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Document and Entity Information - USD ($) $ in Billions	12 Months Ended
Document and Entity Information - USD ($) $ in Billions	Dec. 31, 2013	Mar. 06, 2014
Document and Entity Information
Entity Registrant Name	PLAINS GP HOLDINGS LP
Entity Central Index Key	0001581990
Document Type	10-K
Document Period End Date	Dec. 31, 2013
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float	$ 3.6
Entity Common Stock, Shares Outstanding		135,833,637
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
CURRENT ASSETS
Cash and cash equivalents	$ 43	$ 25
Trade accounts receivable and other receivables, net	3,637	3,564
Inventory	1,065	1,209
Other current assets	220	351
Total current assets	4,965	5,149
PROPERTY AND EQUIPMENT	12,514	11,183
Accumulated depreciation	(1,673)	(1,519)
Property and equipment, net	10,841	9,664
OTHER ASSETS
Goodwill	2,503	2,535
Linefill and base gas	798	707
Long-term inventory	251	274
Investments in unconsolidated entities	485	343
Other, net	1,610	587
Total assets	21,453	19,259
CURRENT LIABILITIES
Accounts payable and accrued liabilities	3,985	3,824
Short-term debt	1,113	1,086
Other current liabilities	315	275
Total current liabilities	5,413	5,185
LONG-TERM LIABILITIES
Senior notes, net of unamortized discount of $15 and $15, respectively	6,710	6,010
Long-term debt under credit facilities and other	520	510
Other long-term liabilities and deferred credits	531	586
Total long-term liabilities	7,761	7,106
COMMITMENTS AND CONTINGENCIES (NOTE 16)
PARTNERS' CAPITAL
Noncontrolling interests	7,244
Total partners' capital	8,279
MEMBERS' EQUITY
Noncontrolling interests		6,968
Total members' equity		6,968
Total liabilities and partners' capital / members' equity	21,453	$ 19,259
Class A Shares
PARTNERS' CAPITAL
Partners' Capital	1,035
Class B Shares
PARTNERS' CAPITAL
Partners' Capital

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
CONSOLIDATED BALANCE SHEETS
Senior notes, unamortized discount (in dollars)	$ 15	$ 15
Class A Shares
Shares outstanding
Shares outstanding	133,833,637
Class B Shares
Shares outstanding
Shares outstanding	472,196,136

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)
shares in Millions, $ in Millions

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

REVENUES

Supply and Logistics segment revenues

$ 40,692

$ 36,438

$ 33,065

Transportation segment revenues

701

623

572

Facilities segment revenues

856

736

638

Total revenues

42,249

37,797

34,275

COSTS AND EXPENSES

Purchases and related costs

38,465

34,368

31,564

Field operating costs

1,322

1,180

870

General and administrative expenses

360

342

294

Depreciation and amortization

378

483

250

Total costs and expenses

40,525

36,373

32,978

OPERATING INCOME

1,724

1,424

1,297

OTHER INCOME/(EXPENSE)

Equity earnings in unconsolidated entities

Interest expense (net of capitalized interest of $38, $36 and $25, respectively)

(309)

(295)

(259)

Other income/(expense), net

(19)

INCOME BEFORE TAX

1,480

1,173

1,032

Current income tax expense

(100)

(54)

(38)

Deferred income tax expense

(6)

(1)

(7)

NET INCOME

1,374

1,118

987

Net income attributable to noncontrolling interests

(1,359)

(1,115)

(985)

NET INCOME ATTRIBUTABLE TO PAGP

$ 15

$ 3

$ 2

BASIC AND DILUTED NET INCOME PER CLASS A SHARE

Basic and diluted weighted average Class A shares outstanding (in shares)

^[1]

132

Basic and diluted net income per Class A share (in dollars per share)

^[1]

$ 0.10

[1]

Basic and diluted net income per Class A share are calculated based on net income attributable to PAGP for the period following the closing of our initial public offering on October 21, 2013 and basic weighted average number of Class A shares outstanding weighted for the same period. See Note 4, "Net Income Per Class A Share".

CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CONSOLIDATED STATEMENTS OF OPERATIONS
Interest expense, capitalized interest	$ 38	$ 36	$ 25

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net income	$ 1,374	$ 1,118	$ 987
Other comprehensive income/(loss)	(176)	29	(61)
Comprehensive income	1,198	1,147	926
Comprehensive income attributable to noncontrolling interests	(1,183)	(1,144)	(924)
Comprehensive income attributable to PAGP	$ 15	$ 3	$ 2

CONSOLIDATED STATEMENTS OF CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Increase (Decrease) in Accumulated Other Comprehensive Income
Balance at beginning of period	$ 79	$ 50	$ 111
Reclassification adjustments	(66)	(58)	135
Deferred gain (loss) on cash flow hedges, net of tax	110	43	(155)
Currency translation adjustments	(220)	44	(42)
Proportionate share of our unconsolidated entities' other comprehensive income			1
Total period activity	(176)	29	(61)
Balance at end of period	(97)	79	50
Derivative Instruments
Increase (Decrease) in Accumulated Other Comprehensive Income
Balance at beginning of period	(121)	(106)	(86)
Reclassification adjustments	(66)	(58)	135
Deferred gain (loss) on cash flow hedges, net of tax	110	43	(155)
Total period activity	44	(15)	(20)
Balance at end of period	(77)	(121)	(106)
Translation Adjustments
Increase (Decrease) in Accumulated Other Comprehensive Income
Balance at beginning of period	200	156	198
Currency translation adjustments	(220)	44	(42)
Total period activity	(220)	44	(42)
Balance at end of period	$ (20)	$ 200	156
Other
Increase (Decrease) in Accumulated Other Comprehensive Income
Balance at beginning of period			(1)
Proportionate share of our unconsolidated entities' other comprehensive income			1
Total period activity			$ 1

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 1,374	$ 1,118	$ 987
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	378	483	250
Inventory valuation adjustments	7	128	4
Equity-indexed compensation expense	116	101	110
Gain on sales of linefill and base gas	(7)	(19)	(21)
Settlement of terminated interest rate and foreign currency hedging instruments	8	(112)	12
Other	(1)	(1)	15
Changes in assets and liabilities, net of acquisitions:
Trade accounts receivable and other	(185)	218	83
Inventory	134	(180)	518
Accounts payable and other current liabilities	124	(504)	399
Net cash provided by operating activities	1,948	1,232	2,357
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions, net of cash acquired (Note 3)	(28)	(2,156)	(1,390)
Change in restricted cash			20
Additions to property, equipment and other	(1,613)	(1,204)	(635)
Cash received for sales of linefill and base gas	40	65	56
Cash paid for purchases of linefill and base gas	(122)	(109)	(78)
Investment in unconsolidated entities	(133)	(76)
Proceeds from sales of assets	200	22	12
Cash received upon formation of equity-method investment		59
Other investing activities	3	7	(5)
Net cash used in investing activities	(1,653)	(3,392)	(2,020)
CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings/(repayments) under PAA senior secured hedged inventory facility (Note 9)	(660)	591	(425)
Net borrowings/(repayments) under PAA senior unsecured revolving credit facility (Note 9)	(92)	59	(793)
Net borrowings/(repayments) under PNG credit agreement (Note 9)	(382)	61	62
Net borrowings/(repayments) under AAP revolving credit facility (Note 9)	15	(7)	3
Proceeds from AAP term loan (Note 9)	300
Net borrowings under PAA commercial paper program (Note 9)	1,110
Proceeds from the issuance of PAA senior notes	699	1,996	597
Repayments of PAA senior notes	(250)	(500)	(200)
Net proceeds from the issuance of PAA common units	465	959	870
Contributions from noncontrolling interests related to PAA common unit issuances	10	28	17
Net proceeds from the issuance of PNG common units	40		370
Proceeds received from initial public offering (Note 10)	2,825
Distribution of proceeds received from initial public offering (Note 10)	(2,825)
Distributions paid to noncontrolling interests (Note 10)	(1,494)	(1,005)	(822)
Distributions paid to members (Note 10)	(6)	(3)	(2)
Other financing activities	(29)	(20)	(14)
Net cash provided by/(used in) financing activities	(274)	2,159	(337)
Effect of translation adjustment on cash	(3)	(1)	(10)
Net increase/(decrease) in cash and cash equivalents	18	(2)	(10)
Cash and cash equivalents, beginning of period	25	27	37
Cash and cash equivalents, end of period	43	25	27
Cash paid for:
Interest, net of amounts capitalized	312	302	261
Income taxes, net of amounts refunded	$ 37	$ 72	$ 11

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL / MEMBERS' EQUITY - USD ($) $ in Millions	Total	Partners' Capital (Excluding Noncontrolling Interests) Class A Shares	Noncontrolling Interests	Members' Equity (Excluding Noncontrolling Interests)
Balance at Dec. 31, 2010	$ 4,391		$ 4,391
Increase (Decrease) in Partners' Capital and Members' Equity
Net income	987		985	$ 2
Distributions	(824)		(822)
Distributions				(2)
Issuance of PAA common units	870		870
Issuance of PAA common units under LTIP	15		15
Contributions from noncontrolling interests related to PAA common unit issuances	19		19
Issuance of PNG common units	370		370
Equity-indexed compensation expense	28		28
Other comprehensive income/(loss)	(61)		(61)
Other	(1)		(1)
Balance at Dec. 31, 2011	5,794		5,794
Increase (Decrease) in Partners' Capital and Members' Equity
Net income	1,118		1,115	3
Distributions	(1,008)		(1,005)
Distributions				(3)
Issuance of PAA common units	959		959
Issuance of PAA common units under LTIP	33		33
Contributions from noncontrolling interests related to PAA common unit issuances	21		21
Equity-indexed compensation expense	28		28
Distribution equivalent right payments	(5)		(5)
Other comprehensive income/(loss)	29		29
Other	(1)		(1)
Balance at Dec. 31, 2012	6,968		6,968
Increase (Decrease) in Partners' Capital and Members' Equity
Net income	1,374	$ 12	1,359	3
Distributions	(1,500)		(1,494)
Distributions				(6)
Transfer of ownership interest		(52)	49	$ 3
Issuance of Class A shares to the public, net of offering and other costs	2,825	2,825
Distribution of net proceeds of initial public offering	(2,825)	(2,825)
Deferred tax asset	1,076	1,076
Issuance of PAA common units	468		468
Issuance of PAA common units under LTIP	4		4
Contributions from noncontrolling interests related to PAA common unit issuances	9		9
Units tendered by employees to satisfy tax withholding obligations	(15)		(15)
Issuance of PNG common units	40		40
Equity-indexed compensation expense	39		39
Distribution equivalent right payments	(6)		(6)
Other comprehensive income/(loss)	(176)		(176)
Other	(2)	(1)	(1)
Balance at Dec. 31, 2013	$ 8,279	$ 1,035	$ 7,244

Organization and Basis of Presentation

12 Months Ended

Dec. 31, 2013

Organization and Basis of Presentation

Organization and Basis of Presentation

Note 1—Organization and Basis of Presentation

Organization

Plains GP Holdings, L.P. (“PAGP”) is a Delaware limited partnership formed on July 17, 2013 to own an interest in the general partner and incentive distribution rights (“IDRs”) of Plains All American Pipeline, L.P (“PAA”), a publicly traded Delaware limited partnership. PAGP has elected to be treated as a corporation for U.S. federal income tax purposes.

We completed our initial public offering (“IPO”) on October 21, 2013. Immediately prior to our IPO, certain owners of Plains AAP, L.P. (“AAP”) sold a portion of their interests in AAP to us, resulting in our ownership of AAP units, which represent limited partnership interests in AAP. As of December 31, 2013, we owned 133,833,637 AAP units (representing a 22.1% limited partner interest in AAP), and the remaining AAP units continue to be held by the owners of AAP immediately prior to our IPO (the “Legacy Owners”). AAP is a Delaware limited partnership that directly owns all of PAA’s incentive distribution rights and indirectly owns the 2% general partner interest in PAA. AAP is the sole member of PAA GP LLC (“PAA GP”), a Delaware limited liability company that directly holds the 2% general partner interest in PAA. Also, through a series of transactions prior to our IPO with our general partner and the owners of Plains All American GP LLC (“GP LLC”), a Delaware limited liability company formed on May 2, 2001, GP LLC’s general partner interest in AAP became a non-economic interest, and we became the owner of a 100% managing member interest in GP LLC. See “Basis of Consolidation and Presentation” below for the resulting accounting impacts.

GP LLC manages the business and affairs of PAA and AAP. Except for certain matters relating to PAA that require the approval of the limited partners of PAA, and certain matters relating to AAP that require the approval of the limited partners of AAP or of us as the sole member of GP LLC, either pursuant to the governing documents of PAA, AAP or GP LLC, or as may be required by non-waivable provisions of applicable law, GP LLC has full and complete authority, power and discretion to manage and control the business, affairs and property of PAA and AAP, to make all decisions regarding those matters and to perform any and all other acts or activities customary or incident to the management of PAA and AAP’s business, including the execution of contracts and management of litigation. GP LLC employs all domestic officers and personnel involved in the operation and management of PAA and AAP. PAA’s Canadian officers and personnel are employed by Plains Midstream Canada ULC.

PAA is a publicly traded master limited partnership that owns and operates midstream energy infrastructure and provides logistics services for crude oil, natural gas liquids (“NGL”), natural gas and refined products. The term NGL includes ethane and natural gasoline products as well as products commonly referred to as liquefied petroleum gas (“LPG”) such as propane and butane. When used in this Form 10-K, NGL refers to all NGL products including LPG. PAA owns an extensive network of pipeline transportation, terminalling, storage, and gathering assets in key crude oil and NGL producing basins and transportation corridors and at major market hubs in the United States and Canada. Our business activities are conducted through three operating segments: (i) Transportation, (ii) Facilities and (iii) Supply and Logistics. See Note 18 for further discussion of our operating segments.

As used in this Form 10-K and unless the context indicates otherwise, the terms “PAGP,” “Partnership,” “Plains,” “we,” “us,” “our,” “ours” and similar terms refer to PAGP, GP LLC, AAP, PAA GP and PAA and its consolidated subsidiaries.

Definitions

Additional defined terms are used in the following notes and shall have the meanings indicated below:

AOCI	=	Accumulated other comprehensive income
Bcf	=	Billion cubic feet
Btu	=	British thermal unit
CAD	=	Canadian dollar
CERCLA	=	Federal Comprehensive Environmental Response, Compensation and Liability Act, as amended
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	=	Intercontinental Exchange
IPO	=	Initial public offering
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
NYMEX	=	New York Mercantile Exchange
NYSE	=	New York Stock Exchange
Pacific	=	Pacific Energy Partners, L.P.
PLA	=	Pipeline loss allowance
PNG	=	PAA Natural Gas Storage, L.P.
PNGS	=	PAA Natural Gas Storage, LLC
Rainbow	=	Rainbow Pipe Line Company, Ltd.
RCRA	=	Federal Resource Conservation and Recovery Act, as amended
SG Resources	=	SG Resources Mississippi, LLC
SLC Pipeline	=	SLC Pipeline LLC
SOP	=	Shell Oil Products
USD	=	United States dollar
Velocity	=	Velocity South Texas Gathering, LLC
White Cliffs	=	White Cliffs Pipeline, LLC
WTI	=	West Texas Intermediate
WTS	=	West Texas Sour

Basis of Consolidation and Presentation

The accompanying financial statements and related notes present and discuss our consolidated financial position as of December 31, 2013 and 2012, and the consolidated results of our operations, cash flows, changes in partners’ capital, comprehensive income and changes in accumulated other comprehensive income for the years ended December 31, 2013, 2012 and 2011. These financials include PAGP and all of our wholly owned subsidiaries and those entities that we control. Under GAAP, we consolidate PAA, AAP and GP LLC. Amounts associated with the interests in these entities not owned by us are reflected in our results of operations as net income attributable to noncontrolling interests and in our balance sheet partners’ capital section as noncontrolling interests.

For periods prior to our IPO, the accompanying consolidated financial statements reflect the financial statements of GP LLC, the predecessor of PAGP, and are based on the historical ownership percentages of GP LLC and AAP. These financial statements, to the extent they relate to periods prior to our IPO, have been prepared from the separate financial records maintained by GP LLC and may not necessarily be indicative of the actual results of operations that might have occurred if PAGP had operated separately during those periods.

All significant intercompany transactions have been eliminated in consolidation. Investments in entities over which we have significant influence but not control are accounted for by the equity method. We evaluate our equity investments for impairment in accordance with FASB guidance with respect to the equity method of accounting for investments in common stock. An impairment of an equity investment results when factors indicate that the investment’s fair value is less than its carrying value and the reduction in value is other than temporary in nature.

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

Completion of PNG Merger

On October 21, 2013, PAA entered into a definitive agreement and plan of merger (the “PNG Merger Agreement”) with PNG that provided for a merger whereby PNG would become PAA’s wholly-owned subsidiary through a unit-for-unit exchange. On December 31, 2013, PNG’s common unitholders approved the PNG Merger Agreement, with PNG surviving the transactions as PAA’s wholly-owned subsidiary (referred to herein as the “PNG Merger”). Since we historically consolidated PNG for financial reporting purposes, the PNG Merger did not change the basis of consolidation of our historical financial statements.

- Definition

The entire disclosure for organization, consolidation and basis of presentation of financial statements disclosure.

+ References

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+ Details

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2013

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Note 2—Summary of Significant Accounting Policies

Use of Estimates

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

Revenue Recognition

Supply and Logistics Segment Revenues. Revenues from sales of crude oil and NGL are recognized at the time title to the product sold transfers to the purchaser, which occurs upon delivery of the product to the purchaser or its designee. Sales of crude oil and NGL consist of outright sales contracts. Inventory purchases and sales under buy/sell transactions are treated as inventory exchanges. The sales under these exchanges are netted to zero in Supply and Logistics segment revenues in our Consolidated Statements of Operations.

Additionally, we may utilize derivatives in connection with the transactions described above. For commodity derivatives that are designated as cash flow hedges, derivative gains and losses are deferred in AOCI and recognized in revenues in the periods during which the underlying physical hedged transaction impacts earnings. Also, the ineffective portion of the change in fair value of cash flow hedges is recognized in revenues each period along with the change in fair value of derivatives that do not qualify for or are not designated for hedge accounting.

Transportation Segment Revenues. Revenues from pipeline tariffs and fees are associated with the transportation of crude oil and NGL at a published tariff, as well as revenues associated with leases and other agreements for committed space on various assets. Tariff revenues are recognized either at the point of delivery or at the point of receipt pursuant to specifications outlined in the regulated and non-regulated tariffs. Revenues associated with lease fees are recognized in the month to which the lease applies. The majority of our pipeline tariff and fee revenues are based on actual volumes and rates. As is common in the industry, our tariffs incorporate a loss allowance factor that is intended to 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. In addition, we have certain agreements that require counterparties to ship a minimum volume over an agreed upon period. Revenue is recognized at the latter of when the volume is shipped (pursuant to specifications outlined in the tariffs) or when the counterparty’s ability to make up the minimum volume has expired.

Facilities Segment Revenues. Our Facilities segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services for crude oil, refined products, NGL and natural gas, NGL fractionation and isomerization services and natural gas and condensate processing services. Revenues generated in this segment include (i) storage fees that are generated when we lease storage capacity, (ii) terminal throughput fees that are generated when we receive crude oil, refined products or NGL from one connecting source and redeliver the applicable product to another connecting carrier, (iii) rail terminal loading and unloading fees, (iv) hub service fees associated with natural gas park and loan activities, interruptible storage services and wheeling and balancing services, (v) revenues from the sale of natural gas, (vi) fees from NGL fractionation and isomerization and (vii) fees from gas processing services. We generate revenue through a combination of month-to-month and multi-year leases and processing arrangements. Storage fees resulting from short-term and long-term contracts are typically recognized in revenue ratably over the term of the contract regardless of the actual storage capacity utilized. Terminal fees (including throughput and rail fees) are recognized as the crude oil, NGL or refined product enters or exits the terminal and is received from or delivered to the connecting carrier or third-party terminal, as applicable. Hub service fees are recognized in the period the natural gas moves across our header system. Fees from NGL fractionation, isomerization services and gas processing services are recognized in the period when the services are performed. Revenues associated with the sale of natural gas are recognized at the time title to the product sold transfers to the purchaser or its designee. In addition, we have certain agreements that require counterparties to throughput a minimum volume over an agreed upon period. Revenue is recognized at the latter of when the volume exits the terminal or when the counterparty’s ability to make up the minimum volume has expired.

Purchases and Related Costs

Purchases and related costs include (i) the cost of crude oil, NGL, natural gas and refined products obtained in outright purchases, (ii) fees incurred for third-party transportation and storage, whether by pipeline, truck, rail, ship or barge, (iii) interest cost attributable to borrowings for inventory stored in a contango market and (iv) performance-related bonus costs. These costs are recognized when incurred except in the case of products purchased, which are recognized at the time title transfers to us. Purchases that are part of exchanges under buy/sell transactions are netted with the related sales, with any margin presented in “Purchases and related costs” in our Consolidated Statements of Operations.

Field Operating Costs and General and Administrative Expenses

Field operating costs consist of various field operating expenses, including fuel and power costs, telecommunications, payroll and benefit costs (including equity-indexed compensation expense) for truck drivers and field personnel, third-party trucking transportation costs for our U.S. crude oil operations, maintenance and integrity management costs, regulatory compliance, environmental remediation, insurance, vehicle leases, and property taxes. General and administrative expenses consist primarily of payroll and benefit costs (including equity-indexed compensation expense), certain information systems and legal costs, office rent, contract and consultant costs and audit and tax fees.

Foreign Currency Transactions

Certain of our subsidiaries use the Canadian dollar as their functional currency. Assets and liabilities of subsidiaries with a Canadian dollar functional currency are translated at period-end rates of exchange, and revenues and expenses are translated at average exchange rates prevailing for each month. The resulting translation adjustments are made directly to a separate component of other comprehensive income, which is reflected in Partners’ Capital on our Consolidated Balance Sheet.

Certain of our subsidiaries also enter into transactions and have monetary assets and liabilities that are denominated in a currency other than the entities’ respective functional currencies. Gains and losses from the revaluation of foreign currency transactions and monetary assets and liabilities are included in the Consolidated Statements of Operations. The revaluation of foreign currency transactions and monetary assets and liabilities resulted in a gain of approximately $1 million for the year ended December 31, 2013 and losses of approximately $2 million for each of the years ended December 31, 2012 and 2011.

Cash and Cash Equivalents

Cash and cash equivalents consist of all unrestricted demand deposits and funds invested in highly liquid instruments with original maturities of three months or less and typically exceed federally insured limits. We periodically assess the financial condition of the institutions where these funds are held and believe that our credit risk is minimal. In accordance with our policy, outstanding checks are classified as accounts payable rather than negative cash. As of December 31, 2013 and 2012, accounts payable included approximately $70 million and $72 million, respectively, of outstanding checks that were reclassified from cash and cash equivalents.

Accounts Receivable

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

To mitigate credit risk 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 December 31, 2013 and 2012, we had received approximately $117 million and $173 million, respectively, of advance cash payments from third parties to mitigate credit risk. Furthermore, at December 31, 2013 and 2012, we had received approximately $426 million and $343 million, respectively, of standby letters of credit to support obligations due from third parties, a portion of which applies to future business. In addition, in an effort to mitigate credit risk, a significant portion of our transactions with counterparties are settled on a net-cash basis. Further, we enter into netting agreements (contractual agreements that allow us to offset receivables and payables with those counterparties against each other on our balance sheet) for a majority of such arrangements.

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 December 31, 2013 and 2012, 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 $5 million and $4 million at December 31, 2013 and 2012, respectively. Although we consider our allowance for doubtful trade accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.

Equity Method of Accounting

Our investments in the following entities are accounted for under the equity method of accounting:

Entity	Type of Operation	Our Ownership Interest
Settoon Towing, LLC	Barge Transportation Services	50	%
Eagle Ford Pipeline LLC	Crude Oil Pipeline	50	%
White Cliffs Pipeline, LLC	Crude Oil Pipeline	36	%
Frontier Pipeline Company	Crude Oil Pipeline	22	%
Butte Pipe Line Company	Crude Oil Pipeline	22	%

We do not consolidate any part of the assets or liabilities of our equity investees. Our share of net income or loss is reflected as one line item on our Consolidated Statements of Operations entitled “Equity earnings in unconsolidated entities” and will increase or decrease, as applicable, the carrying value of our investments in unconsolidated entities on the balance sheet. In addition, as applicable, we include a proportionate share of our equity method investees’ unrealized gains and losses in other comprehensive income on our Consolidated Balance Sheet. We also adjust our investment balances in these investees by the like amount. Distributions we receive reduce the carrying value of our investments and will be reflected in our Consolidated Statements of Cash Flows in operating activities. In turn, contributions will increase the carrying value of our investments and will be reflected in our Consolidated Statements of Cash Flows in investing activities.

During the year ended December 31, 2013, we contributed approximately $133 million to our equity method investees. Such contributions were primarily to Eagle Ford Pipeline LLC and White Cliffs Pipeline LLC for construction and expansion activities.

In August 2012, we formed Eagle Ford Pipeline LLC with Enterprise Products Partners (“Enterprise”) for the purpose of developing a crude oil pipeline system in the Eagle Ford Area of South Texas. In conjunction with the formation, we and Enterprise contributed fixed assets with estimated book values of approximately $134 million and $15 million, respectively. In addition, Enterprise contributed cash of $59 million, which we received from Eagle Ford Pipeline LLC. Subsequent to the formation and through December 31, 2012, we and Enterprise contributed $75 million each to fund continued development of the pipeline system.

We received distributions of approximately $55 million, $40 million and $23 million from our equity method investees during the years ended December 31, 2013, 2012 and 2011, respectively.

Noncontrolling Interests

We account for noncontrolling interests in subsidiaries in accordance with FASB guidance, which requires all entities to report noncontrolling interests in subsidiaries as a component of equity in the consolidated financial statements. Noncontrolling interest represents the portion of assets and liabilities in a consolidated subsidiary that is owned by a third-party. See Note 10 for additional discussion regarding our noncontrolling interests.

Asset Retirement Obligations

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

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

A small portion of our contractual or regulatory obligations is related to assets that are inactive or that we plan to take out of service and, although the ultimate timing and costs to settle these obligations are not known with certainty, we have recorded a reasonable estimate of these obligations. We have estimated that the fair value of these obligations was approximately $34 million and $31 million, respectively, at December 31, 2013 and 2012.

Fair Value Measurements

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. The determination of the fair values 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. See Notes 9 and 11 for further discussion.

Other Significant Accounting Policies

See the respective footnotes for our accounting policies regarding (i) net income per Class A share, (ii) inventory, linefill and base gas and long-term inventory, (iii) property and equipment, (iv) other assets, (v) goodwill, (vi) derivatives and risk management activities, (vii) income taxes, (viii) equity-indexed compensation and (ix) environmental matters.

Recent Accounting Pronouncements

In March 2013, the FASB issued guidance regarding the release of cumulative translation adjustments into net income when a parent either sells a part or all of its investment in a foreign entity or no longer holds a controlling financial interest in a subsidiary or group of assets that is a business within a foreign entity. This guidance becomes effective beginning after December 15, 2013. We adopted this guidance on January 1, 2014. Our adoption is not expected to have a material impact on our financial position, results of operations or cash flows.

In February 2013, the FASB issued guidance requiring an entity to present either in a single note or parenthetically on the face of the financial statements (i) the amount of significant items reclassified from each component of AOCI and (ii) the income statement line items affected by the reclassification. This guidance became effective for interim and annual periods beginning after December 15, 2012. We adopted this guidance during the first quarter of 2013. For the years ended December 31, 2013, 2012 and 2011, all reclassifications out of AOCI were related to derivative instruments. Other than requiring additional disclosure, which is included in Note 11, our adoption did not have an impact on our financial position, results of operations or cash flows.

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 is effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012, with early adoption permitted in certain circumstances. We adopted this guidance on January 1, 2013. Our adoption did not have a material impact on our financial position, results of operations or cash flows.

In December 2011, the FASB issued guidance requiring disclosures of both gross and net information about recognized financial instruments and derivative instruments that are either (i) offset in accordance with the specified sections of GAAP or (ii) subject to an enforceable master netting arrangement or similar agreement. In January 2013, the FASB amended and clarified the scope of these disclosures to include only (i) derivative instruments, (ii) repurchase agreements and reverse repurchase agreements and (iii) securities lending transactions. This guidance is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. We adopted this guidance on January 1, 2013. Other than requiring additional disclosure, which is included in Note 11, our adoption did not have an impact on our financial position, results of operations or cash flows.

Acquisitions and Dispositions

12 Months Ended

Dec. 31, 2013

Acquisitions and Dispositions

Acquisitions and Dispositions

Note 3—Acquisitions and Dispositions

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.

2013 Acquisitions

During the year ended December 31, 2013, we completed an acquisition for aggregate consideration of approximately $19 million. The assets acquired included a trucking business included in our Transportation segment. We recognized goodwill of approximately $6 million related to this acquisition.

2012 Acquisitions

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.

The 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	$	241		N/A
Property and equipment	1,081			5 - 70
Linefill	85			N/A
Long-term inventory	165			N/A
Intangible assets (contract)	130			13
Goodwill	236			N/A
Deferred tax liability	(236		)	N/A
Environmental liability	(14		)	N/A
Other long-term liabilities	(5		)	N/A
Total	$	1,683

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.

Intangible assets above consisted of a contract with a 13 year life. Amortization of this contract under the declining balance method was approximately $31 million and $41 million during the years ended December 31, 2013 and 2012, respectively, and the future amortization through 2017 is estimated as follows:

2014	$	10
2015	$	8
2016	$	7
2017	$	6

The BP NGL Acquisition was pre-funded through various means, including the issuance of PAA common units and senior notes in March 2012 for net proceeds of approximately $1.69 billion. During the year ended December 31, 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 Consolidated Statement of Operations.

USD Rail Terminal Acquisition

On December 12, 2012, we completed a transaction with U.S. Development Group (referred to herein as the “USD Rail Terminal Acquisition”) for an aggregate consideration of approximately $503 million, paid in cash. Through the USD Rail Terminal Acquisition, we acquired four operating crude oil rail terminals and one terminal under development. The determination of the fair value of the assets and liabilities acquired was approximately $1 million of working capital, $76 million of property and equipment and $426 million of goodwill. The goodwill arising from the USD Rail Terminal Acquisition represents anticipated opportunities to generate future cash flows from the rail facilities by utilizing them to reduce capacity constraints in certain geographic market areas.

Other 2012 Acquisitions

During the year ended December 31, 2012, we completed several additional acquisitions for an aggregate consideration of approximately $150 million. The assets acquired primarily included crude oil and condensate gathering pipelines, a truck unloading terminal and 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.

Pro Forma Results

Disclosure of the revenues and earnings from the BP NGL Acquisition, USD Rail Terminal Acquisition and our other 2012 acquisitions in our results for the year ended December 31, 2012 is not practicable as they are not being operated as standalone subsidiaries. Selected unaudited pro forma results of operations for the years ended December 31, 2012 and 2011, assuming our 2012 acquisitions had occurred on January 1, 2011, are presented below (in millions):

	Year Ended December 31,
	2012		2011
Total revenues	$	38,729	$	37,493
Net income attributable to PAGP	$	3	$	2

2011 Acquisitions

Southern Pines Acquisition

On February 9, 2011, we acquired 100% of the equity interests in SG Resources from SGR Holdings, L.L.C. (the “Southern Pines Acquisition”) for an aggregate purchase price of approximately $765 million in cash (approximately $750 million, net of cash and other working capital acquired). The purchase price included the release of restricted cash of approximately $20 million held in escrow prior to the closing of the acquisition. The primary asset of SG Resources is the Southern Pines Energy Center (“Southern Pines”), a FERC-regulated, salt-cavern natural gas storage facility located in Greene County, Mississippi.

The fair value of assets acquired and liabilities assumed was as follows (in millions):

			Average
			Depreciable
Description	Amount		Life (in years)
Inventory	$	14	N/A
Property and equipment	340		5 - 70
Base gas	3		N/A
Other working capital (including approximately $13 million of cash acquired)	15		N/A
Intangible assets	92		2 - 10
Goodwill	301		N/A
Total	$	765

The allocation of fair value to intangible assets above was comprised of a tax abatement valued at approximately $15 million and contracts valued at approximately $77 million. Goodwill or indefinite lived intangible assets will not be subject to depreciation or amortization, but will be subject to periodic impairment testing and, if necessary, will be written down to fair value should circumstances warrant.

Several factors contributed to a purchase price in excess of the fair value of the net tangible and intangible assets acquired. Such factors included the strategic location of the Southern Pines facility, the limited alternative locations and the extended lead times required to develop and construct such facility, along with its operational flexibility, organic expansion capabilities and synergies anticipated to be obtained from combining Southern Pines with our existing asset base. This acquisition is reflected in our Facilities segment.

Other 2011 Acquisitions

Western Acquisition. On December 29, 2011, we completed two transactions with Western Refining for a combined consideration of approximately $220 million in cash. Through the first transaction, we acquired crude oil, refined products and NGL storage and the associated manifold and pumping equipment located at Western’s Yorktown, Virginia refinery site, which we operate as a terminal, as well as certain intangible assets. The second transaction included an 82-mile, 16-inch segment of pipeline that originates in Chaves County, New Mexico and connects into our Basin Pipeline system at Jal, New Mexico. The transaction includes associated tankage, piping and other related assets at the Lynch and Jal Stations.

Gardendale Gathering System Acquisition. On November 29, 2011, we completed the acquisition of 100% of the member interests in Velocity from Velocity Midstream Partners, LLC for an aggregate consideration of approximately $349 million in cash. The assets acquired included approximately 120 miles of crude oil and condensate gathering and transportation pipelines (the “Gardendale Gathering System”) in the Eagle Ford Shale. We recognized goodwill of approximately $155 million associated with this acquisition, which was primarily related to the potential incremental income from anticipated growth projects.

Additional2011 Acquisitions. During 2011, we completed six additional acquisitions for an aggregate consideration of approximately $20 million. These acquisitions included propane storage and terminal facilities included in our Facilities segment, a trucking business included in our Transportation segment as well as the right to ship on third-party pipelines, the revenues of which are included in our Supply and Logistics segment.

The determination of fair value of assets acquired and liabilities assumed for all other acquisitions completed during 2011, including the Western and Gardendale Gathering System acquisitions, is as follows (in millions):

Description	Amount
Inventory	$	2
Linefill	2
Property and equipment	280
Other working capital, net of cash acquired	(6		)
Intangible assets	142
Environmental liability	(9		)
Goodwill	178
Total	$	589

Dispositions

During 2013, 2012 and 2011, we sold various property and equipment for proceeds totaling approximately $200 million, $22 million and $12 million, respectively. Gains of less than $1 million and approximately $6 million and a loss of approximately $6 million were recognized in 2013, 2012 and 2011, respectively, related to these sales.

In February 2013, we signed a definitive agreement to sell certain refined products pipeline systems and related assets included in our Transportation segment. At December 31, 2012, these assets were classified as held for sale on our Consolidated Balance Sheet (in “Other current assets”). We closed a portion of the transaction on July 1, 2013 and the balance in November 2013.

- Definition

The entire disclosure for a business combination (or series of individually immaterial business combinations) completed during the period, including background, timing, and recognized assets and liabilities. The disclosure may include leverage buyout transactions (as applicable).

+ References

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+ Details

Net Income Per Class A Share

12 Months Ended

Dec. 31, 2013

Net Income Per Class A Share

Net Income Per Class A Share

Note 4—Net Income Per Class A Share

Basic net income per Class A share is determined by dividing net income attributable to PAGP by the weighted average number of outstanding Class A shares during the period. Class B shares do not share in the earnings of the Partnership. Accordingly, basic and diluted net income per Class B share has not been presented. Diluted net income per Class A share is determined by dividing net income attributable to PAGP by the weighted average number of outstanding diluted Class A shares during the period. For the purposes of the calculation of diluted net income per Class A share, both the net income attributable to PAGP and the weighted average number of outstanding diluted Class A shares consider the impact of possible future exchange of (i) certain AAP units and the associated Class B shares into our Class A shares and (ii) certain AAP Management Units into our Class A shares. See Note 10 for discussion of possible conversion of such shares.

AAP Management Units are considered potentially dilutive unless (i) vesting occurs only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. See Note 15 for a discussion of the vesting terms of the AAP Management Units. Conversions of AAP units and AAP Management Units are assumed to have occurred at the beginning of the period (the date of the closing of our IPO in this instance) and the incremental income attributable to PAGP resulting from the assumed conversions is representative of the incremental income that would have been attributable to PAGP if the assumed conversions occurred on that date.

For the period from October 21, 2013 (the closing of our IPO) through December 31, 2013, the possible conversion of certain AAP units and AAP Management Units would both be anti-dilutive. As there are no dilutive units for the period, the following table illustrates the calculation of both basic net income per Class A share and diluted net income per Class A share (amounts in millions, except per share data):

	October 21, 2013 to December 31, 2013
Basic and Diluted Net Income per Class A Share
Net income attributable to PAGP	$	15
Less net income attributable to PAGP for the period from January 1, 2013 to October 20, 2013	(3		)
Net income attributable to PAGP for the period from October 21, 2013 to December 31, 2013	$	12
Basic and diluted weighted average number of Class A shares outstanding (1)	132

Basic and diluted net income per Class A share	$	0.10

(1) Basic weighted average number of Class A shares outstanding is weighted for the period following the closing of our IPO. Approximately 128 million Class A shares were issued upon closing of our IPO with approximately 4 million additional Class A shares issued through the exercise in October 2103 of an over-allotment option. Subsequent conversions of AAP units were immaterial.

Inventory, Linefill and Base Gas and Long-term Inventory

12 Months Ended

Dec. 31, 2013

Inventory, Linefill and Base Gas and Long-term Inventory

Inventory, Linefill and Base Gas and Long-term Inventory

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

Inventory primarily consists of crude oil, NGL and natural gas in pipelines, storage facilities and railcars that are valued at the lower of cost or market, with cost determined using an average cost method within specific inventory pools. At the end of each reporting period, we assess the carrying value of our inventory and make any adjustments necessary to reduce the carrying value to the applicable net realizable value. We recorded non-cash charges of approximately $7 million and $128 million for the years ended December 31, 2013 and 2012, respectively related to the writedown of our crude oil and NGL inventory due to declines in prices during the period. As of December 31, 2013 and 2012, a majority of the inventory subject to writedown in each period had been liquidated and the applicable derivative instruments had been settled by the end of each year. The recognition of these adjustments in 2013 and 2012, which are a component of “Purchases and related costs” in our accompanying Consolidated Statement of Operations, was substantially offset by the recognition of gains on derivative instruments being utilized to hedge the future sales of our crude oil and NGL inventory. Substantially all of such gains were recorded to “Supply and Logistics segment revenues” in our Consolidated Statement of Operations. See Note 11 for discussion of our derivative and risk management activities. We did not recognize a material writedown of inventory during 2011.

Linefill and base gas and minimum working inventory requirements in assets we own are recorded at historical cost and consist of crude oil, NGL and natural gas. We classify as linefill or base gas (i) our proportionate share of barrels used to fill a pipeline that we own such that when an incremental barrel is pumped into or enters a pipeline it forces product out at another location, (ii) barrels that represent the minimum working requirements in tanks that we own and (iii) natural gas required to maintain the minimum operating pressure of natural gas storage facilities we own. During 2013, 2012 and 2011, we recorded gains of approximately $7 million, $19 million and $21 million, respectively, on the sale of linefill and base gas for proceeds of approximately $40 million, $65 million and $56 million, respectively.

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

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

	December 31, 2013						December 31, 2012
	Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)		Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)
Inventory
Crude oil	6,951	barrels	$	540	$	77.69	9,492	barrels	$	737	$	77.64
NGL	8,061	barrels	352		$	43.67	9,472	barrels	388		$	40.96
Natural gas	40,505	Mcf	150		$	3.70	20,374	Mcf	60		$	2.94
Other	N/A		23		N/A		N/A		24		N/A
Inventory subtotal			1,065						1,209

Linefill and base gas
Crude oil	10,966	barrels	679		$	61.92	9,919	barrels	583		$	58.78
NGL	1,341	barrels	62		$	46.23	1,400	barrels	70		$	50.00
Natural gas	16,615	Mcf	57		$	3.43	15,755	Mcf	54		$	3.43
Linefill and base gas subtotal			798						707

Long-term inventory
Crude oil	2,498	barrels	202		$	80.86	1,962	barrels	149		$	75.94
NGL	1,161	barrels	49		$	42.20	3,238	barrels	125		$	38.60
Long-term inventory subtotal			251						274

Total			$	2,114					$	2,190

(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.

Property and Equipment

12 Months Ended

Dec. 31, 2013

Property and Equipment

Property and Equipment

Note 6—Property and Equipment

In accordance with our capitalization policy, expenditures made to expand the existing operating and/or earnings capacity of our assets, including related interest costs, are capitalized. For the years ended December 31, 2013, 2012 and 2011, capitalized interest was $38 million, $36 million and $25 million, respectively. We also capitalize expenditures for the replacement of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets. Repair and maintenance expenditures incurred in order to maintain the day to day operation of our existing assets are expensed as incurred.

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

	Estimated Useful	December 31,
	Lives (Years)	2013			2012
Pipelines and related facilities	10 - 70	$	6,154		$	5,346
Storage, terminal and rail facilities	30 - 70	4,704			4,354
Trucking equipment and other	3 - 15	150			136
Construction in progress	—	1,008			910
Office property and equipment	2 - 50	125			111
Land and other	N/A	373			326
		12,514			11,183
Accumulated depreciation		(1,673		)	(1,519		)
Property and equipment, net		$	10,841		$	9,664

Depreciation expense for the years ended December 31, 2013, 2012 and 2011 was approximately $262 million, $223 million and $197 million, respectively. We also classify gains and losses on sales of assets and asset impairments as a component of “Depreciation and amortization” in our Consolidated Statements of Operations. See Note 3 for additional information regarding dispositions. See “Impairment of Long-Lived Assets” below for a discussion of our policy for the recognition of asset impairments.

We calculate our depreciation using the straight-line method, based on estimated useful lives and salvage values of our assets. During 2011, we extended the depreciable lives of several of our crude oil and other storage facilities and pipeline systems based on a review to assess the useful lives of our property and equipment and to adjust those lives, if appropriate, to reflect current expectations given actual experience and current technology. For the year ended December 31, 2012, these extensions reduced depreciation expense by $13 million as compared to the year ended December 31, 2011.

Impairment of Long-Lived Assets

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

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

· whether there is an indication of impairment;

· the grouping of assets;

· the intention of “holding,” “abandoning” or “selling” an asset;

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

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

For the years ended December 31, 2013 and 2011, we recognized impairments of approximately $20 million and $5 million, respectively, related predominantly to assets taken out of service.

During the year ended December 31, 2012, we recognized losses on impairments of long-lived assets of approximately $168 million, primarily related to our Pier 400 terminal project, which is reflected in “Depreciation and amortization” on our Consolidated Statement of Operations. This project, which we acquired in late 2006 by virtue of our merger with Pacific, was to develop 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.

Also in 2012, we recognized a loss on impairment as a result of our decision to sell certain refined products pipeline systems and related assets included in the Transportation segment. At December 31, 2012, these assets were classified as held for sale on our Consolidated Balance Sheet (in “Other current assets”). In accordance with GAAP, we wrote their book value down to their expected sales price. In February 2013, we signed a definitive agreement to sell these systems and related assets. A portion of the transaction closed in July 2013 and we closed the balance of the transaction in November 2013.

Goodwill

12 Months Ended

Dec. 31, 2013

Goodwill

Goodwill

Note 7—Goodwill

Goodwill represents the future economic benefits arising from assets acquired in a business combination that are not individually identified and separately recognized.

In accordance with FASB guidance, we test goodwill at least annually (as of June 30) and on an interim basis if a triggering event occurs, such as an adverse change in business climate, to determine whether impairment has occurred. Goodwill is tested for impairment at a level of reporting referred to as a reporting unit. A reporting unit is an operating segment or one level below an operating segment for which discrete financial information is available and regularly reviewed by segment management. Our reporting units are our operating segments. FASB guidance requires a two-step, quantitative approach to testing goodwill for impairment; however, we may first assess certain qualitative factors to determine whether it is necessary to perform the two-step goodwill impairment test. We did not elect to apply this qualitative assessment during our 2013 annual goodwill impairment test, but proceeded directly to the two-step, quantitative test. In Step 1, we compare the fair value of the reporting unit with the respective book values, including goodwill, by using an income approach based on a discounted cash flow analysis. This approach requires us to make long-term forecasts of future revenues, expenses and other expenditures. Those forecasts require the use of various assumptions and estimates, the most significant of which are net revenues (total revenues less purchases and related costs), operating expenses, general and administrative expenses and the weighted average cost of capital. Fair value of the reporting units is determined using significant unobservable inputs, or level 3 inputs in the fair value hierarchy. When the fair value is greater than book value, then the reporting unit’s goodwill is not considered impaired. If the book value is greater than fair value, then we proceed to Step 2. In Step 2, we compare the implied fair value of the reporting unit’s goodwill with the book value. A goodwill impairment loss is recognized if the carrying amount exceeds its fair value.

Through Step 1 of our annual testing of goodwill for potential impairment, which also includes a sensitivity analysis regarding the excess of our reporting unit’s fair value over book value, we determined that the fair value of each reporting unit was substantially greater than its respective book value, and therefore goodwill was not considered impaired. We will continue to monitor various potential indicators (including the financial markets) to determine if a triggering event occurs and will perform another goodwill impairment analysis if necessary.

The table below reflects our goodwill by segment and changes during the periods presented (in millions):

	Transportation			Facilities			Supply and Logistics			Total
Balance at December 31, 2011	$	818		$	609		$	427		$	1,854

2012 Goodwill Related Activity:
BP NGL Acquisition	72			136			28			236
USD Rail Terminal Acquisition	—			426			—			426
Other acquisitions	10			—			—			10
Foreign currency translation adjustments	5			—			2			7
Purchase price accounting adjustments and other	(8		)	—			10			2
Balance at December 31, 2012	$	897		$	1,171		$	467		$	2,535

2013 Goodwill Related Activity:
Acquisitions (1)	6			—			—			6
Foreign currency translation adjustments	(20		)	(9		)	(4		)	(33		)
Purchase price accounting adjustments and other (1)	(5		)	—			—			(5		)
Balance at December 31, 2013	$	878		$	1,162		$	463		$	2,503

(1) 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. See Note 3 for additional discussion of our acquisitions.

Other Assets, Net

12 Months Ended

Dec. 31, 2013

Other Assets, Net

Other Assets, Net

Note 8—Other Assets, Net

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

	December 31,
	2013			2012
Deferred tax asset	$	1,068		$	—
Debt issue costs	72			70
Fair value of derivative instruments	30			10
Intangible assets	674			642
Other	37			54
	1,881			776
Accumulated amortization	(271		)	(189		)
	$	1,610		$	587

In connection with the transfer of the ownership interest in AAP in connection with our IPO in October 2013 and any subsequent transfers in 2013, a deferred tax asset was created. See Note 12 for further discussion.

Costs incurred in connection with the issuance of long-term debt and amendments to credit facilities are capitalized and amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the “effective interest” method of amortization. Fully amortized debt issue costs and the related accumulated amortization are written off in conjunction with the refinancing or termination of the applicable debt arrangement. We capitalized debt issue costs of approximately $10 million and $21 million in 2013 and 2012, respectively. Approximately $8 million and $5 million of gross debt issue costs, primarily related to the restructuring of credit facilities, were removed from our Consolidated Balance Sheet during 2013 and 2012, respectively.

Amortization expense related to other assets (including finite-lived intangible assets) for the three years ended December 31, 2013, 2012 and 2011 was approximately $96 million, $99 million and $44 million, respectively. Our amortization expense for finite-lived intangible assets for the years ended December 31, 2013, 2012 and 2011 was approximately $85 million, $90 million and $36 million, respectively.

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

		December 31, 2013							December 31, 2012
	Estimated Useful			Accumulated							Accumulated
	Lives (Years)	Cost		Amortization			Net		Cost		Amortization			Net
Customer contracts and relationships	1 - 20	$	591	$	(237	)	$	354	$	558	$	(157	)	$	401
Property tax abatement	7 - 13	38		(14		)	24		38		(10		)	28
Other agreements	25 - 70	37		(3		)	34		38		(2		)	36
Emission reduction credits (1)	N/A	8		—			8		8		—			8
		$	674	$	(254	)	$	420	$	642	$	(169	)	$	473

(1) Emission reduction credits, once surrendered in exchange for environmental permits, are finite-lived.

We estimate that our amortization expense related to finite-lived intangible assets for the next five years will be as follows (in millions):

2014	$	59
2015	$	52
2016	$	45
2017	$	42
2018	$	36

Debt

12 Months Ended

Dec. 31, 2013

Debt

Debt

Note 9—Debt

Debt consisted of the following as of the dates indicated (in millions):

	December 31,			December 31,
	2013			2012
SHORT-TERM DEBT
Credit Facilities (1):
PAA senior secured hedged inventory facility, bearing a weighted-average interest rate of 1.6% at December 31, 2012 (2)	$	—		$	665
PAA senior unsecured revolving credit facility, bearing a weighted-average interest rate of 2.4% at December 31, 2012 (2)	—			92
PNG senior unsecured revolving credit facility, bearing a weighted-average interest rate of 2.1% at December 31, 2012 (3)	—			77
PAA commercial paper notes, bearing a weighted-average interest rate of 0.33% at December 31, 2013 (2)	1,109			—
PAA 5.63% senior notes due December 2013	—			250
Other	4			2
Total short-term debt	1,113			1,086

LONG-TERM DEBT
PAA Senior Notes:
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	750			750
2.85% senior notes due January 2023	400			400
3.85% senior notes due October 2023	700			—
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	500			500
4.30% senior notes due January 2043	350			350
Unamortized discounts	(15		)	(15		)
PAA senior notes, net of unamortized discounts	6,710			6,010
Credit Facilities and Other Long-Term Debt (1):
AAP term loan, bearing a weighted-average interest rate of 1.9% and 1.8% at December 31, 2013 and December 31, 2012, respectively	500			200
AAP senior secured revolving credit facility, bearing a weighted-average interest rate of 2.2% at December 31, 2013	15			—
PNG senior unsecured revolving credit facility, bearing a weighted-average interest rate of 2.1% at December 31, 2012 (3)	—			105
PNG GO Bond term loans, bearing a weighted-average interest rate of 1.5% at December 31, 2012 (3)	—			200
Other	5			5
Total long-term debt	7,230			6,520
Total debt (2) (3) (4)	$	8,343		$	7,606

(1) During 2013 and 2012, we renewed, extended or refinanced our principal bank credit facilities. See “Credit Facilities” below for further discussion.

(2) We classify as short-term certain borrowings under the PAA commercial paper program, PAA senior unsecured revolving credit facility and PAA senior secured hedged inventory 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) On December 31, 2013, in connection with the completion of the PNG Merger, all of PNG’s outstanding debt obligations were repaid and terminated.

(4) PAA’s fixed-rate senior notes (including current maturities) had a face value of approximately $6.7 billion and $6.3 billion as of December 31, 2013 and 2012, respectively. We estimated the aggregate fair value of these notes as of December 31, 2013 and 2012 to be approximately $7.2 billion and $7.3 billion, respectively. PAA’s 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 year end. We estimate that the carrying value of outstanding borrowings under credit facilities and agreements and commercial paper program approximates fair value as interest rates reflect current market rates. The fair value estimates for both the senior notes and credit facilities are based upon observable market data and are classified within Level 2 of the fair value hierarchy.

Commercial Paper Program

In August 2013, PAA established a commercial paper program under which it may issue, from time to time, privately placed, unsecured commercial paper notes for up to a maximum aggregate amount outstanding at any time of $1.5 billion. Such notes are backstopped by the PAA senior unsecured revolving credit facility and the PAA senior secured hedged inventory facility; as such, any borrowings under the PAA commercial paper program reduce the available capacity under these facilities.

Credit Facilities

PAA senior secured hedged inventory facility. In August 2013, PAA amended its senior secured hedged inventory facility agreement to, among other things, extend the maturity date of the facility by two years to August 2016. The agreement also provides for one or more one-year extensions, subject to applicable approval. The facility has a committed borrowing capacity of $1.4 billion, of which $400 million 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. Proceeds from the facility are being used to finance purchased or stored hedged inventory. Obligations under the committed facility are secured by the financed inventory and the associated accounts receivable and will be repaid from the proceeds of the sale of the financed inventory. Borrowings accrue interest based, at PAA’s election, on either the Eurocurrency Rate or the Base Rate, in each case plus a margin based on PAA’s credit rating at the applicable time.

PAA senior unsecured revolving credit facility. In August 2013, PAA amended its senior unsecured revolving credit facility agreement to, among other things, extend the maturity date by two years to August 2018. The agreement also provides for one or more one-year extensions, subject to applicable approval. The facility has a committed borrowing capacity of $1.6 billion which contains an accordion feature that enables us to increase the committed capacity to $2.1 billion, subject to obtaining additional or increased lender commitments. The credit agreement also provides for the issuance of letters of credit. Borrowings accrue interest based, at PAA’s election, on the Eurocurrency Rate, the Base Rate or the Canadian Prime Rate, in each case plus a margin based on PAA’s credit rating at the applicable time.

AAP senior secured credit agreement. In September 2013, the AAP credit agreement was amended to increase the term loan facility from $200 million to $500 million, increase the aggregate commitments under the revolving credit facility from $25 million to $75 million and extend the maturity date by one year to September 2018. We pay a quarterly commitment fee on the revolver that is based on AAP’s Consolidated Indebtedness to Consolidated EBITDA ratio (“Leverage Ratio”), as defined in the credit agreement. The commitment fee can range from 0.175% to 0.35% and is payable on the daily average unused amount of the revolver. Borrowings accrue interest based, at AAP’s election, on the Alternative Base Rate (the greater of the Base Rate or Federal Funds Effective Rate) or the Eurodollar Rate, in each case plus a margin as determined by AAP’s Leverage Ratio.

PNG senior unsecured credit agreement. The PNG senior unsecured credit agreement provided for (i) $350 million under a revolving credit facility and (ii) two $100 million GO Bond term loans. PNG’s revolving credit facility included the ability to issue letters of credit. Borrowings under the revolving credit facility accrued interest, at PNG’s election, on either the Eurodollar Rate or the Base Rate, in each case plus an applicable margin. The GO Bond term loans accrued interest in accordance with the interest payable on the related GO Bonds purchased with respect thereto as provided in such GO Bonds and the GO Bonds Indenture pursuant to which such GO Bonds are issued and governed. On December 31, 2013, in connection with the completion of the PNG Merger, all outstanding borrowings were repaid under the credit facility and the related revolving credit commitments were terminated. PAA retained the effectiveness of the GO Bond Indenture, which may be utilized for a future tax-exempt $200 million debt issuance.

Senior Notes

PAA’s senior notes are co-issued, jointly and severally, by Plains All American Pipeline, L.P. and a 100%-owned consolidated finance subsidiary (neither of which have independent assets or operations) and are unsecured senior obligations of such entities and rank equally in right of payment with existing and future senior indebtedness of the issuers. PAA may, at its option, redeem any series of senior notes at any time in whole or from time to time in part, prior to maturity, at the redemption prices described in the indentures governing the senior notes. In August 2011, as permitted under the indentures governing the senior notes, PAA released the guarantees of each subsidiary guarantor. As such, PAA’s senior notes are not guaranteed by any of its subsidiaries.

Senior Notes Issuances

In August 2013, PAA completed the sale and issuance of $700 million, 3.85% senior notes due October 15, 2023. The senior notes were sold at 99.792% of face value. Interest payments are due on April 15 and October 15 each year beginning on April 15, 2014.

In December 2012, PAA completed the sale and issuance of $400 million, 2.85% senior notes due January 31, 2023 and $350 million, 4.30% senior notes due January 31, 2043. The senior notes were sold at 99.752% and 99.925% of face value, respectively. Interest payments are due on January 31 and July 31 each year, which began on July 31, 2013.

In March 2012, PAA completed the sale and issuance of $750 million, 3.65% senior notes due June 1, 2022 and $500 million, 5.15% senior notes due June 1, 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, which began on December 1, 2012.

Senior Note Repayments and Redemptions

On December 13, 2013, PAA repaid its $250 million, 5.63% senior notes. PAA utilized cash on hand and available capacity under its commercial paper program to repay these notes.

On September 4, 2012, PAA repaid its $500 million, 4.25% senior notes. PAA utilized cash on hand and available capacity under its credit facilities to repay these notes.

On February 7, 2011, PAA’s $200 million 7.75% senior notes due 2012 were redeemed in full. In conjunction with the early redemption, we recognized a loss of approximately $23 million, recorded to “Other income/(expense), net” in our Consolidated Statement of Operations. PAA utilized cash on hand and available capacity under its credit facilities to redeem these notes.

Maturities

The weighted average life of our long-term debt outstanding at December 31, 2013 was approximately 11 years and the aggregate maturities for the next five years and thereafter are as follows (in millions):

Calendar Year	Payment
2014	$	—
2015	550
2016	175
2017	400
2018	1,115
Thereafter	5,000
Total (1)	$	7,240

(1) Excludes aggregate unamortized net discount of approximately $15 million and other long-term obligations of approximately $5 million.

Covenants and Compliance

PAA’s Credit Agreements. PAA’s credit agreements (which impact the ability to access the PAA commercial paper program) and the indentures governing PAA’s senior notes contain cross-default provisions. PAA’s credit agreements prohibit declaration or payments of distributions on, or purchases or redemptions of, units if any default or event of default is continuing. In addition, the agreements contain various covenants limiting PAA’s ability to, among other things:

· grant liens on certain property;

· incur indebtedness, including capital leases;

· sell substantially all of its assets or enter into a merger or consolidation;

· engage in certain transactions with affiliates; and

· enter into certain burdensome agreements.

The PAA senior unsecured revolving credit facility and the PAA senior secured hedged inventory facility treat a change of control as an event of default and also requires PAA to maintain a debt-to-EBITDA coverage ratio that will not be greater than 5.00 to 1.00 (or 5.50 to 1.00 on all outstanding debt during an acquisition period (generally, the period consisting of three fiscal quarters following an acquisition greater than $150 million)).

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

A default under PAA’s credit facilities would permit the lenders to accelerate the maturity of the outstanding debt. As long as PAA is in compliance with its credit agreements, PAA’s ability to make distributions of available cash is not restricted. As of December 31, 2013, PAA was in compliance with the covenants contained in its credit agreements and indentures.

AAP Credit Agreement. In order to secure the facility, AAP pledged 100% of (i) its incentive distribution rights in PAA and (ii) its interest in PAA GP. The credit agreement contains various covenants limiting AAP’s ability to, among other things:

· incur additional indebtedness;

· grant liens;

· make fundamental changes as defined;

· make restrictive payments as defined; and

· enter into restrictive agreements.

The AAP credit agreement requires AAP to maintain a Leverage Ratio of no greater than 4.0 to 1.0.

Borrowings and Repayments

Total borrowings under credit agreements and the commercial paper program for the years ended December 31, 2013, 2012 and 2011 were approximately $31.5 billion, $12.9 billion and $9.7 billion, respectively. Total repayments under credit agreements and the commercial paper program were approximately $31.2 billion, $12.2 billion and $10.9 billion for the years ended December 31, 2013, 2012 and 2011, respectively. The variance in total gross borrowings and repayments is impacted by various business and financial factors including, but not limited to, the timing, average term and method of general partnership borrowing activities.

Letters of Credit

In connection with our supply and logistics activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase of crude oil, NGL and natural gas. These letters of credit are issued under the PAA senior unsecured revolving credit facility and the PAA senior secured hedged inventory facility, and our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the crude oil, NGL or natural gas is purchased. Generally, these letters of credit are issued for periods of up to seventy days and are terminated upon completion of each transaction. Additionally, we issue letters of credit to support insurance programs and construction activities. At December 31, 2013 and 2012, we had outstanding letters of credit of approximately $41 million and $24 million, respectively.

Partners' Capital and Distributions

12 Months Ended

Dec. 31, 2013

Partners' Capital and Distributions

Partners' Capital and Distributions

Note 10—Partners’ Capital and Distributions

Initial Public Offering

Through a series of transactions with our general partner and the owners of GP LLC prior to the closing of our IPO, we issued 473,647,679 Class B shares and an equal number of units of our general partner to such owners and received a 100% managing member interest in GP LLC. Also prior to the IPO, certain owners of AAP (the “Selling Owners”) sold a portion of their interests in AAP to us in exchange for the right to receive an amount equal to the net proceeds of the IPO, resulting in our ownership of AAP units representing limited partnership interests in AAP.

In October 2013, we completed our IPO of 132,382,094 Class A shares representing limited partner interests at a price of $22.00 per Class A share, generating net proceeds, after deducting underwriting discounts and commissions and direct offering expenses, of approximately $2.8 billion. We distributed the net proceeds of the IPO to the Selling Owners.

Shares Outstanding

Partners’ capital at December 31, 2013 consists of 133,833,637 Class A shares and 472,196,136 Class B shares outstanding. Our Class A shares and Class B shares represent limited partner interests in us. The holders of our Class A and Class B shares are entitled to exercise the rights or privileges available to limited partners under our partnership agreement, but only holders of Class A shares are entitled to participate in our distributions.

Exchange Rights. Permitted transferees of holders of AAP units will each have the right to exchange all or a portion of their AAP units into Class A shares at an exchange ratio of one Class A share for each AAP unit exchanged. This exchange right may be exercised only if, simultaneously therewith, an equal number of our Class B shares and general partner units are transferred by the exercising party to us. Additionally, if our Class A shares are publicly traded at any time after December 31, 2015, a holder of vested AAP Management Units will be entitled to exchange his or her AAP Management Units for AAP units and a like number of our Class B shares based on a conversion ratio calculated in accordance with the AAP limited partnership agreement (which conversion ratio will not be more than one-to-one and was approximately 0.90 AAP units for each AAP Management Unit as of December 31, 2013). Following any such exchange, the holder will have the Exchange Right for our Class A shares. Holders of AAP Management Units who exchange for AAP units and Class B shares will not receive general partner units and thus will not need to include any general partner units in a transfer or the exercise of their Exchange Right. See Note 15 for additional information regarding the AAP Management Units. A total of 1,451,543 AAP units, Class B shares and general partner units were exchanged through December 31, 2013 for 1,451,543 Class A shares.

The following table sets forth the changes in our outstanding shares since becoming public:

	Class A Shares	Class B Shares
Balance at October 21, 2013 (IPO date)	—	—
Shares issued in connection with the reorganization and IPO	132,382,094	473,647,679
Shares issued/(exchanged) in connection with AAP unit exchanges	1,451,543	(1,451,543	)
Balance at December 31, 2013	133,833,637	472,196,136

Distributions

We distribute 100% of our available cash within 55 days after the end of each quarter to Class A shareholders of record. Available cash is generally defined as all cash on hand at the date of determination of available cash for the distribution in respect to such quarter (including expected distributions from AAP in respect of such quarter), less reserves established by our general partner for future requirements.

Distributions to Class A Shareholders. On January 9, 2014, we declared a distribution for the fourth quarter of 2013 of $0.12505 per outstanding Class A share, which was prorated for the partial quarter following the closing of our IPO on October 21, 2013. This distribution of approximately $17 million was paid on February 14, 2014 to shareholders of record at the close of business on January 31, 2014.

Distributions Prior to our IPO. During the years ended December 31, 2013, 2012 and 2011, $6 million, $3 million and $2 million, respectively, were distributed to the owners of GP LLC. Of the amount distributed during the year ended December 31, 2013, approximately $3 million relates to distributions received from AAP related to the net proceeds from the increase in AAP’s term loan. See Note 9 for further discussion.

Noncontrolling Interests in Subsidiaries

As of December 31, 2013, noncontrolling interests in subsidiaries consisted of the following: (i) a 98% limited partner interest in PAA, (ii) an approximate 78% limited partner interest in AAP that consists of Class A units and AAP Management Units (a profits interest) and (iii) a 25% interest in SLC Pipeline. Prior to our IPO, noncontrolling interests in subsidiaries consisted of: (i) a 98% limited partner interest in PAA, (ii) a 99% limited partner interest in AAP that consisted of Class A units and AAP Management Units (a profits interest), (iii) an approximate 37% limited partner interest in PNG and (iv) a 25% interest in SLC Pipeline.

PAA Distributions

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

AAP is entitled to receive (i) distributions representing its 2% indirect general partner interest in PAA and (ii) incentive distributions if the amount PAA distributes with respect to any quarter exceeds levels specified in PAA’s partnership agreement. Under the quarterly distribution provisions, AAP is entitled, without duplication, to 2% of amounts PAA distributes up to $0.2250 per unit, referred to as the MQD, 15% of amounts PAA distributes in excess of $0.2250 per unit, 25% of the amounts PAA distributes in excess of $0.2475 per unit and 50% of amounts PAA distributes in excess of $0.3375 per unit.

AAP agreed to reduce the amount of its incentive distribution by $3.75 million per quarter for distributions paid during 2013, $6.75 million for the distribution paid in February 2014, $5.5 million per quarter thereafter through November 2015, $5.0 million per quarter in 2016 and $3.75 million per quarter thereafter. These reductions were agreed to in connection with the BP NGL Acquisition and the completion of the PNG Merger on December 31, 2013. See Note 3 for further discussion of the BP NGL Acquisition. For distributions paid during the years ended December 31, 2013, 2012 and 2011, AAP’s incentive distributions were reduced by approximately $15 million, $11 million and $7 million, respectively.

Total cash distributions paid by PAA during the periods indicated were as follows (in millions, except per unit amounts):

	Distributions Paid								Distributions
	Common		AAP						per limited
Year	Units		Incentive		2%		Total		partner unit
2013	$	791	$	353	$	16	$	1,160	$	2.33
2012	$	684	$	271	$	14	$	969	$	2.11
2011	$	575	$	204	$	12	$	791	$	1.95

On January 9, 2014, PAA declared a cash distribution of $0.6150 per unit on PAA’s outstanding common units. The distribution was paid on February 14, 2014 to unitholders of record on January 31, 2014, for the period October 1, 2013 through December 31, 2013. The total distribution paid was approximately $328 million, with approximately $221 million paid to PAA’s common unitholders and $5 million and $102 million paid to AAP for its general partner and incentive distribution interests, respectively.

AAP Distributions

AAP distributes all of the cash received from PAA distributions on a quarterly basis, less reserves established in the discretion of its general partner for future requirements. Generally, distributions are paid to its partners in proportion to their percentage interest in the AAP. During the years ended December 31, 2013, 2012 and 2011, AAP distributed approximately $361 million, $276 million and $209 million, respectively, to its partners, related to distributions received from PAA.

In September 2013, the AAP credit agreement was amended to increase the amount of the term loan by $300 million. Upon receipt, the net term loan proceeds of approximately $299 million were distributed to AAP’s partners, excluding AAP Management Unit holders, in proportion to their respective ownership interests. See Note 9 for further discussion.

On February 14, 2014, AAP distributed approximately $104 million to its partners. The distribution was prorated as of the date of the consummation of our IPO, such that the Selling Owners received the portion of the distribution attributable to the period of the fourth quarter of 2013 prior to our IPO, and the owners of AAP at the date of record of January 31, 2013, including us, received the portion of the distribution attributable to the period beginning on the date of our IPO through the end of the fourth quarter of 2013.

PAA Equity Offerings

Continuous Offering Program. During 2012 and 2013 PAA entered into several equity distribution agreements, under its Continuous Offering Program, with respect to the offer and sale, through sales agents, of common units representing limited partner interests having aggregate offering prices ranging from up to $300 million to up to $750 million. Sales of such common units are made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed upon by the sales agent and PAA.

During the year ended December 31, 2013, PAA sold an aggregate of approximately 8.6 million common units under its Continuous Offering Program, generating proceeds of approximately $468 million, net of offering costs.

During the year ended December 31, 2012, PAA sold an aggregate of approximately 12.0 million common units under its Continuous Offering Program, generating proceeds of approximately $513 million, net of offering costs.

Other Equity Offerings. In addition to sales of PAA’s common units under its Continuous Offering Program described above, PAA completed the following offerings of its common units during the three years ended December 31, 2013 (in millions, except unit and per unit data):

		Gross		Proceeds					Net
Period	Units Issued	Unit Price		from Sale		Costs			Proceeds
March 2012 (1)	11,500,000	$	40.015	$	460	$	(14	)	$	446
2012 Total	11,500,000			$	460	$	(14	)	$	446

November 2011 (1)	12,000,000	$	32.515	$	390	$	(13	)	$	377
March 2011 (1)	15,870,000	$	32.000	508		(15		)	493
2011 Total	27,870,000			$	898	$	(28	)	$	870

(1) These offerings of common units were underwritten transactions that required PAA to pay a gross spread.

Contributions from Noncontrolling Interests

Contributions from noncontrolling interests consists of contributions from the owners of AAP (other than us) to reimburse AAP for its capital contribution required to maintain its indirect 2% general partner interest in PAA following PAA’s issuance of common units.

Issuance of PNG Common Units

PNG issued approximately 1.9 million and 27.6 million common units during the years ended December 31, 2013 and 2011, respectively. PNG did not issue any common units during the year ended December 31, 2012. As a result of PNG’s common unit issuances, we recorded an increase in noncontrolling interest of approximately $40 million and $370 million in 2013 and 2011, respectively.

Derivatives and Risk Management Activities

12 Months Ended

Dec. 31, 2013

Derivatives and Risk Management Activities

Derivatives and Risk Management Activities

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.

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 December 31, 2013, net derivative positions related to these activities included:

· An average of 242,800 barrels per day net long position (total of 7.5 million barrels) associated with our crude oil purchases, which was unwound ratably during January 2014 to match monthly average pricing.

· A net short spread position averaging approximately 13,600 barrels per day (total of 5.4 million barrels), which hedges a portion of our anticipated crude oil lease gathering purchases through February 2015. 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.

· An average of 2,200 barrels per day (total of 1.0 million barrels) of butane/WTI spread positions, which hedge specific butane sales contracts that are priced as a percentage of WTI through March 2015.

· A long position of approximately 2.3 Bcf through April 2016 related to anticipated base gas requirements.

· A short position of approximately 40.5 Bcf through April 2014 related to anticipated sales of natural gas inventory.

· A short position of approximately 6.9 million barrels through March 2015 related to the anticipated sales of our crude oil, NGL and refined products inventory.

Storage Capacity Utilization — We own a significant amount 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 in a backwardated market structure. As of December 31, 2013, we used derivatives to manage the risk of not utilizing approximately 0.8 million barrels per month of storage capacity through February 2014. These positions involve no outright price exposure, but instead enable us to profitably use the capacity to store hedged crude oil.

Pipeline Loss Allowance Oil — As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor that is intended to offset losses due to evaporation, measurement and other losses in transit. We utilize derivative instruments to hedge a portion of the anticipated sales of the allowance oil that is to be collected under our tariffs. As of December 31, 2013, our PLA hedges included a net short position for an average of approximately 1,700 barrels per day (total of 1.2 million barrels) through December 2015 and a long call option position of approximately 0.5 million barrels through December 2015.

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 price risk associated with the purchase of the natural gas and the subsequent sale of the individual specification products. As of December 31, 2013, we had a long natural gas position of approximately 19.5 Bcf through December 2015, a short propane position of approximately 3.4 million barrels through December 2015, a short butane position of approximately 1.0 million barrels through December 2015 and a short WTI position of approximately 0.4 million barrels through December 2015. In addition, we had a long power position of 0.5 million megawatt hours which hedges a portion of our power supply requirements at our natural gas processing and fractionation plants through June 2016.

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 normal purchase normal sale scope exception. Physical commodity contracts that meet the definition of a derivative but are ineligible, or not designated, for the normal purchase normal sale 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 December 31, 2013, AOCI includes deferred losses of approximately $65 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 loss related to these instruments is being amortized to interest expense over the terms of the hedged debt instruments.

PAA has 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 PAA’s forward starting interest rate swaps as of December 31, 2013 (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

10 forward starting swaps (30-year)

250

6/15/2015

3.60

Cash flow hedge

Concurrent with PAA’s August 2013 senior notes issuance, PAA terminated five thirty-year forward starting interest rate swaps. These swaps had an aggregate notional amount of $125 million and an average fixed rate of 3.39%. We received cash proceeds of approximately $11 million, of which a gain of approximately $8 million was deferred in AOCI and a gain of approximately $3 million was recognized in interest expense attributable to the ineffective portion of these swaps.

Concurrent with PAA’s December 2012 senior note issuance, PAA terminated six thirty-year forward starting interest rate swaps. These swaps had an aggregate notional amount of $250 million and an average fixed rate of 4.24%. We made a cash payment of approximately $89 million in connection with the termination of these swaps.

Concurrent with PAA’s March 2012 senior note issuances, PAA 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 PAA’s January 2011 senior notes issuance, PAA 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 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. Following the completion of the PNG Merger, these swaps were terminated in conjunction with the termination of the PNG credit facility.

During December 2007 and January 2008, AAP entered into a total of three interest rate swaps to fix the interest rate on a portion of its outstanding debt. These swaps had an aggregate notional amount of $200 million with an average interest rate of 3.99%. Two of these swaps terminated in January 2011 and one terminated in January 2013. These swaps were designated as cash flow hedges.

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 December 31, 2013, our outstanding foreign currency derivatives include derivatives we use to (i) hedge currency exchange risk associated with USD-denominated commodity purchases and sales in Canada and (ii) 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 December 31, 2013 (in millions):

		USD		CAD		Average Exchange Rate USD to CAD
Forward exchange contracts that exchange CAD for USD:
	2014	$	336	$	358	$1.00 - $1.06
	2015	9		9		$1.00 - $1.07
		$	345	$	367	$1.00 - $1.06

Forward exchange contracts that exchange USD for CAD:
	2014	$	336	$	354	$1.00 - $1.05
	2015	9		9		$1.00 - $1.06
		$	345	$	363	$1.00 - $1.05

Net position by currency:
	2014	$	—	$	4
	2015	—		—
		$	—	$	4

Summary of Financial Impact

We record all open derivatives on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of derivatives are recognized currently in earnings unless specific hedge accounting criteria are met. 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 are recognized in earnings. 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 Consolidated Statements of Cash Flows.

A summary of the impact of our derivative activities recognized in earnings for the years ended December 31, 2013, 2012 and 2011 is as follows (in millions):

	Year Ended December 31, 2013
	Derivatives in Hedging Relationships
Location of gain/(loss)	Gain/(loss) reclassified from AOCI into income (1)			Other gain/(loss) recognized in income			Derivatives Not Designated as a Hedge			Total
Commodity Derivatives

Supply and Logistics segment revenues	$	78		$	(1	)	$	(116	)	$	(39	)

Facilities segment revenues	(10		)	(1		)	—			(11		)

Field operating costs	—			—			8			8

Interest Rate Derivatives

Interest expense	(7		)	3			—			(4		)

Foreign Currency Derivatives

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

Total Gain/(Loss) on Derivatives Recognized in Net Income	$	66		$	1		$	(108	)	$	(41	)

	Year Ended December 31, 2012
	Derivatives in Hedging Relationships
Location of gain/(loss)	Gain/(loss) reclassified from AOCI into income (1)			Other gain/(loss) recognized in income			Derivatives Not Designated as a Hedge			Total
Commodity Derivatives

Supply and Logistics segment revenues	$	12		$	—		$	60		$	72

Facilities segment revenues	3			(1		)	1			3

Purchases and related costs	45			—			1			46

Field operating costs	—			—			1			1

Interest Rate Derivatives

Interest expense	(8		)	1			—			(7		)

Foreign Currency Derivatives

Supply and Logistics segment revenues	—			—			(1		)	(1		)

Other income/(expense), net	6			—			—			6

Total Gain/(Loss) on Derivatives Recognized in Net Income	$	58		$	—		$	62		$	120

	Year Ended December 31, 2011
	Derivatives in Hedging Relationships
Location of gain/(loss)	Gain/(loss) reclassified from AOCI into income (1)			Other gain/(loss) recognized in income			Derivatives Not Designated as a Hedge		Total
Commodity Derivatives

Supply and Logistics segment revenues	$	(153	)	$	(8	)	$	99	$	(62	)

Facilities segment revenues	11			—			—		11

Purchases and related costs	6			—			—		6

Field operating costs	—			—			1		1

Interest Rate Derivatives

Interest expense	(5		)	2			—		(3		)

Foreign Currency Derivatives

Supply and Logistics segment revenues	—			—			1		1

Other income/(expense), net	6			—			—		6

Total Gain/(Loss) on Derivatives Recognized in Net Income	$	(135	)	$	(6	)	$	101	$	(40	)

(1) During the year ended December 31, 2013, we reclassified a gain of approximately $3 million and losses of approximately $1 million from AOCI to Supply and Logistics segment revenues and Facilities segment revenues, respectively, as a result of anticipated hedged transactions that are probable of not occurring. During the year ended December 31, 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 probable of not occurring. During the year ended December 31, 2012, all of our hedged transactions were deemed probable of occurring.

The following table summarizes the derivative assets and liabilities on our Consolidated Balance Sheet on a gross basis as of December 31, 2013 (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	$	36	Other current assets	$	(24	)
	Other long-term assets	5
Interest rate derivatives	Other long-term assets	26
Total derivatives designated as hedging instruments		$	67		$	(24	)

Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	60	Other current assets	$	(117	)
	Other long-term assets	5		Other long-term assets	(6		)
	Other current liabilities	1		Other current liabilities	(5		)
				Other long-term liabilities	(1		)
Foreign currency derivatives				Other current liabilities	(4		)
Total derivatives not designated as hedging instruments		$	66		$	(133	)

Total derivatives		$	133		$	(157	)

The following table summarizes the derivative assets and liabilities on our Consolidated Balance Sheet on a gross basis as of December 31, 2012 (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	$	45	Other current assets	$	(23	)
	Other long-term assets	11		Other long-term assets	(1		)
Interest rate derivatives				Other long-term liabilities	(38		)

Total derivatives designated as hedging instruments		$	56		$	(62	)

Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	128	Other current assets	$	(115	)
	Other long-term assets	1		Other long-term assets	(3		)
	Other current liabilities	4		Other current liabilities	(7		)
	Other long-term liabilities	2		Other long-term liabilities	(2		)

Total derivatives not designated as hedging instruments		$	135		$	(127	)

Total derivatives		$	191		$	(189	)

Our derivative transactions are governed through ISDA (International Swaps and Derivatives Association) master agreements and clearing brokerage agreements. These agreements include stipulations regarding the right of set off in the event that we or our counterparty default on our performance obligations. If a default were to occur, both parties have the right to net amounts payable and receivable into a single net settlement between parties.

Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting arrangement exists. Accordingly, we also offset derivative assets and liabilities with amounts associated with cash margin. Our exchange-traded derivatives are transacted through clearing 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 December 31, 2013, we had a net broker receivable of approximately $161 million (consisting of initial margin of $85 million increased by $76 million of variation margin that had been posted by us). As of December 31, 2012, we had a net broker receivable of approximately $41 million (consisting of initial margin of $69 million reduced by $28 million of variation margin that had been returned to us).

The following tables present information about derivatives and financial assets and liabilities that are subject to offsetting, including enforceable master netting arrangements at December 31, 2013 and December 31, 2012 (in millions):

	December 31, 2013						December 31, 2012
	Derivative			Derivative			Derivative			Derivative
	Asset Positions			Liability Positions			Asset Positions			Liability Positions

Netting Adjustments:
Gross position - asset/(liability)	$	133		$	(157	)	$	191		$	(189	)
Netting adjustment	(148		)	148			(148		)	148
Cash collateral paid/(received)	161			––			41			—
Net position - asset/(liability)	$	146		$	(9	)	$	84		$	(41	)

Balance Sheet Location After Netting Adjustments:
Other current assets	$	116		$	––		$	76		$	—
Other long-term assets	30			––			8			—
Other current liabilities	––			(8		)	—			(3		)
Other long-term liabilities	––			(1		)	—			(38		)
	$	146		$	(9	)	$	84		$	(41	)

As of December 31, 2013, there was a net loss of approximately $77 million deferred in AOCI including tax effects. The 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 or (ii) interest expense accruals associated with underlying debt instruments. Of the total net loss deferred in AOCI at December 31, 2013, we expect to reclassify a net loss of approximately $10 million to earnings in the next twelve months. The remaining deferred loss of approximately $67 million is expected to be reclassified to earnings through 2045. A portion of these amounts are based on market prices as of December 31, 2013; thus, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

The net deferred gain/(loss), including tax effects, recognized in AOCI for derivatives for the three years ended December 31, 2013 are as follows (in millions):

	Year Ended December 31,
	2013		2012			2011
Commodity derivatives, net	$	38	$	56		$	(18	)
Interest rate derivatives, net	72		(13		)	(137		)
Total	$	110	$	43		$	(155	)

At December 31, 2013 and December 31, 2012, 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. Although we may be required to post margin on our cleared derivatives as described above, we do not require our non-cleared derivative counterparties to post collateral with us.

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 December 31, 2013 and December 31, 2012 (in millions):

	Fair Value as of December 31, 2013											Fair Value as of December 31, 2012
Recurring Fair Value Measures (1)	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total
Commodity derivatives	$	16	$	(59	)	$	(3	)	$	(46	)	$	1	$	35		$	4	$	40
Interest rate derivatives	—		26			—			26			—		(38		)	—		(38		)
Foreign currency derivatives	—		(4		)	—			(4		)	—		—			—		—
Total net derivative asset/(liability)	$	16	$	(37	)	$	(3	)	$	(24	)	$	1	$	(3	)	$	4	$	2

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

Level 1

Level 1 of the fair value hierarchy includes exchange-traded commodity derivatives such as futures and options. 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 Asset/ (Liability)

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

	Year Ended December 31,
	2013			2012
Beginning Balance	$	4		$	12
Total gains/(losses) for the period:
Included in earnings (1)	(1		)	(3		)
Included in other comprehensive income	—			3
Settlements	(3		)	(22		)
Derivatives entered into during the period	(3		)	23
Transfers out of level 3	—			(9		)
Ending Balance	$	(3	)	$	4

Change in unrealized gains/(losses) included in earnings relating to level 3 derivatives still held at the end of the periods	$	(4	)	$	24

(1) We reported unrealized gains and losses associated with level 3 commodity derivatives in our Consolidated Statements of Operations as Supply and Logistics segment revenues.

During the third quarter of 2012, we transferred commodity derivatives with an aggregate fair value of a $14 million gain 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.

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.

- Definition

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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Reference 14: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Income Taxes

12 Months Ended

Dec. 31, 2013

Income Taxes

Income Taxes

Note 12—Income Taxes

We estimate (i) income taxes in the jurisdictions in which we operate, (ii) net deferred tax assets and liabilities based on temporary differences that are expected to be recovered or settled at the enacted tax rates expected in future periods, (iii) valuation allowances for deferred tax assets and (iv) contingent tax liabilities for estimated exposures related to our current tax positions.

Pursuant to FASB guidance related to accounting for uncertainty in income taxes, we must recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the tax position and also the past administrative practices and precedents of the taxing authority. As of December 31, 2013 and 2012, we had not recognized any material amounts in connection with uncertainty in income taxes.

U.S. Federal and State Taxes

Although we are organized as a limited partnership, we have elected to be treated as a corporation for U.S. federal income tax purposes and are therefore subject to both U. S. federal and state income taxes.

Canadian Federal and Provincial Taxes

All of our Canadian operations are conducted within entities that are treated as corporations for Canadian tax purposes (flow through for U.S. tax purposes) and that are subject to Canadian federal and provincial taxes. Additionally, payments of interest and dividends from our Canadian entities to other Plains entities are subject to Canadian withholding tax that is treated as income tax expense.

Tax Components

Components of income tax expense are as follows (in millions):

	Year Ended December 31,
	2013			2012		2011
Current tax expense:
State income tax	$	1		$	2	$	2
Canadian federal and provincial income tax	99			52		36
Total current tax expense	$	100		$	54	$	38

Deferred tax (benefit)/expense:
Federal income tax	$	7		$	—	$	—
State income tax	––			––		(2		)
Canadian federal and provincial income tax	(1		)	1		9
Total deferred tax (benefit)/expense	$	6		$	1	$	7
Total income tax expense	$	106		$	55	$	45

The difference between tax expense based on the statutory federal income tax rate and our effective tax expense is summarized as follows (in millions):

	Year Ended December 31,
	2013			2012			2011
Income before tax	$	1,480		$	1,173		$	1,032
Net income attributable to noncontrolling interest	(1,359		)	(1,115		)	(985		)
Income taxes attributable to noncontrolling interest	(99		)	(55		)	(45		)
	$	22		$	3		$	2
Federal statutory income tax rate	35		%	0		%	0		%
Income tax at statutory rate	$	8		$	—		$	—

Federal benefit of state income taxes	$	(1	)	$	—		$	—
Income taxes attributable to noncontrolling interest:
Canadian federal and provincial income taxes	79			35			33
Canadian withholding taxes	19			18			12
State income tax	1			2			—
Total income tax expense	$	106		$	55		$	45

Deferred tax assets and liabilities are aggregated by the applicable tax paying entity and jurisdiction and presented in “Other long-term assets” and net in “Other long-term liabilities and deferred credits” on our Consolidated Balance Sheet and result from the following (in millions):

	December 31,
	2013			2012
Deferred tax assets:
Investment in partnerships	$	1,057		$	—
Net operating losses	11			—
Book accruals in excess of current tax deductions	56			28
Total deferred tax assets	1,124			28

Deferred tax liabilities:
Property and equipment in excess of tax values	(398		)	(397		)
Total deferred tax liabilities	(398		)	(397		)
Net deferred tax assets / (liabilities)	$	726		$	(369	)

Balance sheet classification of deferred tax assets / (liabilities):
Other long-term assets	$	1,068		$	—
Other long-term liabilities and deferred credits	(342		)	(369		)
	$	726		$	(369	)

In connection with the transfer of the ownership interest in AAP in connection with our IPO in October 2013 and any subsequent transfers in 2013, a deferred tax asset was created. These transfers were accounted for at the historical carrying basis for U.S. GAAP accounting purposes, but were recorded at the value of the consideration paid for U.S. federal income tax purposes. The resulting basis difference resulted in a deferred tax asset that was recorded as a component of partners’ capital as it results from transactions among shareholders. The deferred tax asset is amortized to deferred income tax expense as the associated basis step-up is realized on our tax returns.

Generally, tax returns for our Canadian entities are open to audit from 2009 through 2013. Our U.S. and state tax years are generally open to examination from 2010 to 2013.

Major Customers and Concentration of Credit Risk	12 Months Ended
Major Customers and Concentration of Credit Risk	Dec. 31, 2013
Major Customers and Concentration of Credit Risk
Major Customers and Concentration of Credit Risk	Note 13—Major Customers and Concentration of Credit Risk Marathon Petroleum Corporation and its subsidiaries accounted for approximately 15% of our revenues for the year ended December 31, 2013 and approximately 16% of our revenues for each of the years ended December 31, 2012 and 2011. ExxonMobil Corporation and its subsidiaries accounted for approximately 13%, 13% and 10% of our revenues for the years ended December 31, 2013, 2012 and 2011, respectively. Phillips 66 and its subsidiaries accounted for approximately 11% of our revenues for the year ended December 31, 2013. ConocoPhillips Company (prior to the spin-off of Phillips 66, which was effective May 1, 2012) accounted for approximately 10% of our revenues for the year ended December 31, 2011. No other customers accounted for 10% or more of our revenues during any of the three years ended December 31, 2013. The majority of revenues from these customers pertain to our supply and logistics operations. The sales to these customers occur at multiple locations and we believe that the loss of these customers would have only a short-term impact on our operating results. There is risk, however, that we would not be able to identify and access a replacement market at comparable margins. Financial instruments that potentially subject us to concentrations of credit risk consist principally of trade receivables. Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL and natural gas storage. This industry concentration has the potential to impact our overall exposure to credit risk in that the customers may be similarly affected by changes in economic, industry or other conditions. We review credit exposure and financial information of our counterparties and generally require letters of credit for receivables from customers that are not considered creditworthy, unless the credit risk can otherwise be reduced. See Note 2 for additional discussion of our accounts receivable and our review of credit exposure.

Related Party Transactions

12 Months Ended

Dec. 31, 2013

Related Party Transactions

Related Party Transactions

Note 14—Related Party Transactions

Occidental Petroleum Corporation

As of December 31, 2013, a subsidiary of Occidental Petroleum Corporation (“Oxy”) owned approximately 25% of the limited partner interests in AAP and had a representative on the board of directors of GP LLC and our general partner. During the three years ended December 31, 2013, 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):

	Year Ended December 31,
	2013		2012		2011
Revenues	$	1,309	$	1,636	$	2,568

Purchases and related costs	$	863	$	557	$	361

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

	December 31,
	2013		2012
Trade accounts receivable and other receivables	$	133	$	231

Accounts payable	$	181	$	129

Other

We also have transactions with companies in which we hold an investment accounted for under the equity method of accounting (see Note 2 for information related to these investments). We recorded revenues of approximately $33 million and $18 million during the years ended December 31, 2013 and 2012, respectively, primarily associated with sales of crude oil to Eagle Ford Pipeline LLC for its linefill requirements. These sales did not result in any gain for us. Revenues from transactions with our equity method investees in 2011 were immaterial. During the three years ended December 31, 2013, we utilized transportation services provided by these companies. Costs related to these services totaled approximately $79 million, $42 million and $33 million for the years ended December 31, 2013, 2012 and 2011, respectively. These transactions were conducted at posted tariff rates or contracted rates or prices that we believe approximate market. Receivables from our equity method investees totaled approximately $2 million and $8 million at December 31, 2013 and 2012, respectively. Accounts payable to our equity method investees at December 31, 2013 and 2012 were approximately $6 million and $4 million, respectively.

- Definition

The entire disclosure for related party transactions. Examples of related party transactions include transactions between (a) a parent company and its subsidiary; (b) subsidiaries of a common parent; (c) and entity and its principal owners; and (d) affiliates.

+ References + Details

Equity-Indexed Compensation Plans

12 Months Ended

Dec. 31, 2013

Equity-Indexed Compensation Plans

Equity-Indexed Compensation Plans

Note 15—Equity-Indexed Compensation Plans

Plains GP Holdings, L.P. Long-Term Incentive Plan

In connection with our IPO in October 2013, our general partner adopted the Plains GP Holdings, L.P. Long-Term Incentive Plan (the “PAGP LTIP”), which is intended to align the interests of employees and directors with those of our shareholders by providing such employees and directors incentive compensation awards that reward achievement of targeted distribution levels and other business objectives. The PAGP LTIP provides for awards of options, restricted shares, phantom shares and share appreciation rights. Certain awards may also include distribution equivalent rights (“DERs”), which, subject to applicable vesting criteria, entitle the grantee to a cash payment equal to the cash distribution paid on an outstanding Class A Share. The PAGP LTIP authorizes the issuance of up to 10 million Class A Shares deliverable upon vesting. As of December 31, 2013, no grants or awards had been issued or were outstanding under the PAGP LTIP; however, three of our directors received PAGP LTIP awards for an aggregate of 83,200 phantom Class A shares in February 2014.

PAA Long-Term Incentive Plan Awards

Plains All American 2013 Long-Term Incentive Plan. In November 2013, PAA’s common unitholders approved the Plains All American 2013 Long-Term Incentive Plan (the “PAA 2013 LTIP”), which consolidated PAA’s three previous long-term incentive plans (the Plains All American GP LLC 1998 Long-Term Incentive Plan, as amended, the Plains All American 2005 Long-Term Incentive Plan, as amended, and the Plains All American PPX Successor Long-Term Incentive Plan, as amended) into a single plan. The PAA 2013 LTIP authorizes the issuance of an aggregate of approximately 13.1 million PAA common units deliverable upon vesting. Although other types of awards are contemplated under the PAA 2013 LTIP, currently outstanding awards are limited to “phantom units,” which mature into the right to receive common units of PAA (or cash equivalent) upon vesting. Some awards also include DERs, which, subject to applicable vesting criteria, entitle the grantee to a cash payment equal to the cash distribution paid on an outstanding PAA common unit.

Plains All American PNG Successor Long-Term Incentive Plan. In conjunction with the PNG Merger on December 31, 2013, PAA’s general partner adopted and assumed the PAA Natural Gas Storage, L.P. 2010 Long-Term Incentive Plan (the “PNG 2010 LTIP”) and changed the plan name to the Plains All American PNG Successor Long-Term Incentive Plan (the “PNG Successor LTIP”). Additionally, as a result of the PNG Merger, outstanding awards of PNG phantom units issued under the PNG 2010 LTIP were converted into comparable awards of phantom units representing the right to receive PAA common units by applying the Merger Exchange Ratio to each outstanding phantom unit and rounding down to the nearest PAA phantom unit for any fractions. See Note 10 for further discussion of the PNG Merger. The PNG Successor LTIP authorizes the issuance of an aggregate of 1.3 million PAA common units deliverable upon vesting. Although other types of awards are contemplated under the PNG Successor LTIP, currently outstanding awards are limited to “phantom units,” which mature into the right to receive common units of PAA (or cash equivalent) upon vesting. Some awards also include DERs, which, subject to applicable vesting criteria, entitle the grantee to a cash payment equal to the cash distribution paid on an outstanding PAA common unit.

Plains All American GP LLC 2006 Long-Term Incentive Tracking Unit Plan. PAA’s general partner has adopted the Plains All American GP LLC 2006 Long-Term Incentive Tracking Unit Plan (the “2006 Plan”) for non-officer employees. The 2006 Plan authorizes the grant of approximately 4.2 million “tracking units” which, upon vesting, represent the right to receive a cash payment in an amount based upon the market value of a PAA common unit at the time of vesting.

At December 31, 2013, the following LTIP awards, denominated in PAA units, were outstanding (units in millions):

PAA

LTIP Units

Distribution

Estimated Unit Vesting Date

Outstanding (1) (2)

Required (3)

2014

2015

2016

2017

Thereafter

8.4

$1.925 - $2.65

1.9

2.1

2.0

1.3

1.1

(1) Approximately 4.5 million of the 8.4 million outstanding PAA LTIP awards also include DERs, of which 3.0 million had vested as of December 31, 2013.

(2) LTIP units outstanding do not include AAP Management Units.

(3) These LTIP awards have performance conditions requiring the attainment of an annualized PAA distribution of between $1.925 and $2.65 and vest upon the later of a certain date or the attainment of such levels. If the performance conditions are not attained while the grantee remains employed by us, or the grantee does not meet employment requirements, these awards will be forfeited. For purposes of this disclosure, vesting dates are based on an estimate of future distribution levels and assume that all grantees remain employed by us through the vesting date.

PAA’s LTIP awards include both liability-classified and equity-classified awards. In accordance with FASB guidance regarding share-based payments, the fair value of liability-classified LTIP awards is calculated based on the closing market price of the underlying PAA unit at each balance sheet date and adjusted for the present value of any distributions that are estimated to occur on the underlying units over the vesting period that will not be received by the award recipients. The fair value of equity-classified LTIP awards is calculated based on the closing market price of the PAA unit on the respective grant dates and adjusted for the present value of any distributions that are estimated to occur on the underlying units over the vesting period that will not be received by the award recipient. This fair value is recognized as compensation expense over the service period.

PAA’s LTIP awards typically contain performance conditions based on the attainment of certain PAA annualized distribution levels and vest upon the later of a certain date or the attainment of such levels. For awards with performance conditions (such as distribution targets), expense is accrued over the service period only if the performance condition is considered to be probable of occurring. When awards with performance conditions that were previously considered improbable become probable, we incur additional expense in the period that the probability assessment changes. This is necessary to bring the accrued obligation associated with these awards up to the level it would be as if we had been accruing for these awards since the grant date. DER awards typically contain performance conditions based on the attainment of certain annualized distribution levels and become earned upon the attainment of such levels. The DERs terminate with the vesting or forfeiture of the underlying LTIP award. For liability-classified awards, we recognize DER payments in the period the payment is earned as compensation expense. For equity-classified awards, we recognize DER payments in the period it is paid as a reduction of noncontrolling interest in partners’ capital.

Our accrued liability at December 31, 2013 related to all outstanding liability-classified PAA LTIP awards and DERs is approximately $98 million, of which approximately $43 million was classified as short-term and approximately $55 million was classified as long-term. These short- and long-term accrued LTIP liabilities are reflected in “Accounts payable and accrued liabilities” and “Other long-term liabilities and deferred credits,” respectively, on our Consolidated Balance Sheet. These liabilities include accruals associated with our assessments that an annualized PAA distribution of $2.75 was probable of occurring. At December 31, 2012, the accrued liability was approximately $90 million.

Equity-indexed compensation activity for LTIP awards is summarized in the following table (units in millions):

	PAA Units (1) (3)				PNG Units (2) (4)
			Weighted Average				Weighted Average
			Grant Date				Grant Date
	Units		Fair Value per Unit		Units		Fair Value per Unit
Outstanding, December 31, 2010	8.8		$	20.85	1.0		$	20.55
Granted	1.0		$	27.53	—		$	—
Vested	(1.4	)	$	20.34	(0.1	)	$	23.62
Cancelled or forfeited	(0.4	)	$	20.99	(0.1	)	$	19.20
Outstanding, December 31, 2011	8.0		$	21.77	0.8		$	20.55
Granted	1.5		$	33.90	0.1		$	15.33
Vested	(3.2	)	$	19.82	—		$	23.64
Cancelled or forfeited	(0.3	)	$	29.36	—		$	—
Outstanding, December 31, 2012	6.0		$	25.55	0.9		$	17.49
Granted	4.1		$	47.60	0.4		$	17.51
Vested	(1.8	)	$	24.79	—		$	18.88
Cancelled or forfeited (5)	(0.3	)	$	36.70	(0.3	)	$	21.62
Conversion of PNG unit-denominated awards into PAA unit-denominated awards (6)	0.4		$	40.54	(1.0	)	$	16.41
Outstanding, December 31, 2013	8.4		$	36.97	—		$	—

(1) Amounts do not include AAP Management Units.

(2) Amounts include PNG Transaction Grants, which are discussed further below.

(3) Approximately 0.5 million, 1.0 million, and 0.5 million PAA common units were issued net of tax withholding of approximately 0.3 million, 0.5 million and 0.2 million units, in 2013, 2012, and 2011 respectively, in connection with the settlement of vested awards. The remaining 1.0 million, 1.7 million and 0.8 million of awards that vested during 2013, 2012 and 2011 respectively, were settled in cash.

(4) Less than 0.1 million PNG units vested during each of the years ended December 31, 2013 and December 31, 2012.

(5) As a result of the PNG Merger on December 31, 2013, approximately 0.3 million outstanding PNG Transaction Grants were cancelled.

(6) As a result of the PNG Merger on December 31, 2013, outstanding awards of PNG phantom units were converted into comparable awards of PAA phantom units representing the right to receive PAA common units by applying the Merger Exchange Ratio to each outstanding PNG phantom unit and rounding down to the nearest PAA phantom unit for any fractions.

PNG Transaction Grants

In connection with the IPO of PNG in 2010, PAA created a plan based on PNG equity. In September 2010, PAA entered into agreements with certain of its officers, pursuant to which these officers acquired in equal proportion, phantom common units, phantom series A subordinated units, and phantom series B subordinated units representing a portion of the limited partner interests of PNG issued to PAA in connection with PNG’s IPO. The phantom common units vested in equal one-half increments in May 2011 and May 2012. The unvested portion of these grants were surrendered on December 31, 2013 in connection with the closing of the PNG Merger.

AAP Management Units

In August 2007, the owners of AAP authorized the issuance of AAP Management Units in order to provide additional performance incentives and encourage retention for certain members of our senior management. AAP Management Units become earned in various increments upon the achievement of PAA distribution levels of between $1.75 and $2.85 (or in some cases, within 180 days thereafter). When earned, the AAP Management Units are entitled to participate in distributions paid by AAP in excess of $11 million (as adjusted for debt service costs and excluding special distributions funded by debt) per quarter. Up to approximately 52.1 million AAP Management Units are authorized for issuance. Assuming all 52.1 million AAP Management Units were granted and earned, the maximum participation would be approximately 8% of AAP’s distribution in excess of $11 million (as adjusted) each quarter.

Additionally, if our Class A shares are publicly traded at any time after December 31, 2015, a holder of vested AAP Management Units will be entitled to exchange his or her AAP Management Units for AAP units and a like number of our Class B shares based on a conversion ratio calculated in accordance with the AAP limited partnership agreement. Following any such exchange, the holder will have the Exchange Right for our Class A shares. See Note 10 for additional information.

As a result of the recapitalization of AAP in connection with our IPO on October 21, 2013, the number of AAP Management Units reserved for future grants, outstanding and earned were adjusted on a proportionate basis. The adjustment did not result in a change in vesting criteria, service period, or total grant date fair value. This adjustment is reflected retrospectively in the following summary of AAP Management Units (in millions):

	Reserved for Future Grants		Outstanding		Outstanding Units Earned	Grant Date Fair Value Of Outstanding AAP Management Units (1)
Balance as of December 31, 2011	4.3		47.8		20.9	$	44
Forfeitures	0.4		(0.4	)	—	—
Earned	N/A		N/A		13.1	N/A
Balance as of December 31, 2012	4.7		47.4		34.0	$	44
Granted	(1.2	)	1.2		—	7
Earned	N/A		N/A		13.0	N/A
Balance as of December 31, 2013	3.5		48.6		47.0	$	51

(1) Of the grant date fair value, approximately $5 million, $6 million and $9 million was recognized as expense during the years ended December 31, 2013, 2012 and 2011, respectively. Of the $51 million grant date fair value, approximately $49 million had been recognized through December 31, 2013.

As the intent of the AAP Management Units is to provide a performance incentive and encourage retention for certain members of PAA’s senior management we recognize the grant date fair value of the AAP Management Units as compensation expense over the service period, with a corresponding credit to noncontrolling interest in partners’ capital on our Consolidated Financial Statements.

Other Consolidated Equity-Indexed Compensation Information

We refer to all of the LTIPs and AAP Management Units collectively as the “Equity-indexed compensation plans.” The table below summarizes the expense recognized and the value of vesting (settled both in units and cash) related to the equity-indexed compensation plans and includes both liability-classified and equity-classified awards (in millions):

	2013		2012		2011
Equity-indexed compensation expense	$	116	$	101	$	110
LTIP unit-settled vestings (1)	$	48	$	62	$	24
LTIP cash-settled vestings	$	61	$	66	$	19
DER cash payments	$	8	$	7	$	4

(1) For the years ended December 31, 2013, 2012 and 2011, less than $1 million, approximately $1 million and $2 million, respectively, relates to unit vestings which were settled with PNG common units.

Based on the December 31, 2013 fair value measurement and probability assessment regarding future distributions, we expect to recognize approximately $193 million of additional expense over the life of outstanding awards related to the remaining unrecognized fair value. Actual amounts may differ materially as a result of a change in the market price of PAA’s units and/or probability assessments regarding future distributions. We estimate that the remaining fair value will be recognized in expense as shown below (in millions):

Year	Equity-Indexed Compensation Plan Fair Value Amortization (1) (2)
2014	$	80
2015	55
2016	36
2017	16
2018	5
Thereafter	1
Total	$	193

(1) Amounts do not include fair value associated with awards containing performance conditions that are not considered to be probable of occurring at December 31, 2013.

(2) Includes unamortized fair value associated with AAP Management Units.

Commitments and Contingencies

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies

Commitments and Contingencies

Note 16—Commitments and Contingencies

Commitments

Expenditures related to leases for 2013, 2012 and 2011 were approximately $132 million, $102 million and $60 million, respectively. We have commitments, some of which are leases, related to real property, equipment and operating facilities. We also incur costs associated with leased land, rights-of-way, permits and regulatory fees. Future non-cancelable commitments related to these items at December 31, 2013, are summarized below (in millions):

	2014		2015		2016		2017		2018		Thereafter		Total
Leases (1)	$	152	$	132	$	124	$	103	$	78	$	386	$	975
Other commitments (2)	38		32		29		25		16		42		182
Total	$	190	$	164	$	153	$	128	$	94	$	428	$	1,157

(1) Includes capital and operating leases as defined by the FASB guidance.

(2) Primarily includes third-party storage and transportation agreements and pipeline throughput agreements.

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 material 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 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.

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. In February 2013, the Court granted Plains Marketing, L.P.’s motion to be dismissed from the April 2012 lawsuit. In October 2013, the Court issued an order in the May 2011 lawsuit granting summary judgment in favor of Plains Marketing, L.P. with respect to all of PEP’s remaining claims against Plains Marketing, L.P. In February 2014, the Court affirmed its order granting summary judgment in favor of Plains Marketing, L.P., denied PEP’s motion for reconsideration, and issued a judgment dismissing all claims against Plains. PEP has the right to appeal such rulings.

PNG Merger. Purported class action lawsuits were filed on behalf of PNG unitholders challenging the PNG Merger. Two lawsuits were filed in the Delaware Court of Chancery in September 2013 and were consolidated under the caption In re PAA Natural Gas Storage, Limited Partnership Unitholder Litigation, C.A. No. 8908-VCL (which we refer to as the Consolidated Delaware Action). Two lawsuits were filed in Texas state court in September 2013 and were consolidated under the caption Vicars v. PNGS GP, LLC, et al., Cause No. 2013-52687 (Tex. Dist. Ct. Harris County) (which we refer to as the Consolidated Texas Action). Four lawsuits were filed in Texas federal court in October 2013 and were consolidated under the caption The DuckPond Trust, et al., v. PAA Natural Gas Storage, LP., et al., 4:13-cv-03170 (S.D. Tex.) (which we refer to as the Consolidated Federal Action).

Plaintiffs in the Consolidated Delaware Action generally allege that (i) the individual defendants breached fiduciary duties owed to PNG unitholders by allegedly approving the merger agreement at an unfair price and through an unfair process and by agreeing to certain deal protection devices; and (ii) the PNG Merger unfairly benefits certain members of PNG’s board of directors. Plaintiffs also allege that PNG’s general partner, PNG and other of our affiliates aided and abetted the alleged fiduciary breaches by the individual defendants.

Plaintiffs in the Consolidated Texas Action generally allege that (i) the individual defendants breached their duties owed to PNG’s unitholders under PNG’s partnership agreement as well as the implied covenant of good faith and fair dealing, and are engaging in self-dealing; and (ii) PNG’s general partner, PNG and other of our affiliates have aided and abetted the defendant directors for the purpose of advancing their own interests and/or assisting such directors in connection with their breaches of their respective duties. In addition, the Consolidated Texas Action includes purported derivative claims on behalf of PNG based on the alleged breaches of duties by the individual defendants.

In February 2014, the Consolidated Federal Action was dismissed. Plaintiffs in the remaining actions generally seek, among other relief, to enjoin the transaction, rescission in the event the transaction is consummated, an order directing defendants to account to plaintiff and other members of the putative class for all damages caused by their breaches, money damages and an award of costs and disbursements, including reasonable attorneys’ fees. We cannot predict the outcome of these or any other lawsuits that might be filed, nor can we predict the amount of time and expense that will be required to resolve these lawsuits. We intend to defend vigorously against these and any other actions. See Note 1 for a description of the PNG Merger.

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 surface water bodies, groundwater aquifers or other sensitive environments. Whether current or past, damages and liabilities associated with any such releases from our assets may substantially affect our business.

We record environmental liabilities when environmental assessments and/or remedial efforts are probable and the amounts can be reasonably estimated. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We do not discount our environmental remediation liabilities to present value. We also record environmental liabilities assumed in business combinations based on the estimated fair value of the environmental obligations caused by past operations of the acquired company. We record receivables for amounts recoverable from insurance or from third parties under indemnification agreements in the period that we determine the costs are probable of recovery.

Environmental expenditures that pertain to current operations or to future revenues are expensed or capitalized consistent with our capitalization policy for property and equipment. Expenditures that result from the remediation of an existing condition caused by past operations and that do not contribute to current or future profitability are expensed.

At December 31, 2013, our estimated undiscounted reserve for environmental liabilities totaled approximately $93 million, of which approximately $11 million was classified as short-term and approximately $82 million was classified as long-term. At December 31, 2012, our reserve for environmental liabilities totaled approximately $96 million, of which approximately $13 million was classified as short-term and approximately $83 million was classified as long-term. The short- and long-term environmental liabilities referenced above are reflected in “Accounts payable and accrued liabilities” and “Other long-term liabilities and deferred credits,” respectively, on our Consolidated Balance Sheets. At December 31, 2013 and 2012, we had recorded receivables totaling approximately $10 million and $42 million, respectively, for amounts probable of recovery under insurance and from third parties under indemnification agreements, which are predominantly reflected in “Trade accounts receivable and other receivables, net” on our Consolidated Balance Sheets.

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.

Rainbow Pipeline Release. During April 2011, we experienced a crude oil release of approximately 28,000 barrels of crude oil on a remote section of our Rainbow Pipeline located in Alberta, Canada. Since the release and through December 31, 2013, we spent approximately $70 million, before insurance recoveries, in connection with site clean-up, reclamation and remediation activities, and as of December 31, 2013, we did not have any material outstanding liabilities or insurance receivables relating to this release. On February 26, 2013, the Alberta Energy Regulator (“AER”) issued a report detailing four enforcement actions against Plains Midstream Canada ULC (“PMC”) for failure to comply with certain regulatory requirements in connection with the release, including requirements related to operations and maintenance procedures, leak detection and response, backfill and compaction procedures and emergency response plan testing. PMC is in the process of taking appropriate actions necessary to respond to and comply with the enforcement actions set forth in the report, including the implementation of additional risk assessment procedures and the taking of other actions designed to minimize the risk that similar incidents occur in the future and enhance the effectiveness of PMC’s response to any such future incidents. In addition, on April 23, 2013, the Alberta Crown Prosecutor filed civil charges under the Environmental Protection and Enhancement Act against PMC relating to the release. To date, PMC has not been assessed any fines or penalties related to this release; however, such fines or penalties may be assessed in the future and are not expected to be material.

Rangeland Pipeline Release. During June 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. Remediation activities in the reservoir area were completed by June 30, 2012, remediation of the remaining impacted areas of government-owned lands was completed by September 30, 2012 and interim closure, in respect of those lands, was received from the applicable regulatory agencies. Monitoring will continue into 2014, and a long-term monitoring plan has been developed and implemented in accordance with regulatory requirements. Through December 31, 2013, we spent approximately $46 million, before insurance recoveries, in connection with site clean-up, reclamation and remediation activities. This release is currently under investigation by the AER, which also intends to perform an audit of PMC’s operations. Although the AER’s final investigation is not complete, on July 4, 2013, the AER issued four enforcement actions against PMC citing failure to inspect water crossings, failure to complete an engineering assessment to determine suitability of continued operation of the Rangeland Pipeline, failure to maintain updated emergency response plans, and failure to conduct regular public awareness programs. To date, no fines or penalties have been assessed against PMC with respect to this release; however, it is possible that fines or penalties may be assessed against PMC in the future and are not expected to be material.

Bay Springs Pipeline Release During February 2013, we experienced a crude oil release of approximately 120 barrels on a portion of one of our pipelines near Bay Springs, Mississippi. Most of the released oil was contained within our pipeline right of way, but some of the released oil entered a nearby waterway where it was contained with booms. The EPA has issued an administrative order requiring us to take various actions in response to the release, including remediation, reporting and other actions, and we may be subjected to a civil penalty. The aggregate cost to clean up and remediate the site was approximately $6 million, which has been recognized in “Field operating costs” on our Consolidated Statement of Operations.

Kemp River Pipeline Release. During May and June 2013, two separate releases were discovered on our Kemp River pipeline in Northern Alberta, Canada that, in the aggregate, resulted in the release of approximately 700 barrels of condensate and light crude oil. Clean-up and remediation activities are being conducted in cooperation with the applicable regulatory agencies. We estimate that the aggregate clean-up and remediation costs associated with these releases will be approximately $15 million which we have recognized in “Field operating costs” on our Consolidated Statement of Operations.

Environmental Remediation

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

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

Assets we have acquired or will acquire in the future may have environmental remediation liabilities for which we are not indemnified. We have in the past experienced and in the future likely will experience releases of crude oil into the environment from our pipeline and storage operations. We also may discover environmental impacts from past releases that were previously unidentified.

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, costs have increased substantially and deductibles have increased as well.

In 2011, we elected not to renew our hurricane insurance, and, instead, to 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. This decision does not affect our third-party liability insurance, which still covers hurricane-related liability claims 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.

Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2013

Quarterly Financial Data (Unaudited)

Quarterly Financial Data (Unaudited)

Note 17—Quarterly Financial Data (Unaudited)

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter		Total (1)
	(in millions, except per share data)
2013
Revenues	$	10,620	$	10,295	$	10,703	$	10,631	$	42,249
Gross margin (2)	$	761	$	474	$	375	$	476	$	2,084
Operating income	$	655	$	383	$	296	$	391	$	1,724
Net income	$	535	$	299	$	236	$	305	$	1,374
Net income attributable to PAGP	$	1	$	1	$	1	$	12	$	15
Basic and diluted net income per Class A share (3)	N/A		N/A		N/A		$	0.10	$	0.10

2012
Revenues	$	9,218	$	9,786	$	9,354	$	9,439	$	37,797
Gross margin (2)	$	407	$	551	$	328	$	479	$	1,766
Operating income	$	313	$	462	$	247	$	401	$	1,424
Net income	$	234	$	384	$	171	$	327	$	1,118
Net income attributable to PAGP	$	—	$	1	$	1	$	1	$	3

(1) The sum of the four quarters may not equal the total year due to rounding.

(2) Gross margin is calculated as Total revenues less (i) Purchases and related costs, (ii) Field operating costs and (iii) Depreciation and amortization.

(3) Calculated based on net income attributable to PAGP for the period following the closing of our IPO on October 21, 2013 and basic weighted average number of Class A shares outstanding weighted for the same period.

Operating Segments

12 Months Ended

Dec. 31, 2013

Operating Segments

Operating Segments

Note 18—Operating Segments

We manage our operations through three operating segments: (i) Transportation, (ii) Facilities and (iii) Supply and Logistics. See “Revenue Recognition” in Note 2 for a summary of the types of products and services from which each segment derives its revenues.

Our Chief Operating Decision Maker (our Chief Executive Officer) evaluates segment performance based on measures including segment profit and maintenance capital investment. We define segment profit as revenues and equity earnings in unconsolidated entities less (i) purchases and related costs, (ii) field operating costs and (iii) segment general and administrative expenses. Each of the items above excludes depreciation and amortization.

We look at each period’s earnings before non-cash depreciation and amortization as an important measure of segment performance. The exclusion of depreciation and amortization expense could be viewed as limiting the usefulness of segment profit as a performance measure because it does not account in current periods for the implied reduction in value of our capital assets, such as crude oil pipelines and facilities, caused by age-related decline and wear and tear. We compensate for this limitation by recognizing that depreciation and amortization are largely offset by repair and maintenance investments, which acts to partially offset the aging and wear and tear in the value of our principal fixed assets. These maintenance investments are a component of field operating costs included in segment profit or in maintenance capital, depending on the nature of the cost. Maintenance capital consists of capital expenditures for the replacement of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets. Capital expenditures made to expand the existing operating and/or earnings capacity of our assets are considered expansion capital expenditures, not maintenance capital. Repair and maintenance expenditures incurred in order to maintain the day to day operation of our existing assets are charged to expense as incurred.

The following table reflects certain financial data for each segment for the periods indicated (in millions):

	Transportation		Facilities		Supply and Logistics		Total
Twelve Months Ended December 31, 2013
Revenues:
External Customers	$	701	$	856	$	40,692	$	42,249
Intersegment (1)	797		521		4		1,322
Total revenues of reportable segments	$	1,498	$	1,377	$	40,696	$	43,571
Equity earnings in unconsolidated entities	$	64	$	—	$	—	$	64
Segment profit (2) (3)	$	729	$	616	$	822	$	2,167
Capital expenditures	$	1,046	$	549	$	46	$	1,641
Total assets	$	7,767	$	6,741	$	6,945	$	21,453
Maintenance capital	$	123	$	38	$	15	$	176

Twelve Months Ended December 31, 2012
Revenues:
External Customers	$	623	$	736	$	36,438	$	37,797
Intersegment (1)	793		362		2		1,157
Total revenues of reportable segments	$	1,416	$	1,098	$	36,440	$	38,954
Equity earnings in unconsolidated entities	$	38	$	—	$	—	$	38
Segment profit (2) (3)	$	710	$	482	$	753	$	1,945
Capital expenditures	$	1,244	$	1,724	$	503	$	3,471
Total assets	$	6,447	$	6,134	$	6,678	$	19,259
Maintenance capital	$	108	$	49	$	13	$	170

Twelve Months Ended December 31, 2011
Revenues:
External Customers	$	572	$	638	$	33,065	$	34,275
Intersegment (1)	593		158		3		754
Total revenues of reportable segments	$	1,165	$	796	$	33,068	$	35,029
Equity earnings in unconsolidated entities	$	13	$	—	$	—	$	13
Segment profit (2) (3)	$	555	$	358	$	647	$	1,560
Capital expenditures	$	600	$	1,317	$	18	$	1,935
Total assets	$	5,189	$	4,506	$	5,719	$	15,414
Maintenance capital	$	86	$	22	$	12	$	120

(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.

(2) Supply and Logistics segment profit includes interest expense (related to hedged inventory purchases) of approximately $30 million, $12 million and $20 million for the years ended December 31, 2013, 2012 and 2011, respectively.

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

	Year Ended December 31,
	2013			2012			2011
Segment profit	$	2,167		$	1,945		$	1,560
Unallocated general and administrative expenses	(1		)	—			—
Depreciation and amortization	(378		)	(483		)	(250		)
Interest expense	(309		)	(295		)	(259		)
Other income/(expense), net	1			6			(19		)
Income tax expense	(106		)	(55		)	(45		)
Net income	1,374			1,118			987
Net income attributable to noncontrolling interests	(1,359		)	(1,115		)	(985		)
Net income attributable to PAGP	$	15		$	3		$	2

Geographic Data

We have operations in the United States and Canada. Set forth below are revenues and long-lived assets attributable to these geographic areas (in millions):

	Year Ended December 31,
Revenues (1)	2013		2012		2011
United States	$	32,924	$	29,978	$	28,181
Canada	9,325		7,819		6,094
	$	42,249	$	37,797	$	34,275

(1) Revenues are primarily attributed to each region based on where the services are provided or the product is shipped.

	December 31,
Long-Lived Assets (1)	2013		2012
United States	$	12,835	$	10,423
Canada	3,623		3,677
	$	16,458	$	14,100

(1) Excludes long-term derivative assets.

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8933-108599

Reference 7: http://www.xbrl.org/2003/role/presentationRef
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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-Publisher FASB
-Name Accounting Standards Codification
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-SubTopic 10
-Section 50
-Paragraph 42
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e9054-108599

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-Name Accounting Standards Codification
-Topic 280
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-Name Accounting Standards Codification
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+ Details

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Summary of Significant Accounting Policies

Basis of Consolidation and Presentation

Basis of Consolidation and Presentation

These financials include PAGP and all of our wholly owned subsidiaries and those entities that we control. Under GAAP, we consolidate PAA, AAP and GP LLC. Amounts associated with the interests in these entities not owned by us are reflected in our results of operations as net income attributable to noncontrolling interests and in our balance sheet partners’ capital section as noncontrolling interests.

Use of Estimates

Use of Estimates

Revenue Recognition

Revenue Recognition

Purchases and Related Costs

Purchases and Related Costs

Field Operating Costs and General and Administrative Expenses

Field Operating Costs and General and Administrative Expenses

Foreign Currency Transactions

Foreign Currency Transactions

Cash and Cash Equivalents

Cash and Cash Equivalents

Accounts Receivable

Accounts Receivable

Equity Method of Accounting

Equity Method of Accounting

Noncontrolling Interest

Noncontrolling Interests

Asset Retirement Obligations

Asset Retirement Obligations

Fair Value Measurements

Fair Value Measurements

Recent Accounting Pronouncements

Recent Accounting Pronouncements

Acquisitions

Net Income Per Class A Share

	October 21, 2013 to December 31, 2013
Basic and Diluted Net Income per Class A Share
Net income attributable to PAGP	$	15
Less net income attributable to PAGP for the period from January 1, 2013 to October 20, 2013	(3		)
Net income attributable to PAGP for the period from October 21, 2013 to December 31, 2013	$	12
Basic and diluted weighted average number of Class A shares outstanding (1)	132

Basic and diluted net income per Class A share	$	0.10

Inventory, Linefill, Base Gas and Long-term Inventory

Property and Equipment

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

	Estimated Useful	December 31,
	Lives (Years)	2013			2012
Pipelines and related facilities	10 - 70	$	6,154		$	5,346
Storage, terminal and rail facilities	30 - 70	4,704			4,354
Trucking equipment and other	3 - 15	150			136
Construction in progress	—	1,008			910
Office property and equipment	2 - 50	125			111
Land and other	N/A	373			326
		12,514			11,183
Accumulated depreciation		(1,673		)	(1,519		)
Property and equipment, net		$	10,841		$	9,664

Impairment of Long-Lived Assets

· whether there is an indication of impairment;

· the grouping of assets;

· the intention of “holding,” “abandoning” or “selling” an asset;

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

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

Goodwill

Goodwill represents the future economic benefits arising from assets acquired in a business combination that are not individually identified and separately recognized.

The table below reflects our goodwill by segment and changes during the periods presented (in millions):

	Transportation			Facilities			Supply and Logistics			Total
Balance at December 31, 2011	$	818		$	609		$	427		$	1,854

2012 Goodwill Related Activity:
BP NGL Acquisition	72			136			28			236
USD Rail Terminal Acquisition	—			426			—			426
Other acquisitions	10			—			—			10
Foreign currency translation adjustments	5			—			2			7
Purchase price accounting adjustments and other	(8		)	—			10			2
Balance at December 31, 2012	$	897		$	1,171		$	467		$	2,535

2013 Goodwill Related Activity:
Acquisitions (1)	6			—			—			6
Foreign currency translation adjustments	(20		)	(9		)	(4		)	(33		)
Purchase price accounting adjustments and other (1)	(5		)	—			—			(5		)
Balance at December 31, 2013	$	878		$	1,162		$	463		$	2,503

Debt

Intangible Assets

Intangible assets that have finite lives are tested for impairment when events or circumstances indicate that the carrying value may not be recoverable.

Derivatives

Derivatives That Qualify for Hedge Accounting

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 are recognized in earnings.

Derivatives That Do Not Qualify for Hedge Accounting

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 Derivative Activities

Cash settlements associated with our derivative activities are reflected as cash flows from operating activities in our Consolidated Statements of Cash Flows.

Offsetting Derivative Assets and Liabilities

Income Taxes

Concentration of Credit Risk

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

Equity Compensation

Legal Contingencies

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.

Environmental Matters

Operating Segments

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2013

Summary of Significant Accounting Policies

Investments in entities accounted for under the equity method of accounting

Entity	Type of Operation	Our Ownership Interest
Settoon Towing, LLC	Barge Transportation Services	50	%
Eagle Ford Pipeline LLC	Crude Oil Pipeline	50	%
White Cliffs Pipeline, LLC	Crude Oil Pipeline	36	%
Frontier Pipeline Company	Crude Oil Pipeline	22	%
Butte Pipe Line Company	Crude Oil Pipeline	22	%

Acquisitions and Dispositions (Tables)

12 Months Ended

Dec. 31, 2013

Business acquisition

Schedule of amortization of the contract under the declining balance method for the four full or partial calendar years

We estimate that our amortization expense related to finite-lived intangible assets for the next five years will be as follows (in millions):

2014	$	59
2015	$	52
2016	$	45
2017	$	42
2018	$	36

Summary of unaudited pro forma results of operations

Selected unaudited pro forma results of operations for the years ended December 31, 2012 and 2011, assuming our 2012 acquisitions had occurred on January 1, 2011, are presented below (in millions):

	Year Ended December 31,
	2012		2011
Total revenues	$	38,729	$	37,493
Net income attributable to PAGP	$	3	$	2

BP NGL Acquisition

Business acquisition

Business acquisition fair value determination

The 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	$	241		N/A
Property and equipment	1,081			5 - 70
Linefill	85			N/A
Long-term inventory	165			N/A
Intangible assets (contract)	130			13
Goodwill	236			N/A
Deferred tax liability	(236		)	N/A
Environmental liability	(14		)	N/A
Other long-term liabilities	(5		)	N/A
Total	$	1,683

Schedule of amortization of the contract under the declining balance method for the four full or partial calendar years

2014	$	10
2015	$	8
2016	$	7
2017	$	6

Southern Pines Acquisition

Business acquisition

Business acquisition fair value determination

The fair value of assets acquired and liabilities assumed was as follows (in millions):

			Average
			Depreciable
Description	Amount		Life (in years)
Inventory	$	14	N/A
Property and equipment	340		5 - 70
Base gas	3		N/A
Other working capital (including approximately $13 million of cash acquired)	15		N/A
Intangible assets	92		2 - 10
Goodwill	301		N/A
Total	$	765

Other 2011 Acquisitions

Business acquisition

Business acquisition fair value determination

Description	Amount
Inventory	$	2
Linefill	2
Property and equipment	280
Other working capital, net of cash acquired	(6		)
Intangible assets	142
Environmental liability	(9		)
Goodwill	178
Total	$	589

Net Income Per Class A Share (Tables)

12 Months Ended

Dec. 31, 2013

Net Income Per Class A Share

Computation of basic and diluted net income per class A share

As there are no dilutive units for the period, the following table illustrates the calculation of both basic net income per Class A share and diluted net income per Class A share (amounts in millions, except per share data):

	October 21, 2013 to December 31, 2013
Basic and Diluted Net Income per Class A Share
Net income attributable to PAGP	$	15
Less net income attributable to PAGP for the period from January 1, 2013 to October 20, 2013	(3		)
Net income attributable to PAGP for the period from October 21, 2013 to December 31, 2013	$	12
Basic and diluted weighted average number of Class A shares outstanding (1)	132

Basic and diluted net income per Class A share	$	0.10

Inventory, Linefill and Base Gas and Long-term Inventory (Tables)

12 Months Ended

Dec. 31, 2013

Inventory, Linefill and Base Gas and Long-term Inventory

Components of inventory, linefill and base gas and long-term inventory

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

	December 31, 2013						December 31, 2012
	Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)		Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)
Inventory
Crude oil	6,951	barrels	$	540	$	77.69	9,492	barrels	$	737	$	77.64
NGL	8,061	barrels	352		$	43.67	9,472	barrels	388		$	40.96
Natural gas	40,505	Mcf	150		$	3.70	20,374	Mcf	60		$	2.94
Other	N/A		23		N/A		N/A		24		N/A
Inventory subtotal			1,065						1,209

Linefill and base gas
Crude oil	10,966	barrels	679		$	61.92	9,919	barrels	583		$	58.78
NGL	1,341	barrels	62		$	46.23	1,400	barrels	70		$	50.00
Natural gas	16,615	Mcf	57		$	3.43	15,755	Mcf	54		$	3.43
Linefill and base gas subtotal			798						707

Long-term inventory
Crude oil	2,498	barrels	202		$	80.86	1,962	barrels	149		$	75.94
NGL	1,161	barrels	49		$	42.20	3,238	barrels	125		$	38.60
Long-term inventory subtotal			251						274

Total			$	2,114					$	2,190

Property and Equipment (Tables)

12 Months Ended

Dec. 31, 2013

Property and Equipment

Components of property and equipment, net

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

	Estimated Useful	December 31,
	Lives (Years)	2013			2012
Pipelines and related facilities	10 - 70	$	6,154		$	5,346
Storage, terminal and rail facilities	30 - 70	4,704			4,354
Trucking equipment and other	3 - 15	150			136
Construction in progress	—	1,008			910
Office property and equipment	2 - 50	125			111
Land and other	N/A	373			326
		12,514			11,183
Accumulated depreciation		(1,673		)	(1,519		)
Property and equipment, net		$	10,841		$	9,664

Goodwill (Tables)

12 Months Ended

Dec. 31, 2013

Goodwill

Schedule of goodwill by segment and changes during the period

The table below reflects our goodwill by segment and changes during the periods presented (in millions):

	Transportation			Facilities			Supply and Logistics			Total
Balance at December 31, 2011	$	818		$	609		$	427		$	1,854

2012 Goodwill Related Activity:
BP NGL Acquisition	72			136			28			236
USD Rail Terminal Acquisition	—			426			—			426
Other acquisitions	10			—			—			10
Foreign currency translation adjustments	5			—			2			7
Purchase price accounting adjustments and other	(8		)	—			10			2
Balance at December 31, 2012	$	897		$	1,171		$	467		$	2,535

2013 Goodwill Related Activity:
Acquisitions (1)	6			—			—			6
Foreign currency translation adjustments	(20		)	(9		)	(4		)	(33		)
Purchase price accounting adjustments and other (1)	(5		)	—			—			(5		)
Balance at December 31, 2013	$	878		$	1,162		$	463		$	2,503

Other Assets, Net (Tables)

12 Months Ended

Dec. 31, 2013

Other Assets, Net

Components of other assets, net of accumulated amortization

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

	December 31,
	2013			2012
Deferred tax asset	$	1,068		$	—
Debt issue costs	72			70
Fair value of derivative instruments	30			10
Intangible assets	674			642
Other	37			54
	1,881			776
Accumulated amortization	(271		)	(189		)
	$	1,610		$	587

Components of intangible assets that have finite lives

Our intangible assets that have finite lives consist of the following as of the dates indicated (in millions):

		December 31, 2013							December 31, 2012
	Estimated Useful			Accumulated							Accumulated
	Lives (Years)	Cost		Amortization			Net		Cost		Amortization			Net
Customer contracts and relationships	1 - 20	$	591	$	(237	)	$	354	$	558	$	(157	)	$	401
Property tax abatement	7 - 13	38		(14		)	24		38		(10		)	28
Other agreements	25 - 70	37		(3		)	34		38		(2		)	36
Emission reduction credits (1)	N/A	8		—			8		8		—			8
		$	674	$	(254	)	$	420	$	642	$	(169	)	$	473

(1) Emission reduction credits, once surrendered in exchange for environmental permits, are finite-lived.

Estimated amortization expense related to finite-lived intangible assets for the next five years

We estimate that our amortization expense related to finite-lived intangible assets for the next five years will be as follows (in millions):

2014	$	59
2015	$	52
2016	$	45
2017	$	42
2018	$	36

Debt (Tables)

12 Months Ended

Dec. 31, 2013

Debt

Components of debt

Debt consisted of the following as of the dates indicated (in millions):

	December 31,			December 31,
	2013			2012
SHORT-TERM DEBT
Credit Facilities (1):
PAA senior secured hedged inventory facility, bearing a weighted-average interest rate of 1.6% at December 31, 2012 (2)	$	—		$	665
PAA senior unsecured revolving credit facility, bearing a weighted-average interest rate of 2.4% at December 31, 2012 (2)	—			92
PNG senior unsecured revolving credit facility, bearing a weighted-average interest rate of 2.1% at December 31, 2012 (3)	—			77
PAA commercial paper notes, bearing a weighted-average interest rate of 0.33% at December 31, 2013 (2)	1,109			—
PAA 5.63% senior notes due December 2013	—			250
Other	4			2
Total short-term debt	1,113			1,086

LONG-TERM DEBT
PAA Senior Notes:
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	750			750
2.85% senior notes due January 2023	400			400
3.85% senior notes due October 2023	700			—
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	500			500
4.30% senior notes due January 2043	350			350
Unamortized discounts	(15		)	(15		)
PAA senior notes, net of unamortized discounts	6,710			6,010
Credit Facilities and Other Long-Term Debt (1):
AAP term loan, bearing a weighted-average interest rate of 1.9% and 1.8% at December 31, 2013 and December 31, 2012, respectively	500			200
AAP senior secured revolving credit facility, bearing a weighted-average interest rate of 2.2% at December 31, 2013	15			—
PNG senior unsecured revolving credit facility, bearing a weighted-average interest rate of 2.1% at December 31, 2012 (3)	—			105
PNG GO Bond term loans, bearing a weighted-average interest rate of 1.5% at December 31, 2012 (3)	—			200
Other	5			5
Total long-term debt	7,230			6,520
Total debt (2) (3) (4)	$	8,343		$	7,606

(1) During 2013 and 2012, we renewed, extended or refinanced our principal bank credit facilities. See “Credit Facilities” below for further discussion.

(3) On December 31, 2013, in connection with the completion of the PNG Merger, all of PNG’s outstanding debt obligations were repaid and terminated.

Long-term debt maturities

Calendar Year	Payment
2014	$	—
2015	550
2016	175
2017	400
2018	1,115
Thereafter	5,000
Total (1)	$	7,240

(1) Excludes aggregate unamortized net discount of approximately $15 million and other long-term obligations of approximately $5 million.

Partners' Capital and Distributions (Tables)

12 Months Ended

Dec. 31, 2013

Partners' Capital and Distributions

Schedule of changes in outstanding shares since becoming public

	Class A Shares	Class B Shares
Balance at October 21, 2013 (IPO date)	—	—
Shares issued in connection with the reorganization and IPO	132,382,094	473,647,679
Shares issued/(exchanged) in connection with AAP unit exchanges	1,451,543	(1,451,543	)
Balance at December 31, 2013	133,833,637	472,196,136

Schedule of total cash distributions paid by PAA

Total cash distributions paid by PAA during the periods indicated were as follows (in millions, except per unit amounts):

	Distributions Paid								Distributions
	Common		AAP						per limited
Year	Units		Incentive		2%		Total		partner unit
2013	$	791	$	353	$	16	$	1,160	$	2.33
2012	$	684	$	271	$	14	$	969	$	2.11
2011	$	575	$	204	$	12	$	791	$	1.95

Equity offerings of common units

In addition to sales of PAA’s common units under its Continuous Offering Program described above, PAA completed the following offerings of its common units during the three years ended December 31, 2013 (in millions, except unit and per unit data):

		Gross		Proceeds					Net
Period	Units Issued	Unit Price		from Sale		Costs			Proceeds
March 2012 (1)	11,500,000	$	40.015	$	460	$	(14	)	$	446
2012 Total	11,500,000			$	460	$	(14	)	$	446

November 2011 (1)	12,000,000	$	32.515	$	390	$	(13	)	$	377
March 2011 (1)	15,870,000	$	32.000	508		(15		)	493
2011 Total	27,870,000			$	898	$	(28	)	$	870

(1) These offerings of common units were underwritten transactions that required PAA to pay a gross spread.

Derivatives and Risk Management Activities (Tables)

12 Months Ended

Dec. 31, 2013

Derivative disclosures

Schedule of interest rate risk hedging

The following table summarizes the terms of PAA’s forward starting interest rate swaps as of December 31, 2013 (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

10 forward starting swaps (30-year)

250

6/15/2015

3.60

Cash flow hedge

Open foreign currency exchange contracts

The following table summarizes our open forward exchange contracts as of December 31, 2013 (in millions):

		USD		CAD		Average Exchange Rate USD to CAD
Forward exchange contracts that exchange CAD for USD:
	2014	$	336	$	358	$1.00 - $1.06
	2015	9		9		$1.00 - $1.07
		$	345	$	367	$1.00 - $1.06

Forward exchange contracts that exchange USD for CAD:
	2014	$	336	$	354	$1.00 - $1.05
	2015	9		9		$1.00 - $1.06
		$	345	$	363	$1.00 - $1.05

Net position by currency:
	2014	$	—	$	4
	2015	—		—
		$	—	$	4

Impact of derivative activities recognized in earnings

A summary of the impact of our derivative activities recognized in earnings for the years ended December 31, 2013, 2012 and 2011 is as follows (in millions):

	Year Ended December 31, 2013
	Derivatives in Hedging Relationships
Location of gain/(loss)	Gain/(loss) reclassified from AOCI into income (1)			Other gain/(loss) recognized in income			Derivatives Not Designated as a Hedge			Total
Commodity Derivatives

Supply and Logistics segment revenues	$	78		$	(1	)	$	(116	)	$	(39	)

Facilities segment revenues	(10		)	(1		)	—			(11		)

Field operating costs	—			—			8			8

Interest Rate Derivatives

Interest expense	(7		)	3			—			(4		)

Foreign Currency Derivatives

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

Total Gain/(Loss) on Derivatives Recognized in Net Income	$	66		$	1		$	(108	)	$	(41	)

	Year Ended December 31, 2012
	Derivatives in Hedging Relationships
Location of gain/(loss)	Gain/(loss) reclassified from AOCI into income (1)			Other gain/(loss) recognized in income			Derivatives Not Designated as a Hedge			Total
Commodity Derivatives

Supply and Logistics segment revenues	$	12		$	—		$	60		$	72

Facilities segment revenues	3			(1		)	1			3

Purchases and related costs	45			—			1			46

Field operating costs	—			—			1			1

Interest Rate Derivatives

Interest expense	(8		)	1			—			(7		)

Foreign Currency Derivatives

Supply and Logistics segment revenues	—			—			(1		)	(1		)

Other income/(expense), net	6			—			—			6

Total Gain/(Loss) on Derivatives Recognized in Net Income	$	58		$	—		$	62		$	120

	Year Ended December 31, 2011
	Derivatives in Hedging Relationships
Location of gain/(loss)	Gain/(loss) reclassified from AOCI into income (1)			Other gain/(loss) recognized in income			Derivatives Not Designated as a Hedge		Total
Commodity Derivatives

Supply and Logistics segment revenues	$	(153	)	$	(8	)	$	99	$	(62	)

Facilities segment revenues	11			—			—		11

Purchases and related costs	6			—			—		6

Field operating costs	—			—			1		1

Interest Rate Derivatives

Interest expense	(5		)	2			—		(3		)

Foreign Currency Derivatives

Supply and Logistics segment revenues	—			—			1		1

Other income/(expense), net	6			—			—		6

Total Gain/(Loss) on Derivatives Recognized in Net Income	$	(135	)	$	(6	)	$	101	$	(40	)

Summary of derivative assets and liabilities on condensed consolidated balance sheet

The following table summarizes the derivative assets and liabilities on our Consolidated Balance Sheet on a gross basis as of December 31, 2013 (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	$	36	Other current assets	$	(24	)
	Other long-term assets	5
Interest rate derivatives	Other long-term assets	26
Total derivatives designated as hedging instruments		$	67		$	(24	)

Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	60	Other current assets	$	(117	)
	Other long-term assets	5		Other long-term assets	(6		)
	Other current liabilities	1		Other current liabilities	(5		)
				Other long-term liabilities	(1		)
Foreign currency derivatives				Other current liabilities	(4		)
Total derivatives not designated as hedging instruments		$	66		$	(133	)

Total derivatives		$	133		$	(157	)

The following table summarizes the derivative assets and liabilities on our Consolidated Balance Sheet on a gross basis as of December 31, 2012 (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	$	45	Other current assets	$	(23	)
	Other long-term assets	11		Other long-term assets	(1		)
Interest rate derivatives				Other long-term liabilities	(38		)

Total derivatives designated as hedging instruments		$	56		$	(62	)

Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	128	Other current assets	$	(115	)
	Other long-term assets	1		Other long-term assets	(3		)
	Other current liabilities	4		Other current liabilities	(7		)
	Other long-term liabilities	2		Other long-term liabilities	(2		)

Total derivatives not designated as hedging instruments		$	135		$	(127	)

Total derivatives		$	191		$	(189	)

Schedule of derivatives assets and liabilities that are subject to offsetting, including enforceable master netting arrangements

	December 31, 2013						December 31, 2012
	Derivative			Derivative			Derivative			Derivative
	Asset Positions			Liability Positions			Asset Positions			Liability Positions

Netting Adjustments:
Gross position - asset/(liability)	$	133		$	(157	)	$	191		$	(189	)
Netting adjustment	(148		)	148			(148		)	148
Cash collateral paid/(received)	161			––			41			—
Net position - asset/(liability)	$	146		$	(9	)	$	84		$	(41	)

Balance Sheet Location After Netting Adjustments:
Other current assets	$	116		$	––		$	76		$	—
Other long-term assets	30			––			8			—
Other current liabilities	––			(8		)	—			(3		)
Other long-term liabilities	––			(1		)	—			(38		)
	$	146		$	(9	)	$	84		$	(41	)

Net deferred gain/(loss), including tax effects, recognized in AOCI for derivatives

The net deferred gain/(loss), including tax effects, recognized in AOCI for derivatives for the three years ended December 31, 2013 are as follows (in millions):

	Year Ended December 31,
	2013		2012			2011
Commodity derivatives, net	$	38	$	56		$	(18	)
Interest rate derivatives, net	72		(13		)	(137		)
Total	$	110	$	43		$	(155	)

Derivative financial assets and liabilities within the fair value hierarchy accounted for at fair value on a recurring basis

	Fair Value as of December 31, 2013											Fair Value as of December 31, 2012
Recurring Fair Value Measures (1)	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total
Commodity derivatives	$	16	$	(59	)	$	(3	)	$	(46	)	$	1	$	35		$	4	$	40
Interest rate derivatives	—		26			—			26			—		(38		)	—		(38		)
Foreign currency derivatives	—		(4		)	—			(4		)	—		—			—		—
Total net derivative asset/(liability)	$	16	$	(37	)	$	(3	)	$	(24	)	$	1	$	(3	)	$	4	$	2

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

Reconciliation of changes in fair value of derivatives classified as level 3

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

	Year Ended December 31,
	2013			2012
Beginning Balance	$	4		$	12
Total gains/(losses) for the period:
Included in earnings (1)	(1		)	(3		)
Included in other comprehensive income	—			3
Settlements	(3		)	(22		)
Derivatives entered into during the period	(3		)	23
Transfers out of level 3	—			(9		)
Ending Balance	$	(3	)	$	4

Change in unrealized gains/(losses) included in earnings relating to level 3 derivatives still held at the end of the periods	$	(4	)	$	24

(1) We reported unrealized gains and losses associated with level 3 commodity derivatives in our Consolidated Statements of Operations as Supply and Logistics segment revenues.

- Definition

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=7476318&loc=d3e41641-113959

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5624163-113959

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=7476318&loc=d3e41678-113959

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=7476318&loc=d3e41638-113959

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5580258-113959

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5579245-113959

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5624171-113959

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 25
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6886632&loc=d3e76258-113986

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5579240-113959

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=7476318&loc=d3e41620-113959

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(n)(2))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

+ Details

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2013

Income Taxes

Components of income tax expense

Components of income tax expense are as follows (in millions):

	Year Ended December 31,
	2013			2012		2011
Current tax expense:
State income tax	$	1		$	2	$	2
Canadian federal and provincial income tax	99			52		36
Total current tax expense	$	100		$	54	$	38

Deferred tax (benefit)/expense:
Federal income tax	$	7		$	—	$	—
State income tax	––			––		(2		)
Canadian federal and provincial income tax	(1		)	1		9
Total deferred tax (benefit)/expense	$	6		$	1	$	7
Total income tax expense	$	106		$	55	$	45

Summary of differences between tax expense based on the statutory federal income tax rate and the entity's effective tax expense

The difference between tax expense based on the statutory federal income tax rate and our effective tax expense is summarized as follows (in millions):

	Year Ended December 31,
	2013			2012			2011
Income before tax	$	1,480		$	1,173		$	1,032
Net income attributable to noncontrolling interest	(1,359		)	(1,115		)	(985		)
Income taxes attributable to noncontrolling interest	(99		)	(55		)	(45		)
	$	22		$	3		$	2
Federal statutory income tax rate	35		%	0		%	0		%
Income tax at statutory rate	$	8		$	—		$	—

Federal benefit of state income taxes	$	(1	)	$	—		$	—
Income taxes attributable to noncontrolling interest:
Canadian federal and provincial income taxes	79			35			33
Canadian withholding taxes	19			18			12
State income tax	1			2			—
Total income tax expense	$	106		$	55		$	45

Deferred tax assets and liabilities are aggregated by the applicable tax paying entity and jurisdiction

	December 31,
	2013			2012
Deferred tax assets:
Investment in partnerships	$	1,057		$	—
Net operating losses	11			—
Book accruals in excess of current tax deductions	56			28
Total deferred tax assets	1,124			28

Deferred tax liabilities:
Property and equipment in excess of tax values	(398		)	(397		)
Total deferred tax liabilities	(398		)	(397		)
Net deferred tax assets / (liabilities)	$	726		$	(369	)

Balance sheet classification of deferred tax assets / (liabilities):
Other long-term assets	$	1,068		$	—
Other long-term liabilities and deferred credits	(342		)	(369		)
	$	726		$	(369	)

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2013

Oxy

Related party transaction

These transactions were conducted at posted tariff rates or prices that we believe approximate market. See detail below (in millions):

	Year Ended December 31,
	2013		2012		2011
Revenues	$	1,309	$	1,636	$	2,568

Purchases and related costs	$	863	$	557	$	361

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

	December 31,
	2013		2012
Trade accounts receivable and other receivables	$	133	$	231

Accounts payable	$	181	$	129

Equity-Indexed Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2013

Equity-Indexed Compensation Plans

Schedule of estimated vesting date for PAA long term incentive plan awards outstanding

At December 31, 2013, the following LTIP awards, denominated in PAA units, were outstanding (units in millions):

PAA

LTIP Units

Distribution

Estimated Unit Vesting Date

Outstanding (1) (2)

Required (3)

2014

2015

2016

2017

Thereafter

8.4

$1.925 - $2.65

1.9

2.1

2.0

1.3

1.1

(1) Approximately 4.5 million of the 8.4 million outstanding PAA LTIP awards also include DERs, of which 3.0 million had vested as of December 31, 2013.

(2) LTIP units outstanding do not include AAP Management Units.

Summary of equity-indexed compensation activity for long-term incentive plan awards

Equity-indexed compensation activity for LTIP awards is summarized in the following table (units in millions):

	PAA Units (1) (3)				PNG Units (2) (4)
			Weighted Average				Weighted Average
			Grant Date				Grant Date
	Units		Fair Value per Unit		Units		Fair Value per Unit
Outstanding, December 31, 2010	8.8		$	20.85	1.0		$	20.55
Granted	1.0		$	27.53	—		$	—
Vested	(1.4	)	$	20.34	(0.1	)	$	23.62
Cancelled or forfeited	(0.4	)	$	20.99	(0.1	)	$	19.20
Outstanding, December 31, 2011	8.0		$	21.77	0.8		$	20.55
Granted	1.5		$	33.90	0.1		$	15.33
Vested	(3.2	)	$	19.82	—		$	23.64
Cancelled or forfeited	(0.3	)	$	29.36	—		$	—
Outstanding, December 31, 2012	6.0		$	25.55	0.9		$	17.49
Granted	4.1		$	47.60	0.4		$	17.51
Vested	(1.8	)	$	24.79	—		$	18.88
Cancelled or forfeited (5)	(0.3	)	$	36.70	(0.3	)	$	21.62
Conversion of PNG unit-denominated awards into PAA unit-denominated awards (6)	0.4		$	40.54	(1.0	)	$	16.41
Outstanding, December 31, 2013	8.4		$	36.97	—		$	—

(1) Amounts do not include AAP Management Units.

(2) Amounts include PNG Transaction Grants, which are discussed further below.

(4) Less than 0.1 million PNG units vested during each of the years ended December 31, 2013 and December 31, 2012.

(5) As a result of the PNG Merger on December 31, 2013, approximately 0.3 million outstanding PNG Transaction Grants were cancelled.

Summary of AAP Management Units

This adjustment is reflected retrospectively in the following summary of AAP Management Units (in millions):

	Reserved for Future Grants		Outstanding		Outstanding Units Earned	Grant Date Fair Value Of Outstanding AAP Management Units (1)
Balance as of December 31, 2011	4.3		47.8		20.9	$	44
Forfeitures	0.4		(0.4	)	—	—
Earned	N/A		N/A		13.1	N/A
Balance as of December 31, 2012	4.7		47.4		34.0	$	44
Granted	(1.2	)	1.2		—	7
Earned	N/A		N/A		13.0	N/A
Balance as of December 31, 2013	3.5		48.6		47.0	$	51

Summary of expense recognized and value of vesting related to equity-indexed compensation plans

The table below summarizes the expense recognized and the value of vesting (settled both in units and cash) related to the equity-indexed compensation plans and includes both liability-classified and equity-classified awards (in millions):

	2013		2012		2011
Equity-indexed compensation expense	$	116	$	101	$	110
LTIP unit-settled vestings (1)	$	48	$	62	$	24
LTIP cash-settled vestings	$	61	$	66	$	19
DER cash payments	$	8	$	7	$	4

Equity-indexed compensation plan fair value amortization

We estimate that the remaining fair value will be recognized in expense as shown below (in millions):

Year	Equity-Indexed Compensation Plan Fair Value Amortization (1) (2)
2014	$	80
2015	55
2016	36
2017	16
2018	5
Thereafter	1
Total	$	193

(1) Amounts do not include fair value associated with awards containing performance conditions that are not considered to be probable of occurring at December 31, 2013.

(2) Includes unamortized fair value associated with AAP Management Units.

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies

Future non-cancelable commitments relating to operating and capital leases and third-party operation agreements

Future non-cancelable commitments related to these items at December 31, 2013, are summarized below (in millions):

	2014		2015		2016		2017		2018		Thereafter		Total
Leases (1)	$	152	$	132	$	124	$	103	$	78	$	386	$	975
Other commitments (2)	38		32		29		25		16		42		182
Total	$	190	$	164	$	153	$	128	$	94	$	428	$	1,157

(1) Includes capital and operating leases as defined by the FASB guidance.

(2) Primarily includes third-party storage and transportation agreements and pipeline throughput agreements.

Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2013

Quarterly Financial Data (Unaudited)

Quarterly Financial Data (Unaudited)

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter		Total (1)
	(in millions, except per share data)
2013
Revenues	$	10,620	$	10,295	$	10,703	$	10,631	$	42,249
Gross margin (2)	$	761	$	474	$	375	$	476	$	2,084
Operating income	$	655	$	383	$	296	$	391	$	1,724
Net income	$	535	$	299	$	236	$	305	$	1,374
Net income attributable to PAGP	$	1	$	1	$	1	$	12	$	15
Basic and diluted net income per Class A share (3)	N/A		N/A		N/A		$	0.10	$	0.10

2012
Revenues	$	9,218	$	9,786	$	9,354	$	9,439	$	37,797
Gross margin (2)	$	407	$	551	$	328	$	479	$	1,766
Operating income	$	313	$	462	$	247	$	401	$	1,424
Net income	$	234	$	384	$	171	$	327	$	1,118
Net income attributable to PAGP	$	—	$	1	$	1	$	1	$	3

(1) The sum of the four quarters may not equal the total year due to rounding.

(2) Gross margin is calculated as Total revenues less (i) Purchases and related costs, (ii) Field operating costs and (iii) Depreciation and amortization.

Operating Segments (Tables)

12 Months Ended

Dec. 31, 2013

Operating Segments

Segment financial data

The following table reflects certain financial data for each segment for the periods indicated (in millions):

	Transportation		Facilities		Supply and Logistics		Total
Twelve Months Ended December 31, 2013
Revenues:
External Customers	$	701	$	856	$	40,692	$	42,249
Intersegment (1)	797		521		4		1,322
Total revenues of reportable segments	$	1,498	$	1,377	$	40,696	$	43,571
Equity earnings in unconsolidated entities	$	64	$	—	$	—	$	64
Segment profit (2) (3)	$	729	$	616	$	822	$	2,167
Capital expenditures	$	1,046	$	549	$	46	$	1,641
Total assets	$	7,767	$	6,741	$	6,945	$	21,453
Maintenance capital	$	123	$	38	$	15	$	176

Twelve Months Ended December 31, 2012
Revenues:
External Customers	$	623	$	736	$	36,438	$	37,797
Intersegment (1)	793		362		2		1,157
Total revenues of reportable segments	$	1,416	$	1,098	$	36,440	$	38,954
Equity earnings in unconsolidated entities	$	38	$	—	$	—	$	38
Segment profit (2) (3)	$	710	$	482	$	753	$	1,945
Capital expenditures	$	1,244	$	1,724	$	503	$	3,471
Total assets	$	6,447	$	6,134	$	6,678	$	19,259
Maintenance capital	$	108	$	49	$	13	$	170

Twelve Months Ended December 31, 2011
Revenues:
External Customers	$	572	$	638	$	33,065	$	34,275
Intersegment (1)	593		158		3		754
Total revenues of reportable segments	$	1,165	$	796	$	33,068	$	35,029
Equity earnings in unconsolidated entities	$	13	$	—	$	—	$	13
Segment profit (2) (3)	$	555	$	358	$	647	$	1,560
Capital expenditures	$	600	$	1,317	$	18	$	1,935
Total assets	$	5,189	$	4,506	$	5,719	$	15,414
Maintenance capital	$	86	$	22	$	12	$	120

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

	Year Ended December 31,
	2013			2012			2011
Segment profit	$	2,167		$	1,945		$	1,560
Unallocated general and administrative expenses	(1		)	—			—
Depreciation and amortization	(378		)	(483		)	(250		)
Interest expense	(309		)	(295		)	(259		)
Other income/(expense), net	1			6			(19		)
Income tax expense	(106		)	(55		)	(45		)
Net income	1,374			1,118			987
Net income attributable to noncontrolling interests	(1,359		)	(1,115		)	(985		)
Net income attributable to PAGP	$	15		$	3		$	2

Reconciliation of segment profit to net income attributable to PAGP

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

	Year Ended December 31,
	2013			2012			2011
Segment profit	$	2,167		$	1,945		$	1,560
Unallocated general and administrative expenses	(1		)	—			—
Depreciation and amortization	(378		)	(483		)	(250		)
Interest expense	(309		)	(295		)	(259		)
Other income/(expense), net	1			6			(19		)
Income tax expense	(106		)	(55		)	(45		)
Net income	1,374			1,118			987
Net income attributable to noncontrolling interests	(1,359		)	(1,115		)	(985		)
Net income attributable to PAGP	$	15		$	3		$	2

Revenues attributable to geographical areas

We have operations in the United States and Canada. Set forth below are revenues and long-lived assets attributable to these geographic areas (in millions):

	Year Ended December 31,
Revenues (1)	2013		2012		2011
United States	$	32,924	$	29,978	$	28,181
Canada	9,325		7,819		6,094
	$	42,249	$	37,797	$	34,275

(1) Revenues are primarily attributed to each region based on where the services are provided or the product is shipped.

Long-lived assets attributable to geographical areas

	December 31,
Long-Lived Assets (1)	2013		2012
United States	$	12,835	$	10,423
Canada	3,623		3,677
	$	16,458	$	14,100

(1) Excludes long-term derivative assets.

Organization and Basis of Presentation (Details)	2 Months Ended	12 Months Ended
Organization and Basis of Presentation (Details)	Dec. 31, 2013	Dec. 31, 2013 segment shares
Organization and basis of presentation
Operating segments number \| segment		3
GP LLC
Organization and basis of presentation
General partner or managing member ownership interest (as a percent)	100.00%
AAP
Organization and basis of presentation
Number of AAP units owned \| shares		133,833,637
Limited partnership ownership interest (as a percent)		22.10%
AAP \| PAA \| Indirect Ownership
Organization and basis of presentation
General partner or managing member ownership interest (as a percent)		2.00%
PAA GP LLC \| PAA
Organization and basis of presentation
General partner or managing member ownership interest (as a percent)		2.00%

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Foreign Currency Transactions
Gain (loss) on revaluation of foreign currency transactions and monetary assets and liabilities	$ 1	$ (2)	$ (2)
Cash and Cash Equivalents
Outstanding checks that were reclassified from cash and cash equivalents to be included in accounts payable	70	72
Accounts Receivable
Advance cash payments received from third parties to mitigate credit risk	117	173
Standby letters of credit	$ 426	$ 343
Net accounts receivable, maximum age of balances past their scheduled invoice date	30 days	30 days
Allowance for doubtful accounts receivable	$ 5	$ 4

Summary of Significant Accounting Policies (Details 2) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Aug. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Equity Method of Accounting
Contribution to entity's equity method investees		$ 133	$ 76
Cash received upon formation of equity-method investment			59
Distributions received from equity method investees		55	40	$ 23
Asset Retirement Obligations
Fair value of asset retirement obligations		$ 34	31
Settoon Towing, LLC
Equity Method of Accounting
Ownership interest (as a percent)		50.00%
Eagle Ford Pipeline LLC
Equity Method of Accounting
Ownership interest (as a percent)		50.00%
Contribution to entity's equity method investees			75
Contributed assets	$ 134
Cash received upon formation of equity-method investment	59
Eagle Ford Pipeline LLC \| Enterprise Product Partners
Equity Method of Accounting
Contribution to entity's equity method investees			$ 75
Contributed assets	$ 15
White Cliffs Pipeline, LLC
Equity Method of Accounting
Ownership interest (as a percent)		36.00%
Frontier Pipeline Company
Equity Method of Accounting
Ownership interest (as a percent)		22.00%
Butte Pipe Line Company
Equity Method of Accounting
Ownership interest (as a percent)		22.00%

Acquisitions and Dispositions (Details) $ in Millions						1 Months Ended	12 Months Ended
Acquisitions and Dispositions (Details) $ in Millions	Dec. 12, 2012 USD ($) railterminal	Apr. 02, 2012 USD ($)	Dec. 29, 2011 USD ($) transaction in mi	Nov. 29, 2011 USD ($) mi	Feb. 09, 2011 USD ($)	Mar. 31, 2012 USD ($)	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)	Dec. 31, 2011 USD ($) entity
Business acquisition
Release of restricted cash previously held in escrow									$ (20)
Business acquisition, allocation of fair value of assets and liabilities
Goodwill							$ 2,503	$ 2,535	1,854
Finite Lived Intangible assets
Amortization under the declining balance method							85	90	36
Estimated amortization expense
2014							59
2015							52
2016							45
2017							42
Supplemental pro forma:
Pro Forma, Total revenues								38,729	37,493
Pro forma, Net income attributable to PAGP								3	2
2013 Acquisitions
Business acquisition
Purchase Price							19
Business acquisition, allocation of fair value of assets and liabilities
Goodwill							6
BP NGL Acquisition
Business acquisition
Purchase Price		$ 1,680
Imputed interest		$ 17
Business acquisition, allocation of fair value of assets and liabilities
Working capital								241
Property and equipment								1,081
Linefill								85
Long-term inventory								165
Intangible assets								130
Goodwill								236
Deferred tax liability								(236)
Environmental liability								(14)
Other long-term liabilities								(5)
Total net assets acquired								1,683
Net proceeds from issuance of common units and senior notes						$ 1,690
Acquisition-related costs								$ 13
Finite Lived Intangible assets
Average Depreciable Life								13 years
Amortization under the declining balance method							31	$ 41
Estimated amortization expense
2014							10
2015							8
2016							7
2017							$ 6
BP NGL Acquisition \| Minimum
Property and equipment, useful life
Average Depreciable Life								5 years
BP NGL Acquisition \| Maximum
Property and equipment, useful life
Average Depreciable Life								70 years
USD Rail Terminal Acquisition
Business acquisition
Purchase Price	$ 503
Number of operating crude oil rail terminals acquired \| railterminal	4
Number of terminals under development acquired \| railterminal	1
Business acquisition, allocation of fair value of assets and liabilities
Working capital								$ 1
Property and equipment								76
Goodwill								426
Other 2012 Acquisitions
Business acquisition
Purchase Price								150
Business acquisition, allocation of fair value of assets and liabilities
Goodwill								$ 10
Southern Pines Acquisition
Business acquisition
Interest acquired (as a percent)					100.00%
Purchase Price					$ 765
Purchase price net of cash and other working capital acquired					750
Release of restricted cash previously held in escrow					$ (20)
Business acquisition, allocation of fair value of assets and liabilities
Inventory									14
Property and equipment									340
Base Gas									3
Other working capital (including cash acquired)									15
Cash acquired									13
Intangible assets									92
Goodwill									301
Total net assets acquired									765
Finite Lived Intangible assets
Tax abatement included in amortizable intangible assets									15
Contracts value included in amortizable intangible assets									$ 77
Southern Pines Acquisition \| Minimum
Property and equipment, useful life
Average Depreciable Life									5 years
Finite Lived Intangible assets
Average Depreciable Life									2 years
Southern Pines Acquisition \| Maximum
Property and equipment, useful life
Average Depreciable Life									70 years
Finite Lived Intangible assets
Average Depreciable Life									10 years
Other 2011 Acquisitions
Business acquisition
Purchase Price									$ 20
Number of additional acquisitions completed (in entities) \| entity									6
Business acquisition, allocation of fair value of assets and liabilities
Inventory									$ 2
Property and equipment									280
Linefill									2
Other working capital, net of cash acquired									(6)
Intangible assets									142
Goodwill									178
Environmental liability									(9)
Total net assets acquired									$ 589
Western Acquisition
Business acquisition
Purchase Price			$ 220
Number of transactions completed \| transaction			2
Pipelines acquired (in miles) \| mi			82
Diameter of pipeline acquired (in inches) \| in			16
Gardendale Gathering System Acquisition
Business acquisition
Interest acquired (as a percent)				100.00%
Purchase Price				$ 349
Pipelines acquired (in miles) \| mi				120
Business acquisition, allocation of fair value of assets and liabilities
Goodwill				$ 155

Acquisitions and Dispositions (Details 2) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Dispositions
Proceeds from sale of various property and equipment	$ 200	$ 22	$ 12
Gain (loss) on sale of various property and equipment		$ 6	$ (6)
Maximum
Dispositions
Gain (loss) on sale of various property and equipment	$ 1

Net Income Per Class A Share (Details) - USD ($)
$ / shares in Units, $ in Millions

1 Months Ended

2 Months Ended

3 Months Ended

10 Months Ended

12 Months Ended

Oct. 31, 2013

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Oct. 20, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Basic and Diluted Net Income per Class A Share

Net income attributable to PAGP

$ 12

$ 1

$ 15

$ 3

$ 2

Basic and diluted weighted average number of Class A shares outstanding

^[1]

132,000,000

Basic and diluted net income per Class A share

$ 0.10

^[1]

Class A Shares

Basic and diluted earnings per share

Number of dilutive units (in unit)

Basic and Diluted Net Income per Class A Share

Net income attributable to PAGP

$ 12

$ 3

$ 15

Basic and diluted weighted average number of Class A shares outstanding

132,000,000

Basic and diluted net income per Class A share

$ 0.10

Number of shares issued upon closing of the IPO

128,000,000

Number of shares issued through exercise of over-allotment option

4,000,000

[1]

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Net Income
-URI http://asc.fasb.org/extlink&oid=6518256

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 230
-SubTopic 10
-Section 45
-Paragraph 28
-URI http://asc.fasb.org/extlink&oid=31042434&loc=d3e3602-108585

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 944
-SubTopic 225
-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-04.19)
-URI http://asc.fasb.org/extlink&oid=6879464&loc=d3e573970-122913

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 260
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6371337&loc=d3e3550-109257

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 225
-SubTopic 10
-Section S99
-Paragraph 2
-Subparagraph (SX 210.5-03.18)
-URI http://asc.fasb.org/extlink&oid=26872669&loc=d3e20235-122688

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 944
-SubTopic 225
-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-04.22)
-URI http://asc.fasb.org/extlink&oid=6879464&loc=d3e573970-122913

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Other Comprehensive Income
-URI http://asc.fasb.org/extlink&oid=6519514

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=28358780&loc=d3e565-108580

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 03
-Paragraph 19
-Article 5

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 04
-Paragraph 20
-Article 9

+ Details

Inventory, Linefill and Base Gas and Long-term Inventory (Details) bbl in Thousands, Mcf in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2013 USD ($) $ / Mcf $ / bbl bbl Mcf	Dec. 31, 2012 USD ($) $ / Mcf $ / bbl bbl Mcf	Dec. 31, 2011 USD ($)
Inventory-related disclosures
Non-cash charges related to the write-down of inventory	$ 7	$ 128	$ 4
Gain on sale of linefill and base gas	7	19	21
Cash received for sales of linefill and base gas	40	65	$ 56
Inventory by category
Inventory	1,065	1,209
Linefill and base gas	798	707
Long-term inventory	251	274
Total	2,114	2,190
Crude oil
Inventory by category
Inventory	540	737
Linefill and base gas	679	583
Long-term inventory	$ 202	$ 149
Inventory, Volumes (in barrels or in Mcf) \| bbl	6,951	9,492
Linefill and base gas, Volumes (in barrels or in Mcf) \| bbl	10,966	9,919
Long-term inventory, Volumes (in barrels or Mcf) \| bbl	2,498	1,962
Inventory, Price/Unit of measure (in dollars per unit) \| $ / bbl	77.69	77.64
Linefill and base gas, Price/Unit of measure (in dollars per unit) \| $ / bbl	61.92	58.78
Long-term inventory, Price/Unit of measure (in dollars per unit) \| $ / bbl	80.86	75.94
NGL
Inventory by category
Inventory	$ 352	$ 388
Linefill and base gas	62	70
Long-term inventory	$ 49	$ 125
Inventory, Volumes (in barrels or in Mcf) \| bbl	8,061	9,472
Linefill and base gas, Volumes (in barrels or in Mcf) \| bbl	1,341	1,400
Long-term inventory, Volumes (in barrels or Mcf) \| bbl	1,161	3,238
Inventory, Price/Unit of measure (in dollars per unit) \| $ / bbl	43.67	40.96
Linefill and base gas, Price/Unit of measure (in dollars per unit) \| $ / bbl	46.23	50.00
Long-term inventory, Price/Unit of measure (in dollars per unit) \| $ / bbl	42.20	38.60
Natural gas
Inventory by category
Inventory	$ 150	$ 60
Linefill and base gas	$ 57	$ 54
Inventory, Volumes (in barrels or in Mcf) \| Mcf	40,505	20,374
Linefill and base gas, Volumes (in barrels or in Mcf) \| Mcf	16,615	15,755
Inventory, Price/Unit of measure (in dollars per unit) \| $ / Mcf	3.70	2.94
Linefill and base gas, Price/Unit of measure (in dollars per unit) \| $ / Mcf	3.43	3.43
Other
Inventory by category
Inventory	$ 23	$ 24

Property and Equipment (Details) - USD ($) $ in Millions	12 Months Ended
Property and Equipment (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Property and Equipment
Interest expense, capitalized interest	$ 38	$ 36	$ 25
Property and equipment, gross	12,514	11,183
Accumulated depreciation	(1,673)	(1,519)
Property and equipment, net	10,841	9,664
Depreciation expense	262	223	197
Incremental reduction in depreciation expense due to depreciable life extensions		13
Impairment charges - predominantly related to assets taken out of service	20		$ 5
Impairments of long-lived assets primarily related to Pier 400 terminal project		168
Pipelines and related facilities
Property and Equipment
Property and equipment, gross	$ 6,154	5,346
Pipelines and related facilities \| Minimum
Property and Equipment
Estimated Useful Lives	10 years
Pipelines and related facilities \| Maximum
Property and Equipment
Estimated Useful Lives	70 years
Storage, terminal and rail facilities
Property and Equipment
Property and equipment, gross	$ 4,704	4,354
Storage, terminal and rail facilities \| Minimum
Property and Equipment
Estimated Useful Lives	30 years
Storage, terminal and rail facilities \| Maximum
Property and Equipment
Estimated Useful Lives	70 years
Trucking equipment and other
Property and Equipment
Property and equipment, gross	$ 150	136
Trucking equipment and other \| Minimum
Property and Equipment
Estimated Useful Lives	3 years
Trucking equipment and other \| Maximum
Property and Equipment
Estimated Useful Lives	15 years
Construction in progress
Property and Equipment
Property and equipment, gross	$ 1,008	910
Office property and equipment
Property and Equipment
Property and equipment, gross	$ 125	111
Office property and equipment \| Minimum
Property and Equipment
Estimated Useful Lives	2 years
Office property and equipment \| Maximum
Property and Equipment
Estimated Useful Lives	50 years
Land and other
Property and Equipment
Property and equipment, gross	$ 373	$ 326

Goodwill (Details) - USD ($) $ in Millions	12 Months Ended
Goodwill (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
Changes in goodwill
Balance at beginning of period	$ 2,535	$ 1,854
Acquisitions	6
Foreign currency translation adjustments	(33)	7
Purchase price accounting adjustments and other	(5)	2
Balance at end of period	2,503	2,535
BP NGL Acquisition
Changes in goodwill
Balance at beginning of period	236
Acquisitions		236
Balance at end of period		236
USD Rail Terminal Acquisition
Changes in goodwill
Balance at beginning of period	426
Acquisitions		426
Balance at end of period		426
Other acquisitions
Changes in goodwill
Acquisitions		10
Transportation
Changes in goodwill
Balance at beginning of period	897	818
Acquisitions	6
Foreign currency translation adjustments	(20)	5
Purchase price accounting adjustments and other	(5)	(8)
Balance at end of period	878	897
Transportation \| BP NGL Acquisition
Changes in goodwill
Acquisitions		72
Transportation \| Other acquisitions
Changes in goodwill
Acquisitions		10
Facilities
Changes in goodwill
Balance at beginning of period	1,171	609
Foreign currency translation adjustments	(9)
Balance at end of period	1,162	1,171
Facilities \| BP NGL Acquisition
Changes in goodwill
Acquisitions		136
Facilities \| USD Rail Terminal Acquisition
Changes in goodwill
Acquisitions		426
Supply and Logistics
Changes in goodwill
Balance at beginning of period	467	427
Foreign currency translation adjustments	(4)	2
Purchase price accounting adjustments and other		10
Balance at end of period	$ 463	467
Supply and Logistics \| BP NGL Acquisition
Changes in goodwill
Acquisitions		$ 28

Other Assets, Net (Details) - USD ($) $ in Millions	12 Months Ended
Other Assets, Net (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Other Assets, Net
Deferred tax asset	$ 1,068
Debt issue costs	72	$ 70
Fair value of derivative instruments	30	10
Intangible assets	674	642
Other	37	54
Other assets, gross	1,881	776
Accumulated amortization	(271)	(189)
Other assets, net	1,610	587
Debt issuance costs capitalized during the period	10	21
Write off of debt issuance cost	8	5
Amortization expense related to other assets (including finite-lived intangible assets)	96	99	$ 44
Amortization expense for finite-lived intangible assets	$ 85	$ 90	$ 36

Other Assets, Net (Details 2) - USD ($) $ in Millions	12 Months Ended
Other Assets, Net (Details 2) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
Finite-Lived Intangible Assets
Cost	$ 674	$ 642
Accumulated amortization	(254)	(169)
Net	420	473
Estimated amortization expense related to finite-lived intangible assets for the next five years
2014	59
2015	52
2016	45
2017	42
2018	36
Customer contracts and relationships
Finite-Lived Intangible Assets
Cost	591	558
Accumulated amortization	(237)	(157)
Net	$ 354	401
Customer contracts and relationships \| Minimum
Finite-Lived Intangible Assets
Estimated Useful Lives	1 year
Customer contracts and relationships \| Maximum
Finite-Lived Intangible Assets
Estimated Useful Lives	20 years
Property tax abatement
Finite-Lived Intangible Assets
Cost	$ 38	38
Accumulated amortization	(14)	(10)
Net	$ 24	28
Property tax abatement \| Minimum
Finite-Lived Intangible Assets
Estimated Useful Lives	7 years
Property tax abatement \| Maximum
Finite-Lived Intangible Assets
Estimated Useful Lives	13 years
Other agreements
Finite-Lived Intangible Assets
Cost	$ 37	38
Accumulated amortization	(3)	(2)
Net	$ 34	36
Other agreements \| Minimum
Finite-Lived Intangible Assets
Estimated Useful Lives	25 years
Other agreements \| Maximum
Finite-Lived Intangible Assets
Estimated Useful Lives	70 years
Emission reduction credits
Finite-Lived Intangible Assets
Cost	$ 8	8
Net	$ 8	$ 8

Debt (Details) - USD ($) $ in Millions	12 Months Ended
Debt (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
Short-term debt:
Other short-term debt	$ 4	$ 2
Total short-term debt	1,113	1,086
Long-term debt:
Unamortized discounts	(15)	(15)
PAA Senior notes, net of unamortized discounts	6,710	6,010
Long-term debt, other	5	5
Total long-term debt	7,230	6,520
Total debt	$ 8,343	$ 7,606
PAA commercial paper notes
Debt
Interest rate (as a percent)	0.33%
Short-term debt:
Commercial Paper Notes, Current	$ 1,109
Repayment period	1 year
PAA senior secured hedged inventory facility
Debt
Credit facility, interest rate (as a percent)		1.60%
Short-term debt:
Credit Facility, Current		$ 665
Repayment period	1 year
PAA senior unsecured revolving credit facility
Debt
Credit facility, interest rate (as a percent)		2.40%
Short-term debt:
Credit Facility, Current		$ 92
Repayment period	1 year
AAP senior secured revolving credit facility
Debt
Credit facility, interest rate (as a percent)	2.20%
Long-term debt:
Long-term debt under credit facilities	$ 15
PAA's fixed rate senior notes
Long-term debt:
Debt instrument face value	6,700	6,300
Debt instrument fair value	$ 7,200	$ 7,300
5.25% senior notes due June 2015
Debt
Debt instrument, interest rate (as a percent)	5.25%	5.25%
Long-term debt:
Senior Notes	$ 150	$ 150
3.95% senior notes due September 2015
Debt
Debt instrument, interest rate (as a percent)	3.95%	3.95%
Long-term debt:
Senior Notes	$ 400	$ 400
5.88% senior notes due August 2016
Debt
Debt instrument, interest rate (as a percent)	5.88%	5.88%
Long-term debt:
Senior Notes	$ 175	$ 175
6.13% senior notes due January 2017
Debt
Debt instrument, interest rate (as a percent)	6.13%	6.13%
Long-term debt:
Senior Notes	$ 400	$ 400
6.50% senior notes due May 2018
Debt
Debt instrument, interest rate (as a percent)	6.50%	6.50%
Long-term debt:
Senior Notes	$ 600	$ 600
8.75% senior notes due May 2019
Debt
Debt instrument, interest rate (as a percent)	8.75%	8.75%
Long-term debt:
Senior Notes	$ 350	$ 350
5.75% senior notes due January 2020
Debt
Debt instrument, interest rate (as a percent)	5.75%	5.75%
Long-term debt:
Senior Notes	$ 500	$ 500
5.00% senior notes due February 2021
Debt
Debt instrument, interest rate (as a percent)	5.00%	5.00%
Long-term debt:
Senior Notes	$ 600	$ 600
3.65% senior notes due June 2022
Debt
Debt instrument, interest rate (as a percent)	3.65%	3.65%
Long-term debt:
Senior Notes	$ 750	$ 750
2.85% senior notes due January 2023
Debt
Debt instrument, interest rate (as a percent)	2.85%	2.85%
Long-term debt:
Senior Notes	$ 400	$ 400
3.85% senior notes due October 2023
Debt
Debt instrument, interest rate (as a percent)	3.85%
Long-term debt:
Senior Notes	$ 700
6.70% senior notes due May 2036
Debt
Debt instrument, interest rate (as a percent)	6.70%	6.70%
Long-term debt:
Senior Notes	$ 250	$ 250
6.65% senior notes due January 2037
Debt
Debt instrument, interest rate (as a percent)	6.65%	6.65%
Long-term debt:
Senior Notes	$ 600	$ 600
5.15% senior notes due June 2042
Debt
Debt instrument, interest rate (as a percent)	5.15%	5.15%
Long-term debt:
Senior Notes	$ 500	$ 500
4.30% senior notes due January 2043
Debt
Debt instrument, interest rate (as a percent)	4.30%	4.30%
Long-term debt:
Senior Notes	$ 350	$ 350
Debt instrument face value		$ 350
5.63% senior notes due December 2013
Debt
Debt instrument, interest rate (as a percent)		5.63%
Short-term debt:
Senior Notes, Current		$ 250
AAP term loan
Debt
Interest rate (as a percent)	1.90%	1.80%
Long-term debt:
Term Loans, amounts outstanding	$ 500	$ 200
PNG senior unsecured revolving credit facility
Debt
Credit facility, interest rate (as a percent)		2.10%
Short-term debt:
Credit Facility, Current		$ 77
Long-term debt:
Long-term debt under credit facilities		$ 105
PNG GO Bond term loans
Debt
Interest rate (as a percent)		1.50%
Long-term debt:
Term Loans, amounts outstanding		$ 200

Debt (Details 2) $ in Millions	1 Months Ended		12 Months Ended
Debt (Details 2) $ in Millions	Sep. 30, 2013 USD ($)	Aug. 31, 2013 USD ($) extension	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($) loan
PAA Commercial Paper Program
Debt
Maximum borrowing capacity		$ 1,500
PAA senior secured hedged inventory facility
Debt
Maturity date extension		2 years
Extension period		1 year
Borrowing capacity			$ 1,400
Maximum borrowing capacity			$ 1,900
Basis Variable interest rate used			Eurocurrency Rate or the Base Rate
PAA senior secured hedged inventory facility \| Minimum
Debt
Credit facility extensions available \| extension		1
PAA senior secured hedged inventory facility \| Letters of credit
Debt
Borrowing capacity			$ 400
PAA senior unsecured revolving credit facility
Debt
Maturity date extension		2 years
Extension period		1 year
Borrowing capacity			1,600
Maximum borrowing capacity			$ 2,100
Basis Variable interest rate used			Eurocurrency Rate, the Base Rate or the Canadian Rate
PAA senior unsecured revolving credit facility \| Minimum
Debt
Credit facility extensions available \| extension		1
AAP senior secured credit agreement
Debt
Maturity date extension	1 year
Basis Variable interest rate used			Alternative Base Rate or Eurodollar Rate
AAP senior secured credit agreement \| Minimum
Debt
Commitment fee (as a percent)			0.175%
AAP senior secured credit agreement \| Maximum
Debt
Commitment fee (as a percent)			0.35%
AAP term loan
Debt
Term Loans, amounts outstanding			$ 500	$ 200
Maximum borrowing capacity of loan before amendment	$ 200
AAP revolving credit facility
Debt
Maximum borrowing capacity	75		$ 75
Maximum borrowing capacity of credit facility before amendment	$ 25
PNG senior unsecured credit facility
Debt
Borrowing capacity				$ 350
Basis Variable interest rate used			Eurodollar Rate or the Base Rate
PNG GO Bond term loans
Debt
Number of term loans \| loan				2
Term Loans, amounts outstanding				$ 200
Amount that may be utilized for future tax-exempt debt issuance			$ 200
PNG Term Loan One
Debt
Term Loans, amounts outstanding				100
PNG Term Loan Two
Debt
Term Loans, amounts outstanding				$ 100

Debt (Details 3) $ in Millions				12 Months Ended
Debt (Details 3) $ in Millions	Dec. 13, 2013 USD ($)	Sep. 04, 2012 USD ($)	Feb. 07, 2011 USD ($)	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)	Dec. 31, 2011 USD ($)	Aug. 31, 2013 USD ($)	Mar. 31, 2012 USD ($)
Debt
Repayments of PAA senior notes				$ 250	$ 500	$ 200
PAA
Debt
Consolidated subsidiary, ownership interest held by the parent (as a percent)				100.00%
PAA senior secured hedged inventory facility
Debt
Coverage ratio of debt-to-EBITDA, maximum				5.00
Ratio of debt-to-EBITDA during acquisition period, maximum				5.50
Acquisition period				9 months
Threshold for acquisition period qualification				$ 150
PAA senior unsecured revolving credit facility
Debt
Coverage ratio of debt-to-EBITDA, maximum				5.00
Ratio of debt-to-EBITDA during acquisition period, maximum				5.50
Acquisition period				9 months
Threshold for acquisition period qualification				$ 150
Credit agreements and PAA commercial paper program
Debt
Total borrowings				31,500	12,900	9,700
Total repayments				$ 31,200	12,200	$ 10,900
AAP senior secured credit agreement
Debt
Percentage of pledge to partnership interest				100.00%
Leverage Ratio				4.0
3.65% senior notes due June 2022
Debt
Debt instrument face value								$ 750
Debt instrument, interest rate (as a percent)								3.65%
Percentage of face value at which senior notes are sold								99.823%
2.85% senior notes due January 2023
Debt
Debt instrument face value					$ 400
Debt instrument, interest rate (as a percent)					2.85%
Percentage of face value at which senior notes are sold					99.752%
3.85% senior notes due October 2023
Debt
Debt instrument face value							$ 700
Debt instrument, interest rate (as a percent)							3.85%
Percentage of face value at which senior notes are sold							99.792%
5.15% senior notes due June 2042
Debt
Debt instrument face value								$ 500
Debt instrument, interest rate (as a percent)								5.15%
Percentage of face value at which senior notes are sold								99.755%
4.30% senior notes due January 2043
Debt
Debt instrument face value					$ 350
Debt instrument, interest rate (as a percent)					4.30%
Percentage of face value at which senior notes are sold					99.925%
5.63% senior notes due December 2013
Debt
Repayments of PAA senior notes	$ 250
Debt instrument, interest rate (as a percent)	5.63%
4.25% senior notes due September 2012
Debt
Repayments of PAA senior notes		$ 500
Debt instrument, interest rate (as a percent)		4.25%
7.75% senior notes due 2012
Debt
Early redemption of senior notes			$ 200
Debt instrument, interest rate (as a percent)			7.75%
Loss on early redemption of senior notes			$ (23)

Debt (Details 4) - USD ($) $ in Millions	12 Months Ended
Debt (Details 4) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
Debt
Weighted-average life of long-term debt	11 years
Maturities
2015	$ 550
2016	175
2017	400
2018	1,115
Thereafter	5,000
Total	7,240
Aggregate unamortized net discount	15
Other long-term obligations excluded from debt maturities	$ 5
Debt Covenant Compliance	As of December 31, 2013, we were in compliance with the covenants contained in our credit agreements and indentures
Letters of credit
Debt
Periods for which letters of credit are issued	70 days
Outstanding letters of credit	$ 41	$ 24

Partners' Capital and Distributions (Details) - USD ($) $ / shares in Units, $ in Millions		1 Months Ended	2 Months Ended	12 Months Ended
	Feb. 14, 2014	Oct. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Oct. 20, 2013
Partners Capital and Distribution
Net proceeds from IPO, after deducting underwriting discounts and commissions and direct offering expenses				$ 2,825
PAA
Changes in our outstanding shares since becoming public
Percentage of available cash distributed (as a percent)				100.00%
Number of days after end of quarter within which distributions must be paid to unitholders				45 days
PAA \| Distribution to AAP - Level One
Changes in our outstanding shares since becoming public
Percent of distribution amount to the general partner before incentive distributions				2.00%
PAA \| Distribution to AAP - Level Two
Changes in our outstanding shares since becoming public
Percent of distribution amount to the general partner above threshold				15.00%
Quarterly incentive distribution threshold amount (in dollars per unit)				$ 0.2250
PAA \| Distribution to AAP - Level Three
Changes in our outstanding shares since becoming public
Percent of distribution amount to the general partner above threshold				25.00%
Quarterly incentive distribution threshold amount (in dollars per unit)				$ 0.2475
PAA \| Distribution to AAP - Level Four
Changes in our outstanding shares since becoming public
Percent of distribution amount to the general partner above threshold				50.00%
Quarterly incentive distribution threshold amount (in dollars per unit)				$ 0.3375
PAA \| Noncontrolling Interests
Changes in our outstanding shares since becoming public
Noncontrolling interests, ownership percentage of noncontrolling owners			98.00%	98.00%			98.00%
AAP units
Changes in our outstanding shares since becoming public
Shares or units exchanged for Class A shares			(1,451,543)
General partner units
Changes in our outstanding shares since becoming public
Shares or units exchanged for Class A shares			(1,451,543)
AAP \| Noncontrolling Interests
Changes in our outstanding shares since becoming public
Noncontrolling interests, ownership percentage of noncontrolling owners			78.00%	78.00%			99.00%
SLC Pipeline \| Noncontrolling Interests
Changes in our outstanding shares since becoming public
Noncontrolling interests, ownership percentage of noncontrolling owners			25.00%	25.00%			25.00%
PNG \| Noncontrolling Interests
Changes in our outstanding shares since becoming public
Noncontrolling interests, ownership percentage of noncontrolling owners							37.00%
Subsequent Event \| Fourth quarter distribution \| PAA
Changes in our outstanding shares since becoming public
Declaration date of quarterly distribution				Jan. 09, 2014
Unitholders of record, date				Jan. 31, 2014
Class A Shares
Partners Capital and Distribution
Share price of shares sold in IPO (in dollars per share)		$ 22.00
Net proceeds from IPO, after deducting underwriting discounts and commissions and direct offering expenses		$ 2,800
Changes in our outstanding shares since becoming public
Shares issued in connection with the reorganization and IPO		132,382,094
Shares issued in connection with exchanges			1,451,543
Shares outstanding			133,833,637	133,833,637
Percentage of available cash distributed (as a percent)			100.00%
Number of days after end of quarter within which distributions must be paid to shareholders			55 days
Class A Shares \| AAP units
Partners Capital and Distribution
AAP unit conversion ratio to shares			100.00%
Class A Shares \| Subsequent Event \| Fourth quarter distribution
Changes in our outstanding shares since becoming public
Declaration date of quarterly distribution				Jan. 09, 2014
Distributions declared per common share outstanding (in dollars per share)	$ 0.12505
Quarterly distribution declared, aggregate amount	$ 17
Unitholders of record, date				Jan. 31, 2014
Class B Shares
Changes in our outstanding shares since becoming public
Shares issued in connection with the reorganization and IPO		473,647,679
Shares or units exchanged for Class A shares			(1,451,543)
Shares outstanding			472,196,136	472,196,136
Class B Shares \| AAP units \| AAP Management Units
Partners Capital and Distribution
Conversion ratio of AAP Management Units to AAP units and Class B shares				0.90
Class B Shares \| AAP units \| AAP Management Units \| Maximum
Partners Capital and Distribution
Conversion ratio of AAP Management Units to AAP units and Class B shares				1
GP LLC
Changes in our outstanding shares since becoming public
Distributions paid during the period				$ 6	$ 3	$ 2
General partner or managing member ownership interest (as a percent)			100.00%
GP LLC \| AAP term loan
Changes in our outstanding shares since becoming public
Distributions paid during the period				$ 3

Partners' Capital and Distributions (Details 2) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended			12 Months Ended
	Mar. 31, 2012	Nov. 30, 2011	Mar. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reduction in incentive distributions
Net Proceeds				$ 468,000
PAA \| PAA Continuous Offering Program
Reduction in incentive distributions
Units Issued (in shares)				8,600,000	12,000,000
Net Proceeds				$ 468,000	$ 513,000
PAA \| PAA Continuous Offering Program \| Minimum
Reduction in incentive distributions
Maximum aggregate offer price of common stock					$ 300,000
PAA \| PAA Continuous Offering Program \| Maximum
Reduction in incentive distributions
Maximum aggregate offer price of common stock				750,000
PAA \| Other Equity Offerings
Reduction in incentive distributions
Units Issued (in shares)	11,500,000	12,000,000	15,870,000		11,500,000	27,870,000
Gross Unit Price (in dollars per unit)	$ 40.015	$ 32.515	$ 32.000
Proceeds from Sale	$ 460,000	$ 390,000	$ 508,000		$ 460,000	$ 898,000
Costs	(14,000)	(13,000)	(15,000)		(14,000)	(28,000)
Net Proceeds	$ 446,000	$ 377,000	$ 493,000		446,000	870,000
AAP
Reduction in incentive distributions
Reduction in incentive distributions				15,000	$ 11,000	$ 7,000
AAP \| BP NGL Acquisition \| PNG Merger
Reduction in incentive distributions
Reduction in incentive distributions per quarter for distributions paid during 2013 (in dollars per quarter)				3,750
Reduction in incentive distributions in February 2014				6,750
Reduction in incentive distributions per quarter from May 2014 through November 2015 (in dollars per quarter)				5,500
Reduction in incentive distributions per quarter in 2016 (in dollars per quarter)				5,000
Reduction in incentive distributions per quarter after 2016 (in dollars per quarter)				$ 3,750

Partners' Capital and Distributions (Details 3) - USD ($) $ / shares in Units, $ in Millions		1 Months Ended	12 Months Ended
	Feb. 14, 2014	Sep. 30, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
PAA
Partners Capital and Distribution
Cash distributions paid to common unit holders			$ 791	$ 684	$ 575
Cash distribution paid to General Partner - Incentive			353	271	204
Cash distributions paid to General Partner - 2%			16	14	12
Total distributions paid during the period			$ 1,160	$ 969	$ 791
Distribution per limited partner unit (in dollars per unit)			$ 2.33	$ 2.11	$ 1.95
PAA \| Subsequent Event \| Fourth quarter distribution
Partners Capital and Distribution
Declaration date of quarterly distribution			Jan. 09, 2014
Unitholders of record, date			Jan. 31, 2014
Cash distributions paid to common unit holders	$ 221
Cash distribution paid to General Partner - Incentive	102
Cash distributions paid to General Partner - 2%	5
Total distributions paid during the period	$ 328
Distribution per limited partner unit (in dollars per unit)	$ 0.6150
AAP
Partners Capital and Distribution
Total distributions paid during the period			$ 361	$ 276	$ 209
AAP \| AAP term loan
Partners Capital and Distribution
Total distributions paid during the period		$ 299
Increase in amount of term loan		$ 300
AAP \| Subsequent Event \| Fourth quarter distribution
Partners Capital and Distribution
Total distributions paid during the period	$ 104

Partners' Capital and Distributions (Details 4) - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2011
Partners Capital and Distribution
Increase (Decrease) in noncontrolling interest	$ 40	$ 370
PAA \| Indirect Ownership \| AAP
Partners Capital and Distribution
General partner or managing member ownership interest (as a percent)	2.00%
PNG
Partners Capital and Distribution
Increase (Decrease) in noncontrolling interest	$ 40	$ 370
PNG \| Common Units
Partners Capital and Distribution
Units Issued (in shares)	1.9	27.6

Derivatives and Risk Management Activities (Details) bbl / mo in Millions, bbl in Millions, Mcf in Millions, MWh in Millions	Dec. 31, 2013 bbl Mcf MWh bbl / d bbl / mo
Commodity Price Risk Hedging:
Derivative hedges to manage the risk of not utilizing storage capacity (in barrels per month) \| bbl / mo	0.8
Net long position associated with crude oil purchases
Commodity Price Risk Hedging:
Net derivative positions per day (in barrels) \| bbl / d	242,800
Inventory hedged (in barrels, Mcf or megawatt hours)	7.5
Net short spread position hedging anticipated crude oil lease gathering purchases
Commodity Price Risk Hedging:
Net derivative positions per day (in barrels) \| bbl / d	13,600
Inventory hedged (in barrels, Mcf or megawatt hours)	5.4
Butane/WTI spread positions
Commodity Price Risk Hedging:
Net derivative positions per day (in barrels) \| bbl / d	2,200
Inventory hedged (in barrels, Mcf or megawatt hours)	1.0
Long natural gas position for anticipated base gas requirements
Commodity Price Risk Hedging:
Inventory hedged (in barrels, Mcf or megawatt hours) \| Mcf	2.3
Short natural gas position related to anticipated natural gas sales
Commodity Price Risk Hedging:
Inventory hedged (in barrels, Mcf or megawatt hours) \| Mcf	40.5
Short position related to anticipated sales of crude oil, NGL and refined products inventory
Commodity Price Risk Hedging:
Inventory hedged (in barrels, Mcf or megawatt hours)	6.9
PLA crude oil net short position
Commodity Price Risk Hedging:
Net derivative positions per day (in barrels) \| bbl / d	1,700
Inventory hedged (in barrels, Mcf or megawatt hours)	1.2
PLA Crude oil long call option position
Commodity Price Risk Hedging:
Inventory hedged (in barrels, Mcf or megawatt hours)	0.5
Long natural gas position for natural gas purchases
Commodity Price Risk Hedging:
Inventory hedged (in barrels, Mcf or megawatt hours) \| Mcf	19.5
Short propane position related to subsequent sale of products
Commodity Price Risk Hedging:
Inventory hedged (in barrels, Mcf or megawatt hours)	3.4
Short Butane position related to subsequent sale of products
Commodity Price Risk Hedging:
Inventory hedged (in barrels, Mcf or megawatt hours)	1.0
Short WTI position related to subsequent sale of products
Commodity Price Risk Hedging:
Inventory hedged (in barrels, Mcf or megawatt hours)	0.4
Long power position for power supply requirements
Commodity Price Risk Hedging:
Inventory hedged (in barrels, Mcf or megawatt hours) \| MWh	0.5

Derivatives and Risk Management Activities (Details 2) $ in Millions	1 Months Ended					12 Months Ended
	Aug. 31, 2013 USD ($) contract	Jan. 31, 2013 contract	Dec. 31, 2012 USD ($) contract	Mar. 31, 2012 USD ($) contract	Jan. 31, 2011 USD ($) contract	Dec. 31, 2013 USD ($) contract	Jan. 31, 2008 USD ($) contract
PNG
Interest Rate Risk Hedging
Number of interest rate swaps that terminated (in contracts) \| contract						3
Interest Rate Contracts
Interest Rate Risk Hedging
Net deferred gains/(losses) from interest rate risk hedging included in AOCI						$ (65)
10 forward starting interest rate swaps (30-year) \| PAA \| Cash flow hedge
Interest Rate Risk Hedging
Number of outstanding interest rate swaps (in contracts) \| contract						10
Notional amount of derivatives						$ 250
Rate of fixed interest to be received on interest rate swap (as a percent)						3.60%
5 forward starting interest rate swaps (30-year) \| PAA
Interest Rate Risk Hedging
Notional amount of derivatives	$ 125
Rate of fixed interest to be received on interest rate swap (as a percent)	3.39%
Number of interest rate swaps that terminated (in contracts) \| contract	5
Cash payment for (proceeds from) termination of interest rate swaps	$ (11)
Gain on derivative instruments deferred in AOCI	8
5 forward starting interest rate swaps (30-year) \| PAA \| Interest expense
Interest Rate Risk Hedging
Gain on derivative instruments recognized in interest expense attributable to the ineffective portion of the swaps	$ 3
6 forward starting interest rate swaps (30-year) \| PAA
Interest Rate Risk Hedging
Notional amount of derivatives			$ 250
Rate of fixed interest to be received on interest rate swap (as a percent)			4.24%
Number of interest rate swaps that terminated (in contracts) \| contract			6
Cash payment for (proceeds from) termination of interest rate swaps			$ 89
4 forward starting interest rate swaps (10-year) \| PAA
Interest Rate Risk Hedging
Notional amount of derivatives				$ 200
Rate of fixed interest to be received on interest rate swap (as a percent)				3.46%
Number of interest rate swaps that terminated (in contracts) \| contract				4
Cash payment for (proceeds from) termination of interest rate swaps				$ 24
3 forward starting interest rate swaps \| AAP
Interest Rate Risk Hedging
Number of outstanding interest rate swaps (in contracts) \| contract							3
Notional amount of derivatives							$ 200
Rate of fixed interest to be received on interest rate swap (as a percent)							3.99%
Number of interest rate swaps that terminated (in contracts) \| contract		1			2
Forward starting interest rate swaps terminated in January 2011 \| PAA
Interest Rate Risk Hedging
Notional amount of derivatives					$ 100
Rate of fixed interest to be received on interest rate swap (as a percent)					3.60%
Number of interest rate swaps that terminated (in contracts) \| contract					3
Cash payment for (proceeds from) termination of interest rate swaps					$ (12)

Derivatives and Risk Management Activities (Details 3) $ in Millions, $ in Millions	Dec. 31, 2013 USD ($) $ / $	Dec. 31, 2013 CAD ($) $ / $
Foreign exchange contracts
Currency Exchange Rate Risk Hedging:
Notional amount of derivatives \| $		$ 4
Foreign Exchange Forward Contracts that exchange CAD for USD at the Rate USD 1.00 to CAD 1.06 Maturing in 2014
Currency Exchange Rate Risk Hedging:
Notional amount of derivatives	$ 336	$ 358
Average exchange rate for outstanding foreign currency forward exchange contracts	1.06	1.06
Foreign Exchange Forward Contracts that exchange CAD for USD at the Rate USD 1.00 to CAD 1.07 Maturing in 2015
Currency Exchange Rate Risk Hedging:
Notional amount of derivatives	$ 9	$ 9
Average exchange rate for outstanding foreign currency forward exchange contracts	1.07	1.07
Foreign Exchange Forward Contracts that exchange CAD for USD at the Rate USD 1.00 to CAD 1.06
Currency Exchange Rate Risk Hedging:
Notional amount of derivatives	$ 345	$ 367
Average exchange rate for outstanding foreign currency forward exchange contracts	1.06	1.06
Foreign Exchange Forward Contracts that exchange USD for CAD at the Rate USD 1.00 to CAD 1.05 Maturing in 2014
Currency Exchange Rate Risk Hedging:
Notional amount of derivatives	$ 336	$ 354
Average exchange rate for outstanding foreign currency forward exchange contracts	1.05	1.05
Foreign Exchange Forward Contracts that exchange USD for CAD at the Rate USD 1.00 to CAD 1.06 Maturing in 2015
Currency Exchange Rate Risk Hedging:
Notional amount of derivatives	$ 9	$ 9
Average exchange rate for outstanding foreign currency forward exchange contracts	1.06	1.06
Foreign Exchange Forward Contracts that exchange USD for CAD at the Rate USD 1.00 to CAD 1.05
Currency Exchange Rate Risk Hedging:
Notional amount of derivatives	$ 345	$ 363
Average exchange rate for outstanding foreign currency forward exchange contracts	1.05	1.05
Foreign Exchange Forward Contracts Maturing in 2014
Currency Exchange Rate Risk Hedging:
Notional amount of derivatives \| $		$ 4

Derivatives and Risk Management Activities (Details 4) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Impact of derivative activities recognized in earnings
Total	$ (41)	$ 120	$ (40)
Commodity \| Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total	(39)	72	(62)
Commodity \| Facilities segment revenues
Impact of derivative activities recognized in earnings
Total	(11)	3	11
Commodity \| Purchases and related costs
Impact of derivative activities recognized in earnings
Total		46	6
Commodity \| Field Operating costs
Impact of derivative activities recognized in earnings
Total	8	1	1
Interest Rate Contracts \| Interest expense
Impact of derivative activities recognized in earnings
Total	(4)	(7)	(3)
Foreign exchange contracts \| Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total		(1)	1
Foreign exchange contracts \| Other income/(expense), net
Impact of derivative activities recognized in earnings
Total	5	6	6
Derivatives designated as hedging instruments
Impact of derivative activities recognized in earnings
Amount of gain/(loss) reclassified from AOCI into income	66	58	(135)
Other gain/(loss) recognized in income	1		(6)
Derivatives designated as hedging instruments \| Commodity \| Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Amount of gain/(loss) reclassified from AOCI into income	78	12	(153)
Other gain/(loss) recognized in income	(1)		(8)
Derivatives designated as hedging instruments \| Commodity \| Facilities segment revenues
Impact of derivative activities recognized in earnings
Amount of gain/(loss) reclassified from AOCI into income	(10)	3	11
Other gain/(loss) recognized in income	(1)	(1)
Derivatives designated as hedging instruments \| Commodity \| Purchases and related costs
Impact of derivative activities recognized in earnings
Amount of gain/(loss) reclassified from AOCI into income		45	6
Derivatives designated as hedging instruments \| Interest Rate Contracts \| Interest expense
Impact of derivative activities recognized in earnings
Amount of gain/(loss) reclassified from AOCI into income	(7)	(8)	(5)
Other gain/(loss) recognized in income	3	1	2
Derivatives designated as hedging instruments \| Foreign exchange contracts \| Other income/(expense), net
Impact of derivative activities recognized in earnings
Amount of gain/(loss) reclassified from AOCI into income	5	6	6
Derivatives designated as hedging instruments \| Hedged Transactions probable of not occurring \| Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Other gain/(loss) recognized in income	3
Derivatives designated as hedging instruments \| Hedged Transactions probable of not occurring \| Facilities segment revenues
Impact of derivative activities recognized in earnings
Other gain/(loss) recognized in income	(1)		1
Derivatives designated as hedging instruments \| Hedged Transactions probable of not occurring \| Other income/(expense), net
Impact of derivative activities recognized in earnings
Other gain/(loss) recognized in income			1
Derivatives not designated as hedging instruments
Impact of derivative activities recognized in earnings
Total	(108)	62	101
Derivatives not designated as hedging instruments \| Commodity \| Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total	(116)	60	99
Derivatives not designated as hedging instruments \| Commodity \| Facilities segment revenues
Impact of derivative activities recognized in earnings
Total		1
Derivatives not designated as hedging instruments \| Commodity \| Purchases and related costs
Impact of derivative activities recognized in earnings
Total		1
Derivatives not designated as hedging instruments \| Commodity \| Field Operating costs
Impact of derivative activities recognized in earnings
Total	$ 8	1	1
Derivatives not designated as hedging instruments \| Foreign exchange contracts \| Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total		$ (1)	$ 1

Derivatives and Risk Management Activities (Details 5) $ in Millions	12 Months Ended
	Dec. 31, 2013 USD ($) contract	Dec. 31, 2012 USD ($) contract	Dec. 31, 2011 USD ($)
Derivatives disclosures
Asset Derivatives Fair Value	$ 133	$ 191
Liability Derivatives Fair Value	(157)	(189)
Net gain/(loss) deferred in AOCI	(77)
Net gain/(loss) expected to be reclassified to earnings in next 12 months	(10)
Gain/(loss) expected to be reclassified to earnings through 2045	(67)
Net deferred gain/(loss) recognized in AOCI on derivatives (effective portion)	110	43	$ (155)
Broker receivable	161	41
Initial margin	85	69
Variation margin paid/(received)	$ 76	$ (28)
Number of outstanding derivatives containing credit-risk related contingent features \| contract	0	0
Derivative credit-risk related contingent features	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
Commodity
Derivatives disclosures
Net deferred gain/(loss) recognized in AOCI on derivatives (effective portion)	$ 38	$ 56	(18)
Interest Rate Contracts
Derivatives disclosures
Net deferred gain/(loss) recognized in AOCI on derivatives (effective portion)	72	(13)	$ (137)
Derivatives designated as hedging instruments
Derivatives disclosures
Asset Derivatives Fair Value	67	56
Liability Derivatives Fair Value	(24)	(62)
Derivatives designated as hedging instruments \| Commodity \| Other current assets
Derivatives disclosures
Asset Derivatives Fair Value	36	45
Liability Derivatives Fair Value	(24)	(23)
Derivatives designated as hedging instruments \| Commodity \| Other long-term assets
Derivatives disclosures
Asset Derivatives Fair Value	5	11
Liability Derivatives Fair Value		(1)
Derivatives designated as hedging instruments \| Interest Rate Contracts \| Other long-term assets
Derivatives disclosures
Asset Derivatives Fair Value	26
Derivatives designated as hedging instruments \| Interest Rate Contracts \| Other long term liabilities
Derivatives disclosures
Liability Derivatives Fair Value		(38)
Derivatives not designated as hedging instruments
Derivatives disclosures
Asset Derivatives Fair Value	66	135
Liability Derivatives Fair Value	(133)	(127)
Derivatives not designated as hedging instruments \| Commodity \| Other current assets
Derivatives disclosures
Asset Derivatives Fair Value	60	128
Liability Derivatives Fair Value	(117)	(115)
Derivatives not designated as hedging instruments \| Commodity \| Other long-term assets
Derivatives disclosures
Asset Derivatives Fair Value	5	1
Liability Derivatives Fair Value	(6)	(3)
Derivatives not designated as hedging instruments \| Commodity \| Other current liabilities
Derivatives disclosures
Asset Derivatives Fair Value	1	4
Liability Derivatives Fair Value	(5)	(7)
Derivatives not designated as hedging instruments \| Commodity \| Other long term liabilities
Derivatives disclosures
Asset Derivatives Fair Value		2
Liability Derivatives Fair Value	(1)	$ (2)
Derivatives not designated as hedging instruments \| Foreign currency derivatives \| Other current liabilities
Derivatives disclosures
Liability Derivatives Fair Value	$ (4)

Derivatives and Risk Management Activities (Details 6) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
Derivative Asset Positions
Gross Position - Asset	$ 133	$ 191
Netting Adjustment	(148)	(148)
Cash Collateral Paid	161	41
Net Position - Asset	146	84
Derivative Liability Positions
Gross Position - Liability	(157)	(189)
Netting Adjustment	148	148
Net Position - Liability	(9)	(41)
Other current assets
Derivative Asset Positions
Net Position - Asset	116	76
Other long-term assets
Derivative Asset Positions
Net Position - Asset	30	8
Other current liabilities
Derivative Liability Positions
Net Position - Liability	(8)	(3)
Other long term liabilities
Derivative Liability Positions
Net Position - Liability	$ (1)	$ (38)

Derivatives and Risk Management Activities (Details 7) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Sep. 30, 2012	Jun. 30, 2012	Dec. 31, 2013	Dec. 31, 2012
Level 3
Roll forward of Level 3 Net Asset
Beginning Balance			$ 4	$ 12
Total gains/(losses) for the period:
Included in earnings			(1)	(3)
Included in other comprehensive income				3
Settlements			(3)	(22)
Derivatives entered into during the period			(3)	23
Transfers out of Level 3 (liability)		$ 5
Transfers out of Level 3 (asset)				(9)
Ending Balance			(3)	4
Transfers out of Level 3 (asset)	$ 14
Change in unrealized gains/(losses) included in earnings relating to level 3 derivatives still held at the end of the periods			(4)	24
Recurring Fair Value Measures \| Level 1
Recurring Fair Value Measures
Net derivative asset/(liability)			16	1
Recurring Fair Value Measures \| Level 1 \| Commodity
Recurring Fair Value Measures
Net derivative asset/(liability)			16	1
Recurring Fair Value Measures \| Level 2
Recurring Fair Value Measures
Net derivative asset/(liability)			(37)	(3)
Recurring Fair Value Measures \| Level 2 \| Commodity
Recurring Fair Value Measures
Net derivative asset/(liability)			(59)	35
Recurring Fair Value Measures \| Level 2 \| Interest Rate Contracts
Recurring Fair Value Measures
Net derivative asset/(liability)			26	(38)
Recurring Fair Value Measures \| Level 2 \| Foreign currency derivatives
Recurring Fair Value Measures
Net derivative asset/(liability)			(4)
Recurring Fair Value Measures \| Level 3
Recurring Fair Value Measures
Net derivative asset/(liability)			(3)	4
Recurring Fair Value Measures \| Level 3 \| Commodity
Recurring Fair Value Measures
Net derivative asset/(liability)			(3)	4
Recurring Fair Value Measures \| Total
Recurring Fair Value Measures
Net derivative asset/(liability)			(24)	2
Recurring Fair Value Measures \| Total \| Commodity
Recurring Fair Value Measures
Net derivative asset/(liability)			(46)	40
Recurring Fair Value Measures \| Total \| Interest Rate Contracts
Recurring Fair Value Measures
Net derivative asset/(liability)			26	$ (38)
Recurring Fair Value Measures \| Total \| Foreign currency derivatives
Recurring Fair Value Measures
Net derivative asset/(liability)			$ (4)

Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
Income Taxes (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current tax expense:
State income tax	$ 1	$ 2	$ 2
Canadian federal and provincial income tax	99	52	36
Total current tax expense	100	54	38
Deferred tax (benefit)/expense:
Federal Income Tax	7
State income tax			(2)
Canadian federal and provincial income tax	(1)	1	9
Total deferred tax (benefit)/expense	6	1	7
Total income tax expense	$ 106	$ 55	$ 45

Income Taxes (Details 2) - USD ($) $ in Millions	12 Months Ended
Income Taxes (Details 2) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Taxes
Income before tax	$ 1,480	$ 1,173	$ 1,032
Net income attributable to noncontrolling interests	(1,359)	(1,115)	(985)
Income taxes attributable to noncontrolling interest	(99)	(55)	(45)
Income before tax after deducting net income and taxes attributable to noncontrolling interest	$ 22	$ 3	$ 2
Federal statutory income tax rate	35.00%	0.00%	0.00%
Income tax at statutory rate	$ 8
Federal benefit of state income taxes	(1)
Income taxes attributable to noncontrolling interest:
Canadian federal and provincial income taxes	79	$ 35	$ 33
Canadian withholding taxes	19	18	12
State income tax	1	2
Total income tax expense	106	55	$ 45
Deferred tax assets:
Investment in partnerships	1,057
Net operating losses	11
Book accruals in excess of current tax deductions	56	28
Total deferred tax assets	1,124	28
Deferred tax liabilities:
Property and equipment in excess of tax values	(398)	(397)
Total deferred tax liabilities	(398)	(397)
Net deferred tax assets / (liabilities):
Net deferred tax assets	726
Net deferred tax liabilities		(369)
Other long-term assets
Net deferred tax assets / (liabilities):
Net deferred tax assets	1,068
Other long-term liabilities and deferred credits
Net deferred tax assets / (liabilities):
Net deferred tax liabilities	$ (342)	$ (369)

Major Customers and Concentration of Credit Risk (Details) - Revenues - Consolidated revenue	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Marathon Petroleum Corporation
Major Customers and Concentration of Credit Risk
Major customer percentage of total revenue	15.00%	16.00%	16.00%
ExxonMobil Corporation
Major Customers and Concentration of Credit Risk
Major customer percentage of total revenue	13.00%	13.00%	10.00%
ConocoPhillips Company
Major Customers and Concentration of Credit Risk
Major customer percentage of total revenue			10.00%
Phillips 66
Major Customers and Concentration of Credit Risk
Major customer percentage of total revenue	11.00%

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Oxy
Related party transaction
Related party ownership of subisidiary (as a percent)	25.00%
Revenues	$ 1,309	$ 1,636	$ 2,568
Purchases and related costs	863	557	361
Trade accounts receivable and other receivables, gross	133	231
Accounts payable, gross	181	129
Other
Related party transaction
Revenues	33	18
Purchases and related costs	79	42	$ 33
Trade accounts receivable and other receivables, gross	2	8
Accounts payable, gross	$ 6	$ 4

Equity-Indexed Compensation Plans (Details)	1 Months Ended		12 Months Ended
Equity-Indexed Compensation Plans (Details)	Feb. 28, 2014 director shares	Nov. 30, 2013 plan shares	Dec. 31, 2013 $ / shares shares	Dec. 31, 2012 shares	Dec. 31, 2011 shares	Dec. 31, 2010 shares
PAGP LTIP \| Class A Shares
Equity-indexed Compensation Plans
Authorized grants (in units)			10,000,000
Granted (in units)			0
Units outstanding (in units)			0
PAGP LTIP \| Class A Shares \| Directors \| Subsequent Event
Equity-indexed Compensation Plans
Number of directors that received awards \| director	3
Shares issued to directors	83,200
PAA Long-Term Incentive Plan Awards
Equity-indexed Compensation Plans
Granted (in units)			4,100,000	1,500,000	1,000,000
Units outstanding (in units)			8,400,000	6,000,000	8,000,000	8,800,000
Estimated PAA unit vesting in 2014 (in units)			1,900,000
Estimated PAA unit vesting in 2015 (in units)			2,100,000
Estimated PAA unit vesting in 2016 (in units)			2,000,000
Estimated PAA unit vesting in 2017 (in units)			1,300,000
Estimated PAA unit vesting thereafter (in units)			1,100,000
Units outstanding that include DERs (in units)			4,500,000
DERs currently vested (in units)			3,000,000
PAA Long-Term Incentive Plan Awards \| Annualized range of distribution
Equity-indexed Compensation Plans
Annualized quarterly distribution, low end of range (in dollars per unit) \| $ / shares			$ 1.925
Annualized quarterly distribution, high end of range (in dollars per unit) \| $ / shares			$ 2.65
PAA 2013 LTIP
Equity-indexed Compensation Plans
Number of long-term incentive plans consolidated \| plan		3
PAA 2013 LTIP \| Common Units
Equity-indexed Compensation Plans
Authorized grants (in units)		13,100,000
2006 Plan
Equity-indexed Compensation Plans
Authorized grants (in units)			4,200,000
PNG Successor LTIP \| Common Units
Equity-indexed Compensation Plans
Authorized grants (in units)			1,300,000

Equity-Indexed Compensation Plans (Details 2) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	1 Months Ended		12 Months Ended
	May 31, 2012	May 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
PNG Transaction Grants
Outstanding (in units)
Cancelled or forfeited (in units)			(0.3)
Equity-indexed Compensation Plans, Additional Disclosures
Phantom common units which vested in increment (in percent)	50.00%	50.00%
PAA Long-Term Incentive Plan Awards
Outstanding (in units)
Outstanding at beginning of period (in units)			6.0	8.0	8.8
Granted (in units)			4.1	1.5	1.0
Vested (in units)			(1.8)	(3.2)	(1.4)
Cancelled or forfeited (in units)			(0.3)	(0.3)	(0.4)
Conversion of PNG-denominated awards into PAA-denominated awards (in units)			0.4
Outstanding at end of period (in units)			8.4	6.0	8.0
Weighted Average Grant Date Fair Value per unit
Outstanding at beginning of period (in dollars per unit)			$ 25.55	$ 21.77	$ 20.85
Granted (in dollars per unit)			47.60	33.90	27.53
Vested (in dollars per unit)			24.79	19.82	20.34
Cancelled or forfeited (in dollars per unit)			36.70	29.36	20.99
Conversion of PNG unit-denominated awards into PAA unit-denominated award (in dollars per unit)			40.54
Outstanding at end of period (in dollars per unit)			$ 36.97	$ 25.55	$ 21.77
Equity-indexed Compensation Plans, Additional Disclosures
Units issued in connection with the settlement of vested awards, net of tax withholding (in units)			0.5	1.0	0.5
Units withheld for taxes (in units)			0.3	0.5	0.2
Vested awards settled in cash (in units)			1.0	1.7	0.8
PAA Long-Term Incentive Plan Awards \| Liability Awards
Equity-indexed Compensation Plans
Accrued liability related to all outstanding LTIP awards and DERs			$ 98	$ 90
Short-term accrued liability related to all outstanding LTIP awards and DERs			43
Long-term accrued liability related to all outstanding LTIP awards and DERs			$ 55
Annualized distribution probable of occurring (in dollars per share)			$ 2.75
PNG LTIP Awards
Outstanding (in units)
Outstanding at beginning of period (in units)			0.9	0.8	1.0
Granted (in units)			0.4	0.1
Vested (in units)					(0.1)
Cancelled or forfeited (in units)			(0.3)		(0.1)
Conversion of PNG-denominated awards into PAA-denominated awards (in units)			(1.0)
Outstanding at end of period (in units)				0.9	0.8
Weighted Average Grant Date Fair Value per unit
Outstanding at beginning of period (in dollars per unit)			$ 17.49	$ 20.55	$ 20.55
Granted (in dollars per unit)			17.51	15.33
Vested (in dollars per unit)			18.88	23.64	23.62
Cancelled or forfeited (in dollars per unit)			21.62		19.20
Conversion of PNG unit-denominated awards into PAA unit-denominated award (in dollars per unit)			$ 16.41
Outstanding at end of period (in dollars per unit)				$ 17.49	$ 20.55
PNG LTIP Awards \| Maximum
Outstanding (in units)
Vested (in units)			(0.1)	(0.1)

Equity-Indexed Compensation Plans (Details 3) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	1 Months Ended	12 Months Ended			77 Months Ended
	Aug. 31, 2007	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013
Grant Date Fair Value of Outstanding AAP Management Units:
Equity-indexed compensation expense		$ 116	$ 101	$ 110
AAP Management Units
Share-based Compensation Arrangement, by Share-based Payment Award
Authorized grants (in units)		52.1			52.1
Annualized distribution, low end of range (in dollars per unit)		$ 1.75
Annualized distribution, high end of range (in dollars per unit)		$ 2.85
Number of days after achievement of distribution that units will become earned, in some cases	180 days
Threshold on distributions paid for participation in award	$ 11
Maximum participation in excess of distribution (as a percent)	8.00%
Reserved for Future Grants
Reserved for future grants outstanding, beginning balance (in units)		4.7	4.3
Forfeitures (in units)			0.4
Granted (in units)		(1.2)
Reserved for future grants outstanding, ending balance (in units)		3.5	4.7	4.3	3.5
Outstanding
Outstanding at the beginning of the period (in units)		47.4	47.8
Forfeitures (in units)			(0.4)
Granted (in units)		1.2
Outstanding at the ending of the period (in units)		48.6	47.4	47.8	48.6
Outstanding Units Earned
Outstanding Units Earned, beginning balance (in units)		34.0	20.9
Units earned (in units)		13.0	13.1
Outstanding Units Earned, end balance (in units)		47.0	34.0	20.9	47.0
Grant Date Fair Value of Outstanding AAP Management Units:
Grant Date Fair Value of Outstanding AAP Management Units, beginning balance		$ 44	$ 44
Units granted		7
Grant Date Fair Value of Outstanding AAP Management Units, ending balance		51	44	$ 44	$ 51
Equity-indexed compensation expense		$ 5	$ 6	$ 9	$ 49

Equity-Indexed Compensation Plans (Details 4) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Other Consolidated Equity-Indexed Compensation Information
Equity-indexed compensation expense	$ 116	$ 101	$ 110
LTIP unit-settled vestings	48	62	24
LTIP cash-settled vestings	61	66	19
DER cash payments	8	7	4
Equity-indexed Compensation Plan Fair Value Amortization
2014	80
2015	55
2016	36
2017	16
2018	5
Thereafter	1
Total	193
PNG
Other Consolidated Equity-Indexed Compensation Information
LTIP unit-settled vestings		$ 1	$ 2
PNG \| Maximum
Other Consolidated Equity-Indexed Compensation Information
LTIP unit-settled vestings	$ 1

Commitments and Contingencies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Future non-cancelable commitments related to various operating and capital leases
Expenditures related to leases	$ 132	$ 102	$ 60
2014	152
2015	132
2016	124
2017	103
2018	78
Thereafter	386
Total	975
Other commitments
2014	38
2015	32
2016	29
2017	25
2018	16
Thereafter	42
Total	182
Total future non-cancelable commitments
2014	190
2015	164
2016	153
2017	128
2018	94
Thereafter	428
Total	$ 1,157

Commitments and Contingencies (Details 2) - case	1 Months Ended
Commitments and Contingencies (Details 2) - case	Oct. 31, 2013	Sep. 30, 2013	Apr. 30, 2012
Pemex Exploraciony Produccion (PEP)
Loss Contingencies
Total number of cases filed			2
Consolidated Delaware Action \| PNG Merger
Loss Contingencies
Number of cases filed during the period		2
Consolidated Texas Action \| PNG Merger
Loss Contingencies
Number of cases filed during the period		2
Consolidated Federal Action \| PNG Merger
Loss Contingencies
Number of cases filed during the period	4

Commitments and Contingencies (Details 3) $ in Millions	1 Months Ended			2 Months Ended	12 Months Ended	19 Months Ended	33 Months Ended
Commitments and Contingencies (Details 3) $ in Millions	Feb. 28, 2013 bbl	Jun. 30, 2012 bbl	Apr. 30, 2011 bbl	Jun. 30, 2013 event bbl	Dec. 31, 2013 USD ($)	Dec. 31, 2013 USD ($)	Dec. 31, 2013 USD ($)	Jul. 04, 2013 enforcementaction	Feb. 26, 2013 enforcementaction	Dec. 31, 2012 USD ($)
Environmental
Estimated environmental reserve					$ 93	$ 93	$ 93			$ 96
Reserve for environmental liabilities, short-term					11	11	11			13
Reserve for environmental liabilities, long-term					82	82	82			83
Probable recoveries from insurers and third parties recorded as a receivable					$ 10	10	10			$ 42
Minimum
Environmental
Actual cash expenditures for environmental liabilities, period paid					3 years
Maximum
Environmental
Actual cash expenditures for environmental liabilities, period paid					5 years
Rainbow pipeline
Environmental
Estimated size of release (in barrels) \| bbl			28,000
Number of enforcement actions \| enforcementaction									4
Total cost to clean up and remediate the site, before insurance recoveries							70
Rangeland Pipeline Release
Environmental
Estimated size of release (in barrels) \| bbl		3,000
Number of enforcement actions \| enforcementaction								4
Total cost to clean up and remediate the site, before insurance recoveries						46
Penalty or fines assessed					$ 0	$ 0	$ 0
Bay Springs Pipeline
Environmental
Estimated size of release (in barrels) \| bbl	120
Total cost to clean up and remediate the site, before insurance recoveries					6
Kemp River Pipeline Release
Environmental
Number of events occurred \| event				2
Estimated size of release (in barrels) \| bbl				700
Total estimated cost to clean up and remediate the site, before insurance recoveries					$ 15

Quarterly Financial Data (Unaudited) (Details) - USD ($)
$ / shares in Units, $ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Quarterly Financial Data (Unaudited)

Revenues

$ 10,631

$ 10,703

$ 10,295

$ 10,620

$ 9,439

$ 9,354

$ 9,786

$ 9,218

$ 42,249

$ 37,797

$ 34,275

Gross margin

476

375

474

761

479

328

551

407

2,084

1,766

Operating income

391

296

383

655

401

247

462

313

1,724

1,424

1,297

Net income

305

236

299

535

327

171

384

$ 234

1,374

1,118

987

Net income attributable to PAGP

$ 12

$ 1

$ 15

$ 3

$ 2

Basic and diluted net income per Class A share (in dollars per share)

$ 0.10

^[1]

[1]

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References

+ Details

Operating Segments (Details) $ in Millions	3 Months Ended								12 Months Ended
Operating Segments (Details) $ in Millions	Dec. 31, 2013 USD ($)	Sep. 30, 2013 USD ($)	Jun. 30, 2013 USD ($)	Mar. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)	Sep. 30, 2012 USD ($)	Jun. 30, 2012 USD ($)	Mar. 31, 2012 USD ($)	Dec. 31, 2013 USD ($) segment	Dec. 31, 2012 USD ($)	Dec. 31, 2011 USD ($)
Operating segment information
Operating segments number \| segment									3
Revenues:
Revenues	$ 10,631	$ 10,703	$ 10,295	$ 10,620	$ 9,439	$ 9,354	$ 9,786	$ 9,218	$ 42,249	$ 37,797	$ 34,275
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Equity earnings in unconsolidated entities									64	38	13
Segment profit									2,167	1,945	1,560
Capital expenditures									1,641	3,471	1,935
Total assets	21,453				19,259				21,453	19,259	15,414
Maintenance capital									176	170	120
Transportation
Revenues:
Revenues									701	623	572
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Equity earnings in unconsolidated entities									64	38	13
Segment profit									729	710	555
Capital expenditures									1,046	1,244	600
Total assets	7,767				6,447				7,767	6,447	5,189
Maintenance capital									123	108	86
Facilities
Revenues:
Revenues									856	736	638
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Segment profit									616	482	358
Capital expenditures									549	1,724	1,317
Total assets	6,741				6,134				6,741	6,134	4,506
Maintenance capital									38	49	22
Supply and Logistics
Revenues:
Revenues									40,692	36,438	33,065
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Segment profit									822	753	647
Capital expenditures									46	503	18
Total assets	$ 6,945				$ 6,678				6,945	6,678	5,719
Maintenance capital									15	13	12
Interest expense related to hedged inventory									30	12	20
Operating Segments
Revenues:
Revenues									43,571	38,954	35,029
Operating Segments \| Transportation
Revenues:
Revenues									1,498	1,416	1,165
Operating Segments \| Facilities
Revenues:
Revenues									1,377	1,098	796
Operating Segments \| Supply and Logistics
Revenues:
Revenues									40,696	36,440	33,068
Intersegment
Revenues:
Revenues									(1,322)	(1,157)	(754)
Intersegment \| Transportation
Revenues:
Revenues									(797)	(793)	(593)
Intersegment \| Facilities
Revenues:
Revenues									(521)	(362)	(158)
Intersegment \| Supply and Logistics
Revenues:
Revenues									$ (4)	$ (2)	$ (3)

Operating Segments (Details 2) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
Operating Segments (Details 2) - USD ($) $ in Millions	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reconciliation of segment profit to net income attributable to Plains
Segment profit									$ 2,167	$ 1,945	$ 1,560
Unallocated general and administrative expenses									(1)
Depreciation and amortization									(378)	(483)	(250)
Interest expense									(309)	(295)	(259)
Other income/(expense), net									1	6	(19)
Income tax expense									(106)	(55)	(45)
NET INCOME	$ 305	$ 236	$ 299	$ 535	$ 327	$ 171	$ 384	$ 234	1,374	1,118	987
Net income attributable to noncontrolling interests									(1,359)	(1,115)	(985)
NET INCOME ATTRIBUTABLE TO PAGP	$ 12	$ 1	$ 1	$ 1	$ 1	$ 1	$ 1		$ 15	$ 3	$ 2

Operating Segments (Details 3) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
Operating Segments (Details 3) - USD ($) $ in Millions	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues and long-lived assets attributable to geographic areas
Revenues	$ 10,631	$ 10,703	$ 10,295	$ 10,620	$ 9,439	$ 9,354	$ 9,786	$ 9,218	$ 42,249	$ 37,797	$ 34,275
Long-Lived Assets	16,458				14,100				16,458	14,100
United States
Revenues and long-lived assets attributable to geographic areas
Revenues									32,924	29,978	28,181
Long-Lived Assets	12,835				10,423				12,835	10,423
Canada
Revenues and long-lived assets attributable to geographic areas
Revenues									9,325	7,819	$ 6,094
Long-Lived Assets	$ 3,623				$ 3,677				$ 3,623	$ 3,677