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

(Address of principal executive offices) (Zip Code)

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

(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
EX-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 June 30, 2009

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.

Index to Exhibits

99.1

Unaudited Condensed Consolidated Balance Sheet of PAA GP LLC, dated as of June 30, 2009

Exhibit 99.1

PAA GP LLC
INDEX TO THE UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET

		Page
Unaudited Condensed Consolidated Balance Sheet as of June 30, 2009			F-2
Notes to the Unaudited Condensed Consolidated Balance Sheet			F-3

PAA GP LLC

CONDENSED CONSOLIDATED BALANCE SHEET
(in millions)

		June 30,
		2009
		(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	7
Trade accounts receivable and other receivables, net			1,674
Inventory			995
Other current assets			246
Total current assets			2,922
PROPERTY AND EQUIPMENT			6,040
Accumulated depreciation			(776	)
			5,264
OTHER ASSETS
Pipeline linefill in owned assets			429
Long-term inventory			127
Investment in unconsolidated entities			256
Goodwill			1,226
Other, net			344
Total assets		$	10,568
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities		$	1,927
Short-term debt			938
Other current liabilities			343
Total current liabilities			3,208
LONG-TERM LIABILITIES
Long-term debt under credit facilities and other			4
Senior notes, net of unamortized net discount of $6			3,394
Other long-term liabilities and deferred credits			247
Total long-term liabilities			3,645
MEMBER’S EQUITY
Member’s equity			90
Total member’s equity excluding noncontrolling interest			90
Noncontrolling interest			3,625
Total member’s equity			3,715
Total liabilities and member’s equity		$	10,568

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

PAA GP LLC
NOTES TO THE 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 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 June 30, 2009, 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. Through its ownership in PAA Natural Gas Storage, LLC (“PNGS”), PAA is also involved in the development and operation of natural gas storage facilities. See Note 4 for further discussion. PAA’s operations can be categorized into three operating segments, including (i) Transportation, (ii) Facilities and (iii) Marketing.

Basis of Consolidation and Presentation

     In June 2005, the Emerging Issues Task Force (“EITF”) released Issue No. 04-05 (“EITF 04-05”), “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights.” EITF 04-05 states that if the limited partners do not have a substantive ability to dissolve (liquidate) 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 Statement of Financial Accounting Standards (“SFAS”) No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of Accounting Research Bulletin No. 51” (“SFAS 160”). SFAS 160 requires all entities to report noncontrolling interests in subsidiaries (formerly referred to as minority interest) as a component of equity. As of June 30, 2009, our noncontrolling interest was approximately $3.6 billion, which is comprised of the book value of PAA’s net assets that are owned by other parties.

     The accompanying condensed consolidated balance sheet includes the accounts of the Company and PAA and all of PAA’s consolidated subsidiaries. Investments in entities in which PAA has significant influence, but not control, are accounted for by the equity method. All significant intercompany transactions have been eliminated. The condensed consolidated balance sheet of the Company and accompanying notes dated as of June 30, 2009 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, 2008, (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 June 30, 2009 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, 2009.

     Subsequent events have been evaluated through the issuance date of September 28, 2009 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 22 years are remaining. At June 30, 2009, the unamortized portion of our excess basis was approximately $9 million and is included in Property and Equipment in our 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 $1 million.

Note 3—Consolidation of PAA GP LLC

     The following condensed consolidating balance sheet is presented before and after the consolidation of PAA and related consolidation entries as of June 30, 2009:

PAA GP LLC
UNAUDITED CONDENSED CONSOLIDATING BALANCE SHEET

June 30, 2009
(in millions)

						Plains All American								PAA GP LLC
		PAA GP LLC				Pipeline, L.P.				Adjustments				Consolidated
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	—			$	7			$	—			$	7
Trade accounts receivable and other receivables, net			—				1,674				—				1,674
Inventory			—				995				—				995
Other current assets			—				246				—				246
Total current assets			—				2,922				—				2,922
PROPERTY AND EQUIPMENT			—				6,028				12	(a)			6,040
Accumulated depreciation			—				(773	)			(3)	(a)			(776	)
			—				5,255				9				5,264
OTHER ASSETS
Pipeline linefill in owned assets			—				429				—				429
Long-term inventory			—				127				—				127
Investment in unconsolidated entities			90				256				(90)	(b)			256
Goodwill			—				1,226				—				1,226
Other, net			—				344				—				344
Total assets		$	90			$	10,559			$	(81	)		$	10,568
LIABILITIES AND PARTNERS’ CAPITAL / MEMBER’S EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities		$	—			$	1,927			$	—			$	1,927
Short-term debt			—				938				—				938
Other current liabilities			—				343				—				343
Total current liabilities			—				3,208				—				3,208
LONG-TERM LIABILITIES
Long-term debt under credit facilities and other			—				4				—				4
Senior notes, net of unamortized net discount of $6			—				3,394				—				3,394
Other long-term liabilities and deferred credits			—				247				—				247
Total long-term liabilities			—				3,645				—				3,645
PARTNERS’ CAPITAL / MEMBER’S EQUITY
Limited partners			—				3,558				(3,558)	(b)			—
General partner			—				85				(85)	(b)			—
Member’s equity			90				—				—				90
Total partners’ capital / member’s equity excluding noncontrolling interest			90				3,643				(3,643	)			90
Noncontrolling interest			—				63				3,562	(b)			3,625
Total partners’ capital / member’s equity			90				3,706				(81	)			3,715
Total liabilities and partners’ capital / member’s equity		$	90			$	10,559			$	(81	)		$	10,568

     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.

Recent Accounting Pronouncements

Standards Adopted as of April 1, 2009

     In May 2009, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standard (“SFAS”) No. 165, “Subsequent Events” (“SFAS 165”). SFAS 165 establishes general standards of accounting for and disclosure of subsequent events or events that occur after the balance sheet date but before financial statements are issued. This standard sets forth (i) the period after the balance sheet date during which management shall evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, (ii) the circumstances under which an entity shall recognize events or transactions occurring after the balance sheet date in its financial statements and (iii) the disclosures that an entity shall make about events or transactions that occurred after the balance sheet date. This standard was effective for interim or annual periods ending after June 15, 2009; therefore, we have adopted SFAS 165 as of April 1, 2009. Adoption did not have any material impact on our financial position, results of operations or cash flows.

     In April 2009, the FASB issued FASB Staff Position (“FSP”) No. FAS 107-1, “Interim Disclosures about Fair Value of Financial Statements” (“FSP No. FAS 107-1”). FSP No. FAS 107-1 increases the frequency of fair value disclosures from annual to quarterly in an effort to provide financial statement users with more timely and transparent information about the effects of current market conditions on financial instruments. This is intended to address concerns raised by some financial statement users about the lack of comparability resulting from the use of different measurement attributes for financial instruments. These disclosures are also intended to stimulate more robust discussions about financial instrument valuations between users and reporting entities. We have adopted FSP No. FAS 107-1 as of April 1, 2009. Adoption did not have any material impact on our financial position, results of operations or cash flows.

Standards Adopted as of January 1, 2009

     In November 2008, the EITF issued Issue No. 08-06, “Equity Method Investment Accounting Considerations” (“EITF 08-06”). EITF 08-06 addresses certain accounting considerations, including initial measurement, decreases in investment value, and changes in the level of ownership or degree of influence related to equity method investments. We have adopted EITF 08-06 as of January 1, 2009. Adoption did not have any material impact on our financial position, results of operations or cash flows.

     In April 2008, the FASB issued FSP No. FAS 142-3, “Determination of the Useful Life of Intangible Assets” (“FSP No. FAS 142-3”). FSP No. FAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”). The intent of this FSP is to improve the consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141 (revised 2007), “Business Combinations,” and other generally accepted accounting principles. We have adopted FSP No. FAS 142-3 as of January 1, 2009. Adoption did not have any material impact on our financial position, results of operations or cash flows.

Trade Accounts Receivable

     At June 30, 2009, we had received approximately $147 million of advance cash payments from third parties to mitigate credit risk. In addition, we enter into netting arrangements with our counterparties. These arrangements cover a significant part of our transactions and also serve to mitigate credit risk.

     We review all outstanding accounts receivable balances on a monthly basis and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. At June 30, 2009, substantially all of our net accounts receivable classified as current assets were less than 30 days past their scheduled invoice date. Our allowance for doubtful accounts receivable totaled $8 million at June 30, 2009. Although we consider our allowance for doubtful trade accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.

Inventory, Linefill and Long-term Inventory

     Inventory, linefill and long-term inventory consisted of the following (barrels in thousands and dollars in millions, except per barrel amounts):

		June 30, 2009
										Dollars/
		Barrels				Dollars				Barrel (1)
Inventory
Crude oil			13,694			$	774			$	56.52
LPG			5,882				216			$	36.72
Refined products			40				2			$	50.00
Parts and supplies			N/A				3				N/A
Inventory subtotal			19,616				995
Pipeline linefill in owned assets
Crude oil			9,101				427			$	46.92
LPG			51				2			$	39.22
Pipeline linefill in owned assets subtotal			9,152				429
Long-term inventory
Crude oil			1,690				115			$	68.05
LPG			342				12			$	35.09
Long-term inventory subtotal			2,032				127
Total			30,800			$	1,551

Debt

     Debt consists of the following (in millions):

		June 30,
		2009
Short-term debt:
Senior secured hedged inventory facility bearing interest at a rate of 2.1% at June 30, 2009		$	436
Senior unsecured revolving credit facility, bearing interest at a rate of 0.8% at June 30, 2009(1)			325
Senior notes, net of unamortized discount (2) (3)			175
Other			2
Total short-term debt			938
Long-term debt:
Long-term debt under senior unsecured revolving credit facility and other (1)			4
Senior notes, net of unamortized net premium and discount			3,394
Total long-term debt(1) (3)			3,398
Total debt		$	4,336

     In April 2009, we completed the issuance of $350 million of 8.75% Senior Notes due May 1, 2019. The senior notes were sold at 99.994% of face value. Interest payments are due on May 1 and November 1 of each year, beginning on November 1, 2009. We used the net proceeds from this offering to reduce outstanding borrowings under our credit facilities, which may be reborrowed to fund future investments and for general partnership purposes, including repayment of our $175 million 4.75% senior notes that mature in August 2009.

     See Note 4 for discussion of a September 2009 debt offering.

Letters of Credit

     In connection with our crude oil marketing, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase of crude oil. At June 30, 2009, we had outstanding letters of credit of approximately $51 million.

Partners’ Capital and Distributions

Equity Offerings

     During the six months ended June 30, 2009, we completed the following equity offerings of our common units (in millions, except per unit data):

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

     See Note 4 for discussion of a September 2009 equity offering.

LTIP Vesting

     In May 2009, in connection with the settlement of vested LTIP awards, we issued 277,038 common units at a price of $41.23, for a fair value of approximately $12 million.

Distributions

     The following table details the distributions related to the first six months of 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
2009
July 15, 2009		August 14, 2009 (1)		$	117			$	32			$	2			$	151			$	0.9050
April 8, 2009		May 15, 2009		$	117			$	32			$	2			$	151			$	0.9050
January 14, 2009		February 13, 2009		$	110			$	28			$	2			$	140			$	0.8925

     Upon closing of the Pacific and Rainbow acquisitions, our general partner agreed to reduce the amounts due it as incentive distributions. The total reduction in incentive distributions related to these acquisitions is $75 million. Following the distribution in August 2009, the aggregate remaining incentive distribution reductions related to these acquisitions will be approximately $21 million. See Note 4 for further discussion.

Equity Compensation Plans

Long-Term Incentive Plans

     For discussion of our Long-Term Incentive Plan (“LTIP”) awards, see Note 10 to our Consolidated Financial Statements included in our 2008 Annual Report on Form 10-K. At June 30, 2009, the following LTIP awards were outstanding (units in millions):

				Vesting
LTIP Units				Distribution		Estimated Unit Vesting Date
Outstanding				Amount		2009				2010				2011				2012				2013
	0.6	(1)		$3.20			—				0.6				—				—				—
	1.4	(2)		$3.50 - $4.50			—				—				0.8				0.5				0.1
	1.5	(3)		$3.50 - $4.00			—				0.9				0.2				0.4				—
	3.5	(4) (5)					—				1.5				1.0				0.9				0.1

     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, 2008			3.9			$	36.44
Granted			0.3			$	26.56
Vested			(0.6	)		$	34.72
Cancelled or forfeited			(0.1	)		$	38.99
Outstanding, June 30, 2009			3.5			$	36.68

     Our accrued liability at June 30, 2009 related to all outstanding LTIP awards and DERs is approximately $55 million, which includes an accrual associated with our assessment that an annualized distribution of $3.75 is probable of occurring. We have not deemed a distribution of more than $3.75 to be probable.

Class B Units of Plains AAP, L.P.

     At June 30, 2009, 165,500 Class B units were outstanding, of which 38,500 units were earned. A total of 34,500 units were reserved for future grants. During the six months ended June 30, 2009, 11,500 Class B units were issued to certain members of our senior management. These Class B units become earned in increments of 37.5%, 37.5% and 25% 180 days after us achieving annualized distribution levels of $3.75, $4.00 and $4.50, respectively. The total grant date fair value of the 165,500 Class B units outstanding at June 30, 2009 was approximately $35 million. For further discussion of the Class B units, see Note 10 to our Consolidated Financial Statements included in our 2008 Annual Report on Form 10-K.

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 vestings (settled both in units and cash) related to the equity compensation plans (in millions):

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2009				2009
LTIP unit settled vestings		$	18			$	18
LTIP cash settled vestings		$	7			$	7
DER cash payments		$	1			$	2

Derivatives and Risk Management Activities

     We identify the risks that underlie our core business activities and utilize risk management activities 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. We calculate hedge effectiveness on a quarterly basis. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives 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 generally (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 marketing activities, we purchase crude oil 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, our personnel are authorized to 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 marketing 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 June 30, 2009, material net derivative positions related to these activities included:

	•		An approximate 187,000 barrel per day net long position (total net of 5.6 million barrels) associated with our crude oil activities, which was unwound ratably during July 2009 to match monthly average pricing.
	•		A net short position averaging approximately 15,900 barrels per day (total of 8.1 million barrels) of calendar spread call options for the period August 2009 through December 2010. 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).

	•		An average of approximately 3,500 barrels per day (total of 1.9 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 2010.
	•		Approximately 16,100 barrels per day on average (total of 8.7 million barrels) of crude oil basis differential hedges, which run through 2010.

     Storage Capacity Utilization — We own approximately 56 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 marketing activities, including for the storage of inventory in a contango market. For capacity allocated to our marketing operations we have utilization risk if the market structure is backwardated. As of June 30, 2009, we used derivatives to manage the risk of not utilizing approximately 3 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 marketing 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 June 30, 2009, we had approximately 10 million barrels of inventory hedged with derivatives.

     We also purchase foreign cargoes of crude oil. Concurrent with the purchase of foreign cargo inventory, we enter into derivatives to mitigate the price risk associated with the foreign cargo inventory between the time the foreign cargo is purchased and the ultimate sale of the foreign cargo. As of June 30, 2009, we had approximately 4 million barrels of foreign cargo inventory hedged with derivatives.

     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 June 30, 2009, 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 2.1 million barrels) from July 2009 through December 2011. 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 2 million barrels through December 2011, which provide upside price participation.

     Diluent Purchases — We use diluent in our Canadian crude oil operations and have used derivative instruments to hedge the anticipated forward purchases of diluent. As of June 30, 2009, we had an average of 4,900 barrels per day of natural gasoline/WTI spread positions (approximately 3.5 million barrels) that run through mid-2011.

     The derivative instruments we use consist primarily of futures, options and swaps traded on the NYMEX, ICE and in over-the-counter transactions. Over-the-counter transactions include commodity swap and option contracts entered into with financial institutions and other energy companies. 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 normal purchase and sale exclusion and thus are not subject to SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (“SFAS 133”). Physical transactions that are derivatives and are ineligible, or become ineligible, for the normal purchase and sale treatment (e.g. due to changes in settlement provisions) 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 consist primarily of interest-rate swaps and treasury locks. As of June 30, 2009, AOCI includes deferred losses that relate to terminated interest-rate swaps and treasury locks that were designated for hedge accounting. These terminated interest-rate swaps and treasury locks were cash settled in connection with the issuance

and refinancing of debt agreements over the previous five years. The deferred loss related to these instruments is being amortized to interest expense over the original terms of the forecasted debt instruments.

     As of June 30, 2009, we had one outstanding interest-rate swap by which we receive fixed interest payments and pay floating-rate interest payments based on six-month LIBOR plus a spread of 1.85% on a quarterly basis. The swap has a notional amount of $20 million with a fixed rate of 7.13% and terminates in 2014. The swap is subject to a call option whereby our counterparty has the right to call the swap for approximately $1 million. Our outstanding interest-rate swap is not designated for hedge accounting. However, the interest-rate swap serves as an economic hedge in the event that market interest rates decline below the fixed interest rate of the underlying debt. During June 2009, we received notice from our counterparty of their intention to call the swap. As a result, the swap was called in July 2009 upon our receipt of the termination payment.

Currency Exchange Rate Risk Hedging

     We use foreign currency derivatives to hedge foreign currency risk associated with our exposure to fluctuations in the U.S. Dollar-to-Canadian Dollar exchange rate. Because a significant portion of our Canadian business is conducted in Canadian Dollars and, at times, a portion of our debt is denominated in Canadian Dollars, we use certain financial instruments to minimize the risks of unfavorable changes in exchange rates. These instruments primarily include forward exchange contracts, swaps and options. As of June 30, 2009, AOCI includes deferred gains 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 Canadian Dollar-denominated interest payments on a Canadian Dollar-denominated intercompany note as a result of changes in the foreign exchange rate. The deferred gains related to these instruments are recognized as other income (expense) concurrent with the underlying Canadian Dollar-denominated interest payments.

     As of June 30, 2009, our outstanding foreign currency derivatives also include derivatives used to hedge Canadian Dollar-denominated crude oil purchases and sales. We may from time to time hedge the commodity price risk associated with a Canadian Dollar-denominated commodity transaction with a U.S. Dollar-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 June 30, 2009, our open foreign exchange derivatives consisted of forward exchange contracts that exchange Canadian Dollars for U.S. Dollars on a net basis as follows (in millions):

		Canadian Dollars				U.S. Dollars				Average Exchange Rate
2009		$	29			$	25			CAD $1.15 to US $1.00
2010		$	31			$	27			CAD $1.14 to US $1.00
2011		$	3			$	3			CAD $1.01 to US $1.00
2012		$	3			$	3			CAD $1.01 to US $1.00
2013		$	9			$	9			CAD $1.00 to US $1.00

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

Summary of Financial Impact

     The majority of our derivative activity relates to our commodity price risk hedging activities. Through these activities, we hedge our exposure to price fluctuations with respect to crude oil, LPG, natural gas and refined products, as well as with respect to anticipated purchases, sales and transportation of these commodities. The majority of our 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 occur. Derivatives that do not qualify for hedge accounting and the portion of cash flow hedges that is not highly effective, as defined in SFAS 133, 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 as of June 30, 2009 (in millions):

		Asset Derivatives							Liability Derivatives
		Balance Sheet							Balance Sheet
		Location		Fair Value					Location		Fair Value
Derivatives designated as hedging instruments under SFAS 133:
Commodity contracts		Other current assets		$	94				Other current liabilities		$	(98	)
		Other long-term assets			48				Other long-term liabilities			—
Interest rate contracts		Other current assets			—				Other current liabilities			—
		Other long-term assets			—				Other long-term liabilities			—
Foreign exchange contracts		Other current assets			1				Other current liabilities			—
		Other long-term assets			5				Other long-term liabilities			(1	)
Total derivatives designated as hedging instruments under SFAS 133				$	148						$	(99	)
Derivatives not designated as hedging instruments under SFAS 133:
Commodity contracts		Other current assets		$	102				Other current liabilities		$	(113	)
		Other long-term assets			91				Other long-term liabilities			(57	)
Interest rate contracts		Other current assets			1				Other current liabilities			—
		Other long-term assets			—				Other long-term liabilities			—
Foreign exchange contracts		Other current assets			1				Other current liabilities			(2	)
		Other long-term assets			—				Other long-term liabilities			—
Total derivatives not designated as hedging instruments under SFAS 133				$	195						$	(172	)
Total derivatives				$	343						$	(271	)

     As of June 30, 2009, there was a net loss of $42 million deferred in AOCI. The total amount of deferred net loss recorded in AOCI is expected to be reclassified to future earnings contemporaneously with (i) the related physical purchase or delivery of the underlying commodity, (ii) interest expense accruals associated with the underlying debt instruments and (iii) the recognition of a foreign currency gain or loss upon the remeasurement of certain Canadian Dollar-denominated intercompany interest receivables. Of the total net loss deferred in AOCI at June 30, 2009, a net loss of approximately $106 million is expected to be reclassified to earnings in the next twelve months. Of the remaining deferred gain in AOCI, approximately 75% is expected to be reclassified to earnings prior to 2012 with the remaining deferred gain being reclassified to earnings through 2018. Because a portion of these amounts is based on market prices at the current period end, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

     During the three months ended June 30, 2009, no amounts were reclassified from AOCI to earnings as a result of forecasted transactions no longer considered to be probable of occurring. During the six months ended June 30, 2009, we reclassed a deferred gain of approximately $6 million from AOCI to other income as a result of anticipated hedge transactions that are no longer considered to be probable of occurring.

     Amounts of gain/(loss) recognized in AOCI on derivatives (effective portion) during the three and six months ended June 30, 2009 are as follows (in millions):

		Three Months Ended				Six Months Ended
		June 30, 2009				June 30, 2009
Commodity contracts		$	(104	)		$	(82	)
Foreign exchange contracts			(4	)			(2	)
Total		$	(108	)		$	(84	)

     We do not enter into master netting agreements with our derivative counterparties, nor do we offset the assets and liabilities associated with the fair value of our derivatives with amounts we have recognized related to our right to receive or our obligation to pay cash collateral. When we deposit cash collateral with our brokers, we recognize a broker receivable, which is a component of our accounts 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. Our broker receivable was approximately $5 million as of June 30, 2009. At June 30, 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 June 30, 2009. As required by SFAS 157, 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 and may affect the placement of assets and liabilities within the fair value hierarchy levels.

		Fair Value as of June 30, 2009
		(in millions)
Recurring Fair Value Measures		Level 1				Level 2				Level 3				Total
Assets:
Commodity derivatives		$	289			$	12			$	34			$	335
Interest rate derivatives			—				—				1				1
Foreign currency derivatives			—				—				7				7
Total assets at fair value		$	289			$	12			$	42			$	343
Liabilities:
Commodity derivatives		$	(224	)		$	—			$	(44	)		$	(268	)
Foreign currency derivatives			—				—				(3	)			(3	)
Total liabilities at fair value		$	(224	)		$	—			$	(47	)		$	(271	)
Net asset/(liability) at fair value		$	65			$	12			$	(5	)		$	72

The determination of the fair values above incorporates various factors required under SFAS 157. These factors include 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 commodity derivatives that are exchange-traded, which include derivative contracts 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

     Included within level 2 of the fair value hierarchy is a physical commodity supply contract that meets the definition of a derivative, but is not excluded from SFAS 133 under the normal purchase and normal sale scope exception. The fair value of this commodity derivative is measured with level 1 inputs for similar but not identical instruments and therefore must be included in level 2 of the fair value hierarchy.

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 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 and 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 the derivatives included in level 3 of the fair value hierarchy are classified as level 3 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 measured at fair value using inputs classified as level 3 in the fair value hierarchy (in millions):

		Three Months				Six Months
		Ended				Ended
		June 30,				June 30,
		2009				2009
Balance as of April 1, 2009 and January 1, 2009		$	26			$	74
Realized and unrealized gains/(losses):
Included in earnings			8				54
Included in other comprehensive income/(loss)			(21	)			(22	)
Purchases, issuances, sales and settlements			(18	)			(111	)
Transfers into or (out of) level 3			—				—
Ending Balance as of June 30, 2009		$	(5	)		$	(5	)
Change in unrealized gains/(losses) included in earnings relating to level 3 derivatives still held as of June 30, 2009		$	(8	)		$	(8	)

     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 a master limited partnership, we are not subject to U.S. federal income taxes; rather, the tax effect of our operations is passed through to our unitholders. Although, we are subject to state income taxes in some states, the impact is 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 delay the effective date of such legislation until 2011 provided that such entities do not exceed the normal growth guidelines. Although we continuously review acquisition opportunities that, if consummated, could cause us to exceed the normal growth guidelines, we believe that we are currently within the normal growth guidelines.

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 Environmental Protection Agency (the “EPA”), the Texas Commission on Environmental Quality and the Texas Railroad Commission conducted clean-up operations at each site. Approximately 980 and 4,200 barrels were recovered from the two respective sites. The unrecovered oil was removed or otherwise addressed by us in the course of site remediation. Aggregate costs associated with the releases, including estimated remediation costs, 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 U.S. Department of Justice (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. As a result of our statutory protections and contractual rights of setoff, substantially all of our pre-petition claims against SemCrude should be satisfied. 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. The aggregate amount subject to challenge is approximately $62 million. Certain SemCrude creditors have also filed state court actions alleging a producer’s lien on crude oil sold to SemCrude, and the continuation of such lien when SemCrude sold the oil to subsequent purchasers such as us. 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. Pacific Pipeline System, LLC (“PPS”). In March 2005, a release of approximately 3,400 barrels of crude oil occurred on Line 63, subsequently acquired by us in the Pacific merger. The release occurred when 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, which was filed in the Federal District Court for the Central District of California, Civil Action No. CV08-5768DSF(SSX), seeks the maximum permissible penalty under the relevant statutes of approximately $3.7 million. The Plaintiff filed a motion for summary judgment to determine that the Clean Water Act does not require Plaintiff to demonstrate that PPS was the proximate cause of the release of oil. The motion was granted. The court also affirmed that $3.7 million was the statutory maximum permissible penalty for the release. The EPA and DOJ have discretion to reduce the fine, if any, after considering other mitigating factors. Because of the uncertainty associated with these factors, the final amount of the fine that will be assessed for the alleged

offenses cannot be ascertained. We may also be subjected to injunctive remedies that would impose additional requirements, costs and constraints on our operations. We will defend against these charges. We believe that several defenses and mitigating circumstances and factors exist that could substantially reduce any penalty or fine imposed, and intend to pursue discussions with the EPA and DOJ regarding such defenses and mitigating circumstances and factors. Although we have established an estimated loss contingency for this matter, we are presently unable to determine whether the March 2005 spill incident may result in a loss in excess of our accrual for this matter. Discussions with the DOJ on behalf of the EPA to resolve this matter have commenced.

     Exxon Mobil Corp. v. GATX Corp. (Superior Court of New Jersey — Gloucester County). This Pacific legacy matter involves the allocation of responsibility for remediation of MTBE (and other petroleum product) contamination at the Pacific Atlantic Terminals LLC (“PAT”) facility at Paulsboro, New Jersey. The estimated maximum potential remediation cost ranges up to $8 million. Both Exxon and GATX were prior owners of the terminal. We contend that Exxon and 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 contamination.

     New Jersey Dep’t of Environmental Protection v. ExxonMobil Corp. et al. In a matter related to Exxon v. GATX, the New Jersey Department of Environmental Protection (“NJDEP”) has brought suit against GATX and Exxon to recover natural resources damages associated with the contamination. Exxon and GATX have filed third-party demands against PAT, seeking indemnity and contribution. Discussions with the NJDEP have commenced.

     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. We have, for instance, recently learned that some of the fuel handling activities at two Pacific terminals in Colorado, which activities were performed at the request of customers, may not have been fully compliant with the EPA’s interpretation of certain fuel reporting and record-keeping obligations imposed under the federal Clean Air Act. We have responded to information requests from the EPA regarding these past practices and have been cooperating with EPA in its evaluation of this matter. 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, including a Section 308 request received in late October 2007 with respect to a 400-barrel release of crude oil, a portion of which reached a tributary of the Colorado River in a remote area of West Texas. See “—Pipeline Releases” above.

     At June 30, 2009, our reserve for environmental liabilities totaled approximately $46 million, of which approximately $10 million is classified as short-term and $36 million is classified as long-term. At June 30, 2009, 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 facts known 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 in excess of this reserve may be higher and may potentially have a material adverse effect on our financial condition, results of operations, or cash flows.

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 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 4—Subsequent Events

     In July 2009, PAA completed the issuance of $500 million of 4.25% Senior Notes due September 1, 2012. The senior notes were sold at 99.802% of face value. PAA will pay interest on March 1 and September 1 of each year, beginning on March 1, 2010. PAA used the net proceeds from this offering to supplement the capital available under its existing hedged inventory facility to fund working capital needs associated with base levels of routine foreign crude oil import and for seasonal LPG inventory requirements. Concurrent with the issuance of these Senior Notes, PAA entered into interest rate swaps whereby PAA receives fixed payments at 4.25% and pays three-month LIBOR plus a spread on a notional principal amount of $150 million maturing in two years and an additional $150 million notional principal amount maturing in three years.

     On August 14, 2009, PAA paid a distribution of $0.905 per limited partner unit. We (PAA GP LLC) received a distribution of approximately $2 million associated with our 2% general partner interest in PAA, which we then distributed to AAPLP.

     On September 3, 2009, PAA acquired the remaining 50% interest in PNGS (the “PNGS Acquisition”) from Vulcan Gas Storage LLC (“Vulcan”), which resulted in PAA’s ownership of a 100% interest in PNGS. The purchase price for the transaction was $220 million, consisting of $90 million in cash paid at closing, $90 million in equivalent value of PAA common units (1,907,305 PAA common units based on a 20 business-day average closing price per unit) issued to Vulcan at closing, and up to $40 million of deferred/contingent cash consideration. The deferred/contingent consideration is payable in cash in two installments of $20 million each upon the achievement of certain performance milestones and events expected to occur over the next several years.

     PAA has historically accounted for its 50% indirect interest in PNGS under the equity method. As a result of the PNGS Acquisition, 100% of the natural gas storage business and related operating entities will be accounted for on a consolidated basis. At the closing of the PNGS Acquisition, PAA repaid all of PNGS’s outstanding debt using cash of PNGS and borrowings under PAA’s revolving credit facility.

     To enhance PAA’s distribution coverage ratio over the next 24 months in connection with the PNGS Acquisition, PAA’s general partner has agreed to reduce its incentive distributions by an aggregate of $8 million over the next two years - $1.25 million per quarter for the first four quarters and $0.75 million per quarter for the next four quarters. The IDR reduction will become effective upon payment of a quarterly distribution of $0.92 per limited partner unit.

     In September 2009, PAA completed the issuance of $500 million of 5.75% Senior Notes due January 15, 2020. The senior notes were sold at 99.523% of face value. PAA will pay interest on January 15 and July 15 of each year, beginning on January 15, 2010. PAA used the net proceeds from this offering to repay outstanding borrowings under its credit facilities, a portion of which was incurred to fund the cash requirements of the PNGS Acquisition (which included repayment of all of PNGS’s debt).

     On September 4, 2009, notice was given of PAA’s intent to redeem all of its outstanding $250 million 7.13% senior notes due 2014 on October 5, 2009. These notes will be classified as short-term debt on PAA’s balance sheet beginning on the notice date until they are all redeemed.

     In September 2009, PAA sold 5,290,000 common units representing limited partner interests at $46.70 per common unit. The sale included 1,070,663 common units with an aggregate value of $50 million (based on the public offering price) purchased

by an affiliate of an owner of an aggregate 10 percent interest in PAA’s general partner entities. PAA received net proceeds from the offering, including our capital contribution necessary to maintain our 2% interest and after deducting underwriting discounts and commissions and estimated offering expenses, of approximately $246 million. PAA used the net proceeds of this offering to reduce outstanding borrowings under its credit facilities, which may be re-borrowed to redeem $250 million aggregate principal amount of its outstanding 7.13% senior notes due 2014, and for its general partnership purposes.