UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d) of The
Securities Exchange Act of 1934

Plains All American Pipeline, L.P.

(Exact name of registrant as specified in its charter)

DELAWARE (State or other jurisdiction of incorporation)		1-14569 (Commission File Number)		76-0582150 (IRS Employer Identification No.)

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

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

N/A
(Former name or former address, if changed since last report.)

     Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

	o		Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
	o		Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
	o		Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
	o		Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 

 

TABLE OF CONTENTS

		Page
Item 9.01. Financial Statements and Exhibits			2
Signatures			3
Index to Exhibits			4
EXHIBIT 99.1

Item 9.01. Financial Statements and Exhibits

(d) Exhibits

99.1		Unaudited Condensed Consolidated Balance Sheet of PAA GP LLC, dated as of March 31, 2010

SIGNATURES

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

		PLAINS ALL AMERICAN PIPELINE, L.P.
Date: June 17, 2010		By:		PAA GP LLC, its general partner
		By:		Plains AAP, L.P., its sole member
		By:		Plains All American GP LLC, its general partner
		By:		/s/ TINA L. SUMMERS
				Name:		Tina L. Summers
				Title:		Vice President – Accounting and Chief Accounting Officer

Index to Exhibits

99.1		Unaudited Condensed Consolidated Balance Sheet of PAA GP LLC, dated as of March 31, 2010

Exhibit 99.1

PAA GP LLC
INDEX TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET

		Page
Unaudited Condensed Consolidated Balance Sheet as of March 31, 2010		F-2
Notes to Unaudited Condensed Consolidated Balance Sheet		F-3

PAA GP LLC

CONDENSED CONSOLIDATED BALANCE SHEET
(in millions)

		March 31,
		2010
		(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	16
Trade accounts receivable and other receivables, net			2,049
Inventory			1,244
Other current assets			32
Total current assets			3,341
PROPERTY AND EQUIPMENT			7,390
Accumulated depreciation			(969	)
			6,421
OTHER ASSETS
Linefill and base gas			521
Long-term inventory			123
Goodwill			1,297
Other, net			408
Total assets		$	12,111
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities		$	2,402
Short-term debt			951
Other current liabilities			144
Total current liabilities			3,497
LONG-TERM LIABILITIES
Long-term debt under credit facilities and other			8
Senior notes, net of unamortized discount of $14			4,136
Other long-term liabilities and deferred credits			253
Total long-term liabilities			4,397
MEMBER’S EQUITY
Member’s equity			97
Total member’s equity excluding noncontrolling interest			97
Noncontrolling interest			4,120
Total member’s equity			4,217
Total liabilities and member’s equity		$	12,111

The accompanying notes are an integral part of this unaudited condensed consolidated balance sheet.

PAA GP LLC
NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET

Note 1—Organization and Basis of Consolidation

Organization

     PAA GP LLC (the “Company”) is a Delaware limited liability company, formed on December 28, 2007. Upon our formation, Plains AAP, L.P. (“AAPLP”) conveyed to us its 2% general partner interest in Plains All American Pipeline, L.P. (“PAA”). AAPLP is our sole member and is also the entity that owns 100% of the incentive distribution rights of PAA. As used in this unaudited condensed consolidated balance sheet and notes thereto, the terms “we,” “us,” “our,” “ours” and similar terms refer to the Company, unless otherwise indicated.

     AAPLP (through its general partner, Plains All American GP LLC (“GP LLC”)) manages the business and affairs of the Company. AAPLP has full and complete authority, power and discretion to manage and control the business, affairs and property of the Company, to make all decisions regarding those matters and to perform any and all other acts or activities customary or incident to the management of the Company’s business, including the execution of contracts and management of litigation. GP LLC also manages PAA’s operations and employs PAA’s domestic officers and personnel. PAA’s Canadian officers and personnel are employed by PAA’s subsidiary, PMC (Nova Scotia) Company.

     As of March 31, 2010, we own a 2% general partner interest in PAA, the ownership of which entitles us to receive distributions. PAA is engaged in the transportation, storage, terminalling and marketing of crude oil, refined products and liquefied petroleum gas and other natural gas-related petroleum products. PAA is also engaged in the development and operation of natural gas storage facilities. PAA’s operations can be categorized into three operating segments, including (i) Transportation, (ii) Facilities and (iii) Supply and Logistics.

Basis of Consolidation and Presentation

     In June 2005, the Financial Accounting Standards Board (“FASB”) issued guidance for determining whether a general partner, or the general partners as a group, controls a limited partnership or similar entity when the limited partners have certain rights. The guidance provides that if the limited partners do not have a substantive ability to dissolve (liquidate) the limited partnership or substantive participating rights, then the general partner is presumed to control that partnership and would be required to consolidate the limited partnership. Because the limited partners do not have a substantive ability to dissolve or have substantive participating rights in regards to PAA, we are required to consolidate PAA and its consolidated subsidiaries into our consolidated financial statement. The consolidation of PAA resulted in the recognition of a noncontrolling interest.

     We account for noncontrolling interest in accordance with guidance issued by the FASB that requires all entities to report noncontrolling interests in subsidiaries (formerly referred to as minority interest) as a component of equity. As of March 31, 2010, our noncontrolling interest was approximately $4.1 billion, which is comprised of the book value of PAA’s net assets that are owned by other parties.

     The accompanying unaudited condensed consolidated balance sheet includes the accounts of the Company and PAA and all of PAA’s consolidated subsidiaries. Investments in entities over which PAA has significant influence, but not control, are accounted for by the equity method. All significant intercompany transactions have been eliminated. The unaudited condensed consolidated balance sheet of the Company and accompanying notes dated as of March 31, 2010 should be read in conjunction with (i) the consolidated balance sheet of PAA and notes thereto presented in PAA’s Annual Report on Form 10-K for the year ended December 31, 2009, (ii) the condensed consolidated balance sheet of PAA and notes thereto presented in PAA’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2010 and (iii) the consolidated balance sheet of the Company and notes thereto presented in PAA’s Current Report on Form 8-K filed on March 12, 2010.

     Subsequent events have been evaluated through the financial statement issuance date and have been included within the following footnotes where applicable. See Note 4 for further discussion of subsequent events.

Note 2—Member’s Equity

     The Company is a wholly owned subsidiary of AAPLP. Accordingly, we distribute to AAPLP on a quarterly basis all of the cash received from PAA distributions, less reserves established by management.

     Our investment in PAA, which is eliminated in consolidation, exceeds our share of the underlying equity in the net assets of PAA. This excess is related to the fair value of PAA’s crude oil pipelines and other assets at the time of AAPLP’s formation in July 2001. Upon AAPLP’s conveyance to us of its 2% general partner interest in PAA, a portion of AAPLP’s unamortized excess basis was also allocated to us. This excess basis is amortized on a straight-line basis over the estimated useful life of 30 years, of which 21 years are remaining. At March 31, 2010, the unamortized portion of our excess basis was approximately $9 million and is included in Property and Equipment in our unaudited condensed consolidated balance sheet.

     Included in member’s equity is our proportionate share of PAA’s accumulated other comprehensive income, which is a deferred gain of approximately $3 million.

Note 3-Consolidation of PAA GP LLC

     The following unaudited condensed consolidating balance sheet is presented before and after the consolidation of PAA and related consolidation entries as of March 31, 2010:

PAA GP LLC
UNAUDITED CONDENSED CONSOLIDATING BALANCE SHEET

March 31, 2010
(in millions)

						Plains All American								PAA GP LLC
		PAA GP LLC				Pipeline, L.P.				Adjustments				Consolidated
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	—			$	16			$	—			$	16
Trade accounts receivable and other receivables, net			—				2,049				—				2,049
Inventory			—				1,244				—				1,244
Other current assets			—				32				—				32
Total current assets			—				3,341				—				3,341
PROPERTY AND EQUIPMENT			—				7,378				12	(a)			7,390
Accumulated depreciation			—				(966	)			(3)	(a)			(969	)
			—				6,412				9				6,421
OTHER ASSETS
Linefill and base gas			—				521				—				521
Long-term inventory			—				123				—				123
Goodwill			—				1,297				—				1,297
Other, net			98				408				(98)	(b)			408
Total assets		$	98			$	12,102			$	(89	)		$	12,111
LIABILITIES AND PARTNERS’ CAPITAL / MEMBER’S EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities		$	1			$	2,401			$	—			$	2,402
Short-term debt			—				951				—				951
Other current liabilities			—				144				—				144
Total current liabilities			1				3,496				—				3,497
LONG-TERM LIABILITIES
Long-term debt under credit facilities and other			—				8				—				8
Senior notes, net of unamortized net discount of $14			—				4,136				—				4,136
Other long-term liabilities and deferred credits			—				253				—				253
Total long-term liabilities			—				4,397				—				4,397
PARTNERS’ CAPITAL / MEMBER’S EQUITY
Limited partners			—				4,051				(4,051)	(b)			—
General partner			—				95				(95)	(b)			—
Member’s equity			97				—				—				97
Total partners’ capital / member’s equity excluding noncontrolling interest			97				4,146				(4,146	)			97
Noncontrolling interest			—				63				4,057	(b)			4,120
Total partners’ capital / member’s equity			97				4,209				(89	)			4,217
Total liabilities and partners’ capital / member’s equity		$	98			$	12,102			$	(89	)		$	12,111

     The remainder of this Note 3 relates only to the Plains All American Pipeline, L.P. column shown above. As used in the remainder of this Note 3, 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 “general partner,” as the context requires, include any or all of the Company, AAPLP and GP LLC. The following additional defined terms are used in this Note 3 and shall have the meaning indicated below:

AOCI		= Accumulated other comprehensive income
Bcf		= Billion cubic feet
CAA		= Clean Air Act
CAD		= Canadian Dollar
Class B units		= Class B units of Plains AAP, L.P.
DERs		= Distribution Equivalent Rights
DOJ		= United States Department of Justice
EPA		= United States Environmental Protection Agency
ICE		= IntercontinentalExchange
IPO		= Initial Public Offering
LIBOR		= London Interbank Offered Rate
LPG		= Liquefied petroleum gas and other natural gas-related petroleum products
LTIP		= Long term incentive plan
Mcf		= Thousand cubic feet
MLP		= Master limited partnership
MTBE		= Methyl tertiary-butyl ether
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
USD		= United States Dollar
WTI		= West Texas Intermediate

Recent Accounting Pronouncements

     Fair Value Measurement Disclosure Requirements. In January 2010, the FASB issued guidance to improve disclosures relating to fair value measurements. This new guidance requires additional disclosures regarding transfers in and out of Level 1 and Level 2 measurements and requires a gross presentation of activities within the Level 3 roll forward. This guidance is effective for the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 roll forward, which is required for annual reporting periods beginning after December 15, 2010 and for interim reporting periods within those years. We adopted the guidance, which is effective for the first interim or annual reporting period beginning after December 15, 2009, on January 1, 2010. Our adoption did not have any material impact on our financial position, results of operations, or cash flows. See “— Derivatives and Risk Management Activities” for applicable disclosure. We will adopt the guidance that will be effective for annual reporting periods beginning after December 15, 2010 on January 1, 2011. We do not expect that adoption of this guidance will have any material impact on our financial position, results of operations, or cash flows.

Trade Accounts Receivable

     We review all outstanding accounts receivable balances on a monthly basis and record a reserve for amounts that we expect will not be fully recovered. We do not apply actual balances against the reserve until we have exhausted substantially all collection efforts. At March 31, 2010, substantially all of our accounts receivable (net of allowance for doubtful accounts) were less than 60 days past their scheduled invoice date. Our allowance for doubtful accounts receivable totaled $9 million at March 31, 2010. Although we consider our allowance for doubtful accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.

     At March 31, 2010, we had received approximately $133 million of advance cash payments from third parties to mitigate credit risk. In addition, we enter into netting arrangements with our counterparties, which cover a significant part of our transactions and also serve to mitigate credit risk.

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
						Unit of		Total				Price/
		Volumes				Measure		Value				Unit (1)
Inventory
Crude oil			14,833			barrels		$	1,156			$	77.93
LPG			1,683			barrels			78			$	46.35
Refined products			127			barrels			9			$	70.87
Natural gas (2)			115			mcf			—			$	2.97
Parts and supplies			N/A						1				N/A
Inventory subtotal									1,244
Linefill and base gas
Crude oil			9,459			barrels			482			$	50.96
Natural gas (2)			10,994			mcf			37			$	3.37
LPG			56			barrels			2			$	35.71
Linefill and base gas subtotal									521
Long-term inventory
Crude oil			1,460			barrels			101			$	69.18
LPG			458			barrels			22			$	48.03
Long-term inventory subtotal									123
Total								$	1,888

Debt

     Debt consists of the following (in millions):

		March 31,
		2010
Short-term debt:
Senior secured hedged inventory facility bearing interest at a rate of 2.5% as of March 31, 2010		$	400
Senior unsecured revolving credit facility, bearing interest at a rate of 0.7% as of March 31, 2010 (1)			549
Other			2
Total short-term debt			951
Long-term debt:
4.25% senior notes due September 2012 (2)			500
7.75% senior notes due October 2012			200
5.63% senior notes due December 2013			250
5.25% senior notes due June 2015			150
6.25% senior notes due September 2015			175
5.88% senior notes due August 2016			175
6.13% senior notes due January 2017			400
6.50% senior notes due May 2018			600
8.75% senior notes due May 2019			350
5.75% senior notes due January 2020			500
6.70% senior notes due May 2036			250
6.65% senior notes due January 2037			600
Unamortized premium/(discount), net			(14	)
Long-term debt under credit facilities and other			8
Total long-term debt (1) (3)			4,144
Total debt		$	5,095

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 obligation for the purchase of crude oil. At March 31, 2010, we had outstanding letters of credit of approximately $107 million.

Partners’ Capital and Distributions

Equity Offerings

     We did not complete any equity offerings during the three months ended March 31, 2010.

Distributions

     The following table details the distributions pertaining to the first three months of 2010, 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

     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.”

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):

		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

     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

     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.

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

														Grant Date
														Fair Value Of
		Reserved for								Outstanding Units				Outstanding Class B
		Future Grants				Outstanding				Earned				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

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 value of vesting (settled both in units and cash) related to our equity compensation plans (in millions):

		Three Months Ended
		March 31,
		2010
		Liability Awards				Equity Awards
LTIP unit vestings		$	—			$	—
LTIP cash settled vestings		$	—			$	—
DER cash payments		$	1			$	—

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.
	•		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 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.

     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								Balance Sheet
		Location				Fair Value				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	)

     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 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 are as follows (in millions):

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

     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. At March 31, 2010, 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)
Recurring Fair Value Measures(1)		Level 1				Level 2				Level 3				Total
Commodity derivatives		$	49			$	—			$	(7	)		$	42
Interest rate derivatives			—				—				3				3
Foreign currency derivatives			—				—				(1	)			(1	)
Total		$	49			$	—			$	(5	)		$	44

     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 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
Beginning Balance		$	(28	)
Unrealized gains/(losses):
Included in earnings (1)			7
Included in other comprehensive income			—
Settlements and derivatives entered into during the period			16
Ending Balance		$	(5	)
Change in unrealized gains/(losses) included in earnings relating to level 3 derivatives still held at the end of the periods		$	—

     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.

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 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 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.

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) and will comply with other requirements set forth in the consent decree, which include performance of additional remediation, work plans and restoration tasks pertaining to a segment of Line 63. The affected segment of Line 63 was taken out of service. Certain operational and construction requirements will have to be satisfied to put this segment back into service. Total projected costs associated with this additional work are estimated at less than $6 million. PPS is also prohibited from

transferring ownership of Line 63 to an unaffiliated entity unless the transferee agrees in writing to be bound by any provisions of the consent decree that have not been previously satisfied. This prohibition on transfer will not apply if PPS retains a portion of ownership and continues as operator of the line.

     ExxonMobil Corp. v. GATX Corp. (Superior Court of New Jersey — Gloucester County). This Pacific legacy matter was filed by ExxonMobil in April 2003 and involves the allocation of responsibility for remediation of MTBE and other petroleum product contamination at the PAT facility at Paulsboro, New Jersey. We estimate that the maximum potential cost to effectively remediate ranges up to $10 million although the NJDEP is asserting a much larger expenditure. Both ExxonMobil and GATX were prior owners of the terminal. We contend that ExxonMobil and/or GATX are primarily responsible for the majority of the remediation costs. We are in dispute with Kinder Morgan (as successor in interest to GATX) regarding the indemnity by GATX in favor of Pacific in connection with Pacific’s purchase of the facility. We are vigorously defending against any claim that PAT is directly or indirectly liable for damages or costs associated with the MTBE contamination.

     NJDEP v. ExxonMobil Corp. et al. In a matter related to ExxonMobil v. GATX, in June 2007, the NJDEP brought suit against GATX and Exxon to recover natural resources damages associated with, and to require remediation of, the contamination. ExxonMobil and GATX have filed third-party demands against PAT, seeking indemnity and contribution. NJDEP environmental consultants have asserted a clean-up expense that is significantly larger than our estimate.

     EPA v. RMPS. In February 2009, we received a request for information from EPA regarding aspects of the fuel handling activities of RMPS, a subsidiary acquired in the Pacific merger, at two truck terminals in Colorado. These activities, performed at the request of customers, included the mixture of certain blendstocks with gasoline. We provided the information requested, and cooperated in EPA’s investigation of such activities. In January 2010, we received a notice of violations from EPA, alleging failure of RMPS to comply with provisions of the CAA related to registration, sampling, recording and reporting in connection with such activities. EPA further alleges that the violations occurred on an ongoing basis from October 2006 through February 2009. We plan to engage in discussion with EPA, and to emphasize factors intended to mitigate the severity of any penalties imposed. In December 2009, RMPS self-reported late filing of certain reports required under Clean Air Act Diesel Fuel Regulations. All reports have been filed.

     Other Pacific-Legacy Matters. At the time of its merger with Plains, Pacific had completed a number of acquisitions that had not been fully integrated into its operations. Accordingly, we have and may become aware of various instances in which some of these operations may not have been fully compliant with applicable environmental and safety regulations. Although we have been working to bring all of these operations into compliance with applicable requirements, any past noncompliance could result in the imposition of fines, penalties or corrective action requirements by governmental entities. Although we believe that our operations are presently in material compliance with applicable requirements, it is possible that EPA or other governmental entities may seek to impose fines, penalties or performance obligations on us, or on a portion of our operations, as a result of any past noncompliance that may have occurred.

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

Environmental

     We have in the past experienced and in the future likely will experience releases of crude oil into the environment from our pipeline and storage operations. We also may discover environmental impacts from past releases that were previously unidentified. Although we maintain an inspection program designed to 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.

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.

  Note 4—Subsequent Events

     On May 14, 2010, PAA paid a distribution of $0.935 per limited partner unit. We (PAA GP LLC) received a distribution of approximately $3 million associated with our 2% general partner interest in PAA, which we then distributed to AAPLP.