PART I. FINANCIAL INFORMATION

Item 1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions, except units)

	March 31,			December 31,
	2010			2009
	(unaudited)
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	16		$	25
Trade accounts receivable and other receivables, net	2,049			2,253
Inventory	1,244			1,157
Other current assets	32			223
Total current assets	3,341			3,658

PROPERTY AND EQUIPMENT	7,378			7,240
Accumulated depreciation	(966		)	(900		)
	6,412			6,340

OTHER ASSETS
Linefill and base gas	521			501
Long-term inventory	123			121
Goodwill	1,297			1,287
Other, net	408			451
Total assets	$	12,102		$	12,358

LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	2,401		$	2,295
Short-term debt	951			1,074
Other current liabilities	144			413
Total current liabilities	3,496			3,782

LONG-TERM LIABILITIES
Long-term debt under credit facilities and other	8			6
Senior notes, net of unamortized discount of $14 for both periods presented	4,136			4,136
Other long-term liabilities and deferred credits	253			275
Total long-term liabilities	4,397			4,417

COMMITMENTS AND CONTINGENCIES (NOTE 11)

PARTNERS’ CAPITAL
Common unitholders (136,135,988 units outstanding for both periods presented)	4,051			4,002
General partner	95			94
Total partners’ capital excluding noncontrolling interest	4,146			4,096
Noncontrolling interest	63			63
Total partners’ capital	4,209			4,159
Total liabilities and partners’ capital	$	12,102		$	12,358

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per unit data)

	Three Months Ended
	March 31,
	2010			2009
	(unaudited)

REVENUES
Supply & Logistics segment revenues	$	5,912		$	3,132
Transportation segment revenues	138			123
Facilities segment revenues	75			47
Total revenues	6,125			3,302

COSTS AND EXPENSES
Purchases and related costs	5,623			2,790
Field operating costs	162			152
General and administrative expenses	62			46
Depreciation and amortization	67			58
Total costs and expenses	5,914			3,046

OPERATING INCOME	211			256

OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	1			3
Interest expense (net of capitalized interest of $6 and $3, respectively)	(58		)	(51		)
Other income/(expense), net	(3		)	4

INCOME BEFORE TAX	151			212
Current income tax expense	(1		)	(2		)
Deferred income tax benefit	1			1

NET INCOME	$	151		$	211

NET INCOME:

LIMITED PARTNERS	$	112		$	180

GENERAL PARTNER	$	39		$	31

BASIC NET INCOME PER LIMITED PARTNER UNIT	$	0.80		$	1.42

DILUTED NET INCOME PER LIMITED PARTNER UNIT	$	0.80		$	1.41

BASIC WEIGHTED AVERAGE UNITS OUTSTANDING	136			124

DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING	137			125

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Three Months Ended
	March 31,
	2010			2009
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	151		$	211
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	67			58
Equity compensation charge	19			11
Deferred gains on settled hedges, net	—			9
Other	(3		)	(4		)
Changes in assets and liabilities, net of acquisitions:
Trade accounts receivable and other	341			420
Inventory	(89		)	121
Accounts payable and other current liabilities	(95		)	(348		)
Net cash provided by operating activities	391			478

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property, equipment and other	(104		)	(116		)
Cash received for sale of noncontrolling interest in a subsidiary	—			26
Other investing activities	(4		)	2
Net cash used in investing activities	(108		)	(88		)

CASH FLOWS FROM FINANCING ACTIVITIES
Net repayments on revolving credit facilities	(227		)	(544		)
Net borrowings on short-term letter of credit and hedged inventory facility	100			78
Net proceeds from the issuance of common units	—			210
Distributions paid to common unitholders (Note 7)	(126		)	(110		)
Distributions paid to general partner (Note 7)	(40		)	(30		)
Other financing activities	1			—
Net cash used in financing activities	(292		)	(396		)

Effect of translation adjustment on cash	—			2

Net decrease in cash and cash equivalents	(9		)	(4		)
Cash and cash equivalents, beginning of period	25			11
Cash and cash equivalents, end of period	$	16		$	7

Cash paid for interest, net of amounts capitalized	$	60		$	48

Cash paid/(refunded) for income taxes, net	$	6		$	4

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(in millions)

								Partners’ Capital
								Excluding
	Common Units				General			Noncontrolling			Noncontrolling		Partners’
	Units	Amount			Partner			Interest			Interest		Capital
	(unaudited)
Balance, December 31, 2009	136	$	4,002		$	94		$	4,096		$	63	$	4,159
Net income	—	112			39			151			—		151
Distributions (Note 7)	—	(126		)	(40		)	(166		)	—		(166		)
Class B Units of Plains AAP, L.P. (Note 8)	—	—			1			1			—		1
Equity compensation expense under LTIP (Note 8)	—	1			—			1			—		1
Other comprehensive income	—	62			1			63			—		63
Balance, March 31, 2010	136	$	4,051		$	95		$	4,146		$	63	$	4,209

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

	Three Months Ended
	March 31,
	2010		2009
	(unaudited)
Net income	$	151	$	211
Other comprehensive income/(loss)	63		(120		)
Comprehensive income	$	214	$	91

CONDENSED CONSOLIDATED STATEMENT OF

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME

(in millions)

	Derivative			Translation
	Instruments			Adjustments		Other			Total
	(unaudited)
Balance, December 31, 2009	$	18		$	106	$	(1	)	$	123
Reclassification adjustments	14			—		—			14
Net deferred loss on cash flow hedges	(5		)	—		—			(5		)
Currency translation adjustment	—			54		—			54
Total period activity	9			54		—			63
Balance, March 31, 2010	$	27		$	160	$	(1	)	$	186

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1—Organization and Basis of Presentation

Organization

We engage in the transportation, storage, terminalling and marketing of crude oil, refined products and LPG. We also engage in the development and operation of natural gas storage facilities. We manage our operations through three operating segments: (i) Transportation, (ii) Facilities and (iii) Supply and Logistics. See Note 12 for further detail of our operating segments.

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. References to our “general partner,” as the context requires, include any or all of PAA GP LLC, Plains AAP, L.P. and Plains All American GP LLC. The following additional defined terms are used in this Form 10-Q and shall have the meanings indicated below:

AOCI	= Accumulated other comprehensive income
API 653	= American Petroleum Institute Standard 653
Bcf	= Billion cubic feet
CAA	= Clean Air Act
CAD	= Canadian Dollar
Class B units	= Class B units of Plains AAP, L.P.
DCP	= Disclosure controls and procedures
DERs	= Distribution Equivalent Rights
DOJ	= United States Department of Justice
EPA	= United States Environmental Protection Agency
FERC	= Federal Energy Regulation Commission
FASB	= Financial Accounting Standards Board
ICE	= IntercontinentalExchange
IPO	= Initial Public Offering
LPG	= Liquefied petroleum gas and other natural gas-related petroleum products
LTIP	= Long term incentive plan
Mcf	= Thousand cubic feet
MLP	= Master limited partnership
NJDEP	= New Jersey Department of Environmental Protection
NYMEX	= New York Mercantile Exchange
NPNS	= Normal purchase and normal sale
PNG	= PAA Natural Gas Storage, L.P.
PNGS	= PAA Natural Gas Storage, LLC
PAT	= Pacific Atlantic Terminals, LLC
PPS	= Pacific Pipeline System
Rainbow	= Rainbow Pipe Line Company Ltd.
RMPS	= Rocky Mountain Pipeline System
SEC	= Securities and Exchange Commission
U.S. GAAP	= United States generally accepted accounting principles
USD	= United States Dollar
WTI	= West Texas Intermediate

Basis of Consolidation and Presentation

The accompanying condensed consolidated interim financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our 2009 Annual Report on Form 10-K. The financial statements have been prepared in accordance with the instructions for interim reporting as prescribed by the SEC. All

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Note 4—Inventory, Linefill, Base Gas and Long-term Inventory

Inventory, linefill, base gas and long-term inventory consisted of the following (barrels in thousands, natural gas volumes in millions and total value in millions):

	March 31, 2010						December 31, 2009
		Unit of	Total		Price/			Unit of	Total		Price/
	Volumes	Measure	Value		Unit (1)		Volumes	Measure	Value		Unit (1)
Inventory
Crude oil	14,833	barrels	$	1,156	$	77.93	12,232	barrels	$	886	$	72.43
LPG	1,683	barrels	78		$	46.35	6,051	barrels	247		$	40.82
Refined products	127	barrels	9		$	70.87	283	barrels	21		$	74.20
Natural gas (2)	115	mcf	—		$	2.97	181	mcf	1		$	3.30
Parts and supplies	N/A		1		N/A		N/A		2		N/A
Inventory subtotal			1,244						1,157

Linefill and base gas
Crude oil	9,459	barrels	482		$	50.96	9,404	barrels	471		$	50.09
Natural gas (2)	10,994	mcf	37		$	3.37	9,194	mcf	28		$	3.04
LPG	56	barrels	2		$	35.71	52	barrels	2		$	38.46
Linefill and base gas subtotal			521						501

Long-term inventory
Crude oil	1,460	barrels	101		$	69.18	1,497	barrels	103		$	68.80
LPG	458	barrels	22		$	48.03	458	barrels	18		$	39.30
Long-term inventory subtotal			123						121

Total			$	1,888					$	1,779

(1) Price per unit represents a weighted average associated with various grades, qualities, and locations; accordingly, these prices may not be comparable to published benchmarks for such products.

(2) The volumetric ratio of mcf of natural gas to barrels of crude oil is 6:1; thus, natural gas volumes can be converted to barrels by dividing by 6.

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Note 5—Debt

Debt consists of the following (in millions):

	March 31,			December 31,
	2010			2009
Short-term debt:
Senior secured hedged inventory facility bearing interest at a rate of 2.5% and 2.5% as of March 31, 2010 and December 31, 2009, respectively	$	400		$	300
Senior unsecured revolving credit facility, bearing interest at a rate of 0.7% and 0.8% as of March 31, 2010 and December 31, 2009, respectively (1)	549			772
Other	2			2
Total short-term debt	951			1,074

Long-term debt:
4.25% senior notes due September 2012 (2)	500			500
7.75% senior notes due October 2012	200			200
5.63% senior notes due December 2013	250			250
5.25% senior notes due June 2015	150			150
6.25% senior notes due September 2015	175			175
5.88% senior notes due August 2016	175			175
6.13% senior notes due January 2017	400			400
6.50% senior notes due May 2018	600			600
8.75% senior notes due May 2019	350			350
5.75% senior notes due January 2020	500			500
6.70% senior notes due May 2036	250			250
6.65% senior notes due January 2037	600			600
Unamortized premium/(discount), net	(14		)	(14		)
Long-term debt under credit facilities and other	8			6
Total long-term debt (1) (3)	4,144			4,142
Total debt	$	5,095		$	5,216

(1) We classify borrowings under our senior unsecured revolving credit facility as short-term. These borrowings are designated as working capital borrowings, must be repaid within one year and are primarily for hedged LPG and crude oil inventory and NYMEX and ICE margin deposits.

(2) These notes were issued in July 2009 and the proceeds are being used to supplement capital available from our hedged inventory facility. At March 31, 2010, approximately $209 million had been used to fund hedged inventory and would be classified as short-term debt if funded on our credit facilities.

(3) Our fixed rate senior notes have a face value of approximately $4.2 billion as of March 31, 2010. We estimate the aggregate fair value of these notes as of March 31, 2010 to be approximately $4.5 billion. Our fixed-rate senior notes are traded among institutions, which trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near quarter end.

Letters of Credit

In connection with our crude oil supply and logistics activities, we provide certain suppliers with irrevocable standby letters

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of credit to secure our obligation for the purchase of crude oil. At March 31, 2010 and December 31, 2009, we had outstanding letters of credit of approximately $107 million and $76 million, respectively.

Note 6—Net Income Per Limited Partner Unit

The following table sets forth the computation of basic and diluted earnings per limited partner unit for the three months ended March 31, 2010 and 2009 (amounts in millions, except per unit data):

	Three Months Ended March 31,
	2010			2009
Numerator for basic and diluted earnings per limited partner unit:
Net income	$	151		$	211
Less: General partner’s incentive distribution paid (1)	(37		)	(28		)
Subtotal	114			183
Less: General partner 2% ownership (1)	(2		)	(3		)
Net income available to limited partners	112			180
Adjustment in accordance with application of the two-class method for MLPs (1)	(3		)	(4		)
Net income available to limited partners in accordance with the application of the two-class method for MLPs	$	109		$	176

Denominator:
Basic weighted average number of limited partner units outstanding	136			124
Effect of dilutive securities:
Weighted average LTIP units (2)	1			1
Diluted weighted average number of limited partner units outstanding	137			125

Basic net income per limited partner unit	$	0.80		$	1.42

Diluted net income per limited partner unit	$	0.80		$	1.41

(1) We calculate net income available to limited partners based on the distribution paid during the current quarter (including the incentive distribution interest in excess of the 2% general partner interest). However, FASB guidance requires that the distribution pertaining to the current period’s net income, which is to be paid in the subsequent quarter, be utilized in the earnings per unit calculation. After adjusting for this distribution, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner and limited partners in accordance with the contractual terms of the partnership agreement for earnings per unit calculation purposes. We reflect the impact of the difference in (i) the distribution utilized and (ii) the calculation of the excess 2% general partner interest as the “Adjustment in accordance with application of the two-class method for MLPs.”

(2) Our LTIP awards (described in Note 8) that contemplate the issuance of common units are considered dilutive unless (i) vesting occurs only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. LTIP awards that are deemed to be dilutive are reduced by a hypothetical unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB.

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Note 7—Partners’ Capital and Distributions

Equity Offerings

We did not complete any equity offerings during the three months ended March 31, 2010; however, we completed the following equity offering of our common units during the three months ended March 31, 2009 (in millions, except unit and per unit data):

						General
		Gross		Proceeds		Partner					Net
Period	Units Issued	Unit Price		from Sale		Contribution		Costs			Proceeds
March 2009 (1)	5,750,000	$	36.90	$	212	$	4	$	(6	)	$	210

(1) This offering of common units was an underwritten transaction that required us to pay a gross spread. The net proceeds from this offering were used to reduce outstanding borrowings under our credit facilities and for general partnership purposes.

Distributions

The following table details the distributions pertaining to the first three months of 2010 and 2009, net of reductions to the general partner’s incentive distributions (in millions, except per unit amounts):

		Distributions Paid								Distributions
		Common		General Partner						per limited
Date Declared	Date Paid or To Be Paid	Units		Incentive		2%		Total		partner unit
2010
April 13, 2010	May 14, 2010 (1)	$	127	$	39	$	3	$	169	$	0.9350
January 20, 2010	February 12, 2010	$	126	$	37	$	3	$	166	$	0.9275

2009
April 8, 2009	May 15, 2009	$	117	$	32	$	2	$	151	$	0.9050
January 14, 2009	February 13, 2009	$	110	$	28	$	2	$	140	$	0.8925

(1) Payable to unitholders of record on May 4, 2010, for the period January 1, 2010 through March 31, 2010.

Upon closing of the Pacific acquisition in November 2006, the Rainbow acquisition in May 2008 and the PNGS acquisition in September 2009, our general partner agreed to reduce the amounts due it as incentive distributions. The total reduction in incentive distributions related to these acquisitions is $83 million. Following the distribution in May 2010, the aggregate incentive distribution reductions remaining will be approximately $14 million. See Note 2 to our Consolidated Financial Statements included in Part IV of our 2009 Annual Report on Form 10-K for further detail regarding our “General Partner Incentive Distributions.”

Note 8—Equity Compensation Plans

LTIPs

For discussion of our LTIP awards, see Note 10 to our Consolidated Financial Statements included in Part IV of our 2009 Annual Report on Form 10-K. At March 31, 2010, the following LTIP awards were outstanding (units in millions):

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		Vesting
LTIP Units		Distribution
Outstanding		Amount	2010	2011	2012	2013	2014	2015
0.6	(1)	$3.20	0.6	—	—	—	—	—
3.0	(2)	$3.50 - $4.50	—	0.5	0.9	0.6	0.5	0.5
1.7	(3)	$3.50 - $4.25	0.5	0.3	0.7	0.2	—	—
5.3	(4) (5)		1.1	0.8	1.6	0.8	0.5	0.5

(1) Upon our February 2007 annualized distribution of $3.20, these LTIP awards satisfied all distribution requirements and will vest upon completion of the respective service period.

(2) These LTIP awards have performance conditions requiring the attainment of an annualized distribution of between $3.50 and $4.50 and vest upon the later of a certain date or the attainment of such levels. If the performance conditions are not attained while the grantee remains employed by us, or the grantee does not continue to be employed for the requisite service period, these awards will be forfeited. For purposes of this disclosure, vesting dates are based on an estimate of future distribution levels and assume that all grantees remain employed by us through the vesting date.

(3) These LTIP awards have performance conditions requiring the attainment of an annualized distribution of between $3.50 and $4.25. For a majority of these LTIP awards, fifty percent will vest at specified dates regardless of whether the performance conditions are attained. For purposes of this disclosure, vesting dates are based on an estimate of future distribution levels and assume that all grantees remain employed by us through the vesting date.

(4) Approximately 3 million of our approximately 5.3 million outstanding LTIP awards also include DERs, of which approximately 1 million are currently earned.

(5) LTIP units outstanding do not include Class B units described below.

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, December 31, 2009	3.9		$	36.40
Granted (1)	1.5		$	42.53
Vested	—		$	—
Cancelled or forfeited	(0.1	)	$	31.54
Outstanding, March 31, 2010	5.3		$	38.18

(1) Includes approximately 1 million equity classified awards.

Our accrued liability at March 31, 2010 related to all outstanding liability classified LTIP awards and DERs is approximately $104 million, which includes an accrual associated with our assessment that an annualized distribution of $3.90 is probable of occurring. We have not deemed a distribution of more than $3.90 to be probable. At December 31, 2009, the accrued liability was approximately $87 million.

Class B Units

For further discussion of the Class B units, see Note 10 to our Consolidated Financial Statements included in Part IV of our 2009 Annual Report on Form 10-K. The following table contains a summary of Class B unit awards that were (i) reserved for future

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grants (ii) outstanding and (iii) earned as of and for the three months ended March 31, 2010 and as of December 31, 2009:

	Reserved for Future Grants		Outstanding	Outstanding Units Earned	Grant Date Fair Value Of Outstanding Class B Units (1)
					(in millions)
Balance, December 31, 2009	34,500		165,500	38,500	$	36
Class B unit issuance	(3,000	)	3,000	—	—
Class B units earned	—		—	—	—
Balance, March 31, 2010	31,500		168,500	38,500	$	36

(1) Of the grant date fair value, approximately $1 million was recognized as expense during the three months ended March 31, 2010.

Other Consolidated Equity Compensation Information

We refer to our LTIP Plans and the Class B units collectively as “Equity compensation plans.” The table below summarizes the expense recognized and the value of vesting (settled both in units and cash) related to our equity compensation plans (in millions):

	Three Months Ended				Three Months Ended
	March 31,				March 31,
	2010				2009
	Liability Awards		Equity Awards		Liability Awards		Equity Awards
Equity compensation expense	$	17	$	2	$	10	$	1
LTIP unit vestings	$	—	$	—	$	—	$	—
LTIP cash settled vestings	$	—	$	—	$	—	$	—
DER cash payments	$	1	$	—	$	1	$	—

Based on the March 31, 2010 fair value measurement and probability assessment regarding future distributions, we expect to recognize approximately $68 million of additional expense over the life of our outstanding awards related to the remaining unrecognized fair value. For our liability classified awards, this estimate is based on the closing market price of our units of $56.90 at March 31, 2010. For our equity classified awards, this estimate is based on the closing price of our units as of the grant date. Actual amounts may differ materially as a result of a change in the market price of our units and/or probability assessment regarding future distributions. We estimate that the remaining fair value will be recognized in expense as shown below (in millions):

	Equity Compensation
	Plans Remaining Fair Value
Year	Amortization (1) (2)
2010 (3)	$	28
2011	22
2012	14
2013	4
Total	$	68

(1) Amounts do not include fair value associated with awards containing performance conditions that are not considered to be probable of occurring at March 31, 2010.

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(2) Includes unamortized fair value associated with Class B units.

(3) Includes equity compensation plan fair value amortization for the remaining nine months of 2010.

Note 9—Derivatives and Risk Management Activities

We identify the risks that underlie our core business activities and use risk management strategies to mitigate those risks when we determine that there is value in doing so. We use various derivative instruments to (i) manage our exposure to commodity price risk as well as to optimize our profits, (ii) manage our exposure to interest rate risk and (iii) manage our exposure to currency exchange rate risk. Our policy is to use derivative instruments only for risk management purposes. Our commodity risk management policies and procedures are designed to monitor NYMEX, ICE and over-the-counter positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity, to help ensure that our hedging activities address our risks. Our interest rate and foreign currency risk management policies and procedures are designed to monitor our positions and ensure that those positions are consistent with our objectives and approved strategies. Our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategies for undertaking the hedge. 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 used in a transaction are highly effective in offsetting changes in cash flows or the fair value of hedged items. A discussion of our derivative activities by risk category follows.

Commodity Price Risk Hedging

Our core business activities contain certain commodity price-related risks that we manage in various ways, including the use of derivative instruments. Our policy is (i) to purchase only product for which we have a market, (ii) to structure our sales contracts so that price fluctuations do not materially affect the segment profit we earn, and (iii) not to acquire and hold physical inventory, futures contracts or other derivative products for the purpose of speculating on outright commodity price changes. Although we seek to maintain a position that is substantially balanced within our supply and logistics activities, we purchase crude oil, refined products and LPG from thousands of locations and may experience net unbalanced positions as a result of production, transportation and delivery variances, as well as logistical issues associated with inclement weather conditions and other uncontrollable events that occur within each month. In connection with our efforts to maintain a balanced position, specifically authorized personnel can purchase or sell an aggregate limit of up to 810,000 barrels of crude oil, refined products and LPG relative to the volumes originally scheduled for such month, based on interim information. The purpose of these purchases and sales is to manage risk as opposed to establishing a risk position. When unscheduled physical inventory builds or draws do occur, they are monitored constantly and managed to a balanced position over a reasonable period of time.

The material commodity related risks inherent in our business activities can be summarized into the following general categories:

Commodity Purchases and Sales — In the normal course of our supply and logistics operations, we purchase and sell crude oil, LPG, and refined products. We use derivatives to manage the associated risks and to optimize profits. As of March 31, 2010, material net derivative positions related to these activities included:

· An approximate 222,000 barrels per day net long position (total of 6.7 million barrels) associated with our crude oil activities, which was unwound ratably during April 2010 to match monthly average pricing.

· An approximate 29,900 barrels per day (total of 19.8 million barrels) net short spread position which hedges a portion of our anticipated crude oil lease gathering purchases through January 2012. These derivatives protect our margin on future floating price crude oil purchase commitments. These derivatives in the aggregate do not result in exposure to outright price movements.

· A net short spread position averaging approximately 3,400 barrels per day (total of 2.1 million barrels) of calendar spread call options for the period April 2010 through January 2012. These derivatives in the aggregate do not result in exposure to outright price movements.

· An average of approximately 3,000 barrels per day (total of 1.1 million barrels) of butane/WTI spread positions, which hedge specific butane sales contracts that are priced as a fixed percentage of WTI and continue through March 2011.

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· Approximately 18,400 barrels per day on average (total of 5.0 million barrels) of crude oil basis differential hedges through December 2010.

Storage Capacity Utilization — We own approximately 59 million barrels of crude oil, LPG and refined products storage capacity that is not used in our transportation operations. This storage may be leased to third parties or utilized in our own supply and logistics activities, including for the storage of inventory in a contango market. For capacity allocated to our supply and logistics operations, we have utilization risk if the market structure is backwardated. As of March 31, 2010, we used derivatives to manage the risk of not utilizing approximately 2.6 million barrels per month of storage capacity through 2011. These positions are a combination of calendar spread options and NYMEX futures contracts. These positions involve no outright price exposure, but instead represent potential offsetting purchases and sales between time periods (first month versus second month for example).

Inventory Storage — At times, we elect to purchase and store crude oil, LPG and refined products inventory in conjunction with our supply and logistics activities. These activities primarily relate to the seasonal storage of LPG inventories and contango market storage activities. When we purchase and store barrels, we enter into physical sales contracts or use derivatives to mitigate price risk associated with the inventory. As of March 31, 2010, we had approximately 8.9 million barrels of inventory hedged with derivatives.

We also purchase foreign cargoes of crude oil and may enter into derivatives to mitigate various price risks associated with the purchase and ultimate sale of foreign crude inventory. As of March 31, 2010, we had approximately 1.5 million barrels of crude oil derivatives hedging the anticipated sale of foreign crude inventory and 2.9 million barrels of crude oil spread positions hedging the anticipated purchase of foreign crude inventory.

Pipeline Loss Allowance Oil — As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor that is intended to, among other things, offset losses due to evaporation, measurement and other losses in transit. We utilize derivative instruments to hedge a portion of the anticipated sales of the allowance oil that is to be collected under our tariffs. As of March 31, 2010, we had entered into a net short position consisting of crude oil futures and swaps to manage the risk associated with the anticipated sale of an average of approximately 2,300 barrels per day (total of 2.3 million barrels) from April 2010 through December 2012. In addition, we had a long put option position of approximately 1 million barrels through December 2012 and a net long call option position of approximately 1.5 million barrels through December 2011, which provide upside price participation.

Diluent Purchases — We use diluent in our Canadian crude oil pipeline operations and have used derivative instruments to hedge the anticipated forward purchases of diluent and diluent inventory. As of March 31, 2010, we had an average of 1,300 barrels per day of natural gasoline/WTI spread positions (approximately 1 million barrels) that run through mid-2011 and an average of 3,300 barrels per day of short crude oil futures (approximately 0.3 million barrels) to hedge condensate through the second quarter of 2010.

Natural Gas Purchases — Our gas storage facilities require minimum levels of natural gas (“base gas”) to operate. For our natural gas storage facilities that are under construction, we anticipate purchasing base gas in future periods as construction is completed. We use derivatives to hedge such anticipated purchases of natural gas. As of March 31, 2010, we have a net long position of approximately 2 Bcf consisting of natural gas futures contracts through August 2011 and natural gas call options for approximately 1 Bcf through August 2011.

The derivative instruments we use to manage our commodity price risk consist primarily of futures, options and swaps traded on the NYMEX and ICE and in over-the-counter transactions. Over-the-counter transactions include commodity swap and option contracts. All of our commodity derivatives that qualify for hedge accounting are designated as cash flow hedges. Therefore, the corresponding changes in fair value for the effective portion of the hedges are deferred into AOCI and recognized in revenues or purchases and related costs in the periods during which the underlying physical transactions occur. We have determined that substantially all of our physical purchase and sale agreements qualify for the NPNS exclusion and thus are not subject to the accounting treatment for derivative instruments and hedging activities as set forth in FASB guidance. Physical commodity contracts that meet the definition of a derivative but are ineligible, or not designated, for the NPNS scope exception are recorded on the balance sheet as assets or liabilities at their fair value, with the changes in fair value recorded net in revenues.

Interest Rate Risk Hedging

We use interest rate derivatives to hedge interest rate risk associated with anticipated debt issuances and, in certain cases, outstanding debt instruments. The derivative instruments we use to manage this risk consist primarily of interest rate swaps and

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treasury locks. As of March 31, 2010, AOCI includes deferred losses of $8 million that relate to terminated interest rate swaps and treasury locks that were designated for hedge accounting. These terminated interest rate derivatives were cash-settled in connection with the issuance and refinancing of debt agreements. The deferred loss related to these instruments is being amortized to interest expense over the original terms of the forecasted debt instruments.

As of March 31, 2010, we had four outstanding interest rate swaps by which we receive fixed interest payments and pay floating-rate interest payments based on three-month LIBOR plus an average spread of 2.42% on a semi-annual basis. The swaps have an aggregate notional amount of $300 million with fixed rates of 4.25%. Two of the swaps terminate in 2011 and two of the swaps terminate in 2012.

Currency Exchange Rate Risk Hedging

We use foreign currency derivatives to hedge foreign currency risk associated with our exposure to fluctuations in the USD-to-CAD exchange rate. Because a significant portion of our Canadian business is conducted in CAD and, at times, a portion of our debt is denominated in CAD, we use certain financial instruments to minimize the risks of unfavorable changes in exchange rates. These instruments primarily include foreign currency exchange contracts, forwards and options. As of March 31, 2010, AOCI includes net deferred gains of $15 million that relate to open and settled forward exchange contracts that were designated for hedge accounting. These forward exchange contracts hedge the cash flow variability associated with CAD-denominated interest payments on a CAD-denominated intercompany note as a result of changes in the foreign exchange rate.

As of March 31, 2010, our outstanding foreign currency derivatives also include derivatives used to hedge CAD-denominated crude oil purchases and sales. We may from time to time hedge the commodity price risk associated with a CAD-denominated commodity transaction with a USD-denominated commodity derivative. In conjunction with entering into the commodity derivative, we enter into a foreign currency derivative to hedge the resulting foreign currency risk. These foreign currency derivatives are generally short-term in nature and are not designated for hedge accounting.

At March 31, 2010, our open foreign exchange derivatives included forward exchange contracts that exchange CAD for USD on a net basis as follows (in millions):

	CAD		USD		Average Exchange Rate
2010	$	32	$	29	CAD $1.14 to USD $1.00
2011	$	15	$	15	CAD $1.01 to USD $1.00
2012	$	15	$	15	CAD $1.01 to USD $1.00
2013	$	9	$	9	CAD $1.00 to USD $1.00

These financial instruments are placed with large, highly rated financial institutions.

Summary of Financial Impact

The majority of our derivative activity is related to our commodity price risk hedging activities. All of our commodity derivatives that qualify for hedge accounting are designated as cash flow hedges. Therefore, the corresponding changes in fair value for the effective portion of the hedges are deferred to AOCI and recognized in earnings in the periods during which the underlying physical transactions impact earnings. Derivatives that do not qualify for hedge accounting and the portion of cash flow hedges that is not highly effective in offsetting changes in cash flows of the hedged items are recognized in earnings each period. Cash settlements associated with our derivative activities are reflected as operating cash flows in our consolidated statements of cash flows.

A summary of the impact of our derivative activities recognized in earnings for the three months ended March 31, 2010 is as follows (in millions):

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Three Months Ended March 31, 2010:

		Derivatives in Cash Flow
		Hedging Relationships						Derivatives Not
		AOCI			Ineffective			Designated
	Location of gain/(loss)	Reclass (1)			Portion (2)			as a Hedge (3)			Total
Commodity derivatives	Supply and Logistics segment revenues	$	(19	)	$	(1	)	$	27		$	7

	Transportation segment revenues	1			—			—			1

	Facilities segment revenues	(1		)	—			1			—

	Purchases and related costs	5			—			(24		)	(19		)

Interest rate derivatives	Other income, net	—			—			—			—

	Interest Expense	—			—			1			1

Foreign exchange derivatives	Supply and Logistics segment revenues	—			—			—			—

	Purchases and related costs	—			—			2			2

	Other income, net	—			—			(1		)	(1		)

Total Gain/(Loss) on Derivatives Recognized in Income		$	(14	)	$	(1	)	$	6		$	(9	)

(1) Amounts represent derivative gains and losses that were reclassed from AOCI to earnings during the period to coincide with earnings impact of the respective hedged transaction.

(2) Amounts represent the ineffective portion of the fair value of our unrealized cash flow hedges that were recognized in earnings during the period.

(3) Includes realized and unrealized gains or losses for derivatives not designated for hedge accounting during the period.

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A summary of the impact of our derivative activities recognized in earnings for the three months ended March 31, 2009 is as follows (in millions):

Three Months Ended March 31, 2009:

		Derivatives in Cash Flow
		Hedging Relationships						Derivatives Not
		AOCI			Ineffective			Designated
	Location of gain/(loss)	Reclass (1)			Portion (2)			as a Hedge (3)			Total
Commodity derivatives	Supply and Logistics segment revenues	$	125		$	(1	)	$	(29	)	$	95

	Transportation segment revenues	2			—			—			2

	Facilities segment revenues	—			—			—			—

	Purchases and related costs	(32		)	—			95			63

Interest rate derivatives	Other income, net	—			—			(1		)	(1		)

	Interest Expense	—			—			—			—

Foreign exchange derivatives	Supply and Logistics segment revenues	—			—			—			—

	Purchases and related costs	—			—			(5		)	(5		)

	Other income, net	5			—			—			5

Total Gain/(Loss) on Derivatives Recognized in Income		$	100		$	(1	)	$	60		$	159

(1) Amounts represent derivative gains and losses that were reclassed from AOCI to earnings during the period to coincide with earnings impact of the respective hedged transaction.

(2) Amounts represent the ineffective portion of the fair value of our unrealized cash flow hedges that were recognized in earnings during the period.

(3) Includes realized and unrealized gains or losses for derivatives not designated for hedge accounting during the period.

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The following table summarizes the derivative assets and liabilities on our consolidated balance sheet on a gross basis as of March 31, 2010 (in millions):

	Asset Derivatives			Liability Derivatives
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments:
Commodity derivatives	Other current assets	$	52	Other current assets	$	(50	)
	Other long-term assets	27		Other current liabilities	(11		)
	Other long-term liabilities	6		Other long-term liabilities	(1		)
Foreign exchange derivatives	Other long-term assets	1		Other long-term liabilities	—
Total derivatives designated as hedging instruments		$	86		$	(62	)

Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	77	Other current assets	$	(82	)
	Other long-term assets	29		Other current liabilities	—
	Other long-term liabilities	6		Other long-term liabilities	(11		)
Interest rate derivatives	Other current assets	3		Other current liabilities	—
Foreign exchange derivatives	Other current assets	1		Other current liabilities	(3		)
Total derivatives not designated as hedging instruments		$	116		$	(96	)

Total derivatives		$	202		$	(158	)

The following table summarizes the derivative assets and liabilities on our consolidated balance sheet on a gross basis as of December 31, 2009 (in millions):

	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
Derivatives designated as hedging instruments:
Commodity derivatives	Other current assets	$	153	Other current liabilities	$	(140	)
	Other long-term assets	34		Other long-term liabilities	(1		)
Foreign exchange derivatives	Other long-term assets	2		Other long-term liabilities	—
Total derivatives designated as hedging instruments		$	189		$	(141	)

Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	34	Other current liabilities	$	(91	)
	Other long-term assets	41		Other long-term liabilities	(34		)
Interest rate derivatives	Other current assets	1		Other current liabilities	—
	Other long-term assets	1		Other long-term liabilities	—
Foreign exchange derivatives	Other current assets	2		Other current liabilities	(3		)
Total derivatives not designated as hedging instruments		$	79		$	(128	)

Total derivatives		$	268		$	(269	)

As of March 31, 2010, there was a net gain of $27 million deferred in AOCI. The total amount of deferred net gain recorded in AOCI is expected to be reclassified to future earnings contemporaneously with (i) the earnings recognition of the underlying hedged physical transaction, (ii) interest expense accruals associated with underlying debt instruments or (iii) the recognition of a foreign currency gain or loss upon the remeasurement of certain CAD-denominated intercompany balances. Of the total net gain deferred in AOCI at March 31, 2010, we expect to reclassify a net loss of approximately $6 million to earnings in the next twelve months. Of the remaining deferred gain in AOCI, approximately 98% is expected to be reclassified to earnings prior to 2013 with the remaining deferred gain being reclassified to earnings through 2019. These amounts are predominately based on market prices at the current period end, thus 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, 2010 no amounts were reclassed from AOCI to earnings as a result of

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anticipated hedge transactions that were no longer considered to be probable of occurring. During the three months ended March 31, 2009, we reclassed a deferred gain of approximately $6 million from AOCI to other income as a result of anticipated hedge transactions that were no longer considered to be probable of occurring.

Amounts of gain/(loss) recognized in AOCI on derivatives (effective portion) during the three months ended March 31, 2010 and March 31, 2009 are as follows (in millions):

	Three Months Ended March 31, 2010			Three Months Ended March 31, 2009
Commodity derivatives	$	(4	)	$	(72	)
Foreign exchange derivatives	(1		)	(3		)
Total	$	(5	)	$	(75	)

Our accounting policy is to offset fair value amounts associated with derivatives executed with the same counterparty when a master netting agreement exists. Accordingly, we also offset fair value amounts associated with our right to reclaim cash collateral or our obligation to pay cash collateral. When we deposit cash collateral with our brokers, we recognize a broker receivable. The account equity in our brokerage accounts is a combination of our cash balance and the fair value of our open derivatives within our brokerage account. When our account equity is less than our initial margin requirement we are required to post margin. As of March 31, 2010, we had an obligation to pay cash collateral of approximately $8 million, which was netted with the fair value of our derivatives. Our broker receivable was approximately $53 million as of December 31, 2009. At March 31, 2010 and December 31, 2009, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings.

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2010. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, which does affect the placement of assets and liabilities within the fair value hierarchy levels.

	Fair Value as of March 31, 2010 (in millions)										Fair Value as of December 31, 2009 (in millions)
Recurring Fair Value Measures(1)	Level 1		Level 2		Level 3			Total			Level 1		Level 2		Level 3			Total
Commodity derivatives	$	49	$	—	$	(7	)	$	42		$	27	$	—	$	(31	)	$	(4	)
Interest rate derivatives	—		—		3			3			—		—		2			2
Foreign currency derivatives	—		—		(1		)	(1		)	—		—		1			1
Total	$	49	$	—	$	(5	)	$	44		$	27	$	—	$	(28	)	$	(1	)

(1) Derivative assets and liabilities are presented above on a net basis but do not include related cash collateral amounts.

The determination of the fair values above includes not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit) but also the impact of our nonperformance risk on our liabilities. The fair value of our commodity derivatives, interest-rate derivatives and foreign currency derivatives includes adjustments for credit risk. We measure credit risk by deriving a probability of default from market-observed credit default swap spreads as of the measurement date. The probability of default is applied to the net credit exposure of each of our counterparties and includes a recovery rate adjustment. The recovery rate is an estimate of what would ultimately be recovered through a bankruptcy proceeding in the event of default. There were no changes to any of our valuation techniques during the period.

Level 1

Included within level 1 of the fair value hierarchy are exchange-traded commodity derivatives such as futures, options and swaps. The fair value of exchange-traded commodity derivatives is based on unadjusted quoted prices in active markets and is therefore classified within level 1 of the fair value hierarchy.

Level 2

No activity.

Level 3

Included within level 3 of the fair value hierarchy are the following derivatives:

· Commodity Derivatives: Level 3 commodity derivatives include over-the-counter commodity derivatives such as

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forwards, swaps and options and certain physical commodity contracts. The fair value of our level 3 commodity derivatives is based on either an indicative broker or dealer price quotation or a valuation model. Our valuation models utilize inputs such as price, volatility and correlation but do not involve significant management judgments.

· Interest Rate Derivatives: Level 3 interest rate derivatives include interest rate swaps. The fair value of our interest rate derivatives is based on indicative broker or dealer price quotations. Broker or dealer price quotations are corroborated with objective inputs including forward LIBOR curves and forward Treasury yields that are obtained from pricing services.

· Foreign Currency Derivatives: Level 3 foreign currency derivatives include foreign currency swaps, forward exchange contracts and options. The fair value of our foreign currency derivatives is based on indicative broker or dealer price quotations. Broker or dealer price quotations are corroborated with objective inputs including forward CAD/USD forward exchange rates that are obtained from pricing services.

The majority of our level 3 derivatives are classified as such because the broker or dealer price quotations used to measure fair value and the pricing services used to corroborate the quotations are indicative quotations rather than quotations whereby the broker or dealer is ready and willing to transact. However, the fair value of these level 3 derivatives is not based upon significant management assumptions or subjective inputs.

Rollforward of Level 3 Net Liability

The following table provides a reconciliation of changes in fair value of the beginning and ending balances for our derivatives classified as level 3 (in millions):

	Three Months Ended March 31,
	2010			2009
Beginning Balance	$	(28	)	$	74
Unrealized gains/(losses):
Included in earnings (1)	7			46
Included in other comprehensive income	—			(1		)
Settlements and derivatives entered into during the period	16			(93		)
Ending Balance	$	(5	)	$	26

Change in unrealized gains/(losses) included in earnings relating to level 3 derivatives still held at the end of the periods	$	—		$	43

(1) We reported unrealized gains and losses associated with level 3 commodity derivatives in our consolidated statements of operations as supply and logistics segment revenues. Gains and losses associated with interest rate derivatives are reported in our consolidated statements of operations as either other income, net or interest expense. Gains and losses associated with foreign currency derivatives are reported in our consolidated statements of operations as either supply and logistics segment revenues, purchases and related costs, or other income, net.

We believe that a proper analysis of our level 3 gains or losses must incorporate the understanding that these items are generally used to hedge our commodity price risk, interest rate risk and foreign currency exchange risk and are therefore offset by the underlying transactions.

Note 10—Income Taxes

U.S. Federal and State Taxes

As an MLP, we are not subject to U.S. federal income taxes; rather, the tax effect of our operations is passed through to our unitholders. Some of our U.S. corporate subsidiaries in which we have equity investments pay U.S. federal and state income taxes. Deferred income tax assets and liabilities for operations conducted through these subsidiaries are recognized for temporary differences between assets and liabilities for financial reporting and tax purposes. Although we are subject to state income taxes in some states and our subsidiaries are subject to federal and state income taxes, the impact to the three months ended March 31, 2010 and 2009 was immaterial.

Canadian Federal and Provincial Taxes

Certain of our Canadian subsidiaries are corporations for Canadian tax purposes, thus their operations are subject to Canadian

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federal and provincial income taxes. The remainder of our Canadian operations is conducted through an operating limited partnership, which has historically been treated as a flow-through entity for tax purposes. This entity is subject to Canadian legislation passed in June 2007 that imposes entity-level taxes on certain types of flow-through entities. This legislation includes safe harbor guidelines that grandfather certain existing entities (which, we believe, would include us) and delays the effective date of such legislation until 2011. Effective January 1, 2011, all income earned in our Canadian entities will be subject to Canadian federal and provincial income taxes at the Canadian corporate tax rates.

Additionally, in December 2008, the Fifth Protocol to the U.S./Canada Tax Treaty was ratified and contained language that increases the withholding tax on dividends and intercompany interest effective in 2010. As a result of these collective changes, we are in the process of reviewing our Canadian structure.

Note 11—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 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 $5 million to $6 million. In cooperation with the appropriate state and federal environmental authorities, we have 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 DOJ for further investigation in connection with a civil penalty enforcement action under the Federal Clean Water Act. We have cooperated in the investigation and are currently involved in settlement discussions with DOJ and EPA. Our assessment is that it is probable we will pay penalties related to the releases. We may also be subjected to injunctive remedies that would impose additional requirements, costs and constraints on our operations. We have accrued our current estimate of the likely penalties as a loss contingency, which is included in the estimated aggregate costs set forth above. We understand that the maximum permissible penalty, if any, that EPA could assess with respect to the subject releases under relevant statutes would be approximately $6.8 million. Such statutes contemplate the potential for substantial reduction in penalties based on mitigating circumstances and factors. We believe that several of such circumstances and factors exist, and thus have been a primary focus in our discussions with the DOJ and EPA with respect to these matters.

SemCrude L.P., et al — Debtors (U.S. Bankruptcy Court — Delaware). We will from time to time have claims relating to insolvent suppliers, customers or counterparties, such as the bankruptcy proceedings of SemCrude, which commenced in July 2008. Statutory protections and our contractual rights of setoff covered substantially all of our pre-petition claims against SemCrude. However, certain creditors of SemCrude and its affiliates have challenged our contractual and statutory rights to setoff certain of our payables to the debtor against our receivables from the debtor. One of these creditors and its affiliates have also filed Oklahoma and New Mexico state court actions alleging a producer’s lien on crude oil sold to SemCrude and its affiliates, and the continuation of such lien when SemCrude and its affiliates sold the oil to subsequent purchasers such as us. These actions have been removed to federal court and the Oklahoma federal court actions were transferred to the U.S. Bankruptcy Court in Delaware. The New Mexico federal court actions may be transferred to Bankruptcy Court, and both such federal court actions may be consolidated with our declaratory judgment action in Bankruptcy Court. The aggregate amount subject to challenge is approximately $23 million. We intend to vigorously defend our contractual and statutory rights.

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

United States of America v. 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 the pipeline 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 have been incurred and recovered under a pre-existing PPS pollution liability insurance policy. In September 2008, the EPA filed a civil complaint against PPS, a subsidiary acquired in the Pacific merger, in connection with the Pyramid Lake release. The complaint was filed in the Federal District Court for the Central District of California, Civil Action No. CV085768DSF(SSX). On March 4, 2010, the US District Court entered into a consent decree binding upon the DOJ, EPA, and PPS. PPS paid a civil penalty of $1.3 million (which was covered by insurance)

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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 help prevent releases, damages and liabilities incurred due to any such releases from our assets may substantially affect our business. As we expand our pipeline assets through acquisitions, we typically improve on (reduce) the releases from such assets (in terms of frequency or volume) as we implement our procedures, remove selected assets from service and spend capital to upgrade the assets. 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 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, 2010, our reserve for environmental liabilities totaled approximately $63 million, of which approximately $9 million is classified as short-term and $54 million is classified as long-term. At March 31, 2010, we have recorded receivables totaling approximately $4 million for amounts that are probable of recovery under insurance and from third parties under indemnification agreements.

In some cases, the actual cash expenditures may not occur for three to five years. Our estimates used in these reserves are based on known facts and believed to be relevant at the time and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment and the possibility of existing legal claims giving rise to additional claims. Therefore, although we believe that the reserve is adequate, costs incurred may be in excess of the reserve and may potentially have a material adverse effect on our financial condition, results of operations, or cash flows.

Insurance

A pipeline, terminal or other facility may experience damage as a result of an accident, natural disaster or terrorist activity. 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 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 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 and wind damage exposures, incorporate higher retention in our insurance arrangements, pay higher premiums or some combination of such actions.

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 conditions, results of operations or cash flows.

Note 12—Operating Segments

We manage our operations through three operating segments: (i) Transportation, (ii) Facilities and (iii) Supply and Logistics. The following table reflects certain financial data for each segment for the periods indicated (in millions):

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	Transportation		Facilities		Supply & Logistics		Total
Three Months Ended March 31, 2010
Revenues:
External Customers	$	138	$	75	$	5,912	$	6,125
Intersegment (1)	112		39		—		151
Total revenues of reportable segments	$	250	$	114	$	5,912	$	6,276
Equity earnings of unconsolidated entities	$	1	$	—	$	—	$	1
Segment profit (2) (3) (4)	$	127	$	59	$	93	$	279
Maintenance capital	$	7	$	3	$	1	$	11

Three Months Ended March 31, 2009
Revenues:
External Customers	$	123	$	47	$	3,132	$	3,302
Intersegment (1)	102		30		1		133
Total revenues of reportable segments	$	225	$	77	$	3,133	$	3,435
Equity earnings of unconsolidated entities	$	1	$	2	$	—	$	3
Segment profit (2) (3) (4)	$	112	$	46	$	159	$	317
Maintenance capital	$	14	$	6	$	2	$	22

(1) Segment revenues and purchases and related costs include intersegment amounts. Intersegment sales are conducted at posted tariff rates, rates similar to those charged to third parties or rates that we believe approximate market rates. For further discussion, see “Analysis of Operating Segments” under Item 7 of our 2009 Annual Report on Form 10-K.

(2) Gains/losses from derivative activities are included in supply and logistics revenues and to a lesser extent facilities revenues and impact segment profit.

(3) Supply and logistics segment profit includes interest expense on contango inventory purchases of $3 million and $2 million for the three months ended March 31, 2010 and 2009, respectively.

(4) The following table reconciles segment profit to net income (in millions):

	For the Three Months
	Ended March 31,
	2010			2009
Segment profit	$	279		$	317
Depreciation and amortization	(67		)	(58		)
Interest expense	(58		)	(51		)
Other income/(expense), net	(3		)	4
Income tax expense	—			(1		)
Net income	$	151		$	211

Note 13 — Supplemental Condensed Consolidating Financial Information

For purposes of this Note 13, Plains is referred to as “Parent.” See Note 13 to our Consolidated Financial Statements included in Part IV of our 2009 Annual Report on Form 10-K for further detail regarding subsidiaries classified as “Guarantor Subsidiaries” and subsidiaries classified as “Non-Guarantor Subsidiaries.” There have been no material changes in the entities that constitute our guarantor and non-guarantor subsidiaries since December 31, 2009.

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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 (in millions):

Condensed Consolidating Balance Sheet

	As of March 31, 2010
			Combined		Combined
			Guarantor		Non-Guarantor
	Parent		Subsidiaries		Subsidiaries		Eliminations			Consolidated
ASSETS
Total current assets	$	3,065	$	3,523	$	237	$	(3,484	)	$	3,341
Property, plant and equipment, net	—		4,663		1,749		—			6,412
Other assets, net	5,602		4,007		367		(7,627		)	2,349
Total assets	$	8,667	$	12,193	$	2,353	$	(11,111	)	$	12,102

LIABILITIES AND PARTNERS’ CAPITAL
Total current liabilities	$	320	$	6,364	$	296	$	(3,484	)	$	3,496
Long-term debt	4,138		6		474		(474		)	4,144
Other long-term liabilities	—		249		4		—			253
Total liabilities	4,458		6,619		774		(3,958		)	7,893

Partners’ capital excluding noncontrolling interest	4,146		5,511		1,579		(7,090		)	4,146
Noncontrolling interest	63		63		—		(63		)	63
Total partners’ capital	4,209		5,574		1,579		(7,153		)	4,209

Total liabilities and partners’ capital	$	8,667	$	12,193	$	2,353	$	(11,111	)	$	12,102

	As of December 31, 2009
			Combined		Combined
			Guarantor		Non-Guarantor
	Parent		Subsidiaries		Subsidiaries		Eliminations			Consolidated
ASSETS
Total current assets	$	3,428	$	3,831	$	209	$	(3,810	)	$	3,658
Property, plant and equipment, net	—		4,606		1,734		—			6,340
Other assets, net	5,324		3,994		367		(7,325		)	2,360
Total assets	$	8,752	$	12,431	$	2,310	$	(11,135	)	$	12,358

LIABILITIES AND PARTNERS’ CAPITAL
Total current liabilities	$	456	$	6,849	$	287	$	(3,810	)	$	3,782
Long-term debt	4,137		15		450		(460		)	4,142
Other long-term liabilities	—		271		4		—			275
Total liabilities	4,593		7,135		741		(4,270		)	8,199

Partners’ capital excluding noncontrolling interest	4,096		5,233		1,569		(6,802		)	4,096
Noncontrolling interest	63		63		—		(63		)	63
Total partners’ capital	4,159		5,296		1,569		(6,865		)	4,159

Total liabilities and partners’ capital	$	8,752	$	12,431	$	2,310	$	(11,135	)	$	12,358

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Condensed Consolidating Statements of Operations

	Three Months Ended March 31, 2010
				Combined			Combined
				Guarantor			Non-Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Net operating revenues (1)	$	—		$	452		$	50		$	—		$	502
Field operating costs	—			(149		)	(13		)	—			(162		)
General and administrative expenses	—			(54		)	(8		)	—			(62		)
Depreciation and amortization	(1		)	(55		)	(11		)	—			(67		)

Operating income/(loss)	(1		)	194			18			—			211

Equity earnings in unconsolidated entities	215			16			—			(230		)	1
Interest income/(expense)	(63		)	8			(3		)	—			(58		)
Other income, net	—			(3		)	—			—			(3		)
Income tax expense	—			—			—			—			—
Net income	151			215			15			(230		)	151

	Three Months Ended March 31, 2009
				Combined			Combined
				Guarantor			Non-Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Net operating revenues (1)	$	—		$	484		$	28		$	—		$	512
Field operating costs	—			(143		)	(9		)	—			(152		)
General and administrative expenses	—			(44		)	(2		)	—			(46		)
Depreciation and amortization	(1		)	(51		)	(6		)	—			(58		)

Operating income/(loss)	(1		)	246			11			—			256

Equity earnings in unconsolidated entities	265			12			—			(274		)	3
Interest expense	(52		)	1			—			—			(51		)
Other income, net	(1		)	5			—			—			4
Income tax expense	—			(1		)	—			—			(1		)
Net income	211			263			11			(274		)	211

(1) Net operating revenues are calculated as “Total revenues” less “Purchases and related costs.”

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Condensed Consolidating Statements of Cash Flows

	Three Months Ended March 31, 2010
				Combined			Combined
				Guarantor			Non-Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	151		$	215		$	15		$	(230	)	$	151
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	1			55			11			—			67
Equity compensation charge	—			19			—			—			19
Equity earnings in unconsolidated subsidiaries, net of distributions	(215		)	(15		)	—			230			—
Other	—			(3		)	—			—			(3		)
Changes in assets and liabilities, net of acquisitions	365			(214		)	6			—			157
Net cash provided by (used in) operating activities	302			57			32			—			391

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property, equipment and other	—			(76		)	(28		)	—			(104		)
Net cash received for linefill	—			(6		)	—			—			(6		)
Proceeds from the sale of assets and other	—			2			—			—			2
Net cash used in investing activities	—			(80		)	(28		)	—			(108		)

CASH FLOWS FROM FINANCING ACTIVITIES
Net repayments on revolving credit facility	(136		)	(91		)	—			—			(227		)
Net repayments on short-term letter of credit and hedged inventory facility	—			100			—			—			100
Distributions paid to common unitholders and general partner	(166		)	—			—			—			(166		)
Other financing activities	—			1			—			—			1
Net cash provided by (used in) financing activities	(302		)	10			—			—			(292		)

Net increase/(decrease) in cash and cash equivalents	—			(13		)	4			—			(9		)
Cash and cash equivalents, beginning of period	1			19			5			—			25
Cash and cash equivalents, end of period	$	1		$	6		$	9		$	—		$	16

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Condensed Consolidating Statements of Cash Flows (continued)

	Three Months Ended March 31, 2009
				Combined			Combined
				Guarantor			Non-Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	211		$	263		$	11		$	(274	)	$	211
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	1			51			6			—			58
Equity compensation charge	—			11			—			—			11
Deferred gains on settled hedges, net	—			9			—			—			9
Other	(263		)	(15		)	—			274			(4		)
Changes in assets and liabilities, net of acquisitions	235			(30		)	(12		)	—			193
Net cash provided by operating activities	184			289			5			—			478

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property, equipment and other	—			(111		)	(5		)	—			(116		)
Investment in unconsolidated entities	(2		)	—			—			—			(2		)
Cash received for sale of noncontrolling interest in a subsidiary	—			26			—			—			26
Proceeds from the sale of assets and other	—			4			—			—			4
Net cash used in investing activities	(2		)	(81		)	(5		)	—			(88		)

CASH FLOWS FROM FINANCING ACTIVITIES
Net repayments on revolving credit facility	(252		)	(292		)	—			—			(544		)
Net borrowings on short-term letter of credit and hedged inventory facility	—			78			—			—			78
Net proceeds from the issuance of common units	210			—			—			—			210
Distributions paid to common unitholders and general partner	(140		)	—			—			—			(140		)
Net cash used in financing activities	(182		)	(214		)	—			—			(396		)

Effect of translation adjustment on cash	—			2			—			—			2

Net decrease in cash and cash equivalents	—			(4		)	—			—			(4		)
Cash and cash equivalents, beginning of period	2			9			—			—			11
Cash and cash equivalents, end of period	$	2		$	5		$	—		$	—		$	7

Note 14 — Subsequent Events

On May 5, 2010, PNG completed its IPO of 13,478,000 common units representing limited partner interests at $21.50 per common unit. The number of units issued at closing included 1,758,000 common units issued pursuant to the full exercise of the underwriters’ over-allotment option. Net proceeds received by PNG from the sale of the 13,478,000 common units were approximately $269 million. The common units offered represent approximately 23% of the outstanding equity of PNG. We own the remaining 77% equity interests in PNG.

In connection with the IPO, PNG entered into a new $400 million revolving credit facility, which will mature on May 5, 2013. PNG borrowed approximately $200 million under the credit facility as of the closing of the IPO.

PNG will use the net proceeds from the IPO, together with $200 million of borrowings under its new credit facility, to repay intercompany indebtedness owed to us. We expect to use all of these proceeds to repay amounts outstanding under our credit facilities and for general partnership purposes.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Introduction

The following discussion is intended to provide investors with an understanding of our financial condition and results of our operations and should be read in conjunction with our historical consolidated financial statements and accompanying notes and Management’s Discussion and Analysis of Financial Condition and Results of Operations as presented in our 2009 Annual Report on Form 10-K. For more detailed information regarding the basis of presentation for the following financial information, see the “Notes to the Condensed Consolidated Financial Statements.”

Executive Summary

We provide transportation, storage, terminalling, supply and logistics services with respect to crude oil, refined products and LPG. We are also engaged in the development and operation of natural gas storage facilities. We were formed in 1998, and our operations are conducted directly and indirectly through our operating subsidiaries and are managed through three operating segments: (i) Transportation, (ii) Facilities and (iii) Supply and Logistics.

Our discussion and analysis herein includes the following:

· Internal Growth Projects

· Results of Operations

· Liquidity and Capital Resources

· Recent Accounting Pronouncements

· Critical Accounting Policies and Estimates

· Forward-Looking Statements

Internal Growth Projects

The following table summarizes our capital expenditures for internal growth projects, maintenance capital and investments in unconsolidated entities for the periods indicated (in millions):

	Three Months
	Ended March 31,
	2010		2009
Internal growth projects	$	76	$	79
Maintenance capital	11		22
Investment in unconsolidated entities	—		2
Total	$	87	$	103

Our internal growth projects primarily relate to the construction and expansion of pipeline systems, crude oil storage and terminal facilities and natural gas storage facilities. The following table summarizes our more notable projects in progress during 2010 and the forecasted expenditures for the year (in millions):

Projects	2010
PAA Natural Gas Storage	$	95
Patoka Phase III	24
West Texas gathering lines	18
Cushing - Phase VII	17
St. James - Phase III tankage	15
Cushing - Phase VIII	15
Wichita Falls tankage	11
Bumstead facility upgrade	10
Other projects (1)	155
	360
Maintenance capital	85
Total Projected Capital Expenditures (excluding acquisitions)	$	445

(1) Primarily pipeline connections and upgrades, truck stations, new tank construction and refurbishing, and carry-over of projects started in 2009.

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Results of Operations

We manage our operations through three operating segments: (i) Transportation, (ii) Facilities and (iii) Supply and Logistics. In order to evaluate segment performance, management focuses on a variety of measures including segment profit, segment volumes, segment profit per barrel and maintenance capital. See Note 15 to our Consolidated Financial Statements included in Part IV of our 2009 Annual Report on Form 10-K for further discussion on how we evaluate segment performance.

The following table reflects our segment profit, net income and applicable earnings per limited partner unit for the three months ended March 31, 2010 and 2009 (in millions, except per unit amounts):

	Three Months						Favorable/(Unfavorable)
	Ended March 31,						Variance
	2010			2009			$			%
Transportation segment profit	$	127		$	112		$	15		13	%
Facilities segment profit	59			46			13			28	%
Supply & Logistics segment profit	93			159			(66		)	(42	)%
Total segment profit	279			317			(38		)	(12	)%
Depreciation and amortization	(67		)	(58		)	(9		)	(16	)%
Interest expense	(58		)	(51		)	(7		)	(14	)%
Other income/(expense), net	(3		)	4			(7		)	(175	)%
Income tax expense	—			(1		)	1			100	%
Net income	$	151		$	211		$	(60	)	(28	)%

Earnings per basic limited partner unit	$	0.80		$	1.42		$	(0.62	)	(44	)%
Earnings per diluted limited partner unit	$	0.80		$	1.41		$	(0.61	)	(43	)%
Basic weighted average units outstanding	136			124			12			10	%
Diluted weighted average units outstanding	137			125			12			10	%

Analysis of Operating Segments

Transportation Segment

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

	Three Months						Favorable/(Unfavorable)
Operating Results (1)	Ended March 31,						Variance
(in millions, except per barrel amounts)	2010			2009			$			%
Revenues (1)
Tariff activities	$	225		$	201		$	24		12	%
Trucking	25			24			1			4	%
Total transportation revenues	250			225			25			11	%

Costs and Expenses (1)
Trucking costs	(16		)	(16		)	—			—	%
Field operating costs (excluding equity compensation expense)	(81		)	(78		)	(3		)	(4	)%
Equity compensation expense - operations (2)	(3		)	(1		)	(2		)	(200	)%
Segment G&A expenses (excluding equity compensation expense)	(17		)	(14		)	(3		)	(21	)%
Equity compensation expense - general and administrative (2)	(7		)	(5		)	(2		)	(40	)%
Equity earnings in unconsolidated entities	1			1			—			—	%
Segment profit	$	127		$	112		$	15		13	%
Maintenance capital	$	7		$	14		$	7		50	%
Segment profit per barrel	$	0.51		$	0.43		$	0.08		19	%

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	Three Months		Favorable/(Unfavorable)
Average Daily Volumes	Ended March 31,		Variance
(in thousands of barrels per day) (3)	2010	2009	Volumes		%
Tariff activities
All American	39	35	4		11	%
Basin	358	393	(35	)	(9	)%
Capline	159	206	(47	)	(23	)%
Line 63/Line 2000	110	121	(11	)	(9	)%
Salt Lake City Area Systems	128	104	24		23	%
West Texas/New Mexico Area Systems	365	395	(30	)	(8	)%
Manito	61	65	(4	)	(6	)%
Rainbow	192	195	(3	)	(2	)%
Rangeland	48	59	(11	)	(19	)%
Refined products	115	97	18		19	%
Other	1,130	1,141	(11	)	(1	)%
Tariff activities total	2,705	2,811	(106	)	(4	)%
Trucking	88	89	(1	)	(1	)%
Transportation segment total	2,793	2,900	(107	)	(4	)%

(1) Revenues and costs and expenses include intersegment amounts.

(2) Equity compensation expense related to our equity compensation plans. See Note 8 to our Condensed Consolidated Financial Statements for additional discussion of our equity compensation plans.

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

Transportation segment profit and segment profit per barrel were impacted by the following:

As noted in the table above, our transportation segment revenues increased approximately 11% for the three months ended March 31, 2010 compared to the three months ended March 31, 2009 while volumes decreased approximately 4%. The significant variances between the comparative periods are discussed below:

· Loss Allowance Revenue - As is common in the industry, our tariffs incorporate a loss allowance factor that is intended to, among other things, offset losses due to evaporation, measurement and other losses in transit. We value the variance of allowance volumes to actual losses at the estimated net realizable value (including the impact of gains and losses from derivative-related activities) at the time the variance occurred and the result is recorded as either an increase or decrease to tariff revenues. The loss allowance revenue increase of approximately $10 million was primarily due to higher average realized price per barrel for the three months ended March 31, 2010 compared to the three months ended March 31, 2009 (including the impact of gains from derivative activities).

· Foreign Currency Impact - Revenues and expenses from our Canadian based subsidiaries, which use the Canadian dollar as their functional currency, were translated at the prevailing average exchange rate for each month. During 2010, revenues from some of our Canadian pipeline systems were favorably impacted by the depreciation of the U.S. dollar relative to the Canadian dollar. The average Canadian dollar to U.S. dollar exchange rate for the three-month period ended March 31, 2010 was $1.04 CAD: $1.00 USD compared to an average of $1.25 CAD: $1.00 USD for the three-month period ended March 31, 2009.

· Tariff Rates - Tariff rates increased on certain of our pipeline systems during the second half of 2009 as a result of indexing by the FERC. In addition, we had similar type rate increases on some non-FERC regulated pipelines.

· Other Factors – Such favorable revenue variances were partially offset by volume declines primarily resulting from refinery turnarounds and downtime.

Field Operating Costs. Field operating costs (excluding equity compensation charges) increased in the first quarter of 2010 over the first quarter of 2009 primarily due to an approximately $3 million unfavorable foreign currency impact.

General and Administrative Expenses. General and administrative expenses (excluding equity compensation charges) increased in the three months ended March 31, 2010 compared to the three months ended March 31, 2009 primarily due to foreign currency impact.

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Maintenance Capital. The decrease in maintenance capital in the first quarter ended 2010 compared to first quarter ended 2009 is primarily due to (i) increased investment in 2009 applicable to API 653 repairs in an effort to meet our May 2009 compliance deadline and (ii) timing of various repair projects during each year.

Facilities Segment

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

	Three Months						Favorable/(Unfavorable)
Operating Results	Ended March 31,						Variance
(in millions, except per barrel amounts)	2010			2009			$			%
Storage and terminalling revenues (1)	$	114		$	77		$	37		48	%
Storage related costs (natural gas related)	(7		)	—			(7		)	N/A
Field operating costs	(35		)	(27		)	(8		)	(30	)%
Segment G&A expenses (excluding equity compensation expense)	(10		)	(4		)	(6		)	(150	)%
Equity compensation expense - general and administrative (2)	(3		)	(2		)	(1		)	(50	)%
Equity earnings in unconsolidated entities	—			2			(2		)	(100	)%
Segment profit	$	59		$	46		$	13		28	%
Maintenance capital	$	3		$	6		$	3		50	%
Segment profit per barrel	$	0.30		$	0.26		$	0.04		15	%

	Three Months		Favorable/(Unfavorable)
	Ended March 31,		Variance
Volumes (3)(4)(5)	2010	2009	Volumes		%
Crude oil, refined products and LPG storage
(average monthly capacity in millions of barrels)	59	55	4		7	%
Natural gas storage
(average monthly capacity in billions of cubic feet)	40	15	25		167	%
LPG processing
(average throughput in thousands of barrels per day)	11	14	(3	)	(21	)%
Facilities segment total
(average monthly capacity in millions of barrels)	66	58	8		14	%

(1) Includes intersegment amounts.

(2) Equity compensation expense related to our equity compensation plans. See Note 8 to our Condensed Consolidated Financial Statements for additional discussion of our equity compensation plans.

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

(4) Facilities total calculated as the sum of: (i) crude oil, refined products and LPG storage capacity; (ii) natural gas storage capacity divided by 6 to account for the 6:1 mcf of gas to crude oil barrel ratio; and (iii) LPG processing volumes multiplied by the number of days in the period and divided by the number of months in the period.

(5) In September 2009, we acquired the remaining 50% indirect interest in PNGS, which resulted in our 100% ownership of the natural gas storage business and related operating entities. Therefore, natural gas storage volumes for January through March 2009 are netted to our 50% interest in PNGS. January through March 2010 volumes represent our 100% interest in PNGS.

Facilities segment profit and segment profit per barrel were impacted by the following:

As noted in the table above, our facilities segment revenues (less storage related costs) and volumes increased for the three months ended March 31, 2010 compared to the three months ended March 31, 2009. The significant variances in revenues and average monthly volumes between the comparative periods are discussed below:

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	Three Months						Favorable/(Unfavorable)
Operating Results (1)	Ended March 31,						Variance
(in millions, except per barrel amounts)	2010			2009			$			%
Revenues	$	5,912		$	3,133		$	2,779		89	%
Purchases and related costs (2)	(5,749		)	(2,904		)	(2,845		)	(98	)%
Field operating costs	(45		)	(49		)	4			8	%
Segment G&A expenses (excluding equity compensation expense)	(19		)	(18		)	(1		)	(6	)%
Equity compensation expense - general and administrative (3)	(6		)	(3		)	(3		)	(100	)%
Segment profit	$	93		$	159		$	(66	)	(42	)%
Maintenance capital	$	1		$	2		$	1		50	%
Segment profit per barrel (4)	$	1.22		$	2.04		$	(0.82	)	(40	)%

	Three Months		Favorable/(Unfavorable)
Average Daily Volumes (5)	Ended March 31,		Variance
(in thousands of barrels per day)	2010	2009	Volumes		%
Crude oil lease gathering purchases	603	631	(28	)	(4	)%
LPG sales	134	144	(10	)	(7	)%
Waterborne foreign crude oil imported	72	58	14		24	%
Refined products sales	39	36	3		8	%
Supply & Logistics segment total	848	869	(21	)	(2	)%

(1) Revenues and costs include intersegment amounts.

(2) Purchases and related costs include interest expense (related to hedged inventory purchases) of approximately $3 million and $2 million for the three months ended March 31, 2010 and March 31, 2009, respectively.

(3) Equity compensation expense related to our equity compensation plans. See Note 8 to our Condensed Consolidated Financial Statements for additional discussion of our equity compensation plans.

(4) Calculated based on crude oil lease gathering purchased volumes, refined products volumes, LPG sales volumes and waterborne foreign crude oil imported volumes.

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

The absolute amount of our revenues and purchases increased in the first quarter of 2010 as compared to the first quarter of 2009, primarily resulting from higher commodity prices experienced in the 2010 period. The NYMEX benchmark price of crude oil ranged from $70 to $84 per barrel and $33 to $55 per barrel during the first quarter of 2010 and 2009, respectively. Because the commodities that we buy and sell are generally indexed to the same pricing indices for both the purchase and sale, revenues and costs related to purchases will fluctuate with market prices. However, the margins related to those purchases and sales will not necessarily have a corresponding increase or decrease.

Generally, we expect a base level of earnings from our supply and logistics segment that may be optimized and enhanced when there is a high level of market volatility, favorable basis differentials and/or a steep contango or backwardated market structure. In addition, certain of our subsidiaries are based in Canada and use the Canadian dollar as their functional currency. Revenues and expenses are translated at average exchange rates prevailing for each month and comparison between periods may be impacted by changes in the average exchange rates.

Also, our LPG marketing operations are weather-sensitive, particularly during the approximate six-month peak heating season of October through March, and temperature differences from year to year may have a significant effect on financial performance.

Average daily volumes also decreased by approximately 21,000 barrels per day during the same comparative periods primarily due to the elimination of some of our less profitable lease gathering purchases and lower LPG sales volumes. Revenues, net of purchases and related costs, decreased by approximately $66 million or 29% during the first quarter of 2010 as compared to the first quarter of 2009. Such decrease was primarily due to the following:

· Derivative activities, net of inventory valuation adjustments, produced a gain of approximately $18 million during the first quarter of 2010 compared to a net gain of approximately $45 million during the first quarter of 2009 for an unfavorable approximately $27 million. The derivative gains recognized during the first quarter of 2010 are generally offset by future physical positions that are not included in the mark-to-market calculation;

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· Less favorable differentials during the first quarter of 2010 compared to the first quarter of 2009, which unfavorably impacted results. Operating results were further negatively impacted by adverse weather conditions that affected field operations during January and February of 2010 compared to the same months during 2009;

· A weak contango market during the first quarter of 2010 compared to the stronger contango market experienced during the corresponding prior year period; and

· Lower LPG marketing sales margins related to relatively warmer weather during the 2010 period, which unfavorably impacted results by approximately $9 million for the comparative periods.

Our results were favorably impacted, however, during the first quarter of 2010 compared to the first quarter of 2009 as a result of the depreciation of the USD relative to the CAD. The average CAD to USD exchange rate for the three-month period ended March 31, 2010 was $1.04 CAD: $1.00 USD compared to an average of $1.25 CAD: $1.00 USD for the three-month period ended March 31, 2009.

Field Operating Costs. Field operating costs decreased in the first quarter of 2010 compared to the first quarter of 2009 primarily as a result of decreases in third party trucking fees, reduced fleet maintenance costs as aging fleet has been replaced and reductions in various other repairs and maintenance costs.

Equity Compensation Charges. Equity compensation charges increased over the first quarter of 2010 compared to the first quarter of 2009 primarily as a result of an increase in unit price. The fair value of our outstanding equity compensation awards, which is recognized in expense over the service period, is primarily derived from the market price of our common units as of the measurement date. At the end of the first quarter of 2010, our unit price was $56.90 per common unit as compared to $36.76 per common unit at the end of the first quarter of 2009. See Note 8 to our Condensed Consolidated Financial Statements for additional information on our equity compensation plans.

Other Income and Expenses

Depreciation and Amortization. Depreciation and amortization expense increased approximately $9 million for the three months ended March 31, 2010 compared to the three months ended March 31, 2009. Such increases were primarily the result of an increased amount of depreciable assets resulting from our acquisition activities including PNGS as well as various internal growth projects.

Interest Expense. Interest expense for the three months ended March 31, 2010 increased approximately $7 million in comparison to the three months ended March 31, 2009. The following table presents the significant variances in interest expense during the three months ended March 31, 2010 compared to the three months ended March 31, 2009 (in millions):


Impact of retirement of senior notes (1)	$	(6	)
Impact of issuance of senior notes (2)	20
Impact of decreased borrowings under credit facilities	(1		)
Impact of increased capitalized interest	(4		)
Other	(2		)
	$	7

(1) In August 2009, our outstanding $175 million 4.75% senior notes due 2009 matured and were paid. In October 2009, we redeemed our outstanding $250 million 7.13% senior notes due 2014.

(2) In April, July and September 2009 we completed the issuances of $350 million of 8.75% senior notes due 2019, $500 million of 4.25% senior notes due 2012 and $500 million of 5.75% senior notes due 2020, respectively. A fluctuating portion of the 4.25% senior notes due 2012 is utilized to fund hedged inventory and would be classified as short-term debt if such activities were funded through our credit facilities. Interest costs attributable to borrowings for inventory stored in a contango market are included in “Purchases and related costs” in our supply and logistics segment profits as we consider interest on these borrowings a direct cost to storing the inventory. The costs applicable to the portion of the $500 million of 4.25% senior notes that was recognized within purchases and related costs was less than $1 million for the three months ended March 31, 2010.

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Other Income/Expense, Net. Other income/(expense), net for the three months ended March 31, 2010, primarily included (i) a net loss of approximately $2 million related to the foreign currency revaluation of a CAD-denominated interest receivable associated with an intercompany note and the impact of related foreign currency hedges and (ii) a net loss of approximately $1 million recognized in connection with the fair value adjustment associated with the contingent consideration in connection with the PNGS acquisition.

Other income/(expense), net for the three months ended March 31, 2009, primarily included a gain of approximately $4 million related to the foreign currency revaluation of a CAD-denominated interest receivable associated with an intercompany note and the impact of related foreign currency hedges.

Liquidity and Capital Resources

General

Our primary cash requirements include, but are not limited to (i) ordinary course of business uses, such as the payment of amounts related to the purchase of crude oil and other products and other expenses, interest payments on our outstanding debt and distributions to our unitholders and General Partner, (ii) maintenance and expansion activities, (iii) acquisitions of assets or businesses and (iv) repayment of principal on our long-term debt. We generally expect to fund our short-term cash requirements through our primary sources of liquidity, which consist of our cash flow generated from operations as well as borrowings under our credit facilities. In addition, we generally expect to fund our long-term needs, such as those resulting from expansion activities or acquisitions, through a variety of sources (either separately or in combination), which may include operating cash flows, borrowings under our credit facilities, and/or the issuance of additional equity or debt securities. At March 31, 2010, we had a working capital deficit of approximately $155 million and approximately $1.1 billion of liquidity available to meet our ongoing operational, investing and finance needs as noted below (in millions):

	As of
	March 31, 2010
Availability under our senior unsecured revolving credit facility	$	944
Availability under our senior secured hedged inventory facility	100
Cash and cash equivalants	16
Total (1)	$	1,060

(1) Our consolidated liquidity at March 31, 2010, on a pro forma basis to include the PNG IPO, would increase to approximately $1.7 billion (including approximately $200 million available capacity under PNG’s revolving credit facility). See Note 14 to our Condensed Consolidated Financial Statements for additional information related to the PNG IPO.

We believe that we have and will continue to have the ability to access our credit facilities, which we use to meet our short-term cash needs. We believe that our financial position remains strong and we have sufficient liquidity; however, extended disruptions in the financial markets and/or energy price volatility that adversely affect our business may have a material adverse effect on our financial condition, results of operations or cash flows. See Item 1A. “Risk Factors” in our 2009 Annual Report on Form 10-K for further discussion regarding risks that may impact our liquidity and capital resources. Usage of the credit facilities is subject to ongoing compliance with covenants. We are currently in compliance with all covenants.

Cash Flows from Operating Activities

For a comprehensive discussion of the primary drivers of our cash flow from operations, including the impact of varying market conditions and the timing of settlement of our derivative activities, see “Liquidity and Capital Resources—Cash Flow from Operations” under Item 7 of our 2009 Annual Report on Form 10-K.

Net cash flow provided from operating activities was approximately $391 million for the first three months of 2010 compared to approximately $478 million for the first three months of 2009. Our cash flow from operations can be significantly impacted in periods when we are increasing or decreasing the amount of inventory in storage.

During the first quarter of 2010, we decreased the amount of our inventory. The decrease in inventory was primarily related to the sale of LPG inventory resulting from end users’ increased demand for heating requirements in the winter months. The decrease in LPG inventory was partially offset by an increase to our crude oil contango market storage activities in both volumes and an increase in prices in the first quarter of 2010. The net proceeds received from liquidation of inventory during the quarter were used to repay borrowings under our credit facilities and favorably impacted our cash flow from operating activities.

During the first quarter of 2009, we decreased the amount of our inventory. The decrease in inventory was primarily related to the sale of LPG inventory resulting from end users’ increased demand for heating requirements in the winter months. The decrease in LPG inventory was partially offset by an increase in crude oil inventory related to the strong contango market in the first quarter of 2009. These net volumetric decreases were further impacted by lower prices for our inventory purchases during the quarter compared to prior year amounts. The net proceeds received from liquidation of inventory during the quarter were used to repay borrowings under our credit facilities and favorably impacted our cash flow from operating activities.

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Equity and Debt Financing Activities

Our financing activities primarily relate to funding acquisitions and internal capital projects, and short-term working capital and hedged inventory borrowings related to our LPG business and contango market activities. Our financing activities have primarily consisted of equity offerings, senior notes offerings and borrowings and repayments under our credit facilities.

Registration Statements. We periodically access the capital markets for both equity and debt financing. As of March 31, 2010, approximately $2.0 billion of unsold securities remained available under our shelf registration statement declared effective on December 16, 2009. We also have access to a universal shelf registration statement, which provides us with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and our capital needs.

Equity Offerings. In March 2009, we completed the issuance of 5,750,000 common units at $36.90 per unit for net proceeds of approximately $210 million. The net proceeds include our general partner’s proportionate capital contribution and is reflected net of costs associated with the offering.

Credit Facilities. During the three months ended March 31, 2010 and 2009, we had net repayments on our revolving credit facility and our hedged inventory facility of approximately $127 million and $466 million, respectively. These net repayments resulted primarily from sales of LPG inventory that was liquidated during the respective quarter. For further discussion related to our credit facilities and long-term debt, see “Cash Flow from Operations” above and “Liquidity and Capital Resources—Credit Facilities and Long-Term Debt” under Item 7 of our 2009 Annual Report on Form 10-K.

Subsequent Events. In connection with the PNG IPO, PNG entered into a new $400 million revolving credit facility, which matures on May 5, 2013. PNG borrowed approximately $200 million under the credit facility as of the closing of the PNG IPO.

PNG will use the net proceeds from the PNG IPO, together with $200 million of borrowings under its new credit facility, to repay intercompany indebtedness owed to us. We expect to use all of these proceeds to repay amounts outstanding under our credit facilities and for general partnership purposes. See Note 14 to our Condensed Consolidated Financial Statements for additional information related to the PNG IPO.

Capital Expenditures and Distributions Paid to Unitholders and General Partner

We use cash primarily for our acquisition activities, internal growth projects and distributions paid to our unitholders and general partner. We have made and will continue to make capital expenditures for acquisitions, expansion capital and maintenance capital. Historically, we have financed these expenditures primarily with cash generated by operations and the financing activities discussed above. See “Internal Growth Projects” above and “Acquisitions and Internal Growth Projects” under Item 7 of our 2009 Annual Report on Form 10-K for further discussion for such capital expenditures.

Distributions to unitholders and general partner. We distribute 100% of our available cash within 45 days after the end of each quarter to unitholders of record and to our general partner. Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter less reserves established in the discretion of our general partner for future requirements. On May 14, 2010, we will pay a quarterly distribution of $0.9350 per limited partner unit. This distribution represented a year-over-year distribution increase of approximately 3.3%. See Note 7 to our Condensed Consolidated Financial Statements for details of distributions paid. Also, see Item 5. “Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities—Cash Distribution Policy” of our 2009 Annual Report on Form 10-K for additional discussion of distribution thresholds.

Upon closing of the Pacific, Rainbow and PNGS acquisitions, our general partner agreed to reduce the amounts due as incentive distributions. See Note 7 to our Condensed Consolidated Financial Statements for details related to the general partner’s incentive distribution reduction.

We believe that we have sufficient liquid assets, cash flow from operations and borrowing capacity under our credit agreements to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. We are subject to business and operational risks, however, that could adversely affect our cash flow. A material decrease in our cash flows would likely produce an adverse effect on our borrowing capacity.

Contingencies

See Note 11 to our Condensed Consolidated Financial Statements.

Commitments

Contractual Obligations. In the ordinary course of doing business, we purchase crude oil and LPG from third parties under contracts, the majority of which range in term from thirty-day evergreen to three years. We establish a margin for these purchases by entering into various types of physical and financial sale and exchange transactions through which we seek to maintain a position that is substantially balanced between purchases on the one hand and sales and future delivery obligations on the other. Where applicable, the amounts presented represent the net obligations associated with buy/sell contracts and those subject to a net

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settlement arrangement with the counterparty. We do not expect to use a significant amount of internal capital to meet these obligations, as the obligations will be funded by corresponding sales to creditworthy entities.

The following table includes our best estimate of the amount and timing of these payments as well as others due under the specified contractual obligations as of March 31, 2010 that varied significantly since December 31, 2009 (in millions):

											2015 and
	2010		2011		2012		2013		2014		Thereafter		Total
Long-term debt and interest payments (1)	$	66	$	261	$	950	$	472	$	208	$	4,933	$	6,890
Leases (2)	$	65	$	64	$	55	$	34	$	24	$	242	$	484
Crude oil, refined products and LPG purchases (3)	$	5,597	$	984	$	625	$	246	$	241	$	10	$	7,703

(1) Includes debt service payments, interest payments due on our senior notes and the commitment fee on our revolving credit facility. Although there is an outstanding balance on our revolving credit facility at March 31, 2010, we historically repay and borrow at varying amounts. As such, we have included only the maximum commitment fee (as if no amounts were outstanding on the facility) in the amounts above.

(2) Leases are primarily for (i) storage, (ii) rights-of-way, (iii) office rent, (iv) pipeline assets and (v) trucks used in our gathering activities.

(3) Amounts are based on estimated volumes and market prices based on average activity during March 2010. The actual physical volume purchased and actual settlement prices will vary from the assumptions used in the table. Uncertainties involved in these estimates include levels of production at the wellhead, weather conditions, changes in market prices and other conditions beyond our control.

Letters of Credit. In connection with our crude oil supply and logistics activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligations for the purchase of crude oil. Our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the crude oil is purchased. Generally, these letters of credit are issued for periods of up to seventy days and are terminated upon completion of each transaction. At March 31, 2010 and December 31, 2009, we had outstanding letters of credit of approximately $107 million and $76 million, respectively.

Off-Balance Sheet Arrangements

We have no significant off-balance sheet arrangements as defined by Item 307 of Regulation S-K.

Recent Accounting Pronouncements

See Note 2 to our Condensed Consolidated Financial Statements.

Critical Accounting Policies and Estimates

For additional discussion regarding our critical accounting policies and estimates, see “Critical Accounting Policies and Estimates” under Item 7 of our 2009 Annual Report on Form 10-K.

Forward-Looking Statements

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

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· failure to implement or capitalize on planned internal growth projects;

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

· continued creditworthiness of, and performance by, our counterparties, including financial institutions and trading companies with which we do business;

· the effectiveness of our risk management activities;

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

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

· shortages or cost increases of power supplies, materials or labor;

· the availability of adequate third-party production volumes for transportation and marketing in the areas in which we operate and other factors that could cause declines in volumes shipped on our pipelines by us and third-party shippers, such as declines in production from existing oil and gas reserves or failure to develop additional oil and gas reserves;

· fluctuations in refinery capacity in areas supplied by our mainlines and other factors affecting demand for various grades of crude oil, refined products and natural gas and resulting changes in pricing conditions or transportation throughput requirements;

· the availability of, and our ability to consummate, acquisition or combination opportunities;

· our ability to obtain debt or equity financing on satisfactory terms to fund additional acquisitions, expansion projects, working capital requirements and the repayment or refinancing of indebtedness;

· the successful integration and future performance of acquired assets or businesses and the risks associated with operating in lines of business that are distinct and separate from our historical operations;

· unanticipated changes in crude oil market structure, grade differentials and volatility (or lack thereof);

· the impact of current and future laws, rulings, governmental regulations, accounting standards and statements and related interpretations;

· the effects of competition;

· interruptions in service and fluctuations in tariffs or volumes on third-party pipelines;

· increased costs or lack of availability of insurance;

· fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our long-term incentive plans;

· the currency exchange rate of the Canadian dollar;

· weather interference with business operations or project construction;

· risks related to the development and operation of natural gas storage facilities;

· future developments and circumstances at the time distributions are declared;

· general economic, market or business conditions and the amplification of other risks caused by deteriorated financial markets, capital constraints and pervasive liquidity concerns; and

· other factors and uncertainties inherent in the transportation, storage, terminalling and marketing of crude oil, refined

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products and liquefied petroleum gas and other natural gas related petroleum products.

Other factors, described herein, or factors that are unknown or unpredictable, could also have a material adverse effect on future results. Please read “Risks Factors” discussed in Item 1A of our 2009 Annual Report on Form 10-K. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

The following should be read in conjunction with Quantitative and Qualitative Disclosures About Market Risk included under Item 7A in our 2009 Annual Report on Form 10-K. There have been no material changes in that information other than as discussed below. Also, see Note 9 to our Condensed Consolidated Financial Statements for additional discussion related to derivative instruments and hedging activities.

Commodity Price Risk

All of our open commodity price risk derivatives at March 31, 2010 were categorized as non-trading. The fair value of these instruments and the change in fair value that would be expected from a ten percent price decrease are shown in the table below (in millions):

				Effect of 10%
	Fair Value			Price Decrease
Crude oil:
Futures contracts	$	42		$	43
Swaps and options contracts	3			$	5

LPG and other:
Futures contracts	(2		)	$	—
Swaps and options contracts	(1		)	$	(7	)
Total Fair Value	$	42

Item 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

We maintain written DCP. The purpose of our DCP is to provide reasonable assurance that (i) information is recorded, processed, summarized and reported in a manner that allows for timely disclosure of such information in accordance with the securities laws and SEC regulations and (ii) information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow for timely decisions regarding required disclosure.

Applicable SEC rules require an evaluation of the effectiveness of the design and operation of our DCP. Management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our DCP as of the end of the period covered by this report, and has found our DCP to be effective in providing reasonable assurance of the timely recording, processing, summarization and reporting of information, and in accumulation and communication of information to management to allow for timely decisions with regard to required disclosure.

Changes in Internal Control over Financial Reporting

In addition to the information concerning our DCP, we are required to disclose certain changes in our internal control over financial reporting. Although we have made various enhancements to our controls, there have been no changes in our internal control over financial reporting during the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Certifications

The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to Exchange Act rules 13a-14(a) and 15d-14(a) are filed with this report as Exhibits 31.1 and 31.2. The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. 1350 are furnished with this report as Exhibits 32.1 and 32.2.

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		May 30, 2008).

3.7	—	Amendment No. 6 dated September 3, 2009 to Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed September 3, 2009).

3.8	—	Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. dated as of April 1, 2004 (incorporated by reference to Exhibit 3.2 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

3.9	—	Third Amended and Restated Agreement of Limited Partnership of Plains Pipeline, L.P. dated as of April 1, 2004 (incorporated by reference to Exhibit 3.3 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

3.10	—	Fourth Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC dated August 7, 2008, as amended November 2, 2009 (incorporated by reference to Exhibit 3.10 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2009).

3.11	—	Fifth Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. dated August 7, 2008 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed August 7, 2008).

3.12	—	Certificate of Incorporation of PAA Finance Corp (f/k/a Pacific Energy Finance Corporation, successor-by-merger to PAA Finance Corp.) (incorporated by reference to Exhibit 3.10 to the Annual Report on Form 10-K for the year ended December 31, 2006).

3.13	—	Bylaws of PAA Finance Corp (f/k/a Pacific Energy Finance Corporation, successor-by-merger to PAA Finance Corp.) (incorporated by reference to Exhibit 3.11 to the Annual Report on Form 10-K for the year ended December 31, 2006).

3.14	—	Limited Liability Company Agreement of PAA GP LLC dated December 28, 2007 (incorporated by reference to Exhibit 3.3 to the Current Report on Form 8-K filed January 4, 2008).

4.1	—	Indenture dated September 25, 2002 among Plains All American Pipeline, L.P., PAA Finance Corp. and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2002).

4.2	—	First Supplemental Indenture (Series A and Series B 7.75% Senior Notes due 2012) dated as of September 25, 2002 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2002).

4.3	—	Second Supplemental Indenture (Series A and Series B 5.625% Senior Notes due 2013) dated as of December 10, 2003 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.4 to the Annual Report on Form 10-K for the year ended December 31, 2003).

4.4	—	Fourth Supplemental Indenture (Series A and Series B 5.875% Senior Notes due 2016) dated August 12, 2004 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.5 to the Registration Statement on Form S-4, File No. 333-121168).

4.5	—	Fifth Supplemental Indenture (Series A and Series B 5.25% Senior Notes due 2015) dated May 27, 2005 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed May 31, 2005).

4.6	—	Sixth Supplemental Indenture (Series A and Series B 6.70% Senior Notes due 2036) dated May 12, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed May 12, 2006).

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4.7	—	Seventh Supplemental Indenture dated May 12, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K filed May 12, 2006).

4.8	—	Eighth Supplemental Indenture dated August 25, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed August 25, 2006).

4.9	—	Ninth Supplemental Indenture (Series A and Series B 6.125% Senior Notes due 2017) dated October 30, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed October 30, 2006).

4.10	—	Tenth Supplemental Indenture (Series A and Series B 6.650% Senior Notes due 2037) dated October 30, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed October 30, 2006).

4.11	—	Eleventh Supplemental Indenture dated November 15, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed November 21, 2006).

4.12	—	Twelfth Supplemental Indenture dated January 1, 2008 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.21 to the Annual Report on Form 10-K for the year ended December 31, 2007).

4.13	—	Thirteenth Supplemental Indenture (Series A and Series B 6.5% Senior Notes due 2018) dated April 23, 2008 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed April 23, 2008).

4.14	—	Fourteenth Supplemental Indenture dated July 1, 2008 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.15 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2008).

4.15	—	Fifteenth Supplemental Indenture (8.75% Senior Notes due 2019) dated April 20, 2009 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed April 20, 2009).

4.16	—	Sixteenth Supplemental Indenture (4.25% Senior Notes due 2012) dated July 23, 2009 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed July 23, 2009).

4.17	—	Seventeenth Supplemental Indenture (5.75% Senior Notes due 2020) dated September 4, 2009 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein, and U.S. Bank National Association as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed September 4, 2009).

4.18	—	Indenture dated September 23, 2005 among Pacific Energy Partners, L.P., PAA Finance Corp. (f/k/a Pacific Energy Finance Corporation), the Guarantors named therein, and Wells Fargo Bank, National Association, as trustee of the 61/4% senior notes due 2015 (incorporated by reference to Exhibit 4.1 to Pacific Energy Partners, L.P.’s Current Report on Form 8-K filed September 28, 2005).

4.19	—	First Supplemental Indenture dated November 15, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp. (f/k/a Pacific Energy Finance Corporation), the Guarantors named therein, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K filed November 21, 2006).

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EXHIBIT INDEX

3.1		—		Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. dated as of June 27, 2001 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed August 27, 2001).

3.2		—		Amendment No. 1 dated April 15, 2004 to the Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

3.3		—		Amendment No. 2 dated November 15, 2006 to Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed November 21, 2006).

3.4		—		Amendment No. 3 dated August 16, 2007 to Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed August 22, 2007).

3.5		—		Amendment No. 4 effective as of January 1, 2007 to Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed April 15, 2008).

3.6		—		Amendment No. 5 dated May 28, 2008 to Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed May 30, 2008).

3.7		—		Amendment No. 6 dated September 3, 2009 to Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed September 3, 2009).

3.8		—		Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. dated as of April 1, 2004 (incorporated by reference to Exhibit 3.2 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

3.9		—		Third Amended and Restated Agreement of Limited Partnership of Plains Pipeline, L.P. dated as of April 1, 2004 (incorporated by reference to Exhibit 3.3 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

3.10	—		Fourth Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC dated August 7, 2008, as amended November 2, 2009 (incorporated by reference to Exhibit 3.10 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2009).

3.11		—		Fifth Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. dated August 7, 2008 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed August 7, 2008).

3.12		—		Certificate of Incorporation of PAA Finance Corp (f/k/a Pacific Energy Finance Corporation, successor-by-merger to PAA Finance Corp.) (incorporated by reference to Exhibit 3.10 to the Annual Report on Form 10-K for the year ended December 31, 2006).

3.13		—		Bylaws of PAA Finance Corp (f/k/a Pacific Energy Finance Corporation, successor-by-merger to PAA Finance Corp.) (incorporated by reference to Exhibit 3.11 to the Annual Report on Form 10-K for the year ended December 31, 2006).

3.14		—		Limited Liability Company Agreement of PAA GP LLC dated December 28, 2007 (incorporated by reference to Exhibit 3.3 to the Current Report on Form 8-K filed January 4, 2008).

4.1		—		Indenture dated September 25, 2002 among Plains All American Pipeline, L.P., PAA Finance Corp. and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2002).

4.2		—		First Supplemental Indenture (Series A and Series B 7.75% Senior Notes due 2012) dated as of September 25, 2002

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		among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2002).

4.3	—	Second Supplemental Indenture (Series A and Series B 5.625% Senior Notes due 2013) dated as of December 10, 2003 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.4 to the Annual Report on Form 10-K for the year ended December 31, 2003).

4.4	—	Fourth Supplemental Indenture (Series A and Series B 5.875% Senior Notes due 2016) dated August 12, 2004 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.5 to the Registration Statement on Form S-4, File No. 333-121168).

4.5	—	Fifth Supplemental Indenture (Series A and Series B 5.25% Senior Notes due 2015) dated May 27, 2005 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed May 31, 2005).

4.6	—	Sixth Supplemental Indenture (Series A and Series B 6.70% Senior Notes due 2036) dated May 12, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed May 12, 2006).

4.7	—	Seventh Supplemental Indenture dated May 12, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K filed May 12, 2006).

4.8	—	Eighth Supplemental Indenture dated August 25, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed August 25, 2006).

4.9	—	Ninth Supplemental Indenture (Series A and Series B 6.125% Senior Notes due 2017) dated October 30, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed October 30, 2006).

4.10	—	Tenth Supplemental Indenture (Series A and Series B 6.650% Senior Notes due 2037) dated October 30, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed October 30, 2006).

4.11	—	Eleventh Supplemental Indenture dated November 15, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed November 21, 2006).

4.12	—	Twelfth Supplemental Indenture dated January 1, 2008 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.21 to the Annual Report on Form 10-K for the year ended December 31, 2007).

4.13	—	Thirteenth Supplemental Indenture (Series A and Series B 6.5% Senior Notes due 2018) dated April 23, 2008 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed April 23, 2008).

4.14	—	Fourteenth Supplemental Indenture dated July 1, 2008 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.15 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2008).

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4.15	—	Fifteenth Supplemental Indenture (8.75% Senior Notes due 2019) dated April 20, 2009 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed April 20, 2009).

4.16	—	Sixteenth Supplemental Indenture (4.25% Senior Notes due 2012) dated July 23, 2009 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed July 23, 2009).

4.17	—	Seventeenth Supplemental Indenture (5.75% Senior Notes due 2020) dated September 4, 2009 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein, and U.S. Bank National Association as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed September 4, 2009).

4.18	—	Indenture dated September 23, 2005 among Pacific Energy Partners, L.P., PAA Finance Corp. (f/k/a Pacific Energy Finance Corporation), the Guarantors named therein, and Wells Fargo Bank, National Association, as trustee of the 61/4% senior notes due 2015 (incorporated by reference to Exhibit 4.1 to Pacific Energy Partners, L.P.’s Current Report on Form 8-K filed September 28, 2005).

4.19	—	First Supplemental Indenture dated November 15, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp. (f/k/a Pacific Energy Finance Corporation), the Guarantors named therein, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K filed November 21, 2006).

4.20	—	Second Supplemental Indenture dated January 1, 2008 among Plains All American Pipeline, L.P., PAA Finance Corp. (f/k/a Pacific Energy Finance Corporation), the Guarantors named therein, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.22 to the Annual Report on Form 10-K for the year ended December 31, 2007).

4.21	—	Registration Rights Agreement dated September 3, 2009 by and between Plains All American Pipeline, L.P. and Vulcan Gas Storage LLC (incorporated by reference to Exhibit 4.1 to the Registration Statement on Form S-3, File No. 333-162477).

12.1†	—	Computation of Ratio of Earnings to Fixed Charges

31.1†	—	Certification of Principal Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).

31.2†	—	Certification of Principal Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).

32.1†	—	Certification of Principal Executive Officer pursuant to 18 U.S.C. 1350

32.2†	—	Certification of Principal Financial Officer pursuant to 18 U.S.C. 1350

101†	—	The following financial information from the quarterly report on Form 10-Q of Plains All American Pipeline, L.P. for the quarter ended March 31, 2010, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Statements of Operations, (ii) Condensed Consolidated Balance Sheets, (iii) Condensed Consolidated Statements of Cash Flows, (iv) Condensed Consolidated Statement of Partners’ Capital, (v) Condensed Consolidated Statements of Comprehensive Income, (vi) Condensed Consolidated Statement of Changes in Accumulated Other Comprehensive Income and (vii) Notes to the Condensed Consolidated Financial Statements, tagged as blocks of text.

† Filed herewith

** Management compensatory plan or arrangement

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

	For the quarterly period ended March 31, 2010

OR

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

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

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

Large accelerated filer x		Accelerated filer o		Non-accelerated filer o		Smaller reporting company o
				(Do not check if a smaller reporting company)

		Page
PART I. FINANCIAL INFORMATION		3
Item 1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:		3
Condensed Consolidated Balance Sheets: March 31, 2010 and December 31, 2009		3
Condensed Consolidated Statements of Operations: For the three months ended March 31, 2010 and 2009		4
Condensed Consolidated Statements of Cash Flows: For the three months ended March 31, 2010 and 2009		5
Condensed Consolidated Statement of Partners’ Capital: For the three months ended March 31, 2010		6
Condensed Consolidated Statements of Comprehensive Income: For the three months ended March 31, 2010 and 2009		6
Condensed Consolidated Statement of Changes in Accumulated Other Comprehensive Income: For the three months ended March 31, 2010		6
Notes to the Condensed Consolidated Financial Statements:		7
1.	Organization and Basis of Presentation	7
2.	Recent Accounting Pronouncements	8
3.	Trade Accounts Receivable	8
4.	Inventory, Linefill, Base Gas and Long-term Inventory	9
5.	Debt	10
6.	Net Income Per Limited Partner Unit	11
7.	Partners’ Capital and Distributions	12
8.	Equity Compensation Plans	12
9.	Derivatives and Risk Management Activities	15
10.	Income Taxes	22
11.	Commitments and Contingencies	23
12.	Operating Segments	25
13.	Supplemental Condensed Consolidating Financial Information	26
14.	Subsequent Events	30
Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		31
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		42
Item 4. CONTROLS AND PROCEDURES		42

PART II. OTHER INFORMATION		43
Item 1. LEGAL PROCEEDINGS		43
Item 1A. RISK FACTORS		43
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		43
Item 3. DEFAULTS UPON SENIOR SECURITIES		43
Item 4. [REMOVED AND RESERVED]		43
Item 5. OTHER INFORMATION		43
Item 6. EXHIBITS		43
SIGNATURES		47

	PLAINS ALL AMERICAN PIPELINE, L.P.

	By:	PAA GP LLC, its general partner
	By:	PLAINS AAP, L.P., its sole member
	By:	PLAINS ALL AMERICAN GP LLC, its general partner

Date: May 7, 2010


	By:	/s/ GREG L. ARMSTRONG
		Greg L. Armstrong, Chairman of the Board,
		Chief Executive Officer and Director
		(Principal Executive Officer)

Date: May 7, 2010


	By:	/s/ AL SWANSON
		Al Swanson, Senior Vice President and
		Chief Financial Officer
		(Principal Financial Officer)

FORM 10-Q