Three Months Ended March 31, 2007
Revenues:
External Customers		$	102.0			$	25.6			$	4,101.9			$	4,229.5
Intersegment (2)			76.2				19.5				7.7				103.4
Total revenues of reportable segments		$	178.2			$	45.1			$	4,109.6			$	4,332.9
Equity earnings in unconsolidated entities		$	0.9			$	2.7			$	—			$	3.6
Segment profit (1)(3)(4)		$	73.1			$	21.9			$	66.0			$	161.0
SFAS 133 impact (1)		$	—			$	—			$	(17.0	)		$	(17.0	)
Maintenance capital		$	3.2			$	3.8			$	3.7			$	10.7
Three Months Ended March 31, 2006
Revenues:
External Customers (includes buy/sell revenues of $0, $0, and $4,761.9, respectively) (1)(5)		$	71.7			$	3.3			$	8,560.1			$	8,635.1
Intersegment (2)(5)			46.2				8.6				0.2				55.0
Total revenues of reportable segments		$	117.9			$	11.9			$	8,560.3			$	8,690.1
Equity earnings in unconsolidated entities		$	0.3			$	(0.2	)		$	—			$	0.1
Segment profit (1)(3)(4)		$	38.1			$	2.5			$	53.1			$	93.7
SFAS 133 impact (1)		$	—			$	—			$	(0.7	)		$	(0.7	)
Maintenance capital		$	3.0			$	0.8			$	0.9			$	4.7

		For the Three Months
		Ended March 31
		2007				2006
Segment profit		$	161.0			$	93.7
Depreciation and amortization			(39.9	)			(21.6	)
Interest expense			(41.1	)			(15.3	)
Interest income and other, net			4.8				0.3
Income tax expense			(0.1	)			—
Income before cumulative effect of change in accounting principle		$	84.7			$	57.1

Note 14—Recent Accounting Pronouncements

     In February 2007, the FASB issued SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities — including an amendment of FAS 115” (“SFAS 159”). SFAS 159 allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value in situations in which they are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item’s fair value in subsequent reporting periods must be recognized in current earnings. The provisions of SFAS 159 will be effective for fiscal years beginning after November 15, 2007. We are evaluating the impact of adoption of SFAS 159 but do not currently expect the adoption to have a material impact on our financial position, results of operations or cash flows.

     In December 2006, the FASB issued “FASB Staff Position EITF 00-19-2: Accounting for Registration Payment Arrangements” (the “FSP”). The FSP specifies that the contingent obligation to make future payments under a registration payment arrangement should be separately recognized and measured in accordance with FASB Statement No. 5 “Accounting for Contingencies”. The FSP was effective immediately for registration payment arrangements and the financial instruments subject to those arrangements entered into or modified subsequent to December 21, 2006. For registration payment arrangements and for the financial instruments subject to those arrangements that were entered into prior to December 21, 2006, the FSP is effective for fiscal years beginning after December 15, 2006. At March 31, 2007, we did not have any material contingent obligations under registration payment arrangements.

     In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures regarding fair value measurements. SFAS 157 does not add any new fair value measurements, but it does change current practice and is intended to increase consistency and comparability in such measurement. The provisions of SFAS 157 will be effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. The impact, if any, from the adoption of SFAS 157 in 2008 will depend on our assets and liabilities that are required to be measured at fair value at that time.

     In July 2006, the FASB issued FIN 48 which clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” FIN 48 also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. In addition, FIN 48 provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The provisions of FIN 48 are to be applied to all tax positions upon initial adoption of this standard. Only tax positions that meet the more-likely-than-not recognition threshold at the effective date may be recognized or continue to be recognized as an adjustment to the opening balance of retained earnings (or other appropriate components of equity) for that fiscal year. The provisions of FIN 48 were effective for fiscal years beginning after December 15, 2006. The adoption of FIN 48 did not have a material impact on our financial position, results of operations or cash flows. See Note 11.

     In June 2006, the EITF issued Issue No. 06-3 (“EITF 06-3”), “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net presentation).” EITF 06-3 is effective for all periods beginning after December 15, 2006 and its scope includes any tax that is assessed by a governmental authority that is both imposed on and concurrent with a specific revenue-producing transaction between a seller and a customer. The EITF stated that it is an entity’s accounting policy decision whether to present the taxes on a gross basis (within revenues and costs) or on a net basis (excluded from revenues) but that the accounting policy should be disclosed. If presented on a gross basis, an entity is required to report the amount of such taxes for each period for which an income statement is presented, if those amounts are significant. Our accounting policy is to present such taxes on a net basis.

Note 15 — Supplemental Condensed Consolidating Financial Information

     In conjunction with the Pacific acquisition, some but not all of our 100% owned subsidiaries issued full, unconditional, and joint and several guarantees of our Senior Notes. Given that certain, but not all, subsidiaries are guarantors of our Senior Notes, we are required to present the following supplemental condensed consolidating financial information. For purposes of the following footnote, we are referred to as “Plains All American”, while the “Guarantor Subsidiaries” are PAA Finance Corp.; Plains Marketing, L.P.; Plains Pipeline, L.P.; Plains Marketing GP Inc.; Plains Marketing Canada LLC; Plains Marketing Canada, L.P.; PMC (Nova Scotia) Company; Basin Holdings GP LLC; Basin Pipeline Holdings, L.P.; Rancho Holdings GP LLC; Rancho Pipeline Holdings L.P.; Plains LPG Services GP LLC; Plains LPG Services, L.P.; Lone Star Trucking, LLC; Plains Marketing International GP LLC; Plains Marketing International, L.P.; Plains LPG Marketing, L.P.; Rocky Mountain Pipeline System, LLC; Pacific Marketing and Transportation LLC; Pacific Atlantic Terminals LLC; Pacific LA Marine Terminal, LLC; Ranch Pipeline LLC; PEG Canada GP LLC; PEG Canada, L.P.; Pacific Energy Group LLC; Pacific Energy Finance Corporation; Rangeland Pipeline Company; Rangeland Marketing Company; Rangeland Northern Pipeline Company; Rangeland Pipeline Partnership; and Aurora Pipeline Company, Ltd. and “Non-Guarantor Subsidiaries” are Atchafalaya Pipeline, L.L.C.; Andrews Partners, LLC; Pacific Pipeline System, LLC, Pacific Terminals, LLC, Pacific Energy Management LLC and Pacific Energy GP LP.

     The following supplemental condensed consolidating financial information reflects the Parent’s separate accounts, the combined accounts of the Guarantor Subsidiaries, the combined accounts of the Non-Guarantor Subsidiaries, the combined consolidating adjustments and eliminations and the Parent’s consolidated accounts for the dates and periods indicated. For purposes of the following condensed consolidating information, the Parent’s investments in its subsidiaries and the Guarantor Subsidiaries’ investments in their subsidiaries are accounted for under the equity method of accounting:

		Condensed Consolidating Balance Sheet
		March 31, 2007
		Plains				Combined				Combined
		All				Guarantor				Non-Guarantor
		American				Subsidiaries				Subsidiaries				Eliminations				Consolidated
		(in millions)
		(unaudited)
ASSETS
Total current assets		$	2,263.4			$	2,798.2			$	147.0			$	(2,399.1	)		$	2,809.5
Property plant and equipment, net			—				3,342.8				615.9				—				3,958.7
Other assets:
Investment in unconsolidated entities			3,339.5				798.6				—				(3,942.4	)			195.7
Other assets			22.0				1,220.4				306.7				—				1,549.1
Total assets		$	5,624.9			$	8,160.0			$	1,069.6			$	(6,341.5	)		$	8,513.0
LIABILITIES AND PARTNERS’ CAPITAL
Total current liabilities		$	57.9			$	4,871.0			$	320.4			$	(2,398.7	)			2,850.6
Other liabilities:
Long-term debt			2,623.1				3.0				—				—				2,626.1
Other long-term liabilities			0.3				90.2				2.2				—				92.7
Total liabilities			2,681.3				4,964.2				322.6				(2,398.7	)			5,569.4
Partners’ capital			2,943.6				3,195.8				747.0				(3,942.8	)			2,943.6
Total liabilities and partners’ capital		$	5,624.9			$	8,160.0			$	1,069.6			$	(6,341.5	)		$	8,513.0

		Condensed Consolidating Statement of Operations
		Three Months Ended March 31, 2007
		Plains				Combined				Combined
		All				Guarantor				Non-Guarantor
		American				Subsidiaries				Subsidiaries				Eliminations				Consolidated
		(in millions)
		(unaudited)
Net operating revenues(1)		$	—			$	301.8			$	28.1			$	—			$	329.9
Field operating costs			—				117.1				8.6				—				125.7
General and administrative expenses			—				48.0				(1.2	)			—				46.8
Depreciation and amortization			0.7				34.2				5.0				—				39.9
Operating income			(0.7	)			102.5				15.7				—				117.5
Equity earnings in unconsolidated entities			126.2				16.6				—				(139.2	)			3.6
Interest expense			41.2				(0.1	)			—				—				41.1
Interest and other income (expense)			0.4				4.4				—				—				4.8
Income tax expense			—				0.1				—				—				0.1
Net income (loss)		$	84.7			$	123.5			$	15.7			$	(139.2	)		$	84.7

						Condensed Consolidating Statements of Cash Flows
						Three Months Ended March 31, 2007
		Plains				Combined				Combined
		All				Guarantor				Non-Guarantor
		American				Subsidiaries				Subsidiaries				Eliminations				Consolidated
		(in millions)
		(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	84.7			$	123.5			$	15.7			$	(139.2	)		$	84.7
Adjustments to reconcile to cash flows from operating activities:
Depreciation, amortization and other			0.7				34.2				5.0				—				39.9
Inventory valuation adjustment			—				1.0				—				—				1.0
Gain on sale of investment assets			—				(3.9	)			—				—				(3.9	)
SFAS 133 mark-to-market adjustment			—				17.0				—				—				17.0
Long-Term Incentive Plan charge			—				18.6				—				—				18.6
Noncash amortization of terminated interest rate hedging instruments			0.2				—				—				—				0.2
Loss on foreign currency revaluation			—				(0.2	)			—				—				(0.2	)
Equity earnings in unconsolidated entities			(126.2	)			(16.6	)			—				139.2				(3.6	)
Net change in assets and liabilities, net of acquisitions			155.4				82.3				(19.9	)			0.2				218.0
Net cash provided by operating activities			114.8				255.9				0.8				0.2				371.7
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisition			—				(17.3	)			—				—				(17.3	)
Additions to property and equipment			—				(133.3	)			(0.8	)			—				(134.1	)
Investment in unconsolidated entities, net			(9.1	)			0.2				—				(0.2	)			(9.1	)
Cash paid for linefill in assets owned			—				(4.5	)			—				—				(4.5	)
Proceeds from sales of assets			—				4.3				—				—				4.3
Net cash used in investing activities			(9.1	)			(150.6	)			(0.8	)			(0.2	)			(160.7	)
CASH FLOWS FROM FINANCING ACTIVITIES
Net repayments on working capital revolving credit facility			—				(69.9	)			—				—				(69.9	)
Net repayments on short-term letter of credit and hedged inventory facility			—				(32.1	)			—				—				(32.1	)
Distributions paid to unitholders and general partner			(104.6	)			—				—				—				(104.6	)
Other financing activities			—				(0.2	)			—				—				(0.2	)
Net cash used in financing activities			(104.6	)			(102.2	)			—				—				(206.8	)
Effect of translation adjustment on cash			—				1.1				—				—				1.1
Net increase in cash and cash equivalents			1.1				4.2				—				—				5.3
Cash and cash equivalents, beginning of period			2.3				9.0				—				—				11.3
Cash and cash equivalents, end of period		$	3.4			$	13.2			$	—			$	—			$	16.6