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 June 30, 2007

OR

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

Commission file number: 1-14569

PLAINS ALL AMERICAN PIPELINE, L.P.

(Exact name of registrant as specified in its charter)

Delaware		76-0582150
(State or other jurisdiction of		(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 August 1, 2007, there were outstanding 115,981,676 Common Units.

 

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

TABLE OF CONTENTS

		Page
PART I. FINANCIAL INFORMATION			3
Item 1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:			3
Condensed Consolidated Balance Sheets: June 30, 2007 and December 31, 2006			3
Condensed Consolidated Statements of Operations: For the three months and six months ended June 30, 2007 and 2006			4
Condensed Consolidated Statements of Cash Flows: For the six months ended June 30, 2007 and 2006			5
Condensed Consolidated Statement of Partners’ Capital: For the six months ended June 30, 2007			6
Condensed Consolidated Statements of Comprehensive Income: For the three months and six months ended June 30, 2007 and 2006			6
Condensed Consolidated Statement of Changes in Accumulated Other Comprehensive Income: For the six months ended June 30, 2007			6
Notes to the Condensed Consolidated Financial Statements			7
Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			26
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			40
Item 4. CONTROLS AND PROCEDURES			41
PART II. OTHER INFORMATION			41
Item 1. LEGAL PROCEEDINGS			41
Item 1A. RISK FACTORS			41
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			41
Item 3. DEFAULTS UPON SENIOR SECURITIES			41
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS			41
Item 5. OTHER INFORMATION			41
Item 6. EXHIBITS			42
SIGNATURES			45
Joinder and Supplement
Certification of Principal Executive Officer Pursuant to Rule 13a-14(a) and 15d-14(a)
Certification of Principal Financial Officer Pursuant to Rule 13a-14(a) and 15d-14(a)
Certification of Principal Executive Officer
Certification of Principal Financial Officer

PART I. FINANCIAL INFORMATION

Item 1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

		June 30,				December 31,
		2007				2006
		(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	44.6			$	11.3
Trade accounts receivable and other receivables, net			1,716.3				1,725.4
Inventory			1,585.8				1,290.0
Other current assets			115.7				130.9
Total current assets			3,462.4				3,157.6
PROPERTY AND EQUIPMENT			4,517.8				4,190.1
Accumulated depreciation			(431.0	)			(348.1	)
			4,086.8				3,842.0
OTHER ASSETS
Pipeline linefill in owned assets			248.3				265.5
Inventory in third-party assets			64.1				75.7
Investment in unconsolidated entities			200.1				183.0
Goodwill			1,045.5				1,026.2
Other, net			157.0				164.9
Total assets		$	9,264.2			$	8,714.9
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES
Accounts payable and accrued liabilities		$	2,053.8			$	1,846.6
Short-term debt			890.9				1,001.2
Other current liabilities			171.0				176.9
Total current liabilities			3,115.7				3,024.7
LONG-TERM LIABILITIES
Long-term debt under credit facilities and other			1.2				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			124.6				87.1
Total long-term liabilities			2,748.9				2,713.4
COMMITMENTS AND CONTINGENCIES (NOTE 12)
PARTNERS’ CAPITAL
Common unitholders (115,981,676 and 109,405,178 units outstanding at June 30, 2007 and December 31, 2006, respectively)			3,320.3				2,906.1
General partner			79.3				70.7
Total partners’ capital			3,399.6				2,976.8
Total liabilities and partners’ capital		$	9,264.2			$	8,714.9

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

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2007				2006				2007				2006
		(unaudited)								(unaudited)
REVENUES
Crude oil, refined products and LPG sales and related revenues (includes buy/sell transactions of $4,761.9 in the first three months of 2006)		$	3,792.0			$	4,819.1			$	7,908.7			$	13,394.4
Pipeline tariff activities revenues			92.8				69.6				179.5				127.0
Other revenues			33.0				3.3				59.1				5.7
Total revenues			3,917.8				4,892.0				8,147.3				13,527.1
COSTS AND EXPENSES
Crude oil, refined products and LPG purchases and related costs (includes buy/sell transactions of $4,795.1 in the first three months of 2006)			3,529.6				4,657.3				7,429.2				13,081.8
Field operating costs			135.7				89.4				261.4				174.6
General and administrative expenses			47.7				27.4				94.5				59.2
Depreciation and amortization			52.1				21.3				92.0				42.9
Total costs and expenses			3,765.1				4,795.4				7,877.1				13,358.5
OPERATING INCOME			152.7				96.6				270.2				168.6
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities			5.0				1.6				8.6				1.7
Interest expense (net of capitalized interest of $2.9 million and $0.9 million in the three months and $5.7 and $1.7 million in the six months ended June 30, 2007 and 2006, respectively)			(41.2	)			(18.0	)			(82.3	)			(33.3	)
Interest income and other income (expense), net			0.4				0.1				5.2				0.4
Income before tax			116.9				80.3				201.7				137.4
Current income tax expense			(0.7	)			—				(0.8	)			—
Deferred income tax expense			(11.4	)			—				(11.4	)			—
Income before cumulative effect of change in accounting principle			104.8				80.3				189.5				137.4
Cumulative effect of change in accounting principle			—				—				—				6.3
NET INCOME		$	104.8			$	80.3			$	189.5			$	143.7
NET INCOME-LIMITED PARTNERS		$	86.3			$	71.4			$	154.4			$	128.2
NET INCOME-GENERAL PARTNER		$	18.5			$	8.9			$	35.1			$	15.5
BASIC NET INCOME PER LIMITED PARTNER UNIT
Income before cumulative effect of change in accounting principle		$	0.78			$	0.82			$	1.40			$	1.47
Cumulative effect of change in accounting principle			—				—				—				0.08
Net income		$	0.78			$	0.82			$	1.40			$	1.55
DILUTED NET INCOME PER LIMITED PARTNER UNIT
Income before cumulative effect of change in accounting principle		$	0.78			$	0.81			$	1.39			$	1.45
Cumulative effect of change in accounting principle			—				—				—				0.08
Net income		$	0.78			$	0.81			$	1.39			$	1.53
BASIC WEIGHTED AVERAGE UNITS OUTSTANDING			110.5				77.0				109.9				75.5
DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING			111.2				77.8				110.9				76.3

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

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

		Six Months Ended
		June 30,
		2007				2006
		(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income		$	189.5			$	143.7
Adjustments to reconcile to cash flows from operating activities:
Depreciation and amortization			92.0				42.9
Cumulative effect of change in accounting principle			—				(6.3	)
SFAS 133 mark-to-market adjustment			2.1				3.1
Inventory valuation adjustment			0.6				—
Gain on sale of investment assets			(3.9	)			—
Long-Term Incentive Plan (“LTIP”) charge			40.4				16.8
Income tax expense			12.2				—
Noncash amortization of terminated interest rate hedging instruments			0.4				0.8
(Gain)/loss on foreign currency revaluation			(2.0	)			1.8
Equity earnings in unconsolidated entities, net of distributions			(7.8	)			(1.7	)
Changes in assets and liabilities, net of acquisitions:
Trade accounts receivable and other			36.1				(1,088.0	)
Inventory			(235.4	)			(214.3	)
Accounts payable and other liabilities			146.4				464.5
Inventory in third party assets			0.1				—
Due to related parties			1.8				(6.0	)
Net cash provided by (used in) operating activities			272.5				(642.7	)
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions (Note 3)			(17.5	)			(359.8	)
Additions to property and equipment			(266.9	)			(121.6	)
Investment in unconsolidated entities			(9.3	)			(10.0	)
Cash paid for linefill in assets owned			(14.7	)			(4.8	)
Proceeds from sales of assets			12.6				3.5
Net cash used in investing activities			(295.8	)			(492.7	)
CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings on long-term revolving credit facility			—				54.6
Net borrowings/(repayments) on working capital revolving credit facility			(175.1	)			229.9
Net borrowings on short-term letter of credit and hedged inventory facility			52.3				579.4
Proceeds from issuance of senior notes			—				249.5
Net proceeds from the issuance of common units (Note 7)			382.5				152.4
Distributions paid to common unitholders (Note 7)			(176.4	)			(105.3	)
Distributions paid to general partner (Note 7)			(35.6	)			(15.1	)
Other financing activities			(0.1	)			(4.4	)
Net cash provided by financing activities			47.6				1,141.0
Effect of translation adjustment on cash			9.0				(7.6	)
Net increase (decrease) in cash and cash equivalents			33.3				(2.0	)
Cash and cash equivalents, beginning of period			11.3				9.6
Cash and cash equivalents, end of period		$	44.6			$	7.6
Cash paid for interest, net of amounts capitalized		$	74.6			$	49.7
Cash paid for income taxes		$	2.0			$	—

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

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

														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			—				154.4				35.1				189.5
Distributions			—				(176.4	)			(35.6	)			(212.0	)
Issuance of common units			6.3				374.8				7.7				382.5
Issuance of common units under LTIP			0.3				17.2				0.4				17.6
Other comprehensive income			—				44.2				1.0				45.2
Balance at June 30, 2007			116.0			$	3,320.3			$	79.3			$	3,399.6

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in millions)

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2007				2006				2007				2006
		(unaudited)								(unaudited)
Net income		$	104.8			$	80.3			$	189.5			$	143.7
Other comprehensive income			58.5				19.2				45.2				19.7
Comprehensive income		$	163.3			$	99.5			$	234.7			$	163.4

CONDENSED CONSOLIDATED STATEMENT OF

		Net Deferred
		Gain/(Loss) on				Currency
		Derivative				Translation
		Instruments				Adjustments				Total
						(unaudited)
Balance at December 31, 2006		$	(19.8	)		$	69.5			$	49.7
Current Period Activity:
Reclassification adjustments for settled contracts			(28.0	)			—				(28.0	)
Changes in fair value of outstanding hedge positions			17.4				—				17.4
Currency translation adjustment			—				55.8				55.8
Total period activity			(10.6	)			55.8				45.2
Balance at June 30, 2007		$	(30.4	)		$	125.3			$	94.9

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

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1—Organization and Accounting Policies

     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 are also engaged in the development and operation of natural gas storage facilities.

     Our condensed 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 June 30, 2007 and December 31, 2006, (ii) the results of our consolidated operations for the three months and six months ended June 30, 2007 and 2006, (iii) our consolidated cash flows for the six months ended June 30, 2007 and 2006, (iv) our consolidated changes in partners’ capital for the six months ended June 30, 2007, (v) our consolidated comprehensive income for the three months and six months ended June 30, 2007 and 2006, and (vi) our changes in consolidated accumulated other comprehensive income for the six months ended June 30, 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 and six months ended June 30, 2007 should not be taken as indicative of the results to be expected for the full year.

     The accompanying condensed consolidated financial statements of PAA include PAA and all of its wholly-owned subsidiaries. Investments in 50% or less owned entities over which we have significant influence but not control are accounted for by the equity method.

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 are generally high volume and low margin activities, in many cases involving exchanges of crude oil volumes. We determine 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 June 30, 2007 and December 31, 2006, we had received approximately $22.3 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 June 30, 2007 and December 31, 2006, substantially all of our net accounts receivable were less than 60 days past their scheduled invoice date. Although we consider our allowance for doubtful trade accounts receivable to be adequate, actual amounts might vary significantly from estimated amounts.

Note 3—Acquisitions and Dispositions

     During the first half of 2007, we acquired (i) a commercial refined products supply and marketing business (reflected in our marketing segment) for approximately $8 million in cash (including approximately $7 million of goodwill) and (ii) a trucking business (reflected in our transportation segment) for approximately $9 million in cash (including approximately $4 million of goodwill). Also, during the first half of 2007, we signed an agreement to acquire the Bumstead LPG storage facility located near Phoenix, Arizona for

approximately $52 million. The acquisition closed in July 2007 and will be reflected in our facilities segment.

     In the second quarter of 2007, we incurred a net loss of approximately $9 million upon disposition of certain assets. This loss is included within “Depreciation and Amortization” on our Condensed Consolidated Statements of Operations.

Note 4—Inventory and Linefill

     At June 30, 2007 and December 31, 2006, inventory and linefill consisted of :

		June 30, 2007												December 31, 2006
										Dollar/												Dollar/
		Barrels				Dollars				barrel(2)				Barrels				Dollars				barrel(2)
						(Barrels in thousands and dollars in millions)
Inventory(1)
Crude oil			20,502			$	1,297.6			$	63.29				18,331			$	1,029.1			$	56.14
LPG			5,949				274.9			$	46.21				5,818				250.7			$	43.09
Refined Products			65				4.8			$	73.85				81				3.8			$	46.91
Parts and supplies			N/A				8.5				N/A				N/A				6.4				N/A
Inventory subtotal			26,516				1,585.8								24,230				1,290.0
Inventory in third-party assets
Crude oil			1,156				60.7			$	52.51				1,212				62.5			$	51.57
LPG			75				3.4			$	45.33				318				13.2			$	41.51
Inventory in third-party assets subtotal			1,231				64.1								1,530				75.7
Pipeline linefill in owned assets
Crude oil			7,338				246.8			$	33.63				7,831				264.4			$	33.76
LPG			39				1.5			$	38.46				31				1.1			$	35.48
Pipeline linefill in owned assets subtotal			7,377				248.3								7,862				265.5
Total			35,124			$	1,898.2								33,622			$	1,631.2

Note 5—Debt

     Below is a description of our debt as of June 30, 2007 (in millions):

		June 30,				December 31,
		2007				2006
Short-term debt:
Senior secured hedged inventory facility bearing interest at a rate of 5.8% at both June 30, 2007 and December 31, 2006		$	887.6			$	835.3
Working capital borrowings, bearing interest at a rate of 5.9% at December 31, 2006(1)			—				158.2
Other			3.3				7.7
Total short-term debt			890.9				1,001.2
Long-term debt:
4.75% senior notes due August 2009, net of unamortized discount of $0.3 million and $0.4 million at June 30, 2007 and December 31, 2006, respectively			174.7				174.6
7.75% senior notes due October 2012, net of unamortized discount of $0.2 million and $0.2 million at June 30, 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 June 30, 2007 and December 31, 2006, respectively			249.6				249.5
7.13 % senior notes due June 2014, net of unamortized premium of $8.2 million and $8.8 million at June 30, 2007 and December 31, 2006, respectively			258.2				258.8
5.25% senior notes due June 2015, net of unamortized discount of $0.6 million and $0.6 million at June 30, 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 June 30, 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 June 30, 2007 and December 31, 2006, respectively			174.1				174.1
6.13% senior notes due January 2017, net of unamortized discount of $1.6 million and $1.8 million at June 30, 2007 and December 31, 2006, respectively			398.4				398.2
6.70% senior notes due May 2036, net of unamortized discount of $0.4 million and $0.4 million at June 30, 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 June 30, 2007 and December 31, 2006, respectively			595.1				595.0
Senior notes, net of unamortized discount (2)			2,623.1				2,623.2
Adjustment related to fair value hedge			(1.4	)			—
Long-term debt under credit facilities and other			2.6				3.1
Total long-term debt (1)(2)			2,624.3				2,626.3
Total debt		$	3,515.2			$	3,627.5

     In June 2007, the borrowing capacity under our senior secured hedged inventory facility was increased from $1.0 billion to $1.2 billion under the terms and conditions of such facility, as amended.

     On July 31, 2007, we amended our revolving credit facility to, among other things, change the maximum debt coverage ratio during an acquisition period from 5.25 to 1.0 to 5.5 to 1.0, and extend the maturity date from July 2011 to July 27, 2012.

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 and accrued liabilities” 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 June 30, 2007, approximately $89.4 million of letters of credit were outstanding under our credit facility.

Note 6—Earnings Per Limited Partner Unit

     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 98% to the limited partners and 2% to the general partner. Basic and diluted net income per limited partner unit is determined by dividing net income attributable to limited partners by the weighted average number of outstanding limited partner units during the period.

     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 applies to any accounting period where our aggregate net income exceeds our aggregate distribution. In such periods, 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 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. Earnings per limited partner unit (both basic and diluted) were reduced by $0.11 and $0.15 for the three and six months ended June 30, 2006, respectively, attributable to the application of EITF 03-06. The application of EITF 03-06 had no impact on our results for the three and six months ended June 30, 2007.

     The following sets forth the computation of basic and diluted earnings per limited partner unit (in millions, except per unit data).

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2007				2006				2007				2006
Numerator:
Net income		$	104.8			$	80.3			$	189.5			$	143.7
Less: General partner’s incentive distribution paid			(16.7	)			(7.4	)			(32.0	)			(12.9	)
Subtotal			88.1				72.9				157.5				130.8
Less: General partner 2% ownership			(1.8	)			(1.5	)			(3.1	)			(2.6	)
Net income available to limited partners			86.3				71.4				154.4				128.2
Less: EITF 03-06 additional general partner’s distribution			—				(8.2	)			—				(11.2	)
Net income available to limited partners under EITF 03-06			86.3				63.2				154.4				117.0
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		$	86.3			$	63.2			$	154.4			$	110.8
Denominator:
Basic earnings per limited partner unit (weighted average number of limited partner units outstanding)			110.5				77.0				109.9				75.5
Effect of dilutive securities:
LTIP units outstanding (1)			0.7				0.8				1.0				0.8
Diluted earnings per limited partner unit (weighted average number of limited partner units outstanding)			111.2				77.8				110.9				76.3
Basic net income per limited partner unit before cumulative effect of change in accounting principle		$	0.78			$	0.82			$	1.40			$	1.47
Cumulative effect of change in accounting principle per limited partner unit			—				—				—				0.08
Basic net income per limited partner unit		$	0.78			$	0.82			$	1.40			$	1.55
Diluted net income per limited partner unit before cumulative effect of change in accounting principle		$	0.78			$	0.81			$	1.39			$	1.45
Cumulative effect of change in accounting principle per limited partner unit			—				—				—				0.08
Diluted net income per limited partner unit		$	0.78			$	0.81			$	1.39			$	1.53

Note 7—Partners’ Capital and Distributions

Direct Placements of Common Units

     We completed the following equity offerings of our common units during the six months ended June 30, 2007 and 2006, respectively (in millions, except units and per unit amounts):

				Gross		Proceeds		General Partner				Net
Period		Units		Unit Price		from Sale		Contribution		Costs		Proceeds
June 2007		6,296,172		$59.56		$375.0		$7.7		$(0.2)		$382.5
March/April 2006		3,504,672		$42.80		$150.0		$3.0		$(0.6)		$152.4

LTIP Vesting

     In May 2007, we issued 280,326 common units at a unit price of $61.47, for an approximate fair value of $17.2 million in connection with the settlement of vested LTIP awards. In addition, our general partner contributed $0.4 million in connection with the LTIP unit issuance.

Distributions

     The following table details the distributions we have declared and paid in the six months ended June 30, 2007 and 2006 (in millions, except per unit amounts):

		Distributions Paid
		Common				General Partner												Distribution
		Unitholders				Incentive				2%				Total				per unit
May 15, 2007		$	88.9			$	16.7			$	1.8			$	107.4			$	0.8125
February 14, 2007			87.5				15.3				1.8				104.6			$	0.8000
2007 total		$	176.4			$	32.0			$	3.6			$	212.0
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		$	105.3			$	13.0			$	2.1			$	120.4

     On July 19, 2007, we declared a cash distribution of $0.83 per unit on our outstanding common units. The distribution is payable on August 14, 2007 to unitholders of record on August 3, 2007, for the period April 1, 2007 through June 30, 2007. The total distribution to be paid is approximately $118.2 million, with approximately $96.3 million to be paid to our common unitholders and $2.0 million and $19.9 million to be 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 beginning with the February 2007 distribution, (ii) $3.75 million per quarter for the following eight quarters, (iii) $2.5 million per quarter for the following four quarters, and (iv) $1.25 million per quarter for the final four quarters. The aggregate 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 1998 Plan”), the 2005 Long-Term Incentive Plan (“the 2005 Plan”) and the PPX Successor Long-Term Incentive Plan for employees and directors (“the PPX Successor Plan”), as well as the Plains All American GP LLC 2006 Long-Term Incentive Tracking Unit Plan for non-officer employees (“the 2006 Plan”). 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 earning criteria, a DER entitles the grantee to a cash payment equal to the cash distribution 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 for services provided to us.

     Under SFAS 123(R) the fair value of the awards, which are subject to liability classification, is calculated based on the closing market price of our units at each 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 recognized as compensation expense over the period the awards are earned. Our LTIP awards typically contain performance conditions based on attainment of certain annualized distribution levels and vest upon the later of a certain date or the attainment of such levels. For awards with performance conditions, we recognize LTIP compensation expense only if the achievement of the performance condition is considered probable and amortize that expense over the service period. 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. Our DER awards typically contain performance conditions based on attainment of certain annualized distribution levels and become earned upon the earlier of a certain date or the attainment of such levels. The DERs terminate with the vesting or forfeiture of the underlying LTIP award. We recognize compensation expense for DER payments in the period the payment is earned.

     At June 30, 2007 we have approximately 3.7 million awards outstanding. Upon our February 2007 annualized distribution of $3.20, approximately 1.5 million of these awards satisfied one of the two conditions necessary for vesting (the attainment of certain annualized distribution levels) and only lack the passage of time, vesting in various increments over the next 5 years. Approximately 1.8 million of our awards have performance conditions requiring the attainment of an annualized distribution of between $3.50 and $4.00 and vest upon the later of a certain date or the attainment of such levels. Provided the performance conditions associated with these awards are ultimately attained, these awards will vest in various increments between 2010 and 2014. The remaining 0.4 million awards contain the same performance conditions in order to accelerate the vesting but will vest in 2012 regardless of whether the performance conditions are attained. Approximately 2.3 million of our 3.7 million outstanding awards also include DERs, of which 1.1 million are currently earned.

     Our accrued liability at June 30, 2007 related to all outstanding awards and DERs is $51.9 million which includes an accrual associated with our assessment that the distribution threshold of $3.50 is probable of occurring.

     Our expenses and cash and noncash vestings related to our LTIP are summarized in the table below (in millions):

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2007				2006				2007				2006
LTIP expense(1)		$	21.8			$	6.0			$	40.4			$	16.8
LTIP unit vestings		$	17.2			$	—			$	17.2			$	—
LTIP cash settled vestings		$	15.8			$	0.4			$	15.8			$	0.4
DER cash payments		$	1.3			$	0.7			$	2.4			$	1.2

     As of June 30, 2007, the weighted average remaining contractual life of our outstanding awards (that are currently considered probable of vesting) was approximately 3.2 years based on expected vesting dates. Based on the June 30, 2007 fair value measurement and probability assessment regarding future distributions, we expect to recognize an additional $91.6 million of expense over the life of our outstanding awards related to the remaining unrecognized fair value. This estimate is based on the closing market price of our limited partner units of $63.65 at June 30, 2007. Actual amounts may differ materially as a result of a change in market price and a change in probability assessment of future distributions. 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)		$	16.3
2008			30.8
2009			23.7
2010			14.3
2011			4.4
2012			2.1
Total		$	91.6

     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				47.43
Vested			(0.7	)			34.90
Cancelled or forfeited			—				—
Outstanding at June 30, 2007			3.7			$	37.44

Note 9—Derivative Instruments and Hedging Activities

Summary of Financial Impact

     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, is as follows (in millions, losses designated in parentheses):

		For the Three Months Ended												For the Three Months Ended
		June 30, 2007												June 30, 2006
		Mark-to-												Mark-to-
		market, net				Settled				Total				market, net				Settled				Total
Commodity price-risk hedging		$	13.4			$	11.1			$	24.5			$	(2.6	)		$	(10.1	)		$	(12.7	)
Controlled trading program			—				0.8				0.8				—				—				—
Interest rate risk hedging			(0.3	)			(0.2	)			(0.5	)			—				(0.4	)			(0.4	)
Currency exchange rate risk hedging			1.8				0.8				2.6				0.2				—				0.2
Total		$	14.9			$	12.5			$	27.4			$	(2.4	)		$	(10.5	)		$	(12.9	)

		For the Six Months Ended												For the Six Months Ended
		June 30, 2007												June 30, 2006
		Mark-to-												Mark-to-
		market, net				Settled				Total				market, net				Settled				Total
Commodity price-risk hedging		$	(5.6	)		$	80.9			$	75.3			$	(3.3	)		$	(3.9	)		$	(7.2	)
Controlled trading program			—				0.9				0.9				—				—				—
Interest rate risk hedging			(0.3	)			(0.4	)			(0.7	)			—				(0.8	)			(0.8	)
Currency exchange rate risk hedging			3.8				(0.2	)			3.6				0.2				—				0.2
Total		$	(2.1	)		$	81.2			$	79.1			$	(3.1	)		$	(4.7	)		$	(7.8	)

     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 parentheses):

		For the Three Months ended June 30,								For the Six Months ended June 30,
		2007				2006				2007				2006
Derivatives that do not qualify for hedge accounting			$15.7				$(2.8	)			$(0.7	)			$(3.6	)
Ineffective portion of cash flow hedges			(0.8	)			0.4				(1.4	)			0.5
Total			$14.9				$(2.4	)			$(2.1	)			$(3.1	)

     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 No. 133, “Accounting For Derivative Instruments and Hedging Activities,” as amended (“SFAS 133”) and (ii) certain transactions that have not been designated as hedges.

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

		June 30,				December 31,
		2007				2006
Other current assets		$	38.7			$	55.2
Other long-term assets			6.6				9.0
Other current liabilities			(68.2	)			(77.3	)
Long-term debt under credit facilities and other (fair value hedge adjustment)			1.4				—
Other long-term liabilities and deferred credits			(26.1	)			(21.4	)
Net liability		$	(47.6	)		$	(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 Accumulated Other Comprehensive Income (“AOCI”) as follows, by category (in millions, losses designated in parentheses):

		June 30, 2007												December 31, 2006
		Net asset												Net asset
		(liability)				Earnings				AOCI				(liability)				Earnings				AOCI
Commodity price-risk hedging		$	(49.1	)		$	(24.5	)		$	(24.6	)		$	(32.5	)		$	(18.9	)		$	(13.6	)
Controlled trading program			—				—				—				—				—				—
Interest rate risk hedging(1)			(0.3	)			(0.3	)			—				—				—				—
Currency exchange rate risk hedging			1.8				1.8				—				(2.0	)			(2.0	)			—
		$	(47.6	)		$	(23.0	)		$	(24.6	)		$	(34.5	)		$	(20.9	)		$	(13.6	)

     In addition to the $24.6 million of unrealized losses deferred to AOCI for open derivative positions, AOCI also includes a deferred loss of approximately $5.9 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 June 30, 2007, a net loss of $25.3 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 and six months ended June 30, 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

     Until August 12, 2005, Vulcan Energy owned 100% of Calumet Florida L.L.C. (“Calumet”). Until May 24, 2007, Calumet was owned by Vulcan Resources Florida, Inc., the majority of which is owned by Paul G. Allen. On May 24, 2007, Calumet was sold and ceased to be related to Vulcan. In the period from April 1, 2007, until the date that Calumet was sold, we purchased crude oil from Calumet for approximately $5.9 million and in the period from January 1, 2007 until the date that Calumet was sold, we purchased crude oil from Calumet for approximately $17.2 million. In the second quarter and the first six months of 2006, we purchased crude oil from Calumet for approximately $11.3 million and $22.6 million, respectively.

     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 because 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. Our provision for income taxes for the three and six months ended June 30, 2007 reflects these Canadian federal and provincial taxes in addition to tax obligations under the Texas Margin Tax described below.

     In June 2007, Canadian legislation was passed that imposes Canadian tax on Specified Flow-Through Investments (“SIFT”). The legislation includes a safe harbor provision which grandfathers existing entities and delays the effective date of such legislation until 2011 subject to companies not exceeding the normal growth guidelines as defined in the legislation. Although limited guidance is currently available, we believe that it is more likely than not that our Canadian partnerships will be considered a SIFT under the legislation and thus would be subject to the tax. We are currently within the normal growth guidelines as defined in the legislation, which delays the effective date for us until 2011. In conjunction with the passage of this legislation, we have recognized a net deferred income tax provision of approximately $10.8 million during the three months ended June 30, 2007. This amount represents the estimated tax effect of temporary differences that exist at June 30, 2007 and are expected to reverse after the date that this legislation is effective for us based on the 31.5% tax rate that is expected to be in effect when these temporary differences reverse. Substantially all of this amount is related to differences between book basis and tax basis depreciation on applicable property and equipment. If and when facts and circumstances change, we will reassess our position and record adjustments as necessary.

     In May 2006, the State of Texas enacted a new business tax (the “Texas Margin Tax”) that replaced its franchise tax. In general, any entity that conducts business in Texas is subject to the Texas Margin Tax. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits.

     Although the bill states that the margin tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenue and expenses. Therefore we have accounted for Texas Margin Tax as income tax expense. Texas Margin Tax is effective for returns originally due on or after January 1, 2008. For calendar year end companies such as us, the margin tax is applied to 2007 activity.

     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. The adoption of FIN 48 had no material impact on our financial statements. We recognize interest and penalties related to uncertain tax positions in income tax expense. At June 30, 2007, we have no material assets, liabilities or accrued interest associated with uncertain tax positions.

     We file income tax returns in 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 June 30, 2007. We expect to incur the remaining costs before the end of 2007. We anticipate that the majority of such costs 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 $1.1 million 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 in which 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 denied all allegations of wrongdoing and expressed willingness to settle the lawsuit solely because the settlement would eliminate the burden and expense of further litigation. The settlement was approved by the court on June 25, 2007. The settlement did not include award of monetary damages, however, in connection with the settlement, we (as successor to Pacific) paid approximately $0.5 million to the plaintiff’s counsel for their fees and expenses and incurred the cost of mailing materials to the Pacific unitholders.

     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. Although we are currently unable to determine the outcome of the foregoing, at this time, we do not believe it will have a material impact on our financial condition, results of operations or cash flows.

     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 or 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 near-term post-acquisition period, however, the inclusion of additional miles of pipe in our operations 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 June 30, 2007, our reserve for environmental liabilities totaled approximately $36.3 million, of which $16.1 million is classified as short-term and $20.2 million is classified as long-term. At June 30, 2007, we have recorded receivables totaling approximately $8.3 million for amounts that are probable of recovery under insurance and from third parties under indemnification agreements. Although we believe our reserve is adequate, costs incurred in excess of this reserve may be higher and may potentially 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. For example, in connection with our renewal of insurance in mid-2006, we increased our retention level for sudden and accidental pollution from $1 million to $5 million.

     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, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. In addition, although we believe that we have established adequate reserves to the extent that such risks are not insured, costs incurred in excess of these reserves may be higher and may potentially have a material adverse effect on our financial condition, results of operations or cash flows.

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.

     Our chief operating decision maker evaluates segment performance based on segment profit, segment volumes, segment profit per barrel 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. We compensate for this limitation by recognizing that depreciation and amortization are largely offset by repair and maintenance costs, which lessen 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 (in millions):

		Transportation				Facilities				Marketing				Total
Three Months Ended June, 2007
Revenues:
External Customers (1)		$	108.5			$	30.9			$	3,778.4			$	3,917.8
Intersegment (2)			85.7				23.3				9.1				118.1
Total revenues of reportable segments		$	194.2			$	54.2			$	3,787.5			$	4,035.9
Equity earnings in unconsolidated entities		$	1.2			$	3.8			$	—			$	5.0
Segment profit (1)(3)(4)		$	79.7			$	28.9			$	101.2			$	209.8
SFAS 133 impact (1)		$	—			$	—			$	15.2			$	15.2
Maintenance capital		$	9.2			$	2.4			$	(0.7	)		$	10.9

		Transportation				Facilities				Marketing				Total
Three Months Ended June, 2006
Revenues:
External Customers (1)		$	85.6			$	9.2			$	4,797.2			$	4,892.0
Intersegment (2)			45.3				12.2				0.2				57.7
Total revenues of reportable segments		$	130.9			$	21.4			$	4,797.4			$	4,949.7
Equity earnings in unconsolidated entities		$	0.5			$	1.1			$	—			$	1.6
Segment profit (1)(3)(4)		$	53.4			$	8.1			$	58.0			$	119.5
SFAS 133 impact (1)		$	—			$	—			$	(2.4	)		$	(2.4	)
Maintenance capital		$	3.4			$	0.7			$	0.3			$	4.4

		Transportation				Facilities				Marketing				Total
Six Months Ended June 30, 2007
Revenues:
External Customers (1)		$	210.5			$	56.5			$	7,880.3			$	8,147.3
Intersegment (2)			161.9				42.8				16.8				221.5
Total revenues of reportable segments		$	372.4			$	99.3			$	7,897.1			$	8,368.8
Equity earnings in unconsolidated entities		$	2.1			$	6.5			$	—			$	8.6
Segment profit (1)(3)(4)		$	152.8			$	50.8			$	167.2			$	370.8
SFAS 133 impact (1)		$	—			$	—			$	(1.8	)		$	(1.8	)
Maintenance capital		$	12.4			$	6.2			$	3.1			$	21.7