Plains All American Pipeline (PAA) 10-K 23 Feb 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2016	Feb. 10, 2017	Jun. 30, 2016
Document and Entity Information
Entity Registrant Name	PLAINS ALL AMERICAN PIPELINE LP
Entity Central Index Key	1,070,423
Document Type	10-K
Document Period End Date	Dec. 31, 2016
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 10.8
Entity Common Stock Outstanding (shares)		675,097,184
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
CURRENT ASSETS
Cash and cash equivalents	$ 47	$ 27
Trade accounts receivable and other receivables, net	2,279	1,785
Inventory	1,343	916
Other current assets	603	241
Total current assets	4,272	2,969
PROPERTY AND EQUIPMENT	16,220	15,654
Accumulated depreciation	(2,348)	(2,180)
Property and equipment, net	13,872	13,474
OTHER ASSETS
Goodwill	2,344	2,405
Investments in unconsolidated entities	2,343	2,027
Linefill and base gas	896	898
Long-term inventory	193	129
Other long-term assets, net	290	386
Total assets	24,210	22,288
CURRENT LIABILITIES
Accounts payable and accrued liabilities	2,588	2,038
Short-term debt	1,715	999
Other current liabilities	361	370
Total current liabilities	4,664	3,407
LONG-TERM LIABILITIES
Senior notes, net of unamortized discounts and debt issuance costs	9,874	9,698
Other long-term debt	250	677
Other long-term liabilities and deferred credits	606	567
Total long-term liabilities	10,730	10,942
COMMITMENTS AND CONTINGENCIES (NOTE 17)
PARTNERS’ CAPITAL
General partner	0	301
Total partners’ capital excluding noncontrolling interests	8,759	7,881
Noncontrolling interests	57	58
Total partners’ capital	8,816	7,939
Total liabilities and partners’ capital	24,210	22,288
Series A Preferred Units
PARTNERS’ CAPITAL
Unitholders	1,508	0
Common Units
PARTNERS’ CAPITAL
Unitholders	$ 7,251	$ 7,580

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Series A Preferred Units
Units outstanding (in units)	64,388,853	0	0	0
Common Units
Units outstanding (in units)	669,194,419	397,727,624	375,107,793	359,133,200

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
REVENUES
Supply and Logistics segment revenues	$ 19,004	$ 21,927	$ 42,114
Transportation segment revenues	632	697	774
Facilities segment revenues	546	528	576
Total revenues	20,182	23,152	43,464
COSTS AND EXPENSES
Purchases and related costs	17,233	19,726	39,500
Field operating costs	1,182	1,454	1,456
General and administrative expenses	279	278	325
Depreciation and amortization	494	432	384
Total costs and expenses	19,188	21,890	41,665
OPERATING INCOME	994	1,262	1,799
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	195	183	108
Interest expense (net of capitalized interest of $47, $57 and $48, respectively)	(467)	(432)	(348)
Other income/(expense), net	33	(7)	(2)
INCOME BEFORE TAX	755	1,006	1,557
Current income tax expense	(85)	(84)	(71)
Deferred income tax benefit/(expense)	60	(16)	(100)
NET INCOME	730	906	1,386
Net income attributable to noncontrolling interests	(4)	(3)	(2)
NET INCOME ATTRIBUTABLE TO PAA	726	903	1,384
NET INCOME PER COMMON UNIT (NOTE 3):
Net income attributable to common unitholders - Basic	$ 200	$ 305	878
Basic net income per common unit (in dollars per unit)	$ 0.43	$ 0.78
Net income attributable to common unitholders - Diluted	$ 200	$ 305	$ 878
Diluted net income per common unit (in dollars per unit)	$ 0.43	$ 0.77
Common Units
NET INCOME PER COMMON UNIT (NOTE 3):
Basic weighted average common units outstanding (in units)	464	394	367
Basic net income per common unit (in dollars per unit)	$ 0.43	$ 0.78	$ 2.39
Diluted weighted average common units outstanding (in units)	466	396	369
Diluted net income per common unit (in dollars per unit)	$ 0.43	$ 0.77	$ 2.38

CONSOLIDATED STATEMENTS OF OPE5

CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Statement [Abstract]
Interest expense, capitalized interest	$ 47	$ 57	$ 48

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement of Comprehensive Income [Abstract]
Net income	$ 730	$ 906	$ 1,386
Other comprehensive income/(loss)	72	(614)	(370)
Comprehensive income	802	292	1,016
Comprehensive income attributable to noncontrolling interests	(4)	(3)	(2)
Comprehensive income attributable to PAA	$ 798	$ 289	$ 1,014

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Balance at beginning of period	$ (1,081)	$ (467)	$ (97)
Reclassification adjustments	8	(45)	4
Deferred gain/(loss) on cash flow hedges, net of tax	(33)	1	(86)
Currency translation adjustments	96	(570)	(288)
Other	1
Total period activity	72	(614)	(370)
Balance at end of period	(1,009)	(1,081)	(467)
Derivative Instruments
Balance at beginning of period	(203)	(159)	(77)
Reclassification adjustments	8	(45)	4
Deferred gain/(loss) on cash flow hedges, net of tax	(33)	1	(86)
Total period activity	(25)	(44)	(82)
Balance at end of period	(228)	(203)	(159)
Translation Adjustments
Balance at beginning of period	(878)	(308)	(20)
Currency translation adjustments	96	(570)	(288)
Total period activity	96	(570)	(288)
Balance at end of period	(782)	$ (878)	$ (308)
Other
Other	1
Total period activity	1
Balance at end of period	$ 1

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 730	$ 906	$ 1,386
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	494	432	384
Equity-indexed compensation expense	60	27	98
Inventory valuation adjustments	3	117	289
Deferred income tax (benefit)/expense	(60)	16	100
Settlement of terminated interest rate hedging instruments	(29)	(48)	(7)
Change in fair value of Preferred Distribution Rate Reset Option (Note 12)	(30)	0	0
Equity earnings in unconsolidated entities	(195)	(183)	(108)
Distributions from unconsolidated entities	216	214	105
Other	23	(21)	24
Changes in assets and liabilities, net of acquisitions:
Trade accounts receivable and other	(524)	803	1,177
Inventory	(463)	(90)	(129)
Accounts payable and other current liabilities	501	(829)	(1,315)
Net cash provided by operating activities	726	1,344	2,004
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions, net of cash acquired (Note 6)	(282)	(105)	(1,098)
Investments in unconsolidated entities (Note 8)	(301)	(253)	(158)
Additions to property, equipment and other	(1,334)	(2,079)	(1,932)
Cash paid for purchases of linefill and base gas	(7)	(133)	(161)
Proceeds from sales of assets	654	5	28
Other investing activities	(3)	35	25
Net cash used in investing activities	(1,273)	(2,530)	(3,296)
CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings/(repayments) under commercial paper program (Note 10)	(564)	631	(366)
Net borrowings under senior secured hedged inventory facility (Note 10)	447	300	0
Repayment under AAP senior secured revolving credit facility (Note 10)	(92)	0	0
Repayment of AAP term loan (Note 10)	(550)	0	0
Proceeds from the issuance of senior notes (Note 10)	748	998	2,595
Repayments of senior notes (Note 10)	(175)	(549)	0
Net proceeds from the sale of Series A preferred units (Note 11)	1,569		0
Net proceeds from the sale of common units (Note 11)	796	1,099	848
Contributions from general partner	42	23	18
Distributions paid to common unitholders (Note 11)	(1,062)	(1,081)	(934)
Distributions paid to general partner (Note 11)	(565)	(590)	(473)
Other financing activities	(31)	(17)	(31)
Net cash provided by financing activities	563	814	1,657
Effect of translation adjustment on cash	4	(4)	(3)
Net increase/(decrease) in cash and cash equivalents	20	(376)	362
Cash and cash equivalents, beginning of period	27	403	41
Cash and cash equivalents, end of period	47	27	403
Cash paid for:
Interest, net of amounts capitalized	450	396	334
Income taxes, net of amounts refunded	$ 98	$ 50	$ 159

CONSOLIDATED STATEMENTS OF CHA9

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL - USD ($) $ in Millions	Total	Partners' Capital Excluding Noncontrolling Interests	Noncontrolling Interests	General PartnerPartners' Capital Excluding Noncontrolling Interests	Series A Preferred UnitsLimited PartnersPartners' Capital Excluding Noncontrolling Interests	Common UnitsLimited PartnersPartners' Capital Excluding Noncontrolling Interests
Balance, beginning of period at Dec. 31, 2013	$ 7,703	$ 7,644	$ 59	$ 295		$ 7,349
Increase (Decrease) in Partners' Capital
Net income	1,386	1,384	2	500		884
Cash distributions to partners	(1,410)	(1,407)	(3)	(473)		(934)
Sale of common units	866	866		18		848
Other comprehensive income (loss)	(370)	(370)		(8)		(362)
Other	16	16		8		8
Balance, end of period at Dec. 31, 2014	8,191	8,133	58	340		7,793
Increase (Decrease) in Partners' Capital
Net income	906	903	3	589		314
Cash distributions to partners	(1,674)	(1,671)	(3)	(590)		(1,081)
Sale of common units	1,121	1,121		22		1,099
Other comprehensive income (loss)	(614)	(614)		(12)		(602)
Other	9	9		(48)		57
Balance, end of period at Dec. 31, 2015	7,939	7,881	58	301		7,580
Increase (Decrease) in Partners' Capital
Net income	730	726	4	393		333
Cash distributions to partners	(1,631)	(1,627)	(4)	(565)		(1,062)
Sale of Series A preferred units	1,542	1,542		33	$ 1,509
Sale of common units	805	805		9		796
Other comprehensive income (loss)	72	72				72
Simplification Transactions (Note 1)	(642)	(642)		(171)		(471)
Other	1	2	(1)		(1)	3
Balance, end of period at Dec. 31, 2016	$ 8,816	$ 8,759	$ 57	$ 0	$ 1,508	$ 7,251

Organization and Basis of Conso

Organization and Basis of Consolidation and Presentation	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Basis of Consolidation and Presentation	Organization and Basis of Consolidation and Presentation Organization Plains All American Pipeline, L.P. (“PAA”) is a Delaware limited partnership formed in 1998. Our operations are conducted directly and indirectly through our primary operating subsidiaries. As used in this Form 10-K and unless the context indicates otherwise, the terms “Partnership,” “we,” “us,” “our,” “ours” and similar terms refer to PAA and its subsidiaries. We own and operate midstream energy infrastructure and provide logistics services for crude oil, natural gas liquids (“NGL”), natural gas and refined products. We own 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: Transportation, Facilities and Supply and Logistics. See Note 19 for further discussion of our operating segments. Our non-economic general partner interest is held by PAA GP LLC (“PAA GP”), a Delaware limited liability company, whose sole member is Plains AAP, L.P. (“AAP”), a Delaware limited partnership. In addition to its ownership of PAA GP, as of December 31, 2016, AAP also owned an approximate 33% limited partner interest in us represented by 241.7 million of our common units. Plains All American GP LLC (“GP LLC”), a Delaware limited liability company, is AAP’s general partner. Plains GP Holdings, L.P. (“PAGP”) is the sole and managing member of GP LLC, and, at December 31, 2016 , owned an approximate 42% limited partner interest in AAP. PAA GP Holdings LLC (“PAGP GP”) is the general partner of PAGP. As the sole member of GP LLC, PAGP has responsibility for conducting our business and managing our operations; however, the board of directors of PAGP GP has ultimate responsibility for managing the business and affairs of PAGP, AAP and us. GP LLC employs our domestic officers and personnel; our Canadian officers and personnel are employed by our subsidiary, Plains Midstream Canada ULC (“PMC”). References to the “PAGP Entities” include PAGP GP, PAGP, GP LLC, AAP and PAA GP. References to our “general partner,” as the context requires, include any or all of the PAGP Entities. References to the “Plains Entities” include us, our subsidiaries and the PAGP Entities. Simplification Transactions On November 15, 2016, the Plains Entities closed a series of transactions and executed several organizational and ancillary documents (the “Simplification Transactions”) intended to simplify our capital structure, better align the interests of our stakeholders and improve our overall credit profile. The Simplification Transactions included, among other things: • the permanent elimination of our incentive distribution rights (“IDRs”) and the economic rights associated with our 2% general partner interest in exchange for the issuance by us to AAP of 245.5 million PAA common units (including approximately 0.8 million units to be issued in the future) and the assumption by us of all of AAP’s outstanding debt ( $642 million ); • the implementation of a unified governance structure pursuant to which the board of directors of GP LLC was eliminated and an expanded board of directors of PAGP GP assumed oversight responsibility over both us and PAGP; • the provision for annual PAGP shareholder elections beginning in 2018 with certain directors with expiring terms in 2018, and the participation of our common unitholders and Series A preferred unitholders in such elections through our ownership of newly issued Class C shares in PAGP, which provide us, as the sole holder, the right to vote in elections of eligible PAGP directors together with the holders of PAGP Class A and Class B shares; • the execution by AAP of a reverse split to adjust the number of AAP Class A units (“AAP units”) such that the number of outstanding AAP units (assuming the conversion of AAP Class B units (the “AAP Management Units”) into AAP units) equaled the number of our common units received by AAP at the closing of the Simplification Transactions. Simultaneously, PAGP executed a reverse split to adjust the number of PAGP Class A and Class B shares outstanding to equal the number of AAP units it owns following AAP’s reverse unit split. These reverse splits, along with the Omnibus Agreement, resulted in economic alignment between our common unitholders and PAGP’s Class A shareholders, such that the number of outstanding PAGP Class A shares equals the number of AAP units owned by PAGP, which in turn equals the number of our common units held by AAP. The Plains Entities also entered into an Omnibus Agreement, pursuant to which such one-to-one relationship will be maintained subsequent to the closing of the Simplification Transactions; and • the creation of a right for certain holders of the AAP units to cause AAP to redeem such AAP units in exchange for an equal number of our common units held by AAP. The Simplification Transactions were between and among consolidated subsidiaries of PAGP that are considered entities under common control. These equity transactions did not result in a change in the carrying value of the underlying assets and liabilities. Definitions Additional defined terms are used in the following notes and shall have the meanings indicated below: AOCI = Accumulated other comprehensive income/(loss) Bcf = Billion cubic feet Btu = British thermal unit CAD = Canadian dollar DERs = Distribution equivalent rights EBITDA = Earnings before interest, taxes, depreciation and amortization EPA = United States Environmental Protection Agency FASB = Financial Accounting Standards Board GAAP = Generally accepted accounting principles in the United States ICE = Intercontinental Exchange IPO = Initial public offering LTIP = Long-term incentive plan Mcf = Thousand cubic feet MLP = Master limited partnership NGL = Natural gas liquids, including ethane, propane and butane NYMEX = New York Mercantile Exchange Oxy = Occidental Petroleum Corporation or its subsidiaries PLA = Pipeline loss allowance USD = United States dollar WTI = West Texas Intermediate Basis of Consolidation and Presentation The accompanying financial statements and related notes present and discuss our consolidated financial position as of December 31, 2016 and 2015 , and the consolidated results of our operations, cash flows, changes in partners’ capital, comprehensive income and changes in accumulated other comprehensive income/(loss) for the years ended December 31, 2016 , 2015 and 2014 . All significant intercompany transactions have been eliminated in consolidation, and certain reclassifications have been made to information from previous years to conform to the current presentation. These reclassifications do not affect net income attributable to PAA. The accompanying consolidated financial statements include the accounts of PAA and all of its wholly owned subsidiaries and those entities that it controls. Investments in entities over which we have significant influence but not control are accounted for by the equity method. We apply proportionate consolidation for pipelines and other assets in which we own undivided joint interests. Subsequent events have been evaluated through the financial statements issuance date and have been included in the following footnotes where applicable.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	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) estimated fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets, (ii) fair value of derivatives, (iii) accruals and contingent liabilities, (iv) equity-indexed compensation plan accruals, (v) property and equipment, depreciation expense and asset retirement obligations, (vi) allowance for doubtful accounts and (vii) inventory valuations. 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, NGL and natural gas 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. Our Transportation segment operations generally consist of fee-based activities associated with transporting crude oil and NGL on pipelines, gathering systems, trucks and barges. 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 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 tariffs. Revenues associated with fees are recognized in the month to which the fee applies. 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 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. 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, as well as NGL fractionation and isomerization services and natural gas and condensate processing services. Revenues generated in this segment include (i) fees that are generated from storage capacity agreements, (ii) terminal throughput fees that are generated when we receive crude oil, refined products or NGL from one connecting source and deliver the applicable product to another connecting carrier, (iii) loading and unloading fees at our rail terminals, (iv) fees from NGL fractionation and isomerization, (v) fees from natural gas and condensate processing services and (vi) fees associated with natural gas park and loan activities, interruptible storage services and wheeling and balancing services. We generate revenue through a combination of month-to-month and multi-year agreements. 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. Minimum Volume Commitments. We have certain agreements that require counterparties to deliver, transport or throughput a minimum volume over an agreed upon period. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote. At December 31, 2016 and 2015 , counterparty deficiencies associated with agreements that include minimum volume commitments totaled $66 million and $33 million , respectively, of which $54 million and $17 million , respectively, was recorded as deferred revenue. The balance of $12 million and $16 million at each respective date was related to deficiencies for which the counterparties had not met their contractual minimum commitments and were not reflected in our Consolidated Financial Statements as we had not yet billed or collected such amounts. Purchases and Related Costs Purchases and related costs include (i) the cost of crude oil, NGL and natural gas obtained in outright purchases, (ii) fees incurred for third-party storage and transportation, whether by pipeline, truck, rail, ship or barge and (iii) 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 inventory 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 (including the impact of gains and losses from derivative related activities), telecommunications, payroll and benefit costs (including equity-indexed compensation expense) for truck drivers and field and other operations 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/Translation 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 Sheets. 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 net loss of $8 million for the year ended December 31, 2016 , a net gain of $21 million for the year ended December 31, 2015 and a net loss of $13 million for the year ended December 31, 2014 . 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, 2016 and 2015 , accounts payable included $66 million and $60 million , respectively, of outstanding checks that were reclassified from cash and cash equivalents. Accounts Receivable, Net Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL and natural gas. 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. The sustained decrease in commodity prices since late 2014 has caused liquidity issues throughout the energy industry, which in turn has increased the potential credit risks associated with certain counterparties with which we do business. To mitigate credit risk related to our accounts receivable, we utilize a rigorous credit review process. We closely monitor market conditions to make a determination with respect to the amount, if any, of open 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 advance cash payments, standby letters of credit or parental guarantees. As of December 31, 2016 and 2015 , we had received $89 million and $88 million , respectively, of advance cash payments from third parties to mitigate credit risk. We also received $66 million and $36 million as of December 31, 2016 and 2015 , respectively, of standby letters of credit to support obligations due from third parties, a portion of which applies to future business. Additionally, in an effort to mitigate credit risk, a significant portion of our transactions with counterparties are settled on a net-cash basis. Furthermore, we also 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, 2016 and 2015 , substantially all of our trade 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 $3 million and $4 million at December 31, 2016 and 2015 , respectively. Although we consider our allowance for doubtful accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts. 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 11 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 $44 million and $35 million , respectively, at December 31, 2016 and 2015 . 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 Note 12 for further discussion. Other Significant Accounting Policies See the respective footnotes for our accounting policies regarding (i) net income per common unit, (ii) inventory, linefill and base gas and long-term inventory, (iii) property and equipment, (iv) acquisitions, (v) goodwill, (vi) investments in unconsolidated entities, (vii) other long-term assets, net, (viii) income allocation for partners’ capital presentation purposes,(ix) derivatives and risk management activities, (x) income taxes, (xi) equity-indexed compensation and (xii) legal and environmental matters. Recent Accounting Pronouncements In November 2016, the FASB issued guidance requiring that a statement of cash flows explain the change in total cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents during the period. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period total amounts shown on the statement of cash flows. This guidance will become effective for interim and annual periods beginning after December 31, 2017. We expect to adopt this guidance on January 1, 2018, and we do not currently anticipate that our adoption will have a material impact on our statement of cash flows. In October 2016, the FASB issued guidance to improve the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. This guidance will become effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted in the first interim period of an annual reporting period. We expect to adopt this guidance on January 1, 2018, and we are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations and cash flows. In October 2016, the FASB issued guidance changing how a reporting entity that is the single decision maker of a variable interest entity (“VIE”) should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. This guidance is effective for interim and annual periods beginning after December 31, 2016. We adopted this guidance on January 1, 2017. Our adoption did not have a material impact on our financial position, results of operations or cash flows. In August 2016, the FASB issued guidance relating to the classification and presentation of eight specific cash flow issues. This guidance will become effective for interim and annual periods beginning after December 15, 2018, with early adoption permitted. We early adopted this guidance during the fourth quarter of 2016, and our adoption had no impact on our statement of cash flows. In June 2016, the FASB issued new guidance for the accounting for credit losses on certain financial instruments. This guidance will become effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted by one year. We expect to adopt this guidance on January 1, 2020, and we are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations and cash flows. In March 2016, the FASB issued guidance to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification of certain related payments on the statement of cash flows. This guidance is effective for interim and annual periods beginning after December 15, 2016, with early adoption permitted. We adopted this guidance on January 1, 2017 and elected to account for forfeitures as they occur, utilizing the modified retrospective approach of adoption. Our adoption did not have a material impact on our financial position, results of operations or cash flows. In February 2016, the FASB issued guidance that revises the current accounting model for leases. The most significant changes are the clarification of the definition of a lease and required lessee recognition on the balance sheet of lease assets and liabilities with lease terms of more than 12 months, including extensive quantitative and qualitative disclosures. This guidance will become effective for interim and annual periods beginning after December 15, 2018, with a modified retrospective application required. Early adoption is permitted, including adoption in an interim period. We expect to adopt this guidance on January 1, 2019. We are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations and cash flows. Although our evaluation is ongoing, we do expect that the adoption will impact our financial statements as the standard requires the recognition on the balance sheet of a right of use asset and corresponding lease liability. We are currently analyzing our contracts to determine whether they contain a lease under the revised guidance and have not quantified the amount of the asset and liability that will be recognized on our consolidated balance sheet. In September 2015, the FASB issued guidance to simplify the accounting for measurement-period adjustments for provisional amounts recognized in a business combination by eliminating the requirement for an acquirer to retrospectively account for measurement-period adjustments. Under the updated guidance, the acquirer must recognize adjustments in the reporting period in which the adjustment amounts are determined and the effect on earnings as a result of the change to the provisional amounts must be calculated as if the accounting had been completed at the acquisition date. This guidance was effective for interim and annual periods beginning after December 15, 2015, with early adoption permitted, and prospective application required. We adopted this guidance on January 1, 2016. Our adoption did not have a material impact on our financial position, results of operations or cash flows. In July 2015, the FASB issued guidance to simplify the measurement of inventory. This updated guidance requires entities to measure inventory at the lower of cost and net realizable value; however, inventory measured using last-in, first-out and the retail inventory method is unchanged by this update. This guidance is effective for interim and annual periods beginning after December 15, 2016, with prospective application required. We adopted this guidance on January 1, 2017. Our adoption did not have a material impact on our financial position, results of operations or cash flows. In February 2015, the FASB issued guidance that revises the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. All legal entities are subject to reevaluation under the revised consolidation model. Among other things, this guidance (i) modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities, (ii) eliminates the presumption that a general partner should consolidate a limited partnership and (iii) affects the consolidation analysis of reporting entities that are involved with variable interest entities, particularly those that have fee arrangements and related party relationships. This guidance was effective for interim and annual periods beginning after December 15, 2015, with early adoption permitted. We adopted this guidance on January 1, 2016. Our adoption did not have a material impact on our financial position, results of operations or cash flows. In August 2014, the FASB issued guidance that requires management to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures in certain situations. This guidance is effective for the annual period ending after December 15, 2016, and for interim and annual periods thereafter. We adopted this guidance for the 2016 annual reporting period. Our adoption has not had any impact on our financial position, results of operations or cash flows. In May 2014, the FASB issued guidance regarding the recognition of revenue from contracts with customers with the underlying principle that an entity will recognize revenue to reflect amounts expected to be received in exchange for the provision of goods and services to customers upon the transfer of those goods or services. The guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue and the related cash flows. This guidance can be adopted either with a full retrospective approach or a modified retrospective approach with a cumulative-effect adjustment as of the date of adoption. This guidance is effective for interim and annual periods beginning after December 15, 2017. We implemented a process to evaluate the impact of adopting this guidance on each type of revenue contract entered into with customers and our implementation team is in the process of determining appropriate changes to our business processes, systems and controls to support recognition and disclosure under the new standard. In addition, while we have not identified any significant revenue recognition timing differences for types of revenue streams assessed to date, our evaluation is not complete, and we have not quantified the impact to our financial statements, including assessing the impact of changes to disclosures. We expect this determination will near completion during the first half of 2017. We will adopt this guidance on January 1, 2018, and are currently evaluating which transition approach to apply.

Net Income Per Common Unit

Net Income Per Common Unit	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Net Income Per Common Unit	Net Income Per Common Unit After consideration of distributions to preferred unitholders (whether cash or paid-in-kind), basic and diluted net income per common unit is determined pursuant to the two-class method as prescribed in FASB guidance. This method is an earnings allocation formula that is used to determine allocations to the general partner, limited partners and participating securities according to distributions pertaining to the current period’s net income and participation rights in undistributed earnings or distributions in excess of earnings. Under the two-class method, net income is reduced by distributions pertaining to the period, and all remaining earnings or distributions in excess of earnings are then allocated to our general partner, common unitholders and participating securities based on their respective rights to share in distributions, regardless of whether those earnings would actually be distributed during a particular period from an economic or practical perspective. Participating securities include LTIP awards that have vested DERs, which entitle the grantee to a cash payment equal to the cash distribution paid on our outstanding common units. The Simplification Transactions, which closed on November 15, 2016, included the permanent elimination of our IDRs and the economic rights associated with our 2% general partner interest in exchange for the issuance by us to AAP of approximately 244.7 million common units and the assumption by us of AAP’s debt. In addition, we will issue to AAP up to 0.8 million common units in connection with certain AAP Management Units becoming earned in future periods. As such, beginning with the distribution pertaining to the fourth quarter of 2016, our general partner is no longer entitled to receive distributions on the IDRs or general partner interest. See Note 1 for additional discussion of the Simplification Transactions. We calculate basic and diluted net income per common unit by dividing net income attributable to PAA (after deducting amounts allocated to the preferred unitholders and participating securities, and for applicable periods, the 2% general partner’s interest and IDRs) by the basic and diluted weighted-average number of common units outstanding during the period. Diluted net income per common unit is computed based on the weighted-average number of common units plus the effect of potentially dilutive securities outstanding during the period, which include (i) our Series A preferred units, (ii) our LTIP awards and (iii) units that are issuable to AAP when certain AAP Management Units are earned. See Note 11 for additional information regarding our Series A preferred units. See Note 16 for a complete discussion of our LTIP awards, including specific discussion regarding DERs, and the AAP Management Units. When applying the if-converted method prescribed by FASB guidance, the possible conversion of our Series A preferred units was excluded from the calculation of diluted net income per common unit for the year ended December 31, 2016 as the effect was antidilutive. Our LTIP awards and certain AAP Management Units that contemplate the issuance of common units are considered dilutive unless (i) vesting occurs only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. LTIP awards that were deemed to be dilutive for the periods presented were reduced by a hypothetical common unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. As none of the necessary conditions for the remaining AAP Management Units to become earned had been satisfied by December 31, 2016, no units issuable to AAP were contemplated in the calculation of diluted net income per common unit. The following table sets forth the computation of basic and diluted net income per common unit (in millions, except per unit data): Year Ended December 31, 2016 2015 2014 Basic Net Income per Common Unit Net income attributable to PAA $ 726 $ 903 $ 1,384 Distributions to Series A preferred units (1) (122 ) — — Distributions to general partner (1) (412 ) (608 ) (502 ) Distributions to participating securities (1) (4 ) (6 ) (6 ) Undistributed loss allocated to general partner (1) 14 16 2 Other (2 ) — — Net income allocated to common unitholders in accordance with application of the two-class method $ 200 $ 305 $ 878 Basic weighted average common units outstanding (2) 464 394 367 Basic net income per common unit $ 0.43 $ 0.78 $ 2.39 Diluted Net Income per Common Unit Net income attributable to PAA $ 726 $ 903 $ 1,384 Distributions to Series A preferred units (1) (122 ) — — Distributions to general partner (1) (412 ) (608 ) (502 ) Distributions to participating securities (1) (4 ) (6 ) (6 ) Undistributed loss allocated to general partner (1) 14 16 2 Other (2 ) — — Net income allocated to common unitholders in accordance with application of the two-class method $ 200 $ 305 $ 878 Basic weighted average common units outstanding (2) 464 394 367 Effect of dilutive securities: Weighted average LTIP units 2 2 2 Diluted weighted average common units outstanding 466 396 369 Diluted net income per common unit $ 0.43 $ 0.77 $ 2.38 (1) We calculate net income allocated to common unitholders based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings (“undistributed loss”), if any, are allocated to the general partner, common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and as further prescribed under the two-class method. (2) We have considered the common units issued in connection with the Simplification Transactions to be outstanding for the entire fourth quarter of 2016 in the calculation of weighted average common units outstanding to more closely reflect the ownership interests in us with rights to the distributions for the periods included in the calculation of net income allocated to common unitholders.

Inventory, Linefill and Base Ga

Inventory, Linefill and Base Gas and Long-term Inventory	12 Months Ended
	Dec. 31, 2016
Inventory, Linefill and Base Gas and Long-term Inventory
Inventory, Linefill and Base Gas and Long-term Inventory	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. Any resulting adjustments are a component of “Purchases and related costs” on our accompanying Consolidated Statements of Operations. During the years ended December 31, 2016 , 2015 and 2014 , we recorded charges of $3 million , $117 million and $289 million , respectively, related to the writedown of our crude oil, NGL and natural gas inventory due to declines in prices. In addition, the charges recorded during the year ended December 31, 2014 included the writedown of our natural gas inventory that was purchased in conjunction with managing natural gas storage deliverability requirements during the extended period of severe cold weather in the first quarter of 2014. A portion of these inventory valuation adjustments was 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 accompanying Consolidated Statement of Operations. See Note 12 for discussion of our derivative and risk management activities. Linefill and base gas 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 and caverns that we own and (iii) natural gas required to maintain the minimum operating pressure of natural gas storage facilities we own. We recognized gains of less than $1 million and $8 million during 2015 and 2014, respectively, on the sale of linefill and base gas for proceeds of $1 million and $24 million , respectively. We did not conduct any sales of linefill and base gas during 2016. Linefill and base gas carrying amounts are reviewed for impairment in accordance with FASB guidance with respect to accounting for the impairment or disposal of long-lived assets. Carrying amounts that are not expected to be recoverable through future cash flows are written down to estimated fair value. See Note 5 for further discussion regarding impairment of long-lived assets. During 2016 , 2015 and 2014 , we did not recognize any impairments of linefill and base gas. Minimum working inventory requirements in third-party assets and other working inventory in our assets that are 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 Sheets. Inventory, linefill and base gas and long-term inventory consisted of the following (barrels and natural gas volumes in thousands and carrying value in millions): December 31, 2016 December 31, 2015 Volumes Unit of Measure Carrying Value Price/ Unit (1) Volumes Unit of Measure Carrying Value Price/ Unit (1) Inventory Crude oil 23,589 barrels $ 1,049 $ 44.47 16,345 barrels $ 608 $ 37.20 NGL 13,497 barrels 242 $ 17.93 13,907 barrels 218 $ 15.68 Natural gas 14,540 Mcf 32 $ 2.20 22,080 Mcf 53 $ 2.40 Other N/A 20 N/A N/A 37 N/A Inventory subtotal 1,343 916 Linefill and base gas Crude oil 12,273 barrels 710 $ 57.85 12,298 barrels 713 $ 57.98 NGL 1,660 barrels 45 $ 27.11 1,348 barrels 44 $ 32.64 Natural gas 30,812 Mcf 141 $ 4.58 30,812 Mcf 141 $ 4.58 Linefill and base gas subtotal 896 898 Long-term inventory Crude oil 3,279 barrels 163 $ 49.71 3,417 barrels 106 $ 31.02 NGL 1,418 barrels 30 $ 21.16 1,652 barrels 23 $ 13.92 Long-term inventory subtotal 193 129 Total $ 2,432 $ 1,943 (1) Price per unit of measure is comprised of 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

Property and Equipment	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Property and Equipment	Property and Equipment In accordance with our capitalization policy, expenditures made to expand the existing operating and/or earnings capacity of our assets are capitalized. We also capitalize certain costs directly related to the construction of such assets, including related internal labor costs, engineering costs and interest costs. For the years ended December 31, 2016 , 2015 and 2014 , capitalized interest recorded to property and equipment was $34 million , $49 million and $48 million , respectively. In addition, we capitalize interest related to investments in certain unconsolidated entities. See Note 8 for additional information. 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 (in millions): Estimated Useful Lives (Years) December 31, 2016 2015 Pipelines and related facilities (1) 10 - 70 $ 9,025 $ 8,395 Storage, terminal and rail facilities 30 - 70 5,305 5,012 Trucking equipment and other 3 - 15 408 392 Construction in progress — 826 1,217 Office property and equipment 2 - 50 222 196 Land and other N/A 434 442 Property and equipment, gross 16,220 15,654 Accumulated depreciation (2,348 ) (2,180 ) Property and equipment, net $ 13,872 $ 13,474 (1) We include rights-of-way, which are intangible assets, in our pipeline and related facilities amounts within property and equipment. We calculate our depreciation using the straight-line method, based on estimated useful lives and salvage values of our assets. Depreciation expense for the years ended December 31, 2016 , 2015 and 2014 was $470 million , $380 million and $319 million , respectively. Such amounts for the 2016 period include $33 million of costs associated with the discontinuation of certain capital projects during 2016 and an $18 million charge related to the write-off of the remaining book value of assets taken out of service. Such assets were included in our Transportation and Facilities segments. 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 6 for a discussion of our acquisition and disposition activities. See “ Impairment of Long-Lived Assets ” below for a discussion of our policy for the recognition of asset impairments. 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. During the year ended December 31, 2016, we recognized $80 million of non-cash impairment losses on certain of our long-lived rail and other terminal assets included in our Facilities segment. Such impairment losses are reflected in “Depreciation and amortization” on our Consolidated Financial Statements. The decline in demand for movements of crude oil by rail in the United States due to sustained unfavorable market conditions resulted in expected decreases in future cash flows for certain of our rail terminal assets, which was a triggering event that required us to assess the recoverability of our carrying value of such long-lived assets. As a result of this impairment review, we wrote off the portion of the carrying amount of these long-lived assets that exceeded their fair value. Our estimated fair values were based upon recent sales prices of comparable facilities, as well as management’s expectation of the market values for such assets based on their industry experience. We consider such inputs to be a Level 3 input in the fair value hierarchy. We did no t recognize any impairments during the year ended December 31, 2015. During the year ended December 31, 2014, we recognized impairments of $10 million primarily related to assets that were taken out of service.

Acquisitions and Dispositions

Acquisitions and Dispositions	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
Acquisitions and Dispositions	Acquisitions and Dispositions The following acquisitions, excluding acquired interests accounted for under the equity method of accounting mentioned specifically below, 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. Acquisitions 2017 . On February 14, 2017, we acquired 100% of the equity interests of Alpha Holding Company, LLC (“Alpha Holding”) for cash consideration of $1.215 billion , subject to working capital and other adjustments. Alpha Holding indirectly owns the Alpha Crude Connector (“ACC”) gathering system located in the Northern Delaware Basin in Southeastern New Mexico and West Texas. The ACC gathering system is comprised of 515 miles of recently constructed gathering and transmission lines and five market interconnects, including to our Basin Pipeline at Wink, and is supported by long-term acreage dedications. The initial accounting for this acquisition was not complete as of the financial statement issuance date. 2016 . During the year ended December 31, 2016, we completed two acquisitions for aggregate cash consideration of $289 million . These acquisitions included (i) an integrated system of NGL assets in Western Canada for cash consideration of approximately $204 million and (ii) the remaining interest in a Gulf Coast pipeline that was subsequently sold in July 2016. The assets acquired were primarily included in our Transportation and Facilities segments. We did no t recognize any goodwill related to these acquisitions. 2015. During the year ended December 31, 2015, we completed three acquisitions for aggregate cash consideration of $105 million . These acquisitions included (i) an additional approximate 28% interest in Frontier Aspen LLC, which is accounted for under the equity method of accounting, (ii) a crude oil terminal included in our Facilities segment and (iii) the remaining interest in a pipeline system included in our Transportation segment. We recognized goodwill of $11 million related to these acquisitions. See Note 8 for additional discussion of our equity method investments. 2014 . During the year ended December 31, 2014, we completed three acquisitions for aggregate cash consideration of $1.099 billion . Included in these acquisitions was a 50% interest in BridgeTex Pipeline Company, LLC from Oxy. We account for this investment under the equity method of accounting. See Note 8 for additional discussion. The remaining acquisitions were a crude oil terminal and a propane terminal included in our Facilities segment. We recognized goodwill of $1 million related to these acquisitions. Dispositions and Divestitures During the year ended December 31, 2016, we sold several non-core assets, including certain of our Gulf Coast pipelines and East Coast refined products terminals. In addition, we sold interests in Cheyenne Pipeline LLC and STACK Pipeline LLC. See Note 8 for additional discussion. In the aggregate, we recognized a net gain of approximately $100 million related to these transactions, which is included in “Depreciation and amortization” on our Consolidated Statement of Operations. Such amount is comprised of gains of $158 million and losses of $58 million , including $15 million of impairment of goodwill that was included in a disposal group classified as held for sale prior to the closing of such transaction. During 2015 and 2014, we sold various property and equipment and recognized a net loss of $2 million and a net gain of $1 million , respectively. As of December 31, 2016, we classified approximately $275 million of assets as held for sale on our Consolidated Balance Sheet (in “Other current assets”) primarily related to definitive agreements to sell non-core assets, a majority of which are property and equipment and included in our Facilities segment. We expect the sales to be consummated in the first half of 2017, subject to customary closing conditions, as applicable. As of December 31, 2015, we did no t have any assets classified as held for sale. During the first quarter of 2017, we completed the sale of an undivided interest in a segment of our Red River Pipeline for proceeds of approximately $70 million . In addition, we executed definitive agreements to sell two non-core assets for aggregate proceeds of approximately $310 million . These transactions include a natural gas storage facility and a non-core pipeline segment and are expected to close during the first half of 2017.

Goodwill

Goodwill	12 Months Ended
	Dec. 31, 2016
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill	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 to determine whether an impairment has occurred at least annually (as of June 30) and on an interim basis if it is more likely than not that a reporting unit’s fair value is less than its carrying value. 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 2016 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 to 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; therefore, goodwill was not considered impaired. We did not recognize any material impairments of goodwill during the last three years. Goodwill by segment and changes in goodwill is reflected in the following table (in millions): Transportation Facilities Supply and Logistics Total Balance at December 31, 2014 $ 854 $ 1,152 $ 459 $ 2,465 Acquisitions 3 8 — 11 Foreign currency translation adjustments (42 ) (19 ) (10 ) (71 ) Other — (54 ) 54 — Balance at December 31, 2015 $ 815 $ 1,087 $ 503 $ 2,405 Foreign currency translation adjustments 6 3 1 10 Dispositions and reclassifications to assets held for sale (15 ) (56 ) — (71 ) Balance at December 31, 2016 $ 806 $ 1,034 $ 504 $ 2,344

Investments in Unconsolidated E

Investments in Unconsolidated Entities	12 Months Ended
	Dec. 31, 2016
Equity Method Investments and Joint Ventures [Abstract]
Investments in Unconsolidated Entities	Investments in Unconsolidated Entities Investments in entities over which we have significant influence but not control are accounted for by the equity method. 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 our Consolidated Balance Sheets. 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. Our investments in unconsolidated entities consisted of the following (in millions, except percentage data): Ownership Interest at December 31, 2016 December 31, Entity Type of Operation 2016 2015 BridgeTex Pipeline Company, LLC (“BridgeTex”) Crude Oil Pipeline 50% $ 1,098 $ 1,082 Butte Pipe Line Company Crude Oil Pipeline 22% 11 9 Caddo Pipeline LLC Crude Oil Pipeline 50% 65 28 Cheyenne Pipeline LLC (“Cheyenne”) Crude Oil Pipeline 50% 30 — Diamond Pipeline LLC (“Diamond”) Crude Oil Pipeline (1) 50% 143 38 Eagle Ford Pipeline LLC Crude Oil Pipeline 50% 372 382 Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Terminals”) Crude Oil Terminal and Dock (1) 50% 53 29 Frontier Aspen LLC Crude Oil Pipeline 50% 45 48 Saddlehorn Pipeline Company, LLC Crude Oil Pipeline 40% 213 103 Settoon, Towing LLC Barge Transportation Services 50% 87 84 STACK Pipeline LLC (“STACK”) Crude Oil Pipeline 50% 14 — White Cliffs Pipeline, LLC Crude Oil Pipeline 36% 212 224 Total Investments in Unconsolidated Entities $ 2,343 $ 2,027 (1) Asset is currently under construction by the entity and has not yet been placed in service. In June 2016, we sold 50% of our investment in Cheyenne, and in August 2016 we sold 50% of our investment in STACK. As a result of these transactions, we now account for our remaining 50% equity interest in such entities under the equity method of accounting. See Note 6 for additional information related to these transactions. In November 2014, we acquired a 50% interest in BridgeTex from Oxy. BridgeTex owns a crude oil pipeline that extends from Colorado City in West Texas to a crude oil terminal in East Houston, which we believe is complementary to our existing West Texas assets. We paid cash of $1.088 billion , including working capital adjustments of $13 million , for our interest in BridgeTex. Distributions received from unconsolidated entities are classified based on the nature of the distribution approach, which looks to the activity that generated the distribution. We consider distributions received from unconsolidated entities as a return on investment in those entities to the extent that the distribution was generated through operating results, and therefore classify these distributions as cash flows from operating activities in our Consolidated Statement of Cash Flows. Other distributions received from unconsolidated entities are considered a return of investment and classified as cash flows from investing activities on the Consolidated Statement of Cash Flows. We generally fund our portion of development, construction or capital expansion projects of our equity method investees through capital contributions. Our contributions to these entities increase the carrying value of our investments and are reflected in our Consolidated Statements of Cash Flows as cash used in investing activities. During the years ended December 31, 2016 , 2015 and 2014 , we made cash contributions of $288 million , $245 million and $158 million , respectively, to certain of our equity method investees. The contributions amount for 2015 is net of $53 million of cash received as a return of our investment. In addition, we capitalized interest of $13 million and $8 million during the years ended December 31, 2016 and 2015, respectively, related to contributions to unconsolidated entities for projects under development and construction. We anticipate that we will make additional contributions related to ongoing projects at BridgeTex, Diamond, Eagle Ford Terminals and STACK over the next few years. Our investments in unconsolidated entities exceeded our share of the underlying equity in the net assets of such entities by $736 million and $760 million at December 31, 2016 and 2015 , respectively. Such basis differences are included in the carrying values of our investments on our Consolidated Balance Sheets. The portion of the basis differences attributable to depreciable or amortizable assets is amortized on a straight-line basis over the estimated useful life of the related assets, which reduces “Equity earnings in unconsolidated entities” on our Consolidated Statements of Operations. The portion of the basis differences attributable to goodwill is not amortized. The basis difference is primarily related to our acquisition of an interest in BridgeTex in 2014. Summarized Financial Information of Unconsolidated Entities Combined summarized financial information for all of our unconsolidated entities is shown in the tables below (in millions). None of our unconsolidated entities have noncontrolling interests. December 31, 2016 2015 Current assets $ 303 $ 365 Noncurrent assets $ 3,558 $ 2,901 Current liabilities $ 241 $ 231 Noncurrent liabilities $ 162 $ 184 Year Ended December 31, 2016 2015 2014 Revenues $ 802 $ 769 $ 531 Operating income $ 469 $ 441 $ 301 Net income $ 452 $ 424 $ 285

Other Long-Term Assets, Net

Other Long-Term Assets, Net	12 Months Ended
	Dec. 31, 2016
Other Assets [Abstract]
Other Long-Term Assets, Net	Other Long-Term Assets, Net Other long-term assets, net of accumulated amortization, consisted of the following (in millions): December 31, 2016 2015 Intangible assets (1) $ 603 $ 610 Fair value of derivative instruments 1 9 Other 47 94 651 713 Accumulated amortization (361 ) (327 ) $ 290 $ 386 (1) We include rights-of-way, which are intangible assets, in our pipeline and related facilities amounts within property and equipment. See Note 5 for a discussion of property and equipment. Amortization expense for finite-lived intangible assets for the years ended December 31, 2016 , 2015 and 2014 was $44 million , $49 million and $57 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 consisted of the following (in millions): December 31, 2016 December 31, 2015 Estimated Useful Lives (Years) Cost Accumulated Amortization Net Cost Accumulated Amortization Net Customer contracts and relationships 1 – 20 $ 529 $ (330 ) $ 199 $ 537 $ (301 ) $ 236 Property tax abatement 7 – 13 38 (26 ) 12 38 (22 ) 16 Other agreements 25 – 70 29 (5 ) 24 28 (4 ) 24 Emission reduction credits (1) N/A 7 — 7 7 — 7 $ 603 $ (361 ) $ 242 $ 610 $ (327 ) $ 283 (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): 2017 $ 42 2018 $ 37 2019 $ 34 2020 $ 32 2021 $ 30

Debt

Debt	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Debt	Debt Debt consisted of the following (in millions): December 31, December 31, SHORT-TERM DEBT Commercial paper notes, bearing a weighted-average interest rate of 1.6% and 1.1%, respectively (1) $ 563 $ 696 Senior secured hedged inventory facility, bearing a weighted-average interest rate of 1.8% and 1.4%, respectively (1) 750 300 Senior notes: 6.13% senior notes due January 2017 400 — Other 2 3 Total short-term debt (2) 1,715 999 LONG-TERM DEBT Senior notes: 5.88% senior notes due August 2016 (3) — 175 6.13% senior notes due January 2017 — 400 6.50% senior notes due May 2018 600 600 8.75% senior notes due May 2019 350 350 2.60% senior notes due December 2019 500 500 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 700 700 3.60% senior notes due November 2024 750 750 4.65% senior notes due October 2025 1,000 1,000 4.50% senior notes due December 2026 750 — 6.70% senior notes due May 2036 250 250 6.65% senior notes due January 2037 600 600 5.15% senior notes due June 2042 500 500 4.30% senior notes due January 2043 350 350 4.70% senior notes due June 2044 700 700 4.90% senior notes due February 2045 650 650 Unamortized discounts and debt issuance costs (76 ) (77 ) Senior notes, net of unamortized discounts and debt issuance costs 9,874 9,698 Commercial paper notes, bearing a weighted-average interest rate of 1.6% and 1.1%, respectively (3) 247 672 Other 3 5 Total long-term debt 10,124 10,375 Total debt (4) $ 11,839 $ 11,374 (1) We classified these commercial paper notes and credit facility borrowings as short-term at December 31, 2016 and 2015 , as these notes and borrowings were primarily designated as working capital borrowings, were required to be repaid within one year and were primarily for hedged NGL and crude oil inventory and NYMEX and ICE margin deposits. (2) At December 31, 2016, includes borrowings of $410 million for cash margin deposits with NYMEX and ICE, which are associated with financial derivatives used for hedging purposes. (3) As of December 31, 2016 and 2015 , we classified a portion of our commercial paper notes as long-term and as of December 31, 2015, we classified our $175 million , 5.88% senior notes due August 2016 as long-term based on our ability and intent to refinance such amounts on a long-term basis under our credit facilities. (4) Our fixed-rate senior notes (including current maturities) had a face value of approximately $10.3 billion and $9.8 billion as of December 31, 2016 and 2015 , respectively. We estimated the aggregate fair value of these notes as of December 31, 2016 and 2015 to be approximately $10.4 billion and $8.6 billion , respectively. Our fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near year end. We estimate that the carrying value of outstanding borrowings under our credit facilities and commercial paper program approximates fair value as interest rates reflect current market rates. The fair value estimates for our senior notes, credit facilities and commercial paper program are based upon observable market data and are classified in Level 2 of the fair value hierarchy. Commercial Paper Program We have a commercial paper program under which we may issue (and have outstanding at any time) up to $3.0 billion in the aggregate of privately placed, unsecured commercial paper notes. Such notes are backstopped by our senior unsecured revolving credit facility and our senior secured hedged inventory facility; as such, any borrowings under our commercial paper program reduce the available capacity under these facilities. Credit Facilities Senior secured hedged inventory facility . We have a credit agreement that provides for a senior secured hedged inventory facility with 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 capacity of the facility may be increased to $1.9 billion . Proceeds from the facility are primarily used to finance purchased or stored hedged inventory, including NYMEX and ICE margin deposits. Such obligations under the committed facility are secured by the financed inventory and the associated accounts receivable and are repaid from the proceeds of the sale of the financed inventory. Borrowings accrue interest based, at our election, on either the Eurocurrency Rate or the Base Rate , in each case plus a margin based on our credit rating at the applicable time. The agreement also provides for one or more one -year extensions, subject to applicable approval. In August 2016, we amended this agreement to, among other things, extend the maturity date of the facility to August 2019 for each extending lender. The maturity date with respect to each non-extending lender (which represent aggregate commitments of approximately $126.3 million out of total commitments of $1.4 billion from all lenders) remains August 2018. Senior unsecured revolving credit facility. We have a credit agreement that provides for a senior unsecured revolving credit facility with a committed borrowing capacity of $1.6 billion . Subject to obtaining additional or increased lender commitments, the committed capacity may be increased to $2.1 billion . The credit agreement also provides for the issuance of letters of credit. Borrowings accrue interest based, at our election, on the Eurocurrency Rate, the Base Rate or the Canadian Prime Rate , in each case plus a margin based on our credit rating at the applicable time. The agreement also provides for one or more one -year extensions, subject to applicable approval. In August 2016, we amended this agreement to, among other things, extend the maturity date of the facility to August 2021 for each extending lender. The maturity date with respect to each non-extending lender (which represent aggregate commitments of $140 million out of total commitments of $1.6 billion from all lenders) remains August 2020. Senior unsecured 364-day revolving credit facility. We have a credit agreement that provides for a 364 -day senior unsecured revolving credit facility with a borrowing capacity of $1.0 billion . In August 2016, we amended this agreement to extend the maturity date to August 2017. Borrowings accrue interest based, at our election, on either the Eurocurrency Rate or the Base Rate , as defined in the agreement, in each case plus a margin based on our credit rating at the applicable time. AAP senior secured credit agreement . In connection with the Simplification Transactions, on November 15, 2016, we assumed all of AAP’s then outstanding borrowings under the AAP senior secured credit agreement, and immediately repaid such amounts and canceled the credit agreement. See Note 1 for further discussion of the Simplification Transactions. Senior Notes Our 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. We may, at our 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. Our senior notes are not guaranteed by any of our subsidiaries. Senior Notes Issuances The table below summarizes our issuances of senior unsecured notes during 2016 , 2015 and 2014 (in millions): Year Description Maturity Face Value Interest Payment Dates 2016 4.50% Senior Notes issued at 99.716% of face value December 2026 $ 750 June 15 and December 15 2015 4.65% Senior Notes issued at 99.846% of face value October 2025 $ 1,000 April 15 and October 15 2014 2.60% Senior Notes issued at 99.813% of face value December 2019 $ 500 June 15 and December 15 2014 4.90% Senior Notes issued at 99.876% of face value February 2045 $ 650 February 15 and August 15 2014 3.60% Senior Notes issued at 99.842% of face value November 2024 $ 750 May 1 and November 1 2014 4.70% Senior Notes issued at 99.734% of face value June 2044 $ 700 June 15 and December 15 Senior Note Repayments Our $400 million , 6.13% senior notes were repaid in January 2017. Our $175 million , 5.88% senior notes were repaid in August 2016. We utilized cash on hand and available capacity under our commercial paper program and credit facilities to repay these notes. Our $150 million , 5.25% senior notes and $400 million , 3.95% senior notes were repaid in June 2015 and September 2015, respectively. We utilized cash on hand and available capacity under our commercial paper program to repay these notes. Maturities The weighted average maturity of our long-term debt outstanding at December 31, 2016 was approximately 11 years . The following table presents the aggregate contractually scheduled maturities of such long-term debt for the next five years and thereafter. The amounts presented exclude unamortized discounts and debt issuance costs. Calendar Year Payment (in millions) 2017 $ 247 2018 600 2019 850 2020 500 2021 600 Thereafter 7,403 Covenants and Compliance Our credit agreements (which impact our ability to access our commercial paper program because they provide the backstop that supports our short-term credit ratings) and the indentures governing our senior notes contain cross-default provisions. Our 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 our ability to, among other things: • grant liens on certain property; • incur indebtedness, including capital leases; • sell substantially all of our assets or enter into a merger or consolidation; • engage in certain transactions with affiliates; and • enter into certain burdensome agreements. The credit agreements for our senior unsecured revolving credit facility, senior secured hedged inventory facility and senior unsecured 364-day revolving credit facility treat a change of control as an event of default and also require us to maintain a debt-to-EBITDA coverage ratio that, on a trailing four-quarter basis, 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 ), and/or during the GP Simplification Period (the period beginning on November 15, 2016 and ending on December 31, 2017)). For covenant compliance purposes, Consolidated EBITDA may include certain adjustments, including those for material projects and certain non-recurring expenses. Additionally, letters of credit and borrowings to fund hedged inventory and margin requirements are excluded when calculating the debt coverage ratio. A default under our credit facilities would permit the lenders to accelerate the maturity of the outstanding debt. As long as we are in compliance with our credit agreements, our ability to make distributions of available cash is not restricted. As of December 31, 2016, we were in compliance with the covenants contained in our credit agreements and indentures. Borrowings and Repayments Total borrowings under our credit agreements and commercial paper program for the years ended December 31, 2016 , 2015 and 2014 were approximately $60.3 billion , $62.2 billion and $70.9 billion , respectively. Total repayments under our credit agreements and commercial paper program were approximately $61.0 billion , $61.3 billion and $71.3 billion for the years ended December 31, 2016 , 2015 and 2014 , 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, derivative transactions and construction activities. At December 31, 2016 and 2015 , we had outstanding letters of credit of $73 million and $46 million , respectively. Debt Issuance Costs Costs incurred in connection with the issuance of senior notes are recorded as a direct deduction from the related debt liability and are 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.

Partners' Capital and Distribut

Partners' Capital and Distributions	12 Months Ended
	Dec. 31, 2016
Partners' Capital Notes [Abstract]
Partners' Capital and Distributions	Partners’ Capital and Distributions Units Outstanding At December 31, 2016 , partners’ capital consisted of outstanding common units and Series A preferred units, which represent limited partner interests in us, which give the holders thereof the right to participate in distributions and to exercise the other rights or privileges as outlined in our partnership agreement. Our general partner has a non-economic interest in us. However, prior to the closing of the Simplification Transactions, our outstanding common units and Series A preferred units represented a 98% effective aggregate ownership interest in us and our subsidiaries after giving effect to the 2% general partner interest. See Note 1 for discussion of the Simplification Transactions. The following table presents the activity for our Series A preferred units and common units: Limited Partners Preferred Units Common Units Outstanding at December 31, 2013 — 359,133,200 Sale of common units — 15,375,810 Issuance of common units under LTIP — 598,783 Outstanding at December 31, 2014 — 375,107,793 Sale of common units — 22,133,904 Issuance of common units under LTIP — 485,927 Outstanding at December 31, 2015 — 397,727,624 Sale of Series A preferred units 61,030,127 — Issuance of Series A preferred units in connection with in-kind distributions 3,358,726 — Sale of common units — 26,278,288 Issuance of common units under LTIP — 480,581 Issuance of common units in connection with Simplification Transactions — 244,707,926 Outstanding at December 31, 2016 64,388,853 669,194,419 Distributions In accordance with our partnership agreement, after making distributions to holders of outstanding Series A preferred units, we distribute 100% of our available cash within 45 days following the end of each quarter to unitholders of record. Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter, less reserves established in the discretion of our general partner for future requirements. The following table details distributions paid during the year presented (in millions, except per unit data): Distributions Paid Distributions per common unit Year Common Unitholders General Partner (1) Total 2016 $ 1,062 $ 565 $ 1,627 $ 2.65 2015 $ 1,081 $ 590 $ 1,671 $ 2.76 2014 $ 934 $ 473 $ 1,407 $ 2.55 (1) During the years ended December 31, 2016 , 2015 and 2014 , our general partner’s incentive distributions were reduced by approximately $18 million , $22 million and $23 million , respectively, which were agreed to in connection with certain acquisitions. On January 9, 2017 , we declared a cash distribution of $0.55 per unit on our outstanding common units. The total distribution of $371 million was paid on February 14, 2017 to unitholders of record on January 31, 2017 , for the period October 1, 2016 through December 31, 2016 . General Partner Distributions . Prior to the Simplification Transactions, our general partner was entitled to receive (i) distributions representing its 2% indirect general partner interest and (ii) as the holder of our IDRs, incentive distributions if the amount we distributed with respect to any quarter exceeded certain specified levels. Under the quarterly distribution provisions contained in our partnership agreements effective prior to the Simplification Transactions, our general partner was entitled directly and indirectly, without duplication and except for the agreed upon adjustments discussed below, to 2% of amounts we distributed up to $0.2250 per unit, referred to as our minimum quarterly distribution, 15% of amounts we distributed in excess of $0.2250 per unit, 25% of the amounts we distributed in excess of $0.2475 per unit and 50% of amounts we distributed in excess of $0.3375 per unit. In-kind distributions. In 2016, we issued 3,358,726 additional Series A preferred units in lieu of cash distributions of $89 million . On February 14, 2017, we issued 1,287,773 additional Series A preferred units in lieu of a cash distribution of $34 million . Since this quarterly distribution was declared as payment-in-kind, the distribution payable was accrued to partners’ capital as of December 31, 2016 and thus had no net impact on the Series A preferred unitholders’ capital account. Equity Offerings Common Unit Issuances . We have entered into several equity distribution agreements under our Continuous Offering Program, pursuant to which we may offer and sell, through sales agents, common units representing limited partner interests. In addition to our Continuous Offering Program, we may sell common units through overnight or underwritten offerings. The following table summarizes our issuance of common units in connection with our Continuous Offering Program and underwritten offerings (net proceeds in millions): Year Type of Offering Units Issued Net Proceeds (1) (2) 2016 Total Continuous Offering Program 26,278,288 $ 805 (3) 2015 Continuous Offering Program 1,133,904 $ 59 (3) 2015 Underwritten Offering 21,000,000 1,062 2015 Total 22,133,904 $ 1,121 2014 Total Continuous Offering Program 15,375,810 $ 866 (3) (1) Amounts are net of costs associated with the offerings. (2) For periods prior to the closing of the Simplification Transactions, amounts include our general partner’s proportionate capital contributions of $9 million , $22 million and $18 million during 2016 , 2015 and 2014 , respectively. (3) We pay commissions to our sales agents in connection with common unit issuances under our Continuous Offering Program. We paid $8 million , $1 million and $9 million of such commissions during 2016 , 2015 and 2014 , respectively. Preferred Unit Issuance . On January 28, 2016 (the “Issuance Date”), we completed the private placement of approximately 61.0 million Series A preferred units representing limited partner interests in us for a cash purchase price of $26.25 per unit (the “Issue Price”), resulting in total net proceeds to us, after deducting offering expenses and the 2% transaction fee due to the purchasers and including our general partner’s proportionate capital contribution, of approximately $1.6 billion . Certain of the purchasers or their affiliates are related parties. See Note 15 for additional information. The Series A preferred units are a new class of equity security that ranks senior to all classes or series of our equity securities with respect to distribution rights and rights upon liquidation. The holders of the Series A preferred units receive cumulative quarterly distributions, subject to customary antidilution adjustments, equal to $0.525 per unit ( $2.10 per unit annualized). With respect to any quarter ending on or prior to December 31, 2017 (the “Initial Distribution Period”), we may elect to pay distributions on the Series A preferred units in additional preferred units, in cash or a combination of both. With respect to any quarter ending after the Initial Distribution Period, we must pay distributions on the Series A preferred units in cash. The purchasers may convert their Series A preferred units into common units, generally on a one-for-one basis and subject to customary anti-dilution adjustments, at any time after the second anniversary of the Issuance Date (or prior to a liquidation), in whole or in part, subject to certain minimum conversion amounts. We may convert the Series A preferred units into common units at any time (but not more often than once per quarter) after the third anniversary of the Issuance Date, in whole or in part, subject to certain minimum conversion amounts, if the closing price of our common units is greater than 150% of the Issue Price for the preceding 20 trading days. The Series A preferred units will vote on an as-converted basis with our common units and will have certain other class voting rights with respect to any amendment to our partnership agreement that would adversely affect any rights, preferences or privileges of the Series A preferred units. In addition, upon certain events involving a change of control, the holders of the Series A preferred units may elect, among other potential elections, to convert the preferred units to common units at the then applicable conversion rate. For a period of 30 days following (a) the fifth anniversary of the Issuance Date of the Series A preferred units and (b) each subsequent anniversary of the Issuance Date, the holders of the Series A preferred units, acting by majority vote, may make a one -time election to reset the distribution rate to equal the then applicable rate of the ten-year U.S. Treasury plus 5.85% (the “Preferred Distribution Rate Reset Option”). The Preferred Distribution Rate Reset Option is accounted for as an embedded derivative. See Note 12 for additional information. If the holders of the Series A preferred units have exercised the Preferred Distribution Rate Reset Option, then, at any time following 30 days after the sixth anniversary of the Issuance Date, we may redeem all or any portion of the outstanding Series A preferred units in exchange for cash, common units (valued at 95% of the volume-weighted average price of the common units for a trading day period specified in our partnership agreement) or a combination of cash and common units at a redemption price equal to 110% of the Issue Price, plus any accrued and unpaid distributions. Income Allocation We allocate net income for partners’ capital presentation purposes by applying the allocation methodology in our partnership agreement. Following the closing of the Simplification Transactions, net income is allocated 100% to our common unitholders, after giving effect to income allocations for cash distributions to our preferred unitholders. In accordance with our partnership agreement, our preferred unitholders are not allocated income for paid-in-kind distributions for partners’ capital presentation purposes. For periods prior to the Simplification Transactions, our general partner and common unitholders were allocated income based on their respective partnership percentages, after giving effect to income allocations for (i) incentive distributions, if any, to our general partner for distributions declared and paid following the close of each quarter and (ii) cash distributions to our preferred unitholders. Our preferred unitholders were not allocated income for paid-in-kind distributions for partners’ capital presentation purposes. For purposes of determining basic and diluted net income per common unit, income is allocated as prescribed in FASB guidance for calculating earnings per unit, including a deduction to income available to common unitholders for cash or paid-in-kind distributions to preferred untiholders. See Note 3 for additional information. Noncontrolling Interests in Subsidiaries As of December 31, 2016 , noncontrolling interests in our subsidiaries consisted of a 25% interest in SLC Pipeline LLC.

Derivatives and Risk Management

Derivatives and Risk Management Activities	12 Months Ended
	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives and Risk Management Activities	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 manage our exposure to (i) commodity price risk, as well as to optimize our profits, (ii) interest rate risk and (iii) currency exchange rate risk. Our commodity price 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 throughout the hedging relationship, we assess whether the derivatives employed are highly effective in offsetting changes in cash flows of anticipated hedged transactions. Commodity Price Risk Hedging Our core business activities involve certain commodity price-related risks that we manage in various ways, including through 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, 2016 , net derivative positions related to these activities included: • A net long position of 3.6 million barrels associated with our crude oil purchases, which was unwound ratably during January 2017 to match monthly average pricing. • A net short time spread position of 5.2 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through January 2018. • A crude oil grade basis position of 43.8 million barrels through December 2019. These derivatives allow us to lock in grade basis differentials. • A net short position of 12.2 Bcf through May 2017 related to anticipated sales of natural gas inventory. • A net short position of 34.5 million barrels through December 2019 related to anticipated net sales of our crude oil and NGL inventory. Pipeline Loss Allowance Oil — As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor that is intended to, among other things, offset losses due to evaporation, measurement and other losses in transit. We utilize derivative instruments to hedge a portion of the anticipated sales of the allowance oil that is to be collected under our tariffs. As of December 31, 2016 , our PLA hedges included a long call option position of 0.9 million barrels through November 2018. Natural Gas Processing/NGL Fractionation — We purchase natural gas for processing and operational needs. Additionally, we purchase NGL mix for fractionation and 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, 2016 , we had a long natural gas position of 61.3 Bcf which hedges our natural gas processing and operational needs through December 2018. We also had a short propane position of 10.6 million barrels through December 2018, a short butane position of 3.2 million barrels through December 2018 and a short WTI position of 1.5 million barrels through December 2018. In addition, we had a long power position of 0.3 million megawatt hours, which hedges a portion of our power supply requirements at our Canadian natural gas processing and fractionation plants through December 2018. Physical commodity contracts that meet the definition of a derivative but are ineligible, or not designated, for the normal purchases and normal sales scope exception are recorded on the balance sheet at fair value, with changes in fair value recognized in earnings. We have determined that substantially all of our physical commodity contracts qualify for the normal purchases and normal sales scope exception. Interest Rate Risk Hedging We use interest rate derivatives to hedge the benchmark interest rate associated interest payments occurring as a result of debt issuances. The derivative instruments we use to manage this risk consist of forward starting interest rate swaps and treasury locks. These derivatives are designated as cash flow hedges. As such, changes in fair value are deferred in AOCI and are reclassified to interest expense as we incur the interest payments associated with the underlying debt. The following table summarizes the terms of our outstanding interest rate derivatives as of December 31, 2016 (notional amounts in millions): Hedged Transaction Number and Types of Derivatives Employed Notional Amount Expected Termination Date Average Rate Locked Accounting Treatment Anticipated interest payments 8 forward starting swaps (30-year) $ 200 6/15/2017 3.14 % Cash flow hedge Anticipated interest payments 8 forward starting swaps (30-year) $ 200 6/15/2018 3.20 % Cash flow hedge Anticipated interest payments 8 forward starting swaps (30-year) $ 200 6/14/2019 2.83 % Cash flow hedge 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 risk of unfavorable changes in exchange rates. These instruments include foreign currency exchange contracts and forwards. As of December 31, 2016 , our outstanding foreign currency derivatives include derivatives we use to hedge currency exchange risk (i) associated with USD-denominated commodity purchases and sales in Canada and (ii) 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, 2016 (in millions): USD CAD Average Exchange Rate USD to CAD Forward exchange contracts that exchange CAD for USD: 2017 $ 274 $ 363 $1.00 - $1.33 Forward exchange contracts that exchange USD for CAD: 2017 $ 492 $ 652 $1.00 - $1.33 Preferred Distribution Rate Reset Option A derivative feature embedded in a contract that does not meet the definition of a derivative in its entirety must be bifurcated and accounted for separately if the economic characteristics and risks of the embedded derivative are not clearly and closely related to those of the host contract. The Preferred Distribution Rate Reset Option of our Series A preferred units is an embedded derivative that must be bifurcated from the related host contract, our partnership agreement, and recorded at fair value on our Consolidated Balance Sheets. Corresponding changes in fair value are recognized in “Other income/(expense), net” in our Consolidated Statement of Operations. At December 31, 2016 , the fair value of this embedded derivative was a liability of approximately $32 million . We recognized gains of approximately $30 million for the year ended December 31, 2016 . See Note 11 for additional information regarding our Series A preferred units and the Preferred Distribution Rate Reset Option. 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 classified within the same category as the related hedged item in our Consolidated Statements of Cash Flows. A summary of the impact of our derivative activities recognized in earnings for the periods indicated is as follows (in millions): Year Ended December 31, 2016 Location of Gain/(Loss) Derivatives in Hedging Relationships (1) (2) Derivatives Not Designated as a Hedge Total Commodity Derivatives Supply and Logistics segment revenues $ 2 $ (344 ) $ (342 ) Transportation segment revenues — 5 5 Interest Rate Derivatives Interest expense, net (14 ) — (14 ) Foreign Currency Derivatives Supply and Logistics segment revenues — (3 ) (3 ) Preferred Distribution Rate Reset Option Other income/(expense), net — 30 30 Total Gain/(Loss) on Derivatives Recognized in Net Income $ (12 ) $ (312 ) $ (324 ) Year Ended December 31, 2015 Location of Gain/(Loss) Derivatives in Hedging Relationships (1) (2) Derivatives Not Designated as a Hedge Total Commodity Derivatives Supply and Logistics segment revenues $ 56 $ 152 $ 208 Transportation segment revenues — 8 8 Field operating costs — (18 ) (18 ) Interest Rate Derivatives Interest expense, net (11 ) — (11 ) Foreign Currency Derivatives Supply and Logistics segment revenues — (31 ) (31 ) Total Gain/(Loss) on Derivatives Recognized in Net Income $ 45 $ 111 $ 156 Year Ended December 31, 2014 Location of Gain/(Loss) Derivatives in Hedging Relationships (1) (2) Derivatives Not Designated as a Hedge Total Commodity Derivatives Supply and Logistics segment revenues $ (1 ) $ 206 $ 205 Field operating costs — (21 ) (21 ) Interest Rate Derivatives Interest expense, net (5 ) — (5 ) Foreign Currency Derivatives Supply and Logistics segment revenues — (28 ) (28 ) Other income/(expense), net 2 — 2 Total Gain/(Loss) on Derivatives Recognized in Net Income $ (4 ) $ 157 $ 153 (1) During the year ended December 31, 2016, we reclassified losses of approximately $2 million and $2 million from AOCI to Supply and Logistics segment revenues and Interest expense, net, respectively, due to anticipated hedged transactions being probable of not occurring. During the year ended December 31, 2015, we reclassified a loss of approximately $4 million from AOCI to Interest expense, net due to an anticipated hedged transaction being probable of not occurring. During the year ended December 31, 2014, all of our hedged transactions were probable of occurring. (2) Amounts in Interest expense, net include a loss of $4 million during the year ended December 31, 2016 attributable to the ineffective portion of cash flow hedges. No ineffectiveness was recognized for cash flow hedges during the years ended December 31, 2015 and 2014. The following table summarizes the derivative assets and liabilities on our Consolidated Balance Sheet on a gross basis as of December 31, 2016 (in millions): Asset Derivatives Liability Derivatives Balance Sheet Location Fair Value Balance Sheet Location Fair Value Derivatives designated as hedging instruments: Commodity derivatives $ — Other current assets $ — Interest rate derivatives — Other current liabilities (23 ) Other long-term liabilities and deferred credits (27 ) Total derivatives designated as hedging instruments $ — $ (50 ) Derivatives not designated as hedging instruments: Commodity derivatives Other current assets $ 101 Other current assets $ (344 ) Other long-term assets, net 2 Other long-term assets, net (1 ) Other long-term liabilities and deferred credits 2 Other current liabilities (14 ) Other long-term liabilities and deferred credits (34 ) Foreign currency derivatives Other current liabilities 3 Other current liabilities (6 ) Preferred Distribution Rate Reset Option — Other long-term liabilities and deferred credits (32 ) Total derivatives not designated as hedging instruments $ 108 $ (431 ) Total derivatives $ 108 $ (481 ) The following table summarizes the derivative assets and liabilities on our Consolidated Balance Sheet on a gross basis as of December 31, 2015 (in millions): Asset Derivatives Liability Derivatives Balance Sheet Location Fair Value Balance Sheet Location Fair Value Derivatives designated as hedging instruments: Commodity derivatives Other current assets $ 4 Other current assets $ (2 ) Interest rate derivatives Other long-term assets, net 1 Other current liabilities (17 ) Other long-term liabilities and deferred credits (33 ) Total derivatives designated as hedging instruments $ 5 $ (52 ) Derivatives not designated as hedging instruments: Commodity derivatives Other current assets $ 265 Other current assets $ (35 ) Other long-term assets, net 10 Other long-term assets, net (1 ) Other current liabilities (13 ) Other long-term liabilities and deferred credits (1 ) Foreign currency derivatives Other current liabilities (8 ) Total derivatives not designated as hedging instruments $ 275 $ (58 ) Total derivatives $ 280 $ (110 ) 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 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. The following table provides the components of our net broker receivable/(payable): December 31, 2016 December 31, 2015 Initial margin $ 119 $ 91 Variation margin posted/(returned) 291 (247 ) Net broker receivable/(payable) $ 410 $ (156 ) The following table presents information about derivative financial assets and liabilities that are subject to offsetting, including enforceable master netting arrangements (in millions): December 31, 2016 December 31, 2015 Derivative Asset Positions Derivative Liability Positions Derivative Asset Positions Derivative Liability Positions Netting Adjustments: Gross position - asset/(liability) $ 108 $ (481 ) $ 280 $ (110 ) Netting adjustment (350 ) 350 (38 ) 38 Cash collateral paid/(received) 410 — (156 ) — Net position - asset/(liability) $ 168 $ (131 ) $ 86 $ (72 ) Balance Sheet Location After Netting Adjustments: Other current assets $ 167 $ — $ 76 $ — Other long-term assets, net 1 — 10 — Other current liabilities — (40 ) — (38 ) Other long-term liabilities and deferred credits — (91 ) — (34 ) $ 168 $ (131 ) $ 86 $ (72 ) As of December 31, 2016 , there was a net loss of $228 million deferred in AOCI. 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, 2016 , we expect to reclassify a net loss of $8 million to earnings in the next twelve months. The remaining deferred loss of $220 million is expected to be reclassified to earnings through 2049. A portion of these amounts is based on market prices as of December 31, 2016 ; thus, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions. The following table summarizes the net deferred gain/(loss), including tax effects, recognized in AOCI for derivatives (in millions): Year Ended December 31, 2016 2015 2014 Commodity derivatives, net $ — $ 33 $ 15 Interest rate derivatives, net (33 ) (32 ) (103 ) Foreign currency derivatives, net — — 2 Total $ (33 ) $ 1 $ (86 ) At December 31, 2016 and December 31, 2015 , 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 (in millions): Fair Value as of December 31, 2016 Fair Value as of December 31, 2015 Recurring Fair Value Measures (1) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Commodity derivatives $ (113 ) $ (171 ) $ (4 ) $ (288 ) $ 126 $ 90 $ 11 $ 227 Interest rate derivatives — (50 ) — (50 ) — (49 ) — (49 ) Foreign currency derivatives — (3 ) — (3 ) — (8 ) — (8 ) Preferred Distribution Rate Reset Option — — (32 ) (32 ) — — — — Total net derivative asset/(liability) $ (113 ) $ (224 ) $ (36 ) $ (373 ) $ 126 $ 33 $ 11 $ 170 (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. In addition, it includes certain physical commodity contracts. 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 certain physical commodity contracts and the Preferred Distribution Rate Reset Option contained in our partnership agreement which is classified as an embedded derivative. 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 or decrease in these forward prices could result in a material change in fair value to our physical commodity contracts. We report unrealized gains and losses associated with these physical commodity contracts in our Consolidated Statements of Operations as Supply and Logistics segment revenues. The fair value of the embedded derivative feature contained in our partnership agreement is based on a valuation model that estimates the fair value of the Series A preferred units with and without the Preferred Distribution Rate Reset Option. This model contains inputs, including our common unit price, ten-year U.S. treasury rates, default probabilities and timing estimates which involve management judgment. A significant increase or decrease in the value of these inputs could result in a material change in fair value to this embedded derivative feature. We report unrealized gains and losses associated with this embedded derivative in our Consolidated Statements of Operations as “Other income/(expense), net.” To the extent any transfers between levels of the fair value hierarchy occur, our policy is to reflect these transfers as of the beginning of the reporting period in which they occur. 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, 2016 2015 Beginning Balance $ 11 $ 15 Net gains for the period included in earnings 28 1 Settlements (10 ) (14 ) Derivatives entered into during the period (65 ) 9 Ending Balance $ (36 ) $ 11 Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period $ (36 ) $ 10

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes Income tax expense is estimated using the tax rate in effect or to be in effect during the relevant periods in the jurisdictions in which we operate. Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes and are stated at enacted tax rates expected to be in effect when taxes are actually paid or recovered. To the extent we do not consider it more likely than not that a deferred tax asset will be recovered, a valuation allowance is established. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. We review contingent tax liabilities for estimated exposures on a more likely than not standard related to our current tax positions. Pursuant to FASB guidance related to accounting for uncertainty in income taxes, we may 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, 2016 and 2015 , we had not recognized any material amounts in connection with uncertainty in income taxes. U.S. Federal and State Taxes As an MLP, we are not subject to U.S. federal income taxes; rather the tax effect of our operations is passed through to our unitholders. Although we are subject to state income taxes in some states, the impact to the years ended December 31, 2016 , 2015 , and 2014 was immaterial. Canadian Federal and Provincial Taxes All of our Canadian operations are conducted by entities that are treated as corporations for Canadian tax purposes (flow through for U.S. income 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, 2016 2015 2014 Current income tax expense: State income tax $ 2 $ 1 $ 1 Canadian federal and provincial income tax 83 83 70 Total current income tax expense $ 85 $ 84 $ 71 Deferred income tax expense/(benefit): Canadian federal and provincial income tax $ (60 ) $ 16 $ 100 Total deferred income tax expense/(benefit) $ (60 ) $ 16 $ 100 Total income tax expense $ 25 $ 100 $ 171 The difference between income tax expense based on the statutory federal income tax rate and our effective income tax expense is summarized as follows (in millions): Year Ended December 31, 2016 2015 2014 Income before tax $ 755 $ 1,006 $ 1,557 Partnership earnings not subject to current Canadian tax (723 ) (773 ) (976 ) $ 32 $ 233 $ 581 Canadian federal and provincial corporate tax rate 27 % 26 % 25 % Income tax at statutory rate $ 8 $ 61 $ 145 Canadian withholding tax $ 13 $ 14 $ 16 Canadian permanent differences and rate changes 2 24 9 State income tax 2 1 1 Total income tax expense $ 25 $ 100 $ 171 Deferred tax assets and liabilities are aggregated by the applicable tax paying entity and jurisdiction and result from the following (in millions): December 31, 2016 2015 Deferred tax assets: Derivative instruments $ 49 $ — Book accruals in excess of current tax deductions 24 20 Net operating losses 4 3 Total deferred tax assets 77 23 Deferred tax liabilities: Derivative instruments — (30 ) Property and equipment in excess of tax values (394 ) (312 ) Other (41 ) (41 ) Total deferred tax liabilities (435 ) (383 ) Net deferred tax liabilities $ (358 ) $ (360 ) Balance sheet classification of deferred tax assets/(liabilities): Other long-term assets, net $ 4 $ 3 Other long-term liabilities and deferred credits (362 ) (363 ) $ (358 ) $ (360 ) As of December 31, 2016 , we had foreign net operating loss carryforwards of $15 million , which will expire beginning in 2034. Generally, tax returns for our Canadian entities are open to audit from 2008 through 2016. Our U.S. and state tax years are generally open to examination from 2013 to 2016.

Major Customers and Concentrati

Major Customers and Concentration of Credit Risk	12 Months Ended
	Dec. 31, 2016
Risks and Uncertainties [Abstract]
Major Customers and Concentration of Credit Risk	Major Customers and Concentration of Credit Risk Marathon Petroleum Corporation and its subsidiaries accounted for 18% , 17% and 17% of our revenues for the years ended December 31, 2016 , 2015 and 2014 , respectively. ExxonMobil Corporation and its subsidiaries accounted for 14% , 13% and 15% of our revenues for the years ended December 31, 2016 , 2015 and 2014 , respectively. Phillips 66 Company and its subsidiaries accounted for 11% of our revenues for the year ended December 31, 2016. No other customers accounted for 10% or more of our revenues during any of the three years ended December 31, 2016 . 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. 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

Related Party Transactions	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions Ownership of PAGP Class C Shares As of December 31, 2016, we owned 491,910,863 Class C shares of PAGP. The Class C shares represent a non-economic limited partner interest in PAGP that provides us, as the sole holder, the right to vote in elections of eligible PAGP GP directors together with the holders of PAGP’s Class A and Class B shares, commencing in 2018. Reimbursement of Our General Partner and its Affiliates Our general partner provides general and administrative services necessary to manage and operate our business, properties and assets, including employing or retaining personnel. We do not pay our general partner a management fee, but we do reimburse our general partner for all direct and indirect costs it incurs or payments it makes on our behalf, including the costs of employee, officer and director compensation and benefits allocable to us as well as all other expenses necessary or appropriate to the conduct of our business. We record these costs on the accrual basis in the period in which our general partner incurs them. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. Total costs reimbursed by us to our general partner for the years ended December 31, 2016 , 2015 and 2014 were $514 million , $648 million and $598 million , respectively. Omnibus Agreement In connection with the Simplification Transactions completed in November 2016, the Plains Entities entered into an Omnibus Agreement, which provides for the following: • that, for all periods following the closing of the Simplification Transactions, we will pay all direct or indirect expenses of any of the PAGP Entities, other than income taxes (including, but not limited to, (i) compensation for the directors of PAGP GP, (ii) director and officer liability insurance, (iii) listing exchange fees, (iv) investor relations expenses and (v) fees related to legal, tax, financial advisory and accounting services). We paid $4 million of such expenses in 2016; • the ability of PAGP to issue additional Class A shares and use the net proceeds therefrom to purchase a like number of AAP units from AAP, and the corresponding ability of AAP to use the net proceeds therefrom to purchase a like number of our common units from us; and • the ability of PAGP to lend proceeds of any future indebtedness incurred by it to AAP, and AAP’s corresponding ability to lend such proceeds to us, in each case on substantially the same terms as incurred by PAGP. See Note 1 for discussion of the Simplification Transactions. Transactions with Oxy As of December 31, 2016 , Oxy had a representative on the board of directors of PAGP and owned approximately 13% of the limited partner interests in AAP. During the three years ended December 31, 2016 , we recognized sales and transportation revenues and purchased petroleum products from Oxy. These transactions were conducted at posted tariff rates or prices that we believe approximate market. Included in these transactions was a crude oil buy/sell agreement that includes a multi-year minimum volume commitment. The impact to our Consolidated Statements of Operations from those transactions is included below (in millions): Year Ended December 31, 2016 2015 2014 Revenues $ 655 $ 866 $ 1,212 Purchases and related costs (1) $ 42 $ 41 $ 925 (1) Purchases and related costs include crude oil buy/sell transactions that are accounted for as inventory exchanges and are presented net in our Consolidated Statements of Operations. We currently have a netting arrangement with Oxy. Our gross receivable and payable amounts with Oxy were as follows (in millions): December 31, 2016 2015 Trade accounts receivable and other receivables $ 789 $ 405 Accounts payable $ 836 $ 363 In November 2014, we purchased Oxy’s 50% interest in BridgeTex. See Note 8 for further discussion. Also in November 2014, Oxy exchanged a portion of its interest in our general partner for Class A shares of PAGP and immediately sold such shares through a secondary public offering completed by PAGP. Transactions with Equity Method Investees We also have transactions with companies in which we hold an investment accounted for under the equity method of accounting (see Note 8 for information related to these investments). We recorded revenues of $14 million , $17 million and $3 million during the years ended December 31, 2016 , 2015 and 2014 , respectively. During the three years ended December 31, 2016 , we utilized transportation services and purchased petroleum products provided by these companies. Costs related to these services totaled $209 million , $164 million and $75 million for the years ended December 31, 2016 , 2015 and 2014 , 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 $39 million and $14 million at December 31, 2016 and 2015 , respectively, and included amounts related to capital activity at several of our investments. In addition, we had prepaid tariff costs related to our equity method investees of $14 million at December 31, 2016. Accounts payable to our equity method investees were $35 million and $25 million at December 31, 2016 and 2015 , respectively, and included amounts related to capital activity at several of our investments. In addition, we have an agreement to transport crude oil at posted tariff rates on a pipeline that is owned by an equity method investee, in which we own a 50% interest. Our commitment to transport is supported by crude oil buy/sell agreements with third parties (including Oxy) with commensurate quantities. Preferred Unit Issuance In January 2016, we completed a private placement of preferred units. Certain of the purchasers of the preferred units or their affiliates are related parties. Kayne Anderson Capital Advisors, L.P. and certain of its affiliates and an affiliate of The Energy Minerals Group hold ownership interests in our general partner. In addition, certain of the current directors of our general partner are affiliated with certain of the purchasers. See Note 11 for additional information.

Equity-Indexed Compensation Pla

Equity-Indexed Compensation Plans	12 Months Ended
	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Equity-Indexed Compensation Plans	Equity-Indexed Compensation Plans PAA Long-Term Incentive Plan Awards Plains All American 2013 Long-Term Incentive Plan . In November 2013, our common unitholders approved the Plains All American 2013 Long-Term Incentive Plan (the “PAA 2013 LTIP”). The PAA 2013 LTIP authorizes the issuance of an aggregate of approximately 10.1 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 . Our general partner has adopted the Plains All American PNG Successor Long-Term Incentive Plan (the “PNG Successor LTIP”). 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. Our 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 10.8 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. Our general partner is entitled to reimbursement by us for any costs incurred in settling obligations under the PAA 2013 LTIP, the PNG Successor LTIP or the 2006 Plan. At December 31, 2016 , the following LTIP awards, denominated in PAA units, were outstanding (units in millions): PAA LTIP Units Outstanding (1) (2) PAA Distribution Required (3) Estimated Unit Vesting Date 2017 2018 2019 2020 Thereafter Total 8.9 $2.20-$2.65 1.7 2.1 2.0 1.3 1.8 8.9 (1) Approximately 4.3 million of the 8.9 million outstanding PAA LTIP awards also include DERs, of which 1.6 million had vested as of December 31, 2016 . (2) LTIP units outstanding do not include AAP Management Units. (3) Certain LTIP awards vest upon the later of a certain date or the attainment of performance conditions requiring the attainment of certain annualized PAA distribution levels or upon the attainment of such levels alone. 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. As of December 31, 2016 , a distribution of $2.20 per common unit was deemed probable of occurring in the reasonably foreseeable future (and was initially determined to be probable in the third quarter of 2016). Our 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 underlying 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. Certain LTIP awards contain performance conditions based on the attainment of certain annualized distribution levels and vest upon the later of a certain date or the attainment of such levels. For awards with performance conditions (such as distribution targets), expense is accrued over the service period only if the performance condition is considered probable of occurring. When awards with performance conditions that were previously considered improbable become probable, we incur additional expense in the period that the probability assessment changes. This is necessary to bring the accrued obligation associated with these awards up to the level it would be 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 they are paid as a reduction of partners’ capital. During the third quarter of 2016 modifications were made to the vesting criteria of 2.2 million PAA LTIP units such that the awards, with performance conditions requiring the attainment of an annualized PAA distribution in excess of $2.80 , no longer include a distribution performance threshold and will vest based solely on the passage of time during the years 2017 to 2020 ( 0.9 million of these units would have vested based on the passage of time, but will vest earlier following the modification). There are awards outstanding that were issued prior to the modification in the third quarter of 2016 which had performance conditions requiring the attainment of an annualized PAA distribution between $2.30 and $2.80 which have been satisfied and those awards will vest at the later of the date stated in each award’s respective grant letter. Our accrued liability at December 31, 2016 related to all outstanding liability-classified LTIP awards and DERs was $38 million , of which $25 million was classified as short-term and $13 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 Sheets. These liabilities include accruals associated with our assessment that an annualized distribution of $2.20 per unit is probable of occurring in the reasonably foreseeable future (which was initially determined to be probable in the third quarter of 2016). At December 31, 2015 , the accrued liability was $33 million , of which $20 million was classified as short-term and $13 million was classified as long-term. Activity for LTIP awards under our equity-indexed compensation plans denominated in PAA units is summarized in the following table (units in millions): PAA Units (1) (2) Units Weighted Average Grant Date Fair Value per Unit Outstanding at December 31, 2013 8.4 $ 36.97 Granted 1.2 $ 47.68 Vested (1.9 ) $ 25.49 Cancelled or forfeited (0.4 ) $ 40.14 Outstanding at December 31, 2014 7.3 $ 41.45 Granted 2.1 $ 28.76 Vested (2.1 ) $ 28.91 Cancelled or forfeited (0.4 ) $ 44.56 Outstanding at December 31, 2015 6.9 $ 41.23 Granted 4.5 $ 23.38 Vested (1.9 ) $ 45.91 Modified (3) — $ (8.21 ) Cancelled or forfeited (0.6 ) $ 37.19 Outstanding at December 31, 2016 8.9 $ 29.62 (1) Amounts do not include AAP Management Units. (2) Approximately 0.5 million , 0.5 million and 0.6 million PAA common units were issued, net of tax withholding of approximately 0.3 million , 0.3 million and 0.3 million units during 2016 , 2015 and 2014 , respectively, in connection with the settlement of vested awards. The remaining PAA awards (approximately 1.1 million , 1.3 million and 1.0 million units) that vested during 2016 , 2015 and 2014 , respectively, were settled in cash. (3) During the third quarter of 2016 modifications were made to the vesting criteria of 2.2 million PAA LTIP units. In accordance with FASB guidance on share-based payments, the grant date fair values of these awards were adjusted as of the modification date. AAP Management Units In August 2007, the owners of AAP authorized the issuance of AAP Management Units (a profits interest) in order to provide additional long-term incentives and encourage retention for certain members of our senior management. In the third quarter of 2016, modifications were made to the distribution performance thresholds of the 0.8 million unearned AAP Management Units such that the awards will become earned based on the attainment of PAA distribution levels between $2.20 and $2.40 and additional performance conditions based on distributable cash flow measures determined by management. Additionally, this plan has been discontinued and there will be no new grants of AAP Management Units. As of December 31, 2016, 0.8 million AAP Management Units were unearned. Once earned, we will issue to AAP approximately 0.941 common units for each AAP Management Unit and each AAP Management Unit will be entitled to a distribution equal to approximately 94.1% of the distribution paid by AAP to an AAP unit on a quarterly basis. Once vested, each AAP Management Unit holder is entitled to convert his or her AAP Management Units into AAP units and a like number of PAGP Class B shares based on a conversion ratio of approximately 0.941 AAP units and Class B shares for each AAP Management Unit. The following is a summary of activity of AAP Management Units (in millions): Outstanding Outstanding Units Earned Grant Date Fair Value of Outstanding AAP Management Units (1) Balance at December 31, 2014 18.4 17.9 $ 64 Granted 0.6 — 24 Earned N/A 0.3 N/A Balance at December 31, 2015 19.0 18.2 $ 88 Modified (2) — — (17 ) Converted (15.6 ) (15.6 ) (36 ) Balance at December 31, 2016 3.4 2.6 $ 35 (1) Of the $35 million grant date fair value, $22 million had been recognized through December 31, 2016 on a cumulative basis. Of this amount, $2 million , $1 million and $7 million was recognized as expense during the years ended December 31, 2016 , 2015 and 2014 , respectively. (2) During the third quarter of 2016 modifications were made to the distribution performance thresholds of the 0.8 million unearned AAP Management Units. In accordance with FASB guidance on share-based payments, the grant date fair values of these awards were adjusted as of the modification date. As the intent of the AAP Management Units is to provide a performance incentive and encourage retention for certain members of our senior management, we recognize the grant date fair value of the AAP Management Units as compensation expense over the service period. The expense is also reflected as a capital contribution and thus, results in a corresponding credit to partners’ capital on our Consolidated Financial Statements. Other Consolidated Equity-Indexed Compensation Plan Information We refer to all of the LTIPs and AAP Management Units collectively as our “equity-indexed compensation plans.” The table below summarizes the expense recognized and the value of vested LTIP awards (settled both in common units and cash) under our equity-indexed compensation plans and includes both liability-classified and equity-classified awards (in millions): Year Ended December 31, 2016 2015 2014 Equity-indexed compensation expense $ 60 $ 27 $ 98 LTIP unit-settled vestings $ 24 $ 37 $ 53 LTIP cash-settled vestings $ 28 $ 66 $ 53 DER cash payments $ 6 $ 8 $ 8 Based on the December 31, 2016 fair value measurement and probability assessment regarding future distributions, we expect to recognize $135 million of additional expense over the life of our 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 our 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) 2017 $ 65 2018 42 2019 19 2020 7 2021 2 Total $ 135 (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, 2016 . (2) Includes unamortized fair value associated with AAP Management Units.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Commitments 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, 2016 , are summarized below (in millions): 2017 2018 2019 2020 2021 Thereafter Total Leases and rights-of-way easements (1) $ 195 $ 165 $ 140 $ 118 $ 97 $ 404 $ 1,119 Other commitments (2) 257 166 153 132 128 378 1,214 Total $ 452 $ 331 $ 293 $ 250 $ 225 $ 782 $ 2,333 (1) Includes capital and operating leases as defined by FASB guidance as well as obligations for rights-of-way easements. Lease expense for 2016 , 2015 and 2014 was $198 million , $164 million and $145 million , respectively. (2) Primarily includes third-party storage and transportation agreements and pipeline throughput agreements, as well as approximately $855 million associated with an agreement to transport crude oil on a pipeline that is owned by an equity method investee, in which we own a 50% interest. Our commitment to transport is supported by crude oil buy/sell agreements with third parties (including Oxy) with commensurate quantities. Loss Contingencies — General To the extent we are able to assess the likelihood of a negative outcome for a contingency, 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 an undiscounted liability equal to the estimated amount. If a range of probable loss amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then we accrue an undiscounted liability equal to the minimum amount in the range. In addition, we estimate legal fees that we expect to incur associated with loss contingencies and accrue those costs when they are material and probable of being incurred. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss. Legal Proceedings — General In the ordinary course of business, we are involved in various legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully protect us from losses arising from current or future legal proceedings. Taking into account what we believe to be all relevant known facts and circumstances, and based on what we believe to be reasonable assumptions regarding the application of those facts and circumstances to existing laws and regulations, we do not believe that the outcome of the legal proceedings in which we are currently involved (including those described below) will, individually or in the aggregate, have a material adverse effect on our consolidated financial condition, results of operations or cash flows. Environmental — General Although over the course of the last several years we have made significant investments in our maintenance and integrity programs, and have hired additional personnel in those areas, we have experienced (and likely will experience future) releases of hydrocarbon products into the environment from our pipeline, rail, storage and other facility operations. These releases can result from accidents or from unpredictable man-made or natural forces and may reach surface water bodies, groundwater aquifers or other sensitive environments. Damages and liabilities associated with any such releases from our existing or future assets could be significant and could have a material adverse effect on our consolidated financial condition, results of operations or cash flows. 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, 2016 , our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident, as discussed further below) totaled $147 million , of which $61 million was classified as short-term and $86 million was classified as long-term. At December 31, 2015 , our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident) totaled $185 million , of which $81 million was classified as short-term and $104 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, 2016 , we had recorded receivables totaling $56 million for amounts probable of recovery under insurance and from third parties under indemnification agreements, of which $39 million was reflected in “Trade accounts receivable and other receivables, net” and $17 million was reflected in “Other long-term assets, net” on our Consolidated Balance Sheet. At December 31, 2015, we had recorded $161 million of such receivables, of which $138 million was reflected in “Trade accounts receivable and other receivables, net” and $23 million was reflected in “Other long-term assets, net” on our Consolidated Balance Sheet. In some cases, the actual cash expenditures associated with these liabilities may not occur for three years or longer. Our estimates used in determining 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 or future legal claims giving rise to additional liabilities. Therefore, although we believe that the reserve is adequate, actual costs incurred (which may ultimately include costs for contingencies that are currently not reasonably estimable or costs for contingencies where the likelihood of loss is currently believed to be only reasonably possible or remote) may be in excess of the reserve and may potentially have a material adverse effect on our consolidated financial condition, results of operations or cash flows. Specific Legal, Environmental or Regulatory Matters Line 901 Incident . In May 2015, we experienced a crude oil release from our Las Flores to Gaviota Pipeline (Line 901) in Santa Barbara County, California. A portion of the released crude oil reached the Pacific Ocean at Refugio State Beach through a drainage culvert. Following the release, we shut down the pipeline and initiated our emergency response plan. A Unified Command, which includes the United States Coast Guard, the EPA, the California Office of Spill Prevention and Response and the Santa Barbara Office of Emergency Management, was established for the response effort. Clean-up and remediation operations with respect to impacted shoreline and other areas has been determined by the Unified Command to be complete, subject to continued shoreline monitoring. Our current “worst case” estimate of the amount of oil spilled, representing the maximum volume of oil that we believed could have been spilled based on relevant facts, data and information, is approximately 2,935 barrels. As a result of the Line 901 incident, several governmental agencies and regulators initiated investigations into the Line 901 incident, various claims have been made against us and a number of lawsuits have been filed against us. We may be subject to additional claims, investigations and lawsuits, which could materially impact the liabilities and costs we currently expect to incur as a result of the Line 901 incident. Set forth below is a brief summary of actions and matters that are currently pending: On May 21, 2015, we received a corrective action order from the United States Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”), the governmental agency with jurisdiction over the operation of Line 901 as well as over a second stretch of pipeline extending from Gaviota Pump Station in Santa Barbara County to Emidio Pump Station in Kern County, California (Line 903), requiring us to shut down, purge, review, remediate and test Line 901. The corrective action order was subsequently amended on June 3, 2015; November 13, 2015; and June 16, 2016 to require us to take additional corrective actions with respect to both Lines 901 and 903 (as amended, the “CAO”). Among other requirements, the CAO also obligates us to conduct a root cause failure analysis with respect to Line 901 and present remedial work plans and restart plans to PHMSA prior to returning Line 901 and 903 to service; the CAO also imposes a pressure restriction on the section of Line 903 between Pentland Pump Station and Emidio Pump Station and requires us to take other specified actions with respect to both Lines 901 and 903. We intend to continue to comply with the CAO and to cooperate with any other governmental investigations relating to or arising out of the release. Excavation and removal of the affected section of the pipeline was completed on May 28, 2015. Line 901 and Line 903 have been purged and are not currently operational. No timeline has been established for the restart of Line 901 or Line 903. On February 17, 2016, PHMSA issued a Preliminary Factual Report of the Line 901 failure, which contains PHMSA’s preliminary findings regarding factual information about the events leading up to the accident and the technical analysis that has been conducted to date. On May 19, 2016, PHMSA issued its final Failure Investigation Report regarding the Line 901 incident. PHMSA’s findings indicate that the direct cause of the Line 901 incident was external corrosion that thinned the pipe wall to a level where it ruptured suddenly and released crude oil. PHMSA also concluded that there were numerous contributory causes of the Line 901 incident, including ineffective protection against external corrosion, failure to detect and mitigate the corrosion and a lack of timely detection and response to the rupture. The report also included copies of various engineering and technical reports regarding the incident. By virtue of its statutory authority, PHMSA has the power and authority to impose fines and penalties on us and cause civil or criminal charges to be brought against us. While to date PHMSA has not imposed any such fines or penalties or pursued any such civil or criminal charges with respect to the Line 901 release, their investigation is still open and we may have fines or penalties imposed upon us, or civil or criminal charges brought against us, in the future. On September 11, 2015, we received a Notice of Probable Violation and Proposed Compliance Order from PHMSA arising out of its inspection of Lines 901 and 903 in August, September and October of 2013 (the “2013 Audit NOPV”). The 2013 Audit NOPV alleges that the Partnership committed probable violations of various federal pipeline safety regulations by failing to document, or inadequately documenting, certain activities. On October 12, 2015, the Partnership filed a response to the 2013 Audit NOPV. To date, PHMSA has not issued a final order with respect to the 2013 Audit NOPV, nor has it assessed any fines or penalties with respect thereto; however, we cannot provide any assurances that any such fines or penalties will not be assessed against us. In late May of 2015, the California Attorney General’s Office and the District Attorney’s office for the County of Santa Barbara began investigating the Line 901 incident to determine whether any applicable state or local laws had been violated. On May 16, 2016, PAA and one of its employees were charged by a California state grand jury, pursuant to an indictment filed in California Superior Court, Santa Barbara County (the “May 2016 Indictment”), with alleged violations of California law in connection with the Line 901 incident. The indictment included a total of 46 counts, 36 of which were misdemeanor charges relating to wildlife allegedly taken as a result of the accidental release. The remaining 10 counts ( four felony and six misdemeanor charges) relate to the release of crude oil or reporting of the release. PAA believes that the criminal charges are unwarranted and that neither PAA nor any of its employees engaged in any criminal behavior at any time in connection with this accident. PAA intends to continue to vigorously defend itself against the charges. On July 28, 2016, at an arraignment hearing held in California Superior Court in Santa Barbara County, PAA pled not guilty to all counts. Also in late May of 2015, the United States Attorney for the Department of Justice, Central District of California, Environmental Crimes Section (“DOJ”) began an investigation into whether there were any violations of federal criminal statutes in connection with the Line 901 incident, including potential violations of the federal Clean Water Act. We are cooperating with the DOJ’s investigation by responding to their requests for documents and access to our employees. The DOJ has already spoken to several of our employees and has expressed an interest in talking to other employees; consistent with the terms of our governing organizational documents, we are funding our employees’ defense costs, including the costs of separate counsel engaged to represent such individuals. On August 26, 2015, we received a Request for Information from the EPA relating to Line 901. We have provided various responsive materials to date and we will continue to do so in the future in cooperation with the EPA. While to date no civil or criminal charges with respect to the Line 901 release, other than those brought pursuant to the May 2016 Indictment, have been brought against PAA or any of its affiliates, officers or employees by PHMSA, DOJ, EPA, the California Attorney General, the Santa Barbara District Attorney or the California Department of Fish and Wildlife, and no fines or penalties have been imposed by such governmental agencies, the investigations being conducted by such agencies are still open and we may have fines or penalties imposed upon us, our officers or our employees, or civil or criminal charges brought against us, our officers or our employees in the future, whether by those or other governmental agencies. Shortly following the Line 901 incident, we established a claims line and encouraged any parties that were damaged by the release to contact us to discuss their damage claims. We have received a number of claims through the claims line and we are processing those claims for payment as we receive them. In addition, we have also had nine class action lawsuits filed against us, six of which have been administratively consolidated into a single proceeding in the United States District Court for the Central District of California. In general, the plaintiffs are seeking to establish different classes of claimants that have allegedly been damaged by the release, including potential classes such as persons that derive a significant portion of their income through commercial fishing and harvesting activities in the waters adjacent to Santa Barbara County or from businesses that are dependent on marine resources from Santa Barbara County, retail businesses located in historic downtown Santa Barbara, certain owners of oceanfront and/or beachfront property on the Pacific Coast of California, and other classes of individuals and businesses that were allegedly impacted by the release. We are also defending a separate class action lawsuit proceeding in the United States District Court for the Central District of California brought on behalf of the Line 901 and Line 903 easement holders seeking injunctive relief as well as compensatory damages. There have also been two securities law class action lawsuits filed on behalf of certain purported investors in the Partnership and/or PAGP against the Partnership, PAGP and/or certain of their respective officers, directors and underwriters. Both of these lawsuits have been consolidated into a single proceeding in the United States District Court for the Southern District of Texas. In general, these lawsuits allege that the various defendants violated securities laws by misleading investors regarding the integrity of the Partnership’s pipelines and related facilities through false and misleading statements, omission of material facts and concealing of the true extent of the spill. The plaintiffs claim unspecified damages as a result of the reduction in value of their investments in the Partnership and PAGP, which they attribute to the alleged wrongful acts of the defendants. The Partnership and PAGP, and the other defendants, deny the allegations in these lawsuits and intend to respond accordingly. Consistent with and subject to the terms of our governing organizational documents (and to the extent applicable, insurance policies), we are indemnifying and funding the defense costs of our officers and directors in connection with these lawsuits; we are also indemnifying and funding the defense costs of our underwriters pursuant to the terms of the underwriting agreements we previously entered into with such underwriters. In addition, four unitholder derivative lawsuits have been filed by certain purported investors in the Partnership against the Partnership, certain of its affiliates and certain officers and directors. Two of these lawsuits were filed in the United States District Court for the Southern District of Texas and were administratively consolidated into one action and later dismissed on the basis that Plains Partnership agreements require that derivative suits be filed in Delaware Chancery Court. Following the order dismissing the Texas Federal Court suits, a new derivative suit brought by different plaintiffs was filed in Delaware Chancery Court. The other remaining lawsuit was filed in State District Court in Harris County, Texas. In general, these lawsuits allege that the various defendants breached their fiduciary duties, engaged in gross mismanagement and made false and misleading statements, among other similar allegations, in connection with their management and oversight of the Partnership during the period of time leading up to and following the Line 901 release. The plaintiffs in the two remaining lawsuits claim that the Partnership suffered unspecified damages as a result of the actions of the various defendants and seek to hold the defendants liable for such damages, in addition to other remedies. The defendants deny the allegations in these lawsuits and intend to respond accordingly. Consistent with and subject to the terms of our governing organizational documents (and to the extent applicable, insurance policies), we are indemnifying and funding the defense costs of our officers and directors in connection with these lawsuits. We have also had two lawsuits filed against us wherein the respective plaintiffs seek to compel the production of certain books and records that purportedly relate to the Line 901 incident, our alleged failure to comply with certain regulations and other matters. These lawsuits have been consolidated into a single proceeding in the Chancery Court for the State of Delaware. We have also received several other individual lawsuits and complaints from companies and individuals alleging damages arising out of the Line 901 incident. These lawsuits and claims generally seek compensatory and punitive damages, and in some cases permanent injunctive relief. In addition to the foregoing, as the “responsible party” for the Line 901 incident we are liable for various costs and for certain natural resource damages under the Oil Pollution Act, and we also have exposure to the payment of additional fines, penalties and costs under other applicable federal, state and local laws, statutes and regulations. To the extent any such costs are reasonably estimable, we have included an estimate of such costs in the loss accrual described below. Taking the foregoing into account, as of December 31, 2016 , we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $280 million , which estimate includes actual and projected emergency response and clean-up costs, natural resource damage assessments and certain third party claims settlements, as well as estimates for fines, penalties and certain legal fees. This estimate considers our prior experience in environmental investigation and remediation matters and available data from, and in consultation with, our environmental and other specialists, as well as currently available facts and presently enacted laws and regulations. We have made assumptions for (i) the expected number of remaining days that monitoring services will be required, (ii) the duration of the natural resource damage assessment and the ultimate amount of damages determined, (iii) the resolution of certain third party claims and lawsuits, but excluding claims and lawsuits with respect to which losses are not probable and reasonably estimable, and excluding future claims and lawsuits, (iv) the determination and calculation of fines and penalties, but excluding fines and penalties that are not probable and reasonably estimable and (v) the nature, extent and cost of legal services that will be required in connection with all lawsuits, claims and other matters requiring legal or expert advice associated with the Line 901 incident. Our estimate does not include any lost revenue associated with the shutdown of Line 901 or 903 and does not include any liabilities or costs that are not reasonably estimable at this time or that relate to contingencies where we currently regard the likelihood of loss as being only reasonably possible or remote. We believe we have accrued adequate amounts for all probable and reasonably estimable costs; however, this estimate is subject to uncertainties associated with the assumptions that we have made. For example, the amount of time it takes for us to resolve all of the current and future lawsuits, claims and investigations that relate to the Line 901 incident could turn out to be significantly longer than we have assumed, and as a result the costs we incur for legal services could be significantly higher than we have estimated. In addition, with respect to fines and penalties, the ultimate amount of any fines and penalties assessed against us depends on a wide variety of factors, many of which are not estimable at this time. Where fines and penalties are probable and estimable, we have included them in our estimate, although such estimates could turn out to be wrong. Accordingly, our assumptions and estimates may turn out to be inaccurate and our total costs could turn out to be materially higher; therefore, we can provide no assurance that we will not have to accrue significant additional costs in the future with respect to the Line 901 incident. We have accrued such estimate of aggregate total costs to “Field operating costs” on our Consolidated Statement of Operations. As of December 31, 2016 , we had a remaining undiscounted gross liability of $75 million related to this event, of which approximately $50 million is presented as a current liability in “Accounts payable and accrued liabilities” on our Consolidated Balance Sheet, with the remainder presented in “Other long-term liabilities and deferred credits”. We maintain insurance coverage, which is subject to certain exclusions and deductibles, in the event of such environmental liabilities. Subject to such exclusions and deductibles, we believe that our coverage is adequate to cover the current estimated total emergency response and clean-up costs, claims settlement costs and remediation costs and we believe that this coverage is also adequate to cover any potential increase in the estimates for these costs that exceed the amounts currently identified. Through December 31, 2016 , we had collected, subject to customary reservations, $148 million out of the approximate $197 million of release costs that we believe are probable of recovery from insurance carriers, net of deductibles. Therefore, as of December 31, 2016 , we have recognized a receivable of approximately $49 million for the portion of the release costs that we believe is probable of recovery from insurance, net of deductibles and amounts already collected. Of this amount, approximately $34 million is recognized as a current asset in “Trade accounts receivable and other receivables, net” on our Consolidated Balance Sheet, with the remainder in “Other long-term assets, net”. We have substantially completed the clean-up and remediation efforts, excluding long-term site monitoring activities; however, we expect to make payments for additional costs associated with restoration and monitoring of the area, as well as natural resource damage assessment, legal, professional and regulatory costs, in addition to fines and penalties, during future periods. In the Matter of Bakersfield Crude Terminal LLC et al. On April 30, 2015, the EPA issued a Finding and Notice of Violation (“NOV”) to Bakersfield Crude Terminal LLC, our subsidiary, for alleged violations of the Clean Air Act, as amended. The NOV, which cites 10 separate rule violations, questions the validity of construction and operating permits issued to our Bakersfield rail unloading facility in 2012 and 2014 by the San Joaquin Valley Air Pollution Control District (the “SJV District”). We believe we fully complied with all applicable regulatory requirements and that the permits issued to us by the SJV District are valid. To date, no fines or penalties have been assessed in this matter; however, it is possible that fines and penalties could be assessed in the future. Mesa to Basin Pipeline . On January 6, 2016, PHMSA issued a Notice of Probable Violation and Proposed Civil Penalty relating to an approximate 500 barrel release of crude oil that took place on January 1, 2015 on our Mesa to Basin 12” pipeline in Midland, Texas. PHMSA conducted an accident investigation and reviewed documentation related to the incident, and concluded that we had committed probable violations of certain pipeline safety regulations. In the Notice, PHMSA maintains that we failed to carry out our written damage prevention program and to follow our pipeline excavation/ditching and backfill procedures on four separate occasions, and that such failures resulted in outside force damage that led to the January 1, 2015 release. PHMSA’s compliance officer has recommended that we be assessed a civil penalty of $190,000 . We have formally responded to PHMSA regarding this matter, but at this point we can provide no assurance regarding the final disposition of this matter or the final amount of any civil penalties. 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 the U.S. federal Comprehensive Environmental Response, Compensation and Liability Act, as amended, and the U.S. federal Resource Conservation and Recovery Act, as amended, as well as 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 Pipelines, terminals, trucks or other facilities or equipment may experience damage as a result of an accident, natural disaster, terrorist attack, cyber event or other event. 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 and varying levels of insurance coverage that we consider adequate under the circumstances to cover our operations and properties, and we self-insure certain risks, including gradual pollution and named windstorm. With respect to our insurance, our policies are subject to deductibles and retention levels that we consider reasonable and not excessive. However, such insurance does not cover every potential risk that might occur, associated with operating pipelines, terminals and other facilities and equipment, including the potential loss of significant revenues and cash flows. 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 that we maintain adequate insurance coverage, although insurance will not cover many types of interruptions that might occur, will not cover amounts up to applicable deductibles and will not cover all risks associated with certain of our assets and operations. Additionally we self-insure certain risks including, gradual pollution and named windstorm. With respect to our insurance coverage, no assurance can be given that we will be able to maintain adequate insurance in the future at rates we consider reasonable. As a result, we may elect to self-insure or utilize higher deductibles in certain other insurance programs. In addition, although we believe that we have established adequate reserves and liquidity to the extent such risks are not insured, costs incurred in excess of these reserves may be higher or we may not receive insurance proceeds in a timely manner, and may potentially have a material adverse effect on our financial conditions, results of operations or cash flows.

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data (Unaudited)	Quarterly Financial Data (Unaudited) First Quarter Second Quarter Third Quarter Fourth Quarter Total (1) (in millions, except per unit data) 2016 Total revenues $ 4,111 $ 4,950 $ 5,170 $ 5,952 $ 20,182 Gross margin (2) $ 349 $ 219 $ 419 $ 286 $ 1,273 Operating income $ 282 $ 146 $ 349 $ 218 $ 994 Net income $ 203 $ 102 $ 298 $ 127 $ 730 Net income attributable to PAA $ 202 $ 101 $ 297 $ 126 $ 726 Basic net income/(loss) per common unit $ 0.07 $ (0.20 ) $ 0.40 $ 0.14 $ 0.43 Diluted net income/(loss) per common unit $ 0.07 $ (0.20 ) $ 0.40 $ 0.14 $ 0.43 Cash distributions per common unit (3) $ 0.70 $ 0.70 $ 0.70 $ 0.55 $ 2.65 2015 Total revenues $ 5,942 $ 6,663 $ 5,551 $ 4,996 $ 23,152 Gross margin (2) $ 450 $ 290 $ 395 $ 405 $ 1,540 Operating income $ 372 $ 211 $ 335 $ 344 $ 1,262 Net income $ 284 $ 124 $ 250 $ 248 $ 906 Net income attributable to PAA $ 283 $ 124 $ 249 $ 247 $ 903 Basic net income/(loss) per common unit $ 0.36 $ (0.06 ) $ 0.25 $ 0.24 $ 0.78 Diluted net income/(loss) per common unit $ 0.35 $ (0.06 ) $ 0.24 $ 0.24 $ 0.77 Cash distributions per common unit (3) $ 0.68 $ 0.69 $ 0.70 $ 0.70 $ 2.76 (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) Represents cash distributions declared and paid in the period presented.

Operating Segments

Operating Segments	12 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
Operating Segments	Operating Segments We manage our operations through three operating segments: Transportation, Facilities and 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 (“CODM”) (our Chief Executive Officer) evaluates segment performance based on measures including segment adjusted EBITDA (as defined below) and maintenance capital investment. The measure of segment adjusted EBITDA forms the basis of our internal financial reporting and is the primary performance measure used by our CODM in assessing performance and allocating resources among our operating segments. During the fourth quarter of 2016, we modified our primary segment performance measure to segment adjusted EBITDA from segment profit, and thus prior period segment disclosures have been recast to reflect this change. Prior to the fourth quarter of 2016, our primary segment measure did not include certain adjustments (described further below) that our CODM believes are useful in evaluating the core operating performance of our segments. We define segment adjusted EBITDA as revenues and equity earnings in unconsolidated entities less (a) purchases and related costs, (b) field operating costs and (c) segment general and administrative expenses, plus our proportionate share of the depreciation and amortization expense of unconsolidated entities, and further adjusted for certain selected items including (i) the mark-to-market of derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are related to investing activities (such as the purchase of linefill) and inventory valuation adjustments, as applicable, (ii) long-term inventory costing adjustments, (iii) charges for obligations that are expected to be settled with the issuance of equity instruments, (iv) amounts related to deficiencies associated with minimum volume commitments, net of applicable amounts subsequently recognized into revenue and (v) other items that our CODM believes are integral to understand our core segment operating performance. Segment adjusted EBITDA excludes depreciation and amortization. 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. As an MLP, we make quarterly distributions of our “available cash” (as defined in our partnership agreement) to our unitholders. 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 adjusted EBITDA 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 act 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 adjusted EBITDA or in maintenance capital, depending on the nature of the cost. Capital expenditures made to expand the existing operating and/or earnings capacity of our assets are classified as expansion capital. 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 are classified as maintenance capital, which is deducted in determining “available cash”. 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 (in millions): Transportation Facilities Supply and Logistics Intersegment Adjustment (1) Total Year Ended December 31, 2016 Revenues: External customers $ 954 $ 546 $ 19,004 $ (322 ) $ 20,182 Intersegment (2) 630 561 14 322 1,527 Total revenues of reportable segments $ 1,584 $ 1,107 $ 19,018 $ — $ 21,709 Equity earnings in unconsolidated entities $ 195 $ — $ — $ 195 Segment adjusted EBITDA $ 1,141 $ 667 $ 359 $ 2,167 Capital expenditures (3) $ 1,063 $ 577 $ 54 $ 1,694 Maintenance capital $ 121 $ 55 $ 10 $ 186 As of December 31, 2016 Total assets $ 10,917 $ 7,556 $ 5,737 $ 24,210 Investments in unconsolidated entities $ 2,290 $ 53 $ — $ 2,343 Transportation Facilities Supply and Logistics Intersegment Adjustment (1) Total Year Ended December 31, 2015 Revenues: External customers $ 953 $ 528 $ 21,927 $ (256 ) $ 23,152 Intersegment (2) 641 522 18 256 1,437 Total revenues of reportable segments $ 1,594 $ 1,050 $ 21,945 $ — $ 24,589 Equity earnings in unconsolidated entities $ 183 $ — $ — $ 183 Segment adjusted EBITDA $ 1,056 $ 588 $ 568 $ 2,212 Capital expenditures (3) $ 1,278 $ 813 $ 184 $ 2,275 Maintenance capital $ 144 $ 68 $ 8 $ 220 As of December 31, 2015 Total assets $ 10,345 $ 7,330 $ 4,613 $ 22,288 Investments in unconsolidated entities $ 1,998 $ 29 $ — $ 2,027 Transportation Facilities Supply and Logistics Intersegment Adjustment (1) Total Year Ended December 31, 2014 Revenues: External customers $ 994 $ 576 $ 42,114 $ (220 ) $ 43,464 Intersegment (2) 661 551 36 220 1,468 Total revenues of reportable segments $ 1,655 $ 1,127 $ 42,150 $ — $ 44,932 Equity earnings in unconsolidated entities $ 108 $ — $ — $ 108 Segment adjusted EBITDA $ 979 $ 597 $ 651 $ 2,227 Capital expenditures (3) $ 2,483 $ 582 $ 60 $ 3,125 Maintenance capital $ 165 $ 52 $ 7 $ 224 As of December 31, 2014 Total assets $ 9,579 $ 6,843 $ 5,776 $ 22,198 Investments in unconsolidated entities $ 1,735 $ — $ — $ 1,735 (1) Transportation revenues from external customers include inventory exchanges that are substantially similar to tariff-like arrangements with our customers. Under these arrangements, our Supply and Logistics segment has transacted the inventory exchange and serves as the shipper on our pipeline systems. See Note 2 for discussion of our related accounting policy. We have included an estimate of the revenues from these inventory exchanges in our Transportation segment revenue presented above and adjusted those revenues out such that Total revenue from External customers reconciles to our Consolidated Statement of Operations. This presentation is consistent with the information provided to our CODM. (2) Segment revenues include intersegment amounts that are eliminated in Purchases and related costs and Field operating costs in our Consolidated Statements of Operations. Intersegment sales are conducted at posted tariff rates, rates similar to those charged to third parties or rates that we believe approximate market at the time the agreement is executed or renegotiated. (3) Expenditures for acquisition capital and expansion capital, including investments in unconsolidated entities. Segment Adjusted EBITDA Reconciliation The following table reconciles segment adjusted EBITDA to net income attributable to PAA (in millions): Year Ended December 31, 2016 2015 2014 Segment adjusted EBITDA $ 2,167 $ 2,212 $ 2,227 Adjustments (1) : Depreciation and amortization of unconsolidated entities (2) (50 ) (45 ) (29 ) Gains/(losses) from derivative activities net of inventory valuation adjustments (3) (404 ) (110 ) 243 Long-term inventory costing adjustments (4) 58 (99 ) (85 ) Deficiencies under minimum volume commitments, net (5) (46 ) — — Equity-indexed compensation expense (6) (33 ) (27 ) (56 ) Net gain/(loss) on foreign currency revaluation (7) (9 ) 29 (9 ) Line 901 incident (8) — (83 ) — Depreciation and amortization (494 ) (432 ) (384 ) Interest expense, net (467 ) (432 ) (348 ) Other income/(expense), net 33 (7 ) (2 ) Income before tax 755 1,006 1,557 Income tax expense (25 ) (100 ) (171 ) Net income 730 906 1,386 Net income attributable to noncontrolling interests (4 ) (3 ) (2 ) Net income attributable to PAA $ 726 $ 903 $ 1,384 (1) Represents adjustments utilized by our CODM in the evaluation of segment results. (2) Includes our proportionate share of the depreciation and amortization of equity method investments. (3) We use derivative instruments for risk management purposes and our related processes include specific identification of hedging instruments to an underlying hedged transaction. Although we identify an underlying transaction for each derivative instrument we enter into, there may not be an accounting hedge relationship between the instrument and the underlying transaction. In the course of evaluating our results, we identify the earnings that were recognized during the period related to derivative instruments for which the identified underlying transaction does not occur in the current period and exclude the related gains and losses in determining segment adjusted EBITDA. In addition, we exclude gains and losses on derivatives that are related to investing activities, such as the purchase of linefill. We also exclude the impact of corresponding inventory valuation adjustments, as applicable. (4) We carry crude oil and NGL inventory that is comprised of minimum working inventory requirements in third-party assets and other working inventory that is needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future. Therefore, we classify this inventory as long-term on our balance sheet and do not hedge the inventory with derivative instruments (similar to linefill in our own assets). We exclude the impact of changes in the average cost of the long-term inventory (that result from fluctuations in market prices) and writedowns of such inventory that result from price declines from segment adjusted EBITDA. (5) We have certain agreements that require counterparties to deliver, transport or throughput a minimum volume over an agreed upon period. Substantially all of such agreements were entered into with counterparties to economically support the return on our capital expenditure necessary to construct the related asset. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote. We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue, as a selected item impacting comparability. Our CODM views the inclusion of the contractually committed revenues associated with that period as meaningful to segment adjusted EBITDA as the related asset has been constructed, is standing ready to provide the committed service and the fixed operating costs are included in the current period results. Amounts for years prior to 2016 were not significant to segment adjusted EBITDA ( $13 million and $4 million for the years ended December 31, 2015 and 2014, respectively). (6) Includes equity-indexed compensation expense associated with awards that will or may be settled in units. (7) Includes gains and losses from the revaluation of foreign currency transactions and monetary assets and liabilities. (8) Includes costs recognized during the period related to the Line 901 incident that occurred in May 2015, net of amounts we believe are probable of recovery from insurance. 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) 2016 2015 2014 United States $ 15,599 $ 18,701 $ 34,860 Canada 4,583 4,451 8,604 $ 20,182 $ 23,152 $ 43,464 (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) 2016 2015 United States $ 16,041 $ 15,942 Canada 3,895 3,368 $ 19,936 $ 19,310 (1) Excludes long-term derivative assets.

Summary of Significant Accoun29

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Basis of Consolidation and Presentation	Basis of Consolidation and Presentation The accompanying financial statements and related notes present and discuss our consolidated financial position as of December 31, 2016 and 2015 , and the consolidated results of our operations, cash flows, changes in partners’ capital, comprehensive income and changes in accumulated other comprehensive income/(loss) for the years ended December 31, 2016 , 2015 and 2014 . All significant intercompany transactions have been eliminated in consolidation, and certain reclassifications have been made to information from previous years to conform to the current presentation. These reclassifications do not affect net income attributable to PAA. The accompanying consolidated financial statements include the accounts of PAA and all of its wholly owned subsidiaries and those entities that it controls. Investments in entities over which we have significant influence but not control are accounted for by the equity method. We apply proportionate consolidation for pipelines and other assets in which we own undivided joint interests.
Use of Estimates	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) estimated fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets, (ii) fair value of derivatives, (iii) accruals and contingent liabilities, (iv) equity-indexed compensation plan accruals, (v) property and equipment, depreciation expense and asset retirement obligations, (vi) allowance for doubtful accounts and (vii) inventory valuations. Although we believe these estimates are reasonable, actual results could differ from these estimates.
Revenue Recognition	Revenue Recognition Supply and Logistics Segment Revenues. Revenues from sales of crude oil, NGL and natural gas 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. Our Transportation segment operations generally consist of fee-based activities associated with transporting crude oil and NGL on pipelines, gathering systems, trucks and barges. 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 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 tariffs. Revenues associated with fees are recognized in the month to which the fee applies. 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 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. 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, as well as NGL fractionation and isomerization services and natural gas and condensate processing services. Revenues generated in this segment include (i) fees that are generated from storage capacity agreements, (ii) terminal throughput fees that are generated when we receive crude oil, refined products or NGL from one connecting source and deliver the applicable product to another connecting carrier, (iii) loading and unloading fees at our rail terminals, (iv) fees from NGL fractionation and isomerization, (v) fees from natural gas and condensate processing services and (vi) fees associated with natural gas park and loan activities, interruptible storage services and wheeling and balancing services. We generate revenue through a combination of month-to-month and multi-year agreements. 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. Minimum Volume Commitments. We have certain agreements that require counterparties to deliver, transport or throughput a minimum volume over an agreed upon period. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote.
Purchases and Related Costs	Purchases and Related Costs Purchases and related costs include (i) the cost of crude oil, NGL and natural gas obtained in outright purchases, (ii) fees incurred for third-party storage and transportation, whether by pipeline, truck, rail, ship or barge and (iii) 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 inventory 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 and General and Administrative Expenses Field operating costs consist of various field operating expenses, including fuel and power costs (including the impact of gains and losses from derivative related activities), telecommunications, payroll and benefit costs (including equity-indexed compensation expense) for truck drivers and field and other operations 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/Translation	Foreign Currency Transactions/Translation 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 Sheets. 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.
Cash and Cash Equivalents	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.
Accounts Receivable, Net	Accounts Receivable, Net Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL and natural gas. 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. The sustained decrease in commodity prices since late 2014 has caused liquidity issues throughout the energy industry, which in turn has increased the potential credit risks associated with certain counterparties with which we do business. To mitigate credit risk related to our accounts receivable, we utilize a rigorous credit review process. We closely monitor market conditions to make a determination with respect to the amount, if any, of open 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 advance cash payments, standby letters of credit or parental guarantees. As of December 31, 2016 and 2015 , we had received $89 million and $88 million , respectively, of advance cash payments from third parties to mitigate credit risk. We also received $66 million and $36 million as of December 31, 2016 and 2015 , respectively, of standby letters of credit to support obligations due from third parties, a portion of which applies to future business. Additionally, in an effort to mitigate credit risk, a significant portion of our transactions with counterparties are settled on a net-cash basis. Furthermore, we also 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.
Noncontrolling Interests	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 11 for additional discussion regarding our noncontrolling interests.
Asset Retirement Obligations	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.
Fair Value Measurements	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 Note 12 for further discussion.
Recent Accounting Pronouncements	Recent Accounting Pronouncements In November 2016, the FASB issued guidance requiring that a statement of cash flows explain the change in total cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents during the period. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period total amounts shown on the statement of cash flows. This guidance will become effective for interim and annual periods beginning after December 31, 2017. We expect to adopt this guidance on January 1, 2018, and we do not currently anticipate that our adoption will have a material impact on our statement of cash flows. In October 2016, the FASB issued guidance to improve the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. This guidance will become effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted in the first interim period of an annual reporting period. We expect to adopt this guidance on January 1, 2018, and we are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations and cash flows. In October 2016, the FASB issued guidance changing how a reporting entity that is the single decision maker of a variable interest entity (“VIE”) should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. This guidance is effective for interim and annual periods beginning after December 31, 2016. We adopted this guidance on January 1, 2017. Our adoption did not have a material impact on our financial position, results of operations or cash flows. In August 2016, the FASB issued guidance relating to the classification and presentation of eight specific cash flow issues. This guidance will become effective for interim and annual periods beginning after December 15, 2018, with early adoption permitted. We early adopted this guidance during the fourth quarter of 2016, and our adoption had no impact on our statement of cash flows. In June 2016, the FASB issued new guidance for the accounting for credit losses on certain financial instruments. This guidance will become effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted by one year. We expect to adopt this guidance on January 1, 2020, and we are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations and cash flows. In March 2016, the FASB issued guidance to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification of certain related payments on the statement of cash flows. This guidance is effective for interim and annual periods beginning after December 15, 2016, with early adoption permitted. We adopted this guidance on January 1, 2017 and elected to account for forfeitures as they occur, utilizing the modified retrospective approach of adoption. Our adoption did not have a material impact on our financial position, results of operations or cash flows. In February 2016, the FASB issued guidance that revises the current accounting model for leases. The most significant changes are the clarification of the definition of a lease and required lessee recognition on the balance sheet of lease assets and liabilities with lease terms of more than 12 months, including extensive quantitative and qualitative disclosures. This guidance will become effective for interim and annual periods beginning after December 15, 2018, with a modified retrospective application required. Early adoption is permitted, including adoption in an interim period. We expect to adopt this guidance on January 1, 2019. We are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations and cash flows. Although our evaluation is ongoing, we do expect that the adoption will impact our financial statements as the standard requires the recognition on the balance sheet of a right of use asset and corresponding lease liability. We are currently analyzing our contracts to determine whether they contain a lease under the revised guidance and have not quantified the amount of the asset and liability that will be recognized on our consolidated balance sheet. In September 2015, the FASB issued guidance to simplify the accounting for measurement-period adjustments for provisional amounts recognized in a business combination by eliminating the requirement for an acquirer to retrospectively account for measurement-period adjustments. Under the updated guidance, the acquirer must recognize adjustments in the reporting period in which the adjustment amounts are determined and the effect on earnings as a result of the change to the provisional amounts must be calculated as if the accounting had been completed at the acquisition date. This guidance was effective for interim and annual periods beginning after December 15, 2015, with early adoption permitted, and prospective application required. We adopted this guidance on January 1, 2016. Our adoption did not have a material impact on our financial position, results of operations or cash flows. In July 2015, the FASB issued guidance to simplify the measurement of inventory. This updated guidance requires entities to measure inventory at the lower of cost and net realizable value; however, inventory measured using last-in, first-out and the retail inventory method is unchanged by this update. This guidance is effective for interim and annual periods beginning after December 15, 2016, with prospective application required. We adopted this guidance on January 1, 2017. Our adoption did not have a material impact on our financial position, results of operations or cash flows. In February 2015, the FASB issued guidance that revises the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. All legal entities are subject to reevaluation under the revised consolidation model. Among other things, this guidance (i) modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities, (ii) eliminates the presumption that a general partner should consolidate a limited partnership and (iii) affects the consolidation analysis of reporting entities that are involved with variable interest entities, particularly those that have fee arrangements and related party relationships. This guidance was effective for interim and annual periods beginning after December 15, 2015, with early adoption permitted. We adopted this guidance on January 1, 2016. Our adoption did not have a material impact on our financial position, results of operations or cash flows. In August 2014, the FASB issued guidance that requires management to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures in certain situations. This guidance is effective for the annual period ending after December 15, 2016, and for interim and annual periods thereafter. We adopted this guidance for the 2016 annual reporting period. Our adoption has not had any impact on our financial position, results of operations or cash flows. In May 2014, the FASB issued guidance regarding the recognition of revenue from contracts with customers with the underlying principle that an entity will recognize revenue to reflect amounts expected to be received in exchange for the provision of goods and services to customers upon the transfer of those goods or services. The guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue and the related cash flows. This guidance can be adopted either with a full retrospective approach or a modified retrospective approach with a cumulative-effect adjustment as of the date of adoption. This guidance is effective for interim and annual periods beginning after December 15, 2017. We implemented a process to evaluate the impact of adopting this guidance on each type of revenue contract entered into with customers and our implementation team is in the process of determining appropriate changes to our business processes, systems and controls to support recognition and disclosure under the new standard. In addition, while we have not identified any significant revenue recognition timing differences for types of revenue streams assessed to date, our evaluation is not complete, and we have not quantified the impact to our financial statements, including assessing the impact of changes to disclosures. We expect this determination will near completion during the first half of 2017. We will adopt this guidance on January 1, 2018, and are currently evaluating which transition approach to apply.
Net Income Per Common Unit	After consideration of distributions to preferred unitholders (whether cash or paid-in-kind), basic and diluted net income per common unit is determined pursuant to the two-class method as prescribed in FASB guidance. This method is an earnings allocation formula that is used to determine allocations to the general partner, limited partners and participating securities according to distributions pertaining to the current period’s net income and participation rights in undistributed earnings or distributions in excess of earnings. Under the two-class method, net income is reduced by distributions pertaining to the period, and all remaining earnings or distributions in excess of earnings are then allocated to our general partner, common unitholders and participating securities based on their respective rights to share in distributions, regardless of whether those earnings would actually be distributed during a particular period from an economic or practical perspective. Participating securities include LTIP awards that have vested DERs, which entitle the grantee to a cash payment equal to the cash distribution paid on our outstanding common units. The Simplification Transactions, which closed on November 15, 2016, included the permanent elimination of our IDRs and the economic rights associated with our 2% general partner interest in exchange for the issuance by us to AAP of approximately 244.7 million common units and the assumption by us of AAP’s debt. In addition, we will issue to AAP up to 0.8 million common units in connection with certain AAP Management Units becoming earned in future periods. As such, beginning with the distribution pertaining to the fourth quarter of 2016, our general partner is no longer entitled to receive distributions on the IDRs or general partner interest. See Note 1 for additional discussion of the Simplification Transactions. We calculate basic and diluted net income per common unit by dividing net income attributable to PAA (after deducting amounts allocated to the preferred unitholders and participating securities, and for applicable periods, the 2% general partner’s interest and IDRs) by the basic and diluted weighted-average number of common units outstanding during the period. Diluted net income per common unit is computed based on the weighted-average number of common units plus the effect of potentially dilutive securities outstanding during the period, which include (i) our Series A preferred units, (ii) our LTIP awards and (iii) units that are issuable to AAP when certain AAP Management Units are earned. See Note 11 for additional information regarding our Series A preferred units. See Note 16 for a complete discussion of our LTIP awards, including specific discussion regarding DERs, and the AAP Management Units. When applying the if-converted method prescribed by FASB guidance, the possible conversion of our Series A preferred units was excluded from the calculation of diluted net income per common unit for the year ended December 31, 2016 as the effect was antidilutive. Our LTIP awards and certain AAP Management Units that contemplate the issuance of common units are considered dilutive unless (i) vesting occurs only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. LTIP awards that were deemed to be dilutive for the periods presented were reduced by a hypothetical common unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. As none of the necessary conditions for the remaining AAP Management Units to become earned had been satisfied by December 31, 2016, no units issuable to AAP were contemplated in the calculation of diluted net income per common unit.
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. Any resulting adjustments are a component of “Purchases and related costs” on our accompanying Consolidated Statements of Operations. During the years ended December 31, 2016 , 2015 and 2014 , we recorded charges of $3 million , $117 million and $289 million , respectively, related to the writedown of our crude oil, NGL and natural gas inventory due to declines in prices. In addition, the charges recorded during the year ended December 31, 2014 included the writedown of our natural gas inventory that was purchased in conjunction with managing natural gas storage deliverability requirements during the extended period of severe cold weather in the first quarter of 2014. A portion of these inventory valuation adjustments was 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 accompanying Consolidated Statement of Operations. See Note 12 for discussion of our derivative and risk management activities. Linefill and base gas 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 and caverns that we own and (iii) natural gas required to maintain the minimum operating pressure of natural gas storage facilities we own. We recognized gains of less than $1 million and $8 million during 2015 and 2014, respectively, on the sale of linefill and base gas for proceeds of $1 million and $24 million , respectively. We did not conduct any sales of linefill and base gas during 2016. Linefill and base gas carrying amounts are reviewed for impairment in accordance with FASB guidance with respect to accounting for the impairment or disposal of long-lived assets. Carrying amounts that are not expected to be recoverable through future cash flows are written down to estimated fair value. See Note 5 for further discussion regarding impairment of long-lived assets. During 2016 , 2015 and 2014 , we did not recognize any impairments of linefill and base gas. Minimum working inventory requirements in third-party assets and other working inventory in our assets that are 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 Sheets.
Property and Equipment	In accordance with our capitalization policy, expenditures made to expand the existing operating and/or earnings capacity of our assets are capitalized. We also capitalize certain costs directly related to the construction of such assets, including related internal labor costs, engineering costs and interest costs. For the years ended December 31, 2016 , 2015 and 2014 , capitalized interest recorded to property and equipment was $34 million , $49 million and $48 million , respectively. In addition, we capitalize interest related to investments in certain unconsolidated entities. See Note 8 for additional information. 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 (in millions): Estimated Useful Lives (Years) December 31, 2016 2015 Pipelines and related facilities (1) 10 - 70 $ 9,025 $ 8,395 Storage, terminal and rail facilities 30 - 70 5,305 5,012 Trucking equipment and other 3 - 15 408 392 Construction in progress — 826 1,217 Office property and equipment 2 - 50 222 196 Land and other N/A 434 442 Property and equipment, gross 16,220 15,654 Accumulated depreciation (2,348 ) (2,180 ) Property and equipment, net $ 13,872 $ 13,474 (1) We include rights-of-way, which are intangible assets, in our pipeline and related facilities amounts within property and equipment. We calculate our depreciation using the straight-line method, based on estimated useful lives and salvage values of our assets.
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.
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 to determine whether an impairment has occurred at least annually (as of June 30) and on an interim basis if it is more likely than not that a reporting unit’s fair value is less than its carrying value. 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 2016 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 to 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; therefore, goodwill was not considered impaired. We did not recognize any material impairments of goodwill during the last three years.
Investments in Unconsolidated Entities	Investments in entities over which we have significant influence but not control are accounted for by the equity method. 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 our Consolidated Balance Sheets. 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. Distributions received from unconsolidated entities are classified based on the nature of the distribution approach, which looks to the activity that generated the distribution. We consider distributions received from unconsolidated entities as a return on investment in those entities to the extent that the distribution was generated through operating results, and therefore classify these distributions as cash flows from operating activities in our Consolidated Statement of Cash Flows. Other distributions received from unconsolidated entities are considered a return of investment and classified as cash flows from investing activities on the Consolidated Statement of Cash Flows. We generally fund our portion of development, construction or capital expansion projects of our equity method investees through capital contributions. Our contributions to these entities increase the carrying value of our investments and are reflected in our Consolidated Statements of Cash Flows as cash used in investing activities. During the years ended December 31, 2016 , 2015 and 2014 , we made cash contributions of $288 million , $245 million and $158 million , respectively, to certain of our equity method investees. The contributions amount for 2015 is net of $53 million of cash received as a return of our investment. In addition, we capitalized interest of $13 million and $8 million during the years ended December 31, 2016 and 2015, respectively, related to contributions to unconsolidated entities for projects under development and construction. We anticipate that we will make additional contributions related to ongoing projects at BridgeTex, Diamond, Eagle Ford Terminals and STACK over the next few years. Our investments in unconsolidated entities exceeded our share of the underlying equity in the net assets of such entities by $736 million and $760 million at December 31, 2016 and 2015 , respectively. Such basis differences are included in the carrying values of our investments on our Consolidated Balance Sheets. The portion of the basis differences attributable to depreciable or amortizable assets is amortized on a straight-line basis over the estimated useful life of the related assets, which reduces “Equity earnings in unconsolidated entities” on our Consolidated Statements of Operations. The portion of the basis differences attributable to goodwill is not amortized. The basis difference is primarily related to our acquisition of an interest in BridgeTex in 2014.
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.
Debt	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. Costs incurred in connection with the issuance of senior notes are recorded as a direct deduction from the related debt liability and are 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.
Income Allocation	Income Allocation We allocate net income for partners’ capital presentation purposes by applying the allocation methodology in our partnership agreement. Following the closing of the Simplification Transactions, net income is allocated 100% to our common unitholders, after giving effect to income allocations for cash distributions to our preferred unitholders. In accordance with our partnership agreement, our preferred unitholders are not allocated income for paid-in-kind distributions for partners’ capital presentation purposes. For periods prior to the Simplification Transactions, our general partner and common unitholders were allocated income based on their respective partnership percentages, after giving effect to income allocations for (i) incentive distributions, if any, to our general partner for distributions declared and paid following the close of each quarter and (ii) cash distributions to our preferred unitholders. Our preferred unitholders were not allocated income for paid-in-kind distributions for partners’ capital presentation purposes. For purposes of determining basic and diluted net income per common unit, income is allocated as prescribed in FASB guidance for calculating earnings per unit, including a deduction to income available to common unitholders for cash or paid-in-kind distributions to preferred untiholders. See Note 3 for additional information.
Derivatives	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 manage our exposure to (i) commodity price risk, as well as to optimize our profits, (ii) interest rate risk and (iii) currency exchange rate risk. Our commodity price 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. 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 classified within the same category as the related hedged item in our Consolidated Statements of Cash Flows.
Derivative Hedge Accounting Documentation	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.
Derivative Hedge Effectiveness Determination	Both at the inception of the hedge and throughout the hedging relationship, we assess whether the derivatives employed are highly effective in offsetting changes in cash flows of anticipated hedged transactions.
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 classified within the same category as the related hedged item in our Consolidated Statements of Cash Flows.
Offsetting Derivative Assets and Liabilities	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.
Fair Value Hierarchy Transfer	To the extent any transfers between levels of the fair value hierarchy occur, our policy is to reflect these transfers as of the beginning of the reporting period in which they occur.
Income Taxes	Income tax expense is estimated using the tax rate in effect or to be in effect during the relevant periods in the jurisdictions in which we operate. Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes and are stated at enacted tax rates expected to be in effect when taxes are actually paid or recovered. To the extent we do not consider it more likely than not that a deferred tax asset will be recovered, a valuation allowance is established. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. We review contingent tax liabilities for estimated exposures on a more likely than not standard related to our current tax positions. Pursuant to FASB guidance related to accounting for uncertainty in income taxes, we may 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, 2016 and 2015 , we had not recognized any material amounts in connection with uncertainty in 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. 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.
Reimbursement of Expenses of Our General Partner and its Affiliates	We do not pay our general partner a management fee, but we do reimburse our general partner for all direct and indirect costs it incurs or payments it makes on our behalf, including the costs of employee, officer and director compensation and benefits allocable to us as well as all other expenses necessary or appropriate to the conduct of our business. We record these costs on the accrual basis in the period in which our general partner incurs them. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion.
Equity-indexed Compensation	Our 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 underlying 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. Certain LTIP awards contain performance conditions based on the attainment of certain annualized distribution levels and vest upon the later of a certain date or the attainment of such levels. For awards with performance conditions (such as distribution targets), expense is accrued over the service period only if the performance condition is considered probable of occurring. When awards with performance conditions that were previously considered improbable become probable, we incur additional expense in the period that the probability assessment changes. This is necessary to bring the accrued obligation associated with these awards up to the level it would be 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 they are paid as a reduction of partners’ capital.
AAP Management Units	As the intent of the AAP Management Units is to provide a performance incentive and encourage retention for certain members of our senior management, we recognize the grant date fair value of the AAP Management Units as compensation expense over the service period. The expense is also reflected as a capital contribution and thus, results in a corresponding credit to partners’ capital on our Consolidated Financial Statements.
Loss Contingencies	To the extent we are able to assess the likelihood of a negative outcome for a contingency, 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 an undiscounted liability equal to the estimated amount. If a range of probable loss amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then we accrue an undiscounted liability equal to the minimum amount in the range. In addition, we estimate legal fees that we expect to incur associated with loss contingencies and accrue those costs when they are material and probable of being incurred. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss.
Environmental Matters	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.
Operating Segments	Our Chief Operating Decision Maker (“CODM”) (our Chief Executive Officer) evaluates segment performance based on measures including segment adjusted EBITDA (as defined below) and maintenance capital investment. The measure of segment adjusted EBITDA forms the basis of our internal financial reporting and is the primary performance measure used by our CODM in assessing performance and allocating resources among our operating segments. During the fourth quarter of 2016, we modified our primary segment performance measure to segment adjusted EBITDA from segment profit, and thus prior period segment disclosures have been recast to reflect this change. Prior to the fourth quarter of 2016, our primary segment measure did not include certain adjustments (described further below) that our CODM believes are useful in evaluating the core operating performance of our segments. We define segment adjusted EBITDA as revenues and equity earnings in unconsolidated entities less (a) purchases and related costs, (b) field operating costs and (c) segment general and administrative expenses, plus our proportionate share of the depreciation and amortization expense of unconsolidated entities, and further adjusted for certain selected items including (i) the mark-to-market of derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are related to investing activities (such as the purchase of linefill) and inventory valuation adjustments, as applicable, (ii) long-term inventory costing adjustments, (iii) charges for obligations that are expected to be settled with the issuance of equity instruments, (iv) amounts related to deficiencies associated with minimum volume commitments, net of applicable amounts subsequently recognized into revenue and (v) other items that our CODM believes are integral to understand our core segment operating performance. Segment adjusted EBITDA excludes depreciation and amortization. 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. As an MLP, we make quarterly distributions of our “available cash” (as defined in our partnership agreement) to our unitholders. 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 adjusted EBITDA 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 act 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 adjusted EBITDA or in maintenance capital, depending on the nature of the cost. Capital expenditures made to expand the existing operating and/or earnings capacity of our assets are classified as expansion capital. 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 are classified as maintenance capital, which is deducted in determining “available cash”. Repair and maintenance expenditures incurred in order to maintain the day to day operation of our existing assets are charged to expense as incurred.

Net Income Per Common Unit (Tab

Net Income Per Common Unit (Tables)	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Computation of basic and diluted net income per common unit	The following table sets forth the computation of basic and diluted net income per common unit (in millions, except per unit data): Year Ended December 31, 2016 2015 2014 Basic Net Income per Common Unit Net income attributable to PAA $ 726 $ 903 $ 1,384 Distributions to Series A preferred units (1) (122 ) — — Distributions to general partner (1) (412 ) (608 ) (502 ) Distributions to participating securities (1) (4 ) (6 ) (6 ) Undistributed loss allocated to general partner (1) 14 16 2 Other (2 ) — — Net income allocated to common unitholders in accordance with application of the two-class method $ 200 $ 305 $ 878 Basic weighted average common units outstanding (2) 464 394 367 Basic net income per common unit $ 0.43 $ 0.78 $ 2.39 Diluted Net Income per Common Unit Net income attributable to PAA $ 726 $ 903 $ 1,384 Distributions to Series A preferred units (1) (122 ) — — Distributions to general partner (1) (412 ) (608 ) (502 ) Distributions to participating securities (1) (4 ) (6 ) (6 ) Undistributed loss allocated to general partner (1) 14 16 2 Other (2 ) — — Net income allocated to common unitholders in accordance with application of the two-class method $ 200 $ 305 $ 878 Basic weighted average common units outstanding (2) 464 394 367 Effect of dilutive securities: Weighted average LTIP units 2 2 2 Diluted weighted average common units outstanding 466 396 369 Diluted net income per common unit $ 0.43 $ 0.77 $ 2.38 (1) We calculate net income allocated to common unitholders based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings (“undistributed loss”), if any, are allocated to the general partner, common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and as further prescribed under the two-class method. (2) We have considered the common units issued in connection with the Simplification Transactions to be outstanding for the entire fourth quarter of 2016 in the calculation of weighted average common units outstanding to more closely reflect the ownership interests in us with rights to the distributions for the periods included in the calculation of net income allocated to common unitholders.

Inventory, Linefill and Base 31

Inventory, Linefill and Base Gas and Long-term Inventory (Tables)	12 Months Ended
	Dec. 31, 2016
Inventory, Linefill and Base Gas and Long-term Inventory
Schedule of inventory, linefill and base gas and long-term inventory	Inventory, linefill and base gas and long-term inventory consisted of the following (barrels and natural gas volumes in thousands and carrying value in millions): December 31, 2016 December 31, 2015 Volumes Unit of Measure Carrying Value Price/ Unit (1) Volumes Unit of Measure Carrying Value Price/ Unit (1) Inventory Crude oil 23,589 barrels $ 1,049 $ 44.47 16,345 barrels $ 608 $ 37.20 NGL 13,497 barrels 242 $ 17.93 13,907 barrels 218 $ 15.68 Natural gas 14,540 Mcf 32 $ 2.20 22,080 Mcf 53 $ 2.40 Other N/A 20 N/A N/A 37 N/A Inventory subtotal 1,343 916 Linefill and base gas Crude oil 12,273 barrels 710 $ 57.85 12,298 barrels 713 $ 57.98 NGL 1,660 barrels 45 $ 27.11 1,348 barrels 44 $ 32.64 Natural gas 30,812 Mcf 141 $ 4.58 30,812 Mcf 141 $ 4.58 Linefill and base gas subtotal 896 898 Long-term inventory Crude oil 3,279 barrels 163 $ 49.71 3,417 barrels 106 $ 31.02 NGL 1,418 barrels 30 $ 21.16 1,652 barrels 23 $ 13.92 Long-term inventory subtotal 193 129 Total $ 2,432 $ 1,943 (1) Price per unit of measure is comprised of 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 (Tables)

Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Components of property and equipment, net	Property and equipment, net is stated at cost and consisted of the following (in millions): Estimated Useful Lives (Years) December 31, 2016 2015 Pipelines and related facilities (1) 10 - 70 $ 9,025 $ 8,395 Storage, terminal and rail facilities 30 - 70 5,305 5,012 Trucking equipment and other 3 - 15 408 392 Construction in progress — 826 1,217 Office property and equipment 2 - 50 222 196 Land and other N/A 434 442 Property and equipment, gross 16,220 15,654 Accumulated depreciation (2,348 ) (2,180 ) Property and equipment, net $ 13,872 $ 13,474 (1) We include rights-of-way, which are intangible assets, in our pipeline and related facilities amounts within property and equipment.

Goodwill (Tables)

Goodwill (Tables)	12 Months Ended
	Dec. 31, 2016
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of goodwill by segment and changes during the period	Goodwill by segment and changes in goodwill is reflected in the following table (in millions): Transportation Facilities Supply and Logistics Total Balance at December 31, 2014 $ 854 $ 1,152 $ 459 $ 2,465 Acquisitions 3 8 — 11 Foreign currency translation adjustments (42 ) (19 ) (10 ) (71 ) Other — (54 ) 54 — Balance at December 31, 2015 $ 815 $ 1,087 $ 503 $ 2,405 Foreign currency translation adjustments 6 3 1 10 Dispositions and reclassifications to assets held for sale (15 ) (56 ) — (71 ) Balance at December 31, 2016 $ 806 $ 1,034 $ 504 $ 2,344

Investments in Unconsolidated34

Investments in Unconsolidated Entities (Tables)	12 Months Ended
	Dec. 31, 2016
Equity Method Investments and Joint Ventures [Abstract]
Investments in and summarized financial information for entities accounted for under the equity method of accounting	Our investments in unconsolidated entities consisted of the following (in millions, except percentage data): Ownership Interest at December 31, 2016 December 31, Entity Type of Operation 2016 2015 BridgeTex Pipeline Company, LLC (“BridgeTex”) Crude Oil Pipeline 50% $ 1,098 $ 1,082 Butte Pipe Line Company Crude Oil Pipeline 22% 11 9 Caddo Pipeline LLC Crude Oil Pipeline 50% 65 28 Cheyenne Pipeline LLC (“Cheyenne”) Crude Oil Pipeline 50% 30 — Diamond Pipeline LLC (“Diamond”) Crude Oil Pipeline (1) 50% 143 38 Eagle Ford Pipeline LLC Crude Oil Pipeline 50% 372 382 Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Terminals”) Crude Oil Terminal and Dock (1) 50% 53 29 Frontier Aspen LLC Crude Oil Pipeline 50% 45 48 Saddlehorn Pipeline Company, LLC Crude Oil Pipeline 40% 213 103 Settoon, Towing LLC Barge Transportation Services 50% 87 84 STACK Pipeline LLC (“STACK”) Crude Oil Pipeline 50% 14 — White Cliffs Pipeline, LLC Crude Oil Pipeline 36% 212 224 Total Investments in Unconsolidated Entities $ 2,343 $ 2,027 (1) Asset is currently under construction by the entity and has not yet been placed in service. Combined summarized financial information for all of our unconsolidated entities is shown in the tables below (in millions). None of our unconsolidated entities have noncontrolling interests. December 31, 2016 2015 Current assets $ 303 $ 365 Noncurrent assets $ 3,558 $ 2,901 Current liabilities $ 241 $ 231 Noncurrent liabilities $ 162 $ 184 Year Ended December 31, 2016 2015 2014 Revenues $ 802 $ 769 $ 531 Operating income $ 469 $ 441 $ 301 Net income $ 452 $ 424 $ 285

Other Long-Term Assets, Net (Ta

Other Long-Term Assets, Net (Tables)	12 Months Ended
	Dec. 31, 2016
Other Assets [Abstract]
Components of other long-term assets, net of accumulated amortization	Other long-term assets, net of accumulated amortization, consisted of the following (in millions): December 31, 2016 2015 Intangible assets (1) $ 603 $ 610 Fair value of derivative instruments 1 9 Other 47 94 651 713 Accumulated amortization (361 ) (327 ) $ 290 $ 386 (1) We include rights-of-way, which are intangible assets, in our pipeline and related facilities amounts within property and equipment. See Note 5 for a discussion of property and equipment.
Components of intangible assets that have finite lives	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 consisted of the following (in millions): December 31, 2016 December 31, 2015 Estimated Useful Lives (Years) Cost Accumulated Amortization Net Cost Accumulated Amortization Net Customer contracts and relationships 1 – 20 $ 529 $ (330 ) $ 199 $ 537 $ (301 ) $ 236 Property tax abatement 7 – 13 38 (26 ) 12 38 (22 ) 16 Other agreements 25 – 70 29 (5 ) 24 28 (4 ) 24 Emission reduction credits (1) N/A 7 — 7 7 — 7 $ 603 $ (361 ) $ 242 $ 610 $ (327 ) $ 283 (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): 2017 $ 42 2018 $ 37 2019 $ 34 2020 $ 32 2021 $ 30

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Schedule of debt	Debt consisted of the following (in millions): December 31, December 31, SHORT-TERM DEBT Commercial paper notes, bearing a weighted-average interest rate of 1.6% and 1.1%, respectively (1) $ 563 $ 696 Senior secured hedged inventory facility, bearing a weighted-average interest rate of 1.8% and 1.4%, respectively (1) 750 300 Senior notes: 6.13% senior notes due January 2017 400 — Other 2 3 Total short-term debt (2) 1,715 999 LONG-TERM DEBT Senior notes: 5.88% senior notes due August 2016 (3) — 175 6.13% senior notes due January 2017 — 400 6.50% senior notes due May 2018 600 600 8.75% senior notes due May 2019 350 350 2.60% senior notes due December 2019 500 500 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 700 700 3.60% senior notes due November 2024 750 750 4.65% senior notes due October 2025 1,000 1,000 4.50% senior notes due December 2026 750 — 6.70% senior notes due May 2036 250 250 6.65% senior notes due January 2037 600 600 5.15% senior notes due June 2042 500 500 4.30% senior notes due January 2043 350 350 4.70% senior notes due June 2044 700 700 4.90% senior notes due February 2045 650 650 Unamortized discounts and debt issuance costs (76 ) (77 ) Senior notes, net of unamortized discounts and debt issuance costs 9,874 9,698 Commercial paper notes, bearing a weighted-average interest rate of 1.6% and 1.1%, respectively (3) 247 672 Other 3 5 Total long-term debt 10,124 10,375 Total debt (4) $ 11,839 $ 11,374 (1) We classified these commercial paper notes and credit facility borrowings as short-term at December 31, 2016 and 2015 , as these notes and borrowings were primarily designated as working capital borrowings, were required to be repaid within one year and were primarily for hedged NGL and crude oil inventory and NYMEX and ICE margin deposits. (2) At December 31, 2016, includes borrowings of $410 million for cash margin deposits with NYMEX and ICE, which are associated with financial derivatives used for hedging purposes. (3) As of December 31, 2016 and 2015 , we classified a portion of our commercial paper notes as long-term and as of December 31, 2015, we classified our $175 million , 5.88% senior notes due August 2016 as long-term based on our ability and intent to refinance such amounts on a long-term basis under our credit facilities. (4) Our fixed-rate senior notes (including current maturities) had a face value of approximately $10.3 billion and $9.8 billion as of December 31, 2016 and 2015 , respectively. We estimated the aggregate fair value of these notes as of December 31, 2016 and 2015 to be approximately $10.4 billion and $8.6 billion , respectively. Our fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near year end. We estimate that the carrying value of outstanding borrowings under our credit facilities and commercial paper program approximates fair value as interest rates reflect current market rates. The fair value estimates for our senior notes, credit facilities and commercial paper program are based upon observable market data and are classified in Level 2 of the fair value hierarchy.
Issuances of senior unsecured notes	The table below summarizes our issuances of senior unsecured notes during 2016 , 2015 and 2014 (in millions): Year Description Maturity Face Value Interest Payment Dates 2016 4.50% Senior Notes issued at 99.716% of face value December 2026 $ 750 June 15 and December 15 2015 4.65% Senior Notes issued at 99.846% of face value October 2025 $ 1,000 April 15 and October 15 2014 2.60% Senior Notes issued at 99.813% of face value December 2019 $ 500 June 15 and December 15 2014 4.90% Senior Notes issued at 99.876% of face value February 2045 $ 650 February 15 and August 15 2014 3.60% Senior Notes issued at 99.842% of face value November 2024 $ 750 May 1 and November 1 2014 4.70% Senior Notes issued at 99.734% of face value June 2044 $ 700 June 15 and December 15
Aggregate maturities of long-term debt	The following table presents the aggregate contractually scheduled maturities of such long-term debt for the next five years and thereafter. The amounts presented exclude unamortized discounts and debt issuance costs. Calendar Year Payment (in millions) 2017 $ 247 2018 600 2019 850 2020 500 2021 600 Thereafter 7,403

Partners' Capital and Distrib37

Partners' Capital and Distributions (Tables)	12 Months Ended
	Dec. 31, 2016
Partners' Capital Notes [Abstract]
Activity for Series A preferred units and common units	The following table presents the activity for our Series A preferred units and common units: Limited Partners Preferred Units Common Units Outstanding at December 31, 2013 — 359,133,200 Sale of common units — 15,375,810 Issuance of common units under LTIP — 598,783 Outstanding at December 31, 2014 — 375,107,793 Sale of common units — 22,133,904 Issuance of common units under LTIP — 485,927 Outstanding at December 31, 2015 — 397,727,624 Sale of Series A preferred units 61,030,127 — Issuance of Series A preferred units in connection with in-kind distributions 3,358,726 — Sale of common units — 26,278,288 Issuance of common units under LTIP — 480,581 Issuance of common units in connection with Simplification Transactions — 244,707,926 Outstanding at December 31, 2016 64,388,853 669,194,419
Schedule of distributions paid, net of reductions in the general partner's incentive distributions	The following table details distributions paid during the year presented (in millions, except per unit data): Distributions Paid Distributions per common unit Year Common Unitholders General Partner (1) Total 2016 $ 1,062 $ 565 $ 1,627 $ 2.65 2015 $ 1,081 $ 590 $ 1,671 $ 2.76 2014 $ 934 $ 473 $ 1,407 $ 2.55 (1) During the years ended December 31, 2016 , 2015 and 2014 , our general partner’s incentive distributions were reduced by approximately $18 million , $22 million and $23 million , respectively, which were agreed to in connection with certain acquisitions.
Issuance of common units	The following table summarizes our issuance of common units in connection with our Continuous Offering Program and underwritten offerings (net proceeds in millions): Year Type of Offering Units Issued Net Proceeds (1) (2) 2016 Total Continuous Offering Program 26,278,288 $ 805 (3) 2015 Continuous Offering Program 1,133,904 $ 59 (3) 2015 Underwritten Offering 21,000,000 1,062 2015 Total 22,133,904 $ 1,121 2014 Total Continuous Offering Program 15,375,810 $ 866 (3) (1) Amounts are net of costs associated with the offerings. (2) For periods prior to the closing of the Simplification Transactions, amounts include our general partner’s proportionate capital contributions of $9 million , $22 million and $18 million during 2016 , 2015 and 2014 , respectively. (3) We pay commissions to our sales agents in connection with common unit issuances under our Continuous Offering Program. We paid $8 million , $1 million and $9 million of such commissions during 2016 , 2015 and 2014 , respectively.

Derivatives and Risk Manageme38

Derivatives and Risk Management Activities (Tables)	12 Months Ended
	Dec. 31, 2016
Derivatives and Risk Management Activities
Impact of derivative activities recognized in earnings	A summary of the impact of our derivative activities recognized in earnings for the periods indicated is as follows (in millions): Year Ended December 31, 2016 Location of Gain/(Loss) Derivatives in Hedging Relationships (1) (2) Derivatives Not Designated as a Hedge Total Commodity Derivatives Supply and Logistics segment revenues $ 2 $ (344 ) $ (342 ) Transportation segment revenues — 5 5 Interest Rate Derivatives Interest expense, net (14 ) — (14 ) Foreign Currency Derivatives Supply and Logistics segment revenues — (3 ) (3 ) Preferred Distribution Rate Reset Option Other income/(expense), net — 30 30 Total Gain/(Loss) on Derivatives Recognized in Net Income $ (12 ) $ (312 ) $ (324 ) Year Ended December 31, 2015 Location of Gain/(Loss) Derivatives in Hedging Relationships (1) (2) Derivatives Not Designated as a Hedge Total Commodity Derivatives Supply and Logistics segment revenues $ 56 $ 152 $ 208 Transportation segment revenues — 8 8 Field operating costs — (18 ) (18 ) Interest Rate Derivatives Interest expense, net (11 ) — (11 ) Foreign Currency Derivatives Supply and Logistics segment revenues — (31 ) (31 ) Total Gain/(Loss) on Derivatives Recognized in Net Income $ 45 $ 111 $ 156 Year Ended December 31, 2014 Location of Gain/(Loss) Derivatives in Hedging Relationships (1) (2) Derivatives Not Designated as a Hedge Total Commodity Derivatives Supply and Logistics segment revenues $ (1 ) $ 206 $ 205 Field operating costs — (21 ) (21 ) Interest Rate Derivatives Interest expense, net (5 ) — (5 ) Foreign Currency Derivatives Supply and Logistics segment revenues — (28 ) (28 ) Other income/(expense), net 2 — 2 Total Gain/(Loss) on Derivatives Recognized in Net Income $ (4 ) $ 157 $ 153 (1) During the year ended December 31, 2016, we reclassified losses of approximately $2 million and $2 million from AOCI to Supply and Logistics segment revenues and Interest expense, net, respectively, due to anticipated hedged transactions being probable of not occurring. During the year ended December 31, 2015, we reclassified a loss of approximately $4 million from AOCI to Interest expense, net due to an anticipated hedged transaction being probable of not occurring. During the year ended December 31, 2014, all of our hedged transactions were probable of occurring. (2) Amounts in Interest expense, net include a loss of $4 million during the year ended December 31, 2016 attributable to the ineffective portion of cash flow hedges. No ineffectiveness was recognized for cash flow hedges during the years ended December 31, 2015 and 2014.
Summary of derivative assets and liabilities on consolidated balance sheets on a gross basis	The following table summarizes the derivative assets and liabilities on our Consolidated Balance Sheet on a gross basis as of December 31, 2016 (in millions): Asset Derivatives Liability Derivatives Balance Sheet Location Fair Value Balance Sheet Location Fair Value Derivatives designated as hedging instruments: Commodity derivatives $ — Other current assets $ — Interest rate derivatives — Other current liabilities (23 ) Other long-term liabilities and deferred credits (27 ) Total derivatives designated as hedging instruments $ — $ (50 ) Derivatives not designated as hedging instruments: Commodity derivatives Other current assets $ 101 Other current assets $ (344 ) Other long-term assets, net 2 Other long-term assets, net (1 ) Other long-term liabilities and deferred credits 2 Other current liabilities (14 ) Other long-term liabilities and deferred credits (34 ) Foreign currency derivatives Other current liabilities 3 Other current liabilities (6 ) Preferred Distribution Rate Reset Option — Other long-term liabilities and deferred credits (32 ) Total derivatives not designated as hedging instruments $ 108 $ (431 ) Total derivatives $ 108 $ (481 ) The following table summarizes the derivative assets and liabilities on our Consolidated Balance Sheet on a gross basis as of December 31, 2015 (in millions): Asset Derivatives Liability Derivatives Balance Sheet Location Fair Value Balance Sheet Location Fair Value Derivatives designated as hedging instruments: Commodity derivatives Other current assets $ 4 Other current assets $ (2 ) Interest rate derivatives Other long-term assets, net 1 Other current liabilities (17 ) Other long-term liabilities and deferred credits (33 ) Total derivatives designated as hedging instruments $ 5 $ (52 ) Derivatives not designated as hedging instruments: Commodity derivatives Other current assets $ 265 Other current assets $ (35 ) Other long-term assets, net 10 Other long-term assets, net (1 ) Other current liabilities (13 ) Other long-term liabilities and deferred credits (1 ) Foreign currency derivatives Other current liabilities (8 ) Total derivatives not designated as hedging instruments $ 275 $ (58 ) Total derivatives $ 280 $ (110 )
Schedule of net broker receivable (payable)	The following table provides the components of our net broker receivable/(payable): December 31, 2016 December 31, 2015 Initial margin $ 119 $ 91 Variation margin posted/(returned) 291 (247 ) Net broker receivable/(payable) $ 410 $ (156 )
Schedule of derivative financial assets and liabilities that are subject to offsetting, including enforceable master netting arrangements	The following table presents information about derivative financial assets and liabilities that are subject to offsetting, including enforceable master netting arrangements (in millions): December 31, 2016 December 31, 2015 Derivative Asset Positions Derivative Liability Positions Derivative Asset Positions Derivative Liability Positions Netting Adjustments: Gross position - asset/(liability) $ 108 $ (481 ) $ 280 $ (110 ) Netting adjustment (350 ) 350 (38 ) 38 Cash collateral paid/(received) 410 — (156 ) — Net position - asset/(liability) $ 168 $ (131 ) $ 86 $ (72 ) Balance Sheet Location After Netting Adjustments: Other current assets $ 167 $ — $ 76 $ — Other long-term assets, net 1 — 10 — Other current liabilities — (40 ) — (38 ) Other long-term liabilities and deferred credits — (91 ) — (34 ) $ 168 $ (131 ) $ 86 $ (72 )
Net deferred gain/(loss), including tax effects, recognized in AOCI for derivatives	The following table summarizes the net deferred gain/(loss), including tax effects, recognized in AOCI for derivatives (in millions): Year Ended December 31, 2016 2015 2014 Commodity derivatives, net $ — $ 33 $ 15 Interest rate derivatives, net (33 ) (32 ) (103 ) Foreign currency derivatives, net — — 2 Total $ (33 ) $ 1 $ (86 )
Schedule of derivative financial assets and liabilities accounted for at fair value on a recurring basis, by level within the fair value hierarchy	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 (in millions): Fair Value as of December 31, 2016 Fair Value as of December 31, 2015 Recurring Fair Value Measures (1) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Commodity derivatives $ (113 ) $ (171 ) $ (4 ) $ (288 ) $ 126 $ 90 $ 11 $ 227 Interest rate derivatives — (50 ) — (50 ) — (49 ) — (49 ) Foreign currency derivatives — (3 ) — (3 ) — (8 ) — (8 ) Preferred Distribution Rate Reset Option — — (32 ) (32 ) — — — — Total net derivative asset/(liability) $ (113 ) $ (224 ) $ (36 ) $ (373 ) $ 126 $ 33 $ 11 $ 170 (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, 2016 2015 Beginning Balance $ 11 $ 15 Net gains for the period included in earnings 28 1 Settlements (10 ) (14 ) Derivatives entered into during the period (65 ) 9 Ending Balance $ (36 ) $ 11 Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period $ (36 ) $ 10
Interest Rate Swaps
Derivatives and Risk Management Activities
Schedule of terms of forward starting interest rate swaps	The following table summarizes the terms of our outstanding interest rate derivatives as of December 31, 2016 (notional amounts in millions): Hedged Transaction Number and Types of Derivatives Employed Notional Amount Expected Termination Date Average Rate Locked Accounting Treatment Anticipated interest payments 8 forward starting swaps (30-year) $ 200 6/15/2017 3.14 % Cash flow hedge Anticipated interest payments 8 forward starting swaps (30-year) $ 200 6/15/2018 3.20 % Cash flow hedge Anticipated interest payments 8 forward starting swaps (30-year) $ 200 6/14/2019 2.83 % Cash flow hedge
Foreign Currency Derivatives
Derivatives and Risk Management Activities
Open forward exchange contracts	The following table summarizes our open forward exchange contracts as of December 31, 2016 (in millions): USD CAD Average Exchange Rate USD to CAD Forward exchange contracts that exchange CAD for USD: 2017 $ 274 $ 363 $1.00 - $1.33 Forward exchange contracts that exchange USD for CAD: 2017 $ 492 $ 652 $1.00 - $1.33

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Components of income tax expense	Components of income tax expense are as follows (in millions): Year Ended December 31, 2016 2015 2014 Current income tax expense: State income tax $ 2 $ 1 $ 1 Canadian federal and provincial income tax 83 83 70 Total current income tax expense $ 85 $ 84 $ 71 Deferred income tax expense/(benefit): Canadian federal and provincial income tax $ (60 ) $ 16 $ 100 Total deferred income tax expense/(benefit) $ (60 ) $ 16 $ 100 Total income tax expense $ 25 $ 100 $ 171
Summary of differences between tax expense based on the statutory federal income tax rate and the effective income tax expense	The difference between income tax expense based on the statutory federal income tax rate and our effective income tax expense is summarized as follows (in millions): Year Ended December 31, 2016 2015 2014 Income before tax $ 755 $ 1,006 $ 1,557 Partnership earnings not subject to current Canadian tax (723 ) (773 ) (976 ) $ 32 $ 233 $ 581 Canadian federal and provincial corporate tax rate 27 % 26 % 25 % Income tax at statutory rate $ 8 $ 61 $ 145 Canadian withholding tax $ 13 $ 14 $ 16 Canadian permanent differences and rate changes 2 24 9 State income tax 2 1 1 Total income tax expense $ 25 $ 100 $ 171
Deferred tax assets and liabilities	Deferred tax assets and liabilities are aggregated by the applicable tax paying entity and jurisdiction and result from the following (in millions): December 31, 2016 2015 Deferred tax assets: Derivative instruments $ 49 $ — Book accruals in excess of current tax deductions 24 20 Net operating losses 4 3 Total deferred tax assets 77 23 Deferred tax liabilities: Derivative instruments — (30 ) Property and equipment in excess of tax values (394 ) (312 ) Other (41 ) (41 ) Total deferred tax liabilities (435 ) (383 ) Net deferred tax liabilities $ (358 ) $ (360 ) Balance sheet classification of deferred tax assets/(liabilities): Other long-term assets, net $ 4 $ 3 Other long-term liabilities and deferred credits (362 ) (363 ) $ (358 ) $ (360 )

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2016
Oxy
Related Party Transactions
Schedule of related party transactions	As of December 31, 2016 , Oxy had a representative on the board of directors of PAGP and owned approximately 13% of the limited partner interests in AAP. During the three years ended December 31, 2016 , we recognized sales and transportation revenues and purchased petroleum products from Oxy. These transactions were conducted at posted tariff rates or prices that we believe approximate market. Included in these transactions was a crude oil buy/sell agreement that includes a multi-year minimum volume commitment. The impact to our Consolidated Statements of Operations from those transactions is included below (in millions): Year Ended December 31, 2016 2015 2014 Revenues $ 655 $ 866 $ 1,212 Purchases and related costs (1) $ 42 $ 41 $ 925 (1) Purchases and related costs include crude oil buy/sell transactions that are accounted for as inventory exchanges and are presented net in our Consolidated Statements of Operations. We currently have a netting arrangement with Oxy. Our gross receivable and payable amounts with Oxy were as follows (in millions): December 31, 2016 2015 Trade accounts receivable and other receivables $ 789 $ 405 Accounts payable $ 836 $ 363

Equity-Indexed Compensation P41

Equity-Indexed Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2016
Equity-Indexed Compensation Plans
Schedule of estimated vesting dates for PAA long-term incentive plan awards outstanding	At December 31, 2016 , the following LTIP awards, denominated in PAA units, were outstanding (units in millions): PAA LTIP Units Outstanding (1) (2) PAA Distribution Required (3) Estimated Unit Vesting Date 2017 2018 2019 2020 Thereafter Total 8.9 $2.20-$2.65 1.7 2.1 2.0 1.3 1.8 8.9 (1) Approximately 4.3 million of the 8.9 million outstanding PAA LTIP awards also include DERs, of which 1.6 million had vested as of December 31, 2016 . (2) LTIP units outstanding do not include AAP Management Units. (3) Certain LTIP awards vest upon the later of a certain date or the attainment of performance conditions requiring the attainment of certain annualized PAA distribution levels or upon the attainment of such levels alone. 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. As of December 31, 2016 , a distribution of $2.20 per common unit was deemed probable of occurring in the reasonably foreseeable future (and was initially determined to be probable in the third quarter of 2016).
Summary of expense recognized and the value of vested LTIP awards under equity-indexed compensation plans	The table below summarizes the expense recognized and the value of vested LTIP awards (settled both in common units and cash) under our equity-indexed compensation plans and includes both liability-classified and equity-classified awards (in millions): Year Ended December 31, 2016 2015 2014 Equity-indexed compensation expense $ 60 $ 27 $ 98 LTIP unit-settled vestings $ 24 $ 37 $ 53 LTIP cash-settled vestings $ 28 $ 66 $ 53 DER cash payments $ 6 $ 8 $ 8
Estimated 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) 2017 $ 65 2018 42 2019 19 2020 7 2021 2 Total $ 135 (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, 2016 . (2) Includes unamortized fair value associated with AAP Management Units.
Long-Term Incentive Plan Awards
Equity-Indexed Compensation Plans
Summary of activity for equity-indexed compensation plans	Activity for LTIP awards under our equity-indexed compensation plans denominated in PAA units is summarized in the following table (units in millions): PAA Units (1) (2) Units Weighted Average Grant Date Fair Value per Unit Outstanding at December 31, 2013 8.4 $ 36.97 Granted 1.2 $ 47.68 Vested (1.9 ) $ 25.49 Cancelled or forfeited (0.4 ) $ 40.14 Outstanding at December 31, 2014 7.3 $ 41.45 Granted 2.1 $ 28.76 Vested (2.1 ) $ 28.91 Cancelled or forfeited (0.4 ) $ 44.56 Outstanding at December 31, 2015 6.9 $ 41.23 Granted 4.5 $ 23.38 Vested (1.9 ) $ 45.91 Modified (3) — $ (8.21 ) Cancelled or forfeited (0.6 ) $ 37.19 Outstanding at December 31, 2016 8.9 $ 29.62 (1) Amounts do not include AAP Management Units. (2) Approximately 0.5 million , 0.5 million and 0.6 million PAA common units were issued, net of tax withholding of approximately 0.3 million , 0.3 million and 0.3 million units during 2016 , 2015 and 2014 , respectively, in connection with the settlement of vested awards. The remaining PAA awards (approximately 1.1 million , 1.3 million and 1.0 million units) that vested during 2016 , 2015 and 2014 , respectively, were settled in cash. (3) During the third quarter of 2016 modifications were made to the vesting criteria of 2.2 million PAA LTIP units. In accordance with FASB guidance on share-based payments, the grant date fair values of these awards were adjusted as of the modification date.
AAP Management Units
Equity-Indexed Compensation Plans
Summary of activity for equity-indexed compensation plans	The following is a summary of activity of AAP Management Units (in millions): Outstanding Outstanding Units Earned Grant Date Fair Value of Outstanding AAP Management Units (1) Balance at December 31, 2014 18.4 17.9 $ 64 Granted 0.6 — 24 Earned N/A 0.3 N/A Balance at December 31, 2015 19.0 18.2 $ 88 Modified (2) — — (17 ) Converted (15.6 ) (15.6 ) (36 ) Balance at December 31, 2016 3.4 2.6 $ 35 (1) Of the $35 million grant date fair value, $22 million had been recognized through December 31, 2016 on a cumulative basis. Of this amount, $2 million , $1 million and $7 million was recognized as expense during the years ended December 31, 2016 , 2015 and 2014 , respectively. (2) During the third quarter of 2016 modifications were made to the distribution performance thresholds of the 0.8 million unearned AAP Management Units. In accordance with FASB guidance on share-based payments, the grant date fair values of these awards were adjusted as of the modification date.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Schedule of future non-cancelable commitments	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, 2016 , are summarized below (in millions): 2017 2018 2019 2020 2021 Thereafter Total Leases and rights-of-way easements (1) $ 195 $ 165 $ 140 $ 118 $ 97 $ 404 $ 1,119 Other commitments (2) 257 166 153 132 128 378 1,214 Total $ 452 $ 331 $ 293 $ 250 $ 225 $ 782 $ 2,333 (1) Includes capital and operating leases as defined by FASB guidance as well as obligations for rights-of-way easements. Lease expense for 2016 , 2015 and 2014 was $198 million , $164 million and $145 million , respectively. (2) Primarily includes third-party storage and transportation agreements and pipeline throughput agreements, as well as approximately $855 million associated with an agreement to transport crude oil on a pipeline that is owned by an equity method investee, in which we own a 50% interest. Our commitment to transport is supported by crude oil buy/sell agreements with third parties (including Oxy) with commensurate quantities.

Quarterly Financial Data (Una43

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Quarterly financial data (unaudited)	First Quarter Second Quarter Third Quarter Fourth Quarter Total (1) (in millions, except per unit data) 2016 Total revenues $ 4,111 $ 4,950 $ 5,170 $ 5,952 $ 20,182 Gross margin (2) $ 349 $ 219 $ 419 $ 286 $ 1,273 Operating income $ 282 $ 146 $ 349 $ 218 $ 994 Net income $ 203 $ 102 $ 298 $ 127 $ 730 Net income attributable to PAA $ 202 $ 101 $ 297 $ 126 $ 726 Basic net income/(loss) per common unit $ 0.07 $ (0.20 ) $ 0.40 $ 0.14 $ 0.43 Diluted net income/(loss) per common unit $ 0.07 $ (0.20 ) $ 0.40 $ 0.14 $ 0.43 Cash distributions per common unit (3) $ 0.70 $ 0.70 $ 0.70 $ 0.55 $ 2.65 2015 Total revenues $ 5,942 $ 6,663 $ 5,551 $ 4,996 $ 23,152 Gross margin (2) $ 450 $ 290 $ 395 $ 405 $ 1,540 Operating income $ 372 $ 211 $ 335 $ 344 $ 1,262 Net income $ 284 $ 124 $ 250 $ 248 $ 906 Net income attributable to PAA $ 283 $ 124 $ 249 $ 247 $ 903 Basic net income/(loss) per common unit $ 0.36 $ (0.06 ) $ 0.25 $ 0.24 $ 0.78 Diluted net income/(loss) per common unit $ 0.35 $ (0.06 ) $ 0.24 $ 0.24 $ 0.77 Cash distributions per common unit (3) $ 0.68 $ 0.69 $ 0.70 $ 0.70 $ 2.76 (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) Represents cash distributions declared and paid in the period presented.

Operating Segments (Tables)

Operating Segments (Tables)	12 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
Segment financial data	The following table reflects certain financial data for each segment (in millions): Transportation Facilities Supply and Logistics Intersegment Adjustment (1) Total Year Ended December 31, 2016 Revenues: External customers $ 954 $ 546 $ 19,004 $ (322 ) $ 20,182 Intersegment (2) 630 561 14 322 1,527 Total revenues of reportable segments $ 1,584 $ 1,107 $ 19,018 $ — $ 21,709 Equity earnings in unconsolidated entities $ 195 $ — $ — $ 195 Segment adjusted EBITDA $ 1,141 $ 667 $ 359 $ 2,167 Capital expenditures (3) $ 1,063 $ 577 $ 54 $ 1,694 Maintenance capital $ 121 $ 55 $ 10 $ 186 As of December 31, 2016 Total assets $ 10,917 $ 7,556 $ 5,737 $ 24,210 Investments in unconsolidated entities $ 2,290 $ 53 $ — $ 2,343 Transportation Facilities Supply and Logistics Intersegment Adjustment (1) Total Year Ended December 31, 2015 Revenues: External customers $ 953 $ 528 $ 21,927 $ (256 ) $ 23,152 Intersegment (2) 641 522 18 256 1,437 Total revenues of reportable segments $ 1,594 $ 1,050 $ 21,945 $ — $ 24,589 Equity earnings in unconsolidated entities $ 183 $ — $ — $ 183 Segment adjusted EBITDA $ 1,056 $ 588 $ 568 $ 2,212 Capital expenditures (3) $ 1,278 $ 813 $ 184 $ 2,275 Maintenance capital $ 144 $ 68 $ 8 $ 220 As of December 31, 2015 Total assets $ 10,345 $ 7,330 $ 4,613 $ 22,288 Investments in unconsolidated entities $ 1,998 $ 29 $ — $ 2,027 Transportation Facilities Supply and Logistics Intersegment Adjustment (1) Total Year Ended December 31, 2014 Revenues: External customers $ 994 $ 576 $ 42,114 $ (220 ) $ 43,464 Intersegment (2) 661 551 36 220 1,468 Total revenues of reportable segments $ 1,655 $ 1,127 $ 42,150 $ — $ 44,932 Equity earnings in unconsolidated entities $ 108 $ — $ — $ 108 Segment adjusted EBITDA $ 979 $ 597 $ 651 $ 2,227 Capital expenditures (3) $ 2,483 $ 582 $ 60 $ 3,125 Maintenance capital $ 165 $ 52 $ 7 $ 224 As of December 31, 2014 Total assets $ 9,579 $ 6,843 $ 5,776 $ 22,198 Investments in unconsolidated entities $ 1,735 $ — $ — $ 1,735 (1) Transportation revenues from external customers include inventory exchanges that are substantially similar to tariff-like arrangements with our customers. Under these arrangements, our Supply and Logistics segment has transacted the inventory exchange and serves as the shipper on our pipeline systems. See Note 2 for discussion of our related accounting policy. We have included an estimate of the revenues from these inventory exchanges in our Transportation segment revenue presented above and adjusted those revenues out such that Total revenue from External customers reconciles to our Consolidated Statement of Operations. This presentation is consistent with the information provided to our CODM. (2) Segment revenues include intersegment amounts that are eliminated in Purchases and related costs and Field operating costs in our Consolidated Statements of Operations. Intersegment sales are conducted at posted tariff rates, rates similar to those charged to third parties or rates that we believe approximate market at the time the agreement is executed or renegotiated. (3) Expenditures for acquisition capital and expansion capital, including investments in unconsolidated entities. Segment Adjusted EBITDA Reconciliation The following table reconciles segment adjusted EBITDA to net income attributable to PAA (in millions): Year Ended December 31, 2016 2015 2014 Segment adjusted EBITDA $ 2,167 $ 2,212 $ 2,227 Adjustments (1) : Depreciation and amortization of unconsolidated entities (2) (50 ) (45 ) (29 ) Gains/(losses) from derivative activities net of inventory valuation adjustments (3) (404 ) (110 ) 243 Long-term inventory costing adjustments (4) 58 (99 ) (85 ) Deficiencies under minimum volume commitments, net (5) (46 ) — — Equity-indexed compensation expense (6) (33 ) (27 ) (56 ) Net gain/(loss) on foreign currency revaluation (7) (9 ) 29 (9 ) Line 901 incident (8) — (83 ) — Depreciation and amortization (494 ) (432 ) (384 ) Interest expense, net (467 ) (432 ) (348 ) Other income/(expense), net 33 (7 ) (2 ) Income before tax 755 1,006 1,557 Income tax expense (25 ) (100 ) (171 ) Net income 730 906 1,386 Net income attributable to noncontrolling interests (4 ) (3 ) (2 ) Net income attributable to PAA $ 726 $ 903 $ 1,384 (1) Represents adjustments utilized by our CODM in the evaluation of segment results. (2) Includes our proportionate share of the depreciation and amortization of equity method investments. (3) We use derivative instruments for risk management purposes and our related processes include specific identification of hedging instruments to an underlying hedged transaction. Although we identify an underlying transaction for each derivative instrument we enter into, there may not be an accounting hedge relationship between the instrument and the underlying transaction. In the course of evaluating our results, we identify the earnings that were recognized during the period related to derivative instruments for which the identified underlying transaction does not occur in the current period and exclude the related gains and losses in determining segment adjusted EBITDA. In addition, we exclude gains and losses on derivatives that are related to investing activities, such as the purchase of linefill. We also exclude the impact of corresponding inventory valuation adjustments, as applicable. (4) We carry crude oil and NGL inventory that is comprised of minimum working inventory requirements in third-party assets and other working inventory that is needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future. Therefore, we classify this inventory as long-term on our balance sheet and do not hedge the inventory with derivative instruments (similar to linefill in our own assets). We exclude the impact of changes in the average cost of the long-term inventory (that result from fluctuations in market prices) and writedowns of such inventory that result from price declines from segment adjusted EBITDA. (5) We have certain agreements that require counterparties to deliver, transport or throughput a minimum volume over an agreed upon period. Substantially all of such agreements were entered into with counterparties to economically support the return on our capital expenditure necessary to construct the related asset. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote. We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue, as a selected item impacting comparability. Our CODM views the inclusion of the contractually committed revenues associated with that period as meaningful to segment adjusted EBITDA as the related asset has been constructed, is standing ready to provide the committed service and the fixed operating costs are included in the current period results. Amounts for years prior to 2016 were not significant to segment adjusted EBITDA ( $13 million and $4 million for the years ended December 31, 2015 and 2014, respectively). (6) Includes equity-indexed compensation expense associated with awards that will or may be settled in units. (7) Includes gains and losses from the revaluation of foreign currency transactions and monetary assets and liabilities. (8) Includes costs recognized during the period related to the Line 901 incident that occurred in May 2015, net of amounts we believe are probable of recovery from insurance.
Reconciliation of segment profit to net income attributable to PAA	The following table reconciles segment adjusted EBITDA to net income attributable to PAA (in millions): Year Ended December 31, 2016 2015 2014 Segment adjusted EBITDA $ 2,167 $ 2,212 $ 2,227 Adjustments (1) : Depreciation and amortization of unconsolidated entities (2) (50 ) (45 ) (29 ) Gains/(losses) from derivative activities net of inventory valuation adjustments (3) (404 ) (110 ) 243 Long-term inventory costing adjustments (4) 58 (99 ) (85 ) Deficiencies under minimum volume commitments, net (5) (46 ) — — Equity-indexed compensation expense (6) (33 ) (27 ) (56 ) Net gain/(loss) on foreign currency revaluation (7) (9 ) 29 (9 ) Line 901 incident (8) — (83 ) — Depreciation and amortization (494 ) (432 ) (384 ) Interest expense, net (467 ) (432 ) (348 ) Other income/(expense), net 33 (7 ) (2 ) Income before tax 755 1,006 1,557 Income tax expense (25 ) (100 ) (171 ) Net income 730 906 1,386 Net income attributable to noncontrolling interests (4 ) (3 ) (2 ) Net income attributable to PAA $ 726 $ 903 $ 1,384 (1) Represents adjustments utilized by our CODM in the evaluation of segment results. (2) Includes our proportionate share of the depreciation and amortization of equity method investments. (3) We use derivative instruments for risk management purposes and our related processes include specific identification of hedging instruments to an underlying hedged transaction. Although we identify an underlying transaction for each derivative instrument we enter into, there may not be an accounting hedge relationship between the instrument and the underlying transaction. In the course of evaluating our results, we identify the earnings that were recognized during the period related to derivative instruments for which the identified underlying transaction does not occur in the current period and exclude the related gains and losses in determining segment adjusted EBITDA. In addition, we exclude gains and losses on derivatives that are related to investing activities, such as the purchase of linefill. We also exclude the impact of corresponding inventory valuation adjustments, as applicable. (4) We carry crude oil and NGL inventory that is comprised of minimum working inventory requirements in third-party assets and other working inventory that is needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future. Therefore, we classify this inventory as long-term on our balance sheet and do not hedge the inventory with derivative instruments (similar to linefill in our own assets). We exclude the impact of changes in the average cost of the long-term inventory (that result from fluctuations in market prices) and writedowns of such inventory that result from price declines from segment adjusted EBITDA. (5) We have certain agreements that require counterparties to deliver, transport or throughput a minimum volume over an agreed upon period. Substantially all of such agreements were entered into with counterparties to economically support the return on our capital expenditure necessary to construct the related asset. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote. We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue, as a selected item impacting comparability. Our CODM views the inclusion of the contractually committed revenues associated with that period as meaningful to segment adjusted EBITDA as the related asset has been constructed, is standing ready to provide the committed service and the fixed operating costs are included in the current period results. Amounts for years prior to 2016 were not significant to segment adjusted EBITDA ( $13 million and $4 million for the years ended December 31, 2015 and 2014, respectively). (6) Includes equity-indexed compensation expense associated with awards that will or may be settled in units. (7) Includes gains and losses from the revaluation of foreign currency transactions and monetary assets and liabilities. (8) Includes costs recognized during the period related to the Line 901 incident that occurred in May 2015, net of amounts we believe are probable of recovery from insurance.
Revenues attributable to geographic 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) 2016 2015 2014 United States $ 15,599 $ 18,701 $ 34,860 Canada 4,583 4,451 8,604 $ 20,182 $ 23,152 $ 43,464 (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 geographic areas	December 31, Long-Lived Assets (1) 2016 2015 United States $ 16,041 $ 15,942 Canada 3,895 3,368 $ 19,936 $ 19,310 (1) Excludes long-term derivative assets.

Organization and Basis of Con45

Organization and Basis of Consolidation and Presentation (Details) shares in Millions, $ in Millions	Nov. 15, 2016USD ($)shares	Nov. 14, 2016	Dec. 31, 2016segmentshares
Organization and basis of presentation
Operating segments number | segment			3
Limited partner interest		98.00%
AAP
Organization and basis of presentation
Limited partner interest			33.00%
AAP
Organization and basis of presentation
Limited partner interest (units)			241.7
AAP | PAGP
Organization and basis of presentation
Limited partner interest			42.00%
Simplification Agreement | PAA GP
Organization and basis of presentation
General Partner Economic Ownership Interest Converted Into Non-economic Interest	2.00%
Simplification Agreement | AAP
Organization and basis of presentation
Units agreed to be issued in connection with the Simplification Transactions	245.5
Units to be issued in the future (in units)	0.8
A A P Senior Secured Credit Agreement | Simplification Agreement | AAP
Organization and basis of presentation
Debt assumed | $	$ 642

Summary of Significant Accoun46

Summary of Significant Accounting Policies - Minimum Volume Commitments (Details) - Minimum Volume Commitments - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Minimum Volume Commitments
Total counterparty deficiencies	$ 66	$ 33
Deferred revenue	54	17
Deficiencies not yet billed or collected	$ 12	$ 16

Summary of Significant Accoun47

Summary of Significant Accounting Policies - Various Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Foreign Currency Transactions
Gain (loss) on revaluation of foreign currency transactions and monetary assets and liabilities	$ (8)	$ 21	$ (13)
Cash and Cash Equivalents
Outstanding checks included in accounts payable that were reclassified from cash and cash equivalents	66	60
Accounts Receivable
Advance cash payments received from third parties to mitigate credit risk	89	88
Standby letters of credit	$ 66	$ 36
Substantially all trade accounts receivable, net, maximum age of balances past their scheduled invoice date	30 days	30 days
Allowance for doubtful accounts receivable	$ 3	$ 4
Asset Retirement Obligations
Fair value of asset retirement obligations	$ 44	$ 35

Net Income Per Common Unit (Det

Net Income Per Common Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	Nov. 15, 2016	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Nov. 14, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Related Party Transactions
General partner ownership interest										2.00%
Basic Net Income per Common Unit
Net income attributable to PAA		$ 126	$ 297	$ 101	$ 202	$ 247	$ 249	$ 124	$ 283		$ 726	$ 903	$ 1,384
Distributions to Series A preferred units											(122)	0	0
Distributions to general partner											(412)	(608)	(502)
Distributions to participating securities											(4)	(6)	(6)
Undistributed loss allocated to general partner											14	16	2
Other											(2)	0	0
Net income allocated to common unitholders in accordance with application of the two-class method											$ 200	$ 305	878
Basic net income/(loss) per common unit (in dollars per unit)		$ 0.14	$ 0.40	$ (0.20)	$ 0.07	$ 0.24	$ 0.25	$ (0.06)	$ 0.36		$ 0.43	$ 0.78
Diluted Net Income per Common Unit
Net income attributable to PAA		$ 126	$ 297	$ 101	$ 202	$ 247	$ 249	$ 124	$ 283		$ 726	$ 903	1,384
Distributions to Series A preferred units											(122)	0	0
Distributions to general partner											(412)	(608)	(502)
Distributions to participating securities											(4)	(6)	(6)
Undistributed loss allocated to general partner											14	16	2
Other											(2)	0	0
Net income attributable to common unitholders in accordance with application of the two-class method											$ 200	$ 305	$ 878
Diluted net income per common unit (in dollars per unit)		$ 0.14	$ 0.40	$ (0.20)	$ 0.07	$ 0.24	$ 0.24	$ (0.06)	$ 0.35		$ 0.43	$ 0.77
Common Units
Basic Net Income per Common Unit
Basic weighted average common units outstanding (in units)											464	394	367
Basic net income/(loss) per common unit (in dollars per unit)											$ 0.43	$ 0.78	$ 2.39
Diluted Net Income per Common Unit
Basic weighted average common units outstanding (in units)											464	394	367
Effect of dilutive securities: Weighted average LTIP units (in units)											2	2	2
Diluted weighted average common units outstanding (in units)											466	396	369
Diluted net income per common unit (in dollars per unit)											$ 0.43	$ 0.77	$ 2.38
Simplification Agreement | PAA GP
Related Party Transactions
General Partner Economic Ownership Interest Converted Into Non-economic Interest	2.00%
Simplification Agreement | AAP
Related Party Transactions
Issuance of common units in connection with Simplification Transactions (in units)	244.7
Units to be issued in the future (in units)	0.8

Inventory, Linefill and Base 49

Inventory, Linefill and Base Gas and Long-term Inventory (Details) bbl in Thousands, Mcf in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)$ / Mcf$ / bblbblMcf	Dec. 31, 2015USD ($)$ / Mcf$ / bblbblMcf	Dec. 31, 2014USD ($)
Inventory-related disclosures
Charge related to the write-down of inventory	$ 3	$ 117	$ 289
Gains on sale of linefill and base gas		1	8
Proceeds from sale of linefill and base gas		1	$ 24
Inventory by category
Inventory	1,343	916
Linefill and base gas	896	898
Long-term inventory	193	129
Total	$ 2,432	$ 1,943
Crude oil
Inventory by category
Inventory, Volumes (in barrels or in Mcf) | bbl	23,589	16,345
Linefill and base gas, Volumes (in barrels or in Mcf) | bbl	12,273	12,298
Long-term inventory, Volumes (in barrels or in Mcf) | bbl	3,279	3,417
Inventory	$ 1,049	$ 608
Linefill and base gas	710	713
Long-term inventory	$ 163	$ 106
Inventory, Price/Unit of measure (in dollars per unit) | $ / bbl	44.47	37.20
Linefill and base gas, Price/Unit of measure (in dollars per unit) | $ / bbl	57.85	57.98
Long-term inventory, Price/Unit of measure (in dollars per unit) | $ / bbl	49.71	31.02
NGL
Inventory by category
Inventory, Volumes (in barrels or in Mcf) | bbl	13,497	13,907
Linefill and base gas, Volumes (in barrels or in Mcf) | bbl	1,660	1,348
Long-term inventory, Volumes (in barrels or in Mcf) | bbl	1,418	1,652
Inventory	$ 242	$ 218
Linefill and base gas	45	44
Long-term inventory	$ 30	$ 23
Inventory, Price/Unit of measure (in dollars per unit) | $ / bbl	17.93	15.68
Linefill and base gas, Price/Unit of measure (in dollars per unit) | $ / bbl	27.11	32.64
Long-term inventory, Price/Unit of measure (in dollars per unit) | $ / bbl	21.16	13.92
Natural gas
Inventory by category
Inventory, Volumes (in barrels or in Mcf) | Mcf	14,540	22,080
Linefill and base gas, Volumes (in barrels or in Mcf) | Mcf	30,812	30,812
Inventory	$ 32	$ 53
Linefill and base gas	$ 141	$ 141
Inventory, Price/Unit of measure (in dollars per unit) | $ / Mcf	2.20	2.40
Linefill and base gas, Price/Unit of measure (in dollars per unit) | $ / Mcf	4.58	4.58
Other
Inventory by category
Inventory	$ 20	$ 37

Property and Equipment (Details

Property and Equipment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Property and Equipment
Capitalized interest	$ 47	$ 57	$ 48
Property and equipment, gross	16,220	15,654
Accumulated depreciation	(2,348)	(2,180)
Property and equipment, net	13,872	13,474
Depreciation expense	470	380	319
Costs associated with discontinuation of capital projects	33
Impairments of long-lived assets	18	0	10
Pipelines and related facilities
Property and Equipment
Property and equipment, gross	$ 9,025	8,395
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	$ 5,305	5,012
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	$ 408	392
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	$ 826	1,217
Office property and equipment
Property and Equipment
Property and equipment, gross	$ 222	196
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	$ 434	442
Property, Plant and Equipment
Property and Equipment
Capitalized interest	34	$ 49	$ 48
Rail And Other Terminal Assets | Depreciation and amortization | Facilities
Property and Equipment
Impairment loss on property, plant and equipment	$ 80

Acquisitions and Dispositions

Acquisitions and Dispositions - Acquisitions (Details) $ in Millions	Feb. 14, 2017USD ($)milemarket_interconnect	Dec. 31, 2016USD ($)acquisition	Dec. 31, 2015USD ($)acquisition	Dec. 31, 2014USD ($)acquisition
Acquisitions
Cash consideration		$ 282	$ 105	$ 1,098
Goodwill recognized			11
Individually immaterial business acquisitions
Acquisitions
Cash consideration		$ 289	$ 105	$ 1,099
Number of acquisitions completed | acquisition		2	3	3
Goodwill recognized		$ 0	$ 11	$ 1
Integrated System Of NGL Assets
Acquisitions
Cash consideration		$ 204
Subsequent Event | Alpha Holding Company, LLC
Acquisitions
Equity interests acquired	100.00%
Cash consideration	$ 1,215
Length of gathering and transmission lines | mile	515
Number of market interconnects | market_interconnect	5
Bridge Tex Pipeline Company LLC
Acquisitions
Interest acquired				50.00%
Frontier Aspen, LLC
Acquisitions
Interest acquired			28.00%

Acquisitions and Dispositions52

Acquisitions and Dispositions - Dispositions and Divestitures (Details) $ in Millions	3 Months Ended	6 Months Ended	12 Months Ended
	Mar. 31, 2017USD ($)	Jun. 30, 2017USD ($)asset	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Dispositions
Recognized gains/(losses) related to sale of assets, net				$ (2)	$ 1
Assets classified as held for sale				0
Proceeds from sales of assets			$ 654	$ 5	$ 28
Disposed of by sale | Depreciation and amortization
Dispositions
Recognized gains/(losses) related to sale of assets, net			100
Recognized gains related to sale of assets			158
Recognized losses related to sales of assets			58
Held for sale | Goodwill | Depreciation and amortization
Dispositions
Impairment losses			15
Forecast | Disposed of by sale
Dispositions
Proceeds from sales of assets	$ 70	$ 310
Number of non-core assets sold | asset		2
Other current assets | Held for sale
Dispositions
Assets classified as held for sale			$ 275

Goodwill (Details)

Goodwill (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Changes in goodwill
Balance at beginning of period	$ 2,405	$ 2,465
Acquisitions		11
Foreign currency translation adjustments	10	(71)
Dispositions and reclassifications of assets held for sale	71
Other		0
Balance at end of period	2,344	2,405
Operating Segments | Transportation
Changes in goodwill
Balance at beginning of period	815	854
Acquisitions		3
Foreign currency translation adjustments	6	(42)
Dispositions and reclassifications of assets held for sale	15
Other		0
Balance at end of period	806	815
Operating Segments | Facilities
Changes in goodwill
Balance at beginning of period	1,087	1,152
Acquisitions		8
Foreign currency translation adjustments	3	(19)
Dispositions and reclassifications of assets held for sale	56
Other		(54)
Balance at end of period	1,034	1,087
Operating Segments | Supply and Logistics
Changes in goodwill
Balance at beginning of period	503	459
Acquisitions		0
Foreign currency translation adjustments	1	(10)
Other		54
Balance at end of period	$ 504	$ 503

Investments in Unconsolidated54

Investments in Unconsolidated Entities - Equity Method Investments (Details) - USD ($) $ in Millions	1 Months Ended			12 Months Ended
	Aug. 31, 2016	Jun. 30, 2016	Nov. 30, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Investments in Unconsolidated Entities
Investments in unconsolidated entities				$ 2,343	$ 2,027	$ 1,735
Capital contributions to equity method investees excluding capitalized interest				288	245	158
Cash received as a return of investment					53
Interest expense, capitalized interest				47	57	$ 48
Amount by which investments in unconsolidated entities exceeded our share of the underlying equity in the net assets				$ 736	760
Oxy | BridgeTex Pipeline Company, LLC (BridgeTex)
Investments in Unconsolidated Entities
Interest acquired			50.00%
Payments to acquire unconsolidated entities			$ 1,088
Working capital adjustments			$ 13
BridgeTex Pipeline Company, LLC (BridgeTex)
Investments in Unconsolidated Entities
Ownership interest				50.00%
Investments in unconsolidated entities				$ 1,098	1,082
Interest acquired						50.00%
BridgeTex Pipeline Company, LLC (BridgeTex) | Oxy
Investments in Unconsolidated Entities
Interest acquired			50.00%
Total Investments in Unconsolidated Entities
Investments in Unconsolidated Entities
Ownership interest				22.00%
Investments in unconsolidated entities				$ 11	9
Caddo Pipeline LLC (Caddo)
Investments in Unconsolidated Entities
Ownership interest				50.00%
Investments in unconsolidated entities				$ 65	28
Cheyenne Pipeline LLC (Cheyenne)
Investments in Unconsolidated Entities
Ownership interest				50.00%
Investments in unconsolidated entities				$ 30	0
Ownership percentage sold		50.00%
Diamond Pipeline LLC (Diamond)
Investments in Unconsolidated Entities
Ownership interest				50.00%
Investments in unconsolidated entities				$ 143	38
Eagle Ford Pipeline LLC
Investments in Unconsolidated Entities
Ownership interest				50.00%
Investments in unconsolidated entities				$ 372	382
Eagle Ford Terminals Corpus Christi LLC (Eagle Ford Terminals)
Investments in Unconsolidated Entities
Ownership interest				50.00%
Investments in unconsolidated entities				$ 53	29
Frontier Aspen LLC
Investments in Unconsolidated Entities
Ownership interest				50.00%
Investments in unconsolidated entities				$ 45	48
Saddlehorn Pipeline Company, LLC
Investments in Unconsolidated Entities
Ownership interest				40.00%
Investments in unconsolidated entities				$ 213	103
Settoon Towing, LLC
Investments in Unconsolidated Entities
Ownership interest				50.00%
Investments in unconsolidated entities				$ 87	84
STACK Pipeline LLC (STACK)
Investments in Unconsolidated Entities
Ownership interest				50.00%
Investments in unconsolidated entities				$ 14	0
Ownership percentage sold	50.00%
White Cliffs Pipeline, LLC
Investments in Unconsolidated Entities
Ownership interest				36.00%
Investments in unconsolidated entities				$ 212	224
Equity Method Investees
Investments in Unconsolidated Entities
Interest expense, capitalized interest				$ 13	$ 8

Investments in Unconsolidated55

Investments in Unconsolidated Entities - Summarized Financial Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Combined summarized financial information for unconsolidated entities
Current assets	$ 303	$ 365
Noncurrent assets	3,558	2,901
Current liabilities	241	231
Noncurrent liabilities	162	184
Revenues	802	769	$ 531
Operating income	469	441	301
Net income	$ 452	$ 424	$ 285

Other Long-Term Assets, Net -

Other Long-Term Assets, Net - Schedule of Long-term Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Other Long-Term Assets, Net
Intangible assets	$ 603	$ 610
Fair value of derivative instruments	1	9
Other	47	94
Other long-term assets, gross	651	713
Accumulated amortization	(361)	(327)
Other long-term assets, net	290	386
Amortization expense for finite-lived intangible assets	$ 44	$ 49	$ 57

Other Long-Term Assets, Net 57

Other Long-Term Assets, Net - Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Finite-Lived Intangible Assets
Cost	$ 603	$ 610
Accumulated Amortization	(361)	(327)
Net	242	283
Estimated amortization expense related to finite-lived intangible assets for the next five years
2,017	42
2,018	37
2,019	34
2,020	32
2,021	30
Customer contracts and relationships
Finite-Lived Intangible Assets
Cost	529	537
Accumulated Amortization	(330)	(301)
Net	$ 199	236
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	(26)	(22)
Net	$ 12	16
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	$ 29	28
Accumulated Amortization	(5)	(4)
Net	$ 24	24
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	$ 7	7
Net	$ 7	$ 7

Debt - Components (Details)

Debt - Components (Details) - USD ($)	Dec. 31, 2016	Aug. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Short-term debt:
Total short-term debt	$ 1,715,000,000		$ 999,000,000
Long-term debt:
Senior notes, net of unamortized discounts and debt issuance costs	9,874,000,000		9,698,000,000
Noncurrent portion of other long-term debt	250,000,000		677,000,000
Total long-term debt	10,124,000,000		10,375,000,000
Total debt	11,839,000,000		11,374,000,000
Senior notes
Long-term debt:
Unamortized discounts and debt issuance costs	(76,000,000)		(77,000,000)
Senior notes, net of unamortized discounts and debt issuance costs	9,874,000,000		9,698,000,000
Debt instrument face value	10,300,000,000		9,800,000,000
Other
Long-term debt:
Noncurrent portion of other long-term debt	3,000,000		5,000,000
Commercial Paper
Short-term debt:
Short-term notes and borrowings	$ 563,000,000		$ 696,000,000
Weighted average interest rate, short-term (as a percent)	1.60%		1.10%
Other
Short-term debt:
Other debt, current portion	$ 2,000,000		$ 3,000,000
Level 2 | Senior notes
Long-term debt:
Debt instrument fair value	10,400,000,000		8,600,000,000
5.88% senior notes due August 2016 | Senior notes
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs			$ 175,000,000
Debt instrument, interest rate (as a percent)		5.88%	5.88%
6.13% senior notes due January 2017 | Senior notes
Short-term debt:
Senior notes, current portion	$ 400,000,000
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs			$ 400,000,000
Debt instrument, interest rate (as a percent)	6.13%		6.13%
6.50% senior notes due May 2018 | Senior notes
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 600,000,000		$ 600,000,000
Debt instrument, interest rate (as a percent)	6.50%		6.50%
8.75% senior notes due May 2019 | Senior notes
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 350,000,000		$ 350,000,000
Debt instrument, interest rate (as a percent)	8.75%		8.75%
2.60% senior notes due December 2019 | Senior notes
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 500,000,000		$ 500,000,000
Debt instrument, interest rate (as a percent)	2.60%		2.60%	2.60%
Debt instrument face value				$ 500,000,000
5.75% senior notes due January 2020 | Senior notes
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 500,000,000		$ 500,000,000
Debt instrument, interest rate (as a percent)	5.75%		5.75%
5.00% senior notes due February 2021 | Senior notes
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 600,000,000		$ 600,000,000
Debt instrument, interest rate (as a percent)	5.00%		5.00%
3.65% senior notes due June 2022 | Senior notes
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 750,000,000		$ 750,000,000
Debt instrument, interest rate (as a percent)	3.65%		3.65%
2.85% senior notes due January 2023 | Senior notes
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 400,000,000		$ 400,000,000
Debt instrument, interest rate (as a percent)	2.85%		2.85%
3.85% senior notes due October 2023 | Senior notes
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 700,000,000		$ 700,000,000
Debt instrument, interest rate (as a percent)	3.85%		3.85%
3.60% senior notes due November 2024 | Senior notes
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 750,000,000		$ 750,000,000
Debt instrument, interest rate (as a percent)	3.60%		3.60%	3.60%
Debt instrument face value				$ 750,000,000
4.65% senior notes due October 2025 | Senior notes
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 1,000,000,000		$ 1,000,000,000
Debt instrument, interest rate (as a percent)	4.65%		4.65%
Debt instrument face value			$ 1,000,000,000
4.50% senior notes due December 2026 | Senior notes
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 750,000,000		0
Debt instrument, interest rate (as a percent)	4.50%
Debt instrument face value	$ 750,000,000
6.70% senior notes due May 2036 | Senior notes
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 250,000,000		$ 250,000,000
Debt instrument, interest rate (as a percent)	6.70%		6.70%
6.65% senior notes due January 2037 | Senior notes
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 600,000,000		$ 600,000,000
Debt instrument, interest rate (as a percent)	6.65%		6.65%
5.15% senior notes due June 2042 | Senior notes
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 500,000,000		$ 500,000,000
Debt instrument, interest rate (as a percent)	5.15%		5.15%
4.30% senior notes due January 2043 | Senior notes
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 350,000,000		$ 350,000,000
Debt instrument, interest rate (as a percent)	4.30%		4.30%
4.70% senior notes due June 2044 | Senior notes
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 700,000,000		$ 700,000,000
Debt instrument, interest rate (as a percent)	4.70%		4.70%	4.70%
Debt instrument face value				$ 700,000,000
4.90% senior notes due February 2045 | Senior notes
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 650,000,000		$ 650,000,000
Debt instrument, interest rate (as a percent)	4.90%		4.90%	4.90%
Debt instrument face value				$ 650,000,000
Commercial Paper
Long-term debt:
Noncurrent portion of other long-term debt	$ 247,000,000		$ 672,000,000
Weighted average interest rate, long-term (as a percent)	1.60%		1.10%
Senior secured hedged inventory facility | Line of Credit
Short-term debt:
Short-term notes and borrowings	$ 750,000,000		$ 300,000,000
Weighted average interest rate, short-term (as a percent)	1.80%		1.40%
Exchange Traded
Short-term debt:
Total short-term debt	$ 410,000,000

Debt - Commercial Paper, Credi

Debt - Commercial Paper, Credit Facilities and Senior Notes (Details)	1 Months Ended				12 Months Ended
	Jan. 31, 2017USD ($)	Aug. 31, 2016USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Dec. 31, 2016USD ($)item	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Debt
Repayments of senior notes					$ 175,000,000	$ 549,000,000	$ 0
Commercial Paper
Debt
Maximum aggregate borrowing capacity					3,000,000,000
Senior secured hedged inventory facility
Debt
Maximum aggregate borrowing capacity					1,900,000,000
Committed borrowing capacity					$ 1,400,000,000
Basis for variable interest rate					Eurocurrency Rate or the Base Rate
Number of years by which maturity date of credit facility may be extended					1 year
Senior secured hedged inventory facility | Minimum
Debt
Credit facility extensions available | item					1
Senior secured hedged inventory facility | Letters of credit
Debt
Committed borrowing capacity					$ 400,000,000
Senior unsecured revolving credit facility
Debt
Maximum aggregate borrowing capacity					2,100,000,000
Committed borrowing capacity					$ 1,600,000,000
Basis for variable interest rate					Eurocurrency Rate, the Base Rate or the Canadian Prime Rate
Number of years by which maturity date of credit facility may be extended					1 year
Senior unsecured revolving credit facility | Minimum
Debt
Credit facility extensions available | item					1
Senior unsecured 364-day revolving credit facility
Debt
Committed borrowing capacity					$ 1,000,000,000
Basis for variable interest rate					Eurocurrency Rate or the Base Rate
Senior notes
Debt
Debt instrument face value					$ 10,300,000,000	$ 9,800,000,000
Senior notes | Consolidated finance subsidiary co-issuer
Debt
Consolidated subsidiary, ownership interest held by the parent (as a percent)					100.00%
4.50% senior notes due December 2026 | Senior notes
Debt
Debt instrument, interest rate (as a percent)					4.50%
Debt instrument face value					$ 750,000,000
4.65% senior notes due October 2025 | Senior notes
Debt
Debt instrument, interest rate (as a percent)					4.65%	4.65%
Public offering price (as a percent)						99.846%
Debt instrument face value						$ 1,000,000,000
2.60% senior notes due December 2019 | Senior notes
Debt
Debt instrument, interest rate (as a percent)					2.60%	2.60%	2.60%
Public offering price (as a percent)							99.813%
Debt instrument face value							$ 500,000,000
4.90% senior notes due February 2045 | Senior notes
Debt
Debt instrument, interest rate (as a percent)					4.90%	4.90%	4.90%
Public offering price (as a percent)							99.876%
Debt instrument face value							$ 650,000,000
3.60% senior notes due November 2024 | Senior notes
Debt
Debt instrument, interest rate (as a percent)					3.60%	3.60%	3.60%
Public offering price (as a percent)							99.842%
Debt instrument face value							$ 750,000,000
4.70% senior notes due June 2044 | Senior notes
Debt
Debt instrument, interest rate (as a percent)					4.70%	4.70%	4.70%
Public offering price (as a percent)							99.734%
Debt instrument face value							$ 700,000,000
5.88% senior notes due August 2016 | Senior notes
Debt
Repayments of senior notes		$ 175,000,000
Debt instrument, interest rate (as a percent)		5.88%				5.88%
6.13% senior notes due January 2017 | Senior notes
Debt
Debt instrument, interest rate (as a percent)					6.13%	6.13%
5.25% senior notes due June 2015 | Senior notes
Debt
Repayments of senior notes				$ 150,000,000
Debt instrument, interest rate (as a percent)				5.25%
3.95% senior notes due September 2015 | Senior notes
Debt
Repayments of senior notes			$ 400,000,000
Debt instrument, interest rate (as a percent)			3.95%
Non-extending Lender | Senior secured hedged inventory facility
Debt
Committed borrowing capacity					$ 126,300,000
Non-extending Lender | Senior unsecured revolving credit facility
Debt
Committed borrowing capacity					$ 140,000,000
Subsequent Event | 6.13% senior notes due January 2017 | Senior notes
Debt
Repayments of senior notes	$ 400,000,000
Debt instrument, interest rate (as a percent)	6.13%

Debt - Maturities and Covenant

Debt - Maturities and Covenants (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Debt
Weighted-average maturity of long-term debt	11 years
Maturities
2,017	$ 247
2,018	600
2,019	850
2,020	500
2,021	600
Thereafter	$ 7,403
Acquisition Period	9 months
Credit agreements and commercial paper program
Maturities
Total borrowings	$ 60,300	$ 62,200	$ 70,900
Total repayments	$ 61,000	61,300	$ 71,300
Credit agreements
Maturities
Coverage ratio of debt-to-EBITDA, maximum	5
Ratio of debt-to-EBITDA during acquisition period, maximum	5.50
Threshold for acquisition period qualification	$ 150
Debt covenant compliance	As of December 31, 2016, we were in compliance with the covenants contained in our credit agreements and indentures.
Letters of credit
Maturities
Outstanding letters of credit	$ 73	$ 46
Letters of credit | Maximum
Maturities
Periods for which letters of credit are issued	70 days

Partners' Capital and Distrib61

Partners' Capital and Distributions - Activity for Series A Preferred Units and Common Units (Details) - shares	10 Months Ended	12 Months Ended
	Nov. 14, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Partners Capital and Distributions
Limited partner interest	98.00%
General partner ownership interest	2.00%
Sale of units (in units)		26,278,288	22,133,904
Series A Preferred Units
Partners Capital and Distributions
Balance, beginning of period (in units)	0	0	0	0
Sale of units (in units)		61,030,127
Issuance of Series A preferred units in connection with in-kind distributions (in units)		3,358,726
Balance, end of period (in units)		64,388,853	0	0
Common Units
Partners Capital and Distributions
Balance, beginning of period (in units)	397,727,624	397,727,624	375,107,793	359,133,200
Sale of units (in units)		26,278,288	22,133,904	15,375,810
Issuance of common units under LTIP (in units)		480,581	485,927	598,783
Issuance of common units in connection with Simplification Transactions (in units)		244,707,926
Balance, end of period (in units)		669,194,419	397,727,624	375,107,793

Partners' Capital and Distrib62

Partners' Capital and Distributions - Distributions Paid (Details) - USD ($) $ / shares in Units, $ in Millions	Feb. 14, 2017	Jan. 09, 2017	Nov. 14, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Partners Capital and Distributions
Percentage of available cash distributed				100.00%
Number of days after end of quarter within which distributions must be paid to unitholders				45 days
Total distributions paid during the period				$ 1,631	$ 1,674	$ 1,410
Distributions per common unit (in dollars per unit)				$ 2.65	$ 2.76	$ 2.55
Reduction in incentive distributions				$ 18	$ 22	$ 23
Cash distributions paid				1,062	1,081	934
Subsequent Event | Fourth quarter distribution
Partners Capital and Distributions
Distribution declared, date		Jan. 9, 2017
Distribution per common unit declared (in dollars per unit)		$ 0.55
Cash distributions paid	$ 371
Distribution paid, date	Feb. 14, 2017
Unitholders of record, date	Jan. 31, 2017
Partners' Capital Excluding Noncontrolling Interests
Partners Capital and Distributions
Total distributions paid during the period				1,627	1,671	1,407
General Partner Distribution - Level One
Partners Capital and Distributions
Percent of distribution amount to the general partner before incentive distributions			2.00%
General Partner Distribution - Level Two
Partners Capital and Distributions
Quarterly incentive distribution threshold amount (in dollars per unit)			$ 0.2250
Percent of distribution amount to the general partner above threshold			15.00%
General Partner Distribution - Level Three
Partners Capital and Distributions
Quarterly incentive distribution threshold amount (in dollars per unit)			$ 0.2475
Percent of distribution amount to the general partner above threshold			25.00%
General Partner Distribution - Level Four
Partners Capital and Distributions
Quarterly incentive distribution threshold amount (in dollars per unit)			$ 0.3375
Percent of distribution amount to the general partner above threshold			50.00%
Unit Distribution | Series A Preferred Units
Partners Capital and Distributions
Distributions paid to Common Unitholders				$ 89
Unit distributions paid (in units)				3,358,726
Unit Distribution | Series A Preferred Units | Subsequent Event
Partners Capital and Distributions
Distributions paid to Common Unitholders	$ 34
Unit distributions paid (in units)	1,287,773
Cash Distribution
Partners Capital and Distributions
Distributions paid to General Partner				$ 565	590	473
Total distributions paid during the period				1,627	1,671	1,407
Cash Distribution | Common Units
Partners Capital and Distributions
Distributions paid to Common Unitholders				$ 1,062	$ 1,081	$ 934

Partners' Capital and Distrib63

Partners' Capital and Distributions - Equity Offerings (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Partners Capital and Distributions
Issuance of units (in units)	26,278,288	22,133,904
Issuance of units, net proceeds	$ 805	$ 1,121
General partners' proportionate capital contributions	42	23	$ 18
Continuous and Underwritten Offerings | General Partner
Partners Capital and Distributions
General partners' proportionate capital contributions	9	$ 22	$ 18
Continuous Offering Program
Partners Capital and Distributions
Issuance of units (in units)		1,133,904	15,375,810
Issuance of units, net proceeds		$ 59	$ 866
Commissions to sales agents	$ 8	$ 1	$ 9
Underwritten Offering
Partners Capital and Distributions
Issuance of units (in units)		21,000,000
Issuance of units, net proceeds		$ 1,062

Partners' Capital and Distrib64

Partners' Capital and Distributions - Preferred Unit Issuance (Details) $ / shares in Units, shares in Millions, $ in Millions	Jan. 28, 2016USD ($)item$ / sharesshares	Dec. 31, 2016USD ($)
Partners Capital and Distributions
Net proceeds from private placement | $		$ 1,542
Series A Convertible Preferred Units
Partners Capital and Distributions
Private placement of units (in units) | shares	61
Cash purchase price (in dollars per unit)	$ 26.25
Transaction fee due to purchasers	2.00%
Net proceeds from private placement | $	$ 1,600
Quarterly distributions per unit (in dollars per unit)	$ 0.525
Annualized distribution rate (in dollars per unit)	$ 2.10
Preferred unit conversion ratio	1
Common unit closing price as a percentage of Issue Price, over which the entity has conversion option	150.00%
Period for closing price of common units to be above threshold, to trigger conversion option	20 days
Period after fifth and subsequent anniversaries of issuance for Distribution Rate Resets	30 days
Number of distribution rate reset elections allowed | item	1
Period after sixth anniversary of issuance, after which units may be redeemed if distribution rate has been reset	30 days
Value of common units if exchanged for redemption of preferred units, as a percentage of average price	95.00%
Redemption price as a percentage of Issue Price	110.00%
US Treasury Rate | Series A Convertible Preferred Units
Partners Capital and Distributions
Basis spread on variable rate	5.85%

Partners' Capital and Distrib65

Partners' Capital and Distributions - Income Allocation (Details)	Dec. 31, 2016
Related Party Transactions
Net income allocation	100.00%

Partners' Capital and Distrib66

Partners' Capital and Distributions - Noncontrolling Interests in Subsidiaries (Details)	Dec. 31, 2016
SLC Pipeline LLC
Partners Capital and Distributions
Noncontrolling interests in subsidiaries	25.00%

Derivatives and Risk Manageme67

Derivatives and Risk Management Activities - Commodity Price Risk Hedging (Details) bbl in Millions, MWh in Millions, Mcf in Billions	12 Months Ended
	Dec. 31, 2016MWhbblMcf
Net long position associated with crude oil purchases
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	3.6
Net short time spread position hedging anticipated crude oil lease gathering purchases
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	5.2
Crude oil grade spread positions
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	43.8
Net short position related to anticipated sales of natural gas inventory and base gas requirements
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf) | Mcf	12.2
Net short position related to anticipated net sales of crude oil and NGL inventory
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	34.5
PLA crude oil long call option position
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	0.9
Long natural gas position for natural gas purchases
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf) | Mcf	61.3
Short propane position related to subsequent sale of products
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	10.6
Short butane position related to subsequent sale of products
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	3.2
Short WTI position related to subsequent sale of products
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	1.5
Long power position for power supply requirements
Commodity Price Risk Hedging:
Derivative position notional amount (in megawatt hours) | MWh	0.3

Derivatives and Risk Manageme68

Derivatives and Risk Management Activities - Currency Exchange Rate Risk Hedging (Details) CAD in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)contractCAD / $	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2016CADcontractCAD / $
Currency Exchange Rate Risk Hedging:
Net derivative liability	$ 131	$ 72
Gain on embedded derivative	30	$ 0	$ 0
Forward exchange contracts that exchange CAD for USD at the rate USD 1.00 to CAD 1.38 maturing in 2016
Currency Exchange Rate Risk Hedging:
Notional amount of derivatives	$ 274			CAD 363
Average exchange rate | CAD / $	1.33			1.33
Forward exchange contracts that exchange USD for CAD at the rate USD 1.00 to CAD 1.33 maturing in 2016
Currency Exchange Rate Risk Hedging:
Notional amount of derivatives	$ 492			CAD 652
Average exchange rate | CAD / $	1.33			1.33
Series A Preferred Units | Embedded derivative financial instruments
Currency Exchange Rate Risk Hedging:
Net derivative liability	$ 32
Gain on embedded derivative	$ 30
Cash Flow Hedging | 8 Forward Starting 30 Year Interest Rate Swap One
Currency Exchange Rate Risk Hedging:
Number of interest rate derivatives held | contract	8			8
Notional amount of derivatives	$ 200
Average Rate Locked	3.14%			3.14%
Cash Flow Hedging | 8 Forward Starting 30 Year Interest Rate Swap Two
Currency Exchange Rate Risk Hedging:
Number of interest rate derivatives held | contract	8			8
Notional amount of derivatives	$ 200
Average Rate Locked	3.20%			3.20%
Cash Flow Hedging | 8 Forward Starting 30 Year Interest Rate Swap Three
Currency Exchange Rate Risk Hedging:
Number of interest rate derivatives held | contract	8			8
Notional amount of derivatives	$ 200
Average Rate Locked	2.83%			2.83%

Derivatives and Risk Manageme69

Derivatives and Risk Management Activities - Financial Impact (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income	$ (324)	$ 156	$ 153
Loss on cash flow hedge ineffectiveness	4	0	0
Commodity Derivatives | Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income	(342)	208	205
Commodity Derivatives | Transportation segment revenues
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income	5	8
Commodity Derivatives | Field operating costs
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income		(18)	(21)
Interest Rate Derivatives | Interest expense
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income	(14)	(11)	(5)
Foreign Currency Derivatives | Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income	(3)	(31)	(28)
Foreign Currency Derivatives | Other income/(expense), net
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income			2
Preferred Distribution Rate Reset Option | Other income/(expense), net
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income	30
Derivatives in Hedging Relationships
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income	(12)	45	(4)
Derivatives in Hedging Relationships | Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Loss on discontinuation of cash flow hedge due to forecasted transaction probable of not occurring, net	2
Derivatives in Hedging Relationships | Interest expense
Impact of derivative activities recognized in earnings
Loss on discontinuation of cash flow hedge due to forecasted transaction probable of not occurring, net	2	4
Derivatives in Hedging Relationships | Commodity Derivatives | Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income	2	56	(1)
Derivatives in Hedging Relationships | Interest Rate Derivatives | Interest expense
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income	(14)	(11)	(5)
Derivatives in Hedging Relationships | Foreign Currency Derivatives | Other income/(expense), net
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income			2
Derivatives Not Designated as a Hedge
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income	(312)	111	157
Derivatives Not Designated as a Hedge | Commodity Derivatives | Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income	(344)	152	206
Derivatives Not Designated as a Hedge | Commodity Derivatives | Transportation segment revenues
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income	5	8
Derivatives Not Designated as a Hedge | Commodity Derivatives | Field operating costs
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income		(18)	(21)
Derivatives Not Designated as a Hedge | Foreign Currency Derivatives | Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income	(3)	$ (31)	$ (28)
Derivatives Not Designated as a Hedge | Preferred Distribution Rate Reset Option | Other income/(expense), net
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income	$ 30

Derivatives and Risk Manageme70

Derivatives and Risk Management Activities - Assets and Liabilities (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)contract	Dec. 31, 2015USD ($)contract	Dec. 31, 2014USD ($)
Derivative assets and liabilities
Asset derivatives fair value	$ 108	$ 280
Liability derivatives fair value	(481)	(110)
Initial margin	119	91
Variation margin increase (decrease)	291	(247)
Net broker receivable	410
Net broker payable		(156)
Net loss deferred in AOCI	228
Net loss expected to be reclassified to earnings in the next twelve months	8
Remaining loss expected to be reclassified to earnings through 2049	220
Net deferred gain/(loss) recognized in AOCI on derivatives	$ (33)	$ 1	$ (86)
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
Derivative assets and liabilities
Net deferred gain/(loss) recognized in AOCI on derivatives	$ 0	$ 33	15
Interest Rate Derivatives
Derivative assets and liabilities
Net deferred gain/(loss) recognized in AOCI on derivatives	(33)	(32)	(103)
Foreign Currency Derivatives
Derivative assets and liabilities
Net deferred gain/(loss) recognized in AOCI on derivatives			$ 2
Derivatives in Hedging Relationships
Derivative assets and liabilities
Asset derivatives fair value	0	5
Liability derivatives fair value	(50)	(52)
Derivatives in Hedging Relationships | Commodity Derivatives | Other current assets
Derivative assets and liabilities
Asset derivatives fair value		4
Liability derivatives fair value	0	(2)
Derivatives in Hedging Relationships | Interest Rate Derivatives | Other long-term assets, net
Derivative assets and liabilities
Asset derivatives fair value		1
Derivatives in Hedging Relationships | Interest Rate Derivatives | Other current liabilities
Derivative assets and liabilities
Liability derivatives fair value	(23)	(17)
Derivatives in Hedging Relationships | Interest Rate Derivatives | Other long-term liabilities and deferred credits
Derivative assets and liabilities
Liability derivatives fair value	(27)	(33)
Derivatives Not Designated as a Hedge
Derivative assets and liabilities
Asset derivatives fair value	108	275
Liability derivatives fair value	(431)	(58)
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other current assets
Derivative assets and liabilities
Asset derivatives fair value	101	265
Liability derivatives fair value	(344)	(35)
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other long-term assets, net
Derivative assets and liabilities
Asset derivatives fair value	2	10
Liability derivatives fair value	(1)	(1)
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other current liabilities
Derivative assets and liabilities
Liability derivatives fair value	(14)	(13)
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other long-term liabilities and deferred credits
Derivative assets and liabilities
Asset derivatives fair value	2
Liability derivatives fair value	(34)	(1)
Derivatives Not Designated as a Hedge | Foreign Currency Derivatives | Other current liabilities
Derivative assets and liabilities
Asset derivatives fair value	3
Liability derivatives fair value	(6)	$ (8)
Derivatives Not Designated as a Hedge | Preferred Distribution Rate Reset Option | Other long-term liabilities and deferred credits
Derivative assets and liabilities
Liability derivatives fair value	$ (32)

Derivatives and Risk Manageme71

Derivatives and Risk Management Activities - Offsetting (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Derivative Asset Positions
Gross Position - Asset	$ 108	$ 280
Netting Adjustment	(350)	(38)
Cash collateral paid	410
Cash collateral received		(156)
Net Position - Asset	168	86
Derivative Liability Positions
Gross Position - Liability	(481)	(110)
Netting Adjustment	350	38
Net Position - Liability	(131)	(72)
Other current assets
Derivative Asset Positions
Net Position - Asset	167	76
Other long-term assets, net
Derivative Asset Positions
Net Position - Asset	1	10
Other current liabilities
Derivative Liability Positions
Net Position - Liability	(40)	(38)
Other long-term liabilities and deferred credits
Derivative Liability Positions
Net Position - Liability	$ (91)	$ (34)

Derivatives and Risk Manageme72

Derivatives and Risk Management Activities - Fair Value (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Level 3
Rollforward of Level 3 Net Asset/(Liability)
Beginning Balance	$ 11	$ 15
Net gains for the period included in earnings	28	1
Settlements	(10)	(14)
Derivatives entered into during the period	(65)	9
Ending Balance	(36)	11
Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period	(36)	10
Recurring Fair Value Measures
Recurring Fair Value Measurements
Net derivative asset/(liability)	(373)	170
Recurring Fair Value Measures | Commodity Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)	(288)	227
Recurring Fair Value Measures | Interest Rate Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)	(50)	(49)
Recurring Fair Value Measures | Foreign Currency Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)	(3)	(8)
Recurring Fair Value Measures | Preferred Distribution Rate Reset Option
Recurring Fair Value Measurements
Net derivative asset/(liability)	(32)
Recurring Fair Value Measures | Level 1
Recurring Fair Value Measurements
Net derivative asset/(liability)	(113)	126
Recurring Fair Value Measures | Level 1 | Commodity Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)	(113)	126
Recurring Fair Value Measures | Level 2
Recurring Fair Value Measurements
Net derivative asset/(liability)	(224)	33
Recurring Fair Value Measures | Level 2 | Commodity Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)	(171)	90
Recurring Fair Value Measures | Level 2 | Interest Rate Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)	(50)	(49)
Recurring Fair Value Measures | Level 2 | Foreign Currency Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)	(3)	(8)
Recurring Fair Value Measures | Level 3
Recurring Fair Value Measurements
Net derivative asset/(liability)	(36)	11
Recurring Fair Value Measures | Level 3 | Commodity Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)	(4)	$ 11
Recurring Fair Value Measures | Level 3 | Preferred Distribution Rate Reset Option
Recurring Fair Value Measurements
Net derivative asset/(liability)	$ (32)

Income Taxes - Components (Det

Income Taxes - Components (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current income tax expense:
State income tax	$ 2	$ 1	$ 1
Canadian federal and provincial income tax	83	83	70
Total current income tax expense	85	84	71
Deferred income tax expense/(benefit):
Canadian federal and provincial income tax	(60)	16	100
Total deferred income tax expense/(benefit)	(60)	16	100
Total income tax expense	$ 25	$ 100	$ 171

Income Taxes - Reconciliation

Income Taxes - Reconciliation and Deferred Tax Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Examination [Line Items]
Income before tax	$ 755	$ 1,006	$ 1,557
Partnership earnings not subject to current Canadian tax	(723)	(773)	(976)
Partnership earnings subject to current Canadian tax	$ 32	$ 233	$ 581
Canadian federal and provincial corporate tax rate	27.00%	26.00%	25.00%
Income tax at statutory rate	$ 8	$ 61	$ 145
Canadian withholding tax	13	14	16
Canadian permanent differences and rate changes	2	24	9
State income tax	2	1	1
Total income tax expense	25	100	$ 171
Deferred tax assets:
Derivative instruments	49
Book accruals in excess of current tax deductions	24	20
Net operating losses	4	3
Total deferred tax assets	77	23
Deferred tax liabilities:
Derivative instruments		(30)
Property and equipment in excess of tax values	(394)	(312)
Other	(41)	(41)
Total deferred tax liabilities	(435)	(383)
Net deferred tax liabilities	(358)	(360)
Other long-term assets, net
Deferred tax liabilities:
Net deferred tax assets	4	3
Other long-term liabilities and deferred credits
Deferred tax liabilities:
Net deferred tax liabilities	$ (362)	$ (363)

Income Taxes - Operating Loss

Income Taxes - Operating Loss Carryforwards (Details) $ in Millions	Dec. 31, 2016USD ($)
Foreign
Operating Loss Carryforwards
Net operating loss carryforwards	$ 15

Major Customers and Concentra76

Major Customers and Concentration of Credit Risk (Details) - Revenues - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Marathon Petroleum Corporation
Major Customers and Concentration of Credit Risk
Major customer percentage of total revenue	18.00%	17.00%	17.00%
ExxonMobil Corporation
Major Customers and Concentration of Credit Risk
Major customer percentage of total revenue	14.00%	13.00%	15.00%
Phillips 66
Major Customers and Concentration of Credit Risk
Major customer percentage of total revenue	11.00%

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions	Dec. 31, 2016	Nov. 30, 2014	Nov. 14, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Related Party Transactions
Limited partner interest			98.00%
BridgeTex Pipeline Company, LLC (BridgeTex)
Related Party Transactions
Interest acquired						50.00%
Ownership interest	50.00%			50.00%
BridgeTex Pipeline Company, LLC (BridgeTex) | Oxy
Related Party Transactions
Interest acquired		50.00%
General Partner
Related Party Transactions
Costs reimbursed to general partner				$ 514	$ 648	$ 598
Oxy
Related Party Transactions
Revenues				655	866	1,212
Purchases and related costs				42	41	925
Trade accounts receivable and other receivables	$ 789			789	405
Accounts payable	836			836	363
Equity Method Investees
Related Party Transactions
Revenues				14	17	3
Costs related to services utilized				209	164	$ 75
Trade accounts receivable and other receivables	39			39	14
Prepaid tariff costs	14			14
Accounts payable	$ 35			$ 35	$ 25
Equity Method Investees | Agreement to Transport Crude Oil
Related Party Transactions
Ownership interest	50.00%			50.00%
Shares Class C | PAGP
Related Party Transactions
Class C shares of PAGP held by PAA	491,910,863
Omnibus Agreement
Related Party Transactions
Expenses paid on behalf of affiliates				$ 4
AAP | PAGP
Related Party Transactions
Limited partner interest				42.00%
AAP | Oxy
Related Party Transactions
Limited partner interest	13.00%

Equity-Indexed Compensation P78

Equity-Indexed Compensation Plans - Plan Information (Details) - $ / shares shares in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
PAA LTIP
Equity-Indexed Compensation Plans
Units outstanding (in units)		8.9	6.9	7.3	8.4
Estimated unit vesting in 2017 (in units)		1.7
Estimated unit vesting in 2018 (in units)		2.1
Estimated unit vesting in 2019 (in units)		2
Estimated unit vesting in 2020 (in units)		1.3
Estimated unit vesting thereafter (in units)		1.8
Estimated unit vesting, Total (in units)		8.9
Units outstanding that include DERs (in units)		4.3
DERs currently vested (in units)		1.6
Annualized distribution probable of occurring (in dollars per unit)		$ 2.2
Modified in period (in units)	2.2
Vested in period (in units)	0.9
Annualized distribution level required for vesting	$ 2.80
PAA LTIP | Minimum
Equity-Indexed Compensation Plans
Annualized distribution level required for vesting	2.30	2.20
PAA LTIP | Maximum
Equity-Indexed Compensation Plans
Annualized distribution level required for vesting	$ 2.80	$ 2.65
PAA 2013 LTIP
Equity-Indexed Compensation Plans
Authorized grants (in units)		10.1
PNG Successor LTIP
Equity-Indexed Compensation Plans
Authorized grants (in units)		1.3
2006 Plan
Equity-Indexed Compensation Plans
Authorized grants (in units)		10.8

Equity-Indexed Compensation P79

Equity-Indexed Compensation Plans - Liability and Activity (Details) - PAA LTIP - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Equity-Indexed Compensation Plans
Annualized distribution probable of occurring (in dollars per unit)		$ 2.2
Outstanding (in units)
Outstanding at beginning of period (in units)		6.9	7.3	8.4
Granted (in units)		4.5	2.1	1.2
Vested (in units)		(1.9)	(2.1)	(1.9)
Modified (in units)	2.2
Cancelled or forfeited (in units)		(0.6)	(0.4)	(0.4)
Outstanding at end of period (in units)		8.9	6.9	7.3
Weighted Average Grant Date Fair Value per Unit
Outstanding at beginning of period (in dollars per unit)		$ 41.23	$ 41.45	$ 36.97
Granted (in dollars per unit)		23.38	28.76	47.68
Vested (in dollars per unit)		45.91	28.91	25.49
Modified (in dollars per unit)		(8.21)
Cancelled or forfeited (in dollars per unit)		37.19	44.56	40.14
Outstanding at end of period (in dollars per unit)		$ 29.62	$ 41.23	$ 41.45
Units issued in connection with the settlement of vested awards, net of tax withholding (in units)		0.5	0.5	0.6
Units withheld for taxes (in units)		0.3	0.3	0.3
Vested awards settled in cash (in units)		1.1	1.3	1
Liability Awards
Equity-Indexed Compensation Plans
Accrued liability related to all outstanding LTIP awards and DERs		$ 38	$ 33
Short-term accrued liability related to all outstanding LTIP awards and DERs		25	20
Long-term accrued liability related to all outstanding LTIP awards and DERs		$ 13	$ 13
Annualized distribution probable of occurring (in dollars per unit)	$ 2.2

Equity-Indexed Compensation P80

Equity-Indexed Compensation Plans - AAP Management Units (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended	12 Months Ended			113 Months Ended
	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2016
Grant Date Fair Value of Outstanding AAP Management Units
Equity-indexed compensation expense		$ 60	$ 27	$ 98
AAP Management Units
Equity-Indexed Compensation Plans
Modified in period (in units)	800,000
Number of units available for grant (in units)		0			0
Unearned units		800,000			800,000
Outstanding
Outstanding, beginning balance (in units)		19,000,000	18,400,000
Granted (in units)			600,000
Converted (in units)		(15,600,000)
Outstanding, ending balance (in units)		3,400,000	19,000,000	18,400,000	3,400,000
Outstanding Units Earned
Outstanding Units Earned, beginning balance (in units)		18,200,000	17,900,000
Earned (in units)			300,000
Converted (in units)		(15,600,000)
Outstanding Units Earned, ending balance (in units)		2,600,000	18,200,000	17,900,000	2,600,000
Grant Date Fair Value of Outstanding AAP Management Units
Grant Date Fair Value of Outstanding AAP Management Units, beginning balance		$ 88	$ 64
Granted			24
Modified		(17)
Converted		(36)
Grant Date Fair Value of Outstanding AAP Management Units, ending balance		35	88	$ 64	$ 35
Equity-indexed compensation expense		$ 2	$ 1	$ 7	$ 22
AAP Management Units | Minimum
Equity-Indexed Compensation Plans
Annualized distribution level required for units to become earned (in dollars per unit)	$ 2.20
AAP Management Units | Maximum
Equity-Indexed Compensation Plans
Annualized distribution level required for units to become earned (in dollars per unit)	$ 2.40
Conversion Of Aap Management Units Into Aap Units
Equity-Indexed Compensation Plans
Unit conversion ratio		0.941			0.941
AAP | AAP Management Units
Equity-Indexed Compensation Plans
Equivalent distribution entitled to be received when earned (as a percent)		94.10%			94.10%
AAP
Equity-Indexed Compensation Plans
Units To Be Issued		0.941			0.941

Equity-Indexed Compensation P81

Equity-Indexed Compensation Plans - Compensation Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Other Consolidated Equity-Indexed Compensation Plan Information
Equity-indexed compensation expense	$ 60	$ 27	$ 98
LTIP unit-settled vestings	24	37	53
LTIP cash-settled vestings	28	66	53
DER cash payments	6	$ 8	$ 8
Equity-Indexed Compensation Plan Fair Value Amortization
2,017	65
2,018	42
2,019	19
2,020	7
2,021	2
Total	$ 135

Commitments and Contingencies

Commitments and Contingencies - Commitments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Leases and rights-of-way easements
2,017	$ 195
2,018	165
2,019	140
2,020	118
2,021	97
Thereafter	404
Total	1,119
Lease expense	198	$ 164	$ 145
Other commitments
2,017	257
2,018	166
2,019	153
2,020	132
2,021	128
Thereafter	378
Total	1,214
Total
2,017	452
2,018	331
2,019	293
2,020	250
2,021	225
Thereafter	782
Total	2,333
Agreement to Transport Crude Oil | Equity Method Investees
Other commitments
Total	$ 855
Ownership interest	50.00%

Commitments and Contingencies83

Commitments and Contingencies - Legal, Environmental or Regulatory (Details)	May 16, 2016itememployee	Jan. 06, 2016USD ($)itembbl	May 31, 2015bbl	Dec. 31, 2015USD ($)lawsuit	Dec. 31, 2016USD ($)	Dec. 31, 2016USD ($)lawsuit	Apr. 30, 2015item
Legal, Environmental or Regulatory Matters
Estimated undiscounted reserve for environmental liabilities				$ 185,000,000	$ 147,000,000	$ 147,000,000
Estimated undiscounted reserve for environmental liabilities, short-term				81,000,000	61,000,000	61,000,000
Estimated undiscounted reserve for environmental liabilities, long-term				104,000,000	86,000,000	86,000,000
Amounts probable of recovery under insurance and from third parties under indemnification agreements				$ 161,000,000	56,000,000	56,000,000
Line 901 Incident
Legal, Environmental or Regulatory Matters
Estimated undiscounted reserve for environmental liabilities					75,000,000	75,000,000
Amounts probable of recovery under insurance and from third parties under indemnification agreements					49,000,000	49,000,000
Fines or penalties assessed					0	0
Aggregate total estimated costs					280,000,000	280,000,000
Recoveries from insurance carriers					148,000,000
Total release costs probable of recovery					197,000,000	$ 197,000,000
Line 901 Incident | Maximum
Legal, Environmental or Regulatory Matters
Estimated size of release (in barrels) | bbl			2,935
Line 901 Incident | Indictment In California Superior Court Santa Barbara County [Member]
Legal, Environmental or Regulatory Matters
Number of employees charged in indictment | employee	1
Total number of counts | item	46
Number of misdemeanor charges relating to wildlife | item	36
Number of counts related to the release of crude oil or reporting of the release | item	10
Number of felony charges | item	4
Number of misdemeanor charges related to the release of crude oil or reporting of the release | item	6
Line 901 Incident | Class Action Lawsuits
Legal, Environmental or Regulatory Matters
Number of cases filed during the period | lawsuit						9
Number of cases administratively consolidated into a single proceeding | lawsuit						6
Line 901 Incident | Securities Law Class Action Lawsuits
Legal, Environmental or Regulatory Matters
Number of cases filed during the period | lawsuit				2
Line 901 Incident | Unitholder Derivative Lawsuits
Legal, Environmental or Regulatory Matters
Number of cases filed during the period | lawsuit						4
Claims not consolidated | lawsuit						2
Line 901 Incident | Compliance with Regulations and Other Matters
Legal, Environmental or Regulatory Matters
Number of cases filed during the period | lawsuit						2
In the Matter of Bakersfield Crude Terminal LLC et al
Legal, Environmental or Regulatory Matters
Fines or penalties assessed					0	$ 0
Number of alleged rule violations | item							10
Mesa to Basin Pipeline
Legal, Environmental or Regulatory Matters
Estimated size of release (in barrels) | bbl		500
Mesa to Basin Pipeline | PHMSA
Legal, Environmental or Regulatory Matters
Number of occasions of alleged failure to carry out damage prevention program and other procedures | item		4
Fines or penalties recommended		$ 190,000
Trade Accounts Receivable And Other Receivables
Legal, Environmental or Regulatory Matters
Amounts probable of recovery under insurance and from third parties under indemnification agreements				$ 138,000,000	39,000,000	39,000,000
Trade Accounts Receivable And Other Receivables | Line 901 Incident
Legal, Environmental or Regulatory Matters
Amounts probable of recovery under insurance and from third parties under indemnification agreements					34,000,000	34,000,000
Other long-term assets, net
Legal, Environmental or Regulatory Matters
Amounts probable of recovery under insurance and from third parties under indemnification agreements				$ 23,000,000	17,000,000	17,000,000
Accounts Payable and Accrued Liabilities | Line 901 Incident
Legal, Environmental or Regulatory Matters
Estimated undiscounted reserve for environmental liabilities					$ 50,000,000	$ 50,000,000
United States | Line 901 Incident | Unitholder Derivative Lawsuits
Legal, Environmental or Regulatory Matters
Number of cases filed during the period | lawsuit						2

Quarterly Financial Data (Una84

Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Total revenues	$ 5,952	$ 5,170	$ 4,950	$ 4,111	$ 4,996	$ 5,551	$ 6,663	$ 5,942	$ 20,182	$ 23,152	$ 43,464
Gross margin	286	419	219	349	405	395	290	450	1,273	1,540
Operating income	218	349	146	282	344	335	211	372	994	1,262	1,799
Net income	127	298	102	203	248	250	124	284	730	906	1,386
Net income attributable to PAA	$ 126	$ 297	$ 101	$ 202	$ 247	$ 249	$ 124	$ 283	$ 726	$ 903	$ 1,384
Basic net income/(loss) per common unit (in dollars per unit)	$ 0.14	$ 0.40	$ (0.20)	$ 0.07	$ 0.24	$ 0.25	$ (0.06)	$ 0.36	$ 0.43	$ 0.78
Diluted net income/(loss) per common unit (in dollars per unit)	0.14	0.40	(0.20)	0.07	0.24	0.24	(0.06)	0.35	0.43	0.77
Cash distributions per common unit (in dollars per unit)	$ 0.55	$ 0.7	$ 0.7	$ 0.7	$ 0.7	$ 0.70	$ 0.69	$ 0.68	$ 2.65	$ 2.76

Operating Segments - Segment F

Operating Segments - Segment Financial Data (Details) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016USD ($)	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2016USD ($)segment	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Operating Segments
Operating segments number | segment									3
Revenues:
Total revenues	$ 5,952	$ 5,170	$ 4,950	$ 4,111	$ 4,996	$ 5,551	$ 6,663	$ 5,942	$ 20,182	$ 23,152	$ 43,464
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Equity earnings in unconsolidated entities									195	183	108
Segment adjusted EBITDA									2,167	2,212	2,227
Capital expenditures									1,694	2,275	3,125
Maintenance capital									186	220	224
Total assets	24,210				22,288				24,210	22,288	22,198
Investments in unconsolidated entities	2,343				2,027				2,343	2,027	1,735
Transportation
Revenues:
Total revenues									954	953	994
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Equity earnings in unconsolidated entities									195	183	108
Segment adjusted EBITDA									1,141	1,056	979
Capital expenditures									1,063	1,278	2,483
Maintenance capital									121	144	165
Total assets	10,917				10,345				10,917	10,345	9,579
Investments in unconsolidated entities	2,290				1,998				2,290	1,998	1,735
Facilities
Revenues:
Total revenues									546	528	576
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Segment adjusted EBITDA									667	588	597
Capital expenditures									577	813	582
Maintenance capital									55	68	52
Total assets	7,556				7,330				7,556	7,330	6,843
Investments in unconsolidated entities	53				29				53	29
Supply and Logistics
Revenues:
Total revenues									19,004	21,927	42,114
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Segment adjusted EBITDA									359	568	651
Capital expenditures									54	184	60
Maintenance capital									10	8	7
Total assets	$ 5,737				$ 4,613				5,737	4,613	5,776
Operating Segments
Revenues:
Total revenues									21,709	24,589	44,932
Operating Segments | Transportation
Revenues:
Total revenues									1,584	1,594	1,655
Operating Segments | Facilities
Revenues:
Total revenues									1,107	1,050	1,127
Operating Segments | Supply and Logistics
Revenues:
Total revenues									19,018	21,945	42,150
Intersegment
Revenues:
Total revenues									1,527	1,437	1,468
Intersegment | Transportation
Revenues:
Total revenues									630	641	661
Intersegment | Facilities
Revenues:
Total revenues									561	522	551
Intersegment | Supply and Logistics
Revenues:
Total revenues									14	18	36
Intersegment Adjustment
Revenues:
Total revenues									$ 322	$ 256	$ 220

Operating Segments - Reconcili

Operating Segments - Reconciliation of Segment Profit (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Reconciliation of segment profit to net income attributable to PAA
Segment adjusted EBITDA									$ 2,167	$ 2,212	$ 2,227
Depreciation And Amortization Of Unconsolidated Entities									(50)	(45)	(29)
Gains/(losses) from derivative activities net of inventory valuation adjustments									(404)	(110)	243
Long-term inventory costing adjustments									58	(99)	(85)
Deficiencies under minimum volume commitments, net									46	13	4
Equity-indexed compensation expense									(33)	(27)	(56)
Net gain/(loss) on foreign currency revaluation									(9)	29	(9)
Depreciation and amortization									(494)	(432)	(384)
Interest expense, net									(467)	(432)	(348)
Other income/(expense), net									33	(7)	(2)
INCOME BEFORE TAX									755	1,006	1,557
Income tax expense									(25)	(100)	(171)
NET INCOME	$ 127	$ 298	$ 102	$ 203	$ 248	$ 250	$ 124	$ 284	730	906	1,386
Net income attributable to noncontrolling interests									(4)	(3)	(2)
NET INCOME ATTRIBUTABLE TO PAA	$ 126	$ 297	$ 101	$ 202	$ 247	$ 249	$ 124	$ 283	$ 726	903	$ 1,384
Line 901 Incident
Reconciliation of segment profit to net income attributable to PAA
Line 901 incident										$ (83)

Operating Segments - Geographi

Operating Segments - Geographic Data (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Geographic Data
Total revenues	$ 5,952	$ 5,170	$ 4,950	$ 4,111	$ 4,996	$ 5,551	$ 6,663	$ 5,942	$ 20,182	$ 23,152	$ 43,464
Long-lived assets	19,936				19,310				19,936	19,310
United States
Geographic Data
Total revenues									15,599	18,701	34,860
Long-lived assets	16,041				15,942				16,041	15,942
Canada
Geographic Data
Total revenues									4,583	4,451	$ 8,604
Long-lived assets	$ 3,895				$ 3,368				$ 3,895	$ 3,368