Edgar Filing: PLAINS ALL AMERICAN PIPELINE LP

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2012

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

Commission file number: 1-14569

PLAINS ALL AMERICAN PIPELINE, L.P.

(Exact name of registrant as specified in its charter)

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

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

(713) 646-4100

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes o No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). x Yes o No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer x		Accelerated filer o

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o Yes x No

As of October 31, 2012, there were 334,038,748 Common Units outstanding.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

TABLE OF CONTENTS

	Page
PART I. FINANCIAL INFORMATION
Item 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:
Condensed Consolidated Balance Sheets: September 30, 2012 and December 31, 2011	3
Condensed Consolidated Statements of Operations: For the three and nine months ended September 30, 2012 and 2011	4
Condensed Consolidated Statements of Comprehensive Income: For the three and nine months ended September 30, 2012 and 2011	5
Condensed Consolidated Statement of Changes in Accumulated Other Comprehensive Income: For the nine months ended September 30, 2012	5
Condensed Consolidated Statements of Cash Flows: For the nine months ended September 30, 2012 and 2011	6
Condensed Consolidated Statement of Partners’ Capital: For the nine months ended September 30, 2012	7
Notes to Condensed Consolidated Financial Statements:	8
1. Organization and Basis of Presentation	8
2. Recent Accounting Pronouncements	10
3. Accounts Receivable	10
4. Acquisitions	11
5. Inventory, Linefill, Base Gas and Long-term Inventory	13
6. Goodwill	13
7. Debt	14
8. Net Income Per Limited Partner Unit	16
9. Partners’ Capital and Distributions	17
10. Equity Compensation Plans	19
11. Derivatives and Risk Management Activities	20
12. Commitments and Contingencies	29
13. Operating Segments	31
14. Related Party Transactions	32
15. Impairments	32

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	33
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	50
Item 4. CONTROLS AND PROCEDURES	52

PART II. OTHER INFORMATION	53
Item 1. LEGAL PROCEEDINGS	53
Item 1A. RISK FACTORS	53
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	53
Item 3. DEFAULTS UPON SENIOR SECURITIES	53
Item 4. MINE SAFETY DISCLOSURES	53
Item 5. OTHER INFORMATION	53
Item 6. EXHIBITS	53
SIGNATURES	54

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PART I. FINANCIAL INFORMATION

Item 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions, except units)

	September 30,			December 31,
	2012			2011
	(unaudited)
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	32		$	26
Trade accounts receivable and other receivables, net	3,319			3,190
Inventory	1,320			978
Other current assets	142			157
Total current assets	4,813			4,351

PROPERTY AND EQUIPMENT	10,800			9,029
Accumulated depreciation	(1,452		)	(1,289		)
	9,348			7,740

OTHER ASSETS
Goodwill	2,119			1,854
Linefill and base gas	714			564
Long-term inventory	287			135
Investments in unconsolidated entities	289			191
Other, net	617			546
Total assets	$	18,187		$	15,381

LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	3,707		$	3,599
Short-term debt	834			679
Other current liabilities	345			233
Total current liabilities	4,886			4,511

LONG-TERM LIABILITIES
Senior notes, net of unamortized discount of $14 and $13, respectively	5,511			4,262
Long-term debt under credit facilities and other	300			258
Other long-term liabilities and deferred credits	565			376
Total long-term liabilities	6,376			4,896

COMMITMENTS AND CONTINGENCIES (NOTE 12)

PARTNERS’ CAPITAL
Common unitholders (331,619,386 and 310,753,874 units outstanding, respectively)	6,183			5,249
General partner	237			201
Total partners’ capital excluding noncontrolling interests	6,420			5,450
Noncontrolling interests	505			524
Total partners’ capital	6,925			5,974
Total liabilities and partners’ capital	$	18,187		$	15,381

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per unit data)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
	(unaudited)						(unaudited)
REVENUES
Supply and Logistics segment revenues	$	9,048		$	8,544		$	27,367		$	24,566
Transportation segment revenues	150			140			458			428
Facilities segment revenues	156			153			533			396
Total revenues	9,354			8,837			28,358			25,390

COSTS AND EXPENSES
Purchases and related costs	8,524			8,142			25,855			23,423
Field operating costs	292			217			860			638
General and administrative expenses	81			56			264			199
Depreciation and amortization (Note 15)	210			65			356			191
Total costs and expenses	9,107			8,480			27,335			24,451

OPERATING INCOME	247			357			1,023			939

OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	9			4			25			9
Interest expense (net of capitalized interest of $9, $7, $27 and $18, respectively)	(74		)	(62		)	(214		)	(190		)
Other income/(expense), net	4			(5		)	6			(24		)

INCOME BEFORE TAX	186			294			840			734
Current income tax expense	(10		)	(7		)	(32		)	(25		)
Deferred income tax benefit/(expense)	(3		)	1			(11		)	(3		)

NET INCOME	173			288			797			706
Net income attributable to noncontrolling interests	(8		)	(7		)	(23		)	(18		)
NET INCOME ATTRIBUTABLE TO PLAINS	$	165		$	281		$	774		$	688

NET INCOME ATTRIBUTABLE TO PLAINS:
LIMITED PARTNERS	$	89		$	221		$	554		$	520
GENERAL PARTNER	$	76		$	60		$	220		$	168

BASIC NET INCOME PER LIMITED PARTNER UNIT	$	0.27		$	0.74		$	1.71		$	1.77

DILUTED NET INCOME PER LIMITED PARTNER UNIT	$	0.27		$	0.74		$	1.70		$	1.76

BASIC WEIGHTED AVERAGE UNITS OUTSTANDING	329			299			322			294

DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING	331			300			325			296

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
	(unaudited)						(unaudited)
Net income	$	173		$	288		$	797		$	706
Other comprehensive income/(loss)	84			(278		)	35			(88		)
Comprehensive income	257			10			832			618
Comprehensive income attributable to noncontrolling interests	(5		)	(7		)	(15		)	(18		)
Comprehensive income attributable to Plains	$	252		$	3		$	817		$	600

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME

(in millions)

	Derivative			Translation
	Instruments			Adjustments		Total
	(unaudited)
Balance, December 31, 2011	$	(102	)	$	156	$	54
Reclassification adjustments	(118		)	—		(118		)
Deferred gain on cash flow hedges, net of tax	69			—		69
Currency translation adjustment	—			84		84
Total period activity	(49		)	84		35
Balance, September 30, 2012	$	(151	)	$	240	$	89

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Nine Months Ended
	September 30,
	2012			2011
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	797		$	706
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization (Note 15)	356			191
Inventory valuation adjustments	128			3
Equity compensation expense	82			56
Gain on sales of linefill and base gas	(17		)	(19		)
Net cash received/(paid) for terminated interest rate and foreign currency hedging instruments	(23		)	12
Loss on foreign currency revaluation	2			12
Other	8			6
Changes in assets and liabilities, net of acquisitions	(453		)	785
Net cash provided by operating activities	880			1,752

CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions, net of cash acquired	(1,537		)	(758		)
Change in restricted cash	—			20
Additions to property, equipment and other	(852		)	(449		)
Proceeds from sales of assets	21			10
Net cash paid for sales and purchases of linefill and base gas	(39		)	(3		)
Investment in unconsolidated entities	(24		)	—
Cash received upon formation of equity-method investment	55			—
Other investing activities	—			(5		)
Net cash used in investing activities	(2,376		)	(1,185		)

CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings/(repayments) on PAA’s revolving credit facility	26			(778		)
Net borrowings/(repayments) on PAA’s hedged inventory facility	619			(450		)
Net borrowings/(repayments) on PNG’s credit agreements	54			(7		)
Proceeds from the issuance of senior notes	1,247			597
Repayments of senior notes	(500		)	(200		)
Net proceeds from the issuance of common units (Note 9)	812			503
Cash received for sale of noncontrolling interest in a subsidiary	—			370
Distributions paid to common unitholders (Note 9)	(502		)	(427		)
Distributions paid to general partner (Note 9)	(208		)	(157		)
Distributions paid to noncontrolling interests	(36		)	(28		)
Other financing activities	(11		)	(5		)
Net cash provided by/(used in) financing activities	1,501			(582		)

Effect of translation adjustment on cash	1			(7		)

Net increase/(decrease) in cash and cash equivalents	6			(22		)
Cash and cash equivalents, beginning of period	26			36
Cash and cash equivalents, end of period	$	32		$	14

Cash paid for:
Interest, net of amounts capitalized	$	207		$	204
Income taxes, net of amounts refunded	$	58		$	1

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(in millions)

								Partners’ Capital
								Excluding
	Common Units				General			Noncontrolling			Noncontrolling			Partners’
	Units	Amount			Partner			Interests			Interests			Capital
	(unaudited)
Balance, December 31, 2011	310.8	$	5,249		$	201		$	5,450		$	524		$	5,974
Net income	—	554			220			774			23			797
Distributions	—	(502		)	(208		)	(710		)	(36		)	(746		)
Issuance of common units	19.9	796			16			812			—			812
Issuance of common units under LTIP	0.9	33			1			34			—			34
Equity compensation expense	—	14			6			20			3			23
Distribution equivalent right payments	—	(3		)	—			(3		)	(1		)	(4		)
Other comprehensive income/(loss)	—	42			1			43			(8		)	35
Balance, September 30, 2012	331.6	$	6,183		$	237		$	6,420		$	505		$	6,925

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1—Organization and Basis of Presentation

Organization

Plains All American Pipeline, L.P. is a Delaware limited partnership formed in 1998. As used in this Form 10-Q and unless the context indicates otherwise, the terms “Partnership,” “Plains,” “PAA,” “we,” “us,” “our,” “ours” and similar terms refer to Plains All American Pipeline, L.P. and its subsidiaries. Also, references to our “general partner,” as the context requires, include any or all of PAA GP LLC, Plains AAP, L.P. and Plains All American GP LLC.

We engage in the transportation, storage, terminalling and marketing of crude oil and refined products, as well as in the processing, transportation, fractionation, storage and marketing of natural gas liquids (“NGL”). The term NGL includes ethane and natural gasoline products as well as propane and butane, products which are also commonly referred to as liquid petroleum gas (“LPG”). When used in this document, NGL refers to all NGL products including LPG. Through our general partner interest and majority equity ownership position in PAA Natural Gas Storage, L.P. (NYSE: PNG), we also own and operate natural gas storage facilities. Our business activities are conducted through three operating segments: (i) Transportation, (ii) Facilities and (iii) Supply and Logistics. See Note 13 for further discussion of our three operating segments.

Definitions

Additional defined terms are used in this Form 10-Q and shall have the meanings indicated below:

AOCI	=	Accumulated other comprehensive income
Bcf	=	Billion cubic feet
Btu	=	British thermal unit
CAD	=	Canadian dollar
CME	=	Chicago Mercantile Exchange
DERs	=	Distribution equivalent rights
EBITDA	=	Earnings before interest, taxes, depreciation and amortization
FASB	=	Financial Accounting Standards Board
FERC	=	Federal Energy Regulatory Commission
GAAP	=	Generally accepted accounting principles in the United States
ICE	=	IntercontinentalExchange
LIBOR	=	London Interbank Offered Rate
LLS	=	Light Louisiana Sweet
LTIP	=	Long-term incentive plan
Mcf	=	Thousand cubic feet
MLP	=	Master limited partnership
MQD	=	Minimum quarterly distribution
NGL	=	Natural gas liquids including ethane, natural gasoline products, propane and butane
NPNS	=	Normal purchases and normal sales
NYMEX	=	New York Mercantile Exchange
NYSE	=	New York Stock Exchange
PLA	=	Pipeline loss allowance
PNG	=	PAA Natural Gas Storage, L.P.
SEC	=	Securities and Exchange Commission
USD	=	United States dollar
WTI	=	West Texas Intermediate
WTS	=	West Texas Sour

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Basis of Consolidation and Presentation

The accompanying unaudited condensed consolidated interim financial statements and notes thereto should be read in conjunction with our 2011 Annual Report on Form 10-K. The financial statements have been prepared in accordance with the instructions for interim reporting as set forth by the SEC. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods have been reflected. All significant intercompany transactions have been eliminated in consolidation. As discussed further below, certain reclassifications have been made to information from previous years to conform to the current presentation. The condensed balance sheet data as of December 31, 2011 was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the three and nine months ended September 30, 2012 should not be taken as indicative of results to be expected for the entire year.

Subsequent events have been evaluated through the financial statements issuance date and have been included in the following footnotes where applicable.

Two-for-One Unit Split

In August 2012, the board of directors of our general partner approved a two-for-one split of our common units. The two-for-one split was effected on October 1, 2012, by a distribution of one additional common unit for each common unit outstanding and held by unitholders of record at the close of business on September 17, 2012 (and for each common unit issued by the Partnership during the period between September 18, 2012 and October 1, 2012). The effect of the two-for one split has been retroactively applied to all unit and per-unit amounts presented in this Form 10-Q.

Formation of Eagle Ford Pipeline LLC

During August 2012, we and Enterprise Products Partners (“Enterprise”) formed Eagle Ford Pipeline LLC (“EF Pipeline”) for the purpose of developing a crude oil pipeline system to service production in the Eagle Ford shale play of South Texas. This system will include a 175-mile crude oil and condensate pipeline, a marine terminal facility and approximately 1.8 million barrels of operational storage capacity across the system. Portions of the system are expected to be placed into service in the fourth quarter of 2012, with the remainder expected to be placed into service in the first half of 2013. We own a 50% interest in EF Pipeline and account for our investment under the equity method of accounting. We and Enterprise contributed fixed assets with estimated book values of approximately $134 million and $17 million, respectively. In addition, Enterprise contributed cash of $58 million which we received from EF Pipeline in conjunction with the formation (a portion of which was received during the fourth quarter of 2012). Subsequent to the formation, we and Enterprise contributed $24 million each to fund continued development of the pipeline system.

Revision of Prior Period Financial Statements

Limited Partner and General Partner Income Allocation

During 2011, we identified an error in the manner in which we allocate net income to our limited partners and general partner. Previously, we calculated net income available to limited partners based on the distribution paid during the period by first allocating the incentive distribution paid during the period to the general partner and then allocating the remaining net income based on ownership interests (98% limited partner and 2% general partner). We have revised our methodology for the calculation of this allocation to take into account the distributions attributable to the period, which include distributions paid in the subsequent period. This revision does not impact net income, net income attributable to Plains, net income per limited partner unit, total partners’ capital or cash flows. We have determined that the impact of this error is not material to the previously issued financial statements. We have presented these changes retrospectively in the condensed consolidated statement of operations, which resulted in the following changes (in millions):

	Three Months Ended				Nine Months Ended
	September 30, 2011				September 30, 2011
	As Previously Reported		As Revised		As Previously Reported		As Revised
Net Income Attributable to Plains:
Limited Partners	$	224	$	221	$	528	$	520
General Partner	57		60		160		168
	$	281	$	281	$	688	$	688

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Note 2—Recent Accounting Pronouncements

Other than as discussed below and in our 2011 Annual Report on Form 10-K, no new accounting pronouncements have become effective or have been issued during the nine months ended September 30, 2012 that are of significance or potential significance to us.

In July 2012, the FASB issued guidance intended to simplify the impairment test for indefinite-lived intangible assets other than goodwill by giving entities the option to first assess qualitative factors to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired. The results of the qualitative assessment would be used as a basis in determining whether it is necessary to perform the two-step quantitative impairment testing. An entity can choose to perform the qualitative assessment on none, some or all of its indefinite-lived intangible assets, or may bypass the qualitative assessment and proceed directly to the quantitative impairment test. This guidance will be effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012, with early adoption permitted in certain circumstances. We will adopt this guidance on January 1, 2013. Our adoption is not expected to have a material impact on our financial position, results of operations or cash flows.

In September 2011, the FASB issued guidance with the purpose of simplifying the goodwill impairment test by permitting entities to perform a qualitative assessment to determine whether further impairment testing is necessary. If qualitative factors indicate that it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, an entity need not perform the two-step goodwill impairment test. This guidance became effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. We adopted this guidance on January 1, 2012. Our adoption did not have a material impact on our financial position, results of operations or cash flows.

In June 2011, the FASB issued guidance regarding the presentation of other comprehensive income, which was later amended in December 2011, with the purpose of increasing the prominence of other comprehensive income in financial statements. This guidance, as amended, requires entities to present comprehensive income in either (i) a single continuous statement of comprehensive income or (ii) two separate but consecutive statements. This guidance became effective for interim and annual periods beginning after December 15, 2011. We adopted the guidance, as amended, on January 1, 2012. Since this guidance only impacts the presentation of comprehensive income and does not change the composition or calculation of such financial information, adoption did not have a material impact on our financial position, results of operations or cash flows.

In May 2011, the FASB issued guidance to amend certain fair value measurement and disclosure requirements in an effort to improve consistency with international reporting standards. The amendments generally clarify that the concepts of highest and best use and valuation premise in fair value measurement are relevant only when measuring the fair value of non-financial assets and are not relevant when measuring the fair value of financial assets or of liabilities. In addition, the guidance expanded disclosure requirements associated with (i) unobservable inputs for Level 3 fair value measurements and (ii) items that are not measured at fair value in the financial statements, but for which fair value is required to be disclosed. This guidance became effective prospectively for interim and annual reporting periods beginning after December 15, 2011. We adopted this guidance on January 1, 2012. Other than requiring additional disclosure, which is included in Note 7 and Note 11, our adoption did not have a material impact on our financial position, results of operations or cash flows.

Note 3—Accounts Receivable

We review all outstanding accounts receivable balances on a monthly basis and record a reserve for amounts that we expect will not be fully recovered. We do not apply actual balances against the reserve until we have exhausted substantially all collection efforts. At September 30, 2012 and December 31, 2011, substantially all of our accounts receivable (net of allowance for doubtful accounts) were less than 30 days past their scheduled invoice date. Our allowance for doubtful accounts receivable totaled approximately $4 million and $5 million at September 30, 2012 and December 31, 2011, respectively. Although we consider our allowance for doubtful accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.

To mitigate credit risks related to our accounts receivable, we have in place a rigorous credit review process. We closely monitor market 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 September 30, 2012 and December 31, 2011, we had received approximately $216 million and $186 million, respectively, of advance cash payments from third parties to mitigate credit risk. In addition, we enter into netting arrangements (contractual agreements that allow us and the counterparty to offset receivables and payables against each other) that cover a significant portion of our transactions and also serve to mitigate credit risk.

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Note 4—Acquisitions

The following acquisitions were accounted for using the acquisition method of accounting and the determination of the fair value of the assets and liabilities acquired has been estimated in accordance with the applicable accounting guidance.

BP NGL Acquisition

On April 1, 2012, we acquired all of the outstanding shares of BP Canada Energy Company (“BPCEC”), a wholly owned subsidiary of BP Corporation North America Inc. (“BP North America”) from Amoco Canada International Holdings B.V. (the “Seller”). Total consideration for this acquisition (referred to herein as the “BP NGL Acquisition”), which was based on an October 1, 2011 effective date, was approximately $1.68 billion in cash, including $17 million of imputed interest, subject to working capital and other adjustments.

Upon completion of this acquisition, we became the indirect owner of all of BP North America’s Canadian-based NGL business and certain of BP North America’s NGL assets located in the upper-Midwest United States (collectively the “BP NGL Assets”). The BP NGL Assets acquired include varying ownership interests and contractual rights relating to approximately 2,600 miles of NGL pipelines; approximately 20 million barrels of NGL storage capacity; seven fractionation plants with an aggregate net capacity of approximately 232,000 barrels per day; four straddle plants and two field gas processing plants with an aggregate net capacity of approximately six Bcf per day; and long-term and seasonal NGL inventories of approximately 8 million barrels upon closing. Certain of these pipelines and storage assets are currently inactive. The acquired business also includes various third-party supply contracts at other field gas processing plants and a supply contract relating to a third-party owned straddle plant with throughput capacity of 2.5 Bcf per day, shipping arrangements on third-party NGL pipelines and long-term leases on 720 rail cars used to move product among various locations. We have also entered into an Integrated Supply and Trading Agreement, pursuant to which an affiliate of BP North America will, for a period of two years following the closing of the acquisition, continue to provide sourcing services for gas supply to feed certain of the straddle plants acquired as a result of the acquisition. The preliminary determination of the fair value of the assets and liabilities acquired is as follows (in millions):

				Average
				Depreciable
Description	Amount			Life (in years)
Working capital	$	253		N/A
Property and equipment	1,067			5 - 70
Linefill	84			N/A
Long-term inventory	166			N/A
Intangible assets (contract)	132			13
Goodwill	233			N/A
Deferred tax liability	(233		)	N/A
Environmental liability	(14		)	N/A
Other long-term liabilities	(5		)	N/A
Total	$	1,683

The determination of the fair value of the assets and liabilities acquired is preliminary pending completion of internal valuation procedures primarily related to the resolution of working capital and other adjustments. We expect to finalize our fair value determination during 2012. The purchase price was equal to the fair value of the net tangible and intangible assets acquired, excluding the resulting deferred tax liability and goodwill. The deferred tax liability is determined by the difference between the fair value of the acquired assets and liabilities and the tax basis for those assets and liabilities. The resulting liability gives rise to an equal and offsetting goodwill balance for this transaction.

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Intangible assets above consist of a contract with a 13 year life. Amortization of this contract under the declining balance method for the five full or partial calendar years following the acquisition date is estimated as follows:

2012 (1)	$	39
2013	$	30
2014	$	10
2015	$	8
2016	$	7
2017	$	6

(1) Estimated amortization is for the period from April 1, 2012 through December 31, 2012.

The following table reflects the preliminary determination of total assets and total net assets by segment as a result of the BP NGL Acquisition (in millions):

	Total Assets		Total Net Assets
Transportation	$	555	$	398
Facilities	1,061		787
Supply and Logistics	845		498
Total	$	2,461	$	1,683

The BP NGL Acquisition was pre-funded through various means, including the issuance of common units and senior notes in March 2012 for net proceeds of approximately $1.69 billion. During the nine months ended September 30, 2012, we incurred approximately $13 million of acquisition-related costs associated with the BP NGL Acquisition. Such costs are reflected as a component of general and administrative expenses in our condensed consolidated statement of operations.

Pro Forma Results

Disclosure of the revenues and earnings from the BP NGL Acquisition in our results for the three and nine months ended September 30, 2012 is not practicable as it is not being operated as a standalone subsidiary. Selected unaudited pro forma results of operations for the three and nine months ended September 30, 2012 and 2011, assuming the BP NGL Acquisition had occurred on January 1, 2011, are presented below (in millions, except per unit amounts):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2012		2011		2012		2011
Total revenues	$	9,354	$	9,185	$	29,182	$	27,726
Net income attributable to Plains	$	165	$	333	$	772	$	836
Limited partner interest in net income attributable to Plains	$	89	$	276	$	556	$	675
Net income per limited partner unit:
Basic	$	0.27	$	0.89	$	1.70	$	2.21
Diluted	$	0.27	$	0.88	$	1.69	$	2.20

Other Acquisitions

During the nine months ended September 30, 2012, we completed several additional acquisitions for an aggregate consideration of approximately $25 million. The assets acquired primarily included trailers that are utilized in our transportation segment and terminal facilities included in our facilities segment. We recognized goodwill of approximately $10 million related to these acquisitions.

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Note 5—Inventory, Linefill, Base Gas and Long-term Inventory

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

	September 30, 2012						December 31, 2011
		Unit of	Carrying		Price/			Unit of	Carrying		Price/
	Volumes	Measure	Value		Unit (1)		Volumes	Measure	Value		Unit (1)
Inventory
Crude oil	7,122	barrels	$	650	$	91.27	5,361	barrels	$	483	$	90.10
NGL	14,683	barrels	604		$	41.14	6,885	barrels	438		$	63.62
Natural gas (2)	21,800	Mcf	51		$	2.34	16,170	Mcf	51		$	3.15
Other	N/A		15		N/A		N/A		6		N/A
Inventory subtotal			1,320						978

Linefill and base gas
Crude oil	9,882	barrels	582		$	58.89	9,366	barrels	514		$	54.88
Natural gas (2)	15,005	Mcf	51		$	3.40	14,105	Mcf	48		$	3.40
NGL	1,689	barrels	81		$	47.96	31	barrels	2		$	64.52
Linefill and base gas subtotal			714						564

Long-term inventory
Crude oil	1,916	barrels	143		$	74.63	1,714	barrels	127		$	74.10
NGL	3,620	barrels	144		$	39.78	150	barrels	8		$	53.33
Long-term inventory subtotal			287						135

Total			$	2,321					$	1,677

(1) Price per unit of measure represents a weighted average associated with various grades, qualities and locations. Accordingly, these prices may not coincide with any published benchmarks for such products.

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

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 the second and third quarters of 2012, we recorded non-cash charges of approximately $121 million and $7 million, respectively, related to the writedown of our crude oil and NGL inventory due to declines in prices during the periods. The recognition of this adjustment, which is a component of “Purchases and related costs” in our accompanying condensed consolidated statement of operations, was substantially offset by the recognition of unrealized gains on derivative instruments being utilized to hedge the future sales of our crude oil and NGL inventory. Substantially all of such unrealized gains were recorded to “Supply and Logistics segment revenues” on our condensed consolidated statement of operations. See Note 11 for discussion of our derivative and risk management activities.

Note 6 — Goodwill

The table below reflects our changes in goodwill for the period indicated (in millions):

	Transportation		Facilities		Supply and Logistics		Total (1)
Balance, December 31, 2011	$	818	$	609	$	427	$	1,854
2012 Goodwill Related Activity:
BP NGL acquisition (2)	72		133		28		233
Other acquisitions (2)	10		—		—		10
Foreign currency translation adjustments	8		1		3		12
Purchase price accounting adjustments and other (2)	10		—		—		10
Balance, September 30, 2012	$	918	$	743	$	458	$	2,119

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(1) As of September 30, 2012, the total carrying amount of goodwill is net of approximately $3 million of accumulated impairment losses.

(2) Goodwill is recorded at the acquisition date based on a preliminary fair value determination. This preliminary goodwill balance may be adjusted when the fair value determination is finalized.

We completed our annual goodwill impairment test as of June 30 and determined that there was no impairment of goodwill.

Note 7—Debt

Debt consisted of the following (in millions):

	September 30,			December 31,
	2012			2011
SHORT-TERM DEBT
Credit Facilities (1) :
Senior secured hedged inventory facility bearing a weighted-average interest rate of 1.4% and 1.5% at September 30, 2012 and December 31, 2011, respectively	$	694		$	75
PAA senior unsecured revolving credit facility, bearing a weighted-average interest rate of 2.6% and 1.6% at September 30, 2012 and December 31, 2011, respectively (2)	58			32
PNG senior unsecured revolving credit facility, bearing a weighted-average interest rate of 2.1% at both September 30, 2012 and December 31, 2011 (3)	80			68
4.25% senior notes due September 2012 (4)	—			500
Other	2			4
Total short-term debt	834			679

LONG-TERM DEBT
Senior Notes:
5.63% senior notes due December 2013	250			250
5.25% senior notes due June 2015	150			150
3.95% senior notes due September 2015	400			400
5.88% senior notes due August 2016	175			175
6.13% senior notes due January 2017	400			400
6.50% senior notes due May 2018	600			600
8.75% senior notes due May 2019	350			350
5.75% senior notes due January 2020	500			500
5.00% senior notes due February 2021	600			600
3.65% senior notes due June 2022 (5)	750			—
6.70% senior notes due May 2036	250			250
6.65% senior notes due January 2037	600			600
5.15% senior notes due June 2042 (5)	500			—
Unamortized discounts	(14		)	(13		)
Senior notes, net of unamortized discounts	5,511			4,262
Credit Facilities and Other:
PNG senior unsecured revolving credit facility, bearing a weighted-average interest rate of 2.1% at September 30, 2012 and December 31, 2011 (3)	95			54
PNG GO Bond term loans, bearing a weighted-average interest rate of 1.5% at both September 30, 2012 and December 31, 2011	200			200
Other	5			4
Total long-term debt	5,811			4,520
Total debt (2) (3) (6)	$	6,645		$	5,199

(1) During June 2012, we expanded and extended our senior secured hedged inventory facility and expanded PNG’s credit facility. See “Credit Facilities” below for further discussion.

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

(3) PNG classifies as short-term debt any borrowings under the PNG senior unsecured revolving credit facility that have been designated as working capital borrowings and must be repaid within one year. Such borrowings are primarily related to a portion of PNG’s hedged natural gas inventory.

(4) Our $500 million 4.25% senior notes matured in September 2012 and were repaid with proceeds from our credit facilities. The proceeds from the issuance of these senior notes were used to supplement capital available from our hedged inventory facility, to fund working capital needs associated with base levels of waterborne cargos and for seasonal NGL inventory requirements. After the maturity of these senior notes, we are now using our expanded credit facilities for such purposes. See “Credit Facilities” below.

(5) In March 2012, we completed the issuance of $750 million, 3.65% senior notes due 2022 and $500 million, 5.15% senior notes due 2042. The senior notes were sold at 99.823% and 99.755% of face value, respectively. Interest payments are due on June 1 and December 1 each year, beginning on December 1, 2012. We used the net proceeds from these offerings to fund a portion of the consideration for the BP NGL Acquisition and for general partnership purposes. See Note 4 for more information regarding this acquisition.

(6) Our fixed-rate senior notes had a face value of approximately $5.5 billion and $4.8 billion as of September 30, 2012 and December 31, 2011, respectively. We estimated the aggregate fair value of these notes as of September 30, 2012 and December 31, 2011 to be approximately $6.5 billion and $5.4 billion, respectively. Our fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near quarter end. We estimate that the carrying value of outstanding borrowings under our credit facilities approximates fair value as interest rates reflect current market rates. The fair value estimates for both our senior notes and credit facilities are based upon observable market data and are classified within Level 2 of the fair value hierarchy.

Credit Facilities

Senior secured hedged inventory facility. In June 2012, we amended our senior secured hedged inventory facility which, among other things, increased the committed borrowing capacity from $850 million to $1.4 billion, of which $400 million (an increase from $250 million under the original facility) is available for the issuance of letters of credit. Subject to obtaining additional or increased lender commitments, the committed amount of the facility may be increased to $1.9 billion. The amendment also extended the maturity date of the facility by one year to August 2014 and provides for one or more one-year extensions, subject to applicable approval.

PNG senior unsecured credit agreement. In June 2012, PNG partially exercised the accordion feature of its original senior unsecured credit agreement and increased from $250 million to $350 million the aggregate amount of revolving credit facility commitments. Also in June 2012, PNG amended this credit agreement to, among other things, provide for the further increase of the committed amount to $550 million, subject to obtaining additional or increased lender commitments. The amendment also provides for one or more one-year extensions of the revolving credit facility maturity date of August 2016 and the GO Bond mandatory put date, as defined in such amendment, in each case subject to lender approvals.

Senior unsecured 364-day revolving credit agreement. In December 2011, we entered into a 364-day credit facility agreement with a borrowing capacity of $1.2 billion. Pursuant to its terms, we had the option to activate the facility at any time over a six-month period. In March 2012, we elected to terminate this credit agreement.

Letters of Credit

In connection with our crude oil supply and logistics activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase of crude oil. At September 30, 2012 and December 31, 2011, we had outstanding letters of credit of approximately $21 million and $33 million, respectively.

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Note 8—Net Income Per Limited Partner Unit

Basic and diluted net income per limited partner unit is determined pursuant to the two-class method for Master Limited Partnerships as prescribed in the FASB guidance. The two-class method is an earnings allocation formula that is used to determine earnings to our general partner, common unit holders and participating securities according to distributions pertaining to the current period’s net income and participation rights in undistributed earnings. Under this method, all earnings are allocated to our general partner, common unit holders and participating securities based on their respective rights to receive distributions, regardless of whether those earnings would actually be distributed during a particular period from an economic or practical perspective.

The Partnership calculates basic and diluted net income per limited partner unit by dividing net income attributable to Plains, after deducting the amount allocated to the general partner’s interest, incentive distribution rights (“IDRs”) and participating securities, by the basic and diluted weighted-average number of limited partner units outstanding during the period. Participating securities include LTIP awards that have vested distribution equivalent rights (“DERs”), which entitle the grantee to a cash payment equal to the cash distribution paid on our outstanding common units. As a result of our two-for-one unit split that was effected on October 1, 2012, we have adjusted the computation of limited partners’ net income per unit in our condensed consolidated statements of income and in the table below to present the amounts on a post-split basis for all periods presented.

Diluted net income per limited partner unit is computed based on the weighted average number of units plus the effect of dilutive potential units outstanding during the period using the two-class method. Our LTIP awards that contemplate the issuance of common units are considered dilutive unless (i) vesting occurs only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. LTIP awards that are deemed to be dilutive are reduced by a hypothetical unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. See Note 10 to our Consolidated Financial Statements included in Part IV of our 2011 Annual Report on Form 10-K for a complete discussion of our LTIP awards including specific discussion regarding DERs.

The following table sets forth the computation of basic and diluted earnings per limited partner unit for the three and nine months ended September 30, 2012 and 2011 (amounts in millions, except per unit data):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Numerator for Basic and Diluted Net Income per Limited Partner Unit:
Net income attributable to Plains	$	165		$	281		$	774		$	688
Less: General partner’s incentive distribution (1)	(74		)	(55		)	(208		)	(158		)
Less: General partner 2% ownership (1)	(2		)	(5		)	(12		)	(10		)
Net income available to limited partners	89			221			554			520
Less: Undistributed earnings allocated and distributions to participating securities (1)	(1		)	—			(3		)	—
Net income available to limited partners in accordance with application of the two-class method for MLPs	$	88		$	221		$	551		$	520

Denominator for Basic and Diluted Net Income per Limited Partner Unit:
Basic weighted average number of limited partner units outstanding	329			299			322			294
Effect of dilutive securities: Weighted average LTIP units	2			1			3			2
Diluted weighted average number of limited partner units outstanding	331			300			325			296

Basic net income per limited partner unit	$	0.27		$	0.74		$	1.71		$	1.77

Diluted net income per limited partner unit	$	0.27		$	0.74		$	1.70		$	1.76

(1) We calculate net income available to limited partners based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner, limited partners and participating securities in accordance with the contractual terms of the partnership agreement and as further prescribed under the two-class method.

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The terms of our partnership agreement limit the general partner’s incentive distribution to the amount of available cash, which as defined in the partnership agreement is net of reserves deemed appropriate. As such, IDRs are not allocated undistributed earnings or distributions in excess of earnings for EPU calculation purposes. If, however, undistributed earnings were allocated to our IDRs beyond amounts distributed to them under the terms of the partnership agreement, basic and diluted earnings per limited partner unit as reflected in the table above would be impacted as follows:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2012		2011			2012			2011
Basic net income per limited partner unit impact	$	—	$	(0.12	)	$	(0.04	)	$	(0.14	)

Diluted net income per limited partner unit impact	$	—	$	(0.12	)	$	(0.04	)	$	(0.14	)

Note 9—Partners’ Capital and Distributions

PAA 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. As a result of the two-for-one unit split that was effected on October 1, 2012, the partnership agreement was amended to adjust the quarterly incentive distribution provisions. Under the provisions of the amended partnership agreement, our general partner is entitled, without duplication, to 15% of amounts we distribute in excess of $0.2250 per unit, 25% of the amounts we distribute in excess of $0.2475 per unit and 50% of amounts we distribute in excess of $0.3375 per unit.

The following table details the distributions paid during or pertaining to the first nine months of 2012, net of reductions to the general partner’s incentive distributions (in millions, except per unit amounts):

		Distributions Paid								Distributions
		Common		General Partner						per limited
Date Declared	Date Paid or To Be Paid	Units		Incentive		2%		Total		partner unit (2)
October 4, 2012	November 14, 2012 (1)	$	181	$	74	$	4	$	259	$	0.5425
July 9, 2012	August 14, 2012	$	174	$	69	$	4	$	247	$	0.5325
April 10, 2012	May 15, 2012	$	169	$	65	$	3	$	237	$	0.5225
January 10, 2012	February 14, 2012	$	159	$	63	$	3	$	225	$	0.5125

(1) Payable to unitholders of record at the close of business on November 2, 2012, for the period July 1, 2012 through September 30, 2012.

(2) Distributions per limited partner unit are presented as adjusted for the two-for-one unit split effected on October 1, 2012.

In order to enhance our distribution coverage ratio and liquidity in connection with a significant acquisition, our general partner has, from time to time, agreed to reduce the amounts due to it as incentive distributions. In connection with the BP NGL Acquisition, our general partner agreed to reduce the amount of its incentive distributions by $3.75 million per quarter through February 2014 and $2.5 million per quarter thereafter. Through September 30, 2012, our general partner’s incentive distributions had been reduced by $7.5 million related to this acquisition. See Note 4 for further discussion of the BP NGL Acquisition.

PAA Equity Offerings

Continuous Offering Programs. On May 9, 2012, we entered into an equity distribution agreement with respect to the offer and sale, through our sales agent, of common units representing limited partner interests having an aggregate offering price of up to $300 million. The final sales under this equity distribution agreement occurred during September 2012. Under this agreement, we sold an aggregate of approximately 7.2 million common units, as adjusted for the two-for-one unit split, generating proceeds of approximately $302 million, including our general partner’s proportionate capital contribution, net of approximately $4 million of commissions to our sales agent. The net proceeds from sales were used for general partnership purposes.

On September 13, 2012, we entered into an additional equity distribution agreement with several financial institutions pursuant to which we may offer and sell, through our sales agents, common units representing limited partner interests having an aggregate offering price of up to $500 million. Sales of such common units will be made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed upon by our sales agent and us. Under the terms of the agreement, we have the option to sell common units to any of our sales agents as principal for its own account at a price to be agreed upon at the time of the sale. For any such sales, we will enter into a separate terms agreement with the sales agent.

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Through September 30, 2012, we sold an aggregate of approximately 1.2 million common units, as adjusted for the two-for-one unit split, under this agreement, generating proceeds of approximately $55 million, including our general partner’s proportionate capital contribution, net of approximately $1 million of commissions to our sales agents. The net proceeds from sales were used for general partnership purposes.

Other Equity Offerings. During the first nine months of 2012, we completed an offering of our common units that was not associated with our Continuous Offering Programs, as shown in the table below (in millions, except unit and per unit data):

						General
		Gross		Proceeds		Partner					Net
Date	Units Issued (2)	Unit Price (2)		from Sale		Contribution		Costs			Proceeds
March 2012 (1)	11,500,000	$	40.015	$	460	$	9	$	(14	)	$	455

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

(2) Units issued and gross unit price are presented as adjusted for the two-for-one unit split that was effected on October 1, 2012.

LTIP Vesting

In connection with the settlement of vested LTIP awards, we issued approximately 0.9 million common units, as adjusted for the unit split, during the nine months ended September 30, 2012, which resulted in an increase to partners’ capital of approximately $34 million, including the general partner’s contribution.

Noncontrolling Interests in Subsidiaries

As of September 30, 2012, noncontrolling interests in subsidiaries consisted of the following: (i) an approximate 36% interest in PNG and (ii) a 25% interest in SLC Pipeline LLC.

Modification of PNG Subordinated Units

In February 2012, PNG modified the terms of the first three tranches of the PNG Series B subordinated units held by PAA. The Series B subordinated units do not participate in quarterly distributions. Instead, the Series B subordinated units convert into Series A subordinated units in five distinct tranches upon the achievement of defined benchmarks tied to the amount of capacity in service at Pine Prairie and increases in PNG’s quarterly distributions. Any Series B subordinated units that remain outstanding as of December 31, 2018 will automatically be cancelled. The February 2012 modification increased the quarterly distribution benchmark for Tranche 1, 2 and 3 from annualized levels of $1.44 per unit, $1.53 per unit and $1.63 per unit, respectively, to an annualized level of $1.71 per unit. The following table presents the operational and financial benchmarks, as modified, for conversion of the Series B subordinated units into Series A subordinated units for each tranche (units in millions):

	Series B Subordinated Units to Convert into Series A Subordinated Units	Working Gas Storage Capacity (Bcf)	Annualized Distribution Level (1)
Tranche 1	2.6	29.6	$	1.71
Tranche 2	2.8	35.6	$	1.71
Tranche 3	2.1	41.6	$	1.71
Tranche 4	3.0	48.0	$	1.71
Tranche 5	3.0	48.0	$	1.80

(1) For satisfaction of this benchmark, PNG must, for two consecutive quarters, (i) generate distributable cash flow sufficient to pay a quarterly distribution of at least the annualized distribution benchmark on the weighted average number of common units and Series A subordinated units and all of such Series B subordinated units outstanding during such quarter plus (ii) distribute available cash of at least the annualized distribution benchmark on all of its outstanding common units and Series A subordinated units and the corresponding distributions on PNG’s general partner’s 2% interest and the related distributions on the incentive distribution rights. See Note 5 to our Consolidated Financial Statements included in Part IV of our 2011 Annual Report on Form 10-K for a complete discussion of PNG’s Series B subordinated units.

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Noncontrolling Interests Rollforward

The following table reflects the changes in the noncontrolling interests in partners’ capital (in millions):

	Nine Months Ended
	September 30,
	2012			2011
Beginning balance	$	524		$	231
Sale of noncontrolling interests in a subsidiary	—			306
Net income attributable to noncontrolling interests	23			18
Distributions to noncontrolling interests	(36		)	(28		)
Equity compensation expense	3			2
Distribution equivalent right payments	(1		)	—
Other comprehensive income/(loss):
Reclassification adjustments	(7		)	—
Net deferred loss on cash flow hedges	(1		)	—
Ending balance	$	505		$	529

Note 10—Equity Compensation Plans

For additional discussion of our equity compensation awards, see Note 10 to our Consolidated Financial Statements included in Part IV of our 2011 Annual Report on Form 10-K.

PAA Two-for-One Unit Split. A two-for-one split of PAA’s common units was effected on October 1, 2012. In conjunction with the split, the number of units available for issuance under each of PAA’s LTIP Plans was doubled and for all outstanding unit-denominated LTIP awards, the number of unvested units and DERs (if applicable) was doubled, and the vesting requirements for such outstanding LTIP grants and related DERs, as well as awards denominated in Plains AAP, L.P. Class B Units, that are based on achievement of a specified distribution level were reduced by 50%. The remaining terms and conditions of the outstanding LTIP awards were not impacted. All LTIP information for PAA is presented as adjusted for the unit split.

PNG LTIP Modification. In February 2012, the Board of Directors of PNG’s general partner approved the modification of certain awards previously granted under the PNG Plan. As a result of the modification, 232,500 equity-classified phantom unit awards will now vest in the following manner: (i) 69,750 awards, with DERs also modified to begin payment in February 2012, will vest upon the date PNG pays an annualized distribution of at least $1.45, (ii) 69,750 awards, with DERs also modified to begin payment in May 2013, will vest upon the date PNG pays an annualized distribution of at least $1.50 and (iii) 93,000 awards, with DERs also modified to begin payment in May 2014, will vest upon the date PNG pays an annualized distribution of at least $1.55. Fifty percent of any awards that have not vested as of the November 2016 distribution date will vest at that time and the remainder will expire. Additionally, 232,500 of equity-classified phantom unit awards with vesting terms originally tied to the conversion of PNG’s Series A and Series B subordinated units were modified such that all these awards will now fully vest upon conversion of the Series A subordinated units to common units. DERs were also granted with respect to these awards to begin payment in February 2012. There was no financial impact at the time of the modification; however, we anticipate that we will recognize additional equity compensation expense in the future as a result of the modification.

Class B Units of Plains AAP, L.P. The following table contains a summary of Plains AAP, L.P. Class B Unit awards:

	Reserved for Future Grants	Outstanding		Outstanding Units Earned	Grant Date Fair Value of Outstanding Class B Units (1)
Balance as of December 31, 2011	16,500	183,500		80,063	$	44
Forfeitures	1,000	(1,000	)	—	$	—
Earned	N/A	N/A		50,187	$	N/A
Balance as of September 30, 2012	17,500	182,500		130,250	$	44

(1) Of the grant date fair value, approximately $6 million was recognized as expense during the nine months ended September 30, 2012.

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Other Equity Compensation Information. Our equity compensation activity for LTIP awards denominated in PAA and PNG units is summarized in the following table (units in millions):

	PAA Units (1) (2) (3)				PNG Units (4) (5) (6) (7)
	Units		Weighted Average Grant Date Fair Value per Unit		Units	Weighted Average Grant Date Fair Value per Unit
Outstanding, December 31, 2011	8.0		$	21.77	0.8	$	20.55
Granted	1.4		$	33.32	0.1	$	15.33
Vested	(3.1	)	$	19.65	—	$	23.64
Cancelled or forfeited	(0.3	)	$	29.66	—	$	—
Outstanding, September 30, 2012	6.0		$	25.35	0.9	$	17.49

(1)		Amounts do not include Class B Units of Plains AAP, L.P.
(2)		Approximately 0.9 million common units were issued, net of approximately 0.5 million common units withheld for taxes, for PAA Units that vested during the nine months ended September 30, 2012. The remaining 1.7 million PAA Units that vested were settled in cash.
(3)		PAA Units are presented as adjusted for the two-for-one unit split effected on October 1, 2012.
(4)		Amounts do not include Class B Units of PNGS GP LLC.
(5)		Amounts include PNG Transaction Grants.
(6)		Weighted average grant date fair value per unit for PNG Units outstanding at September 30, 2012 is impacted by the modification of PNG awards during the first quarter of 2012 as discussed above.
(7)		Less than 0.1 million PNG Units vested during the nine months ended September 30, 2012.

The table below summarizes the expense recognized and the value of vesting (settled both in units and cash) related to our equity compensation plans (in millions):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2012		2011		2012		2011
Equity compensation expense	$	22	$	10	$	82	$	56
LTIP unit-settled vestings (1)	$	2	$	2	$	60	$	24
LTIP cash-settled vestings	$	1	$	—	$	66	$	18
DER cash payments	$	2	$	1	$	5	$	3

(1) For the nine months ended September 30, 2012 and September 30, 2011, approximately $1 million and $2 million, respectively, relate to unit vestings that were settled with PNG common units.

Note 11—Derivatives and Risk Management Activities

We identify the risks that underlie our core business activities and use risk management strategies to mitigate those risks when we determine that there is value in doing so. Our policy is to use derivative instruments for risk management purposes and not for the purpose of speculating on hydrocarbon commodity (referred to herein as “commodity”) price changes. 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 commodity risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring our derivative positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity. Our interest rate and currency exchange rate risk management policies and procedures are designed to monitor our derivative positions and ensure that those positions are consistent with our objectives and approved strategies. When we apply hedge accounting, our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives 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.

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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 to (i) only purchase inventory for which we have a market, (ii) structure our sales contracts so that price fluctuations do not materially affect our operating income and (iii) not acquire and hold physical inventory or derivatives for the purpose of speculating on commodity price changes. The material commodity-related risks inherent in our business activities can be divided into the following general categories:

Commodity Purchases and Sales — In the normal course of our operations, we purchase and sell commodities. We use derivatives to manage the associated risks and to optimize profits. As of September 30, 2012, net derivative positions related to these activities included:

· An approximate 201,700 barrels per day net long position (total of 6.3 million barrels) associated with our crude oil purchases, which was unwound ratably during October 2012 to match monthly average pricing.

· A net short spread position averaging approximately 30,800 barrels per day (total of 10.3 million barrels), which hedges a portion of our anticipated crude oil lease gathering purchases through October 2013. These derivatives are time spreads consisting of offsetting purchases and sales between two different months. Our use of these derivatives does not expose us to outright price risk.

· Approximately 11,500 barrels per day on average (total of 5.3 million barrels) of WTS/WTI crude oil basis swaps through December 2013, which hedge anticipated sales of crude oil (WTI). These derivatives are grade spreads between two different grades of crude oil. Our use of these derivatives does not expose us to outright price risk.

· Approximately 1,700 barrels per day on average (total of 0.8 million barrels) of LLS/WTI crude oil basis swaps from October 2012 through December 2013, which hedge anticipated sales of crude oil. These derivatives are grade spreads between two different grades of crude oil. Our use of these derivatives does not expose us to outright price risk.

· An average of 1,000 barrels per day (total of 0.5 million barrels) of butane/WTI spread positions, which hedge specific butane sales contracts that are based on a percentage of WTI through March 2014.

· A long swap position of approximately 7.5 Bcf through April 2016 related to anticipated purchases of natural gas, including 5.0 Bcf of anticipated base gas requirements.

· A short swap position of approximately 24.3 Bcf through January 2013 related to anticipated sales of natural gas.

· Approximately 1,022 barrels per day (total of 0.5 million barrels) of swaps, which hedge anticipated purchases of diesel fuel through December 2013.

Storage Capacity Utilization — We own approximately 100 million barrels of crude oil, NGL and refined products storage capacity other than that 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 September 30, 2012, we used derivatives to manage the risk of not utilizing approximately 1.1 million barrels per month of storage capacity through 2013. These positions are a combination of calendar spread options and futures contracts. These positions involve no outright price exposure, but instead enable us to profitably use the capacity to store hedged crude oil.

Inventory Storage — From time to time, we elect to purchase and store crude oil, NGL and refined products inventory in conjunction with our supply and logistics activities. When we purchase and store inventory, we enter into physical sales contracts or use derivatives to mitigate price risk associated with the inventory. As of September 30, 2012, we had derivatives totaling approximately 13.4 million barrels hedging our inventory. These positions are a combination of futures, swaps and option contracts.

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 September 30, 2012, our PLA hedges included (i) a net short position consisting of crude oil futures and swaps for an average of approximately 1,100 barrels per day (total of 1.4 million barrels) through December 2015, (ii) a short put option position of approximately 0.1 million barrels through December 2012 and (iii) a long call option position of approximately 0.8 million barrels through December 2015.

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Natural Gas Processing/NGL Fractionation — As part of our supply and logistics activities, we purchase natural gas for processing and NGL mix for fractionation, and we sell the resulting individual specification products (including ethane, propane, butane and condensate). In conjunction with these activities, we hedge the purchase of natural gas and the subsequent sale of the individual specification products. As of September 30, 2012, we had a long natural gas position of approximately 14.4 Bcf through October 2014, a short propane position of approximately 2.5 million barrels through October 2014, a short butane position of approximately 0.7 million barrels through October 2014 and a short WTI position of approximately 0.3 million barrels through October 2014.

All of our commodity derivatives that qualify for hedge accounting are designated as cash flow hedges. We have determined that substantially all of our physical purchase and sale agreements qualify for the NPNS exclusion. 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 at fair value, with changes in fair value recognized in earnings.

Interest Rate Risk Hedging

We use interest rate derivatives to hedge interest rate risk associated with anticipated debt issuances and outstanding debt instruments. The derivative instruments we use to manage this risk consist primarily of interest rate swaps and treasury locks. As of September 30, 2012, AOCI includes deferred losses of approximately $150 million that relate to open and terminated interest rate derivatives that were designated for hedge accounting. The terminated interest rate derivatives were cash-settled in connection with the issuance or refinancing of debt agreements. The deferred gain related to these instruments is being amortized to interest expense over the terms of the hedged debt instruments.

We have entered into forward starting interest rate swaps to hedge the underlying benchmark interest rate related to forecasted debt issuances through 2015. The following table summarizes the terms of our forward starting interest rate swaps as of September 30, 2012 (notional amounts in millions):

Hedged Transaction	Number and Types of Derivatives Employed	Notional Amount		Expected Termination Date	Average Rate Locked		Accounting Treatment
Anticipated debt offering	6 forward starting swaps (30-year)	$	250	6/17/2013	4.24	%	Cash flow hedge
Anticipated debt offering	5 forward starting swaps (30-year)	$	125	6/16/2014	3.39	%	Cash flow hedge
Anticipated debt offering	10 forward starting swaps (30-year)	$	250	6/15/2015	3.60	%	Cash flow hedge

During June 2011 and August 2011, PNG entered into three interest rate swaps to fix the interest rate on a portion of PNG’s outstanding debt. The swaps have an aggregate notional amount of $100 million with an average fixed rate of 0.95%. Two of these swaps terminate in June 2014 and the remaining swap terminates in August 2014. These swaps are designated as cash flow hedges.

Concurrent with our March 2012 senior note issuances, we terminated four ten-year forward starting interest rate swaps. These swaps had an aggregate notional amount of $200 million and an average fixed rate of 3.46%. We made a cash payment of approximately $24 million in connection with the termination of the swaps.

Concurrent with our January 2011 senior notes issuance, we terminated three forward starting interest rate swaps. These swaps had an aggregate notional amount of $100 million and an average fixed rate of 3.6%. We received cash proceeds of approximately $12 million in connection with the termination of these swaps.

During July 2009, concurrent with our senior notes issuance, we entered into four interest rate swaps for which we received fixed interest payments and paid floating-rate interest payments based on three-month LIBOR plus an average spread of 2.42% on a semi-annual basis. The swaps had an aggregate notional amount of $300 million with fixed rates of 4.25%. Two of the swaps terminated in September 2011, and the remaining two swaps terminated in September 2012.

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Currency Exchange Rate Risk Hedging

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 foreign currency derivatives to minimize the risks of unfavorable changes in exchange rates. These instruments include foreign currency exchange contracts and forwards. As of September 30, 2012, AOCI includes net deferred gains of approximately $9 million that relate to foreign currency derivatives that were designated for hedge accounting

As of September 30, 2012, our outstanding foreign currency derivatives include derivatives we use to (i) hedge CAD-denominated interest payments on CAD-denominated intercompany notes, (ii) hedge currency exchange risk associated with USD-denominated commodity purchases and sales in Canada and (iii) hedge currency exchange risk created by the use of USD-denominated commodity derivatives to hedge commodity price risk associated with CAD-denominated commodity purchases and sales.

The following table summarizes our open forward exchange contracts as of September 30, 2012 (in millions):

		USD		CAD		Average Exchange Rate USD to CAD
Forward exchange contracts that exchange CAD for USD:
	2012	$	94	$	92	$1.02 to $1.00
	2013	9		9		$1.00 to $1.00
		$	103	$	101	$1.01 to $1.00

Forward exchange contracts that exchange USD for CAD:
	2012	$	123	$	124	$0.99 to $1.00
	2013	149		150		$0.99 to $1.00
		$	272	$	274	$0.99 to $1.00

Net position by currency:
	2012	$	29	$	32
	2013	140		141
		$	169	$	173

Summary of Financial Impact

For derivatives that qualify as cash flow hedges, changes in fair value of the effective portion of the hedges are deferred in AOCI and recognized in earnings in the periods during which the underlying physical transactions impact earnings. For our interest rate swaps that qualify as fair value hedges, changes in the fair value of the derivative and changes in the fair value of the underlying hedged item, attributable to the hedged risk, are recognized in earnings each period. Derivatives that do not qualify for hedge accounting and the portion of cash flow hedges that are not highly effective in offsetting changes in cash flows of the hedged items are recognized in earnings each period. Cash settlements associated with our derivative activities are reflected as cash flows from operating activities in our condensed consolidated statements of cash flows.

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A summary of the impact of our derivative activities recognized in earnings for the three and nine months ended September 30, 2012 and 2011 is as follows (in millions):

	Three Months Ended September 30, 2012									Three Months Ended September 30, 2011
				Derivatives									Derivatives
	Derivatives in			Not						Derivatives in			Not
	Hedging			Designated						Hedging			Designated
Location of gain/(loss)	Relationships (1)			as a Hedge (4)			Total			Relationships (1)(2)			as a Hedge (4)			Total
Commodity Derivatives

Supply and Logistics segment revenues	$	123		$	(102	)	$	21		$	(1	)	$	50		$	49

Facilities segment revenues	—			—			—			3			—			3

Field operating costs	—			4			4			—			(1		)	(1		)

Interest Rate Derivatives

Interest expense	(1		)	—			(1		)	—			—			—

Foreign Currency Derivatives

Supply and Logistics segment revenues	—			4			4			—			(6		)	(6		)

Other income/(expense), net	1			—			1			3			—			3

Total Gain/(Loss) on Derivatives Recognized in Net Income	$	123		$	(94	)	$	29		$	5		$	43		$	48

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	Nine Months Ended September 30, 2012								Nine Months Ended September 30, 2011
				Derivatives								Derivatives
	Derivatives in			Not					Derivatives in			Not
	Hedging			Designated					Hedging			Designated
Location of gain/(loss)	Relationships (1)(2)(3)			as a Hedge (4)		Total			Relationships (1)(3)			as a Hedge (4)			Total
Commodity Derivatives

Supply and Logistics segment revenues	$	62		$	59	$	121		$	(237	)	$	90		$	(147	)

Facilities segment revenues	13			—		13			(3		)	1			(2		)

Purchases and related costs	41			—		41			—			(1		)	(1		)

Field operating costs	—			2		2			—			—			—

Interest Rate Derivatives

Interest expense	(2		)	—		(2		)	1			—			1

Foreign Currency Derivatives

Supply and Logistics segment revenues	—			4		4			—			(3		)	(3		)

Other income/(expense), net	4			—		4			5			—			5

Total Gain/(Loss) on Derivatives Recognized in Net Income	$	118		$	65	$	183		$	(234	)	$	87		$	(147	)

(1)		Amounts represent derivative gains and losses that were reclassified from AOCI to earnings during the period to coincide with the earnings impact of the hedged transaction.
(2)		Amounts include losses of approximately $2 million and gains of approximately $8 million for the nine months ended September 30, 2012 and the three months ended September 30, 2011, respectively. These amounts represent the ineffective portion of our commodity and interest rate derivatives that are designated as cash flow hedges.
(3)		Interest expense includes net gains of approximately $2 million and $1 million for the nine months ended September 30, 2012 and 2011, respectively, associated with interest rate swaps designated as a fair value hedge. These swaps terminated during September 2012.
(4)		Includes realized and unrealized gains or losses for derivatives not designated for hedge accounting during the period.

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The following table summarizes the derivative assets and liabilities on our condensed consolidated balance sheet on a gross basis as of September 30, 2012 (in millions):

	Asset Derivatives			Liability Derivatives
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments:
Commodity derivatives	Other current assets	$	32	Other current assets	$	(30	)
	Other long-term assets	11		Other long-term assets	(3		)
				Other current liabilities	(4		)
Interest rate derivatives				Other current liabilities	(84		)
				Other long-term liabilities	(49		)
Foreign currency derivatives	Other current assets	3		Other current liabilities	(1		)

Total derivatives designated as hedging instruments		$	46		$	(171	)

Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	161	Other current assets	$	(91	)
	Other long-term assets	15		Other long-term assets	(5		)
				Other current liabilities	(1		)
Foreign currency derivatives	Other current assets	4

Total derivatives not designated as hedging instruments		$	180		$	(97	)

Total derivatives		$	226		$	(268	)

The following table summarizes the derivative assets and liabilities on our condensed consolidated balance sheet on a gross basis as of December 31, 2011 (in millions):

	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
Derivatives designated as hedging instruments:
Commodity derivatives	Other current assets	$	72	Other current assets	$	(47	)
	Other long-term assets	20		Other long-term assets	(2		)
Interest rate derivatives	Other current assets	1		Other current liabilities	(24		)
				Other long-term liabilities	(114		)
Foreign currency derivatives	Other current assets	1

Total derivatives designated as hedging instruments		$	94		$	(187	)

Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	87	Other current assets	$	(39	)
	Other long-term assets	6		Other long-term assets	(3		)
				Other current liabilities	(1		)
Total derivatives not designated as hedging instruments		$	93		$	(43	)

Total derivatives		$	187		$	(230	)

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As of September 30, 2012, there was a net loss of approximately $151 million deferred in AOCI including tax effects. The total amount of deferred net loss recorded in AOCI is expected to be reclassified to future earnings contemporaneously with (i) the earnings recognition of the underlying hedged commodity transaction, (ii) interest expense accruals associated with underlying debt instruments or (iii) the recognition of a foreign currency gain or loss upon the remeasurement of certain CAD-denominated intercompany balances. Of the total net loss deferred in AOCI at September 30, 2012, we expect to reclassify a net loss of approximately $11 million to earnings in the next twelve months. Of the remaining deferred loss in AOCI, a net gain of approximately $5 million is expected to be reclassified to earnings prior to 2015 with the remaining deferred loss of $145 million being reclassified to earnings through 2045. These amounts are predominantly based on market prices at the current period end, thus actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

During the three and nine months ended September 30, 2012, all of our hedged transactions were deemed probable of occurring. During the three and nine months ended September 30, 2011, we reclassified a gain of approximately $1 million from AOCI to facilities segment revenues and a gain of approximately $1 million from AOCI to other expense, net as a result of anticipated hedged transactions that are no longer considered probable of occurring. The net deferred gain/(loss), including tax effects, recognized in AOCI for derivatives during the three and nine months ended September 30, 2012 and 2011 are as follows (in millions):

	For the Three Months Ended					For the Nine Months Ended
	September 30,					September 30,
	2012		2011			2012			2011
Commodity derivatives, net	$	88	$	(15	)	$	88		$	(112	)
Foreign currency derivatives, net	—		5			—			4
Interest rate derivatives, net	9		(123		)	(19		)	(117		)
Total	$	97	$	(133	)	$	69		$	(225	)

Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting agreement exists. Accordingly, we also offset derivative assets and liabilities with amounts associated with cash margin. Our exchange-traded derivatives are transacted through brokerage accounts and are subject to margin requirements as established by the respective exchange. On a daily basis, our account equity (consisting of the sum of our cash balance and the fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin. As of September 30, 2012, we had a net broker receivable of approximately $28 million (consisting of initial margin of $82 million reduced by $54 million of variation margin that had been returned to us). As of December 31, 2011, we had a net broker payable of approximately $7 million (consisting of initial margin of $52 million reduced by $59 million of variation margin that had been returned to us). At September 30, 2012 and December 31, 2011, 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.

Recurring Fair Value Measurements

Derivative Financial Assets and Liabilities

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 September 30, 2012 and December 31, 2011. 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 affects the placement of assets and liabilities within the fair value hierarchy levels.

	Fair Value as of September 30, 2012 (in millions)										Fair Value as of December 31, 2011 (in millions)
Recurring Fair Value Measures (1)	Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Commodity derivatives	$	30	$	45		$	10	$	85		$	80	$	1		$	12	$	93
Interest rate derivatives	—		(133		)	—		(133		)	—		(137		)	—		(137		)
Foreign currency derivatives	—		6			—		6			—		1			—		1
Total	$	30	$	(82	)	$	10	$	(42	)	$	80	$	(135	)	$	12	$	(43	)

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

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The determination of the fair values above includes not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit) but also the impact of our nonperformance risk on our liabilities. The fair value of our commodity derivatives, interest-rate derivatives and foreign currency derivatives includes adjustments for credit risk. Our credit adjustment methodology uses market observable inputs and requires judgment. There were no changes to any of our valuation techniques during the period.

Level 1

Level 1 of the fair value hierarchy includes 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.

Level 2

Level 2 of the fair value hierarchy includes exchange-cleared commodity derivatives and over-the-counter commodity, interest rate and foreign currency derivatives that are traded in active markets. The fair value of these derivatives is based on broker price quotations which are corroborated with market observable inputs.

Level 3

Level 3 of the fair value hierarchy includes over-the-counter commodity derivatives that are traded in markets that are active but not sufficiently active to warrant level 2 classification in our judgment and certain physical commodity contracts. The fair value of our level 3 over-the-counter commodity derivatives is based on broker price quotations. The fair value of our level 3 physical commodity contracts is based on a valuation model utilizing broker-quoted forward commodity prices, and timing estimates, which involve management judgment. The significant unobservable inputs used in the fair value measurement of our level 3 derivatives are forward prices obtained from brokers. A significant increase (decrease) in these forward prices would result in a proportionately lower (higher) fair value measurement.

Rollforward of Level 3 Net Assets

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
Beginning Balance	$	36		$	10		$	12		$	(14	)
Unrealized gains/(losses):
Included in earnings (1)	(9		)	17			(1		)	30
Included in other comprehensive income	—			3			3			2
Settlements	(4		)	(2		)	(18		)	31
Derivatives entered into during the period	1			8			23			4
Transfers out of level 3	(14		)	—			(9		)	(17		)
Ending Balance	$	10		$	36		$	10		$	36

Change in unrealized gains/(losses) included in earnings relating to level 3 derivatives still held at the end of the periods	$	(8	)	$	26		$	25		$	35

(1) We reported unrealized gains and losses associated with level 3 commodity derivatives in our condensed consolidated statements of operations as Supply and Logistics segment revenues.

During the third quarter of 2012, we transferred commodity derivatives with an aggregate fair value of $14 million from level 3 to level 2. These derivatives consist of over the counter derivatives that were previously valued using forward prices obtained from a broker and are now being valued using unadjusted quoted prices in active markets. Our policy is to recognize transfers between levels as of the beginning of the reporting period in which the transfer occurred.

During the second quarter of 2012, we transferred commodity derivatives with an aggregate fair value of a $5 million loss from level 3 to level 2. These derivatives consist of NGL derivatives that are cleared through the CME Clearport platform. This transfer resulted from additional analysis regarding the CME’s pricing methodology.

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During the first quarter of 2011, we transferred interest rate and commodity derivatives with an aggregate fair value of $17 million from level 3 to level 2. This transfer resulted from the implementation of additional valuation procedures, using market observable inputs, to validate the broker or dealer price quotations used for fair value measurement.

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 will therefore be offset by gains or losses on the underlying transactions.

Note 12—Commitments and Contingencies

Litigation

General. In the ordinary course of business, we are involved 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. Although we believe that our operations are presently in material compliance with applicable requirements, as we acquire and incorporate additional assets it is possible that the Environmental Protection Agency (“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 whether such noncompliance initially developed before or after our acquisition.

New Jersey Department of Environmental Protection v. ExxonMobil Corp. et al. In June 2007, the New Jersey Department of Environmental Protection (“NJDEP”) brought suit in the Superior Court of New Jersey against GATX Corporation (“GATX”), ExxonMobil and our subsidiary, Plains Products Terminals LLC (“PPT”), to recover natural resources damages associated with, and to require remediation of, contamination at our Paulsboro terminal facility. ExxonMobil and GATX filed third-party demands against PPT, seeking indemnity and contribution. The natural resources damages were settled with the State of New Jersey. The Settlement Agreement was approved by the court in September 2011. PPT’s allocated share of this liability was $550,000, which was paid in November 2011. We remain in dispute with ExxonMobil regarding future remediation responsibility as well as responsibility for prior remediation costs.

Pemex Exploración y Producción v. Big Star Gathering Ltd L.L.P. et al. In two cases filed in the Texas Southern District Court in May 2011 and April 2012, Pemex Exploración y Producción (“PEP”) alleges that certain parties stole condensate from pipelines and gathering stations and conspired with U.S. companies (primarily in Texas) to import and market the stolen condensate. PEP does not allege that Plains was part of any conspiracy, but that it dealt in the condensate only after it had been obtained by others and resold to Plains Marketing, L.P. PEP seeks actual damages, attorney’s fees, and statutory penalties from Plains Marketing, L.P. At a hearing held on October 20, 2011, the Court ruled that Texas law (not Mexican law) governs the actions.

Environmental

General

Although we believe that our efforts to enhance our leak prevention and detection capabilities have produced positive results, we have experienced (and likely will experience future) releases of hydrocarbon products into the environment from our pipeline and storage operations. These releases can result from unpredictable man-made or natural forces and may reach “navigable waters” or other sensitive environments. Whether current or past, damages and liabilities associated with any such releases from our assets may substantially affect our business.

At September 30, 2012, our estimated undiscounted reserve for environmental liabilities, including the reserve related to our Rangeland Pipeline release discussed further below, totaled approximately $106 million, of which approximately $28 million was classified as short-term and approximately $78 million was classified as long-term. At December 31, 2011, our reserve for environmental liabilities totaled approximately $74 million, of which approximately $12 million was classified as short-term and approximately $62 million was classified as long-term. At September 30, 2012 and December 31, 2011, we had recorded receivables totaling approximately $50 million and $47 million, respectively, for amounts probable of recovery under insurance and from third parties under indemnification agreements.

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In some cases, the actual cash expenditures may not occur for three to five years. Our estimates used in these reserves are based on information currently available to us 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 liabilities. 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.

Rangeland Pipeline Release

On June 7, 2012, we experienced a crude oil release on a section of our Rangeland Pipeline located near Sundre, Alberta, Canada. Approximately 3,000 barrels were released into the Red Deer River and were contained downstream in the Gleniffer reservoir. The pipeline, while pressurized, was shut in at the time of the incident and emergency response personnel were mobilized to begin containment, clean-up and remediation procedures in cooperation with the applicable regulatory agencies. Clean-up and remediation activities of the reservoir were completed by June 30, 2012, and such activities for the surrounding impacted area are ongoing.

We estimate that the aggregate total clean-up and remediation costs, before insurance recoveries, will be approximately $53 million. This estimate considers our prior experience in environmental investigation and remediation matters, as well as available data from, and in consultation with, our environmental specialists. Although actual remediation costs may be more than amounts accrued, we believe we have established adequate reserves for all probable and reasonably estimable costs. We have accrued the total estimated costs to operating expense on our condensed consolidated statement of operations.

As of September 30, 2012, we had a remaining undiscounted gross environmental remediation liability related to this release of approximately $19 million, substantially all of which is presented as a current liability in “Accounts payable and accrued liabilities” on our condensed consolidated balance sheet. We maintain insurance coverage, which is subject to certain exclusions and deductibles, to protect us against such environmental liabilities. This coverage is adequate to cover the current estimated total remediation costs, and management believes that this coverage is also adequate to cover any potential remediation costs that may be in excess of amounts currently identified. As of September 30, 2012, we had a remaining receivable of approximately $43 million for the portion of this liability that we believe is probable of recovery from insurance, net of deductibles. This receivable has been recognized as a current asset in “Trade accounts receivable and other receivables, net” on our condensed consolidated balance sheet with the offset reducing operating expense on our condensed consolidated statement of operations.

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 various types of insurance that we consider adequate to cover our operations and certain assets. The insurance policies are subject to deductibles or self-insured retentions that we consider reasonable. Our insurance does not cover every potential risk associated with operating pipelines, terminals and other facilities, including the potential loss of significant revenues.

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 with respect to our operations. In the future, we may not be able to maintain insurance at levels that we consider adequate for rates we consider reasonable. As a result, we may elect to self-insure or utilize higher deductibles in certain insurance programs. For example, the market for hurricane-or windstorm-related property damage coverage has remained difficult the last few years. The amount of coverage available has been limited, and costs have increased substantially with the combination of premiums and deductibles.

In 2011, we elected not to renew our hurricane insurance, and, instead, self-insure this risk. Our assessment of the current availability of coverage and associated rates has led us to the decision to continue to self-insure throughout 2012. This decision does not affect our third-party liability insurance, which still covers hurricane-related liability claims and which we have renewed at our historic coverage levels. In addition, although we believe that we have established adequate reserves to the extent 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.

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Note 13—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 and Logistics		Total
Three Months Ended September 30, 2012
Revenues:
External Customers	$	150	$	156	$	9,048	$	9,354
Intersegment (1)	214		106		1		321
Total revenues of reportable segments	$	364	$	262	$	9,049	$	9,675
Equity earnings in unconsolidated entities	$	9	$	—	$	—	$	9
Segment profit (2) (3)	$	184	$	140	$	142	$	466
Maintenance capital	$	26	$	17	$	4	$	47

Three Months Ended September 30, 2011
Revenues:
External Customers	$	140	$	153	$	8,544	$	8,837
Intersegment (1)	160		38		1		199
Total revenues of reportable segments	$	300	$	191	$	8,545	$	9,036
Equity earnings in unconsolidated entities	$	4	$	—	$	—	$	4
Segment profit (2) (3)	$	152	$	95	$	179	$	426
Maintenance capital	$	17	$	6	$	2	$	25

Nine Months Ended September 30, 2012
Revenues:
External Customers	$	458	$	533	$	27,367	$	28,358
Intersegment (1)	585		252		1		838
Total revenues of reportable segments	$	1,043	$	785	$	27,368	$	29,196
Equity earnings in unconsolidated entities	$	25	$	—	$	—	$	25
Segment profit (2) (3)	$	516	$	344	$	544	$	1,404
Maintenance capital	$	78	$	34	$	11	$	123

Nine Months Ended September 30, 2011
Revenues:
External Customers	$	428	$	396	$	24,566	$	25,390
Intersegment (1)	436		120		1		557
Total revenues of reportable segments	$	864	$	516	$	24,567	$	25,947
Equity earnings in unconsolidated entities	$	9	$	—	$	—	$	9
Segment profit (2) (3)	$	416	$	259	$	464	$	1,139
Maintenance capital	$	52	$	16	$	9	$	77

(1)	Segment revenues and purchases and related costs include intersegment amounts. Intersegment sales are conducted at posted tariff rates, rates similar to those charged to third parties or rates that we believe approximate market. For further discussion, see “Analysis of Operating Segments” under Item 7 of our 2011 Annual Report on Form 10-K.

(2)	Supply and Logistics segment profit includes interest expense (related to hedged inventory purchases) of approximately $3 million and $6 million for the three months ended September 30, 2012 and 2011, respectively, and approximately $9 million and $17 million for the nine months ended September 30, 2012 and 2011, respectively.

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(3)	The following table reconciles segment profit to net income attributable to Plains (in millions):

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2012			2011			2012			2011
Segment profit	$	466		$	426		$	1,404		$	1,139
Depreciation and amortization	(210		)	(65		)	(356		)	(191		)
Interest expense	(74		)	(62		)	(214		)	(190		)
Other income/(expense), net	4			(5		)	6			(24		)
Income tax expense	(13		)	(6		)	(43		)	(28		)
Net income	173			288			797			706
Net income attributable to noncontrolling interests	(8		)	(7		)	(23		)	(18		)
Net income attributable to Plains	$	165		$	281		$	774		$	688

Note 14—Related Party Transactions

See Note 9 to our Consolidated Financial Statements included in Part IV of our 2011 Annual Report on Form 10-K for a complete discussion of our related party transactions.

Occidental Petroleum Corporation

As of September 30, 2012, a subsidiary of Occidental Petroleum Corporation (“Oxy”) owned approximately 35% of our general partner interest and had a representative on the board of directors of Plains All American GP LLC. During the three and nine months ended September 30, 2012 and 2011, we recognized sales and transportation revenues and purchased petroleum products from companies affiliated with Oxy. These transactions were conducted at posted tariff rates or prices that we believe approximate market. See detail below (in millions):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2012		2011		2012		2011
Revenues	$	383	$	530	$	1,435	$	2,311

Purchases and related costs	$	138	$	90	$	416	$	255

We currently have a netting arrangement with Oxy. Our gross receivable and payable amounts with affiliates of Oxy were as follows (in millions):

	September 30,		December 31,
	2012		2011
Trade accounts receivable and other receivables	$	227	$	132

Accounts payable	$	162	$	155

Note 15—Impairments

During the third quarter of 2012, we recognized losses on impairments of long-lived assets of approximately $125 million, primarily related to our Pier 400 terminal project which is reflected in “Depreciation and amortization” on our condensed consolidated statement of operations. This project, which we acquired in late 2006 by virtue of our merger with Pacific Energy Partners, was to develop a deepwater petroleum import terminal at Pier 400 and Terminal Island in the Port of Los Angeles to handle marine receipts of crude oil and refinery feedstock. During the third quarter of 2012, we decided not to proceed with the development of this project. A number of factors contributed to the uncertainties with respect to financial returns and the determination not to proceed with the project, including project delays, the economic downturn, regulatory and permitting hurdles, a challenging refining environment in California and an industry shift in the outlook for availability of domestic crude oil. We assessed the recoverability of these long-lived assets and, where necessary, performed further analysis based on a projected discounted cash flow methodology. As a result of this impairment review, we wrote off a substantial portion of the carrying amount of these long-lived assets, except for the portion that we anticipate we will recover. These project assets were included in our Facilities segment.

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

Introduction

The following discussion is intended to provide investors with an understanding of our financial condition and results of our operations and should be read in conjunction with our historical consolidated financial statements and accompanying notes and Management’s Discussion and Analysis of Financial Condition and Results of Operations as presented in our 2011 Annual Report on Form 10-K. For more detailed information regarding the basis of presentation for the following financial information, see the condensed consolidated financial statements and related notes that are contained in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Our discussion and analysis includes the following:

· Executive Summary

· Acquisitions and Internal Growth Projects

· Results of Operations

· Liquidity and Capital Resources

· Off-Balance Sheet Arrangements

· Recent Accounting Pronouncements

· Critical Accounting Policies and Estimates

· Forward-Looking Statements

Executive Summary

Company Overview

We engage in the transportation, storage, terminalling and marketing of crude oil and refined products, as well as the processing, transportation, fractionation, storage and marketing of NGL. Through our general partner interest and majority equity ownership position in PAA Natural Gas Storage, L.P., we also own and operate natural gas storage facilities. We were formed in 1998, and our operations are conducted directly and indirectly through our operating subsidiaries and are managed through three operating segments: (i) Transportation, (ii) Facilities and (iii) Supply and Logistics.

Overview of Operating Results, Capital Investments and Significant Activities

During the first nine months of 2012, our net income attributable to Plains was approximately $774 million, or $1.70 per diluted limited partner unit, as compared to net income attributable to Plains of approximately $688 million, or $1.76 per diluted limited partner unit, recognized during the first nine months of 2011. The major items impacting the favorable performance between periods include increased utilization of certain existing transportation assets, incremental fee-based contributions associated with acquisition and expansion capital invested in our transportation and facilities segments and increased lease-gathering volumes and improved unit margins in our supply and logistics segment. The majority of the incremental volumes and a portion of the enhanced unit margins are attributable to the increased production from the development of North American crude oil and liquids-rich resource plays. Favorable basis and quality differentials and the mark-to-market impact for derivative instruments (partially offset by the net impact of write downs of inventory and related gains recognized on the sales of such inventory) also contributed substantially to margins in our supply and logistics segment. These favorable contributions to our supply and logistics segment were partially offset by lower margins on our NGL sales due to lower NGL prices and less favorable market conditions.

Other significant items during the period were:

· The completion of our acquisition of all of the outstanding shares of BP Canada Energy Company for total consideration of approximately $1.68 billion, subject to working capital and other adjustments (see Note 4 to our condensed consolidated financial statements for further discussion of this acquisition);

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· The receipt of net proceeds of approximately $2.05 billion from (i) the issuance of senior notes, (ii) the sale of 11.5 million common units through our March equity offering and (iii) the sale of approximately 8.4 million common units under our continuous offering programs; and

· Increased depreciation and amortization expense resulting from our growth through acquisitions and expansion projects completed throughout 2012, as well as impairment losses of approximately $125 million recognized during the third quarter of 2012 primarily related to our Pier 400 terminal project.

Acquisitions and Internal Growth Projects

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

	Nine Months
	Ended September 30,
	2012		2011
Acquisition capital (1)	$	1,657	$	765
Internal growth projects	831		380
Maintenance capital	123		77
Total	$	2,611	$	1,222

(1) Acquisition capital for the first nine months of 2012 primarily relates to the BP NGL Acquisition. See Note 4 to our condensed consolidated financial statements for further discussion regarding our acquisition activities.

Internal Growth Projects

The following table summarizes our more notable projects in progress during 2012 and the forecasted expenditures for the year ending December 31, 2012 (in millions):

Projects		2012
Eagle Ford Project		$125
Spraberry Area Pipeline Projects		90
Gardendale Gathering System (1)		85
Rainbow II Pipeline		75
PAA Natural Gas Storage (multiple projects)		61
Bakken North		50
Rail Projects (2)		50
Mississippian Lime Project		45
St. James Terminal Expansion (3)		45
Yorktown Terminal Project		35
Cushing Terminal Expansion (3)		30
BP NGL Acquisition Related Projects		25
Patoka Terminal Expansion (3)		25
Shafter Expansion		18
Other Projects (4)		391
		$1,150
Potential Adjustments for Timing/Scope Refinement (5)		- $50 + $100
Total Projected Expansion Capital Expenditures		$1,100 - $1,250

Maintenance Capital Expenditures		$160 - $170

(1) Includes pipeline, tankage and condensate stabilization.

(2) Excludes rail project associated with the Yorktown terminal project.

(3) Includes carryover capital from 2011 as well as new expansions.

(4) Primarily multiple, smaller projects comprised of pipeline connections, upgrades and truck stations, new tank construction and refurbishing, pipeline linefill purchases and carry-over of projects from prior years.

(5) Potential variation to current capital costs estimates may result from changes to project design, final cost of materials and labor and timing of incurrence of costs due to uncontrollable factors such as permits, regulatory approvals and weather.

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Results of Operations

Analysis of Operating Segments

We manage our operations through three operating segments: (i) Transportation, (ii) Facilities and (iii) Supply and Logistics. Our Chief Operating Decision Maker (our Chief Executive Officer) evaluates such segment performance based on a variety of measures including segment profit, segment volumes, segment profit per barrel and maintenance capital investment. See Note 13 to our Consolidated Financial Statements included in Part IV of our 2011 Annual Report on Form 10-K for further discussion of how we evaluate segment performance.

The following table sets forth an overview of our consolidated financial results calculated in accordance with GAAP (in millions, except for per unit amounts):

	Three Months						Favorable/ (Unfavorable)					Nine Months						Favorable/ (Unfavorable)
	Ended September 30,						Variance					Ended September 30,						Variance
	2012			2011			$			%		2012			2011			$			%
Transportation segment profit	$	184		$	152		$	32		21	%	$	516		$	416		$	100		24	%
Facilities segment profit	140			95			45			47	%	344			259			85			33	%
Supply and Logistics segment profit	142			179			(37		)	(21	)%	544			464			80			17	%
Total segment profit	466			426			40			9	%	1,404			1,139			265			23	%
Depreciation and amortization	(210		)	(65		)	(145		)	(223	)%	(356		)	(191		)	(165		)	(86	)%
Interest expense	(74		)	(62		)	(12		)	(19	)%	(214		)	(190		)	(24		)	(13	)%
Other income/(expense), net	4			(5		)	9			180	%	6			(24		)	30			125	%
Income tax expense	(13		)	(6		)	(7		)	(117	)%	(43		)	(28		)	(15		)	(54	)%
Net income	173			288			(115		)	(40	)%	797			706			91			13	%
Less: Net income attributable to noncontrolling interests	(8		)	(7		)	(1		)	(14	)%	(23		)	(18		)	(5		)	(28	)%
Net income attributable to Plains	$	165		$	281		$	(116	)	(41	)%	$	774		$	688		$	86		13	%

Net income attributable to Plains:
Earnings per basic limited partner unit	$	0.27		$	0.74		$	(0.47	)	(64	)%	$	1.71		$	1.77		$	(0.06	)	(3	)%
Earnings per diluted limited partner unit	$	0.27		$	0.74		$	(0.47	)	(64	)%	$	1.70		$	1.76		$	(0.06	)	(3	)%
Basic weighted average units outstanding	329			299			30			10	%	322			294			28			10	%
Diluted weighted average units outstanding	331			300			31			10	%	325			296			29			10	%

Non-GAAP Financial Measures

To supplement our financial information presented in accordance with GAAP, management uses additional measures that are known as “non-GAAP financial measures” in its evaluation of past performance and prospects for the future. The primary measures used by management are adjusted earnings before interest, taxes, depreciation and amortization (“adjusted EBITDA”) and implied distributable cash flow (“DCF”).

Management believes that the presentation of such additional financial measures provides useful information to investors regarding our performance and results of operations because these measures, when used in conjunction with related GAAP financial measures, (i) provide additional information about our core operating performance and ability to generate and distribute cash flow, (ii) provide investors with the financial analytical framework upon which management bases financial, operational, compensation and planning decisions and (iii) present measurements that investors, rating agencies and debt holders have indicated are useful in assessing us and our results of operations. These measures may exclude, for example, (i) charges for obligations that are expected to be settled with the issuance of equity instruments, (ii) the mark-to-market of derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), (iii) items that are not indicative of our core operating results and business outlook and/or (iv) other items that we believe should be excluded in understanding our core operating performance. We have defined all such items hereinafter as “Selected Items Impacting Comparability.” These additional financial measures are reconciled from the most directly comparable measures as reported in accordance with GAAP, and should be viewed in addition to, and not in lieu of, our condensed consolidated financial statements and footnotes.

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The following table sets forth non-GAAP financial measures that are reconciled to the most directly comparable GAAP measures (in millions):

	Three Months						Favorable/ (Unfavorable)					Nine Months						Favorable/ (Unfavorable)
	Ended September 30,						Variance					Ended September 30,						Variance
	2012			2011			$			%		2012			2011			$			%
Net income	$	173		$	288		$	(115	)	(40	)%	$	797		$	706		$	91		13	%
Add:
Depreciation and amortization	210			65			145			223	%	356			191			165			86	%
Income tax expense	13			6			7			117	%	43			28			15			54	%
Interest expense	74			62			12			19	%	214			190			24			13	%
EBITDA	$	470		$	421		$	49		12	%	$	1,410		$	1,115		$	295		26	%

Selected Items Impacting Comparability of EBITDA
Gains/(losses) from derivative activities net of inventory valuation adjustments (1)	$	(31	)	$	31		$	(62	)	(200	)%	$	(18	)	$	72		$	(90	)	(125	)%
Equity compensation expense (2)	(12		)	(6		)	(6		)	(100	)%	(50		)	(40		)	(10		)	(25	)%
Net gain/(loss) loss on foreign currency revaluation (3)	11			(17		)	28			165	%	(6		)	(17		)	11			65	%
Net loss on early repayment of senior notes	—			—			—			—	%	—			(23		)	23			100	%
Significant acquisition-related expenses	—			—			—			—	%	(13		)	(4		)	(9		)	(225	)%
Other (4)	—			(1		)	1			100	%	—			(1		)	1			100	%
Selected Items Impacting Comparability of EBITDA	$	(32	)	$	7		$	(39	)	(557	)%	$	(87	)	$	(13	)	$	(74	)	(569	)%

EBITDA	$	470		$	421		$	49		12	%	$	1,410		$	1,115		$	295		26	%
Selected Items Impacting Comparability of EBITDA	32			(7		)	39			557	%	87			13			74			569	%
Adjusted EBITDA	$	502		$	414		$	88		21	%	$	1,497		$	1,128		$	369		33	%

Adjusted EBITDA	$	502		$	414		$	88		21	%	$	1,497		$	1,128		$	369		33	%
Interest expense	(74		)	(62		)	(12		)	(19	)%	(214		)	(190		)	(24		)	(13	)%
Maintenance capital	(47		)	(25		)	(22		)	(88	)%	(123		)	(77		)	(46		)	(60	)%
Current income tax expense	(10		)	(7		)	(3		)	(43	)%	(32		)	(25		)	(7		)	(28	)%
Equity earnings in unconsolidated entities, net of distributions	1			2			(1		)	(50	)%	2			7			(5		)	(71	)%
Distributions to noncontrolling interests (5)	(12		)	(12		)	—			—	%	(36		)	(35		)	(1		)	(3	)%
Other	—			—			—			—	%	—			(1		)	1			100	%
Implied DCF	$	360		$	310		$	50		16	%	$	1,094		$	807		$	287		36	%

(1) Includes mark-to-market gains and losses resulting from derivative instruments that are related to underlying activities in future periods or the reversal of mark-to-market gains and losses from the prior period net of inventory valuation adjustments. See Note 11 to our condensed consolidated financial statements for a comprehensive discussion regarding our derivatives and risk management activities.

(2) Equity compensation expense includes expense associated with awards that will or may be settled in units and awards that will or may be settled in cash. The awards that will or may be settled in units are included in our diluted earnings per unit calculation when the applicable performance criteria have been met. We consider the compensation expense associated with these awards as a selected item impacting comparability as the dilutive impact of the outstanding awards is included in our diluted earnings per unit calculation and the majority of the awards are expected to be settled in units. The compensation expense associated with these awards is shown as a selected item impacting comparability in the table above. The portion of compensation expense associated with awards that are certain to be settled in cash are not considered a selected item impacting comparability. See Note 10 to our Consolidated Financial Statements included in Part IV of our 2011 Annual Report on Form 10-K for a comprehensive discussion regarding our equity compensation plans.

(3) During the three and nine months ended September 30, 2012 and 2011, there were significant fluctuations in the value of the Canadian dollar to the U.S dollar, resulting in losses that were not related to our core operating results and were thus classified as selected items impacting comparability. See Note 11 to our condensed consolidated financial statements for further discussion regarding our currency exchange rate risk hedging activities.

(4) Includes other immaterial selected items impacting comparability.

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(5) Includes distributions that pertain to the current quarter’s net income and are to be paid in the subsequent quarter.

Analysis of Operating Segments

Transportation Segment

Our transportation segment operations generally consist of fee-based activities associated with transporting crude oil, NGL and refined products on pipelines, gathering systems, trucks and barges. The transportation segment generates revenue through a combination of tariffs, third-party leases of pipeline capacity and transportation fees.

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

							Favorable/											Favorable/
	Three Months						(Unfavorable)					Nine Months						(Unfavorable)
Operating Results (1)	Ended September 30,						Variance					Ended September 30,						Variance
(in millions, except per barrel amounts)	2012			2011			$			%		2012			2011			$			%
Revenues (1)
Tariff activities	$	315		$	253		$	62		25	%	$	907		$	742		$	165		22	%
Trucking	49			47			2			4	%	136			122			14			11	%
Total transportation revenues	364			300			64			21	%	1,043			864			179			21	%

Costs and Expenses (1)
Trucking costs	(36		)	(34		)	(2		)	(6	)%	(100		)	(88		)	(12		)	(14	)%
Field operating costs (excluding equity compensation expense)	(119		)	(97		)	(22		)	(23	)%	(343		)	(293		)	(50		)	(17	)%
Equity compensation expense - operations (2)	(3		)	(1		)	(2		)	(200	)%	(12		)	(6		)	(6		)	(100	)%
Segment general and administrative expenses (excluding equity compensation expense) (3)	(23		)	(16		)	(7		)	(44	)%	(73		)	(49		)	(24		)	(49	)%
Equity compensation expense - general and administrative (2)	(8		)	(4		)	(4		)	(100	)%	(24		)	(21		)	(3		)	(14	)%
Equity earnings in unconsolidated entities	9			4			5			125	%	25			9			16			178	%
Segment profit	$	184		$	152		$	32		21	%	$	516		$	416		$	100		24	%
Maintenance capital	$	26		$	17		$	(9	)	(53	)%	$	78		$	52		$	(26	)	(50	)%
Segment profit per barrel	$	0.57		$	0.54		$	0.03		6	%	$	0.55		$	0.50		$	0.05		10	%

Average Daily Volumes	Three Months Ended September 30,		Favorable/ (Unfavorable) Variance				Nine Months Ended September 30,		Favorable/ (Unfavorable) Variance
(in thousands of barrels per day) (4)	2012	2011	Volumes		%		2012	2011	Volumes		%
Tariff activities
Crude Oil Pipelines
All American	38	38	—		—	%	31	36	(5	)	(14	)%
Basin	474	443	31		7	%	495	432	63		15	%
Capline	159	121	38		31	%	144	165	(21	)	(13	)%
Line 63/Line 2000	131	126	5		4	%	126	114	12		11	%
Salt Lake City Area Systems	146	142	4		3	%	141	139	2		1	%
Permian Basin Area Systems	451	408	43		11	%	450	402	48		12	%
Mid-Continent Area Systems	257	217	40		18	%	247	217	30		14	%
Manito	51	65	(14	)	(22	)%	59	66	(7	)	(11	)%
Rainbow	142	96	46		48	%	147	132	15		11	%
Rangeland	57	60	(3	)	(5	)%	60	57	3		5	%
Other	1,141	1,096	45		4	%	1,140	1,063	77		7	%
NGL Pipelines	264	—	264		N/A		163	—	163		N/A
Refined Products Pipelines	112	104	8		8	%	114	99	15		15	%
Tariff activities total	3,423	2,916	507		17	%	3,317	2,922	395		14	%
Trucking	107	109	(2	)	(2	)%	103	104	(1	)	(1	)%
Transportation segment total	3,530	3,025	505		17	%	3,420	3,026	394		13	%

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

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(2) Equity compensation expense shown in the table above includes that portion of equity compensation expense represented by outstanding awards under the LTIP Plans that, pursuant to the terms of such awards, will be settled in cash only and have no impact on diluted units. The equity compensation expense presented in the “Selected Items Impacting Comparability” section of the table under “Results of Operations—Non-GAAP Financial Measures” excludes this portion of the equity compensation expense. See Note 10 to our Consolidated Financial Statements included in Part IV of our 2011 Annual Report on Form 10-K for additional discussion regarding our equity compensation plans.

(3) Segment general and administrative expenses (G&A) reflect direct costs attributable to each segment and an allocation of other expenses to the segments based on the business activities that existed at that time. The proportional allocations by segment require judgment by management and will continue to be based on the business activities that exist during each period.

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

Tariffs and other fees on our pipeline systems vary by receipt point and delivery point. The segment profit generated by our tariff and other fee-related activities depends on the volumes transported on the pipeline and the level of the tariff and other fees charged as well as the fixed and variable field costs of operating the pipeline. Segment profit from our pipeline capacity leases generally reflects a negotiated amount.

The following is a discussion of items impacting transportation segment profit and segment profit per barrel for the periods indicated.

Operating Revenues and Volumes. As noted in the table above, our total transportation segment revenues, net of trucking costs, and volumes increased for both the three and nine months ended September 30, 2012 compared to the three and nine months ended September 30, 2011. The primary drivers of the significant variances in revenues and volumes between the comparative periods were:

· BP NGL Acquisition—The pipelines acquired through the BP NGL Acquisition on April 1, 2012 generated revenues of approximately $29 million and $59 million and increased volumes by approximately 264,000 barrels per day and 163,000 barrels per day for the three and nine months ended September 30, 2012, respectively.

· North American Crude Oil Production—Increased producer drilling activities, primarily in the Permian Basin, Western Oklahoma and Texas Panhandle producing regions, combined with our phased-in expansion projects, resulted in favorable volume and revenue variances for the three and nine months ended September 30, 2012 over the comparative 2011 periods, most notably on our Basin, Mesa, Permian Basin and Mid-Continent Area Systems.

Additional noteworthy volume and revenue variances on our individual pipeline systems for the three months ended September 30, 2012 include (i) increased volumes on the Capline Pipeline System related to unplanned refinery downtime during the comparative 2011 period and (ii) decreased volumes on our Manito Pipeline System primarily due to volumes diverted to rail facilities. Noteworthy variances for the nine months ended September 30, 2012 include decreased volumes on (i) our All American System primarily related to maintenance activities at the production facilities, (ii) the Capline Pipeline System primarily related to shifts in refinery supply, partially offset by unplanned refinery downtime as discussed above and (iii) our Manito Pipeline System due to volumes diverted to rail facilities.

· Rate Changes — Revenues were favorably impacted by increases in rates on our FERC-regulated pipelines due to upward indexing effective July 1, 2011 and July 1, 2012, as well as increasing tariff rates on certain of our intrastate pipelines.

· Loss Allowance Revenue — As is common in the industry, our tariffs incorporate a loss allowance factor that is intended to, among other things, offset losses due to evaporation, measurement and other losses in transit. We value the variance of allowance volumes to actual losses at the estimated net realizable value (including the impact of gains and losses from derivative-related activities) at the time the variance occurred and the result is recorded as either an increase or decrease to tariff revenues. The loss allowance revenue increased by approximately $2 million and $17 million for the three and nine months ended September 30, 2012 compared to the three and nine months ended September 30, 2011. The increase was primarily due to higher volumes, partially offset by lower realized prices, during the comparative 2012 periods.

· Rainbow Pipeline System— Revenues were favorable for both the three and nine months ended September 30, 2012 compared to the 2011 periods due to (i) higher volumes in second and third quarters of 2012 compared to the second and third quarters of 2011 due to the impact of the pipeline release in the 2011 period and (ii) higher revenue in 2012 as a result of rate increases, partially offset in the nine month 2012 period by decreased volumes related to a third-party competitor pipeline that was placed into service in the third quarter of 2011.

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Field Operating Costs. Field operating costs (excluding equity compensation expense as discussed further below) increased during the three and nine months ended September 30, 2012 compared to the three and nine months ended September 30, 2011 consistent with the overall growth in segment volumes and remained relatively constant on a per barrel basis during each of those periods. Operating costs for the nine months ended September 30, 2012 and September 30, 2011 were also impacted by approximately $11 million of environmental remediation expenses associated with the Rangeland Pipeline release in second quarter of 2012 and approximately $13 million of environmental remediation expenses associated with the Rainbow Pipeline release in the second quarter of 2011.

General and Administrative Expenses. General and administrative expenses (excluding equity compensation as discussed below) increased during the three and nine months ended September 30, 2012 compared to the three and nine months ended September 30, 2011 due to costs associated with the closing and integration of the BP NGL Acquisition as well as the overall growth of the segment.

Equity Compensation Expense. A majority of our equity compensation awards (including the Class B units) contain performance conditions contingent upon achieving certain distribution levels. For awards with performance conditions (such as distribution targets), expense is accrued over the service period only if the performance condition is considered probable of occurring. When awards with performance conditions that were previously considered improbable become probable, we incur additional expense in the period that our probability assessment changes. This is necessary to bring the accrued liability associated with these awards up to the level it would have been if we had been accruing for these awards since the grant date. At September 30, 2012, we determined that a PAA distribution level of $2.35 was probable of occurring. Furthermore, a change in unit price impacts the fair value of our liability-classified awards. See Note 10 to our Consolidated Financial Statements included in Part IV of our 2011 Annual Report on Form 10-K for further information regarding our equity compensation plans.

Equity compensation expense increased for the three months ended September 30, 2012 compared to the three months ended September 30, 2011, primarily due to an increase in unit price during the third quarter of 2012 compared to a decrease during the third quarter of 2011. Equity compensation expense increased for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011, primarily due to (i) an increase in unit price for the first nine months of 2012 compared to a decrease for the first nine months of 2011 and (ii) additional awards that have been deemed probable of vesting, partially offset by (i) a decrease in expense related to a less significant impact of the change in probability assessment during the first nine months of 2012 compared to the first nine months of 2011 and (ii) more forfeitures during the first nine months of 2012 compared to the first nine months of 2011.

Maintenance Capital. Maintenance capital consists of capital investments 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. The increase in maintenance capital in the three and nine months ended September 30, 2012 compared to the three and nine months ended September 30, 2011 is primarily due to increased investment in pipeline integrity projects.

Equity Earnings in Unconsolidated Entities. The favorable variance in equity earnings in unconsolidated entities for the three and nine months ended September 30, 2012 compared to the three and nine months ended September 30, 2011 was primarily related to increased earnings in our equity investments due to increased volumes as a result of industry fundamentals as noted above.

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Facilities Segment

Our facilities segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services for crude oil, refined products, natural gas and NGL, as well as NGL fractionation and isomerization services. The facilities segment generates revenue through a combination of month-to-month and multi-year leases and processing arrangements.

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

							Favorable/											Favorable/
	Three Months						(Unfavorable)					Nine Months						(Unfavorable)
Operating Results (1)	Ended September 30,						Variance					Ended September 30,						Variance
(in millions, except per barrel amounts)	2012			2011			$			%		2012			2011			$			%
Revenues (1)	$	236		$	150		$	86		57	%	$	626		$	441		$	185		42	%
Natural gas sales (2)	26			41			(15		)	(37	)%	159			75			84			112	%
Storage related costs (natural gas related)	(4		)	(5		)	1			20	%	(16		)	(15		)	(1		)	(7	)%
Natural gas sales costs (2)	(25		)	(40		)	15			38	%	(152		)	(73		)	(79		)	(108	)%
Field operating costs (excluding equity compensation expense)	(72		)	(38		)	(34		)	(89	)%	(204		)	(122		)	(82		)	(67	)%
Equity compensation expense - operations (3)	—			—			—			—	%	(2		)	(1		)	(1		)	(100	)%
Segment general and administrative expenses (excluding equity compensation expense) (4)	(16		)	(11		)	(5		)	(45	)%	(48		)	(35		)	(13		)	(37	)%
Equity compensation expense - general and administrative (3)	(5		)	(2		)	(3		)	(150	)%	(19		)	(11		)	(8		)	(73	)%
Segment profit	$	140		$	95		$	45		47	%	$	344		$	259		$	85		33	%
Maintenance capital	$	17		$	6		$	(11	)	(183	)%	$	34		$	16		$	(18	)	(113	)%
Segment profit per barrel	$	0.42		$	0.38		$	0.04		11	%	$	0.37		$	0.36		$	0.01		3	%

			Favorable/					Favorable/
	Three Months		(Unfavorable)			Nine Months		(Unfavorable)
	Ended September 30,		Variance			Ended September 30,		Variance
Volumes (5)(6)	2012	2011	Volumes	%		2012	2011	Volumes	%
Crude oil, refined products and NGL storage (average monthly capacity in millions of barrels)	94	71	23	32	%	88	69	19	28	%
Natural gas storage (average monthly capacity in billions of cubic feet)	89	75	14	19	%	82	69	13	19	%
NGL fractionation (average throughput in thousands of barrels per day)	100	16	84	525	%	73	14	59	421	%
Facilities segment total (average monthly capacity in millions of barrels)	111	84	27	32	%	104	81	23	28	%

(1) Includes intersegment amounts.

(2) Natural gas sales and costs are attributable to the activities performed by PNG’s commercial optimization group.

(3) Equity compensation expense shown in the table above includes that portion of equity compensation expense represented by outstanding awards under the LTIPs that, pursuant to the terms of such awards, will be settled in cash only and have no impact on diluted units. The equity compensation expense presented in the “Selected Items Impacting Comparability” section of the table under “Results of Operations—Non-GAAP Financial Measures” excludes this portion of the equity compensation expense. See Note 10 to our Consolidated Financial Statements included in Part IV of our 2011 Annual Report on Form 10-K for additional discussion regarding our equity compensation plans.

(4) Segment general and administrative expenses (G&A) reflect direct costs attributable to each segment and an allocation of other expenses to the segments based on the business activities that existed at that time. The proportional allocations by segment require judgment by management and will continue to be based on the business activities that exist during each period.

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

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(6) Facilities total calculated as the sum of: (i) crude oil, refined products and NGL storage capacity; (ii) natural gas capacity divided by 6 to account for the 6:1 mcf of gas to crude Btu equivalent ratio and further divided by 1,000 to convert to monthly volumes in millions; and (iii) NGL fractionation volumes multiplied by the number of days in the period and divided by the number of months in the period.

The following is a discussion of items impacting facilities segment profit and segment profit per barrel for the periods indicated.

Operating Revenues and Volumes. As noted in the table above, our facilities segment revenues, less storage related costs and natural gas purchases, and volumes increased for the three and nine months ended September 30, 2012 compared to the same periods in 2011. The significant variances in revenues and average monthly volumes between the comparative periods are primarily due to our ongoing acquisition and expansion activities as discussed below:

· BP NGL Acquisition—The NGL storage facilities, fractionation plants and related assets acquired through the BP NGL Acquisition on April 1, 2012 contributed aggregate revenues of approximately $71 million and $132 million for the three and nine months ended September 30, 2012, respectively. These assets increased average monthly capacity of NGL storage by approximately 14 million barrels and 9 million barrels for the three and nine months ended September 30, 2012, respectively, and increased average NGL fractionation throughput by approximately 83,000 barrels per day and 58,000 barrels per day for the three and nine months ended September 30, 2012, respectively.

· Other Acquisitions and Major Expansion Projects — Expansion projects that were completed in phases throughout recent years at some of our major terminal locations, as well as the acquisition of our Yorktown facility in December 2011, favorably impacted revenues and volumes for the comparative 2012 periods. We estimate that these expansion and acquisition activities increased our revenues by approximately $8 million and $28 million, respectively, for the three and nine months ended September 30, 2012 compared to the three and nine months ended September 30, 2011. The most significant expansions were those completed at our Cushing, Patoka and St. James terminals, resulting in increased storage capacity, rail loading and unloading capability and barge loading and receipt capability.

Additionally, our results for the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011 were favorably impacted by (i) increased revenues related to a continued rise in our rail and barge loading and unloading activities; (ii) contributions from a full period of operations at the Southern Pines facility, which was acquired in February 2011 and; (iii) incremental revenues attributable to the expansion of working gas capacity at PNG’s Pine Prairie and Southern Pines facilities.

Field Operating Costs. Field operating costs (excluding equity compensation expense as discussed further below) increased during the three and nine months ended September 30, 2012 compared to the three and nine months ended September 30, 2011 due to our growth through acquisitions, primarily the BP NGL and Yorktown acquisitions. Additionally, the BP NGL Acquisition assets and operations typically have a higher ratio of operating costs to revenue than our historic operations in this segment.

General and Administrative Expenses. General and administrative expenses (excluding equity compensation as discussed below) increased during the three and nine months ended September 30, 2012 compared to the three and nine months ended September 30, 2011 due to growth associated with the BP NGL Acquisition as well as certain one-time costs during the nine months ended September 30, 2012 associated with integrating the acquisition.

Equity Compensation Expense. See “Results of Operations—Analysis of Operating Segments—Transportation Segment—Equity Compensation Expense” above for a discussion regarding variances in equity compensation expense for the comparative periods presented. Also, see Note 10 to our Consolidated Financial Statements included in Part IV of our 2011 Annual Report on Form 10-K for additional information on our equity compensation plans.

Maintenance Capital. The increase in maintenance capital in the three and nine months ended September 30, 2012 over the three and nine months ended September 30, 2011 is primarily a result of increased integrity investment associated with growth from acquisitions, primarily the BP NGL Acquisition, as well as timing of completing integrity projects.

Supply and Logistics Segment

Our revenues from supply and logistics activities reflect the sale of gathered and bulk-purchased crude oil, as well as sales of NGL volumes purchased from processors. These revenues also include the sale of additional barrels exchanged through buy/sell arrangements entered into to supplement the margins of the gathered and bulk-purchased volumes. We do not anticipate that future changes in revenues will be a primary driver of segment profit. Generally, we expect our segment profit to increase or decrease directionally with (i) increases or decreases in our supply and logistics segment volumes (which consist of lease gathered crude oil purchase volumes, NGL sales volumes and

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waterborne cargos), (ii) demand for lease gathering services we provide producers and (iii) the overall volatility and strength or weakness of market conditions and the allocation of our assets among our various risk management strategies. In addition, the execution of our risk management strategies in conjunction with our assets can provide upside in certain markets. Although we believe that the combination of our lease gathered business and our risk management activities provides a balance that provides general stability in our margins, these margins are not fixed and will vary from period to period.

The following table sets forth our operating results from our supply and logistics segment for the periods indicated:

							Favorable/											Favorable/
	Three Months						(Unfavorable)					Nine Months						(Unfavorable)
Operating Results (1)	Ended September 30,						Variance					Ended September 30,						Variance
(in millions, except per barrel amounts)	2012			2011			$			%		2012			2011			$			%
Revenues	$	9,049		$	8,545		$	504		6	%	$	27,368		$	24,567		$	2,801		11	%
Purchases and related costs (2)	(8,776		)	(8,259		)	(517		)	(6	)%	(26,414		)	(23,794		)	(2,620		)	(11	)%
Field operating costs (excluding equity compensation expense)	(101		)	(84		)	(17		)	(20	)%	(308		)	(225		)	(83		)	(37	)%
Equity compensation expense - operations (3)	(1		)	—			(1		)	N/A		(2		)	(1		)	(1		)	(100	)%
Segment general and administrative expenses (excluding equity compensation expense) (4)	(24		)	(20		)	(4		)	(20	)%	(77		)	(67		)	(10		)	(15	)%
Equity compensation expense - general and administrative (3)	(5		)	(3		)	(2		)	(67	)%	(23		)	(16		)	(7		)	(44	)%
Segment profit	$	142		$	179		$	(37	)	(21	)%	$	544		$	464		$	80		17	%
Maintenance capital	$	4		$	2		$	(2	)	(100	)%	$	11		$	9		$	(2	)	(22	)%
Segment profit per barrel	$	1.55		$	2.28		$	(0.73	)	(32	)%	$	2.06		$	1.98		$	0.08		4	%

			Favorable/						Favorable/
	Three Months		(Unfavorable)				Nine Months		(Unfavorable)
Average Daily Volumes	Ended September 30,		Variance				Ended September 30,		Variance
(in thousands of barrels per day)	2012	2011	Volumes		%		2012	2011	Volumes		%
Crude oil lease gathering purchases	811	748	63		8	%	808	731	77		11	%
NGL sales	179	77	102		132	%	155	97	58		60	%
Waterborne cargos	5	27	(22	)	(81	)%	3	28	(25	)	(89	)%
Supply and Logistics segment total	995	852	143		17	%	966	856	110		13	%

(1) Revenues and costs include intersegment amounts.

(2) Purchases and related costs include interest expense (related to hedged crude oil inventory purchases) of approximately $3 million and $9 million for the three and nine months ended September 30, 2012 compared to $6 million and $17 million for the three and nine months ended September 30, 2011, respectively.

(3) Equity compensation expense presented in the reconciliation to segment profit above includes that portion of equity compensation expense represented by outstanding awards under the LTIPs that, pursuant to the terms of such awards, will be settled in cash only and have no impact on diluted units. The equity compensation expense presented in the “Selected Items Impacting Comparability” section of the table under “Results of Operations—Non-GAAP Financial Measures” excludes this portion of the equity compensation expense. See Note 10 to our Consolidated Financial Statements included in Part IV of our 2011 Annual Report on Form 10-K for additional discussion regarding our equity compensation plans.

The New York Mercantile Exchange (“NYMEX”) benchmark price of crude oil ranged from approximately $82 to $100 per barrel and $76 to $101 per barrel during the three months ended September 30, 2012 and 2011, respectively, and from $77 to $111 per barrel and $76 to $115 per barrel during the nine months ended September 30, 2012 and 2011, respectively. Because the commodities that we buy and sell are generally indexed to the same pricing indices for both the sales and purchases, revenues and costs related to purchases will fluctuate with market prices. However, the margins related to those sales and purchases will not necessarily have a corresponding increase or decrease. The absolute amount of our revenues and purchases increased for the three and nine months ended September 30, 2012 and 2011 resulting from increases in volumes in the comparative 2012 periods.

Generally, we expect a base level of earnings from our supply and logistics segment from the assets employed by this segment. This base level may be optimized and enhanced when there is a high level of market volatility, favorable basis differentials and/or a steep contango or backwardated market structure. The increasing production of oil and liquids rich gas in North America has created supply and demand imbalances that have increased the volatility of historical differentials for many grades of crude oil and has

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also impacted the historical pricing relationship between NGL and crude oil. Our supply and logistics segment operating results are further impacted by foreign currency translations adjustments as certain of our subsidiaries are based in Canada and use the Canadian dollar as their functional currency. Revenues and expenses are translated at average exchange rates prevailing for each month and comparison between periods may be impacted by changes in the average exchange rates. Also, our NGL marketing operations are sensitive to weather-related demand, particularly during the approximate five-month peak heating season of November through March, and temperature differences from period-to-period may have a significant effect on NGL demand and thus our financial performance.

The following is a discussion of items impacting supply and logistics segment profit and segment profit per barrel for the periods indicated.

Operating Revenues and Volumes. Revenues, net of purchases and related costs and excluding gains and losses from derivative activities as summarized below, increased for the three and nine months ended September 30, 2012 compared to the three and nine months ended September 30, 2011, and were favorably impacted by:

· higher volumes due to continued increases in production related to the active development of crude oil and liquids-rich resource plays, which was primarily a result of increased drilling activities in the Bakken, Eagle Ford, Permian Basin, Western Oklahoma and Texas Panhandle producing regions, as well as increased NGL volumes related to the BP NGL Acquisition;

· opportunities from more favorable crude oil quality differentials experienced in certain regions; and

· increased margins related to opportunities created in certain producing regions where crude oil production volumes exceed existing pipeline takeaway capacity and where there are associated logistics challenges. We have utilized both railcars and our own trucks to capture enhanced margins in these regions. As the infrastructure in these producing regions continues to be developed, we may not experience the same opportunities for enhanced margins as we are currently experiencing. We believe the fundamentals of our business remain strong; however, a normalization of margins may occur as the logistics challenges are addressed. (See Items 1 and 2 “Business and Properties—Description of Segments and Associated Assets—Supply & Logistics Segment—Impact of Commodity Price Volatility and Dynamic Market Conditions on Our Business Model” included in Part I of our 2011 Annual Report on Form 10-K for further discussion regarding our business model, including diversification and utilization of our asset base among varying demand- and supply-driven markets.)

These favorable impacts to net revenue were fully offset for the three-month comparative periods and were only partially offset for the nine-month comparative periods by the mark-to-market valuation of our derivative activities, net of inventory valuation adjustments, as shown in the table below (in millions):

	Three Months								Nine Months
	Ended September 30,								Ended September 30,
	2012			2011		Variance			2012			2011		Variance
Gains/(losses) from derivative activities (1)	$	(36	)	$	31	$	(67	)	$	(19	)	$	73	$	(92	)

(1) Includes mark-to-market gains and losses resulting from derivative instruments that are related to underlying activities in future periods or the reversal of mark-to-market gains and losses from the prior period. These amounts are reduced by the net impact of inventory valuation adjustments attributable to inventory hedged by the related derivative and gains recognized in later periods on physical sales of inventory that was previously written down. See Note 11 to our condensed consolidated financial statements for a comprehensive discussion regarding our derivatives and risk management activities.

In addition, waterborne cargos decreased over the 2012 period, which is primarily reflective of the increased domestic production as discussed further above.

Field Operating Costs. Field operating costs (excluding equity compensation expense as discussed further below) increased in the three and nine months ended September 30, 2012 compared to the three and nine months ended September 30, 2011 primarily due to an increase in trucking costs, particularly the increased use of third-party contractors, as well as in-house driver and fuel cost. Such increase was associated with the growth in lease gathered volumes in the regions discussed above. The increase in operating costs per barrel was more than offset by higher margins per barrel due to the market fundamentals described above.

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General and Administrative Expenses. General and administrative expenses (excluding equity compensation as discussed below) increased during the three and nine months ended September 30, 2012 compared to the three and nine months ended September 30, 2011 as a result of the overall growth of the segment, certain one-time costs in connection with our acquisition activities and legal fees associated with certain outstanding issues.

Other Income and Expenses

Depreciation and Amortization

Depreciation and amortization expense was $210 million and $356 million for the three and nine months ended September 30, 2012, respectively, compared to $65 million and $191 million for the three and nine months ended September 30, 2011. Included in depreciation and amortization expense for the 2012 periods are losses on impairments of long-lived assets of approximately $125 million primarily related to our Pier 400 terminal project. During the third quarter of 2012, we decided not to proceed with the development of this project. See Note 15 to our condensed consolidated financial statements for further discussion of asset impairments.

The remaining increase in each comparative period was primarily the result of an increased amount of assets resulting from acquisition activities, including accelerated amortization of certain intangible assets associated with those acquisitions, as well as various internal growth projects in both years. The comparative period increases were partially offset by a decrease in expense resulting from extensions of depreciable lives of several of our crude oil and other storage facilities and pipeline systems. Expense in each year was also impacted by a net gain in the nine months ended September 30, 2012 of approximately $5 million recognized upon disposition of certain assets as compared to a net loss in the nine months ended September 30, 2011 of approximately $6 million for asset dispositions.

Interest Expense

Interest expense increased by approximately $12 million and $24 million for the three and nine months ended September 30, 2012, respectively, compared to the three and nine months ended September 30, 2011. These increases were primarily related to the collective issuances of approximately $1.25 billion of senior notes in March 2012, which were used to fund the BP NGL Acquisition.

Other Income/(Expense), Net

During the three and nine months ended September 30, 2012, we recognized net gains of approximately $4 million and $6 million, respectively, in other income/(expense), net compared to net losses of $5 million and $24 million for the three and nine months ended September 30, 2011. The nine-month period ended September 30, 2011 was primarily impacted by a $23 million loss related to the early redemption of our $200 million, 7.75% senior notes for which a similar loss was not experienced during the 2012 periods. Additionally, the periods presented were also impacted by foreign currency gains and losses related to revaluations of CAD-denominated interest receivables associated with our intercompany notes.

Income Tax Expense

Current income tax expense for the three and nine months ended September 30, 2012 compared to the three and nine months ended September 30, 2011 increased as a result of the BP NGL Acquisition which increased the proportion of earnings subject to Canadian federal and provincial taxes and also increased Canadian withholding taxes, which are due as payments occur, on interest and dividends from our Canadian entities to other affiliates. Deferred income tax expense for the three and nine months ended September 30, 2012 compared to the three and nine months ended September 30, 2011 also increased as a result of the BP NGL Acquisition.

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Liquidity and Capital Resources

General

Our primary sources of liquidity are (i) our cash flow from operations as further discussed below in the section entitled “—Cash Flow from Operations” and (ii) borrowings under our credit facilities. Our primary cash requirements include, but are not limited to (i) ordinary course of business uses, such as the payment of amounts related to the purchase of crude oil and other products and other expenses and interest payments on our outstanding debt, (ii) maintenance and expansion activities, (iii) acquisitions of assets or businesses, (iv) repayment of principal on our long-term debt and (v) distributions to our unitholders and general partner. We generally expect to fund our short-term cash requirements through our primary sources of liquidity. In addition, we generally expect to fund our long-term needs, such as those resulting from expansion activities or acquisitions, through a variety of sources (either separately or in combination), which may include operating cash flows, borrowings under our credit facilities, and/or the issuance of additional equity or debt securities. As of September 30, 2012, we had a working capital deficit of approximately $73 million and approximately $2.434 billion of liquidity available to meet our other ongoing operational, investing and finance needs as noted below (in millions):

	As of
	September 30, 2012
Availability under PAA senior unsecured revolving credit facility	$	1,532
Availability under PAA senior secured hedged inventory facility	697
Availability under PNG senior unsecured revolving credit facility	173
Cash and cash equivalents	32
Total	$	2,434

We believe that we have and will continue to have the ability to access our credit facilities, which we use to meet our short-term cash needs. We believe that our financial position remains strong and we have sufficient liquidity; however, extended disruptions in the financial markets and/or energy price volatility that adversely affect our business may have a materially adverse effect on our financial condition, results of operations or cash flows. Also, see “Risk Factors” in Item 1A of our 2011 Annual Report on Form 10-K for further discussion regarding such risks that may impact our liquidity and capital resources. Usage of the credit facilities is subject to ongoing compliance with covenants. We are currently in compliance with all covenants.

During 2010, the U.S. Congress enacted the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”). Although the Dodd-Frank Act includes provisions regarding the use of financial instruments, and the scope and applicability of these provisions as implemented may continue to develop, our current assessment is that the direct effects of the Dodd-Frank Act on PAA will be limited to additional documentation and record-keeping requirements. We cannot, however, predict the effect the Dodd-Frank Act may have on the futures and capital markets, which may affect the depth and quality of our counterparties and lenders and, as a result, our liquidity and access to capital.

Cash Flow from Operations

For a comprehensive discussion of the primary drivers of our cash flow from operations, including the impact of varying market conditions and the timing of settlement of our derivative activities, see “Liquidity and Capital Resources—Cash Flow from Operations” under Item 7 of our 2011 Annual Report on Form 10-K.

Cash provided by operating activities reflects cash generated by our recurring operations, and can also be significantly impacted in periods when we are increasing or decreasing the amount of inventory in storage. Net cash provided by operating activities for the first nine months of 2012 was approximately $880 million, resulting primarily from earnings from our operations. The cash flows from earnings were partially offset by an increase in our crude oil and NGL inventory levels.

Net cash provided by operating activities for the first nine months of 2011 was approximately $1.752 billion, also resulting primarily from earnings from our recurring operations. Additionally, cash flow was positively impacted by the liquidation of (i) crude oil inventory that had been stored in a contango market and (ii) inventory stored through our waterborne cargo purchase activity. These were partially offset by increases in volumes and prices of our NGL inventory in preparation of end users’ increased demand for product used for heating during the winter months.

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Equity and Debt Financing Activities

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

Registration Statements

We periodically access the capital markets for both equity and debt financing. We have filed with the SEC a universal shelf registration statement that, subject to effectiveness at the time of use, allows us to issue up to an aggregate of $2.0 billion of debt or equity securities (“Traditional Shelf”). All issuances of equity securities associated with our continuous offering program, as discussed further below, have been issued pursuant to the Traditional Shelf. At September 30, 2012, we had approximately $1.63 billion of unsold securities available under the Traditional Shelf.

We also have access to a universal shelf registration statement (“WKSI Shelf”), which provides us with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and our capital needs. The March 2012 offerings of our $750 million, 3.65% senior notes due 2022 and our $500 million, 5.15% senior notes due 2042, as well as the March 2012 equity offering, as discussed further below, were all conducted under the WKSI Shelf.

PNG has filed with the SEC a universal shelf registration statement that, subject to effectiveness at the time of use, allows PNG to issue up to an aggregate of $1.0 billion of debt or equity securities. PNG has not issued any securities under its shelf registration statement.

Equity and Debt Offerings

Other Equity Offerings. In March 2012, we completed the sale and issuance of 11.5 million common units at $40.015 per unit, as adjusted for the two-for-one unit split, for net proceeds of approximately $455 million. The net proceeds include our general partner’s proportionate capital contribution and are reflected net of costs associated with the offering. We used the net proceeds to fund a portion of the BP NGL Acquisition, to temporarily reduce outstanding borrowings under our credit facilities and for general partnership purposes. Amounts repaid under our credit facilities may be reborrowed to fund our ongoing capital program, potential future acquisitions or for general partnership purposes.

Senior Notes. In March 2012, we completed the sale and issuance of $750 million, 3.65% senior notes due 2022 and $500 million, 5.15% senior notes due 2042. The senior notes were sold at 99.823% and 99.755% of face value, respectively. Interest payments are due on June 1 and December 1 each year beginning on December 1, 2012. We used the net proceeds from these offerings to fund a portion of the consideration for the BP NGL Acquisition and for general partnership purposes.

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Credit Agreements

General. During the nine months ended September 30, 2012, we had net borrowings on our credit agreements, which include our revolving credit facilities, our GO Bond term loans and our hedged inventory facility, in the aggregate of approximately $699 million.

During the nine months ended September 30, 2011, we had net repayments on our credit agreements in the aggregate of approximately $1.2 billion. The net repayments resulted primarily from cash flows from operating activities, such as sales of crude oil and NGL inventory that was liquidated during the period, as well as our debt and equity activities.

PAA senior secured hedged inventory facility. In June 2012, we amended our senior secured hedged inventory facility which, among other things, increased the committed borrowing capacity from $850 million to $1.4 billion, of which $400 million (an increase from $250 million under the original facility) is available for the issuance of letters of credit. Subject to obtaining additional or increased lender commitments, the committed amount of the facility may be increased to $1.9 billion. The amendment also extended the maturity date of the facility by one year to August 2014 and provides for one or more one-year extensions, subject to applicable approval.

PAA senior unsecured 364-day revolving credit agreement. In March 2012, we elected to terminate an unactivated 364-day credit facility agreement that had a borrowing capacity of $1.2 billion.

Acquisitions and Capital Expenditures and Distributions Paid to Our Unitholders, General Partner and Noncontrolling Interests

In addition to operating needs discussed above, we also use cash for our acquisition activities, internal growth projects and distributions paid to our unitholders, general partner and noncontrolling interests. We have made and will continue to make capital expenditures for acquisitions, expansion capital and maintenance capital. Historically, we have financed these expenditures primarily with cash generated by operations and the financing activities discussed above. See “Internal Growth Projects” above and “Acquisitions and Internal Growth Projects” under Item 7 of our 2011 Annual Report on Form 10-K for further discussion of such capital expenditures.

Acquisitions. The price of acquisitions includes cash paid, assumed liabilities and net working capital items. Because of the non-cash items included in the total price of the acquisitions and the timing of certain cash payments, the net cash paid may differ significantly from the total price of the acquisitions completed during the year.

Distributions to our unitholders and general partner. We distribute 100% of our available cash within 45 days after the end of each quarter to unitholders of record and to our general partner. Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter less reserves established in the discretion of our general partner for future requirements. On November 14, 2012, we will pay a quarterly distribution at an annualized rate of $2.17 per limited partner unit. This distribution represents a year-over-year distribution increase of approximately 9.0%. See Note 9 to our condensed consolidated financial statements for details of distributions paid. Also, see Item 5. “Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities—Cash Distribution Policy” included in our 2011 Annual Report on Form 10-K for additional discussion on distributions.

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Distributions to noncontrolling interests. We paid approximately $36 million and $28 million for distributions to our noncontrolling interests during the nine months ended September 30, 2012 and 2011, respectively. These amounts represent distributions paid on interests in PNG and SLC that are not owned by us.

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

Contingencies

For a discussion of contingencies that may impact us, see Note 12 to our condensed consolidated financial statements.

Commitments

Contractual Obligations. In the ordinary course of doing business, we purchase crude oil and NGL from third parties under contracts, the majority of which range in term from thirty-day evergreen to five years. We establish a margin for these purchases by entering into various types of physical and financial sale and exchange transactions through which we seek to maintain a position that is substantially balanced between purchases on the one hand and sales and future delivery obligations on the other. In addition, we enter into similar contractual obligations in conjunction with our natural gas operations. The table below includes purchase obligations related to these activities. Where applicable, the amounts presented represent the net obligations associated with buy/sell contracts and those subject to a net settlement arrangement with the counterparty. We do not expect to use a significant amount of internal capital to meet these obligations, as the obligations will be funded by corresponding sales to entities that we deem creditworthy or who have provided credit support we consider adequate.

The following table includes our best estimate of the amount and timing of these payments as well as others due under the specified contractual obligations as of September 30, 2012 (in millions):

											2017 and
	2012		2013		2014		2015		2016		Thereafter		Total
Long-term debt and related interest payments (1)	$	80	$	568	$	305	$	847	$	745	$	6,813	$	9,358
Leases (2)	25		77		79		71		61		386		699
Other obligations (3)	92		114		73		61		44		133		517
Subtotal	197		759		457		979		850		7,332		10,574
Crude oil, natural gas, NGL and other purchases (4)	3,889		3,169		1,651		1,143		1,094		2,402		13,348
Total	$	4,086	$	3,928	$	2,108	$	2,122	$	1,944	$	9,734	$	23,922

(1) Includes debt service payments, interest payments due on our senior notes, interest payments and the commitment fee on the PNG credit agreement and the commitment fee on our PAA credit facilities. Although there is an outstanding balance on our PAA credit facilities at September 30, 2012, we historically repay and borrow at varying amounts. As such, we have included only the maximum commitment fee (as if no amounts were outstanding on the facility) in the amounts above.

(2) Leases are primarily for (i) surface rentals, (ii) office rent, (iii) pipeline assets and (iv) trucks, trailers and railcars used in our gathering activities.

(3) Includes (i) other long-term liabilities, (ii) storage and transportation agreements and (iii) commitments related to our capital expansion projects. Excludes a non-current liability of approximately $49 million related to derivative activity included in Crude oil, natural gas, NGL and other purchases.

(4) Amounts are primarily based on estimated volumes and market prices based on average activity during September 2012. The actual physical volume purchased and actual settlement prices will vary from the assumptions used in the table. Uncertainties involved in these estimates include levels of production at the wellhead, weather conditions, changes in market prices and other conditions beyond our control.

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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. 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 September 30, 2012 and December 31, 2011, we had outstanding letters of credit of approximately $21 million and $33 million, respectively.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements as defined by Item 303 of Regulation S-K.

Recent Accounting Pronouncements

See Note 2 to our condensed consolidated financial statements.

Critical Accounting Policies and Estimates

For additional discussion regarding our critical accounting policies and estimates, see “Critical Accounting Policies and Estimates” under Item 7 of our 2011 Annual Report on Form 10-K.

Forward-Looking Statements

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

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

· failure to implement or capitalize, or delays in implementing or capitalizing, on planned internal growth projects;

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

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

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

· the effectiveness of our risk management activities;

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

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

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

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

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

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

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

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

· the effects of competition;

· interruptions in service on third-party pipelines;

· increased costs or lack of availability of insurance;

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

· the currency exchange rate of the Canadian dollar;

· weather interference with business operations or project construction;

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

· factors affecting demand for natural gas and natural gas storage services and rates;

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

· other factors and uncertainties inherent in the transportation, storage, terminalling and marketing of crude oil and refined products, as well as in the storage of natural gas and the processing, transportation, fractionation, storage and marketing of natural gas liquids.

Other factors described herein, as well as factors that are unknown or unpredictable, could also have a material adverse effect on future results. Please read “Risk Factors” discussed in Item 1A of our 2011 Annual Report on Form 10-K. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to various market risks, including (i) commodity risk, (ii) interest rate risk and (iii) currency exchange risk. We use various derivative instruments to manage such risks and, in certain circumstances, to realize incremental margin during volatile market conditions. Our risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring our exchange-cleared and over-the-counter positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity. We have a risk management function that has direct responsibility and authority for our risk policies, related controls around commercial activities and certain aspects of corporate risk management. Our risk management function also approves all new risk management strategies through a formal process. The following discussion addresses each category of risk.

Commodity Price Risk

We use derivative instruments to hedge commodity price risk associated with the following commodities:

· Crude oil and refined products

We utilize crude oil and refined products derivatives to hedge commodity price risk inherent in our Supply and Logistics and Transportation segments. Our objectives for these derivatives include hedging anticipated purchases and sales, stored inventory, and storage capacity utilization. We manage these exposures with various instruments including exchange traded and over-the-counter futures, forwards, swaps and options.

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· Natural gas

We utilize natural gas derivatives to hedge commodity price risk inherent in our Supply and Logistics and Facilities segments. Our objectives for these derivatives include hedging anticipated purchases and sales, stored inventory and to manage our anticipated base gas requirements. We manage these exposures with various instruments including exchange-traded futures, swaps and options.

· NGL

We utilize NGL derivatives, primarily butane and propane derivatives, to hedge commodity price risk inherent in our Supply and Logistics segment. Our objectives for these derivatives include hedging anticipated purchases and sales and stored inventory. We manage these exposures with various instruments including exchange-traded and over-the-counter futures, forwards, swaps and options.

See Note 11 to our condensed consolidated financial statements for further discussion regarding our hedging strategies and objectives.

Our policy is to (i) purchase only product for which we have a market, (ii) hedge our purchase and sales contracts so that price fluctuations do not materially affect our operating income and (iii) not acquire and hold physical inventory or other derivative instruments for the purpose of speculating on outright commodity price changes, as these activities could expose us to significant losses.

The fair value of our commodity derivatives and the change in fair value as of September 30, 2012 that would be expected from a 10% price increase or decrease is shown in the table below (in millions):

			Effect of 10%			Effect of 10%
	Fair Value		Price Increase			Price Decrease
Crude oil and related products	$	19	$	(32	)	$	33
Natural gas	19		$	1		$	(1	)
NGL	47		$	(41	)	$	41
Total fair value	$	85

The fair values presented in the table above reflect the sensitivity of the derivative instruments only and do not include the effect of the underlying hedged commodity. Price-risk sensitivities were calculated by assuming an across-the-board 10% increase or decrease in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of an actual 10% change in near-term commodity prices, the fair value of our derivative portfolio would typically change less than that shown in the table as changes in near-term prices are not typically mirrored in delivery months further out.

Interest Rate Risk

We use both fixed and variable rate debt, and are exposed to interest rate risk. Therefore, from time to time we use interest rate derivatives to hedge interest rate risk associated with anticipated debt issuances and, in certain cases, outstanding debt instruments. All of our senior notes are fixed rate notes and thus not subject to interest rate risk. The majority of our variable rate debt at September 30, 2012, approximately $1.027 billion (which excludes $100 million that swap floating rate debt for fixed), is subject to interest rate re-sets, which range from one week to three months. The average interest rate of approximately 1.8% is based upon rates in effect during the nine months ended September 30, 2012. The fair value of our interest rate derivatives is an unrealized loss of approximately $133 million as of September 30, 2012. A 10% increase in the forward LIBOR curve as of September 30, 2012 would result in an increase of approximately $38 million to the fair value of our interest rate derivatives. A 10% decrease in the forward LIBOR curve as of September 30, 2012 would result in a decrease of approximately $38 million to the fair value of our interest rate derivatives. See Note 11 to our condensed consolidated financial statements for a discussion of our interest rate risk hedging activities.

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Item 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

We maintain written disclosure controls and procedures, which we refer to as our “DCP.” Our DCP is designed to ensure that information required to be disclosed by us in reports that we file under the Securities Exchange Act of 1934 (the “Exchange Act”) is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow for timely decisions regarding required disclosure.

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

Changes in Internal Control over Financial Reporting

In addition to the information concerning our DCP, we are required to disclose certain changes in our internal control over financial reporting. On April 1, 2012 we completed the BP NGL Acquisition (see Note 4 to our condensed consolidated financial statements) and are in the process of integrating the entity’s controls and procedures with ours and incorporating them into our evaluation of internal controls over financial reporting. Although we have made various enhancements to our controls, there have been no changes in our internal control over financial reporting during the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Certifications

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

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PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

The information required by this item is included under the caption “Litigation” in Note 12 to our condensed consolidated financial statements, and is incorporated herein by reference thereto.

Item 1A. RISK FACTORS

For a discussion regarding our risk factors, see Item 1A of our 2011 Annual Report on Form 10-K. Those risks and uncertainties are not the only ones facing us and there may be additional matters of which we are unaware or that we currently consider immaterial. All of those risks and uncertainties could adversely affect our business, financial condition and/or results of operations.

Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

Item 3. DEFAULTS UPON SENIOR SECURITIES

None.

Item 4. MINE SAFETY DISCLOSURES

None.

Item 5. OTHER INFORMATION

None.

Item 6. EXHIBITS

The exhibits listed on the accompanying Exhibit Index are filed or incorporated by reference as part of this report, and such Exhibit Index is incorporated herein by reference.

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SIGNATURES

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

	PLAINS ALL AMERICAN PIPELINE, L.P.

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

Date: November 7, 2012

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

Date: November 7, 2012

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

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EXHIBIT INDEX

3.1	—	Fourth Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. dated as of May 17, 2012 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed May 23, 2012).
3.2	—	Amendment No. 1 dated October 1, 2012 to the Fourth Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed October 2, 2012).

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

3.4	—	Amendment No. 1 dated December 31, 2010 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. (incorporated by reference to Exhibit 3.9 to the Annual Report on Form 10-K for the year ended December 31, 2010).

3.5	—	Amendment No. 2 dated January 1, 2011 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. (incorporated by reference to Exhibit 3.10 to the Annual Report on Form 10-K for the year ended December 31, 2010).

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

3.7	—	Fifth Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC dated December 23, 2010 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed December 30, 2010).

3.8	—	Sixth Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. dated December 23, 2010 (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K filed December 30, 2010).

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

4.13	—	Eighteenth Supplemental Indenture (3.95% Senior Notes due 2015) dated July 14, 2010 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed July 13, 2010).

4.14	—	Nineteenth Supplemental Indenture (5.00% Senior Notes due 2021) dated January 14, 2011 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed January 11, 2011).

4.15	—	Twentieth Supplemental Indenture (3.65% Senior Notes due 2022) dated March 22, 2012 among Plains All American Pipeline, L.P., PAA Finance Corp and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed March 26, 2012).

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4.16	—	Twenty-First Supplemental Indenture (5.15% Senior Notes due 2042) dated March 22, 2012 among Plains All American Pipeline, L.P., PAA Finance Corp and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K filed March 26, 2012).

12.1 †	—	Computation of Ratio of Earnings to Fixed Charges

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

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

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

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

101.INS†	—	XBRL Instance Document

101.SCH†	—	XBRL Taxonomy Extension Schema Document

101.CAL†	—	XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF†	—	XBRL Taxonomy Extension Definition Linkbase Document

101.LAB†	—	XBRL Taxonomy Extension Label Linkbase Document

101.PRE†	—	XBRL Taxonomy Extension Presentation Linkbase Document

† Filed herewith