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PAA GP LLC

NOTES TO 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 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 December 31, 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. 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 December 31, 2009, our noncontrolling interest was approximately $4.1 billion, which is comprised mostly of the book value of PAA’s net assets that are owned by other parties.

The accompanying 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 consolidated balance sheet of the Company and accompanying notes dated as of December 31, 2009 should be read in conjunction with 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.

Subsequent events have been evaluated through the financial statement issuance 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 December 31, 2009, the unamortized portion of our excess basis was approximately $9 million and is included in Property and Equipment in our 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 $2 million.

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PAA GP LLC

CONSOLIDATING BALANCE SHEET

December 31, 2009
(in millions)


			Plains All American						PAA GP LLC
	PAA GP LLC		Pipeline, L.P.			Adjustments			Consolidated
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	—	$	25		$	—		$	25
Trade accounts receivable and other receivables, net		—		2,253			—			2,253
Inventory		—		1,157			—			1,157
Other current assets		—		223			—			223

Total current assets		—		3,658			—			3,658


PROPERTY AND EQUIPMENT		—		7,240			12	(a)		7,252
Accumulated depreciation		—		(900	)		(3)	(a)		(903	)

		—		6,340			9			6,349


OTHER ASSETS
Linefill and base gas		—		501			—			501
Long-term inventory		—		121			—			121
Investment in unconsolidated entities		97		82			(97)	(b)		82
Goodwill		—		1,287			—			1,287
Other, net		—		369			—			369

Total assets	$	97	$	12,358		$	(88	)	$	12,367

LIABILITIES AND PARTNERS’ CAPITAL / MEMBER’S EQUITY

CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	—	$	2,295		$	—		$	2,295
Short-term debt		—		1,074			—			1,074
Other current liabilities		—		413			—			413

Total current liabilities		—		3,782			—			3,782

LONG-TERM LIABILITIES
Long-term debt under credit facilities and other		—		6			—			6
Senior notes, net of unamortized net discount of $14		—		4,136			—			4,136
Other long-term liabilities and deferred credits		—		275			—			275

Total long-term liabilities		—		4,417			—			4,417


PARTNERS’ CAPITAL / MEMBER’S EQUITY
Limited partners		—		4,002			(4,002)	(b)		—
General partner		—		94			(94)	(b)		—
Member’s equity		97		—			—			97

Total partners’ capital / member’s equity excluding noncontrolling interest		97		4,096			(4,096	)		97
Noncontrolling interest		—		63			4,008	(b)		4,071

Total partners’ capital / member’s equity		97		4,159			(88	)		4,168

Total liabilities and partners’ capital / member’s equity	$	97	$	12,358		$	(88	)	$	12,367

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(a)		Reflects the excess basis and related accumulated amortization of the book value of the Company’s investment in PAA.

(b)		Reflects the elimination of the Company’s investment in PAA and PAA’s capital and the establishment of noncontrolling interest, which is comprised of the book value of the Company’s consolidated net assets that are owned by other parties, as appropriate in consolidation.

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.

Summary of Significant Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We make significant estimates with respect to (i) purchases and sales accruals, (ii) estimated fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets, (iii) mark-to-market gains and losses on derivative instruments (pursuant to guidance issued by the FASB regarding fair value measurements), (iv) accruals and contingent liabilities, (v) equity compensation plan accruals, (vi) property, plant and equipment and depreciation expense and (vii) allowance for doubtful accounts. Although we believe these estimates are reasonable, actual results could differ from these estimates.

Cash and Cash Equivalents

Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of three months or less and typically exceed federally insured limits. We periodically assess the financial condition of the institutions where these funds are held and believe that our credit risk is minimal. In accordance with our policy, outstanding checks are classified as accounts payable rather than negative cash. As of December 31, 2009, accounts payable included approximately $50 million of outstanding checks that were reclassified from cash and cash equivalents.

Accounts Receivable

Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of LPG, refined products and natural gas storage. These purchasers include, but are not limited to refineries, producers, marketing and trading companies and financial institutions that are active in the physical and financial commodity markets. The majority of our accounts receivable relate to our crude oil supply and logistics activities that can generally be described as high volume and low margin activities, in many cases involving exchanges of crude oil volumes.

During the last two years, U.S. and world financial markets and energy prices were extremely volatile and global economies substantially weakened. This financial market volatility combined with the fluctuation in energy prices experienced over the past two years has caused liquidity issues impacting many companies, which in turn have increased the potential credit risks associated with certain counterparties with which we do business.

To mitigate such credit risks, we have in place a rigorous credit review process. We closely monitor these conditions in order to make a determination with respect to the amount, if any, of credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of standby letters of credit, “parental” guarantees or advance cash payments. At December 31, 2009, we had received approximately $212 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 December 31, 2009, substantially all of our net accounts receivable were less than 60 days past their scheduled invoice date. Our allowance

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for doubtful accounts receivable totaled $9 million at December 31, 2009. Although we consider our allowance for doubtful trade accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.

Inventory, Linefill, Base Gas and Long-term Inventory

Inventory primarily consists of crude oil, LPG, refined products and natural gas in pipelines, storage facilities and rail cars that are valued at the lower of cost or market, with cost determined using an average cost method within specific inventory pools.

At the end of each reporting period we assess the carrying value of our inventory and make any adjustments necessary to reduce the carrying value to the applicable net realizable value. During 2009, no writedowns were recognized. Linefill, base gas and minimum working inventory requirements in assets we own are recorded at historical cost and consist of crude oil, LPG and natural gas. Linefill is used to pack the pipeline such that when an incremental product is injected into or enters a pipeline it forces product out at another location. Base gas requirements of natural gas, as well as the minimum amount of crude oil and refined products is used to operate our storage and terminalling facilities, similar to linefill in the pipelines. During 2009, we recorded gains of approximately $4 million on the sale of pipeline linefill for proceeds of approximately $24 million.

Minimum working inventory requirements in third-party assets and other working inventory in our assets that is needed for our commercial operations are included within specific inventory pools in Inventory (a current asset) in determining the average cost of operating inventory. At the end of each period, we reclassify the inventory not expected to be liquidated within the succeeding twelve months out of inventory, at average cost, and into long-term inventory, which is reflected as a separate line item within other assets on the consolidated balance sheet.

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


	December 31, 2009
			Unit of	Total		Price/
	Volumes		Measure	Value		Unit (1)
Inventory
Crude oil		12,232	barrels	$	886	$	72.43
LPG		6,051	barrels		247	$	40.82
Refined products		283	barrels		21	$	74.20
Natural gas (2) (3)		181	cubic feet		1	$	3.30
Parts and supplies		N/A			2		N/A

Inventory subtotal					1,157


Linefill and base gas
Crude oil		9,404	barrels		471	$	50.09
Natural gas (2) (3)		9,194	cubic feet		28	$	3.04
LPG		52	barrels		2	$	38.46

Linefill and base gas subtotal					501


Long-term inventory
Crude oil		1,497	barrels		103	$	68.80
LPG		458	barrels		18	$	39.30

Long-term inventory subtotal					121

Total				$	1,779


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

(2)		To account for the 6:1 mcf of natural gas to crude oil barrel ratio, the natural gas volumes can be converted to barrels by dividing by 6.

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(3)		In September 2009, we acquired the remaining 50% indirect interest in PAA Natural Gas Storage, LLC (“PNGS”). We historically accounted for our 50% indirect interest in PNGS under the equity method. As such, we did not have direct ownership of PNGS’s natural gas inventory or base gas.

Property, Plant and Equipment

In accordance with our capitalization policy, costs associated with acquisitions and improvements that expand our existing capacity, including related interest costs, are capitalized. For the year ended December 31, 2009, capitalized interest was $15 million. We also capitalize expenditures for the replacement of partially or fully depreciated assets in order to maintain the service capability, level of production, and/or functionality of our existing assets. Repair and maintenance expenditures incurred in order to maintain the day to day operation of our existing assets are expensed as incurred.

Property, plant and equipment, net is stated at cost and consisted of the following (in millions):


	Estimated Useful		December 31,
	Lives (Years)		2009
Crude oil pipelines and facilities		30 - 50	$	4,535
Storage and terminal facilities		30 - 70		1,735
Trucking equipment and other		5 - 15		331
Construction in progress		—		476
Office property and equipment		3 - 5		84
Land and other		N/A		79

				7,240
Less accumulated depreciation				(900	)


Property and equipment, net			$	6,340

Equity Method of Accounting

Our investments in Frontier Pipeline Company (“Frontier”), Settoon Towing, LLC (“Settoon Towing”) and Butte Pipe Line Company (“Butte”) are accounted for under the equity method of accounting. Our ownership interests in Frontier, Settoon Towing and Butte are 22%, 50% and 22%, respectively. We do not consolidate any part of the assets or liabilities of our equity investees. Our share of net income or loss is reflected as one line item on the income statement and will increase or decrease, as applicable, the carrying value of our investments on the balance sheet. In addition, we include a proportionate share of our equity method investees’ unrealized gains and losses in other comprehensive income on our consolidated balance sheet. We also adjust our investment balances in these investees by the like amount. Distributions to the Partnership will reduce the carrying value of our investments and will be reflected on our cash flow statement netted against equity in earnings. In turn, contributions will increase the carrying value of our investments and will be reflected on our cash flow statement within investing activities.

Noncontrolling Interest

We account for noncontrolling interests in subsidiaries in accordance with FASB guidance specific to noncontrolling interests. FASB guidance requires all entities to report noncontrolling interests in subsidiaries (formerly referred to as minority interest) as a component of equity in the consolidated financial statements. Noncontrolling interest represents the portion of assets and liabilities in a subsidiary that is owned by a third-party.

Asset Retirement Obligations

FASB guidance establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including estimates related to (i) the time of the liability recognition, (ii) initial measurement of the liability, (iii) allocation of asset retirement cost to expense, (iv) subsequent measurement of the liability and (v) financial statement disclosures. FASB guidance also requires that the cost for asset retirement should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method.

Some of our assets, primarily related to our transportation and facilities segments, have contractual or regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are abandoned. These obligations include

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varying levels of activity including disconnecting inactive assets from active assets, cleaning and purging assets, and in some cases, completely removing the assets and returning the land to its original state. These assets have been in existence for many years and with regular maintenance will continue to be in service for many years to come. It is not possible to predict when demand for these transportation or storage services will cease and we do not believe that such demand will cease for the foreseeable future. Accordingly, we believe the date when these assets will be abandoned is indeterminate. With no reasonably determinable abandonment date, we cannot reasonably estimate the fair value of the associated asset retirement obligations. We will record asset retirement obligations for these assets in the period in which sufficient information becomes available for us to reasonably determine the settlement dates.

A small portion of our contractual or regulatory obligations is related to assets that are inactive or that we plan to take out of service and, although the ultimate timing and costs to settle these obligations are not known with certainty, we have recorded a reasonable estimate of these obligations. We have estimated that the fair value of these obligations was approximately $5 million at December 31, 2009.

Impairment of Long-Lived Assets

Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value in accordance with FASB guidance with respect to the accounting for the impairment or disposal of long-lived assets. Under this guidance, a long-lived asset is tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized.

We periodically evaluate property, plant and equipment for impairment when events or circumstances indicate that the carrying value of these assets may not be recoverable. The evaluation is highly dependent on the underlying assumptions of related cash flows. The subjective assumptions used to determine the existence of an impairment in carrying value include:

	•		whether there is an indication of impairment;

	•		the grouping of assets;

	•		the intention of “holding” versus “selling” an asset;

	•		the forecast of undiscounted expected future cash flow over the asset’s estimated useful life; and

	•		if an impairment exists, the fair value of the asset or asset group.

During 2009, we recognized impairments of less than $1 million for assets taken out of service. These assets did not support spending the capital necessary to continue service and we utilized other assets to handle these activities.

Goodwill

In accordance with FASB guidance, we test goodwill at least annually (as of June 30) and on an interim basis if a triggering event occurs, such as an adverse change in business climate, to determine whether an impairment has occurred. Goodwill is tested for impairment at a level of reporting referred to as a reporting unit. A reporting unit is an operating segment or one level below an operating segment for which discrete financial information is available and regularly reviewed by segment management. Our reporting units are our operating segments. FASB guidance requires a two step approach to testing goodwill for impairment. In Step 1, we compare the fair value of the reporting unit with the respective book values, including goodwill, by using an income approach based on a discounted cash flow analysis. This approach requires us to make long-term forecasts of future revenues, expenses and other expenditures. Those forecasts require the use of various assumptions and estimates, the most significant of which are net revenues (total revenues less purchases and related costs), operating expenses, general and administrative expenses and the weighted-average cost of capital. Fair value of the reporting units is determined using significant unobservable inputs, or level 3 inputs in the fair value hierarchy. When the fair value is greater than book value, then the reporting unit’s goodwill is not considered impaired. If the book value is greater than fair value, then we proceed to Step 2. In Step 2, we compare the implied fair value of the reporting unit’s goodwill with the book value. A goodwill impairment loss is recognized if the carrying amount exceeds its fair value.

In addition, there is a potential indicator of impairment if a company’s market capitalization is less than its book equity. Periodically, we compare our market capitalization to our book equity to determine if there is an indicator of potential impairment. Throughout 2009, our

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market capitalization exceeded the book value of our equity and thus, this indicated that there was no triggering event. There were no other indicators of potential impairment of our goodwill during 2009.

Through Step 1 of our annual testing of goodwill for potential impairment, we determined that the fair value of each reporting unit was greater than its respective book value, and therefore goodwill was not considered impaired.

We will continue to monitor various potential indicators (including the financial markets) to determine if a triggering event occurs and will perform another goodwill impairment analysis if necessary. We have not recognized any impairment of goodwill during 2009.

The table below reflects our changes in goodwill (in millions):


						Supply &
	Transportation			Facilities		Logistics		Total ₍₁₎
Balance at December 31, 2008	$	562		$	283	$	365	$	1,210


2009 Goodwill Related Activity:
PNGS acquisition		—			25		—		25
Other acquisitions		24			—		—		24
Purchase accounting adjustments ₍₂₎		(3	)		—		—		(3	)
Foreign currency translation adjustments		25			—		6		31


Balance at December 31, 2009	$	608		$	308	$	371	$	1,287


₍₁₎		As of December 31, 2009, we do not have any accumulated impairment losses.

₍₂₎		Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation. This preliminary goodwill balance may be adjusted when the purchase price allocation is finalized.

Other Assets, Net

Other assets, net of accumulated amortization consist of the following (in millions):


	2009
Debt issue costs	$	42
Fair value of derivative instruments		77
Intangible assets		239
Other		65

		423
Less accumulated amortization		(54	)

	$	369

Costs incurred in connection with the issuance of long-term debt and amendments to our credit facilities are capitalized and amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the “effective interest” method of amortization. Fully amortized debt issue costs and the related accumulated amortization are written off in conjunction with the refinancing or termination of the applicable debt arrangement. We capitalized debt issue costs of approximately $12 million in 2009.

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Intangible assets that have finite lives are tested for impairment when events or circumstances indicate that the carrying value may not be recoverable. Our intangible assets that have finite lives consist of the following (in millions):


			December 31, 2009
	Estimated Useful				Accumulated
	Lives (Years)		Cost		amortization			Net
Customer contracts and relationships		1-30	$	171	$	(36	)	$	135
Emission reduction credits ₍₁₎		N/A		45		—			45
Property tax abatement		13		23		(1	)		22

			$	239	$	(37	)	$	202


₍₁₎		Emission reduction credits are finite lived and are subject to amortization from the date that they are first utilized. At December 31, 2009, none of our emission reduction credits were being utilized because the projects for which they were acquired are not in service.

Environmental Matters

We record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We also record receivables for amounts recoverable from insurance or from third parties under indemnification agreements in the period that we determine the costs are probable of recovery.

We expense expenditures that relate to an existing condition caused by past operations that do not contribute to current or future profitability. We record environmental liabilities assumed in business combinations based on the estimated fair value of the environmental obligations caused by past operations of the acquired company.

Income and Other Taxes

We estimate (i) income taxes in the jurisdictions in which we operate, (ii) net deferred tax assets and liabilities based on temporary differences that are expected to be recovered or settled at the enacted tax rates expected in future periods, (iii) valuation allowances for deferred tax assets and (iv) contingent tax liabilities for estimated exposures related to our current tax positions. We have not recorded a valuation allowance against our deferred tax assets as we believe that it is more likely than not that they will be realized.

We adopted the provisions of the FASB guidance related to accounting for uncertainty in income taxes on January 1, 2007. Pursuant to this guidance, we must recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the tax position and also the past administrative practices and precedents of the taxing authority. As of December 31, 2009, we have not recognized any material amounts in connection with uncertainty in income taxes.

Recent Accounting Pronouncements

In June 2009, the FASB issued guidance to establish the source of authoritative generally accepted accounting principles to be applied by nongovernmental entities in the preparation of financial statements. As this guidance is meant to establish the source of authoritative GAAP and to better organize current accounting guidance, it only affects the referencing to applicable guidance throughout the accompanying consolidated financial statements and the notes thereto. This guidance was effective for interim or annual periods ending after September 15, 2009; therefore, we adopted this guidance as of July 1, 2009. Our adoption did not have any material impact on our financial position.

In May 2009, the FASB issued guidance that 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 guidance 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

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date. This guidance was effective for interim or annual periods ending after June 15, 2009; therefore, we adopted this guidance as of April 1, 2009. Adoption did not have any material impact on our financial position.

In April 2009, the FASB issued guidance that 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 adopted this guidance as of April 1, 2009. Adoption did not have any material impact on our financial position.

In November 2008, the FASB issued guidance that 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 adopted this guidance as of January 1, 2009. Adoption did not have any material impact on our financial position.

In April 2008, the FASB issued guidance that 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 previous guidance over goodwill and other intangible assets. The intent of this guidance is to improve the consistency between the useful life of a recognized intangible asset and the period of expected cash flows used to measure the fair value of the asset under generally accepted accounting principles. We adopted this guidance as of January 1, 2009. Adoption did not have any material impact on our financial position.

In March 2008, the FASB issued guidance that amends previous guidance with respect to disclosures of derivative instruments and hedging activities. This guidance requires enhanced disclosures about (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedged items are accounted for under the guidance and its related interpretations and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The provisions of this guidance were effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We adopted this guidance as of January 1, 2009. Adoption did not have any material impact on our financial position.

In December 2007, the FASB issued guidance regarding accounting for noncontrolling interests in consolidated financial statements. This guidance requires all entities to report noncontrolling (minority) interests in subsidiaries as equity in the consolidated financial statements. The guidance eliminates the diversity that currently exists in accounting for transactions between an entity and noncontrolling interests by requiring that they be treated as equity transactions. The provisions of this guidance were effective on a prospective basis for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. We adopted this guidance as of January 1, 2009. Such adoption did not have any material impact on our consolidated financial position.

In December 2007, the FASB issued further guidance regarding accounting for business combinations. This guidance establishes principles and requirements for how an acquirer (i) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (ii) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase and (iii) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. The provisions of this guidance were effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We adopted this guidance as of January 1, 2009. Adoption has impacted our accounting for acquisitions subsequent to that date.

Derivative Instruments and Hedging Activities

We identify the risks that underlie our core business activities and utilize 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. We record all open derivative instruments on the balance sheet as either assets or liabilities measured at their fair value per the guidance issued by the FASB. This guidance requires that changes in the fair value of derivative instruments be recognized currently in earnings unless specific hedge accounting criteria are met, in which case, changes in fair value of cash flow hedges are deferred in AOCI and reclassified into earnings when the underlying transaction affects earnings. Accordingly, changes in fair value are included in current period earnings for (i) derivatives that do not qualify for hedge accounting and (ii) the portion of cash flow hedges that are not highly effective in offsetting changes in cash flows of hedged items.

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Acquisitions and Dispositions

The following acquisitions were accounted for using the purchase method of accounting and the purchase price was allocated in accordance with such method.

2009 Acquisitions

PNGS Acquisition. On September 3, 2009, we acquired the remaining 50% indirect interest in PAA Natural Gas Storage, LLC (“PNGS”) for an aggregate purchase price of $215 million (“PNGS Acquisition”). The $215 million purchase price consisted of $90 million in cash paid at closing, approximately $91 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. The fair value of this contingent consideration is approximately $34 million. As a result of the transaction, we now own 100% of PNGS’s natural gas storage business and related operating entities, which are accounted for on a consolidated basis beginning in September 2009. We historically accounted for our 50% indirect interest in PNGS under the equity method. We recorded a net gain of approximately $9 million in connection with (i) adjusting our previously owned 50% investment in PNGS to fair value and (ii) terminating an agreement to supply natural gas to PNGS.

PNGS currently owns and operates two natural gas storage facilities located in Louisiana and Michigan that have an aggregate working gas storage capacity of 40 billion cubic feet (“Bcf”) and an aggregate peak injection and withdrawal capacity of 1.7 Bcf per day and 3.2 Bcf per day, respectively. PNGS also leases storage capacity and pipeline transportation capacity from third parties from time to time in order to increase its operational flexibility and enhance the services it offers its customers. As of December 31, 2009, PNGS had 3 Bcf of storage capacity under lease from third parties and had secured the right to 379 MMcf per day of firm transportation service on various pipelines. Substantially all of PNGS’s revenues are derived from the provision of firm storage services under multi-year, fee-based contracts. The gas storage operations are reflected in our facilities segment.

The purchase price consisted of the following (in millions):


Cash	$	90
PAA equity		91

Paid at closing		181
Fair value of contingent consideration ₍₁₎		34

Total purchase price	$	215


₍₁₎		The deferred contingent cash 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. The fair value of the deferred contingent cash consideration was based on a discounted cash flow model utilizing a discount rate of approximately 9%.

The allocation of fair value to the assets and liabilities acquired in the PNGS Acquisition is as follows (in millions):


Property, plant and equipment	$	791
Base gas		28
Goodwill		25
Intangible assets		23
Working capital and other long-term assets and liabilities		9
Debt		(446	)

Total	$	430

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Other 2009 Acquisitions. During 2009, we completed six additional acquisitions for an aggregate consideration of approximately $178 million. These acquisitions included an additional 21% undivided joint interest in Capline and associated tankage, as well as various crude oil pipelines and pipeline systems that are all included within our transportation segment. We also acquired a natural gas processing business, a refined products terminal and various crude oil storage tanks and other related assets that are all included within our facilities segment. The goodwill associated with such acquisitions was approximately $24 million. As of December 31, 2009, purchase price allocations have not been finalized for all acquisitions.

Dispositions

During 2009, we sold various property and equipment for proceeds totaling approximately $4 million. A loss of less than $1 million was recognized in 2009 related to these sales.

Debt

Debt consists of the following (in millions):


	December 31,
	2009
Short-term debt:
Senior secured hedged inventory facility bearing interest at a rate of 2.5% at December 31, 2009	$	300
Senior unsecured revolving credit facility, bearing interest at a rate of 0.8% at December 31, 2009 ₍₁₎		772
Other		2

Total short-term debt		1,074

Long-term debt:
4.75% senior notes due August 2009 ₍₂₎		—
4.25% senior notes due September 2012 ₍₃₎		500
7.75% senior notes due October 2012		200
5.63% senior notes due December 2013		250
7.13% senior notes due June 2014 ₍₄₎		—
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 ₍₁₎		6

Total long-term debt _{(1) (5)}		4,142

Total debt	$	5,216


₍₁₎		At December 31, 2009, we have classified $772 million of borrowings under our senior unsecured revolving credit facility as short-term. These borrowings are designated as working capital borrowings, must be repaid within one year, and are primarily for hedged LPG and crude oil inventory and New York Mercantile Exchange (“NYMEX”) and IntercontinentalExchange (“ICE”) margin deposits.

₍₂₎		We repaid our $175 million 4.75% senior notes on August 15, 2009.

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₍₃₎		These notes were issued in July 2009 and the proceeds are being used to supplement capital available from our hedged inventory facility. At December 31, 2009, approximately $222 million had been used to fund hedged inventory and would be classified as short-term debt if funded on our credit facilities.

₍₄₎		On October 5, 2009 we redeemed all of our outstanding $250 million 7.13% senior notes due 2014. In conjunction with the early redemption, we recognized a loss of approximately $4 million.

₍₅₎		Our fixed rate senior notes have a face value of approximately $4.2 billion as of December 31, 2009. We estimate the aggregate fair value of these notes as of December 31, 2009 to be approximately $4.4 billion. Our fixed-rate senior notes are traded among institutions, which trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near year end.

Credit Facilities

In October 2009, we renewed our 364-day committed hedged inventory credit facility, which matures in October 2010. The new committed facility replaced a similar $525 million facility that was scheduled to mature on November 5, 2009. The new facility has a borrowing capacity of $500 million, which may be increased to $1.2 billion subject to obtaining additional lender commitments. Borrowings under this facility will be used to finance the purchase of hedged crude oil inventory for storage activities and foreign imports. At December 31, 2009, borrowings of approximately $300 million were outstanding under this facility.

As of December 31, 2009, the aggregate borrowing capacity of our senior unsecured revolving credit facility was $1.6 billion (including the sub-facility for Canadian borrowings of $600 million). This credit facility has a maximum debt coverage ratio of 4.75 to 1.0 (5.5 to 1.0 during an acquisition period) and a maturity date of July 2012. Also, the senior unsecured revolving credit facility can be expanded to $2.0 billion, subject to additional lender commitments. At December 31, 2009, amounts outstanding under this facility and together with committed letters of credit were $849 million.

Senior Notes

In September 2009, we 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. Interest payments are due on January 15 and July 15 of each year, beginning on January 15, 2010. We used the net proceeds from this offering to repay outstanding borrowings under our credit facilities, a portion of which was used to fund the cash requirements of the PNGS Acquisition (which included repayment of all of PNGS’s debt).

In July 2009, we 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. Interest payments are due on March 1 and September 1 of each year, beginning on March 1, 2010. We used the net proceeds from this offering to supplement the capital available under our 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, we entered into interest rate swaps whereby we receive fixed payments at 4.25% and pay 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.

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.

In each instance, the notes were co-issued by Plains All American Pipeline, L.P. and a 100% owned consolidated finance subsidiary (neither of which have independent assets or operations) and are fully and unconditionally guaranteed, jointly and severally, by most of our subsidiaries.

Covenants and Compliance

Our credit agreements and the indentures governing the senior notes contain cross-default provisions. Our credit agreements prohibit distributions on, or purchases or redemptions of, units if any default or event of default is continuing. In addition, the agreements contain various covenants limiting our ability to, among other things:

•

incur indebtedness if certain financial ratios are not maintained;

F-16

	•		grant liens;

	•		engage in transactions with affiliates;

	•		enter into sale-leaseback transactions; and

	•		sell substantially all of our assets or enter into a merger or consolidation.

Our senior unsecured revolving credit facility treats a change of control as an event of default and also requires us to maintain a debt-to-EBITDA coverage ratio that will not be greater than 4.75 to 1.0 on outstanding debt, and 5.5 to 1.0 on all outstanding debt during an acquisition period (generally, the period consisting of three fiscal quarters following an acquisition greater than $50 million).

For covenant compliance purposes, letters of credit and borrowings to fund hedged inventory and margin requirements are excluded when calculating the debt coverage ratio.

A default under our credit facility would permit the lenders to accelerate the maturity of the outstanding debt. As long as we are in compliance with our credit agreements, our ability to make distributions of available cash is not restricted. As of December 31, 2009, we were in compliance with the covenants contained in our credit agreements and indentures.

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. These letters of credit are issued under our senior unsecured revolving credit facility, and our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the crude oil is purchased. Generally, these letters of credit are issued for periods of up to seventy days and are terminated upon completion of each transaction. At December 31, 2009, we had outstanding letters of credit of approximately $76 million.

Maturities

The weighted average life of our long-term debt outstanding at December 31, 2009 was approximately 11 years and the aggregate maturities for the next five years and thereafter are as follows (in millions):


Calendar Year	Payment
2010	$	—
2011		—
2012		700
2013		250
2014		—
Thereafter		3,200

Total ₍₁₎	$	4,150


₍₁₎		Excludes aggregate unamortized net discount of $14 million and an adjustment of $1 million related to a fair value hedge.

Partners’ Capital and Distributions

Units Outstanding

Partners’ capital at December 31, 2009 consists of 136,135,988 common units outstanding, representing a 98% effective aggregate ownership interest in the Partnership and its subsidiaries after giving effect to the 2% general partner interest.

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Distributions

We distribute 100% of our available cash within 45 days after the end of each quarter to unitholders of record and to our general partner. Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter, less reserves established by our general partner for future requirements.

General Partner Incentive Distributions

Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, the general partner is typically entitled, without duplication, to 15% of amounts we distribute in excess of $0.450 per unit, referred to as our minimum quarterly distributions (“MQD”), 25% of the amounts we distribute in excess of $0.495 per unit and 50% of amounts we distribute in excess of $0.675 per unit (referred to as “incentive distributions”).

Per unit cash distributions on our outstanding units and the portion of the distributions representing an excess over the MQD were as follows:


	2009
			Excess
	Distribution ₍₁₎		over MQD
First Quarter	$	0.8925	$	0.4425
Second Quarter	$	0.9050	$	0.4550
Third Quarter	$	0.9050	$	0.4550
Fourth Quarter	$	0.9200	$	0.4700


₍₁₎		Distributions represent those declared and paid in the applicable period.

In order to enhance our distribution coverage ratio and liquidity following a significant acquisition, our general partner may agree to reduce the amounts due to it as incentive distributions. Upon closing of the Pacific acquisition in November 2006 and the Rainbow acquisition in May 2008, our general partner agreed to reduce the amounts due to it as incentive distributions. Additionally, in connection with the PNGS Acquisition, our general partner agreed to further 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. This incentive distribution reduction became effective upon payment of our November 2009 quarterly distribution of $0.9200 per limited partner unit. The total reduction in incentive distributions related to the Pacific, Rainbow and PNGS acquisitions is $83 million as displayed on an annual basis in the following table (in millions):


Acquisition	2007		2008		2009		2010		2011		Total
Pacific	$	20	$	15	$	15	$	10	$	5	$	65
Rainbow		—		3		6		1		—		10
PNGS		—		—		1		5		2		8

Total	$	20	$	18	$	22	$	16	$	7	$	83

Following the distribution in February 2010 (as discussed below), the aggregate remaining incentive distribution reductions will be approximately $18 million.

Total cash distributions made were as follows (in millions, except per unit amounts):


	Distributions Paid								Distributions per
	Common		General Partner						limited partner
Year	Units		Incentive		2%		Total		unit
2009	$	468	$	127	$	10	$	605	$	3.62

On January 20, 2010, we declared a cash distribution of $0.9275 per unit on our outstanding common units. The distribution was paid on February 12, 2010 to unitholders of record on February 2, 2010, for the period October 1, 2009 through December 31, 2009. The total distribution paid was approximately $166 million, with approximately $126 million paid to our common unitholders and $3 million and $37 million paid to our general partner for its general partner and incentive distribution interests, respectively.

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Noncontrolling Interest in a Subsidiary

During the fourth quarter of 2008, we completed construction on a 94-mile expansion of the Salt Lake City Area system from Wahsatch, Utah to Salt Lake City. During the first quarter of 2009, this pipeline became fully operational. Pursuant to a master formation agreement, we contributed the pipeline with a book value of approximately $254 million to a newly formed joint venture, SLC Pipeline LLC (“SLC Pipeline”). Holly Energy Partners-Operating, L.P. (“HEP”) contributed approximately $26 million in cash for a 25% ownership in SLC Pipeline. We own the remaining 75% interest in SLC Pipeline and control the joint venture, and therefore, have consolidated the financial results. We recognized a loss in partners’ capital of approximately $38 million related to the formation of the SLC Pipeline joint venture during 2009. This loss represents the difference between HEP’s contribution of cash and the book value of its 25% interest in the net assets of SLC Pipeline. As of December 31, 2009, the noncontrolling interest on the balance sheet consists solely of HEP’s interest in the net assets of SLC Pipeline.

Equity Offerings

During the year ended December 31, 2009, we completed the following equity offerings of our common units (in millions, except unit and per unit data):


							General
			Gross		Proceeds		Partner					Net
Period	Units Issued		Unit Price		from Sale		Contribution		Costs			Proceeds
September 2009 ₍₁₎		5,290,000	$	46.70	$	247	$	5	$	(6	)	$	246
March 2009 ₍₁₎		5,750,000		36.90		212		4		(6	)		210

2009 Total		11,040,000			$	459	$	9	$	(12	)	$	456


₍₁₎		These offerings of common units were underwritten transactions that required us to pay a gross spread. The net proceeds from these offerings were used to reduce outstanding borrowings under our credit facilities and for general partnership purposes.

PNGS Acquisition

In September 2009, we issued 1,907,305 common units valued at approximately $91 million in order to satisfy a portion of the PNGS Acquisition purchase price. In conjunction with the issuance, we received a contribution from our general partner of approximately $2 million.

Class B Units of Plains AAP, L.P.

In August 2007, the owners of Plains AAP, L.P. authorized the board of directors of Plains All American GP LLC to issue grants of Class B units of Plains AAP, L.P. (“Class B units”). At December 31, 2009, grants of approximately 165,500 Class B units were outstanding, of which 38,500 were earned. A total of 34,500 Class B units are reserved for future issuances.

Canadian Withholding Tax

For federal income tax purposes, we are treated as a partnership. Our unitholders are required to report their share of our income, gains, losses and deductions on their federal income tax return. In certain cases, we are subject to, and have paid, Canadian income and withholding taxes. The withholding tax payments are considered to be paid on behalf of our unitholders and thus are treated as distributions for financial reporting purposes. During 2009, we paid approximately $6 million of Canadian withholding taxes.

Derivatives and Hedging Instruments

We identify the risks that underlie our core business activities and utilize 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

F-19

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 December 31, 2009, material net derivative positions related to these activities included:

	•		An approximate 173,900 barrel per day net long position (total of 5.2 million barrels) associated with our crude oil activities, which was unwound ratably during January 2010 to match monthly average pricing.

	•		An approximate 17,500 barrel per day (total of 13.1 million barrels) net short spread position which hedge 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 8,300 barrels per day (total of 6 million barrels) of calendar spread call options for the period February 2010 through January 2012. These derivatives in the aggregate do not result in exposure to outright price movements.

	•		An average of approximately 4,200 barrels per day (total of 1.1 million barrels) of butane/West Texas Intermediate (“WTI”) spread positions, which hedge specific butane sales contracts that are priced as a fixed percentage of WTI and continue through September 2010.

	•		Approximately 18,500 barrels per day on average (total of 6.7 million barrels) of crude oil basis differential hedges through December 2010.

	•		An approximate 5,600 barrels per day (total of 0.5 million barrels) of propane swaps to hedge committed sales of propane inventory through March 2010.

Storage Capacity Utilization — We own approximately 57 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 December 31, 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).

F-20

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 December 31, 2009, we had approximately 8.2 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 December 31, 2009, we had approximately 2.6 million barrels of crude oil derivatives hedging the anticipated sale of foreign crude inventory and 2.2 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 December 31, 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 2.4 million barrels) from January 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 2 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 December 31, 2009, we had an average of 2,400 barrels per day of natural gasoline/WTI spread positions (approximately 1.3 million barrels) that run through mid-2011 and an average of 3,300 barrels per day of short crude oil futures (approximately 0.6 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 anticipated purchases of natural gas. As of December 31, 2009, we have a net long position of approximately 3 Bcf consisting of natural gas futures contracts through August 2010.

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 normal purchase and normal sale (“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 December 31, 2009, 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 December 31, 2009, 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.

F-21

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 forward exchange contracts and foreign currency forwards and options. As of December 31, 2009, 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 December 31, 2009, 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 December 31, 2009, 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	$	43	$	39	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.

F-22

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


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

Total derivatives designated as hedging instruments		$	189		$	(141	)

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

Total derivatives not designated as hedging instruments		$	79		$	(128	)

Total derivatives		$	268		$	(269	)

As of December 31, 2009, there was a net gain of $18 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 interest receivables. Of the total net gain deferred in AOCI at December 31, 2009, a net loss of approximately $25 million is expected to be reclassified to earnings in the next twelve months. Of the remaining deferred gain in AOCI, approximately 96% 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 year ended December 31, 2009, we reclassed a deferred gain of approximately $5 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 loss recognized in AOCI on derivatives (effective portion) during the year ended December 31, 2009 are as follows (in millions):


	For the Year Ended
	December 31, 2009
Commodity contracts	$	(145	)
Foreign exchange contracts		(4	)
Interest rate contracts		(2	)

Total	$	(151	)

We do not enter into master netting agreements with our over-the-counter 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

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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 $53 million as of December 31, 2009. At December 31, 2009, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings.

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2009. 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 December 31, 2009
	(in millions)
Recurring Fair Value Measures	Level 1			Level 2		Level 3			Total
Assets:
Commodity derivatives	$	251		$	—	$	11		$	262
Interest rate derivatives		—			—		2			2
Foreign currency derivatives		—			—		4			4

Total assets at fair value	$	251		$	—	$	17		$	268

Liabilities:
Commodity derivatives	$	(224	)	$	—	$	(42	)	$	(266	)
Foreign currency derivatives		—			—		(3	)		(3	)

Total liabilities at fair value	$	(224	)	$	—	$	(45	)	$	(269	)

Net asset/(liability) at fair value	$	27		$	—	$	(28	)	$	(1	)

The determination of the fair values above 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 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 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 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.

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•

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):


	Year Ended
	December 31,
	2009
Beginning Balance	$	74
Unrealized gains/(losses):
Included in earnings ₍₁₎		46
Included in other comprehensive income		(43	)
Settlements and derivatives entered into during the period		(105	)

Ending Balance	$	(28	)


Change in unrealized gains/(losses) included in earnings relating to level 3 derivatives still held at the end of the periods	$	31


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

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

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 to the year ended December 31, 2009 was immaterial.

Canadian Federal and Provincial Taxes

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

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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.

Tax Components

Deferred tax assets and liabilities, which are included net within other long-term liabilities and deferred credits in our consolidated balance sheet, result from the following (in millions):


	December 31,
	2009
Deferred tax assets:
Book accruals in excess of current tax deductions	$	13

Total deferred tax assets		13


Deferred tax liabilities:
Property, plant and equipment in excess of tax values		(134	)

Total deferred tax liabilities		(134	)

Net deferred tax liabilities	$	(121	)

Generally, tax returns for our Canadian entities are open to audit from 2005 through 2009. Our U.S. and state tax years are open to examination from 2006 to 2009.

Concentration of Credit Risk

Financial instruments that potentially subject us to concentrations of credit risk consist principally of trade receivables. Our accounts receivable are primarily from purchasers and shippers of crude oil. This industry concentration has the potential to impact our overall exposure to credit risk in that the customers may be similarly affected by changes in economic, industry or other conditions. We review credit exposure and financial information of our counterparties and generally require letters of credit for receivables from customers that are not considered creditworthy, unless the credit risk can otherwise be reduced.

Related Party Transactions

Reimbursement of Expenses of Our General Partner and its Affiliates

We do not pay our general partner a management fee, but we do reimburse our general partner for all direct and indirect costs of services provided to us or incurred on our behalf, including the costs of employee, officer and director compensation and benefits allocable to us as well as all other expenses necessary or appropriate to the conduct of our business (other than expenses related to grants of Class B units). We record these costs on the accrual basis in the period in which our general partner incurs them. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. Total costs reimbursed by us to our general partner for the year ended December 31, 2009 were $328 million.

Vulcan Energy Corporation

As of December 31, 2009, Vulcan Energy Corporation (“Vulcan Energy”) and its affiliates owned approximately 50% of our general partner interest, as well as approximately 9% of our outstanding limited partner units.

Voting Agreement. In August 2005, Vulcan Energy’s ownership interest in our general partner increased from 44% to over 50%. At the closing of the transaction, Vulcan Energy entered into a voting agreement that restricts its ability to unilaterally elect or remove our independent directors, and separately, our CEO and COO agreed, subject to certain ongoing conditions, to waive certain change-of-control payment rights that would otherwise have been triggered by the increase in Vulcan Energy’s ownership interest. These ownership changes to our general partner had no material impact on us.

Another owner of Plains All American GP LLC, Lynx Holdings I, LLC, agreed to restrict certain of its voting rights with respect to its approximate 1.4% membership interest in Plains All American GP LLC.

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Administrative Services Agreement. On October 14, 2005, Plains All American GP LLC (“GP LLC”) and Vulcan Energy entered into an Administrative Services Agreement, effective as of September 1, 2005 (the “Services Agreement”). Pursuant to the Services Agreement, GP LLC provides administrative services to Vulcan Energy for consideration of an annual fee, plus certain expenses. Effective October 1, 2006, the annual fee for providing these services was increased to $1 million. Beginning in October 2008, the Services Agreement automatically renews for successive one-year periods unless either party provides written notice of its intention to terminate the Services Agreement. Pursuant to the agreement, Vulcan Energy has appointed certain employees of GP LLC as officers of Vulcan Energy for administrative efficiency. Under the Services Agreement, Vulcan Energy acknowledges that conflicts may arise between itself and GP LLC. If GP LLC believes that a specific service is in conflict with the best interest of GP LLC or its affiliates then GP LLC is entitled to suspend the provision of that service and such a suspension will not constitute a breach of the Services Agreement.

Omnibus Agreement. PAA, GP LLC, certain affiliated entities and Vulcan Energy are parties to an amended and restated omnibus agreement dated as of July 23, 2004. Pursuant to this agreement, Vulcan Energy has agreed, so long as Vulcan Energy or any of its affiliates owns an interest, directly or indirectly, in GP LLC, not to engage in or acquire any business engaged in the following activities:

•

crude oil storage, terminalling and gathering activities in any state in the United States (except for Hawaii), the Outer Continental Shelf of the United States or any province or territory in Canada, for any person other than entities affiliated with Vulcan Energy and its affiliates (collectively, the “Vulcan entities”) or GP LLC, PAA, its operating partnerships and any controlled affiliates (collectively, the “Plains entities”);

•

crude oil marketing activities; and

•

transportation of crude oil by pipeline in any state in the United States (except for Hawaii), the Outer Continental Shelf of the United States or any province or territory in Canada, for any person other than the Plains entities.

These restrictions are subject to specified permitted exceptions and may be terminated by Vulcan Energy upon certain change of control events involving Vulcan Energy. The omnibus agreement further permits, except as otherwise restricted by the omnibus agreement or any other agreement, each Vulcan entity to engage in any business activity, including those that may be in direct competition with the Plains entities. Further, any owner of equity interests in Vulcan Energy may make passive investments in PAA’s competitors so long as such owner does not directly or indirectly use any knowledge or confidential information it received through the ownership by a Plains entity to compete, or to engage in or become interested financially in any person that competes, in the restricted activities described above.

Crude Oil Purchases. From August 2005 to May 2007, Calumet Florida L.L.C (“Calumet”) was owned by Vulcan Resources Florida, Inc., the majority of which is owned by Paul G. Allen. In May 2007, Calumet was sold and ceased to be related to Vulcan Energy. In 2007, until the date that Calumet ceased to be related to Vulcan Energy, we purchased crude oil from Calumet for approximately $17 million.

Investment in PAA/Vulcan Gas Storage, LLC

In September 2005, we and Vulcan Gas Storage LLC, a subsidiary of Vulcan LLC, an investment arm of Paul G. Allen, formed PAA/Vulcan Gas Storage, LLC to acquire ECI (now known as PAA Natural Gas Storage, LLC or “PNGS”), an indirect subsidiary of Sempra Energy, for approximately $250 million. We and Vulcan Gas Storage each made an initial cash investment of approximately $113 million and Bluewater Natural Gas Storage, LLC, a subsidiary of PAA/Vulcan, entered into a $90 million credit facility contemporaneously with closing.

From September 2005 until September 3, 2009, we owned 50% of PAA/Vulcan and Vulcan Gas Storage LLC owned the other 50%. Giving effect to all contributions and distributions made during the period from January 1, 2007 through September 3, 2009, we and Vulcan Gas Storage each made a net contribution of $39 million. Such contributions and distributions did not result in an increase or decrease to our ownership interest.

On September 3, 2009, one of our subsidiaries acquired the remaining 50% interest in PAA/Vulcan from Vulcan Gas Storage LLC, which resulted in our ownership of a 100% interest in PNGS.

Equity Compensation Plans

Our general partner has adopted the Plains All American GP LLC 1998 Long-Term Incentive Plan (the “1998 Plan”), the 2005 Long-Term Incentive Plan (the “2005 Plan”) and the PPX Successor Long-Term Incentive Plan (the “PPX Successor Plan”) for employees and directors as well as the Plains All American GP LLC 2006 Long- Term Incentive Tracking Unit Plan (the “2006 Plan”) for non-officer employees. The 1998 Plan, 2005 Plan and PPX Successor Plan authorize the grant of an aggregate of 5.4 million common units deliverable

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upon vesting. Although other types of awards are contemplated under the plans, currently outstanding awards are limited to “phantom units,” which mature into the right to receive common units (or cash equivalent) upon vesting. Some awards also include distribution equivalent rights (“DERs”). Subject to applicable earning criteria, a DER entitles the grantee to a cash payment equal to the cash distribution paid on an outstanding common unit. The 2006 Plan authorizes the grant of approximately 1.6 million “tracking units” which, upon vesting, represent the right to receive a cash payment in an amount based upon the market value of a common unit at the time of vesting. Our general partner is entitled to reimbursement by us for any costs incurred in settling obligations under the plans.

In accordance with FASB guidance regarding share-based payments, the fair value of our LTIP awards, which are subject to liability classification, is calculated based on the closing market price of our units at each balance sheet date adjusted for (i) the present value of any distributions that are estimated to occur on the underlying units over the vesting period that will not be received by the award recipients and (ii) an estimated forfeiture rate when appropriate. This fair value is recognized as compensation expense over the period the awards are earned. Our LTIP awards typically contain performance conditions based on attainment of certain annualized distribution levels and vest upon the later of a certain date or the attainment of such levels. For awards with performance conditions, we recognize compensation expense only if the achievement of the performance condition is considered probable and we amortize that expense over the service period. When awards with performance conditions that were previously considered improbable of occurring become probable of occurring, we incur additional LTIP compensation expense necessary to adjust the life-to-date accrued liability associated with these awards. Our DER awards typically contain performance conditions based on the attainment of certain annualized distribution levels and become earned upon the attainment of such levels. The DERs terminate with the vesting or forfeiture of the underlying LTIP award. We recognize compensation expense for DER payments in the period the payment is earned.

At December 31, 2009, the following LTIP awards were outstanding (units in millions):


		Vesting
LTIP Units		Distribution		Estimated Unit Vesting Date
Outstanding		Amount		2010		2011		2012		2013
0.6	₍₁₎	$	3.20		0.6		—		—		—
1.5	₍₂₎	$	3.50 - $4.50		—		0.5		0.8		0.1
1.8	₍₃₎	$	3.50 - $4.25		0.5		0.3		0.8		0.2

3.9	₍₄₎₍₅₎				1.1		0.8		1.6		0.3


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

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

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

₍₄₎		Approximately 2.0 million of our approximately 3.9 million outstanding LTIP awards also include DERs, of which 1.0 million are currently earned.

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

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


	Year Ended December 31,
	2009
				Weighted
				Average
				Grant Date
	Units			Fair Value per Unit
Outstanding at beginning of period		3.9		$	36.44
Granted		0.6			32.20
Vested		(0.6	)		34.55
Cancelled or forfeited		(0.1	)		37.82
Acquired ₍₁₎		0.1			26.24

Outstanding at end of period		3.9		$	36.40


₍₁₎		As a result of the PNGS Acquisition, LTIP awards that were granted to PNGS employees in prior years are now included in our consolidated outstanding LTIP awards.

Our accrued liability at December 31, 2009 related to all outstanding LTIP awards and DERs is approximately $87 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 of Plains AAP, L.P.

In August 2007, the owners of Plains AAP, L.P. authorized the issuance of up to 200,000 Class B units of Plains AAP, L.P. Class B units become earned in various increments upon us achieving annualized distribution levels of $3.50, $3.75, $4.00 and $4.50 (or in some cases, within six months thereof). When earned, the Class B unit awards are entitled to participate in distributions paid by Plains AAP, L.P. in excess of $11 million (as adjusted for debt service costs and excluding special distributions funded by debt) per quarter. Assuming all 200,000 Class B units were granted and earned, the maximum participation would be 8% of Plains AAP, L.P.’s distribution in excess of $11 million (as adjusted) each quarter. The following table contains a summary of Class B unit awards that were (i) reserved for future grants, (ii) outstanding and (iii) earned for the years ended December 31, 2009:


								Grant Date
								Fair Value Of
	Reserved for					Outstanding Units		Outstanding Class B
	Future Grants			Outstanding		Earned		Units₍₁₎
								(in millions)
Balance as of December 31, 2008		46,000			154,000		21,000	$	34
Class B unit issuance		(11,500	)		11,500		—		2
Class B units earned		—			—		17,500		—

Balance as of December 31, 2009		34,500			165,500		38,500	$	36

Although the entire economic burden of the Class B units which are equity classified, is borne solely by Plains AAP, L.P. and does not impact our cash or units outstanding, the intent of the Class B units is to provide a performance incentive and encourage retention for certain members of our senior management. Therefore, we recognize the grant date fair value of the Class B units as compensation expense over the service period. The expense is also reflected as a capital contribution and thus, results in a corresponding credit to Partners’ Capital in our Consolidated Financial Statements.

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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):


	Year Ended
	December 31,
	2009
LTIP unit vestings	$	19
LTIP cash settled vestings	$	8
DER cash payments	$	4

Approximately 0.5 million units were issued in 2009 in connection with the settlement of vested awards. The remaining 0.1 million of awards that vested during 2009 were settled in cash.

Commitments and Contingencies

Commitments

We lease certain real property, equipment and operating facilities under various operating and capital leases. We also incur costs associated with leased land, rights-of-way, permits and regulatory fees, the contracts for which generally extend beyond one year but can be cancelled at any time should they not be required for operations. Future non-cancelable commitments related to these items at December 31, 2009, are summarized below (in millions):


2010	$	79
2011		62
2012		54
2013		33
2014		23
Thereafter		240

Total	$	491

Expenditures related to leases for 2009 were $90 million.

Contingencies

Pipeline Releases. In January 2005 and December 2004, we experienced two unrelated releases of crude oil that reached rivers located near the sites where the releases originated. In early January 2005, an overflow from a temporary storage tank located in East Texas resulted in the release of approximately 1,200 barrels of crude oil, a portion of which reached the Sabine River. In late December 2004, one of our pipelines in West Texas experienced a rupture that resulted in the release of approximately 4,500 barrels of crude oil, a portion of which reached a remote location of the Pecos River. In both cases, emergency response personnel under the supervision of a unified command structure consisting of representatives of Plains, the U.S. Environmental Protection Agency (the “EPA”), the Texas Commission on Environmental Quality and the Texas Railroad Commission conducted clean-up operations at each site. Approximately 980 and 4,200 barrels were recovered from the two respective sites. The unrecovered oil was removed or otherwise addressed by us in the course of site remediation. Aggregate costs associated with the releases, including estimated remediation costs, are estimated to be approximately $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.

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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. 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 $23 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. These suits may be consolidated and heard in the U.S. Bankruptcy Court in Delaware. 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. CV085768DSF(SSX), seeks the maximum permissible penalty under the relevant statutes of approximately $3.7 million. In January 2010, the DOJ, EPA and PPS entered into a proposed consent decree, which will be published in the Federal Register and then be subject to a 30-day public comment period. If there are no objections prior to the end of the public comment period, the Court is expected to sign the consent decree. After the consent decree becomes effective, PPS will pay a civil penalty of $1.3 million and comply with other requirements set forth in the consent decree, which include performance of additional remediation and restoration tasks. 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 Pacific Atlantic Terminals LLC (“PAT”) facility at Paulsboro, New Jersey. We estimate that the maximum potential cost to effectively remediate ranges up to $10 million although the New Jersey Department of Environmental Protection (“NJDEP”) is asserting a much larger expenditure. Both ExxonMobil and GATX were prior owners of the terminal. We contend that ExxonMobil 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 MTBE contamination.

New Jersey Dep’t of Environmental Protection 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 significant clean-up expense as indicated. Discussions with the NJDEP have commenced.

EPA v. Rocky Mountain Pipeline System. In February 2009, we received a request for information from EPA regarding aspects of the fuel handling activities of Rocky Mountain Pipeline System (“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 Clean Air Act (“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

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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 December 31, 2009, our reserve for environmental liabilities totaled approximately $62 million, of which approximately $10 million is classified as short-term and $52 million is classified as long-term. At December 31, 2009, we have recorded receivables totaling approximately $3 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.

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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.

Environmental Remediation

We currently own or lease, and in the past have owned and leased, properties where hazardous liquids, including hydrocarbons, are or have been handled. These properties and the hazardous liquids or associated wastes disposed thereon may be subject to CERCLA, RCRA and state and Canadian federal and provincial laws and regulations. Under such laws and regulations, we could be required to remove or remediate hazardous liquids or associated wastes (including wastes disposed of or released by prior owners or operators) and to clean up contaminated property (including contaminated groundwater).

We maintain insurance of various types with varying levels of coverage that we consider adequate under the circumstances to cover our operations and properties. The insurance policies are subject to deductibles and retention levels that we consider reasonable and not excessive. Consistent with insurance coverage generally available in the industry, in certain circumstances our insurance policies provide limited coverage for losses or liabilities relating to gradual pollution, with broader coverage for sudden and accidental occurrences.

In conjunction with our acquisitions, we typically make an assessment of potential environmental exposure and determine whether to negotiate an indemnity, what the terms of any indemnity should be and whether to obtain environmental risk insurance, if available. These contractual indemnifications typically are subject to specific monetary requirements that must be satisfied before indemnification will apply, and have term and total dollar limits. For instance, in connection with the purchase of former Texas New Mexico (“TNM”) pipeline assets from Link in 2004, we identified a number of environmental liabilities for which we received a purchase price reduction from Link and recorded a total environmental reserve of $20 million, of which we agreed in an arrangement with TNM to bear the first $11 million in costs of pre-May 1999 environmental issues. TNM also agreed to pay all costs in excess of $20 million (excluding certain deductibles). TNM’s obligations are guaranteed by Shell Oil Products (“SOP”). As of December 31, 2009, we had incurred approximately $16 million of remediation costs associated with these sites, while SOP’s share has been approximately $6 million. In another example, as a result of our merger with Pacific, we assumed liability for a number of ongoing remediation sites associated with releases from pipeline or storage operations. We have evaluated each of the sites requiring remediation and developed reserve estimates for the Pacific sites, which total approximately $18 million at December 31, 2009.

In connection with the acquisition of certain crude oil transmission and gathering assets from SOP in 2002, SOP purchased an environmental insurance policy covering known and unknown environmental matters associated with operations prior to closing. We are a named beneficiary under the policy, which has a $100,000 deductible per site, an aggregate coverage limit of $70 million, and expires in 2012.

Other assets we have acquired or will acquire in the future may have environmental remediation liabilities for which we are not indemnified.

Operating Segments

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


	Transportation		Facilities		Supply & Logistics		Total
Total assets	$	4,468	$	3,097	$	4,793	$	12,358

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		Page
Report of Independent Auditors		F-2
Consolidated Balance Sheet as of December 31, 2009		F-3
Notes to the Consolidated Balance Sheet		F-4


	As of December 31,
Long-Lived Assets₍₁₎	2009
United States	$	6,945
Canada		1,678

	$	8,623