Plains All American Pipeline (PAA) 10-K 27 Feb 20 2019 FY Annual report Financial data

Cover Page

Cover Page - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2019	Feb. 12, 2020	Jun. 28, 2019
Cover page.
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2019
Document Transition Report	false
Entity File Number	1-14569
Entity Registrant Name	PLAINS ALL AMERICAN PIPELINE LP
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	76-0582150
Entity Address, Address Line One	333 Clay Street
Entity Address, Address Line Two	Suite 1600
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	713
Local Phone Number	646-4100
Title of 12(b) Security	Common Units
Trading Symbol	PAA
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Entity Public Float			$ 11.1
Entity Common Stock Outstanding (shares)		728,050,904
Documents Incorporated by Reference	Portions of the registrant’s definitive Proxy Statement to be filed pursuant to Regulation 14A pertaining to the 2020 Annual Meeting of Unitholders are incorporated by reference into Part III hereof. The registrant intends to file such Proxy Statement no later than 120 days after the end of the fiscal year covered by this Form 10-K.
Entity Central Index Key	0001070423
Current Fiscal Year End Date	--12-31
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
CURRENT ASSETS
Cash and cash equivalents	$ 45	$ 66
Restricted cash	37
Trade accounts receivable and other receivables, net	3,614	2,454
Inventory	604	640
Other current assets	312	373
Total current assets	4,612	3,533
PROPERTY AND EQUIPMENT	18,948	17,866
Accumulated depreciation	(3,593)	(3,079)
Property and equipment, net	15,355	14,787
OTHER ASSETS
Goodwill	2,540	2,521
Investments in unconsolidated entities	3,683	2,702
Linefill and base gas	981	916
Long-term operating lease right-of-use assets, net	466
Long-term inventory	182	136
Other long-term assets, net	858	916
Total assets	28,677	25,511
CURRENT LIABILITIES
Trade accounts payable	3,686	2,704
Short-term debt	504	66
Other current liabilities	827	686
Total current liabilities	5,017	3,456
LONG-TERM LIABILITIES
Senior notes, net	8,939	8,941
Other long-term debt, net	248	202
Long-term operating lease liabilities	387
Other long-term liabilities and deferred credits	891	910
Total long-term liabilities	10,465	10,053
COMMITMENTS AND CONTINGENCIES (NOTE 19)
PARTNERS’ CAPITAL
Total partners' capital excluding noncontrolling interests	13,062	12,002
Noncontrolling interests	133
Total partners’ capital	13,195	12,002
Total liabilities and partners’ capital	28,677	25,511
Series A Preferred Units
PARTNERS’ CAPITAL
Partners' capital	1,505	1,505
Series B Preferred Units
PARTNERS’ CAPITAL
Partners' capital	787	787
Common Units
PARTNERS’ CAPITAL
Partners' capital	$ 10,770	$ 9,710

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Dec. 31, 2019	Dec. 31, 2018
Series A Preferred Units
Units outstanding (in units)	71,090,468	71,090,468
Series B Preferred Units
Units outstanding (in units)	800,000	800,000
Common Units
Units outstanding (in units)	728,028,576	726,361,924

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
REVENUES
Total revenues	$ 33,669	$ 34,055	$ 26,223
COSTS AND EXPENSES
Purchases and related costs	29,452	29,793	22,985
Field operating costs	1,303	1,263	1,183
General and administrative expenses	297	316	276
Depreciation and amortization	601	520	517
(Gains)/losses on asset sales and asset impairments, net	28	(114)	109
Total costs and expenses	31,681	31,778	25,070
OPERATING INCOME	1,988	2,277	1,153
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	388	375	290
Gain on investment in unconsolidated entities	271	200
Interest expense (net of capitalized interest of $34, $30 and $35, respectively)	(425)	(431)	(510)
Other income/(expense), net	24	(7)	(31)
INCOME BEFORE TAX	2,246	2,414	902
Current income tax expense	(112)	(66)	(28)
Deferred income tax (expense)/benefit	46	(132)	(16)
NET INCOME	2,180	2,216	858
Net income attributable to noncontrolling interests	(9)		(2)
NET INCOME ATTRIBUTABLE TO PAA	2,171	2,216	856
NET INCOME PER COMMON UNIT (NOTE 4):
Net income allocated to common unitholders — Basic	1,967	2,009	685
Net income allocated to common unitholders — Diluted	2,119	2,164	685
Supply And Logistics
REVENUES
Total revenues	32,272	32,819	25,056
Transportation
REVENUES
Total revenues	788	648	612
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	388	375	290
Facilities
REVENUES
Total revenues	$ 609	$ 588	$ 555
Common Units
NET INCOME PER COMMON UNIT (NOTE 4):
Basic weighted average common units outstanding (in units)	727	726	717
Basic net income per common unit (in dollars per unit)	$ 2.70	$ 2.77	$ 0.96
Diluted weighted average common units outstanding (in units)	800	799	718
Diluted net income per common unit (in dollars per unit)	$ 2.65	$ 2.71	$ 0.95

CONSOLIDATED STATEMENTS OF OP_2

CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Statement [Abstract]
Capitalized interest	$ 34	$ 30	$ 35

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement of Comprehensive Income [Abstract]
Net income	$ 2,180	$ 2,216	$ 858
Other comprehensive income/(loss)	97	(260)	239
Comprehensive income	2,277	1,956	1,097
Comprehensive income attributable to noncontrolling interests	(9)		(2)
Comprehensive income attributable to PAA	$ 2,268	$ 1,956	$ 1,095

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Total period activity	$ 97	$ (260)	$ 239
Derivative Instruments
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	(177)	(223)	(228)
Reclassification adjustments	9	8	21
Unrealized gain/(loss) on hedges	(91)	38	(16)
Total period activity	(82)	46	5
Ending balance	(259)	(177)	(223)
Translation Adjustments
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	(853)	(548)	(782)
Currency translation adjustments	179	(305)	234
Total period activity	179	(305)	234
Ending balance	(674)	(853)	(548)
Other
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance		1	1
Other		(1)
Total period activity		(1)
Ending balance			1
Total
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	(1,030)	(770)	(1,009)
Reclassification adjustments	9	8	21
Unrealized gain/(loss) on hedges	(91)	38	(16)
Currency translation adjustments	179	(305)	234
Other		(1)
Total period activity	97	(260)	239
Ending balance	$ (933)	$ (1,030)	$ (770)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 2,180	$ 2,216	$ 858
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	601	520	517
(Gains)/losses on asset sales and asset impairments, net	28	(114)	109
Equity-indexed compensation expense	34	79	41
Inventory valuation adjustments (Note 5)	11	8	35
Deferred income tax expense/(benefit)	(46)	132	16
Settlement of terminated interest rate hedging instruments	(55)	14	(29)
Equity earnings in unconsolidated entities	(388)	(375)	(290)
Distributions on earnings from unconsolidated entities	401	422	304
Gain on investment in unconsolidated entities	(271)	(200)
Other	21	39	(3)
Changes in assets and liabilities, net of acquisitions:
Trade accounts receivable and other	(1,158)	309	(511)
Inventory	(5)	(75)	605
Trade accounts payable and other	1,151	(367)	847
Net cash provided by operating activities	2,504	2,608	2,499
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions, net of cash acquired (Note 7)	(50)		(1,280)
Investments in unconsolidated entities (Note 9)	(524)	(468)	(416)
Additions to property, equipment and other	(1,181)	(1,634)	(1,024)
Proceeds from sales of assets (Note 7)	77	1,334	1,083
Return of investment from unconsolidated entities (Note 9)		10	21
Cash received from sales of linefill and base gas			49
Cash paid for purchases of linefill and base gas	(74)	(45)	(2)
Other investing activities	(13)	(10)	(1)
Net cash used in investing activities	(1,765)	(813)	(1,570)
CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings/(repayments) under commercial paper program (Note 11)	93	(123)	(690)
Net borrowings/(repayments) under senior secured hedged inventory facility (Note 11)	325	(778)	36
Proceeds from GO Zone term loans (Note 11)		200
Proceeds from the issuance of senior notes (Note 11)	998
Repayments of senior notes (Note 11)	(1,000)		(1,350)
Net proceeds from the sale of Series B preferred units (Note 12)			788
Net proceeds from the sale of common units (Note 12)			1,664
Sale of noncontrolling interest in a subsidiary (Note 12)	128
Other financing activities	(62)	(24)
Net cash used in financing activities	(720)	(1,757)	(943)
Effect of translation adjustment on cash	(3)	(9)	4
Net increase/(decrease) in cash and cash equivalents and restricted cash	16	29	(10)
Cash and cash equivalents and restricted cash, beginning of period	66	37	47
Cash and cash equivalents and restricted cash, end of period	82	66	37
Cash paid for:
Interest, net of amounts capitalized	397	400	486
Income taxes, net of amounts refunded	136	21	50
Series A Preferred Units
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions paid to unitholders (Note 12)	(149)	(112)
Series B Preferred Units
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions paid to unitholders (Note 12)	(49)	(49)	(5)
Common Units
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions paid to unitholders (Note 12)	$ (1,004)	$ (871)	$ (1,386)

CONSOLIDATED STATEMENTS OF CH_2

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL - USD ($) $ in Millions	Total	Partners’ Capital Excluding Noncontrolling Interests	Noncontrolling Interests	Series A Preferred UnitsLimited PartnersPartners’ Capital Excluding Noncontrolling Interests	Series B Preferred UnitsLimited PartnersPartners’ Capital Excluding Noncontrolling Interests	Common Units	Common UnitsLimited PartnersPartners’ Capital Excluding Noncontrolling Interests
Balance, beginning of period at Dec. 31, 2016	$ 8,816	$ 8,759	$ 57	$ 1,508			$ 7,251
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	858	856	2		$ 11		845
Distributions (Note 12)	(1,399)	(1,397)	(2)		(11)		(1,386)
Sale of Series B preferred units	788	788			788
Sales of common units	1,664	1,664				$ 1,664	1,664
Acquisition of interest in Advantage Joint Venture (Note 7)	40	40					40
Sale of interest in SLC Pipeline LLC (Note 12)	(57)		(57)
Other comprehensive income/(loss)	239	239					239
Equity-indexed compensation expense	22	22					22
Other	(13)	(13)		(3)			(10)
Balance, end of period at Dec. 31, 2017	10,958	10,958		1,505	788		8,665
Increase (Decrease) in Partners' Capital [Roll Forward]
Impact of adoption of ASU 2017-05 | ASU 2017-05	113	113					113
Balance at January 1, 2018	11,071	11,071		1,505	788		8,778
Net income	2,216	2,216		149	49		2,018
Distributions (Note 12)	(1,069)	(1,069)		(149)	(49)		(871)
Other comprehensive income/(loss)	(260)	(260)					(260)
Equity-indexed compensation expense	56	56					56
Other	(12)	(12)			(1)		(11)
Balance, end of period at Dec. 31, 2018	12,002	12,002		1,505	787		9,710
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	2,180	2,171	9	149	49		1,973
Distributions (Note 12)	(1,208)	(1,202)	(6)	(149)	(49)		(1,004)
Other comprehensive income/(loss)	97	97					97
Equity-indexed compensation expense	17	17					17
Sale of noncontrolling interest in a subsidiary (Note 12)	128	(2)	130				(2)
Other	(21)	(21)					(21)
Balance, end of period at Dec. 31, 2019	$ 13,195	$ 13,062	$ 133	$ 1,505	$ 787		$ 10,770

Organization and Basis of Conso

Organization and Basis of Consolidation and Presentation	12 Months Ended
	Dec. 31, 2019
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 primarily for crude oil, natural gas liquids (“NGL”) and natural gas. 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 21 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, 2019, AAP also owned a limited partner interest in us through its ownership of approximately 249.6 million of our common units (approximately 31% of our total outstanding common units and Series A preferred units combined). 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, 2019, owned an approximate 73% 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. 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. Definitions Additional defined terms are used in the following notes and shall have the meanings indicated below: AOCI = Accumulated other comprehensive income/(loss) ASC = Accounting Standards Codification ASU = Accounting Standards Update Bcf = Billion cubic feet CAD = Canadian dollar CODM = Chief Operating Decision Maker 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 ISDA = International Swaps and Derivatives Association LIBOR = London Interbank Offered Rate LTIP = Long-term incentive plan Mcf = Thousand cubic feet MMbls = Million barrels 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 SEC = United States Securities and Exchange Commission TWh = Terawatt hour 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, 2019 and 2018, 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, 2019, 2018 and 2017. 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. 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, 2019
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, as well as the disclosure of contingent assets and liabilities at the date of the financial statements. Such estimates and assumptions also affect 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) impairment assessments of goodwill and intangible assets, (iii) fair value of derivatives, (iv) accruals and contingent liabilities, (v) equity-indexed compensation plan accruals, (vi) property and equipment, depreciation and amortization expense, asset retirement obligations and impairments, (vii) allowance for doubtful accounts and (viii) inventory valuations. Although we believe these estimates are reasonable, actual results could differ from these estimates. Purchases and Related Costs Purchases and related costs include (i) the weighted average cost of crude oil, NGL and natural gas sold to customers, (ii) fees incurred for 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 sold, which are recognized at the time title transfers to our customers. Inventory exchanges under buy/sell transactions are presented net 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 payroll, compensation and benefits costs for operations personnel; fuel and power costs (including the impact of gains and losses from derivative related activities); third-party trucking transportation costs for our U.S. crude oil operations; maintenance and integrity management costs; regulatory compliance; environmental remediation; insurance; costs for usage of third-party owned pipeline, rail and storage assets; vehicle leases; and property taxes. General and administrative expenses consist primarily of payroll, compensation and benefits costs; 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 generally included in the Consolidated Statements of Operations. However, gains and losses arising from intercompany foreign currency transactions that are of a long-term investment nature are reported in the same manner as translation adjustments. The revaluation of foreign currency transactions and monetary assets and liabilities resulted in amounts recorded to the Consolidated Statements of Operations of a net gain of $1 million in each of the years ended December 31, 2019 and 2018 and a net gain of $21 million for the year ended December 31, 2017. Cash and Cash Equivalents and Restricted Cash 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, unless they may be covered by funds on deposit, outstanding checks are classified as trade accounts payable rather than negative cash. As of December 31, 2019 and 2018, trade accounts payable included $38 million and $57 million, respectively, of outstanding checks that were reclassified from cash and cash equivalents. Restricted cash includes cash held by us that is unavailable for general use and is comprised of amounts advanced to us by certain equity method investees related to the construction of fixed assets where we serve as construction manager. The following table presents a reconciliation of cash and cash equivalents and restricted cash reported on our Consolidated Balance Sheet that sum to the total of the amount shown on our Consolidated Statement of Cash Flows as of December 31, 2019 (in millions): December 31, 2019 Cash and cash equivalents $ 45 Restricted cash 37 Total cash and cash equivalents and restricted cash $ 82 We did not have any restricted cash as of December 31, 2018. Noncontrolling Interests Noncontrolling interest represents the portion of assets and liabilities in a consolidated subsidiary that is owned by a third party. FASB guidance requires all entities to report noncontrolling interests in subsidiaries as a component of equity in the consolidated financial statements. See Note 12 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. The following table presents the change in the liability for asset retirement obligations, of which $135 million, $107 million and $99 million were reflected in “Other long-term liabilities and deferred credits” with the remaining portion reflected in “Other current liabilities” on our Consolidated Balance Sheets as of December 31, 2019, 2018 and 2017, respectively (in millions): December 31, 2019 2018 2017 Beginning balance $ 109 $ 103 $ 44 Liabilities incurred 3 3 33 Liabilities settled (3) (3) (4) Accretion expense 5 4 3 Revisions in estimated cash flows 23 2 27 Ending balance $ 137 $ 109 $ 103 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 13 for further discussion. Other Significant Accounting Policies See the respective footnotes for our accounting policies regarding (i) revenues and accounts receivable, (ii) net income per common unit, (iii) inventory, linefill and base gas and long-term inventory, (iv) property and equipment, (v) acquisitions, (vi) goodwill, (vii) investments in unconsolidated entities, (viii) other long-term assets, net, (ix) income allocation for partners’ capital presentation purposes, (x) derivatives and risk management activities, (xi) leases, (xii) income taxes, (xiii) equity-indexed compensation and (xiv) legal and environmental matters. Recent Accounting Pronouncements In December 2019, the FASB issued 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes , to simplify the accounting for income taxes based on changes suggested by stakeholders as part of the FASB’s simplification initiative. This guidance is effective for interim and annual periods beginning after December 15, 2020, with early adoption permitted. We expect to adopt this guidance on January 1, 2021, and we are currently evaluating the effect that our adoption of this guidance will have on our financial position, results of operations and cash flows. In April 2019, the FASB issued 2019-04, Codification Improvements to Topic 326, Financial Instruments—Credit Losses, Topic 815, Derivatives and Hedging, and Topic 825, Financial Instruments , which clarifies certain aspects of accounting for credit losses, hedging activities and financial instruments. We will adopt this guidance effective January 1, 2020, and do not anticipate that the adoption will have a material impact on our financial position, results of operations or cash flows. In October 2018, the FASB issued ASU 2018-17, Consolidation (Topic 810): Targeted Improvements to Related Party Guidance for Variable Interest Entities , in response to stakeholder observations that improvements could be made by requiring reporting entities to consider indirect interests held through related parties under common control on a proportional basis rather than as the equivalent of a direct interest in its entirety as currently required in GAAP. This guidance is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted. We will adopt this guidance effective January 1, 2020, and do not anticipate that the adoption will have a material impact on our financial position, results of operations or cash flows. In October 2018, the FASB issued ASU 2018-16, Derivatives and Hedging (Topic 815): Inclusion of the Secured Overnight Financing Rate (SOFR) Overnight Index Swap (OIS) Rate as a Benchmark Interest Rate for Hedge Accounting Purposes, to include the OIS rate based on SOFR as an eligible benchmark interest rate during the early stages of the marketplace transition to facilitate the LIBOR to SOFR transition and provide sufficient lead time for entities to prepare for changes to interest rate risk hedging strategies for both risk management and hedge accounting purposes . This guidance is effective for interim and annual periods beginning after December 15, 2018, and must be adopted concurrently with the amendments in ASU 2017-12 (see below). We adopted this guidance effective January 1, 2019, and our adoption did not have a material impact on our financial position, results of operations or cash flows. In August 2018, the FASB issued ASU 2018-15, Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (a consensus of the FASB Emerging Issues Task Force) , to address the accounting for implementation costs of a hosting arrangement that is a service contract and to align the accounting for implementation costs for hosting arrangements, regardless of whether they convey a license to the hosted software. This guidance is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted. We will adopt this guidance effective January 1, 2020, and do not anticipate that the adoption will have a material impact on our financial position, results of operations or cash flows. In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement , modifying the disclosure requirements on fair value measurements in Topic 820. This guidance is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted. We will adopt this guidance effective January 1, 2020, and will apply the new guidance to any applicable disclosures. In July 2018, the FASB issued ASU 2018-09, Codification Improvements , which makes updates for clarifications, technical corrections and other minor improvements to a wide variety of Topics to make the ASC easier to understand and to apply. The transition and effective date is based on the facts and circumstances of each amendment with some amendments effective upon issuance. The remaining amendments are effective for annual periods beginning after December 15, 2018. We adopted this guidance effective January 1, 2019, and our adoption did not have a material impact on our financial position, results of operations or cash flows. In June 2018, the FASB issued ASU 2018-07, Compensation—Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting , which expands the scope of Topic 718 to include share-based payment awards to nonemployees and eliminates the classification differences for employee and nonemployee share-based payment awards. This guidance is effective for interim and annual periods beginning after December 15, 2018, with early adoption permitted. We adopted this guidance effective January 1, 2019, and our adoption did not have a material impact on our financial position, results of operations or cash flows. In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities, to better align an entity’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. Under the new guidance, (i) more financial and nonfinancial hedging strategies will be eligible for hedge accounting, (ii) presentation and disclosure requirements are amended and (iii) companies will change the way they assess effectiveness. This guidance is effective for interim and annual periods beginning after December 15, 2018, with early adoption permitted. We adopted this guidance effective January 1, 2019, and our adoption did not have a material impact on our financial position, results of operations or cash flows. In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (followed by a series of related accounting standard updates), which amends guidance on the impairment of financial instruments and adds an impairment model (known as the current expected credit loss (or CECL) model) that is based on expected losses rather than incurred losses. This guidance will become effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted by one year. We will adopt this guidance effective January 1, 2020, and do not anticipate that the adoption will have a material impact on our financial position, results of operations or cash flows. In February 2016, the FASB issued ASU 2016-02, Leases , (followed by a series of related accounting standard updates (collectively referred to as “Topic 842”)), 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 right-of-use assets and lease liabilities with lease terms of more than 12 months (with the election of the practical expedient to exclude short-term leases on the balance sheet), including extensive quantitative and qualitative disclosures. This guidance became effective for interim and annual periods beginning after December 15, 2018. We adopted this guidance effective January 1, 2019. Our adoption resulted in the recording of additional net lease right-of-use assets and lease liabilities of approximately $560 million and $570 million, respectively, on January 1, 2019, and did not have a material impact on our results of operations or cash flows.

Revenues and Accounts Receivabl

Revenues and Accounts Receivable	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Revenues and Accounts Receivable	Revenues and Accounts Receivable Revenue Recognition On January 1, 2018, we adopted Revenues from Contracts with Customers (“Topic 606”) using the modified retrospective approach applied to those contracts which were not completed as of January 1, 2018. Results for reporting periods beginning after January 1, 2018 are presented under Topic 606, while prior period amounts are not adjusted and continue to be reported in accordance with our historic accounting under ASC Topic 605, Revenue Recognition . Under Topic 606, we disaggregate our revenues by segment and type of activity. These categories depict how the nature, amount, timing and uncertainty of revenues and cash flows are affected by economic factors. Supply and Logistics Segment Revenues from Contracts with Customers. The following table presents our Supply and Logistics segment revenues from contracts with customers disaggregated by type of activity (in millions): Year Ended December 31, 2019 2018 Supply and Logistics segment revenues from contracts with customers Crude oil transactions $ 30,082 $ 29,592 NGL and other transactions 1,884 3,108 Total Supply and Logistics segment revenues from contracts with customers $ 31,966 $ 32,700 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. The consideration received under these contracts is variable based on commodity prices. Inventory exchanges under buy/sell transactions are excluded from Supply and Logistics segment revenues in our Consolidated Statements of Operations. Revenues recognized by our Supply and Logistics segment primarily represent margin based activities. In addition, we have certain crude oil sales agreements that are entered into in conjunction with storage arrangements and future inventory exchanges. The revenues under these agreements are deferred until all performance obligations associated with the related agreements are completed. The inventory that has been sold under these crude oil sales agreements is reflected in “Other current assets” on our Consolidated Balance Sheet until all of our performance obligations are complete. At that time, the inventory that has been sold is removed from our Consolidated Balance Sheet and recorded as “Purchases and related costs” in our Consolidated Statement of Operations. At December 31, 2019, other current assets and deferred revenue associated with these agreements were approximately $142 million and $155 million, respectively. At December 31, 2018, other current assets and deferred revenue associated with these agreements was approximately $115 million and $116 million, respectively. See Contract Balances below for further discussion of contract liabilities associated with these agreements. We may also utilize derivatives in connection with the transactions described above. Derivative revenue is not included as a component of revenue from contracts with customers, but is included in other items in revenue. The change in the fair value of derivatives that are not designated or do not qualify for hedge accounting is recognized in revenues each period. Transportation Segment Revenues from Contracts with Customers. The following table presents our Transportation segment revenues from contracts with customers disaggregated by type of activity (in millions): Year Ended December 31, 2019 2018 Transportation segment revenues from contracts with customers Tariff activities: Crude oil pipelines $ 2,039 $ 1,724 NGL pipelines 99 103 Total tariff activities 2,138 1,827 Trucking 145 149 Total Transportation segment revenues from contracts with customers $ 2,283 $ 1,976 Our Transportation segment operations generally consist of fee-based activities associated with transporting crude oil and NGL on pipelines, gathering systems and trucks. Revenues from pipeline tariffs and fees are associated with the transportation of crude oil and NGL at a published tariff. We primarily recognize pipeline tariff and fee revenues over time as services are rendered, based on the volumes transported. As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor. We recognize the allowance volumes collected as part of the transaction price and record this non-cash consideration at fair value, measured as of the contract inception date. Facilities Segment Revenues from Contracts with Customers. The following table presents our Facilities segment revenues from contracts with customers disaggregated by type of activity (in millions): Year Ended December 31, 2019 2018 Facilities segment revenues from contracts with customers Crude oil, NGL and other terminalling and storage $ 697 $ 688 NGL and natural gas processing and fractionation 349 364 Rail load / unload 76 84 Total Facilities segment revenues from contracts with customers $ 1,122 $ 1,136 Our Facilities segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services primarily for crude oil, 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 when we receive liquids from one connecting source and deliver the applicable product to another connecting carrier, fees from storage capacity agreements and fees associated with natural gas storage related activities (collectively “Crude oil, NGL and other terminalling and storage”), (ii) fees from natural gas and condensate processing services and from NGL fractionation and isomerization services (collectively, “NGL and natural gas processing and fractionation”) and (iii) loading and unloading fees at our rail terminals. We generate revenue through a combination of month-to-month and multi-year agreements and processing arrangements. Storage fees are typically recognized in revenue ratably over the term of the contract regardless of the actual storage capacity utilized as our performance obligation is to make available storage capacity for a period of time. Terminal fees (including throughput and rail fees) are recognized as the liquids enter or exit the terminal and are received from or delivered to the connecting carrier or third-party terminal, as applicable. Fees from NGL fractionation and isomerization services and gas processing services are recognized in the period when the services are performed. Natural gas storage related activities fees are recognized in the period the natural gas moves across our header system. We recognize rail loading and unloading fees when the volumes are delivered or received. Reconciliation to Total Revenues of Reportable Segments. Topic 606 requires us to provide information about the relationship between the disaggregated revenues presented above and segment revenues. These disclosures only include information regarding revenues associated with consolidated entities, and revenues from entities accounted for by the equity method are not included in the disclosures. The following tables present the reconciliation of our revenues from contracts with customers (as described above for each segment) to segment revenues and total revenues as disclosed in our Consolidated Statements of Operations (in millions): Year Ended December 31, 2019 Transportation Facilities Supply and Logistics Total Revenues from contracts with customers $ 2,283 $ 1,122 $ 31,966 $ 35,371 Other items in revenues 37 49 310 396 Total revenues of reportable segments $ 2,320 $ 1,171 $ 32,276 $ 35,767 Intersegment revenues (2,098) Total revenues $ 33,669 Year Ended December 31, 2018 Transportation Facilities Supply and Total Revenues from contracts with customers $ 1,976 $ 1,136 $ 32,700 $ 35,812 Other items in revenues 14 25 122 161 Total revenues of reportable segments $ 1,990 $ 1,161 $ 32,822 $ 35,973 Intersegment revenues (1,918) Total revenues $ 34,055 Minimum Volume Commitments. We have certain agreements that require counterparties to 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’s make-up right as a contract liability 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, 2019 and December 31, 2018, counterparty deficiencies associated with contracts with customers and buy/sell arrangements that include minimum volume commitments totaled $42 million and $62 million, respectively, of which $22 million and $40 million, respectively, was recorded as a contract liability. The remaining balance of $20 million and $22 million at December 31, 2019 and December 31, 2018, respectively, 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. Contract Balances . Our contract balances consist of amounts received associated with services or sales for which we have not yet completed the related performance obligation. The following table presents the changes in the contract liability balance (in millions): Contract Liabilities Balance at December 31, 2017 $ 90 Amounts recognized as revenue (81) Additions (1) (2) 332 Other (3) Balance at December 31, 2018 $ 338 Amounts recognized as revenue (227) Additions (3) 244 Other (1) Balance at December 31, 2019 $ 354 (1) Includes approximately $116 million associated with crude oil sales agreements that are entered into in conjunction with storage arrangements and future inventory exchanges. Such amount was recognized as revenue in the first quarter of 2019. (2) Includes $100 million associated with long-term capacity agreements with Cactus II Pipeline LLC. See Note 9 for additional information. (3) Includes approximately $155 million associated with crude oil sales agreements that are entered into in conjunction with storage arrangements and future inventory exchanges. Such amount is expected to be recognized as revenue in the first quarter of 2020. Remaining Performance Obligations . Topic 606 requires a presentation of information about partially and wholly unsatisfied performance obligations under contracts that exist as of the end of the period. The information includes the amount of consideration allocated to those remaining performance obligations and the timing of revenue recognition of those remaining performance obligations. Certain contracts meet the requirements for the presentation as remaining performance obligations. These arrangements include a fixed minimum level of service, typically a set volume of service, and do not contain any variability other than expected timing within a limited range. These contracts are all within the scope of Topic 606. The following table presents the amount of consideration associated with remaining performance obligations for the population of contracts with external customers meeting the presentation requirements as of December 31, 2019 (in millions): 2020 2021 2022 2023 2024 2025 and Thereafter Pipeline revenues supported by minimum volume commitments and capacity agreements (1) $ 164 $ 170 $ 170 $ 168 $ 146 $ 698 Storage, terminalling and throughput agreement revenues 404 312 242 188 147 366 Total $ 568 $ 482 $ 412 $ 356 $ 293 $ 1,064 (1) Calculated as volumes committed under contracts multiplied by the current applicable tariff rate. The presentation above does not include (i) expected revenues from legacy shippers not underpinned by minimum volume commitments, including pipelines where there are no or limited alternative pipeline transportation options, (ii) intersegment revenues and (iii) the amount of consideration associated with certain income generating contracts, which include a fixed minimum level of service, that are either not within the scope of Topic 606 or do not meet the requirements for presentation as remaining performance obligations under Topic 606. The following are examples of contracts that are not included in the table above because they are not within the scope of Topic 606 or do not meet the Topic 606 requirements for presentation: • Minimum volume commitments on certain of our joint venture pipeline systems; • Acreage dedications; • Supply and Logistics buy/sell arrangements with future committed volumes; • All other Supply and Logistics contracts, due to the election of practical expedients related to variable consideration and short-term contracts, as discussed below; • Transportation and Facilities contracts that are short-term, as discussed below; • Contracts within the scope of ASC Topic 842, Leases ; and • Contracts within the scope of ASC Topic 815, Derivatives and Hedging . We have elected practical expedients to exclude the presentation of remaining performance obligations for variable consideration which relates to wholly unsatisfied performance obligations. Certain contracts do not meet the requirements for presentation of remaining performance obligations under Topic 606 due to variability in amount of performance obligation remaining, variability in the timing of recognition or variability in consideration. Acreage dedications do require us to perform future services but do not contain a minimum level of services and are therefore excluded from this presentation. Long-term supply and logistics arrangements contain variable timing, volumes and/or consideration and are excluded from this presentation. The duration of these contracts varies across the periods presented above. Additionally, we have elected practical expedients to exclude contracts with terms of one year or less, and therefore exclude the presentation of remaining performance obligations for short-term transportation, storage and processing services, supply and logistics arrangements, including the non-cancelable period of evergreen arrangements, and any other types of arrangements with terms of one year or less. Trade Accounts Receivable and Other Receivables, Net Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL. These purchasers include, but are not limited to, refiners, producers, marketing and trading companies and financial institutions. The majority of our accounts receivable relate to our crude oil supply and logistics activities that can generally be described as high volume and low margin activities, in many cases involving exchanges of crude oil volumes. To mitigate credit risk related to our accounts receivable, we utilize a rigorous credit review process. We closely monitor market conditions and perform credit reviews of each customer 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, credit insurance or parental guarantees. Additionally, in an effort to mitigate credit risk, a significant portion of our transactions with counterparties are settled on a net-cash basis. For a majority of these net-cash arrangements, 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). Accounts receivable from the sale of crude oil are generally settled with counterparties on the industry settlement date, which is typically in the month following the month in which the title transfers. Otherwise, we generally invoice customers within 30 days of when the products or services were provided and generally require payment within 30 days of the invoice date. 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, 2019 and December 31, 2018, 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 at both December 31, 2019 and December 31, 2018. Although we consider our allowance for doubtful accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts. The following is a reconciliation of trade accounts receivable from revenues from contracts with customers to total Trade accounts receivable and other receivables, net as presented on our Consolidated Balance Sheets (in millions): December 31, 2019 2018 Trade accounts receivable arising from revenues from contracts with customers $ 3,381 $ 2,277 Other trade accounts receivables and other receivables (1) 3,576 2,732 Impact due to contractual rights of offset with counterparties (3,343) (2,555) Trade accounts receivable and other receivables, net $ 3,614 $ 2,454 (1) The balance is comprised primarily of accounts receivable associated with buy/sell arrangements that are not within the scope of Topic 606.

Net Income Per Common Unit

Net Income Per Common Unit	12 Months Ended
	Dec. 31, 2019
Earnings Per Share [Abstract]
Net Income Per Common Unit	Net Income Per Common Unit After consideration of distributions to preferred unitholders (whether paid in cash or 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 our 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 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 equity-indexed compensation plan awards that have vested DERs, which entitle the grantee to a cash payment equal to the cash distribution paid on our outstanding common units. 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) by the basic and diluted weighted average number of common units outstanding during the period. The diluted weighted average number of common units 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 and (ii) our equity-indexed compensation plan awards. See Note 12 for additional information regarding our Series A preferred units. See Note 18 for a complete discussion of our equity-indexed compensation plan awards. 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, 2017 as the effect was antidilutive. Our equity-indexed compensation plan awards that contemplate the issuance of common units are considered dilutive unless (i) they become vested only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. Equity-indexed compensation plan awards that were deemed to be dilutive during the three years ended December 31, 2019 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. 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, 2019 2018 2017 Basic Net Income per Common Unit Net income attributable to PAA $ 2,171 $ 2,216 $ 856 Distributions to Series A preferred unitholders (149) (149) (142) Distributions to Series B preferred unitholders (49) (49) (11) Distributions to participating securities (3) (3) (2) Other (3) (6) (16) Net income allocated to common unitholders (1) $ 1,967 $ 2,009 $ 685 Basic weighted average common units outstanding 727 726 717 Basic net income per common unit $ 2.70 $ 2.77 $ 0.96 Diluted Net Income per Common Unit Net income attributable to PAA $ 2,171 $ 2,216 $ 856 Distributions to Series A preferred unitholders — — (142) Distributions to Series B preferred unitholders (49) (49) (11) Distributions to participating securities (3) (3) (2) Other — — (16) Net income allocated to common unitholders (1) $ 2,119 $ 2,164 $ 685 Basic weighted average common units outstanding 727 726 717 Effect of dilutive securities: Series A preferred units 71 71 — Equity-indexed compensation plan awards 2 2 1 Diluted weighted average common units outstanding 800 799 718 Diluted net income per common unit $ 2.65 $ 2.71 $ 0.95 (1) We calculate net income allocated to common unitholders based on the distributions pertaining to the current period’s net income (whether paid in cash or in-kind). After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings (i.e., undistributed loss), if any, are allocated to the 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.

Inventory, Linefill and Base Ga

Inventory, Linefill and Base Gas and Long-term Inventory	12 Months Ended
	Dec. 31, 2019
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 and NGL in pipelines, storage facilities and railcars that are valued at the lower of cost or net realizable value, 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, 2019, 2018 and 2017, we recorded charges of $11 million, $8 million and $35 million, respectively, related to the writedown of our crude oil inventory due to declines in prices. A portion of these inventory valuation adjustments was offset by the recognition of gains on derivative instruments being utilized to hedge future sales of our crude oil inventory. Such gains were recorded to “Supply and Logistics segment revenues” in our accompanying Consolidated Statements of Operations. See Note 13 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. 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 6 for further discussion regarding impairment of long-lived assets. During 2019, 2018 and 2017, 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 under “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, 2019 December 31, 2018 Volumes Unit of Carrying Price/ Unit (1) Volumes Unit of Carrying Price/ Unit (1) Inventory Crude oil 8,613 barrels $ 450 $ 52.25 9,657 barrels $ 367 $ 38.00 NGL 7,574 barrels 142 $ 18.75 10,384 barrels 262 $ 25.23 Other N/A 12 N/A N/A 11 N/A Inventory subtotal 604 640 Linefill and base gas Crude oil 14,316 barrels 826 $ 57.70 13,312 barrels 761 $ 57.17 NGL 1,701 barrels 47 $ 27.63 1,730 barrels 47 $ 27.17 Natural gas 24,976 Mcf 108 $ 4.32 24,976 Mcf 108 $ 4.32 Linefill and base gas subtotal 981 916 Long-term inventory Crude oil 2,598 barrels 152 $ 58.51 1,890 barrels 79 $ 41.80 NGL 1,707 barrels 30 $ 17.57 2,368 barrels 57 $ 24.07 Long-term inventory subtotal 182 136 Total $ 1,767 $ 1,692 (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, 2019
Property, Plant and Equipment [Abstract]
Property and Equipment	Property and EquipmentIn 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, 2019, 2018 and 2017, capitalized interest recorded to property and equipment was $14 million, $21 million and $17 million, respectively. In addition, we capitalize interest related to investments in certain unconsolidated entities. See Note 9 for additional information. We also capitalize expenditures for the replacement and/or refurbishment 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, 2019 2018 Pipelines and related facilities (1) 10 - 70 $ 11,114 $ 10,137 Storage, terminal and rail facilities 10 - 70 6,134 5,854 Trucking equipment and other 2 - 15 486 410 Construction in progress N/A 518 795 Office property and equipment 2 - 50 269 248 Land and other N/A 427 422 Property and equipment, gross 18,948 17,866 Accumulated depreciation (3,593) (3,079) Property and equipment, net $ 15,355 $ 14,787 (1) We include rights-of-way, which are intangible assets, in our Pipelines 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, 2019, 2018 and 2017 was $525 million, $454 million and $463 million, respectively. See “Impairment of Long-Lived Assets” below for a discussion of our policy for the recognition of asset impairments. As of December 31, 2019, 2018 and 2017, we incurred liabilities for construction in progress that had not been paid of $120 million, $206 million and $127 million, respectively. 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. In addition, when we evaluate property and equipment and other long-lived assets for recoverability, it may also be necessary to review related depreciation estimates and methods.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2019
Business Combinations [Abstract]
Acquisitions and Divestitures	Acquisitions and Divestitures Acquisitions The following acquisitions were accounted for using the acquisition method of accounting (excluding asset acquisitions or acquired interests accounted for under the equity method of accounting mentioned specifically below) and the determination of the fair value of the assets and liabilities acquired has been estimated in accordance with the applicable accounting guidance. In February 2020, we acquired Felix Midstream LLC (“Felix Midstream”) from Felix Energy Holdings II, LLC (“Felix Energy”) for approximately $305 million. Felix Midstream owns and operates a newly constructed crude oil gathering system in the Delaware Basin, with associated crude oil storage and truck offloading capacity, and is supported by a long-term acreage dedication. The assets acquired will primarily be included in our Transportation segment. The initial accounting for this acquisition was not complete as of the financial statements issuance date. During the second quarter of 2019, we acquired a crude oil terminal, including tank bottoms and linefill, in Cushing, Oklahoma for cash consideration of $44 million, which was accounted for as an asset acquisition. Alpha Crude Connector Acquisition On February 14, 2017, we acquired all of the issued and outstanding membership interests in Alpha Holding Company, LLC for cash consideration of $1.215 billion, subject to working capital and other adjustments (the “ACC Acquisition”). The ACC Acquisition was initially funded through borrowings under our senior unsecured revolving credit facility. Such borrowings were subsequently repaid with proceeds from our March 2017 issuance of common units to AAP pursuant to the Omnibus Agreement and in connection with a PAGP underwritten equity offering. See Note 12 for additional information. Upon completion of the ACC Acquisition, we became the owner of a crude oil gathering system known as the “Alpha Crude Connector” (the “ACC System”) located in the Northern Delaware Basin in Southeastern New Mexico and West Texas. The ACC System comprises approximately 515 miles of gathering and transmission lines and five market interconnects, including to our Basin Pipeline at Wink. During 2017, we made additional interconnects to our existing Northern Delaware Basin systems as well as additional enhancements to increase the ACC System capacity to approximately 350,000 barrels per day, depending on the level of volume at each delivery point. The ACC System is supported by acreage dedications covering approximately 315,000 gross acres, including a significant acreage dedication from one of the largest producers in the region. The ACC System complements our other Permian Basin assets and enhances the services available to the producers in the Northern Delaware Basin. The following table reflects the fair value determination (in millions): Identifiable assets acquired and liabilities assumed: Estimated Useful Lives (Years) Recognized amount Property and equipment 3 - 70 $ 299 Intangible assets 20 646 Goodwill N/A 269 Other assets and liabilities, net (including $4 million of cash acquired) N/A 1 $ 1,215 Intangible assets are included in “Other long-term assets, net” on our Consolidated Balance Sheets. The determination of fair value to intangible assets above is comprised of five acreage dedication contracts and associated customer relationships that will be amortized over a remaining weighted average useful life of approximately 20 years. The value assigned to such intangible assets will be amortized to earnings using methods that closely resemble the pattern in which the economic benefits will be consumed. Amortization expense was approximately $34 million, $25 million and $10 million during the years ended December 31, 2019, 2018 and 2017, respectively, and the future amortization expense through 2022 is estimated as follows (in millions): 2020 $ 42 2021 $ 48 2022 $ 54 The goodwill arising from the ACC Acquisition, which is tax deductible, represents the anticipated opportunities to generate future cash flows from undedicated acreage and the synergies created between the ACC System and our existing assets. The assets acquired in the ACC Acquisition, as well as the associated goodwill, are primarily included in our Transportation segment. During the year ended December 31, 2017, we incurred approximately $6 million of acquisition-related costs associated with the ACC Acquisition. Such costs are reflected as a component of “General and administrative expenses” on our Consolidated Statements of Operations. Pro forma financial information assuming the ACC Acquisition had occurred as of the beginning of the calendar year prior to the year of acquisition were not material for disclosure purposes. Other Acquisitions In February 2017, we acquired a propane marine terminal for cash consideration of approximately $41 million. The assets acquired are included in our Facilities segment. We did not recognize any goodwill related to this acquisition. On April 3, 2017, we and an affiliate of Noble Midstream Partners LP (“Noble”) completed the acquisition of Advantage Pipeline, L.L.C. (“Advantage”) through a newly formed 50/50 joint venture (the “Advantage Joint Venture”). We account for our interest in the Advantage Joint Venture under the equity method of accounting. See Note 9 for additional discussion of our equity method investments. Divestitures In January 2020, we signed a definitive agreement to sell certain of our Los Angeles Basin crude oil terminals for $195 million, subject to certain adjustments. We expect the transaction to close in the second half of 2020, subject to customary closing conditions, including the receipt of regulatory approvals, and anticipate we will recognize a loss of approximately $160 million, including goodwill that will be included as part of the disposal group. During the year ended December 31, 2019, we sold certain non-core assets for total proceeds of $77 million that primarily consisted of a storage terminal in North Dakota, which was previously reported in our Facilities segment. For the year ended December 31, 2019, we recognized a net loss related to these asset sales of $16 million, which is comprised of gains of $31 million and losses of $47 million. Such amounts are included in "(Gains)/losses on asset sales and asset impairments, net" on our Consolidated Statement of Operations. During the year ended December 31, 2018, we received proceeds from asset sales of $1.334 billion, which primarily consisted of the sale of a 30% interest in BridgeTex Pipeline Company, LLC for proceeds of $868 million, resulting in a gain of $200 million. See Note 9 for additional discussion. The other assets sold during the year ended December 31, 2018 primarily included non-core property and equipment or are associated with the formation of strategic joint ventures and were previously reported in our Facilities and Transportation segments. For the year ended December 31, 2018, we recognized a net gain on sales of assets of $120 million, which is comprised of gains of $146 million and losses of $26 million. Such amounts are included in “(Gains)/losses on asset sales and asset impairments, net” on our Consolidated Statement of Operations. During the year ended December 31, 2017, we sold certain non-core assets for total proceeds of $1.083 billion, including: • certain of our Bay Area terminal assets located in California; • our Bluewater natural gas storage facility located in Michigan; • certain non-core pipelines in the Rocky Mountain and Bakken regions, including our interest in SLC Pipeline LLC; • non-core pipeline segments primarily located in the Midwestern United States; and • a 40% undivided interest in a segment of our Red River Pipeline extending from Cushing, Oklahoma to the Hewitt Station near Ardmore, Oklahoma for our net book value. The Bay Area terminal assets and the Bluewater natural gas storage facility were reported in our Facilities segment. The pipeline assets were reported in our Transportation segment. In the aggregate, including non-cash impairments recognized upon reclassifications to assets held for sale, we recognized a net gain related to pending or completed asset sales of approximately $43 million for the year ended December 31, 2017, which is included in “(Gains)/losses on asset sales and asset impairments, net” on our Consolidated Statement of Operations. Such amount is comprised of gains of $123 million and losses of $80 million.

Goodwill

Goodwill	12 Months Ended
	Dec. 31, 2019
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 provides for a quantitative approach to testing goodwill for impairment; however, we may first assess certain qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment test. In the quantitative test, 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 goodwill is impaired by the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying value of goodwill. We completed our goodwill impairment test as of June 30, 2019 using a quantitative assessment, 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 greater than its respective book value; therefore, goodwill was not considered impaired. We did not recognize any 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, 2017 $ 1,070 $ 988 $ 508 $ 2,566 Foreign currency translation adjustments (19) (8) (5) (32) Divestitures (11) (2) — (13) Balance at December 31, 2018 $ 1,040 $ 978 $ 503 $ 2,521 Foreign currency translation adjustments 12 4 3 19 Balance at December 31, 2019 $ 1,052 $ 982 $ 506 $ 2,540

Investments in Unconsolidated E

Investments in Unconsolidated Entities	12 Months Ended
	Dec. 31, 2019
Equity Method Investments and Joint Ventures [Abstract]
Investments in Unconsolidated Entities	Investments in Unconsolidated EntitiesInvestments in entities over which we have significant influence but not control are accounted for under 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 Investment Balance Entity (1) Type of Operation 2019 2018 Advantage Pipeline Holdings LLC (“Advantage Joint Venture”) Crude Oil Pipeline 50% $ 76 $ 72 BridgeTex Pipeline Company, LLC (“BridgeTex”) Crude Oil Pipeline 20% 431 435 Cactus II Pipeline LLC (“Cactus II”) Crude Oil Pipeline 65% 738 455 Caddo Pipeline LLC Crude Oil Pipeline 50% 65 65 Capline Pipeline Company LLC Crude Oil Pipeline (2) (3) 54% 484 — Cheyenne Pipeline LLC (“Cheyenne”) Crude Oil Pipeline 50% 44 44 Cushing Connect Pipeline & Terminal LLC Crude Oil Pipeline (3) and Terminal 50% 23 — Diamond Pipeline LLC (“Diamond”) Crude Oil Pipeline 50% 476 479 Eagle Ford Pipeline LLC (“Eagle Ford Pipeline”) Crude Oil Pipeline 50% 382 383 Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Terminals”) Crude Oil Terminal and Dock 50% 126 108 Midway Pipeline LLC Crude Oil Pipeline 50% 76 78 Red Oak Pipeline LLC (“Red Oak”) Crude Oil Pipeline (3) 50% 20 — Saddlehorn Pipeline Company, LLC (“Saddlehorn”) Crude Oil Pipeline 40% 234 215 Settoon Towing, LLC Barge Transportation Services 50% 59 58 STACK Pipeline LLC (“STACK”) Crude Oil Pipeline 50% 117 120 White Cliffs Pipeline, LLC Crude Oil Pipeline 36% 196 190 Wink to Webster Pipeline LLC (“W2W Pipeline”) Crude Oil Pipeline (3) 16% 136 — Total Investments in Unconsolidated Entities $ 3,683 $ 2,702 (1) Except for Eagle Ford Terminals, which is reported in our Facilities segment, the financial results from the entities are reported in our Transportation segment. (2) The Capline pipeline was taken out of service pending the reversal of the pipeline system. (3) Asset is currently under construction or development by the entity and has not yet been placed in service. Formations and Divestitures Capline LLC . During the first quarter of 2019, the owners of the Capline pipeline system contributed their undivided joint interests in the system to a newly formed entity, Capline Pipeline Company LLC (“Capline LLC”), in exchange for equity interests in such entity. After the contribution, Capline LLC owns 100% of the pipeline system. Each owner’s undivided joint interest in the Capline pipeline system prior to the transaction is equal to each owner’s equity interest in Capline LLC. Although we own a majority of Capline LLC’s equity, we do not have a controlling financial interest in Capline LLC because the other members have substantive participating rights. Therefore, we account for our ownership interest in Capline LLC as an equity method investment. Under applicable accounting rules, the transaction resulted in a “loss of control” of our undivided joint interest, which was derecognized and contributed to Capline LLC. The “loss of control” required us to measure our equity interest in Capline LLC at fair value. At the time of the transaction, our 54% undivided joint interest in the Capline pipeline system had a carrying value of $175 million, which primarily related to property and equipment included in our Transportation segment. We determined the fair value of our investment in Capline LLC to be approximately $444 million, resulting in the recognition of a gain of $269 million during the year ended December 31, 2019. Such gain is included in “Gain on investment in unconsolidated entities” on our Consolidated Statement of Operations. The fair value of our investment in Capline LLC was based on an income approach utilizing a discounted cash flow analysis. The cash flow forecasts require the use of various assumptions and estimates which include those related to the timing and amount of capital expenditures, the expected tariff rates and volumes of crude oil, and the terminal value. We probability-weighted various forecasted cash flow scenarios utilized in the analysis when we considered the possible outcomes. We used a discount rate representing our estimate of the risk adjusted discount rate that would be used by market participants. If shipper interest varies from the levels assumed in our model, the related cash flows, and thus the fair value of our investment, could be materially impacted. The fair value of our investment was determined using significant unobservable inputs, or Level 3 inputs in the fair value hierarchy. W2W Pipeline . In 2019, we participated in the formation of W2W Pipeline, a joint venture with subsidiaries of ExxonMobil, Lotus Midstream, LLC and three additional entities, in which we own a 16% interest. We account for our interest in W2W Pipeline under the equity method of accounting. W2W Pipeline is currently developing a new pipeline system that will originate in the Permian Basin in West Texas and transport crude oil to the Texas Gulf Coast. The pipeline system will provide approximately 1.5 million barrels per day of crude oil and condensate capacity and is targeted to commence operations in 2021. W2W Pipeline has entered into an undivided joint-ownership arrangement with a subsidiary of Enterprise Products Partners, L.P. that has acquired 29% of the capacity of the pipeline segment from Midland, Texas to Webster, Texas, and W2W Pipeline now owns 71% of this segment of the pipeline. Red Oak . In June 2019, we announced the formation of Red Oak, a joint venture with a subsidiary of Phillips 66. We own a 50% interest in Red Oak, which is currently developing a new pipeline that will provide crude oil transportation service from Cushing, Oklahoma, and the Permian Basin in West Texas to multiple destinations along the Texas Gulf Coast, including Corpus Christi, Ingleside, Houston and Beaumont, Texas. The pipeline system will provide approximately 1 million barrels per day of capacity, and initial service from Cushing to the Gulf Coast is targeted to commence in the first half of 2021, subject to receipt of applicable permits and regulatory approvals. We account for our interest in Red Oak under the equity method of accounting. In addition to contributing cash for construction of the Red Oak pipeline system, we have also entered into a pipeline capacity lease agreement with Red Oak whereby Red Oak has agreed to lease 260,000 barrels of capacity on our Sunrise II pipeline once the Red Oak pipeline system is operational. Once the Red Oak pipeline system is operational, we will record (i) a $155 million increase to our investment in Red Oak associated with our deemed contribution of the value attributable to the capacity lease and (ii) corresponding deferred revenue that will be recognized on a straight-line basis over the initial lease term of 33 years. Cushing Connect . During the fourth quarter of 2019, we announced the formation of Cushing Connect Pipeline & Terminal LLC, a joint venture with Holly Energy Partners LP for (i) the development and construction of a new 160,000 barrel per day pipeline that will connect the Cushing, Oklahoma crude oil hub to the Tulsa, Oklahoma refining complex owned by a subsidiary of HollyFrontier Corporation and (ii) the ownership and operation of 1.5 million barrels of crude oil storage in Cushing, Oklahoma (the “JV Terminal”). We contributed the crude oil storage to Cushing Connect and own a 50% interest, which is accounted for under the equity method of accounting. The pipeline is expected to be in service during the first quarter of 2021. Cactus II. In the second quarter of 2018, a subsidiary of Oxy and another third party each exercised their purchase options for a 20% interest and a 15% interest, respectively, in Cactus II, which owns the Cactus II pipeline system that is currently under construction. Although we own a majority of Cactus II’s equity, we do not have a controlling financial interest in Cactus II because the other members have substantive participating rights. Therefore, we account for our ownership interest in Cactus II as an equity method investment. Following the exercise of the purchase options, we deconsolidated Cactus II resulting in a reduction of property and equipment of $74 million (which was representative of the costs incurred to date to construct the pipeline and equivalent to fair value), and we received $26 million of cash from Cactus II, which represented the other members’ portion of the property and equipment. In addition, during the second quarter of 2018, we received a $100 million advance cash payment from Cactus II associated with pipeline capacity agreements, which is recorded as long-term deferred revenue within “Other long-term liabilities and deferred credits” on our Consolidated Balance Sheet. Such amount is being recognized in revenue ratably over the life of the contracts. BridgeTex. During the third quarter of 2018, we sold a 30% interest in BridgeTex for proceeds of $868 million, including working capital adjustments, and have retained a 20% interest. We recorded a gain of $200 million related to this sale, which is included in “Gain on investment in unconsolidated entities” on our Consolidated Statement of Operations. We continue to account for our remaining interest under the equity method of accounting. Advantage Joint Venture. On April 3, 2017, we and an affiliate of Noble completed the acquisition of Advantage Pipeline, L.L.C. for a purchase price of $133 million through a newly formed 50/50 joint venture (the “Advantage Joint Venture”). For our 50% share ($66.5 million), we contributed approximately 1.3 million common units with a value of approximately $40 million and approximately $26 million in cash. Through the acquisition, the Advantage Joint Venture owns a 70-mile, 16-inch crude oil pipeline located in the southern Delaware Basin (the “Advantage Pipeline”), which is contractually supported by a third-party acreage dedication and a volume commitment from our wholly-owned marketing subsidiary. Noble serves as operator of the Advantage Pipeline. We account for our interest in the Advantage Joint Venture under the equity method of accounting. Midway Pipeline LLC. During the fourth quarter of 2017, we and an affiliate of CVR Refining, LP (“CVR Refining”) formed a 50/50 joint venture, Midway Pipeline LLC, which acquired from us the Cushing to Broome crude oil pipeline system. The Cushing to Broome pipeline system connects CVR Refining’s Coffeyville, Kansas refinery to the Cushing, Oklahoma oil hub. We continue to serve as operator of the pipeline. We account for our interest in Midway Pipeline LLC under the equity method of accounting. Distributions 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. Contributions 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, 2019, 2018 and 2017, we made cash contributions of $504 million, $459 million and $398 million, respectively, to certain of our equity method investees. In addition, we capitalized interest of $20 million, $9 million and $18 million during the years ended December 31, 2019, 2018 and 2017, respectively, related to contributions to unconsolidated entities for projects under development and construction. We anticipate that we will make additional contributions in 2020 related to ongoing projects. Basis Differences Our investments in unconsolidated entities exceeded our share of the underlying equity in the net assets of such entities by $349 million and $467 million at December 31, 2019 and 2018, 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 majority of the basis difference at both December 31, 2019 and 2018 was related to our ownership interest in BridgeTex. 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, 2019 2018 Current assets $ 652 $ 357 Noncurrent assets $ 7,264 $ 4,861 Current liabilities $ 298 $ 170 Noncurrent liabilities $ 26 $ 30 Year Ended December 31, 2019 2018 2017 Revenues $ 1,469 $ 1,235 $ 938 Operating income $ 994 $ 824 $ 650 Net income $ 995 $ 824 $ 640

Other Long-Term Assets, Net

Other Long-Term Assets, Net	12 Months Ended
	Dec. 31, 2019
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, 2019 December 31, 2018 Estimated Useful Cost Accumulated Net Cost Accumulated Net Customer contracts and relationships 1 – 20 $ 1,134 $ (463) $ 671 $ 1,152 $ (413) $ 739 Property tax abatement 7 – 13 23 (18) 5 23 (16) 7 Other agreements 25 – 70 42 (11) 31 34 (8) 26 Intangible assets (1) 1,199 (492) 707 1,209 (437) 772 Other 152 (1) 151 144 — 144 Other long-term assets, net $ 1,351 $ (493) $ 858 $ 1,353 $ (437) $ 916 (1) We include rights-of-way, which are intangible assets, in our pipeline and related facilities amounts within property and equipment. See Note 6 for a discussion of property and equipment. Intangible assets that have finite lives are tested for impairment when events or circumstances indicate that the carrying value may not be recoverable. We did not recognize any impairments of finite-lived intangible assets during the three years ended December 31, 2019. Amortization expense for finite-lived intangible assets for the years ended December 31, 2019, 2018 and 2017 was $76 million, $66 million and $54 million, respectively. We estimate that our amortization expense related to finite-lived intangible assets for the next five years will be as follows (in millions): 2020 $ 77 2021 $ 73 2022 $ 74 2023 $ 69 2024 $ 67

Debt

Debt	12 Months Ended
	Dec. 31, 2019
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 2.2% (1) $ 93 $ — Senior secured hedged inventory facility, bearing a weighted-average interest rate of 2.7% (1) 325 — Other 86 66 Total short-term debt 504 66 LONG-TERM DEBT Senior notes: 2.60% senior notes due December 2019 (2) — 500 5.75% senior notes due January 2020 — 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 750 750 3.55% senior notes due December 2029 1,000 — 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 (61) (59) Senior notes, net of unamortized discounts and debt issuance costs 8,939 8,941 Other long-term debt: GO Zone term loans, net of debt issuance costs of $1 and $2, respectively, bearing a weighted-average interest rate of 2.6% and 3.1%, respectively 199 198 Other 49 4 Total long-term debt 9,187 9,143 Total debt (3) $ 9,691 $ 9,209 (1) We classified these commercial paper notes and credit facility borrowings as short-term as of December 31, 2019, 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) As of December 31, 2018, we classified our $500 million, 2.60% senior notes due December 2019 as long-term based on our ability and intent to refinance such amounts on a long-term basis. (3) Our fixed-rate senior notes had a face value of approximately $9.0 billion at both December 31, 2019 and 2018. We estimated the aggregate fair value of these notes as of December 31, 2019 and 2018 to be approximately $9.3 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 the end of the reporting period. We estimate that the carrying value of outstanding borrowings under our credit facilities and commercial paper program and GO Zone term loans approximates fair value as interest rates reflect current market rates. The fair value estimates for our senior notes, credit facilities, commercial paper program and GO Zone term loans 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 Agreements 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 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 GO Zone term loans . In August 2018, we entered into an agreement for two $100 million term loans (the “GO Zone term loans”) from the remarketing of our $100 million Mississippi Business Finance Corporation Gulf Opportunity Zone Industrial Development Revenue Bonds (PAA Natural Gas Storage, L.P. Project), Series 2009 and our $100 million Mississippi Business Finance Corporation Gulf Opportunity Zone Industrial Development Revenue Bonds (PAA Natural Gas Storage, L.P. Project), Series 2010 (collectively, the “GO Bonds”). The GO Zone term loans accrue interest in accordance with the interest payable on the related GO Bonds as provided in the GO Bonds Indenture pursuant to which such GO Bonds are issued and governed. The purchasers of the two GO Zone term loans have the right to put, at par, the GO Zone term loans in July 2023. The GO Bonds mature by their terms in May 2032 and August 2035, respectively. 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 the three years ended December 31, 2019 (in millions): Year Description Maturity Face Value Interest Payment Dates 2019 3.55% Senior Notes issued at 99.801% of face value December 2029 $ 1,000 June 15 and December 15 We did not issue any senior unsecured notes during the years ended December 31, 2018 or 2017. Senior Notes Repayments. During the three years ended December 31, 2019, we repaid the following senior unsecured notes (in millions): Year Description Repayment Date 2019 $500 million 2.60% Senior Notes due December 2019 November 2019 (1) 2019 $500 million 5.75% Senior Notes due January 2020 December 2019 (1) 2017 $400 million 6.13% Senior Notes due January 2017 January 2017 (2) 2017 $600 million 6.50% Senior Notes due May 2018 December 2017 (2) (3) 2017 $350 million 8.75% Senior Notes due May 2019 December 2017 (2) (3) (1) We repaid these senior notes with proceeds from our 3.55% senior notes issued in September 2019 and cash on hand. (2) We repaid these senior notes with cash on hand and proceeds from borrowings under our credit facilities and commercial paper program. (3) In conjunction with the early redemptions of these senior notes, we recognized a loss of approximately $40 million, recorded to “Other income/(expense), net” in our Consolidated Statement of Operations. Maturities The weighted average maturity of our senior notes and GO Zone term loans outstanding at December 31, 2019 was approximately 11 years. The following table presents the aggregate contractually scheduled maturities of such senior notes and GO Zone term loans for the next five years and thereafter. The amounts presented exclude unamortized discounts and debt issuance costs. Calendar Year Payment (in millions) 2020 $ — 2021 $ 600 2022 $ 750 2023 $ 1,300 2024 $ 750 Thereafter $ 5,800 Covenants and Compliance The credit agreements for our revolving credit facilities (which impact our ability to access our commercial paper program because they provide the financial backstop that supports our short-term credit ratings) and our term loans 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 finance 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 GO Zone term loans 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)). 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 agreements or indentures would permit the lenders to accelerate the maturity of the outstanding debt. As long as we are in compliance with the provisions contained in our credit agreements, our ability to make distributions of available cash is not restricted. As of December 31, 2019, we were in compliance with the covenants contained in our credit agreements and indentures. Borrowings and Repayments Total borrowings under our credit facilities and commercial paper program for the years ended December 31, 2019, 2018 and 2017 were approximately $13.3 billion, $45.4 billion and $60.8 billion, respectively. Total repayments under our credit facilities and commercial paper program were approximately $12.9 billion, $46.3 billion and $61.5 billion for the years ended December 31, 2019, 2018 and 2017, 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 and transportation of crude oil, NGL and natural gas. These letters of credit are issued under our senior unsecured revolving credit facility and our 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, including hedging-related margin obligations, and construction activities. At December 31, 2019 and 2018, we had outstanding letters of credit of $157 million and $184 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, 2019
Partners' Capital Notes [Abstract]
Partners' Capital and Distributions	Partners’ Capital and Distributions Units Outstanding At December 31, 2019, partners’ capital consisted of outstanding common units and Series A and Series B 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. Series A Preferred Units Our Series A preferred units were issued in a private placement in 2016 at a price of $26.25 per unit (the “Issue Price”). The Series A preferred units represent limited partner interests in us, rank pari passu with our Series B preferred units, and senior to our common units and to each other class 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). The holders 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, in whole or in part, subject to certain minimum conversion amounts (and not more often than once per quarter). We may convert the Series A preferred units into common units at any time (but not more often than once per quarter), 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 vote on an as-converted basis with our common units and 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 Series A preferred units into common units at the then applicable conversion rate. For a period of 30 days following (a) the fifth anniversary of the January 28, 2016 issuance date (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 Series A preferred unit distribution rate to equal the then applicable rate of ten-year U.S. Treasury Securities plus 5.85% (the “Preferred Distribution Rate Reset Option”). The Preferred Distribution Rate Reset Option is accounted for as an embedded derivative. See Note 13 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 our 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. Series B Preferred Units Our Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in us (the “Series B preferred units”) were issued in 2017 at a price to the public of $1,000 per unit, as discussed further below under — Issuances of Units . Our Series B preferred units represent perpetual equity interests in us, and they have no stated maturity or mandatory redemption date and are not redeemable at the option of the holders under any circumstances. Holders of the Series B preferred units generally have no voting rights, except for limited voting rights with respect to (i) potential amendments to our partnership agreement that would have a material adverse effect on the existing preferences, rights, powers or duties of the Series B preferred units, (ii) the creation or issuance of any parity securities if the cumulative distributions payable on then outstanding Series B preferred units are in arrears, (iii) the creation or issuance of any senior securities and (iv) the payment of distributions to our common unitholders out of capital surplus. The Series B preferred units rank, as to the payment of distributions and amounts payable on a liquidation event, pari passu with our outstanding Series A preferred units and senior to our common units. The Series B preferred units have a liquidation preference of $1,000 per unit. Holders of our Series B preferred units are entitled to receive, when, as and if declared by our general partner out of legally available funds for such purpose, cumulative semiannual or quarterly cash distributions, as applicable. Distributions on the Series B preferred units accrue and are cumulative from October 10, 2017, the date of original issue, and are payable semiannually in arrears on the 15th day of May and November through and including November 15, 2022, and after November 15, 2022, quarterly in arrears on the 15th day of February, May, August and November of each year. The initial distribution rate for the Series B preferred units from and including October 10, 2017 to, but not including, November 15, 2022 is 6.125% per year of the liquidation preference per unit (equal to $61.25 per unit per year). On and after November 15, 2022, distributions on the Series B preferred units will accumulate for each distribution period at a percentage of the liquidation preference equal to the Series B Three-Month LIBOR (as defined in and calculated pursuant to our Seventh Amended and Restated Agreement of Limited Partnership) plus a spread of 4.11%. Upon the occurrence of certain rating agency events, we may redeem the Series B preferred units, in whole but not in part, at a price of $1,020 (102% of the liquidation preference) per Series B preferred unit plus an amount equal to all accumulated and unpaid distributions thereon to, but not including, the date of redemption, whether or not declared. In addition, at any time on or after November 15, 2022, we may redeem the Series B preferred units, at our option, in whole or in part, at a redemption price of $1,000 per Series B preferred unit plus an amount equal to all accumulated and unpaid distributions thereon to, but not including, the date of redemption, whether or not declared. The following table presents the activity for our preferred and common units: Limited Partners Series A Preferred Units Series B Common Units Outstanding at December 31, 2016 64,388,853 — 669,194,419 Issuances of Series A preferred units in connection with in-kind distributions 5,307,689 — — Sale of Series B preferred units — 800,000 — Sales of common units — — 54,119,893 Issuance of common units in connection with acquisition of interest in Advantage Joint Venture (Note 7) — — 1,252,269 Issuances of common units under equity-indexed compensation plans — — 622,557 Outstanding at December 31, 2017 69,696,542 800,000 725,189,138 Issuance of Series A preferred units in connection with in-kind distribution 1,393,926 — — Issuances of common units under equity-indexed compensation plans — — 1,172,786 Outstanding at December 31, 2018 71,090,468 800,000 726,361,924 Issuances of common units under equity-indexed compensation plans — — 1,666,652 Outstanding at December 31, 2019 71,090,468 800,000 728,028,576 Issuances of Units Series B Preferred Unit Issuance On October 10, 2017, we issued 800,000 Series B preferred units at a price to the public of $1,000 per unit. We used the net proceeds of $788 million, after deducting the underwriters’ discounts and offering expenses, from the issuance of the Series B preferred units to repay amounts outstanding under our credit facilities and commercial paper program and for general partnership purposes. Common Unit Issuances Sales of Common Units. We did not conduct any sales of common units during the years ended December 31, 2019 or 2018. The following table summarizes our sales of common units during year ended December 31, 2017 (net proceeds in millions): Year Type of Offering Common Units Issued Net Proceeds (1) 2017 Continuous Offering Program 4,033,567 $ 129 (2) 2017 Omnibus Agreement (3) 50,086,326 (4) 1,535 2017 Total 54,119,893 $ 1,664 (1) Amounts are net of costs associated with the offerings. (2) We paid $1 million to sales agents in connection with common unit issuances under our Continuous Offering Program during the year ended December 31, 2017. (3) Pursuant to the Omnibus Agreement entered into on November 15, 2016 by the Plains Entities, PAGP used the net proceeds from the sale of PAGP Class A shares, after deducting the sales agents’ commissions and offering expenses, to purchase from AAP a number of AAP units equal to the number of PAGP Class A shares sold in such offering at a price equal to the net proceeds from such offering. Also pursuant to the Omnibus Agreement, immediately following such purchase and sale, AAP used the net proceeds it received from such sale of AAP units to purchase from us an equivalent number of our common units. (4) Includes (i) approximately 1.8 million common units issued to AAP in connection with PAGP’s issuance of Class A shares under its Continuous Offering Program and (ii) 48.3 million common units issued to AAP in connection with PAGP’s March 2017 underwritten offering. Issuance of Common Units for Earned AAP Class B units. During the years ended December 31, 2019 and 2018, pursuant to the Omnibus Agreement entered into on November 15, 2016 by the Plains Entities, we issued 232,425 and 559,649 common units, respectively, to AAP upon Class B units of AAP becoming earned. Distributions In accordance with our partnership agreement, after making distributions to holders of our outstanding preferred units, we distribute the remainder of our available cash to common unitholders of record within 45 days following the end of each quarter. 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. Our available cash also includes cash on hand resulting from borrowings made after the end of the quarter. Preferred Unit Distributions The following table details distributions paid to our preferred unitholders during the year presented (in millions, except unit data): Series A Preferred Unitholders Series B Preferred Unitholders Distribution (1) Cash Distribution (2) Year Cash Units 2019 $ 149 — $ 49 2018 $ 112 1,393,926 $ 49 2017 $ — 5,307,689 $ 5 (1) We elected to pay distributions on our Series A preferred units in additional Series A preferred units for each quarterly distribution from their issuance through the February 2018 distribution. Distributions on our Series A preferred units have been paid in cash since the May 2018 distribution. During 2018 and 2017, we issued additional Series A preferred units in lieu of cash distributions of $37 million and $139 million, respectively. (2) We paid a pro-rated initial distribution on the Series B preferred units on November 15, 2017 to holders of record at the close of business on November 1, 2017 in an amount equal to approximately $5.9549 per unit. On February 14, 2020, we paid a cash distribution of $37 million to our Series A preferred unitholders. At December 31, 2019, such amount was accrued as distributions payable in “Other current liabilities” on our Consolidated Balance Sheet. At December 31, 2019, approximately $6 million of accrued distributions payable to our Series B preferred unitholders was included in “Other current liabilities” on our Consolidated Balance Sheet. Common Unit Distributions The following table details distributions paid to common unitholders during the year presented (in millions, except per unit data): Distributions Paid Distributions per common unit Year Public AAP Total 2019 $ 632 $ 372 $ 1,004 $ 1.38 2018 $ 532 $ 339 $ 871 $ 1.20 2017 $ 849 $ 537 $ 1,386 $ 1.95 On January 8, 2020, we declared a cash distribution of $0.36 per unit on our outstanding common units. The total distribution of $262 million was paid on February 14, 2020 to unitholders of record at the close of business on January 31, 2020, for the period from October 1, 2019 through December 31, 2019. Of this amount, approximately $90 million was paid to AAP. Income Allocation We allocate net income for partners’ capital presentation purposes by applying the allocation methodology in our partnership agreement. Net income is allocated 100% to our common unitholders, after giving effect to income allocations for cash distributions to our Series A preferred unitholders and guaranteed payments attributable to our Series B preferred unitholders. In accordance with our partnership agreement, our Series A preferred unitholders are 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 distributions attributable to the period (whether paid in cash or in-kind) on our Series A and Series B preferred units. See Note 4 for additional information. Noncontrolling Interests in Subsidiaries In May 2019, we formed a joint venture, Red River Pipeline Company LLC (“Red River LLC”), with Delek Logistics Partners, LP (“Delek”) on our Red River pipeline system. We received approximately $128 million for Delek’s 33% interest in Red River LLC. We consolidate Red River LLC based on control, with Delek’s 33% interest accounted for as a noncontrolling interest. During the fourth quarter of 2017, we sold SLC Pipeline LLC, in which we previously owned a 75% interest and had consolidated under GAAP. As a result of this sale, the noncontrolling interest of 25% was derecognized. We did not have any noncontrolling interests in subsidiaries at December 31, 2018 or 2017. See Note 7 for additional information regarding the sale of SLC Pipeline LLC.

Derivatives and Risk Management

Derivatives and Risk Management Activities	12 Months Ended
	Dec. 31, 2019
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. At the inception of the hedging relationship, we assess whether the derivatives employed are highly effective in offsetting changes in cash flows of anticipated hedged transactions. Throughout the hedging relationship, retrospective and prospective hedge effectiveness is assessed on a qualitative basis. 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 sales 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, 2019, net derivative positions related to these activities included: • A net long position of 10.2 million barrels associated with our crude oil purchases, which was unwound ratably during January 2020 to match monthly average pricing. • A net short time spread position of 9.0 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through February 2021. • A net crude oil basis spread position of 5.9 million barrels at multiple locations through December 2021. These derivatives allow us to lock in grade basis differentials. • A net short position of 17.9 million barrels through December 2021 related to anticipated net sales of crude oil and NGL inventory. Storage Capacity Utilization — For capacity allocated to our supply and logistics operations, we have utilization risk in a backwardated market structure. As of December 31, 2019, we used derivatives to manage the risk that a portion of our storage capacity will not be utilized (an average of approximately 1.2 million barrels per month of storage capacity through January 2021). These positions involve no outright price exposure, but instead enable us to profitably use the capacity to store hedged crude oil. 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. The following table summarizes our open derivative positions utilized to hedge the price risk associated with anticipated purchases and sales related to our natural gas processing and NGL fractionation activities as of December 31, 2019. Notional Volume Remaining Tenor Natural gas purchases 46.4 Bcf December 2022 Propane sales (3.8) MMbls March 2021 Butane sales (1.9) MMbls March 2021 Condensate sales (WTI position) (0.7) MMbls March 2021 Power supply requirements (1) 1.0 TWh December 2022 (1) Power position to hedge a portion of our power supply requirements at our Canadian natural gas processing and fractionation plants. 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 with 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 expense associated with the underlying debt. The following table summarizes the terms of our outstanding interest rate derivatives as of December 31, 2019 (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 6/15/2020 3.06 % Cash flow hedge Currency Exchange Rate Risk Hedging Because a significant portion of our Canadian business is conducted in CAD we use foreign currency derivatives to minimize the risk of unfavorable changes in exchange rates. These instruments include foreign currency exchange contracts, forwards and options. Our use of foreign currency derivatives include (i) derivatives we use to hedge currency exchange risk created by the use of USD-denominated commodity derivatives to hedge commodity price risk associated with CAD-denominated commodity purchases and sales and (ii) foreign currency exchange contracts we use to manage our Canadian business cash requirements. The following table summarizes our open forward exchange contracts as of December 31, 2019 (in millions): USD CAD Average Exchange Rate USD to CAD Forward exchange contracts that exchange CAD for USD: 2020 $ 202 $ 266 $1.00 - $1.31 Forward exchange contracts that exchange USD for CAD: 2020 $ 207 $ 274 $1.00 - $1.32 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. See Note 12 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 designated as cash flow hedges, changes in fair value are deferred in AOCI and recognized in earnings in the periods during which the underlying hedged transactions are recognized in earnings. Derivatives that are not designated as a hedging instrument and derivatives that do not qualify for hedge accounting 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 derivatives recognized in earnings is as follows (in millions): Year Ended December 31, 2019 Location of Gain/(Loss) Commodity Foreign Currency Derivatives Preferred Distribution Interest Rate Derivatives Total Supply and Logistics segment revenues (1) $ 310 $ 8 $ — $ — $ 318 Field operating costs (1) 14 — — — 14 Interest expense, net (2) — — — (9) (9) Other income/(expense), net (1) — — 2 — 2 Total gain/(loss) on derivatives recognized in net income $ 324 $ 8 $ 2 $ (9) $ 325 Year Ended December 31, 2018 Location of Gain/(Loss) Commodity Foreign Currency Derivatives Preferred Distribution Interest Rate Derivatives Total Supply and Logistics segment revenues (1) $ 150 $ (23) $ — $ — $ 127 Field operating costs (1) (2) — — — (2) Interest expense, net (2) — — — (5) (5) Other income/(expense), net (1) — — (14) — (14) Total gain/(loss) on derivatives recognized in net income $ 148 $ (23) $ (14) $ (5) $ 106 Year Ended December 31, 2017 Location of Gain/(Loss) Commodity Foreign Currency Derivatives Preferred Distribution Rate Reset Option Interest Rate Derivatives Total Supply and Logistics segment revenues (1) $ (188) $ 8 $ — $ — $ (180) Field operating costs (1) (10) — — — (10) Depreciation and amortization (2) (3) — — — (3) Interest expense, net (2) — — — (18) (18) Other income/(expense), net (1) — — 13 — 13 Total gain/(loss) on derivatives recognized in net income $ (201) $ 8 $ 13 $ (18) $ (198) (1) Derivatives not designated as a hedge. (2) Derivatives in hedging relationships. The following table summarizes the derivative assets and liabilities on our Consolidated Balance Sheet on a gross basis as of December 31, 2019 (in millions): Derivatives Not Designated As Hedging Instruments Balance Sheet Location Commodity Foreign Currency Derivatives Preferred Distribution Rate Reset Option Total Interest Rate Derivatives (1) Total Derivatives Derivative Assets Other current assets $ 179 $ 4 $ — $ 183 $ — $ 183 Other long-term assets, net 24 — — 24 — 24 Other current liabilities 32 — — 32 — 32 Total Derivative Assets $ 235 $ 4 $ — $ 239 $ — $ 239 Derivative Liabilities Other current assets $ (37) $ (2) $ — $ (39) $ — $ (39) Other long-term assets, net — — — — — — Other current liabilities (56) (1) — (57) (44) (101) Other long-term liabilities and deferred credits (12) — (34) (46) — (46) Total Derivative Liabilities $ (105) $ (3) $ (34) $ (142) $ (44) $ (186) (1) Derivatives in hedging relationships. The following table summarizes the derivative assets and liabilities on our Consolidated Balance Sheet on a gross basis as of December 31, 2018 (in millions): Derivatives Not Designated As Hedging Instruments Balance Sheet Location Commodity Foreign Currency Derivatives Preferred Distribution Rate Reset Option Total Interest Rate Derivatives (1) Total Derivatives Derivative Assets Other current assets $ 441 $ — $ — $ 441 $ 2 $ 443 Other long-term assets, net 34 — — 34 — 34 Other long-term liabilities and deferred credits 3 — — 3 — 3 Total Derivative Assets $ 478 $ — $ — $ 478 $ 2 $ 480 Derivative Liabilities Other current assets $ (182) $ — $ — $ (182) $ — $ (182) Other long-term assets, net (7) — — (7) — (7) Other current liabilities (10) (9) — (19) (1) (20) Other long-term liabilities and deferred credits (9) — (36) (45) (8) (53) Total Derivative Liabilities $ (208) $ (9) $ (36) $ (253) $ (9) $ (262) (1) Derivatives in hedging relationships. Our financial derivatives, used for hedging risk, are governed through ISDA 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, 2019 December 31, 2018 Initial margin $ 73 $ 95 Variation margin posted/(returned) (45) (91) Letters of credit (73) (84) Net broker payable $ (45) $ (80) 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, 2019 December 31, 2018 Derivative Derivative Derivative Derivative Netting Adjustments: Gross position - asset/(liability) $ 239 $ (186) $ 480 $ (262) Netting adjustment (71) 71 (192) 192 Cash collateral paid/(received) (45) — (80) — Net position - asset/(liability) $ 123 $ (115) $ 208 $ (70) Balance Sheet Location After Netting Adjustments: Other current assets $ 99 $ — $ 181 $ — Other long-term assets, net 24 — 27 — Other current liabilities — (69) — (20) Other long-term liabilities and deferred credits — (46) — (50) $ 123 $ (115) $ 208 $ (70) As of December 31, 2019, there was a net loss of $259 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 transactions or (ii) interest expense accruals associated with underlying debt instruments. Of the total net loss deferred in AOCI at December 31, 2019, we expect to reclassify a net loss of $10 million to earnings in the next twelve months. We estimate that substantially all of the remaining deferred loss will be reclassified to earnings through 2050 as the underlying hedged transactions impact earnings. A portion of these amounts is based on market prices as of December 31, 2019; 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 unrealized gain/(loss) recognized in AOCI for derivatives (in millions): Year Ended December 31, 2019 2018 2017 Interest rate derivatives, net $ (91) $ 38 $ (16) At December 31, 2019 and 2018, 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, 2019 Fair Value as of December 31, 2018 Recurring Fair Value Measures (1) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Commodity derivatives $ 42 $ 105 $ (17) $ 130 $ 171 $ 87 $ 12 $ 270 Interest rate derivatives — (44) — (44) — (7) — (7) Foreign currency derivatives — 1 — 1 — (9) — (9) Preferred Distribution Rate Reset Option — — (34) (34) — — (36) (36) Total net derivative asset/(liability) $ 42 $ 62 $ (51) $ 53 $ 171 $ 71 $ (24) $ 218 (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 and over-the-counter commodity contracts such as futures and swaps. The fair value of exchange-traded commodity derivatives and over-the-counter commodity contracts 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 observable markets with less volume and transaction frequency than active markets. In addition, it includes certain physical commodity contracts. The fair values of these derivatives are corroborated with market observable inputs. Level 3 Level 3 of the fair value hierarchy includes certain physical commodity and other contracts, over-the-counter options and the Preferred Distribution Rate Reset Option contained in our partnership agreement which is classified as an embedded derivative. The fair values of our Level 3 physical commodity and other contracts and over-the-counter options are based on valuation models utilizing significant timing estimates, which involve management judgment, and pricing inputs from observable and unobservable markets with less volume and transaction frequency than active markets. Significant deviations from these estimates and inputs could result in a material change in fair value. We report unrealized gains and losses associated with these 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, some of which involve management judgment. A significant change in 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 in “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, 2019 2018 Beginning Balance $ (24) $ (30) Net gains/(losses) for the period included in earnings 10 (13) Settlements (11) 7 Derivatives entered into during the period (26) 12 Ending Balance $ (51) $ (24) Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period $ (16) $ (1)

Leases

Leases	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Leases	Leases Lessee On January 1, 2019, we adopted Topic 842, Leases, using the optional transitional method, thereby applying the new guidance at the effective date, without adjusting the comparative periods. Therefore, results for reporting periods beginning after January 1, 2019 are presented under Topic 842, while prior period amounts are not adjusted and continue to be reported in accordance with our historic accounting under ASC Topic 840, Leases (“Topic 840”). We evaluate all agreements entered into or modified after the date of adoption of Topic 842 that convey to us the use of property or equipment for a term to determine whether the agreement is or contains a lease. We lease certain property and equipment under noncancelable and cancelable operating and finance leases. Our operating leases primarily relate to railcars, office space, land, vehicles, and storage tanks, and our finance leases primarily relate to tractor trailers, land, storage tanks and vehicles. One of our finance leases is for storage tanks owned by an equity method investee, in which we own a 50% interest. For leases with an initial term of greater than 12 months, we recognize a right-of-use asset and lease liability on the balance sheet. Leases with an initial term of 12 months or less are not recorded on the balance sheet. Our lease agreements have remaining lease terms ranging from one year to approximately 60 years. When applicable, this range includes additional terms associated with leases for which we are reasonably certain to exercise the option to renew and such renewal options are recognized as part of our right-of-use assets and lease liabilities. We have renewal options for leases with terms ranging from one year to 40 years that are not recognized as part of our right-of-use assets or lease liabilities as we have determined we are not reasonably certain to exercise the option to renew. Certain of our leases have variable lease payments, many of which are based on changes in market indices such as the Consumer Price Index. Our lease agreements for our tractor trailers contain residual value guarantees equal to the fair market value of the tractor trailers at the end of the lease term in the event that we elect not to purchase the asset for an amount equal to the fair value. Our lease agreements do not contain any material restrictive covenants. For determining the present value of lease payments, we use the discount rate implicit in the lease when readily determinable; however, such rate is not readily determinable for most of our leases. For those leases for which the discount rate is not readily determinable, we utilize incremental borrowing rates that reflect collateralized borrowing with payments and terms that mirror our lease portfolio to discount the lease payments based on information available at the lease commencement date. The following table presents components of lease cost for the year ended December 31, 2019, including both amounts recognized in income and amounts capitalized (in millions): Lease Cost Year Ended Operating lease cost $ 125 Short-term lease cost 35 Other (1) — Total lease cost $ 160 (1) Includes less than $1 million of net immaterial finance lease costs, variable lease costs and sublease income. Lease cost for the years ended December 31, 2018 and 2017, accounted for in accordance with Topic 840, was $199 million and $207 million, respectively. The following table presents information related to cash flows arising from lease transactions (in millions): Year Ended Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases $ 116 Financing cash flows for finance leases $ 18 Non-cash change in lease liabilities arising from obtaining new right-of-use assets or modifications: Operating leases $ 77 Finance leases (1) $ 27 (1) Includes approximately $12 million associated with leased storage tanks owned by an equity method investee, in which we own a 50% interest. Information related to the weighted-average remaining lease term and discount rate is presented in the table below: Year Ended Weighted-average remaining lease term (in years): Operating leases 11 Finance leases 6 Weighted-average discount rate: Operating leases 4.4 % Finance leases 7.1 % The following table presents the amount and location of our operating and finance lease right-of-use assets and liabilities on our Consolidated Balance Sheet (in millions): Leases Balance Sheet Location Year Ended Assets Operating lease right-of-use assets Long-term operating lease right-of-use assets, net $ 466 Finance lease right-of-use assets (1) Property and equipment $ 124 Accumulated depreciation (16) Property and equipment, net $ 108 Total lease right-of-use assets $ 574 Liabilities Operating lease liabilities Current Other current liabilities $ 94 Noncurrent Long-term operating lease liabilities 387 Total operating lease liabilities $ 481 Finance lease liabilities (1) Current Short-term debt $ 18 Noncurrent Other long-term debt, net 49 Total finance lease liabilities $ 67 Total lease liabilities $ 548 (1) Includes approximately $12 million right-of-use asset and lease liability associated with leased storage tanks owned by an equity method investee, in which we own a 50% interest. The following table presents the maturity of undiscounted cash flows for future minimum lease payments under noncancelable leases as of December 31, 2019 reconciled to our lease liabilities on our Consolidated Balance Sheet (amounts in millions): Operating Finance (2) Future minimum lease payments (1) : 2020 $ 109 $ 21 2021 87 12 2022 79 12 2023 60 9 2024 48 9 Thereafter 279 29 Total 662 92 Less: Present value discount (181) (25) Lease liabilities $ 481 $ 67 (1) Excludes future minimum payments for short-term and other immaterial leases not included on our Consolidated Balance Sheet. (2) Includes payments of approximately $2 million for each of the years ending 2020 through 2024 and approximately $23 million thereafter associated with leased storage tanks owned by an equity method investee, in which we own a 50% interest. We have entered into a lease that had not yet commenced as of December 31, 2019 with future minimum lease payments totaling approximately $66 million. This lease will be classified as a finance lease, is for crude oil storage tanks owned by an equity method investee in which we own a 50% interest, has a lease term of 16 years and will commence in April 2020. Lessor We evaluate all agreements entered into or modified after the date of adoption of Topic 842 that convey to others the use of property or equipment for a term to determine whether the agreement is or contains a lease. Significant judgment is required when determining whether a customer obtains the right to direct the use of identified property or equipment. The underlying assets associated with these agreements are evaluated for future use beyond the lease term. Our Facilities and Transportation segments enter into agreements to conduct fee-based activities associated with (i) providing storage services primarily for crude oil, NGL and natural gas and (ii) transporting crude oil and NGL. Certain of these agreements convey counterparties the right to direct the operation of physically distinct assets. Such agreements include (i) fixed consideration, which is measured based on an available capacity during the period multiplied by the rate in the agreement, or (ii) a fixed monthly fee and variable consideration based on usage. These agreements often include options to extend or terminate the lease, with advance notice. These agreements are operating leases under Topic 842. For the year ended December 31, 2019, our lease revenue was not material. The table below presents the maturity of lease payments for operating lease agreements in effect as of December 31, 2019. This presentation includes minimum fixed lease payments and does not include an estimate of variable lease consideration. These agreements have remaining lease terms ranging from two years to 22 years. The following table presents the undiscounted cash flows expected to be received related to these agreements (in millions): 2020 2021 2022 2023 2024 Thereafter Lease revenue $ 19 $ 22 $ 25 $ 21 $ 17 $ 208
Leases	Leases Lessee On January 1, 2019, we adopted Topic 842, Leases, using the optional transitional method, thereby applying the new guidance at the effective date, without adjusting the comparative periods. Therefore, results for reporting periods beginning after January 1, 2019 are presented under Topic 842, while prior period amounts are not adjusted and continue to be reported in accordance with our historic accounting under ASC Topic 840, Leases (“Topic 840”). We evaluate all agreements entered into or modified after the date of adoption of Topic 842 that convey to us the use of property or equipment for a term to determine whether the agreement is or contains a lease. We lease certain property and equipment under noncancelable and cancelable operating and finance leases. Our operating leases primarily relate to railcars, office space, land, vehicles, and storage tanks, and our finance leases primarily relate to tractor trailers, land, storage tanks and vehicles. One of our finance leases is for storage tanks owned by an equity method investee, in which we own a 50% interest. For leases with an initial term of greater than 12 months, we recognize a right-of-use asset and lease liability on the balance sheet. Leases with an initial term of 12 months or less are not recorded on the balance sheet. Our lease agreements have remaining lease terms ranging from one year to approximately 60 years. When applicable, this range includes additional terms associated with leases for which we are reasonably certain to exercise the option to renew and such renewal options are recognized as part of our right-of-use assets and lease liabilities. We have renewal options for leases with terms ranging from one year to 40 years that are not recognized as part of our right-of-use assets or lease liabilities as we have determined we are not reasonably certain to exercise the option to renew. Certain of our leases have variable lease payments, many of which are based on changes in market indices such as the Consumer Price Index. Our lease agreements for our tractor trailers contain residual value guarantees equal to the fair market value of the tractor trailers at the end of the lease term in the event that we elect not to purchase the asset for an amount equal to the fair value. Our lease agreements do not contain any material restrictive covenants. For determining the present value of lease payments, we use the discount rate implicit in the lease when readily determinable; however, such rate is not readily determinable for most of our leases. For those leases for which the discount rate is not readily determinable, we utilize incremental borrowing rates that reflect collateralized borrowing with payments and terms that mirror our lease portfolio to discount the lease payments based on information available at the lease commencement date. The following table presents components of lease cost for the year ended December 31, 2019, including both amounts recognized in income and amounts capitalized (in millions): Lease Cost Year Ended Operating lease cost $ 125 Short-term lease cost 35 Other (1) — Total lease cost $ 160 (1) Includes less than $1 million of net immaterial finance lease costs, variable lease costs and sublease income. Lease cost for the years ended December 31, 2018 and 2017, accounted for in accordance with Topic 840, was $199 million and $207 million, respectively. The following table presents information related to cash flows arising from lease transactions (in millions): Year Ended Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases $ 116 Financing cash flows for finance leases $ 18 Non-cash change in lease liabilities arising from obtaining new right-of-use assets or modifications: Operating leases $ 77 Finance leases (1) $ 27 (1) Includes approximately $12 million associated with leased storage tanks owned by an equity method investee, in which we own a 50% interest. Information related to the weighted-average remaining lease term and discount rate is presented in the table below: Year Ended Weighted-average remaining lease term (in years): Operating leases 11 Finance leases 6 Weighted-average discount rate: Operating leases 4.4 % Finance leases 7.1 % The following table presents the amount and location of our operating and finance lease right-of-use assets and liabilities on our Consolidated Balance Sheet (in millions): Leases Balance Sheet Location Year Ended Assets Operating lease right-of-use assets Long-term operating lease right-of-use assets, net $ 466 Finance lease right-of-use assets (1) Property and equipment $ 124 Accumulated depreciation (16) Property and equipment, net $ 108 Total lease right-of-use assets $ 574 Liabilities Operating lease liabilities Current Other current liabilities $ 94 Noncurrent Long-term operating lease liabilities 387 Total operating lease liabilities $ 481 Finance lease liabilities (1) Current Short-term debt $ 18 Noncurrent Other long-term debt, net 49 Total finance lease liabilities $ 67 Total lease liabilities $ 548 (1) Includes approximately $12 million right-of-use asset and lease liability associated with leased storage tanks owned by an equity method investee, in which we own a 50% interest. The following table presents the maturity of undiscounted cash flows for future minimum lease payments under noncancelable leases as of December 31, 2019 reconciled to our lease liabilities on our Consolidated Balance Sheet (amounts in millions): Operating Finance (2) Future minimum lease payments (1) : 2020 $ 109 $ 21 2021 87 12 2022 79 12 2023 60 9 2024 48 9 Thereafter 279 29 Total 662 92 Less: Present value discount (181) (25) Lease liabilities $ 481 $ 67 (1) Excludes future minimum payments for short-term and other immaterial leases not included on our Consolidated Balance Sheet. (2) Includes payments of approximately $2 million for each of the years ending 2020 through 2024 and approximately $23 million thereafter associated with leased storage tanks owned by an equity method investee, in which we own a 50% interest. We have entered into a lease that had not yet commenced as of December 31, 2019 with future minimum lease payments totaling approximately $66 million. This lease will be classified as a finance lease, is for crude oil storage tanks owned by an equity method investee in which we own a 50% interest, has a lease term of 16 years and will commence in April 2020. Lessor We evaluate all agreements entered into or modified after the date of adoption of Topic 842 that convey to others the use of property or equipment for a term to determine whether the agreement is or contains a lease. Significant judgment is required when determining whether a customer obtains the right to direct the use of identified property or equipment. The underlying assets associated with these agreements are evaluated for future use beyond the lease term. Our Facilities and Transportation segments enter into agreements to conduct fee-based activities associated with (i) providing storage services primarily for crude oil, NGL and natural gas and (ii) transporting crude oil and NGL. Certain of these agreements convey counterparties the right to direct the operation of physically distinct assets. Such agreements include (i) fixed consideration, which is measured based on an available capacity during the period multiplied by the rate in the agreement, or (ii) a fixed monthly fee and variable consideration based on usage. These agreements often include options to extend or terminate the lease, with advance notice. These agreements are operating leases under Topic 842. For the year ended December 31, 2019, our lease revenue was not material. The table below presents the maturity of lease payments for operating lease agreements in effect as of December 31, 2019. This presentation includes minimum fixed lease payments and does not include an estimate of variable lease consideration. These agreements have remaining lease terms ranging from two years to 22 years. The following table presents the undiscounted cash flows expected to be received related to these agreements (in millions): 2020 2021 2022 2023 2024 Thereafter Lease revenue $ 19 $ 22 $ 25 $ 21 $ 17 $ 208
Leases	Leases Lessee On January 1, 2019, we adopted Topic 842, Leases, using the optional transitional method, thereby applying the new guidance at the effective date, without adjusting the comparative periods. Therefore, results for reporting periods beginning after January 1, 2019 are presented under Topic 842, while prior period amounts are not adjusted and continue to be reported in accordance with our historic accounting under ASC Topic 840, Leases (“Topic 840”). We evaluate all agreements entered into or modified after the date of adoption of Topic 842 that convey to us the use of property or equipment for a term to determine whether the agreement is or contains a lease. We lease certain property and equipment under noncancelable and cancelable operating and finance leases. Our operating leases primarily relate to railcars, office space, land, vehicles, and storage tanks, and our finance leases primarily relate to tractor trailers, land, storage tanks and vehicles. One of our finance leases is for storage tanks owned by an equity method investee, in which we own a 50% interest. For leases with an initial term of greater than 12 months, we recognize a right-of-use asset and lease liability on the balance sheet. Leases with an initial term of 12 months or less are not recorded on the balance sheet. Our lease agreements have remaining lease terms ranging from one year to approximately 60 years. When applicable, this range includes additional terms associated with leases for which we are reasonably certain to exercise the option to renew and such renewal options are recognized as part of our right-of-use assets and lease liabilities. We have renewal options for leases with terms ranging from one year to 40 years that are not recognized as part of our right-of-use assets or lease liabilities as we have determined we are not reasonably certain to exercise the option to renew. Certain of our leases have variable lease payments, many of which are based on changes in market indices such as the Consumer Price Index. Our lease agreements for our tractor trailers contain residual value guarantees equal to the fair market value of the tractor trailers at the end of the lease term in the event that we elect not to purchase the asset for an amount equal to the fair value. Our lease agreements do not contain any material restrictive covenants. For determining the present value of lease payments, we use the discount rate implicit in the lease when readily determinable; however, such rate is not readily determinable for most of our leases. For those leases for which the discount rate is not readily determinable, we utilize incremental borrowing rates that reflect collateralized borrowing with payments and terms that mirror our lease portfolio to discount the lease payments based on information available at the lease commencement date. The following table presents components of lease cost for the year ended December 31, 2019, including both amounts recognized in income and amounts capitalized (in millions): Lease Cost Year Ended Operating lease cost $ 125 Short-term lease cost 35 Other (1) — Total lease cost $ 160 (1) Includes less than $1 million of net immaterial finance lease costs, variable lease costs and sublease income. Lease cost for the years ended December 31, 2018 and 2017, accounted for in accordance with Topic 840, was $199 million and $207 million, respectively. The following table presents information related to cash flows arising from lease transactions (in millions): Year Ended Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases $ 116 Financing cash flows for finance leases $ 18 Non-cash change in lease liabilities arising from obtaining new right-of-use assets or modifications: Operating leases $ 77 Finance leases (1) $ 27 (1) Includes approximately $12 million associated with leased storage tanks owned by an equity method investee, in which we own a 50% interest. Information related to the weighted-average remaining lease term and discount rate is presented in the table below: Year Ended Weighted-average remaining lease term (in years): Operating leases 11 Finance leases 6 Weighted-average discount rate: Operating leases 4.4 % Finance leases 7.1 % The following table presents the amount and location of our operating and finance lease right-of-use assets and liabilities on our Consolidated Balance Sheet (in millions): Leases Balance Sheet Location Year Ended Assets Operating lease right-of-use assets Long-term operating lease right-of-use assets, net $ 466 Finance lease right-of-use assets (1) Property and equipment $ 124 Accumulated depreciation (16) Property and equipment, net $ 108 Total lease right-of-use assets $ 574 Liabilities Operating lease liabilities Current Other current liabilities $ 94 Noncurrent Long-term operating lease liabilities 387 Total operating lease liabilities $ 481 Finance lease liabilities (1) Current Short-term debt $ 18 Noncurrent Other long-term debt, net 49 Total finance lease liabilities $ 67 Total lease liabilities $ 548 (1) Includes approximately $12 million right-of-use asset and lease liability associated with leased storage tanks owned by an equity method investee, in which we own a 50% interest. The following table presents the maturity of undiscounted cash flows for future minimum lease payments under noncancelable leases as of December 31, 2019 reconciled to our lease liabilities on our Consolidated Balance Sheet (amounts in millions): Operating Finance (2) Future minimum lease payments (1) : 2020 $ 109 $ 21 2021 87 12 2022 79 12 2023 60 9 2024 48 9 Thereafter 279 29 Total 662 92 Less: Present value discount (181) (25) Lease liabilities $ 481 $ 67 (1) Excludes future minimum payments for short-term and other immaterial leases not included on our Consolidated Balance Sheet. (2) Includes payments of approximately $2 million for each of the years ending 2020 through 2024 and approximately $23 million thereafter associated with leased storage tanks owned by an equity method investee, in which we own a 50% interest. We have entered into a lease that had not yet commenced as of December 31, 2019 with future minimum lease payments totaling approximately $66 million. This lease will be classified as a finance lease, is for crude oil storage tanks owned by an equity method investee in which we own a 50% interest, has a lease term of 16 years and will commence in April 2020. Lessor We evaluate all agreements entered into or modified after the date of adoption of Topic 842 that convey to others the use of property or equipment for a term to determine whether the agreement is or contains a lease. Significant judgment is required when determining whether a customer obtains the right to direct the use of identified property or equipment. The underlying assets associated with these agreements are evaluated for future use beyond the lease term. Our Facilities and Transportation segments enter into agreements to conduct fee-based activities associated with (i) providing storage services primarily for crude oil, NGL and natural gas and (ii) transporting crude oil and NGL. Certain of these agreements convey counterparties the right to direct the operation of physically distinct assets. Such agreements include (i) fixed consideration, which is measured based on an available capacity during the period multiplied by the rate in the agreement, or (ii) a fixed monthly fee and variable consideration based on usage. These agreements often include options to extend or terminate the lease, with advance notice. These agreements are operating leases under Topic 842. For the year ended December 31, 2019, our lease revenue was not material. The table below presents the maturity of lease payments for operating lease agreements in effect as of December 31, 2019. This presentation includes minimum fixed lease payments and does not include an estimate of variable lease consideration. These agreements have remaining lease terms ranging from two years to 22 years. The following table presents the undiscounted cash flows expected to be received related to these agreements (in millions): 2020 2021 2022 2023 2024 Thereafter Lease revenue $ 19 $ 22 $ 25 $ 21 $ 17 $ 208

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2019
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, 2019 and 2018, 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, 2019, 2018, and 2017 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, 2019 2018 2017 Current income tax expense: State income tax $ 3 $ 3 $ 1 Canadian federal and provincial income tax 109 63 27 Total current income tax expense $ 112 $ 66 $ 28 Deferred income tax expense/(benefit): Canadian federal and provincial income tax $ (46) $ 132 $ 16 Total deferred income tax expense/(benefit) $ (46) $ 132 $ 16 Total income tax expense $ 66 $ 198 $ 44 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, 2019 2018 2017 Income before tax $ 2,246 $ 2,414 $ 902 Partnership earnings not subject to current Canadian tax (1,769) (1,690) (756) $ 477 $ 724 $ 146 Canadian federal and provincial corporate tax rate 26 % 27 % 27 % Income tax at statutory rate $ 124 $ 195 $ 39 Canadian withholding tax $ — $ — $ 2 Canadian permanent differences and rate changes (61) — 2 State income tax 3 3 1 Total income tax expense $ 66 $ 198 $ 44 Deferred tax assets and liabilities are aggregated by the applicable tax paying entity and jurisdiction and result from the following (in millions): December 31, 2019 2018 Deferred tax assets: Lease liabilities $ 55 $ — Net operating losses 2 2 Other 16 21 Total deferred tax assets 73 23 Deferred tax liabilities: Property and equipment in excess of tax values (472) (449) Derivative instruments (22) (31) Lease assets (53) — Other (5) (42) Total deferred tax liabilities (552) (522) Net deferred tax liabilities $ (479) $ (499) Balance sheet classification of deferred tax assets/(liabilities): Other long-term assets, net $ 2 $ 2 Other long-term liabilities and deferred credits (481) (501) $ (479) $ (499) As of December 31, 2019, we had foreign net operating loss carryforwards of $9 million, which will expire beginning in 2034. Generally, tax returns for our Canadian entities are open to audit from 2015 through 2019. Our U.S. and state tax years are generally open to examination from 2016 to 2019. In reference to tax years 2008 to 2014, we have received notices of reassessment (“notices”) from the Canada Revenue Agency and the Alberta Tax and Revenue Administration (the “Canadian Tax Authorities”) related primarily to transfer pricing associated with cross-border intercompany financing transactions. These notices include assessments, including penalties and interest, associated with these transfer pricing matters totaling approximately $78 million (based on the exchange rate as of December 31, 2019). Payment of a portion of the assessment is required in order to file a notice of objection to dispute the reassessment. Accordingly, we have remitted approximately $48 million (based on the exchange rate as of December 31, 2019) related to the assessments, which is included in “Other long-term assets, net,” on our Consolidated Balance Sheets. We disagree with these notices and have contested the reassessments. We intend to vigorously defend our position, and we plan to pursue all remedies available to us to successfully resolve these matters, including administrative remedies with the Canadian Tax Authorities, and judicial remedies, if necessary. As of December 31, 2019, we believe that our tax position associated with these matters is “more likely than not” to be sustained and have not recognized any amounts for uncertainty in income taxes related to these notices. During the second quarter of 2019, the Alberta government enacted legislation that reduces the Alberta provincial corporate income tax rate from 12% to 8% over the period from July 1, 2019 through January 1, 2022. As a result, during the second quarter of 2019, we recognized a reduction of our deferred income tax liability of approximately $60 million and a corresponding deferred tax benefit.

Major Customers and Concentrati

Major Customers and Concentration of Credit Risk	12 Months Ended
	Dec. 31, 2019
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 12%, 14% and 19% of our revenues for the years ended December 31, 2019, 2018 and 2017, respectively. ExxonMobil Corporation and its subsidiaries accounted for 12%, 14% and 11% of our revenues for the years ended December 31, 2019, 2018 and 2017, respectively. Phillips 66 Company and its subsidiaries accounted for 11% of our revenues for each of the years ended December 31, 2019 and 2017. No other customers accounted for 10% or more of our revenues during any of the three years ended December 31, 2019. 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. 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 3 for additional discussion of our accounts receivable and our review of credit exposure.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2019
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions Ownership of PAGP Class C Shares As of December 31, 2019 and 2018, we owned 549,538,139 and 516,938,280, respectively, 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, a “pass-through” voting right through which our common unitholders and Series A preferred unitholders have the effective right to vote, pro rata with the holders of Class A and Class B shares of PAGP, for the election of eligible PAGP GP directors. Reimbursement of Our General Partner and its Affiliates Our general partner provides 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, 2019, 2018 and 2017 were $580 million, $494 million and $489 million, respectively. Omnibus Agreement The Plains Entities entered into an Omnibus Agreement on November 15, 2016, which provides for the following: • that 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 each of the years ended December 31, 2019, 2018 and 2017; • 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. During the year ended December 31, 2017, we issued approximately 1.8 million common units to AAP in connection with PAGP’s issuance of Class A shares under its Continuous Offering Program and 48.3 million common units to AAP in connection with PAGP’s March 2017 underwritten offering (See Note 12 for additional information); 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. Transactions with Other Related Parties Our other related parties include (i) principal owners and their affiliated entities and (ii) entities in which we hold investments and account for under the equity method of accounting (see Note 9 for information regarding such entities). We recognize as our principal owners entities that have a designated representative on the board of directors of PAGP GP and/or own greater than 10% of the limited partner interests in AAP. Such limited partner interests in AAP translates into a significantly smaller indirect ownership interest in PAA. We also consider subsidiaries or funds identified as affiliated with principal owners to be related parties. As of December 31, 2019, Kayne Anderson Capital Advisors, L.P. was a principal owner. Through various transactions by an affiliate of The Energy & Minerals Group (“EMG”) in May 2019, EMG ’ s limited partner interest in AAP was significantly reduced, which caused EMG to lose its right to designate a representative on the board of directors of PAGP GP. As a result, EMG ’ s board designee, John T. Raymond, was automatically removed from the PAGP GP board. Subsequent to such removal, Mr. Raymond was elected to continue to serve as a director of the PAGP GP board. Additionally, as a result of various transactions by Oxy in September 2019, Oxy no longer holds a limited partner interest in AAP and lost its right to designate a representative on the board of directors of PAGP GP. As a result, Oxy ’ s board designee, Oscar Brown, was automatically removed from the PAGP GP board. Following these transactions, we no longer recognize EMG or Oxy as a principal owner. During the three years ended December 31, 2019, we recognized sales and transportation revenues, purchased petroleum products and utilized transportation services from our principal owners and their affiliated entities and our equity method investees. 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 these transactions is included below (in millions): Year Ended December 31, 2019 2018 2017 Revenues from related parties (1) (2) $ 692 $ 1,067 $ 927 Purchases and related costs from related parties (2) $ 223 $ 410 $ 286 (1) A majority of these revenues are included in “Supply and Logistics segment revenues” on our Consolidated Statements of Operations. (2) Crude oil 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. Our receivable and payable amounts with these related parties as reflected on our Consolidated Balance Sheets were as follows (in millions): December 31, 2019 2018 Trade accounts receivable and other receivables, net from related parties (1) (2) $ 134 $ 144 Trade accounts payable to related parties (1) (2) (3) $ 102 $ 121 (1) We have a netting arrangement with certain related parties. Receivables and payables are presented net of such amounts. (2) Includes amounts related to crude oil purchases and sales, transportation services and amounts owed to us or advanced to us related to expansion projects of equity method investees where we serve as construction manager. (3) 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. A portion of our commitment to transport is supported by crude oil buy/sell agreements with third parties with commensurate quantities.

Equity-Indexed Compensation Pla

Equity-Indexed Compensation Plans	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Equity-Indexed Compensation Plans	Equity-Indexed Compensation Plans PAA Long-Term Incentive Plan Awards 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. We have elected to recognize forfeitures of awards when they occur. Our LTIP awards contain (i) time based vesting criteria, (ii) performance conditions based on the attainment of certain levels of four quarter trailing distributable cash flow (“DCF”) per common unit (or in some instances, per common unit and common equivalent unit) or (iii) a combination of time based vesting criteria and performance conditions based on four quarter trailing DCF per common unit (or per common unit and common equivalent unit). For awards with performance conditions, 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. The following is a summary of the awards authorized under our LTIPs as of December 31, 2019 (in millions): LTIP PAA LTIP Awards Authorized Plains All American 2013 Long-Term Incentive Plan 13.1 Plains All American PNG Successor Long-Term Incentive Plan 1.3 Plains All American GP LLC 2006 Long-Term Incentive Tracking Unit Plan 10.8 Total (1) 25.2 (1) Of the 25.2 million total awards authorized, 5.9 million awards are currently available. The remaining balance has already vested or is currently outstanding. Although other types of awards are contemplated under certain of the LTIPs, currently outstanding awards are limited to “phantom units,” which mature into the right to receive common units of PAA (or cash equivalent) upon vesting, and “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. 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. The DERs terminate with the vesting or forfeiture of the underlying LTIP award. As of December 31, 2019, 7.1 million LTIP awards were outstanding. Of this amount, 5.4 million include DERs. The outstanding and probable LTIP awards are expected to vest at various dates between January 2020 and August 2026. Our accrued liability at December 31, 2019 related to all outstanding liability-classified LTIP awards and DERs was $13 million, of which $10 million was classified as short-term and $3 million was classified as long-term. At December 31, 2018, the accrued liability was $27 million, of which $19 million was classified as short-term and $8 million was classified as long-term. These short- and long-term accrued LTIP liabilities are reflected in “Other current liabilities” and “Other long-term liabilities and deferred credits,” respectively, on our Consolidated Balance Sheets. 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) Units Weighted Average Outstanding at December 31, 2016 8.9 $ 29.62 Granted 0.9 $ 23.52 Vested (1.7) $ 42.12 Modified — $ (6.04) Cancelled or forfeited (0.8) $ 26.99 Outstanding at December 31, 2017 7.3 $ 24.68 Granted 1.7 $ 23.44 Vested (1.7) $ 32.42 Modified — $ 2.15 Cancelled or forfeited (0.5) $ 21.99 Outstanding at December 31, 2018 6.8 $ 22.19 Granted 3.9 $ 16.17 Vested (3.3) $ 22.44 Cancelled or forfeited (0.3) $ 23.12 Outstanding at December 31, 2019 7.1 $ 18.67 (1) Approximately 1.4 million, 0.6 million and 0.6 million PAA common units were issued, net of tax withholding of approximately 0.6 million, 0.2 million and 0.2 million units during 2019, 2018 and 2017, respectively, in connection with the settlement of vested awards. The remaining PAA awards (approximately 1.3 million, 0.9 million and 0.9 million units) that vested during 2019, 2018 and 2017, respectively, were settled in cash. Equity-Indexed Compensation Plan Information We refer to all of the LTIPs 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): 2019 2018 2017 Equity-indexed compensation expense $ 34 $ 79 $ 41 LTIP unit-settled vestings $ 47 $ 21 $ 16 LTIP cash-settled vestings $ 31 $ 22 $ 25 Based on the December 31, 2019 fair value measurement and probability assessment regarding future performance conditions based on distributable cash flow measures determined by management, we expect to recognize $52 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 distributable cash flow measures. 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) 2020 $ 22 2021 13 2022 7 2023 4 2024 2 Thereafter 4 Total $ 52 (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, 2019.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2019
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 noncancelable commitments related to these items at December 31, 2019 are summarized below (in millions): 2020 2021 2022 2023 2024 Thereafter Total Leases (1) $ 130 $ 99 $ 91 $ 69 $ 57 $ 308 $ 754 Other commitments (2) 272 296 292 276 271 968 2,375 Total $ 402 $ 395 $ 383 $ 345 $ 328 $ 1,276 $ 3,129 (1) Includes both operating and finance leases as defined by FASB guidance. Leases are primarily for (i) railcars, (ii) office space, (iii) land, (iv) vehicles, (v) storage tanks and (vi) tractor trailers. See Note 14 for additional information. (2) Primarily includes third-party storage and transportation agreements and pipeline throughput agreements, as well as approximately $1.8 billion associated with agreements to store, process and transport crude oil at posted tariff rates on pipelines or at facilities that are owned by equity method investees, in which we own a 50% interest. A portion of our commitment to transport is supported by crude oil buy/sell agreements with third parties with commensurate quantities. Expense associated with these storage, transportation and throughput agreements was approximately $236 million, $228 million and $197 million for 2019, 2018 and 2017, respectively. 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, 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, 2019, our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident, as discussed further below) totaled $140 million, of which $60 million was classified as short-term and $80 million was classified as long-term. At December 31, 2018, our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident) totaled $135 million, of which $43 million was classified as short-term and $92 million was classified as long-term. Such short- and long-term environmental liabilities are reflected in “Other current liabilities” and “Other long-term liabilities and deferred credits,” respectively, on our Consolidated Balance Sheets. At December 31, 2019, we had recorded receivables totaling $72 million for amounts probable of recovery under insurance and from third parties under indemnification agreements, of which $35 million was classified as short-term and $37 million was classified as long-term. At December 31, 2018, we had recorded $61 million of such receivables, of which $28 million was classified as short-term and $33 million was classified as long-term. Such short- and long-term receivables are reflected in “Trade accounts receivable and other receivables, net” and “Other long-term assets, net,” respectively, on our Consolidated Balance Sheets. 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 included the United States Coast Guard, the EPA, the State of California Department of Fish and Wildlife (“CDFW”), 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, and the Unified Command has been dissolved. Our estimate of the amount of oil spilled, based on relevant facts, data and information, is approximately 2,934 barrels; of this amount, we estimate that 598 barrels reached the Pacific Ocean. 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 12, 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 obligated 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 imposed a pressure restriction on the section of Line 903 between Pentland Pump Station and Emidio Pump Station, which was subsequently lifted, and required 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, with the exception of the Pentland to Emidio segment of Line 903, which remains in service. 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 brought any such civil or criminal charges with respect to the Line 901 release, their investigation is still open and we are likely to have fines or penalties imposed upon us, and civil charges brought against us, in the future. In late May of 2015, the California Attorney General’s Office and the District Attorney’s office for the County of Santa Barbara (collectively, the “Prosecutors”) 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 May 2016 Indictment included a total of 46 counts against PAA. On July 28, 2016, at an arraignment hearing held in California Superior Court in Santa Barbara County, PAA pled not guilty to all counts. Between May of 2016 and May of 2018, 31 of the criminal charges against PAA (including one felony charge) and all of the criminal charges against our employee, were dismissed. The remaining 15 charges were the subject of a jury trial in California Superior Court in Santa Barbara County that began in May of 2018. The jury returned a verdict on September 7, 2018, pursuant to which we were (i) found guilty on one felony discharge count and eight misdemeanor counts (which included one reporting count, one strict liability discharge count and six strict liability animal takings counts) and (ii) found not guilty on one strict liability animal takings count. The jury deadlocked on three counts (including two felony discharge counts and one strict liability animal takings count), and two misdemeanor discharge counts were dropped. On April 25, 2019, PAA was sentenced to pay fines and penalties in the aggregate amount of just under $3.35 million for the convictions covered by the September 2018 jury verdict (the “2019 Sentence”). The fines and penalties imposed in connection with the 2019 Sentence have been paid. The Superior Court also indicated that it would conduct further hearings on the issue of whether there were any “direct victims” of the spill that are entitled to restitution under applicable law. We do not anticipate that the victim restitution, if any, imposed as a result of these proceedings will have a material adverse impact on the financial position or operations of the Partnership. In April of 2019, the Prosecutors announced their intent to re-try the two felony discharge counts for which no jury verdict was returned. The strict liability animal taking count for which no jury verdict was returned has been dismissed. On October 7, 2019, upon motion from Plains, the court dismissed the two remaining felony counts and vacated a second trial on these 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 have cooperated with the DOJ’s investigation by responding to their requests for documents and access to our 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. Except in connection with the May 2016 Indictment and the 2019 Sentence, to date no civil enforcement actions or criminal charges with respect to the Line 901 release have been brought against PAA or any of its affiliates, officers or employees by PHMSA, the DOJ, the EPA, the California Attorney General or the California Department of Fish and Wildlife, and no fines or penalties have been imposed by such governmental agencies; however, 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 in the future, or civil actions 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 have been processing those claims and making payments as appropriate. 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. To date, the court has certified three sub-classes of claimants and denied certification of the other proposed sub-class. On appeal, the Ninth Circuit Court of Appeals overturned the certification of the oil-industry sub-class, so the remaining sub-classes that have been certified include (i) commercial fishermen who landed fish in certain specified fishing blocks in the waters adjacent to Santa Barbara County or persons or businesses who resold commercial seafood landed in such areas; and (ii) beachfront property and easement owners whose properties were oiled. 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 were also 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 were consolidated into a single proceeding in the United States District Court for the Southern District of Texas. In general, these lawsuits alleged 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 claimed unspecified damages as a result of the reduction in value of their investments in the Partnership and PAGP, which they attributed to the alleged wrongful acts of the defendants. The Partnership and PAGP, and the other defendants, denied the allegations in, and moved to dismiss these lawsuits. On March 29, 2017, the Court ruled in our favor dismissing all claims against all defendants. Plaintiffs refiled their complaint. On April 2, 2018, the Court dismissed all of the refiled claims against all defendants with prejudice. Plaintiffs appealed the dismissal, and on July 16, 2019 the Fifth Circuit Court of Appeals affirmed the dismissal. The time period for a further appeal to the U.S. Supreme Court has lapsed so this ruling is now final. Consistent with and subject to the terms of our governing organizational documents (and to the extent applicable, insurance policies), we indemnified and funded the defense costs of our officers and directors in connection with this lawsuit; we also indemnified and funded 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 PAGP and certain of the Partnership’s affiliates, officers and directors. One lawsuit was filed in State District Court in Harris County, Texas and subsequently dismissed by the Court. 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 and subsequently dismissed without prejudice. Plaintiffs amended and refiled their complaint on June 3, 2019. All claims against the officers and directors of the Partnership and all affiliates of the Partnership, except PAGP, were dismissed with prejudice in January 2020. Consistent with and subject to the terms of our governing organizational documents (and to the extent applicable, insurance policies), we have indemnified and funded the defense costs of our officers and directors in connection with these lawsuits. We will vigorously defend the remaining derivative claim against PAGP. We have also received several other individual lawsuits and complaints from companies, governmental agencies 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. In this regard, following the Line 901 incident, we entered into a cooperative Natural Resource Damage Assessment (“NRDA”) process with the following federal and state agencies designated or authorized by law to act as trustees for the natural resources of the United States and the State of California (collectively, the “Trustees”): the United States Department of Interior, the National Oceanic and Atmospheric Administration, CDFW, the California Department of Parks and Recreation, the California State Lands Commission, and the Regents of the University of California. As part of the NRDA process, the Partnership and the Trustees jointly and independently planned and conducted a number of natural resource assessment activities related to the Line 901 incident. We are currently involved in discussions with the Trustees to determine the amount we will be required to pay as compensation for injuries to, destruction of, loss of, or loss of use of natural resources resulting from the Line 901 incident. We also have exposure to the payment of additional fines, penalties and costs under other applicable federal, state and local laws, statutes and regulations. We are actively involved in discussions with the relevant federal and state agencies to determine the amount of such fines, penalties and costs, and we have included an estimate of such costs in the loss accrual described below. To the extent any unpaid natural resource damages or other fines, penalties or 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, 2019, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $390 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. We accrue such estimates of aggregate total costs to “Field operating costs” in our Consolidated Statements of Operations. 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 duration of the natural resource damage assessment process and the ultimate amount of damages determined, (ii) 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, (iii) the determination and calculation of fines and penalties, but excluding fines and penalties that are not probable or reasonably estimable and (iv) 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. As of December 31, 2019, we had a remaining undiscounted gross liability of $83 million related to this event, of which approximately $50 million is presented in “Other current 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, 2019, we had collected, subject to customary reservations, $203 million out of the approximate $265 million of release costs that we believe are probable of recovery from insurance carriers, net of deductibles. Therefore, as of December 31, 2019, we have recognized a receivable of approximately $62 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 $28 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 completed the required clean-up and remediation work as determined by the Unified Command and the Unified Command has been dissolved; however, we expect to make payments for additional costs associated with restoration of the impacted areas, as well as natural resource damage assessment and compensation, legal, professional and regulatory costs, in addition to fines and penalties, during future periods. San Joaquin Valley Air Pollution Control District. After conducting inspections of the Plains LPG Services, L.P. (“Plains LPG”) facility in Shafter, California during March and June of 2018, the San Joaquin Valley Air Pollution Control District (the “District”) issued four Notices of Violation which totaled $597,000 in the aggregate. Plains LPG entered into a settlement with the District whereby Plains LPG agreed to enter the District’s INSPECT program (a self-reporting and inspection program) and pay a reduced fine of $275,000, which was paid in July 2019 . 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 hydrocarbon products into the environment from our pipeline, rail, storage and other facility 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 to cover our operations and properties, and we self-insure certain risks, including gradual pollution, cybersecurity and named windstorms. 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. With respect to our insurance coverage, our policies are subject to deductibles and retention levels that we consider reasonable and not excessive. Additionally, 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 h

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2019
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) 2019 Total revenues $ 8,375 $ 8,253 $ 7,886 $ 9,154 $ 33,669 Gross margin (2) $ 790 $ 526 $ 566 $ 403 $ 2,285 Operating income $ 714 $ 451 $ 492 $ 331 $ 1,988 Net income $ 970 $ 448 $ 454 $ 307 $ 2,180 Net income attributable to PAA $ 970 $ 446 $ 449 $ 306 $ 2,171 Basic net income per common unit $ 1.26 $ 0.54 $ 0.55 $ 0.35 $ 2.70 Diluted net income per common unit $ 1.20 $ 0.54 $ 0.55 $ 0.35 $ 2.65 Cash distributions per common unit (3) $ 0.30 $ 0.36 $ 0.36 $ 0.36 $ 1.38 2018 Total revenues $ 8,398 $ 8,080 $ 8,792 $ 8,786 $ 34,055 Gross margin (2) $ 460 $ 168 $ 567 $ 1,399 $ 2,593 Operating income $ 381 $ 88 $ 493 $ 1,315 $ 2,277 Net income $ 288 $ 100 $ 710 $ 1,117 $ 2,216 Net income attributable to PAA $ 288 $ 100 $ 710 $ 1,117 $ 2,216 Basic net income per common unit $ 0.33 $ 0.07 $ 0.91 $ 1.46 $ 2.77 Diluted net income per common unit $ 0.33 $ 0.07 $ 0.87 $ 1.38 $ 2.71 Cash distributions per common unit (3) $ 0.30 $ 0.30 $ 0.30 $ 0.30 $ 1.20 (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, (iii) Depreciation and amortization and (iv) (Gains)/losses on asset sales and asset impairments, net. (3) Represents cash distributions declared and paid in the period presented.

Operating Segments

Operating Segments	12 Months Ended
	Dec. 31, 2019
Segment Reporting [Abstract]
Operating Segments	Operating Segments We manage our operations through three operating segments: Transportation, Facilities and Supply and Logistics. See Note 3 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. 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, and gains and losses on significant asset sales by, unconsolidated entities, and further adjusted for certain selected items including (i) gains and losses on 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 the applicable amounts subsequently recognized into revenue and (v) other items that our CODM believes are integral to understanding our core segment operating performance. Segment Adjusted EBITDA excludes depreciation and amortization. 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 and/or refurbishment 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 tables reflect certain financial data for each segment (in millions): Transportation Facilities Supply and Intersegment Total Year Ended December 31, 2019 Revenues: External customers (1) $ 1,259 $ 609 $ 32,272 $ (471) $ 33,669 Intersegment (2) 1,061 562 4 471 2,098 Total revenues of reportable segments $ 2,320 $ 1,171 $ 32,276 $ — $ 35,767 Equity earnings in unconsolidated entities $ 388 $ — $ — $ 388 Segment Adjusted EBITDA $ 1,722 $ 705 $ 803 $ 3,230 Capital expenditures (3) $ 1,127 $ 227 $ 33 $ 1,387 Maintenance capital $ 161 $ 97 $ 29 $ 287 As of December 31, 2019 Total assets $ 14,902 $ 7,336 $ 6,439 $ 28,677 Investments in unconsolidated entities $ 3,557 $ 126 $ — $ 3,683 Transportation Facilities Supply and Intersegment Total Year Ended December 31, 2018 Revenues: External customers (1) $ 1,116 $ 588 $ 32,819 $ (468) $ 34,055 Intersegment (2) 874 573 3 468 1,918 Total revenues of reportable segments $ 1,990 $ 1,161 $ 32,822 $ — $ 35,973 Equity earnings in unconsolidated entities $ 375 $ — $ — $ 375 Segment Adjusted EBITDA $ 1,508 $ 711 $ 462 $ 2,681 Capital expenditures (3) $ 1,631 $ 234 $ 23 $ 1,888 Maintenance capital $ 139 $ 100 $ 13 $ 252 As of December 31, 2018 Total assets $ 13,288 $ 7,200 $ 5,023 $ 25,511 Investments in unconsolidated entities $ 2,594 $ 108 $ — $ 2,702 Transportation Facilities Supply and Intersegment Total Year Ended December 31, 2017 Revenues: External customers (1) $ 1,021 $ 555 $ 25,056 $ (409) $ 26,223 Intersegment (2) 697 618 9 409 1,733 Total revenues of reportable segments $ 1,718 $ 1,173 $ 25,065 $ — $ 27,956 Equity earnings in unconsolidated entities $ 290 $ — $ — $ 290 Segment Adjusted EBITDA $ 1,287 $ 734 $ 60 $ 2,081 Capital expenditures (3) $ 2,126 $ 312 $ 20 $ 2,458 Maintenance capital $ 120 $ 114 $ 13 $ 247 As of December 31, 2017 Total assets $ 12,661 $ 7,313 $ 5,377 $ 25,351 Investments in unconsolidated entities $ 2,681 $ 75 $ — $ 2,756 (1) Transportation revenues from External customers include certain inventory exchanges with our customers where our Supply and Logistics segment has transacted the inventory exchange and serves as the shipper on our pipeline systems. See Note 3 for a discussion of our related accounting policy. We have included an estimate of the revenues from these inventory exchanges in our Transportation segment revenues from External customers presented above and adjusted those revenues out such that Total revenues from External customers reconciles to our Consolidated Statements 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 activities are conducted at posted tariff rates where applicable, or otherwise at 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, 2019 2018 2017 Segment Adjusted EBITDA $ 3,230 $ 2,681 $ 2,081 Adjustments (1) : Depreciation and amortization of unconsolidated entities (2) (62) (56) (45) Gains/(losses) from derivative activities net of inventory valuation adjustments (3) (160) 519 46 Long-term inventory costing adjustments (4) 20 (21) 24 Deficiencies under minimum volume commitments, net (5) 18 (7) (2) Equity-indexed compensation expense (6) (17) (55) (23) Net gain/(loss) on foreign currency revaluation (7) (14) (3) 26 Line 901 incident (8) (10) — (32) Significant acquisition-related expenses (9) — — (6) Depreciation and amortization (601) (520) (517) Gains/(losses) on asset sales and asset impairments, net (28) 114 (109) Gain on investment in unconsolidated entities 271 200 — Interest expense, net (425) (431) (510) Other income/(expense), net 24 (7) (31) Income before tax 2,246 2,414 902 Income tax expense (66) (198) (44) Net income 2,180 2,216 858 Net income attributable to noncontrolling interests (9) — (2) Net income attributable to PAA $ 2,171 $ 2,216 $ 856 (1) Represents adjustments utilized by our CODM in the evaluation of segment results. (2) Includes our proportionate share of the depreciation and amortization of, and gains and losses on significant asset sales by, unconsolidated entities. (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. (6) Includes equity-indexed compensation expense associated with awards that will or may be settled in units. (7) Includes gains and losses realized on the settlement of foreign currency transactions as well as the revaluation of monetary assets and liabilities denominated in a foreign currency. (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. See Note 19 for additional information regarding the Line 901 incident. (9) Includes acquisition-related expenses associated with the ACC Acquisition. See Note 7 for additional discussion. An adjustment for these non-recurring expenses is included in the calculation of Segment Adjusted EBITDA for the year ended December 31, 2017 as our CODM does not view such expenses as integral to understanding our core segment operating performance. 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) 2019 2018 2017 United States $ 27,162 $ 28,362 $ 21,443 Canada 6,507 5,693 4,780 $ 33,669 $ 34,055 $ 26,223 (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) 2019 2018 United States $ 17,565 $ 15,885 Canada 3,935 3,542 $ 21,500 $ 19,427 (1) Excludes long-term derivative assets, long-term deferred tax assets and goodwill.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
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, 2019 and 2018, 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, 2019, 2018 and 2017. 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. 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, as well as the disclosure of contingent assets and liabilities at the date of the financial statements. Such estimates and assumptions also affect 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) impairment assessments of goodwill and intangible assets, (iii) fair value of derivatives, (iv) accruals and contingent liabilities, (v) equity-indexed compensation plan accruals, (vi) property and equipment, depreciation and amortization expense, asset retirement obligations and impairments, (vii) allowance for doubtful accounts and (viii) inventory valuations. Although we believe these estimates are reasonable, actual results could differ from these estimates.
Purchases and Related Costs	Purchases and Related Costs Purchases and related costs include (i) the weighted average cost of crude oil, NGL and natural gas sold to customers, (ii) fees incurred for 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 sold, which are recognized at the time title transfers to our customers. Inventory exchanges under buy/sell transactions are presented net 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 payroll, compensation and benefits costs for operations personnel; fuel and power costs (including the impact of gains and losses from derivative related activities); third-party trucking transportation costs for our U.S. crude oil operations; maintenance and integrity management costs; regulatory compliance; environmental remediation; insurance; costs for usage of third-party owned pipeline, rail and storage assets; vehicle leases; and property taxes. General and administrative expenses consist primarily of payroll, compensation and benefits costs; 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.
Cash and Cash Equivalents and Restricted Cash	Cash and Cash Equivalents and Restricted Cash 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, unless they may be covered by funds on deposit, outstanding checks are classified as trade accounts payable rather than negative cash. As of December 31, 2019 and 2018, trade accounts payable included $38 million and $57 million, respectively, of outstanding checks that were reclassified from cash and cash equivalents.
Noncontrolling Interests	Noncontrolling Interests Noncontrolling interest represents the portion of assets and liabilities in a consolidated subsidiary that is owned by a third party. FASB guidance requires all entities to report noncontrolling interests in subsidiaries as a component of equity in the consolidated financial statements. See Note 12 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.
Fair Value Measurements	Fair Value MeasurementsFinancial 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.
Recent Accounting Pronouncements	Recent Accounting Pronouncements In December 2019, the FASB issued 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes , to simplify the accounting for income taxes based on changes suggested by stakeholders as part of the FASB’s simplification initiative. This guidance is effective for interim and annual periods beginning after December 15, 2020, with early adoption permitted. We expect to adopt this guidance on January 1, 2021, and we are currently evaluating the effect that our adoption of this guidance will have on our financial position, results of operations and cash flows. In April 2019, the FASB issued 2019-04, Codification Improvements to Topic 326, Financial Instruments—Credit Losses, Topic 815, Derivatives and Hedging, and Topic 825, Financial Instruments , which clarifies certain aspects of accounting for credit losses, hedging activities and financial instruments. We will adopt this guidance effective January 1, 2020, and do not anticipate that the adoption will have a material impact on our financial position, results of operations or cash flows. In October 2018, the FASB issued ASU 2018-17, Consolidation (Topic 810): Targeted Improvements to Related Party Guidance for Variable Interest Entities , in response to stakeholder observations that improvements could be made by requiring reporting entities to consider indirect interests held through related parties under common control on a proportional basis rather than as the equivalent of a direct interest in its entirety as currently required in GAAP. This guidance is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted. We will adopt this guidance effective January 1, 2020, and do not anticipate that the adoption will have a material impact on our financial position, results of operations or cash flows. In October 2018, the FASB issued ASU 2018-16, Derivatives and Hedging (Topic 815): Inclusion of the Secured Overnight Financing Rate (SOFR) Overnight Index Swap (OIS) Rate as a Benchmark Interest Rate for Hedge Accounting Purposes, to include the OIS rate based on SOFR as an eligible benchmark interest rate during the early stages of the marketplace transition to facilitate the LIBOR to SOFR transition and provide sufficient lead time for entities to prepare for changes to interest rate risk hedging strategies for both risk management and hedge accounting purposes . This guidance is effective for interim and annual periods beginning after December 15, 2018, and must be adopted concurrently with the amendments in ASU 2017-12 (see below). We adopted this guidance effective January 1, 2019, and our adoption did not have a material impact on our financial position, results of operations or cash flows. In August 2018, the FASB issued ASU 2018-15, Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (a consensus of the FASB Emerging Issues Task Force) , to address the accounting for implementation costs of a hosting arrangement that is a service contract and to align the accounting for implementation costs for hosting arrangements, regardless of whether they convey a license to the hosted software. This guidance is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted. We will adopt this guidance effective January 1, 2020, and do not anticipate that the adoption will have a material impact on our financial position, results of operations or cash flows. In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement , modifying the disclosure requirements on fair value measurements in Topic 820. This guidance is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted. We will adopt this guidance effective January 1, 2020, and will apply the new guidance to any applicable disclosures. In July 2018, the FASB issued ASU 2018-09, Codification Improvements , which makes updates for clarifications, technical corrections and other minor improvements to a wide variety of Topics to make the ASC easier to understand and to apply. The transition and effective date is based on the facts and circumstances of each amendment with some amendments effective upon issuance. The remaining amendments are effective for annual periods beginning after December 15, 2018. We adopted this guidance effective January 1, 2019, and our adoption did not have a material impact on our financial position, results of operations or cash flows. In June 2018, the FASB issued ASU 2018-07, Compensation—Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting , which expands the scope of Topic 718 to include share-based payment awards to nonemployees and eliminates the classification differences for employee and nonemployee share-based payment awards. This guidance is effective for interim and annual periods beginning after December 15, 2018, with early adoption permitted. We adopted this guidance effective January 1, 2019, and our adoption did not have a material impact on our financial position, results of operations or cash flows. In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities, to better align an entity’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. Under the new guidance, (i) more financial and nonfinancial hedging strategies will be eligible for hedge accounting, (ii) presentation and disclosure requirements are amended and (iii) companies will change the way they assess effectiveness. This guidance is effective for interim and annual periods beginning after December 15, 2018, with early adoption permitted. We adopted this guidance effective January 1, 2019, and our adoption did not have a material impact on our financial position, results of operations or cash flows. In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (followed by a series of related accounting standard updates), which amends guidance on the impairment of financial instruments and adds an impairment model (known as the current expected credit loss (or CECL) model) that is based on expected losses rather than incurred losses. This guidance will become effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted by one year. We will adopt this guidance effective January 1, 2020, and do not anticipate that the adoption will have a material impact on our financial position, results of operations or cash flows. In February 2016, the FASB issued ASU 2016-02, Leases , (followed by a series of related accounting standard updates (collectively referred to as “Topic 842”)), 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 right-of-use assets and lease liabilities with lease terms of more than 12 months (with the election of the practical expedient to exclude short-term leases on the balance sheet), including extensive quantitative and qualitative disclosures. This guidance became effective for interim and annual periods beginning after December 15, 2018. We adopted this guidance effective January 1, 2019. Our adoption resulted in the recording of additional net lease right-of-use assets and lease liabilities of approximately $560 million and $570 million, respectively, on January 1, 2019, and did not have a material impact on our results of operations or cash flows.
Revenue Recognition	Revenue Recognition On January 1, 2018, we adopted Revenues from Contracts with Customers (“Topic 606”) using the modified retrospective approach applied to those contracts which were not completed as of January 1, 2018. Results for reporting periods beginning after January 1, 2018 are presented under Topic 606, while prior period amounts are not adjusted and continue to be reported in accordance with our historic accounting under ASC Topic 605, Revenue Recognition . Our Facilities segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services primarily for crude oil, 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 when we receive liquids from one connecting source and deliver the applicable product to another connecting carrier, fees from storage capacity agreements and fees associated with natural gas storage related activities (collectively “Crude oil, NGL and other terminalling and storage”), (ii) fees from natural gas and condensate processing services and from NGL fractionation and isomerization services (collectively, “NGL and natural gas processing and fractionation”) and (iii) loading and unloading fees at our rail terminals. We generate revenue through a combination of month-to-month and multi-year agreements and processing arrangements. Storage fees are typically recognized in revenue ratably over the term of the contract regardless of the actual storage capacity utilized as our performance obligation is to make available storage capacity for a period of time. Terminal fees (including throughput and rail fees) are recognized as the liquids enter or exit the terminal and are received from or delivered to the connecting carrier or third-party terminal, as applicable. Fees from NGL fractionation and isomerization services and gas processing services are recognized in the period when the services are performed. Natural gas storage related activities fees are recognized in the period the natural gas moves across our header system. We recognize rail loading and unloading fees when the volumes are delivered or received. Minimum Volume Commitments. We have certain agreements that require counterparties to 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’s make-up right as a contract liability 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. Remaining Performance Obligations . Topic 606 requires a presentation of information about partially and wholly unsatisfied performance obligations under contracts that exist as of the end of the period. The information includes the amount of consideration allocated to those remaining performance obligations and the timing of revenue recognition of those remaining performance obligations. Certain contracts meet the requirements for the presentation as remaining performance obligations. These arrangements include a fixed minimum level of service, typically a set volume of service, and do not contain any variability other than expected timing within a limited range. These contracts are all within the scope of Topic 606. The following table presents the amount of consideration associated with remaining performance obligations for the population of contracts with external customers meeting the presentation requirements as of December 31, 2019 (in millions): 2020 2021 2022 2023 2024 2025 and Thereafter Pipeline revenues supported by minimum volume commitments and capacity agreements (1) $ 164 $ 170 $ 170 $ 168 $ 146 $ 698 Storage, terminalling and throughput agreement revenues 404 312 242 188 147 366 Total $ 568 $ 482 $ 412 $ 356 $ 293 $ 1,064 (1) Calculated as volumes committed under contracts multiplied by the current applicable tariff rate. The presentation above does not include (i) expected revenues from legacy shippers not underpinned by minimum volume commitments, including pipelines where there are no or limited alternative pipeline transportation options, (ii) intersegment revenues and (iii) the amount of consideration associated with certain income generating contracts, which include a fixed minimum level of service, that are either not within the scope of Topic 606 or do not meet the requirements for presentation as remaining performance obligations under Topic 606. The following are examples of contracts that are not included in the table above because they are not within the scope of Topic 606 or do not meet the Topic 606 requirements for presentation: • Minimum volume commitments on certain of our joint venture pipeline systems; • Acreage dedications; • Supply and Logistics buy/sell arrangements with future committed volumes; • All other Supply and Logistics contracts, due to the election of practical expedients related to variable consideration and short-term contracts, as discussed below; • Transportation and Facilities contracts that are short-term, as discussed below; • Contracts within the scope of ASC Topic 842, Leases ; and • Contracts within the scope of ASC Topic 815, Derivatives and Hedging . We have elected practical expedients to exclude the presentation of remaining performance obligations for variable consideration which relates to wholly unsatisfied performance obligations. Certain contracts do not meet the requirements for presentation of remaining performance obligations under Topic 606 due to variability in amount of performance obligation remaining, variability in the timing of recognition or variability in consideration. Acreage dedications do require us to perform future services but do not contain a minimum level of services and are therefore excluded from this presentation. Long-term supply and logistics arrangements contain variable timing, volumes and/or consideration and are excluded from this presentation. The duration of these contracts varies across the periods presented above.
Trade Accounts Receivable and Other Receivables, Net	Trade Accounts Receivable and Other Receivables, Net Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL. These purchasers include, but are not limited to, refiners, producers, marketing and trading companies and financial institutions. The majority of our accounts receivable relate to our crude oil supply and logistics activities that can generally be described as high volume and low margin activities, in many cases involving exchanges of crude oil volumes. To mitigate credit risk related to our accounts receivable, we utilize a rigorous credit review process. We closely monitor market conditions and perform credit reviews of each customer 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, credit insurance or parental guarantees. Additionally, in an effort to mitigate credit risk, a significant portion of our transactions with counterparties are settled on a net-cash basis. For a majority of these net-cash arrangements, 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).
Net Income Per Common Unit	After consideration of distributions to preferred unitholders (whether paid in cash or 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 our 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 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 equity-indexed compensation plan awards that have vested DERs, which entitle the grantee to a cash payment equal to the cash distribution paid on our outstanding common units. 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) by the basic and diluted weighted average number of common units outstanding during the period. The diluted weighted average number of common units 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 and (ii) our equity-indexed compensation plan awards. See Note 12 for additional information regarding our Series A preferred units. See Note 18 for a complete discussion of our equity-indexed compensation plan awards. 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, 2017 as the effect was antidilutive. Our equity-indexed compensation plan awards that contemplate the issuance of common units are considered dilutive unless (i) they become vested only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. Equity-indexed compensation plan awards that were deemed to be dilutive during the three years ended December 31, 2019 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.
Inventory, Linefill and Base Gas and Long-term Inventory	Inventory primarily consists of crude oil and NGL in pipelines, storage facilities and railcars that are valued at the lower of cost or net realizable value, 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, 2019, 2018 and 2017, we recorded charges of $11 million, $8 million and $35 million, respectively, related to the writedown of our crude oil inventory due to declines in prices. A portion of these inventory valuation adjustments was offset by the recognition of gains on derivative instruments being utilized to hedge future sales of our crude oil inventory. Such gains were recorded to “Supply and Logistics segment revenues” in our accompanying Consolidated Statements of Operations. See Note 13 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. 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 6 for further discussion regarding impairment of long-lived assets. During 2019, 2018 and 2017, 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 under “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, 2019, 2018 and 2017, capitalized interest recorded to property and equipment was $14 million, $21 million and $17 million, respectively. In addition, we capitalize interest related to investments in certain unconsolidated entities. See Note 9 for additional information. We also capitalize expenditures for the replacement and/or refurbishment 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.We calculate our depreciation using the straight-line method, based on estimated useful lives and salvage values of our assets.In addition, when we evaluate property and equipment and other long-lived assets for recoverability, it may also be necessary to review related depreciation estimates and methods.
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.
Business Combinations	The following acquisitions were accounted for using the acquisition method of accounting (excluding asset acquisitions or acquired interests accounted for under the equity method of accounting mentioned specifically below) and the determination of the fair value of the assets and liabilities acquired has been estimated in accordance with the applicable accounting guidance.
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 provides for a quantitative approach to testing goodwill for impairment; however, we may first assess certain qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment test. In the quantitative test, 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 goodwill is impaired by the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying value of goodwill.
Investments in Unconsolidated Entities	Investments in entities over which we have significant influence but not control are accounted for under 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 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. Contributions 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, 2019, 2018 and 2017, we made cash contributions of $504 million, $459 million and $398 million, respectively, to certain of our equity method investees. In addition, we capitalized interest of $20 million, $9 million and $18 million during the years ended December 31, 2019, 2018 and 2017, respectively, related to contributions to unconsolidated entities for projects under development and construction. We anticipate that we will make additional contributions in 2020 related to ongoing projects. Basis Differences Our investments in unconsolidated entities exceeded our share of the underlying equity in the net assets of such entities by $349 million and $467 million at December 31, 2019 and 2018, 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 majority of the basis difference at both December 31, 2019 and 2018 was related to our ownership interest in BridgeTex.
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 and transportation of crude oil, NGL and natural gas. These letters of credit are issued under our senior unsecured revolving credit facility and our 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, including hedging-related margin obligations, and construction activities.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. Net income is allocated 100% to our common unitholders, after giving effect to income allocations for cash distributions to our Series A preferred unitholders and guaranteed payments attributable to our Series B preferred unitholders. In accordance with our partnership agreement, our Series A preferred unitholders are not allocated income for paid-in-kind distributions for partners’ capital presentation purposes.
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.
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	At the inception of the hedging relationship, we assess whether the derivatives employed are highly effective in offsetting changes in cash flows of anticipated hedged transactions. Throughout the hedging relationship, retrospective and prospective hedge effectiveness is assessed on a qualitative basis.
Derivatives That Qualify for Hedge Accounting	For derivatives designated as cash flow hedges, changes in fair value are deferred in AOCI and recognized in earnings in the periods during which the underlying hedged transactions are recognized in earnings.
Derivatives That Do Not Qualify for Hedge Accounting	Derivatives that are not designated as a hedging instrument and derivatives that do not qualify for hedge accounting 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.
Lessee	Lessee On January 1, 2019, we adopted Topic 842, Leases, using the optional transitional method, thereby applying the new guidance at the effective date, without adjusting the comparative periods. Therefore, results for reporting periods beginning after January 1, 2019 are presented under Topic 842, while prior period amounts are not adjusted and continue to be reported in accordance with our historic accounting under ASC Topic 840, Leases (“Topic 840”). We evaluate all agreements entered into or modified after the date of adoption of Topic 842 that convey to us the use of property or equipment for a term to determine whether the agreement is or contains a lease. We lease certain property and equipment under noncancelable and cancelable operating and finance leases. Our operating leases primarily relate to railcars, office space, land, vehicles, and storage tanks, and our finance leases primarily relate to tractor trailers, land, storage tanks and vehicles. One of our finance leases is for storage tanks owned by an equity method investee, in which we own a 50% interest. For leases with an initial term of greater than 12 months, we recognize a right-of-use asset and lease liability on the balance sheet. Leases with an initial term of 12 months or less are not recorded on the balance sheet. Our lease agreements have remaining lease terms ranging from one year to approximately 60 years. When applicable, this range includes additional terms associated with leases for which we are reasonably certain to exercise the option to renew and such renewal options are recognized as part of our right-of-use assets and lease liabilities. We have renewal options for leases with terms ranging from one year to 40 years that are not recognized as part of our right-of-use assets or lease liabilities as we have determined we are not reasonably certain to exercise the option to renew. Certain of our leases have variable lease payments, many of which are based on changes in market indices such as the Consumer Price Index. Our lease agreements for our tractor trailers contain residual value guarantees equal to the fair market value of the tractor trailers at the end of the lease term in the event that we elect not to purchase the asset for an amount equal to the fair value. Our lease agreements do not contain any material restrictive covenants. For determining the present value of lease payments, we use the discount rate implicit in the lease when readily determinable; however, such rate is not readily determinable for most of our leases. For those leases for which the discount rate is not readily determinable, we utilize incremental borrowing rates that reflect collateralized borrowing with payments and terms that mirror our lease portfolio to discount the lease payments based on information available at the lease commencement date.
Lessor	Lessor We evaluate all agreements entered into or modified after the date of adoption of Topic 842 that convey to others the use of property or equipment for a term to determine whether the agreement is or contains a lease. Significant judgment is required when determining whether a customer obtains the right to direct the use of identified property or equipment. The underlying assets associated with these agreements are evaluated for future use beyond the lease term. Our Facilities and Transportation segments enter into agreements to conduct fee-based activities associated with (i) providing storage services primarily for crude oil, NGL and natural gas and (ii) transporting crude oil and NGL. Certain of these agreements convey counterparties the right to direct the operation of physically distinct assets. Such agreements include (i) fixed consideration, which is measured based on an available capacity during the period multiplied by the rate in the agreement, or (ii) a fixed monthly fee and variable consideration based on usage. These agreements often include options to extend or terminate the lease, with advance notice. These agreements are operating leases under Topic 842. For the year ended December 31, 2019, our lease revenue was not material.
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.
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. 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.
Reimbursement of Expenses of Our General Partner and its Affiliates	Our general partner provides 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.
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. We have elected to recognize forfeitures of awards when they occur. Our LTIP awards contain (i) time based vesting criteria, (ii) performance conditions based on the attainment of certain levels of four quarter trailing distributable cash flow (“DCF”) per common unit (or in some instances, per common unit and common equivalent unit) or (iii) a combination of time based vesting criteria and performance conditions based on four quarter trailing DCF per common unit (or per common unit and common equivalent unit). For awards with performance conditions, 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.
Loss Contingencies	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.
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. 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, and gains and losses on significant asset sales by, unconsolidated entities, and further adjusted for certain selected items including (i) gains and losses on 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 the applicable amounts subsequently recognized into revenue and (v) other items that our CODM believes are integral to understanding our core segment operating performance. Segment Adjusted EBITDA excludes depreciation and amortization. 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 and/or refurbishment 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.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Restrictions on Cash and Cash Equivalents	The following table presents a reconciliation of cash and cash equivalents and restricted cash reported on our Consolidated Balance Sheet that sum to the total of the amount shown on our Consolidated Statement of Cash Flows as of December 31, 2019 (in millions): December 31, 2019 Cash and cash equivalents $ 45 Restricted cash 37 Total cash and cash equivalents and restricted cash $ 82
Schedule of Change in Asset Retirement Obligation	The following table presents the change in the liability for asset retirement obligations, of which $135 million, $107 million and $99 million were reflected in “Other long-term liabilities and deferred credits” with the remaining portion reflected in “Other current liabilities” on our Consolidated Balance Sheets as of December 31, 2019, 2018 and 2017, respectively (in millions): December 31, 2019 2018 2017 Beginning balance $ 109 $ 103 $ 44 Liabilities incurred 3 3 33 Liabilities settled (3) (3) (4) Accretion expense 5 4 3 Revisions in estimated cash flows 23 2 27 Ending balance $ 137 $ 109 $ 103

Revenues and Accounts Receiva_2

Revenues and Accounts Receivable (Tables)	12 Months Ended
	Dec. 31, 2019
Disaggregation of Revenue [Line Items]
Disaggregation of Revenue	The following tables present the reconciliation of our revenues from contracts with customers (as described above for each segment) to segment revenues and total revenues as disclosed in our Consolidated Statements of Operations (in millions): Year Ended December 31, 2019 Transportation Facilities Supply and Logistics Total Revenues from contracts with customers $ 2,283 $ 1,122 $ 31,966 $ 35,371 Other items in revenues 37 49 310 396 Total revenues of reportable segments $ 2,320 $ 1,171 $ 32,276 $ 35,767 Intersegment revenues (2,098) Total revenues $ 33,669 Year Ended December 31, 2018 Transportation Facilities Supply and Total Revenues from contracts with customers $ 1,976 $ 1,136 $ 32,700 $ 35,812 Other items in revenues 14 25 122 161 Total revenues of reportable segments $ 1,990 $ 1,161 $ 32,822 $ 35,973 Intersegment revenues (1,918) Total revenues $ 34,055
Contracts with Customers, Assets and Liabilities	The following table presents the changes in the contract liability balance (in millions): Contract Liabilities Balance at December 31, 2017 $ 90 Amounts recognized as revenue (81) Additions (1) (2) 332 Other (3) Balance at December 31, 2018 $ 338 Amounts recognized as revenue (227) Additions (3) 244 Other (1) Balance at December 31, 2019 $ 354 (1) Includes approximately $116 million associated with crude oil sales agreements that are entered into in conjunction with storage arrangements and future inventory exchanges. Such amount was recognized as revenue in the first quarter of 2019. (2) Includes $100 million associated with long-term capacity agreements with Cactus II Pipeline LLC. See Note 9 for additional information. (3) Includes approximately $155 million associated with crude oil sales agreements that are entered into in conjunction with storage arrangements and future inventory exchanges. Such amount is expected to be recognized as revenue in the first quarter of 2020. The following is a reconciliation of trade accounts receivable from revenues from contracts with customers to total Trade accounts receivable and other receivables, net as presented on our Consolidated Balance Sheets (in millions): December 31, 2019 2018 Trade accounts receivable arising from revenues from contracts with customers $ 3,381 $ 2,277 Other trade accounts receivables and other receivables (1) 3,576 2,732 Impact due to contractual rights of offset with counterparties (3,343) (2,555) Trade accounts receivable and other receivables, net $ 3,614 $ 2,454 (1) The balance is comprised primarily of accounts receivable associated with buy/sell arrangements that are not within the scope of Topic 606.
Remaining Performance Obligations	The following table presents the amount of consideration associated with remaining performance obligations for the population of contracts with external customers meeting the presentation requirements as of December 31, 2019 (in millions): 2020 2021 2022 2023 2024 2025 and Thereafter Pipeline revenues supported by minimum volume commitments and capacity agreements (1) $ 164 $ 170 $ 170 $ 168 $ 146 $ 698 Storage, terminalling and throughput agreement revenues 404 312 242 188 147 366 Total $ 568 $ 482 $ 412 $ 356 $ 293 $ 1,064 (1) Calculated as volumes committed under contracts multiplied by the current applicable tariff rate.
Supply And Logistics
Disaggregation of Revenue [Line Items]
Disaggregation of Revenue	The following table presents our Supply and Logistics segment revenues from contracts with customers disaggregated by type of activity (in millions): Year Ended December 31, 2019 2018 Supply and Logistics segment revenues from contracts with customers Crude oil transactions $ 30,082 $ 29,592 NGL and other transactions 1,884 3,108 Total Supply and Logistics segment revenues from contracts with customers $ 31,966 $ 32,700
Transportation
Disaggregation of Revenue [Line Items]
Disaggregation of Revenue	The following table presents our Transportation segment revenues from contracts with customers disaggregated by type of activity (in millions): Year Ended December 31, 2019 2018 Transportation segment revenues from contracts with customers Tariff activities: Crude oil pipelines $ 2,039 $ 1,724 NGL pipelines 99 103 Total tariff activities 2,138 1,827 Trucking 145 149 Total Transportation segment revenues from contracts with customers $ 2,283 $ 1,976
Facilities
Disaggregation of Revenue [Line Items]
Disaggregation of Revenue	The following table presents our Facilities segment revenues from contracts with customers disaggregated by type of activity (in millions): Year Ended December 31, 2019 2018 Facilities segment revenues from contracts with customers Crude oil, NGL and other terminalling and storage $ 697 $ 688 NGL and natural gas processing and fractionation 349 364 Rail load / unload 76 84 Total Facilities segment revenues from contracts with customers $ 1,122 $ 1,136

Net Income Per Common Unit (Tab

Net Income Per Common Unit (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 2018 2017 Basic Net Income per Common Unit Net income attributable to PAA $ 2,171 $ 2,216 $ 856 Distributions to Series A preferred unitholders (149) (149) (142) Distributions to Series B preferred unitholders (49) (49) (11) Distributions to participating securities (3) (3) (2) Other (3) (6) (16) Net income allocated to common unitholders (1) $ 1,967 $ 2,009 $ 685 Basic weighted average common units outstanding 727 726 717 Basic net income per common unit $ 2.70 $ 2.77 $ 0.96 Diluted Net Income per Common Unit Net income attributable to PAA $ 2,171 $ 2,216 $ 856 Distributions to Series A preferred unitholders — — (142) Distributions to Series B preferred unitholders (49) (49) (11) Distributions to participating securities (3) (3) (2) Other — — (16) Net income allocated to common unitholders (1) $ 2,119 $ 2,164 $ 685 Basic weighted average common units outstanding 727 726 717 Effect of dilutive securities: Series A preferred units 71 71 — Equity-indexed compensation plan awards 2 2 1 Diluted weighted average common units outstanding 800 799 718 Diluted net income per common unit $ 2.65 $ 2.71 $ 0.95 (1) We calculate net income allocated to common unitholders based on the distributions pertaining to the current period’s net income (whether paid in cash or in-kind). After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings (i.e., undistributed loss), if any, are allocated to the 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.

Inventory, Linefill and Base _2

Inventory, Linefill and Base Gas and Long-term Inventory (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 December 31, 2018 Volumes Unit of Carrying Price/ Unit (1) Volumes Unit of Carrying Price/ Unit (1) Inventory Crude oil 8,613 barrels $ 450 $ 52.25 9,657 barrels $ 367 $ 38.00 NGL 7,574 barrels 142 $ 18.75 10,384 barrels 262 $ 25.23 Other N/A 12 N/A N/A 11 N/A Inventory subtotal 604 640 Linefill and base gas Crude oil 14,316 barrels 826 $ 57.70 13,312 barrels 761 $ 57.17 NGL 1,701 barrels 47 $ 27.63 1,730 barrels 47 $ 27.17 Natural gas 24,976 Mcf 108 $ 4.32 24,976 Mcf 108 $ 4.32 Linefill and base gas subtotal 981 916 Long-term inventory Crude oil 2,598 barrels 152 $ 58.51 1,890 barrels 79 $ 41.80 NGL 1,707 barrels 30 $ 17.57 2,368 barrels 57 $ 24.07 Long-term inventory subtotal 182 136 Total $ 1,767 $ 1,692 (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, 2019
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, 2019 2018 Pipelines and related facilities (1) 10 - 70 $ 11,114 $ 10,137 Storage, terminal and rail facilities 10 - 70 6,134 5,854 Trucking equipment and other 2 - 15 486 410 Construction in progress N/A 518 795 Office property and equipment 2 - 50 269 248 Land and other N/A 427 422 Property and equipment, gross 18,948 17,866 Accumulated depreciation (3,593) (3,079) Property and equipment, net $ 15,355 $ 14,787 (1) We include rights-of-way, which are intangible assets, in our Pipelines and related facilities amounts within property and equipment.

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables) - Alpha Holding Company, LLC	12 Months Ended
	Dec. 31, 2019
Business Acquisition [Line Items]
Schedule of assets acquired and liabilities assumed	The following table reflects the fair value determination (in millions): Identifiable assets acquired and liabilities assumed: Estimated Useful Lives (Years) Recognized amount Property and equipment 3 - 70 $ 299 Intangible assets 20 646 Goodwill N/A 269 Other assets and liabilities, net (including $4 million of cash acquired) N/A 1 $ 1,215
Schedule of amortization expense	Amortization expense was approximately $34 million, $25 million and $10 million during the years ended December 31, 2019, 2018 and 2017, respectively, and the future amortization expense through 2022 is estimated as follows (in millions): 2020 $ 42 2021 $ 48 2022 $ 54

Goodwill (Tables)

Goodwill (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2017 $ 1,070 $ 988 $ 508 $ 2,566 Foreign currency translation adjustments (19) (8) (5) (32) Divestitures (11) (2) — (13) Balance at December 31, 2018 $ 1,040 $ 978 $ 503 $ 2,521 Foreign currency translation adjustments 12 4 3 19 Balance at December 31, 2019 $ 1,052 $ 982 $ 506 $ 2,540

Investments in Unconsolidated_2

Investments in Unconsolidated Entities (Tables)	12 Months Ended
	Dec. 31, 2019
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 Investment Balance Entity (1) Type of Operation 2019 2018 Advantage Pipeline Holdings LLC (“Advantage Joint Venture”) Crude Oil Pipeline 50% $ 76 $ 72 BridgeTex Pipeline Company, LLC (“BridgeTex”) Crude Oil Pipeline 20% 431 435 Cactus II Pipeline LLC (“Cactus II”) Crude Oil Pipeline 65% 738 455 Caddo Pipeline LLC Crude Oil Pipeline 50% 65 65 Capline Pipeline Company LLC Crude Oil Pipeline (2) (3) 54% 484 — Cheyenne Pipeline LLC (“Cheyenne”) Crude Oil Pipeline 50% 44 44 Cushing Connect Pipeline & Terminal LLC Crude Oil Pipeline (3) and Terminal 50% 23 — Diamond Pipeline LLC (“Diamond”) Crude Oil Pipeline 50% 476 479 Eagle Ford Pipeline LLC (“Eagle Ford Pipeline”) Crude Oil Pipeline 50% 382 383 Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Terminals”) Crude Oil Terminal and Dock 50% 126 108 Midway Pipeline LLC Crude Oil Pipeline 50% 76 78 Red Oak Pipeline LLC (“Red Oak”) Crude Oil Pipeline (3) 50% 20 — Saddlehorn Pipeline Company, LLC (“Saddlehorn”) Crude Oil Pipeline 40% 234 215 Settoon Towing, LLC Barge Transportation Services 50% 59 58 STACK Pipeline LLC (“STACK”) Crude Oil Pipeline 50% 117 120 White Cliffs Pipeline, LLC Crude Oil Pipeline 36% 196 190 Wink to Webster Pipeline LLC (“W2W Pipeline”) Crude Oil Pipeline (3) 16% 136 — Total Investments in Unconsolidated Entities $ 3,683 $ 2,702 (1) Except for Eagle Ford Terminals, which is reported in our Facilities segment, the financial results from the entities are reported in our Transportation segment. (2) The Capline pipeline was taken out of service pending the reversal of the pipeline system. (3) Asset is currently under construction or development 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, 2019 2018 Current assets $ 652 $ 357 Noncurrent assets $ 7,264 $ 4,861 Current liabilities $ 298 $ 170 Noncurrent liabilities $ 26 $ 30 Year Ended December 31, 2019 2018 2017 Revenues $ 1,469 $ 1,235 $ 938 Operating income $ 994 $ 824 $ 650 Net income $ 995 $ 824 $ 640

Other Long-Term Assets, Net (Ta

Other Long-Term Assets, Net (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 December 31, 2018 Estimated Useful Cost Accumulated Net Cost Accumulated Net Customer contracts and relationships 1 – 20 $ 1,134 $ (463) $ 671 $ 1,152 $ (413) $ 739 Property tax abatement 7 – 13 23 (18) 5 23 (16) 7 Other agreements 25 – 70 42 (11) 31 34 (8) 26 Intangible assets (1) 1,199 (492) 707 1,209 (437) 772 Other 152 (1) 151 144 — 144 Other long-term assets, net $ 1,351 $ (493) $ 858 $ 1,353 $ (437) $ 916 (1) We include rights-of-way, which are intangible assets, in our pipeline and related facilities amounts within property and equipment. See Note 6 for a discussion of property and equipment.
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): 2020 $ 77 2021 $ 73 2022 $ 74 2023 $ 69 2024 $ 67

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2019
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 2.2% (1) $ 93 $ — Senior secured hedged inventory facility, bearing a weighted-average interest rate of 2.7% (1) 325 — Other 86 66 Total short-term debt 504 66 LONG-TERM DEBT Senior notes: 2.60% senior notes due December 2019 (2) — 500 5.75% senior notes due January 2020 — 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 750 750 3.55% senior notes due December 2029 1,000 — 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 (61) (59) Senior notes, net of unamortized discounts and debt issuance costs 8,939 8,941 Other long-term debt: GO Zone term loans, net of debt issuance costs of $1 and $2, respectively, bearing a weighted-average interest rate of 2.6% and 3.1%, respectively 199 198 Other 49 4 Total long-term debt 9,187 9,143 Total debt (3) $ 9,691 $ 9,209 (1) We classified these commercial paper notes and credit facility borrowings as short-term as of December 31, 2019, 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) As of December 31, 2018, we classified our $500 million, 2.60% senior notes due December 2019 as long-term based on our ability and intent to refinance such amounts on a long-term basis. (3) Our fixed-rate senior notes had a face value of approximately $9.0 billion at both December 31, 2019 and 2018. We estimated the aggregate fair value of these notes as of December 31, 2019 and 2018 to be approximately $9.3 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 the end of
Issuances of senior unsecured notes	The table below summarizes our issuances of senior unsecured notes during the three years ended December 31, 2019 (in millions): Year Description Maturity Face Value Interest Payment Dates 2019 3.55% Senior Notes issued at 99.801% of face value December 2029 $ 1,000 June 15 and December 15 Year Description Repayment Date 2019 $500 million 2.60% Senior Notes due December 2019 November 2019 (1) 2019 $500 million 5.75% Senior Notes due January 2020 December 2019 (1) 2017 $400 million 6.13% Senior Notes due January 2017 January 2017 (2) 2017 $600 million 6.50% Senior Notes due May 2018 December 2017 (2) (3) 2017 $350 million 8.75% Senior Notes due May 2019 December 2017 (2) (3) (1) We repaid these senior notes with proceeds from our 3.55% senior notes issued in September 2019 and cash on hand. (2) We repaid these senior notes with cash on hand and proceeds from borrowings under our credit facilities and commercial paper program.
Aggregate maturities of long-term debt	The following table presents the aggregate contractually scheduled maturities of such senior notes and GO Zone term loans for the next five years and thereafter. The amounts presented exclude unamortized discounts and debt issuance costs. Calendar Year Payment (in millions) 2020 $ — 2021 $ 600 2022 $ 750 2023 $ 1,300 2024 $ 750 Thereafter $ 5,800

Partners' Capital and Distrib_2

Partners' Capital and Distributions (Tables)	12 Months Ended
	Dec. 31, 2019
Partners Capital and Distribution [Line Items]
Activity for preferred and common units	The following table presents the activity for our preferred and common units: Limited Partners Series A Preferred Units Series B Common Units Outstanding at December 31, 2016 64,388,853 — 669,194,419 Issuances of Series A preferred units in connection with in-kind distributions 5,307,689 — — Sale of Series B preferred units — 800,000 — Sales of common units — — 54,119,893 Issuance of common units in connection with acquisition of interest in Advantage Joint Venture (Note 7) — — 1,252,269 Issuances of common units under equity-indexed compensation plans — — 622,557 Outstanding at December 31, 2017 69,696,542 800,000 725,189,138 Issuance of Series A preferred units in connection with in-kind distribution 1,393,926 — — Issuances of common units under equity-indexed compensation plans — — 1,172,786 Outstanding at December 31, 2018 71,090,468 800,000 726,361,924 Issuances of common units under equity-indexed compensation plans — — 1,666,652 Outstanding at December 31, 2019 71,090,468 800,000 728,028,576
Issuance of common units	The following table summarizes our sales of common units during year ended December 31, 2017 (net proceeds in millions): Year Type of Offering Common Units Issued Net Proceeds (1) 2017 Continuous Offering Program 4,033,567 $ 129 (2) 2017 Omnibus Agreement (3) 50,086,326 (4) 1,535 2017 Total 54,119,893 $ 1,664 (1) Amounts are net of costs associated with the offerings. (2) We paid $1 million to sales agents in connection with common unit issuances under our Continuous Offering Program during the year ended December 31, 2017. (3) Pursuant to the Omnibus Agreement entered into on November 15, 2016 by the Plains Entities, PAGP used the net proceeds from the sale of PAGP Class A shares, after deducting the sales agents’ commissions and offering expenses, to purchase from AAP a number of AAP units equal to the number of PAGP Class A shares sold in such offering at a price equal to the net proceeds from such offering. Also pursuant to the Omnibus Agreement, immediately following such purchase and sale, AAP used the net proceeds it received from such sale of AAP units to purchase from us an equivalent number of our common units. (4) Includes (i) approximately 1.8 million common units issued to AAP in connection with PAGP’s issuance of Class A shares under its Continuous Offering Program and (ii) 48.3 million common units issued to AAP in connection with PAGP’s March 2017 underwritten offering.
Schedule of distributions paid	The following table details distributions paid to common unitholders during the year presented (in millions, except per unit data): Distributions Paid Distributions per common unit Year Public AAP Total 2019 $ 632 $ 372 $ 1,004 $ 1.38 2018 $ 532 $ 339 $ 871 $ 1.20 2017 $ 849 $ 537 $ 1,386 $ 1.95
Series A Preferred Units
Partners Capital and Distribution [Line Items]
Schedule of distributions paid	The following table details distributions paid to our preferred unitholders during the year presented (in millions, except unit data): Series A Preferred Unitholders Series B Preferred Unitholders Distribution (1) Cash Distribution (2) Year Cash Units 2019 $ 149 — $ 49 2018 $ 112 1,393,926 $ 49 2017 $ — 5,307,689 $ 5 (1) We elected to pay distributions on our Series A preferred units in additional Series A preferred units for each quarterly distribution from their issuance through the February 2018 distribution. Distributions on our Series A preferred units have been paid in cash since the May 2018 distribution. During 2018 and 2017, we issued additional Series A preferred units in lieu of cash distributions of $37 million and $139 million, respectively.
Series B Preferred Units
Partners Capital and Distribution [Line Items]
Schedule of distributions paid	The following table details distributions paid to our preferred unitholders during the year presented (in millions, except unit data): Series A Preferred Unitholders Series B Preferred Unitholders Distribution (1) Cash Distribution (2) Year Cash Units 2019 $ 149 — $ 49 2018 $ 112 1,393,926 $ 49 2017 $ — 5,307,689 $ 5 (1) We elected to pay distributions on our Series A preferred units in additional Series A preferred units for each quarterly distribution from their issuance through the February 2018 distribution. Distributions on our Series A preferred units have been paid in cash since the May 2018 distribution. During 2018 and 2017, we issued additional Series A preferred units in lieu of cash distributions of $37 million and $139 million, respectively.

Derivatives and Risk Manageme_2

Derivatives and Risk Management Activities (Tables)	12 Months Ended
	Dec. 31, 2019
Derivatives and Risk Management Activities
Impact of derivative activities recognized in earnings	A summary of the impact of our derivatives recognized in earnings is as follows (in millions): Year Ended December 31, 2019 Location of Gain/(Loss) Commodity Foreign Currency Derivatives Preferred Distribution Interest Rate Derivatives Total Supply and Logistics segment revenues (1) $ 310 $ 8 $ — $ — $ 318 Field operating costs (1) 14 — — — 14 Interest expense, net (2) — — — (9) (9) Other income/(expense), net (1) — — 2 — 2 Total gain/(loss) on derivatives recognized in net income $ 324 $ 8 $ 2 $ (9) $ 325 Year Ended December 31, 2018 Location of Gain/(Loss) Commodity Foreign Currency Derivatives Preferred Distribution Interest Rate Derivatives Total Supply and Logistics segment revenues (1) $ 150 $ (23) $ — $ — $ 127 Field operating costs (1) (2) — — — (2) Interest expense, net (2) — — — (5) (5) Other income/(expense), net (1) — — (14) — (14) Total gain/(loss) on derivatives recognized in net income $ 148 $ (23) $ (14) $ (5) $ 106 Year Ended December 31, 2017 Location of Gain/(Loss) Commodity Foreign Currency Derivatives Preferred Distribution Rate Reset Option Interest Rate Derivatives Total Supply and Logistics segment revenues (1) $ (188) $ 8 $ — $ — $ (180) Field operating costs (1) (10) — — — (10) Depreciation and amortization (2) (3) — — — (3) Interest expense, net (2) — — — (18) (18) Other income/(expense), net (1) — — 13 — 13 Total gain/(loss) on derivatives recognized in net income $ (201) $ 8 $ 13 $ (18) $ (198) (1) Derivatives not designated as a hedge. (2) Derivatives in hedging relationships.
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, 2019 (in millions): Derivatives Not Designated As Hedging Instruments Balance Sheet Location Commodity Foreign Currency Derivatives Preferred Distribution Rate Reset Option Total Interest Rate Derivatives (1) Total Derivatives Derivative Assets Other current assets $ 179 $ 4 $ — $ 183 $ — $ 183 Other long-term assets, net 24 — — 24 — 24 Other current liabilities 32 — — 32 — 32 Total Derivative Assets $ 235 $ 4 $ — $ 239 $ — $ 239 Derivative Liabilities Other current assets $ (37) $ (2) $ — $ (39) $ — $ (39) Other long-term assets, net — — — — — — Other current liabilities (56) (1) — (57) (44) (101) Other long-term liabilities and deferred credits (12) — (34) (46) — (46) Total Derivative Liabilities $ (105) $ (3) $ (34) $ (142) $ (44) $ (186) (1) Derivatives in hedging relationships. The following table summarizes the derivative assets and liabilities on our Consolidated Balance Sheet on a gross basis as of December 31, 2018 (in millions): Derivatives Not Designated As Hedging Instruments Balance Sheet Location Commodity Foreign Currency Derivatives Preferred Distribution Rate Reset Option Total Interest Rate Derivatives (1) Total Derivatives Derivative Assets Other current assets $ 441 $ — $ — $ 441 $ 2 $ 443 Other long-term assets, net 34 — — 34 — 34 Other long-term liabilities and deferred credits 3 — — 3 — 3 Total Derivative Assets $ 478 $ — $ — $ 478 $ 2 $ 480 Derivative Liabilities Other current assets $ (182) $ — $ — $ (182) $ — $ (182) Other long-term assets, net (7) — — (7) — (7) Other current liabilities (10) (9) — (19) (1) (20) Other long-term liabilities and deferred credits (9) — (36) (45) (8) (53) Total Derivative Liabilities $ (208) $ (9) $ (36) $ (253) $ (9) $ (262) (1) Derivatives in hedging relationships.
Schedule of net broker receivable (payable)	The following table provides the components of our net broker receivable/(payable): December 31, 2019 December 31, 2018 Initial margin $ 73 $ 95 Variation margin posted/(returned) (45) (91) Letters of credit (73) (84) Net broker payable $ (45) $ (80)
Schedule of derivative financial assets 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, 2019 December 31, 2018 Derivative Derivative Derivative Derivative Netting Adjustments: Gross position - asset/(liability) $ 239 $ (186) $ 480 $ (262) Netting adjustment (71) 71 (192) 192 Cash collateral paid/(received) (45) — (80) — Net position - asset/(liability) $ 123 $ (115) $ 208 $ (70) Balance Sheet Location After Netting Adjustments: Other current assets $ 99 $ — $ 181 $ — Other long-term assets, net 24 — 27 — Other current liabilities — (69) — (20) Other long-term liabilities and deferred credits — (46) — (50) $ 123 $ (115) $ 208 $ (70)
Schedule of derivative financial 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, 2019 December 31, 2018 Derivative Derivative Derivative Derivative Netting Adjustments: Gross position - asset/(liability) $ 239 $ (186) $ 480 $ (262) Netting adjustment (71) 71 (192) 192 Cash collateral paid/(received) (45) — (80) — Net position - asset/(liability) $ 123 $ (115) $ 208 $ (70) Balance Sheet Location After Netting Adjustments: Other current assets $ 99 $ — $ 181 $ — Other long-term assets, net 24 — 27 — Other current liabilities — (69) — (20) Other long-term liabilities and deferred credits — (46) — (50) $ 123 $ (115) $ 208 $ (70)
Net deferred gain/(loss) recognized in AOCI for derivatives	The following table summarizes the net unrealized gain/(loss) recognized in AOCI for derivatives (in millions): Year Ended December 31, 2019 2018 2017 Interest rate derivatives, net $ (91) $ 38 $ (16)
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, 2019 Fair Value as of December 31, 2018 Recurring Fair Value Measures (1) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Commodity derivatives $ 42 $ 105 $ (17) $ 130 $ 171 $ 87 $ 12 $ 270 Interest rate derivatives — (44) — (44) — (7) — (7) Foreign currency derivatives — 1 — 1 — (9) — (9) Preferred Distribution Rate Reset Option — — (34) (34) — — (36) (36) Total net derivative asset/(liability) $ 42 $ 62 $ (51) $ 53 $ 171 $ 71 $ (24) $ 218 (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, 2019 2018 Beginning Balance $ (24) $ (30) Net gains/(losses) for the period included in earnings 10 (13) Settlements (11) 7 Derivatives entered into during the period (26) 12 Ending Balance $ (51) $ (24) Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period $ (16) $ (1)
Commodity Derivatives
Derivatives and Risk Management Activities
Summary of open derivative contracts	The following table summarizes our open derivative positions utilized to hedge the price risk associated with anticipated purchases and sales related to our natural gas processing and NGL fractionation activities as of December 31, 2019. Notional Volume Remaining Tenor Natural gas purchases 46.4 Bcf December 2022 Propane sales (3.8) MMbls March 2021 Butane sales (1.9) MMbls March 2021 Condensate sales (WTI position) (0.7) MMbls March 2021 Power supply requirements (1) 1.0 TWh December 2022 (1) Power position to hedge a portion of our power supply requirements at our Canadian natural gas processing and fractionation plants.
Interest Rate Swaps
Derivatives and Risk Management Activities
Schedule of terms of forward starting interest rate derivatives	The following table summarizes the terms of our outstanding interest rate derivatives as of December 31, 2019 (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 6/15/2020 3.06 % Cash flow hedge
Foreign Currency Derivatives
Derivatives and Risk Management Activities
Summary of open derivative contracts	The following table summarizes our open forward exchange contracts as of December 31, 2019 (in millions): USD CAD Average Exchange Rate USD to CAD Forward exchange contracts that exchange CAD for USD: 2020 $ 202 $ 266 $1.00 - $1.31 Forward exchange contracts that exchange USD for CAD: 2020 $ 207 $ 274 $1.00 - $1.32

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Schedule of Lease Costs and Other Lessee Information	The following table presents components of lease cost for the year ended December 31, 2019, including both amounts recognized in income and amounts capitalized (in millions): Lease Cost Year Ended Operating lease cost $ 125 Short-term lease cost 35 Other (1) — Total lease cost $ 160 (1) Includes less than $1 million of net immaterial finance lease costs, variable lease costs and sublease income. The following table presents information related to cash flows arising from lease transactions (in millions): Year Ended Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases $ 116 Financing cash flows for finance leases $ 18 Non-cash change in lease liabilities arising from obtaining new right-of-use assets or modifications: Operating leases $ 77 Finance leases (1) $ 27 (1) Includes approximately $12 million associated with leased storage tanks owned by an equity method investee, in which we own a 50% interest. Information related to the weighted-average remaining lease term and discount rate is presented in the table below: Year Ended Weighted-average remaining lease term (in years): Operating leases 11 Finance leases 6 Weighted-average discount rate: Operating leases 4.4 % Finance leases 7.1 %
Schedule of Assets and Liabilities, Lessee	The following table presents the amount and location of our operating and finance lease right-of-use assets and liabilities on our Consolidated Balance Sheet (in millions): Leases Balance Sheet Location Year Ended Assets Operating lease right-of-use assets Long-term operating lease right-of-use assets, net $ 466 Finance lease right-of-use assets (1) Property and equipment $ 124 Accumulated depreciation (16) Property and equipment, net $ 108 Total lease right-of-use assets $ 574 Liabilities Operating lease liabilities Current Other current liabilities $ 94 Noncurrent Long-term operating lease liabilities 387 Total operating lease liabilities $ 481 Finance lease liabilities (1) Current Short-term debt $ 18 Noncurrent Other long-term debt, net 49 Total finance lease liabilities $ 67 Total lease liabilities $ 548 (1) Includes approximately $12 million right-of-use asset and lease liability associated with leased storage tanks owned by an equity method investee, in which we own a 50% interest.
Schedule of Finance Lease Maturity	The following table presents the maturity of undiscounted cash flows for future minimum lease payments under noncancelable leases as of December 31, 2019 reconciled to our lease liabilities on our Consolidated Balance Sheet (amounts in millions): Operating Finance (2) Future minimum lease payments (1) : 2020 $ 109 $ 21 2021 87 12 2022 79 12 2023 60 9 2024 48 9 Thereafter 279 29 Total 662 92 Less: Present value discount (181) (25) Lease liabilities $ 481 $ 67 (1) Excludes future minimum payments for short-term and other immaterial leases not included on our Consolidated Balance Sheet. (2) Includes payments of approximately $2 million for each of the years ending 2020 through 2024 and approximately $23 million thereafter associated with leased storage tanks owned by an equity method investee, in which we own a 50% interest.
Schedule of Operating Lease Maturity	The following table presents the maturity of undiscounted cash flows for future minimum lease payments under noncancelable leases as of December 31, 2019 reconciled to our lease liabilities on our Consolidated Balance Sheet (amounts in millions): Operating Finance (2) Future minimum lease payments (1) : 2020 $ 109 $ 21 2021 87 12 2022 79 12 2023 60 9 2024 48 9 Thereafter 279 29 Total 662 92 Less: Present value discount (181) (25) Lease liabilities $ 481 $ 67 (1) Excludes future minimum payments for short-term and other immaterial leases not included on our Consolidated Balance Sheet. (2) Includes payments of approximately $2 million for each of the years ending 2020 through 2024 and approximately $23 million thereafter associated with leased storage tanks owned by an equity method investee, in which we own a 50% interest.
Schedule of Lessor Future Revenues Maturity	The following table presents the undiscounted cash flows expected to be received related to these agreements (in millions): 2020 2021 2022 2023 2024 Thereafter Lease revenue $ 19 $ 22 $ 25 $ 21 $ 17 $ 208

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Components of income tax expense	Components of income tax expense are as follows (in millions): Year Ended December 31, 2019 2018 2017 Current income tax expense: State income tax $ 3 $ 3 $ 1 Canadian federal and provincial income tax 109 63 27 Total current income tax expense $ 112 $ 66 $ 28 Deferred income tax expense/(benefit): Canadian federal and provincial income tax $ (46) $ 132 $ 16 Total deferred income tax expense/(benefit) $ (46) $ 132 $ 16 Total income tax expense $ 66 $ 198 $ 44
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, 2019 2018 2017 Income before tax $ 2,246 $ 2,414 $ 902 Partnership earnings not subject to current Canadian tax (1,769) (1,690) (756) $ 477 $ 724 $ 146 Canadian federal and provincial corporate tax rate 26 % 27 % 27 % Income tax at statutory rate $ 124 $ 195 $ 39 Canadian withholding tax $ — $ — $ 2 Canadian permanent differences and rate changes (61) — 2 State income tax 3 3 1 Total income tax expense $ 66 $ 198 $ 44
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, 2019 2018 Deferred tax assets: Lease liabilities $ 55 $ — Net operating losses 2 2 Other 16 21 Total deferred tax assets 73 23 Deferred tax liabilities: Property and equipment in excess of tax values (472) (449) Derivative instruments (22) (31) Lease assets (53) — Other (5) (42) Total deferred tax liabilities (552) (522) Net deferred tax liabilities $ (479) $ (499) Balance sheet classification of deferred tax assets/(liabilities): Other long-term assets, net $ 2 $ 2 Other long-term liabilities and deferred credits (481) (501) $ (479) $ (499)

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2019
Related Party Transactions [Abstract]
Schedule of related party transactions	During the three years ended December 31, 2019, we recognized sales and transportation revenues, purchased petroleum products and utilized transportation services from our principal owners and their affiliated entities and our equity method investees. 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 these transactions is included below (in millions): Year Ended December 31, 2019 2018 2017 Revenues from related parties (1) (2) $ 692 $ 1,067 $ 927 Purchases and related costs from related parties (2) $ 223 $ 410 $ 286 (1) A majority of these revenues are included in “Supply and Logistics segment revenues” on our Consolidated Statements of Operations. (2) Crude oil 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. Our receivable and payable amounts with these related parties as reflected on our Consolidated Balance Sheets were as follows (in millions): December 31, 2019 2018 Trade accounts receivable and other receivables, net from related parties (1) (2) $ 134 $ 144 Trade accounts payable to related parties (1) (2) (3) $ 102 $ 121 (1) We have a netting arrangement with certain related parties. Receivables and payables are presented net of such amounts. (2) Includes amounts related to crude oil purchases and sales, transportation services and amounts owed to us or advanced to us related to expansion projects of equity method investees where we serve as construction manager. (3) 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. A portion of our commitment to transport is supported by crude oil buy/sell agreements with third parties with commensurate quantities.

Equity-Indexed Compensation P_2

Equity-Indexed Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Summary of LTIP awards authorized	The following is a summary of the awards authorized under our LTIPs as of December 31, 2019 (in millions): LTIP PAA LTIP Awards Authorized Plains All American 2013 Long-Term Incentive Plan 13.1 Plains All American PNG Successor Long-Term Incentive Plan 1.3 Plains All American GP LLC 2006 Long-Term Incentive Tracking Unit Plan 10.8 Total (1) 25.2 (1) Of the 25.2 million total awards authorized, 5.9 million awards are currently available. The remaining balance has already vested or is currently outstanding.
Summary of activity under 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) Units Weighted Average Outstanding at December 31, 2016 8.9 $ 29.62 Granted 0.9 $ 23.52 Vested (1.7) $ 42.12 Modified — $ (6.04) Cancelled or forfeited (0.8) $ 26.99 Outstanding at December 31, 2017 7.3 $ 24.68 Granted 1.7 $ 23.44 Vested (1.7) $ 32.42 Modified — $ 2.15 Cancelled or forfeited (0.5) $ 21.99 Outstanding at December 31, 2018 6.8 $ 22.19 Granted 3.9 $ 16.17 Vested (3.3) $ 22.44 Cancelled or forfeited (0.3) $ 23.12 Outstanding at December 31, 2019 7.1 $ 18.67 (1) Approximately 1.4 million, 0.6 million and 0.6 million PAA common units were issued, net of tax withholding of approximately 0.6 million, 0.2 million and 0.2 million units during 2019, 2018 and 2017, respectively, in connection with the settlement of vested awards. The remaining PAA awards (approximately 1.3 million, 0.9 million and 0.9 million units) that vested during 2019, 2018 and 2017, respectively, were settled in cash.
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): 2019 2018 2017 Equity-indexed compensation expense $ 34 $ 79 $ 41 LTIP unit-settled vestings $ 47 $ 21 $ 16 LTIP cash-settled vestings $ 31 $ 22 $ 25
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) 2020 $ 22 2021 13 2022 7 2023 4 2024 2 Thereafter 4 Total $ 52 (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, 2019.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2019
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 noncancelable commitments related to these items at December 31, 2019 are summarized below (in millions): 2020 2021 2022 2023 2024 Thereafter Total Leases (1) $ 130 $ 99 $ 91 $ 69 $ 57 $ 308 $ 754 Other commitments (2) 272 296 292 276 271 968 2,375 Total $ 402 $ 395 $ 383 $ 345 $ 328 $ 1,276 $ 3,129 (1) Includes both operating and finance leases as defined by FASB guidance. Leases are primarily for (i) railcars, (ii) office space, (iii) land, (iv) vehicles, (v) storage tanks and (vi) tractor trailers. See Note 14 for additional information. (2) Primarily includes third-party storage and transportation agreements and pipeline throughput agreements, as well as approximately $1.8 billion associated with agreements to store, process and transport crude oil at posted tariff rates on pipelines or at facilities that are owned by equity method investees, in which we own a 50% interest. A portion of our commitment to transport is supported by crude oil buy/sell agreements with third parties with commensurate quantities. Expense associated with these storage, transportation and throughput agreements was approximately $236 million, $228 million and $197 million for 2019, 2018 and 2017, respectively.

Quarterly Financial Data (Una_2

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2019
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) 2019 Total revenues $ 8,375 $ 8,253 $ 7,886 $ 9,154 $ 33,669 Gross margin (2) $ 790 $ 526 $ 566 $ 403 $ 2,285 Operating income $ 714 $ 451 $ 492 $ 331 $ 1,988 Net income $ 970 $ 448 $ 454 $ 307 $ 2,180 Net income attributable to PAA $ 970 $ 446 $ 449 $ 306 $ 2,171 Basic net income per common unit $ 1.26 $ 0.54 $ 0.55 $ 0.35 $ 2.70 Diluted net income per common unit $ 1.20 $ 0.54 $ 0.55 $ 0.35 $ 2.65 Cash distributions per common unit (3) $ 0.30 $ 0.36 $ 0.36 $ 0.36 $ 1.38 2018 Total revenues $ 8,398 $ 8,080 $ 8,792 $ 8,786 $ 34,055 Gross margin (2) $ 460 $ 168 $ 567 $ 1,399 $ 2,593 Operating income $ 381 $ 88 $ 493 $ 1,315 $ 2,277 Net income $ 288 $ 100 $ 710 $ 1,117 $ 2,216 Net income attributable to PAA $ 288 $ 100 $ 710 $ 1,117 $ 2,216 Basic net income per common unit $ 0.33 $ 0.07 $ 0.91 $ 1.46 $ 2.77 Diluted net income per common unit $ 0.33 $ 0.07 $ 0.87 $ 1.38 $ 2.71 Cash distributions per common unit (3) $ 0.30 $ 0.30 $ 0.30 $ 0.30 $ 1.20 (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, (iii) Depreciation and amortization and (iv) (Gains)/losses on asset sales and asset impairments, net. (3) Represents cash distributions declared and paid in the period presented.

Operating Segments (Tables)

Operating Segments (Tables)	12 Months Ended
	Dec. 31, 2019
Segment Reporting [Abstract]
Segment financial data	The following tables reflect certain financial data for each segment (in millions): Transportation Facilities Supply and Intersegment Total Year Ended December 31, 2019 Revenues: External customers (1) $ 1,259 $ 609 $ 32,272 $ (471) $ 33,669 Intersegment (2) 1,061 562 4 471 2,098 Total revenues of reportable segments $ 2,320 $ 1,171 $ 32,276 $ — $ 35,767 Equity earnings in unconsolidated entities $ 388 $ — $ — $ 388 Segment Adjusted EBITDA $ 1,722 $ 705 $ 803 $ 3,230 Capital expenditures (3) $ 1,127 $ 227 $ 33 $ 1,387 Maintenance capital $ 161 $ 97 $ 29 $ 287 As of December 31, 2019 Total assets $ 14,902 $ 7,336 $ 6,439 $ 28,677 Investments in unconsolidated entities $ 3,557 $ 126 $ — $ 3,683 Transportation Facilities Supply and Intersegment Total Year Ended December 31, 2018 Revenues: External customers (1) $ 1,116 $ 588 $ 32,819 $ (468) $ 34,055 Intersegment (2) 874 573 3 468 1,918 Total revenues of reportable segments $ 1,990 $ 1,161 $ 32,822 $ — $ 35,973 Equity earnings in unconsolidated entities $ 375 $ — $ — $ 375 Segment Adjusted EBITDA $ 1,508 $ 711 $ 462 $ 2,681 Capital expenditures (3) $ 1,631 $ 234 $ 23 $ 1,888 Maintenance capital $ 139 $ 100 $ 13 $ 252 As of December 31, 2018 Total assets $ 13,288 $ 7,200 $ 5,023 $ 25,511 Investments in unconsolidated entities $ 2,594 $ 108 $ — $ 2,702 Transportation Facilities Supply and Intersegment Total Year Ended December 31, 2017 Revenues: External customers (1) $ 1,021 $ 555 $ 25,056 $ (409) $ 26,223 Intersegment (2) 697 618 9 409 1,733 Total revenues of reportable segments $ 1,718 $ 1,173 $ 25,065 $ — $ 27,956 Equity earnings in unconsolidated entities $ 290 $ — $ — $ 290 Segment Adjusted EBITDA $ 1,287 $ 734 $ 60 $ 2,081 Capital expenditures (3) $ 2,126 $ 312 $ 20 $ 2,458 Maintenance capital $ 120 $ 114 $ 13 $ 247 As of December 31, 2017 Total assets $ 12,661 $ 7,313 $ 5,377 $ 25,351 Investments in unconsolidated entities $ 2,681 $ 75 $ — $ 2,756 (1) Transportation revenues from External customers include certain inventory exchanges with our customers where our Supply and Logistics segment has transacted the inventory exchange and serves as the shipper on our pipeline systems. See Note 3 for a discussion of our related accounting policy. We have included an estimate of the revenues from these inventory exchanges in our Transportation segment revenues from External customers presented above and adjusted those revenues out such that Total revenues from External customers reconciles to our Consolidated Statements 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 activities are conducted at posted tariff rates where applicable, or otherwise at 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.
Reconciliation of Segment Adjusted EBITDA 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, 2019 2018 2017 Segment Adjusted EBITDA $ 3,230 $ 2,681 $ 2,081 Adjustments (1) : Depreciation and amortization of unconsolidated entities (2) (62) (56) (45) Gains/(losses) from derivative activities net of inventory valuation adjustments (3) (160) 519 46 Long-term inventory costing adjustments (4) 20 (21) 24 Deficiencies under minimum volume commitments, net (5) 18 (7) (2) Equity-indexed compensation expense (6) (17) (55) (23) Net gain/(loss) on foreign currency revaluation (7) (14) (3) 26 Line 901 incident (8) (10) — (32) Significant acquisition-related expenses (9) — — (6) Depreciation and amortization (601) (520) (517) Gains/(losses) on asset sales and asset impairments, net (28) 114 (109) Gain on investment in unconsolidated entities 271 200 — Interest expense, net (425) (431) (510) Other income/(expense), net 24 (7) (31) Income before tax 2,246 2,414 902 Income tax expense (66) (198) (44) Net income 2,180 2,216 858 Net income attributable to noncontrolling interests (9) — (2) Net income attributable to PAA $ 2,171 $ 2,216 $ 856 (1) Represents adjustments utilized by our CODM in the evaluation of segment results. (2) Includes our proportionate share of the depreciation and amortization of, and gains and losses on significant asset sales by, unconsolidated entities. (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. (6) Includes equity-indexed compensation expense associated with awards that will or may be settled in units. (7) Includes gains and losses realized on the settlement of foreign currency transactions as well as the revaluation of monetary assets and liabilities denominated in a foreign currency. (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. See Note 19 for additional information regarding the Line 901 incident.
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) 2019 2018 2017 United States $ 27,162 $ 28,362 $ 21,443 Canada 6,507 5,693 4,780 $ 33,669 $ 34,055 $ 26,223 (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) 2019 2018 United States $ 17,565 $ 15,885 Canada 3,935 3,542 $ 21,500 $ 19,427 (1) Excludes long-term derivative assets, long-term deferred tax assets and goodwill.

Organization and Basis of Con_2

Organization and Basis of Consolidation and Presentation (Details) shares in Millions	12 Months Ended
	Dec. 31, 2019segmentshares
Organization and basis of presentation
Operating segments number | segment	3
AAP | PAGP
Organization and basis of presentation
Limited partner interest	73.00%
PAA | AAP
Organization and basis of presentation
Limited partner interest (units) | shares	249.6
Limited partner interest	31.00%

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Various Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Foreign Currency Transactions/Translation
Gain (loss) on revaluation of foreign currency transactions and monetary assets and liabilities	$ 1	$ 1	$ 21
Cash and Cash Equivalents and Restricted Cash
Outstanding checks included in accounts payable that were reclassified from cash and cash equivalents	38	57
Asset Retirement Obligations
Fair value of asset retirement obligations	137	109	103	$ 44
Other long-term liabilities and deferred credits
Asset Retirement Obligations
Fair value of asset retirement obligations	$ 135	$ 107	$ 99

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Cash and Restricted Cash (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Cash and cash equivalents	$ 45	$ 66
Restricted cash	37
Total cash and cash equivalents and restricted cash	$ 82	$ 66	$ 37	$ 47

Summary of Significant Accoun_6

Summary of Significant Accounting Policies - Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 109	$ 103	$ 44
Liabilities incurred	3	3	33
Liabilities settled	(3)	(3)	(4)
Accretion expense	5	4	3
Revisions in estimated cash flows	23	2	27
Ending balance	$ 137	$ 109	$ 103

Summary of Significant Accoun_7

Summary of Significant Accounting Policies - Recent Accounting Pronouncements (Details) - USD ($) $ in Millions	Dec. 31, 2019	Jan. 01, 2019
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Net lease right-of-use assets recognized upon adoption of Topic 842	$ 574
Lease liabilities recognized upon adoption of Topic 842	$ 548
ASU 2016-02
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Net lease right-of-use assets recognized upon adoption of Topic 842		$ 560
Lease liabilities recognized upon adoption of Topic 842		$ 570

Revenues and Accounts Receiva_3

Revenues and Accounts Receivable - Disaggregation of Revenue (Details) - Operating Segments - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 35,371	$ 35,812
Supply And Logistics
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	31,966	32,700
Supply And Logistics | Crude oil transactions
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	30,082	29,592
Supply And Logistics | NGL and other transactions
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	1,884	3,108
Transportation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	2,283	1,976
Transportation | Total tariff activities
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	2,138	1,827
Transportation | Crude oil pipelines
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	2,039	1,724
Transportation | NGL pipelines
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	99	103
Transportation | Trucking
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	145	149
Facilities
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	1,122	1,136
Facilities | Crude oil, NGL and other terminalling and storage
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	697	688
Facilities | NGL and natural gas processing and fractionation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	349	364
Facilities | Rail load / unload
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 76	$ 84

Revenues and Accounts Receiva_4

Revenues and Accounts Receivable - Segment Revenue (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Total revenues	$ 9,154	$ 7,886	$ 8,253	$ 8,375	$ 8,786	$ 8,792	$ 8,080	$ 8,398	$ 33,669	$ 34,055	$ 26,223
Transportation
Disaggregation of Revenue [Line Items]
Total revenues									788	648	612
Facilities
Disaggregation of Revenue [Line Items]
Total revenues									609	588	555
Supply And Logistics
Disaggregation of Revenue [Line Items]
Total revenues									32,272	32,819	25,056
Operating Segments
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers									35,371	35,812
Total revenues									35,767	35,973	27,956
Operating Segments | Transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers									2,283	1,976
Total revenues									2,320	1,990	1,718
Operating Segments | Facilities
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers									1,122	1,136
Total revenues									1,171	1,161	1,173
Operating Segments | Supply And Logistics
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers									31,966	32,700
Total revenues									32,276	32,822	25,065
Intersegment
Disaggregation of Revenue [Line Items]
Total revenues									(2,098)	(1,918)	(1,733)
Intersegment | Transportation
Disaggregation of Revenue [Line Items]
Total revenues									(1,061)	(874)	(697)
Intersegment | Facilities
Disaggregation of Revenue [Line Items]
Total revenues									(562)	(573)	(618)
Intersegment | Supply And Logistics
Disaggregation of Revenue [Line Items]
Total revenues									(4)	(3)	$ (9)
Other | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenues									396	161
Other | Operating Segments | Transportation
Disaggregation of Revenue [Line Items]
Total revenues									37	14
Other | Operating Segments | Facilities
Disaggregation of Revenue [Line Items]
Total revenues									49	25
Other | Operating Segments | Supply And Logistics
Disaggregation of Revenue [Line Items]
Total revenues									$ 310	$ 122

Revenues and Accounts Receiva_5

Revenues and Accounts Receivable - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Contract With Customer, Asset And Liability [Line Items]
Other current assets	$ 312	$ 373
Contract liability, deferred revenue	$ 354	$ 338	$ 90
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	$ 3
General payment terms	30 days
Crude Oil Sales Agreements Entered Into In Conjunction WIth Storage Arrangements And Future Inventory Exchanges
Contract With Customer, Asset And Liability [Line Items]
Other current assets	$ 142	115
Contract liability, deferred revenue	155	116
Minimum Volume Commitments
Contract With Customer, Asset And Liability [Line Items]
Contract liability, deferred revenue	22	40
Counterparty deficiencies	42	62
Counterparty deficiencies unbilled and uncollected	$ 20	$ 22

Revenues and Accounts Receiva_6

Revenues and Accounts Receivable - Contract Balances (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Change in Contract Liabilities [Roll Forward]
Beginning balance	$ 338	$ 90
Amounts recognized as revenue	(227)	(81)
Additions	244	332
Other	(1)	(3)
Ending balance	354	338
Crude Oil Sales Agreements Entered Into In Conjunction WIth Storage Arrangements And Future Inventory Exchanges
Change in Contract Liabilities [Roll Forward]
Beginning balance	116
Additions	155	116
Ending balance	$ 155	116
Long-term capacity agreement | Cactus II Pipeline LLC (“Cactus II”)
Change in Contract Liabilities [Roll Forward]
Additions		$ 100

Revenues and Accounts Receiva_7

Revenues and Accounts Receivable - Performance Obligations (Details) $ in Millions	Dec. 31, 2019USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 568
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	482
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	412
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	356
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	293
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	1,064
Pipeline revenues supported by minimum volume commitments and long-term capacity agreements | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 164
Remaining performance obligation, expected timing of satisfaction, period	1 year
Pipeline revenues supported by minimum volume commitments and long-term capacity agreements | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 170
Remaining performance obligation, expected timing of satisfaction, period	1 year
Pipeline revenues supported by minimum volume commitments and long-term capacity agreements | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 170
Remaining performance obligation, expected timing of satisfaction, period	1 year
Pipeline revenues supported by minimum volume commitments and long-term capacity agreements | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 168
Remaining performance obligation, expected timing of satisfaction, period	1 year
Pipeline revenues supported by minimum volume commitments and long-term capacity agreements | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 146
Remaining performance obligation, expected timing of satisfaction, period	1 year
Pipeline revenues supported by minimum volume commitments and long-term capacity agreements | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 698
Remaining performance obligation, expected timing of satisfaction, period
Long-term storage, terminalling and throughput agreements revenues | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 404
Remaining performance obligation, expected timing of satisfaction, period	1 year
Long-term storage, terminalling and throughput agreements revenues | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 312
Remaining performance obligation, expected timing of satisfaction, period	1 year
Long-term storage, terminalling and throughput agreements revenues | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 242
Remaining performance obligation, expected timing of satisfaction, period	1 year
Long-term storage, terminalling and throughput agreements revenues | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 188
Remaining performance obligation, expected timing of satisfaction, period	1 year
Long-term storage, terminalling and throughput agreements revenues | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 147
Remaining performance obligation, expected timing of satisfaction, period	1 year
Long-term storage, terminalling and throughput agreements revenues | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 366
Remaining performance obligation, expected timing of satisfaction, period

Revenues and Accounts Receiva_8

Revenues and Accounts Receivable - Contract Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Trade accounts receivable arising from revenues from contracts with customers	$ 3,381	$ 2,277
Other trade accounts receivables and other receivables	3,576	2,732
Impact due to contractual rights of offset with counterparties	(3,343)	(2,555)
Trade accounts receivable and other receivables, net	$ 3,614	$ 2,454

Net Income Per Common Unit (Det

Net Income Per Common Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Basic Net Income per Common Unit
Net income attributable to PAA	$ 306	$ 449	$ 446	$ 970	$ 1,117	$ 710	$ 100	$ 288	$ 2,171	$ 2,216	$ 856
Distributions to participating securities									(3)	(3)	(2)
Other									(3)	(6)	(16)
Net income allocated to common unitholders									1,967	2,009	685
Diluted Net Income per Common Unit
Net income attributable to PAA	$ 306	$ 449	$ 446	$ 970	$ 1,117	$ 710	$ 100	$ 288	2,171	2,216	856
Distributions to participating securities									(3)	(3)	(2)
Other											(16)
Net income allocated to common unitholders									2,119	2,164	685
Series A Preferred Units
Basic Net Income per Common Unit
Distributions to preferred unitholders									(149)	(149)	(142)
Diluted Net Income per Common Unit
Distributions to preferred unitholders											(142)
Series B Preferred Units
Basic Net Income per Common Unit
Distributions to preferred unitholders									(49)	(49)	(11)
Diluted Net Income per Common Unit
Distributions to preferred unitholders									$ (49)	$ (49)	$ (11)
Common Units
Basic Net Income per Common Unit
Basic weighted average common units outstanding (in units)									727	726	717
Basic net income per common unit (in dollars per unit)	$ 0.35	$ 0.55	$ 0.54	$ 1.26	$ 1.46	$ 0.91	$ 0.07	$ 0.33	$ 2.70	$ 2.77	$ 0.96
Diluted Net Income per Common Unit
Basic weighted average common units outstanding (in units)									727	726	717
Effect of dilutive securities:
Series A preferred units (in units)									71	71
Equity-indexed compensation plan awards (in units)									2	2	1
Diluted weighted average common units outstanding (in units)									800	799	718
Diluted net income per common unit (in dollars per unit)	$ 0.35	$ 0.55	$ 0.54	$ 1.20	$ 1.38	$ 0.87	$ 0.07	$ 0.33	$ 2.65	$ 2.71	$ 0.95

Inventory, Linefill and Base _3

Inventory, Linefill and Base Gas and Long-term Inventory (Details) bbl in Thousands, Mcf in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)$ / bbl$ / McfbblMcf	Dec. 31, 2018USD ($)$ / bbl$ / McfbblMcf	Dec. 31, 2017USD ($)
Inventory-related disclosures
Charge related to the write-down of inventory	$ 11	$ 8	$ 35
Inventory by category
Inventory	604	640
Linefill and base gas	981	916
Long-term inventory	182	136
Total	$ 1,767	$ 1,692
Crude oil
Inventory by category
Inventory, Volumes (in barrels or in Mcf) | bbl	8,613	9,657
Linefill and base gas, Volumes (in barrels or in Mcf) | bbl	14,316	13,312
Long-term inventory, Volumes (in barrels or in Mcf) | bbl	2,598	1,890
Inventory	$ 450	$ 367
Linefill and base gas	826	761
Long-term inventory	$ 152	$ 79
Inventory, Price/Unit of measure (in dollars per unit) | $ / bbl	52.25	38
Linefill and base gas, Price/Unit of measure (in dollars per unit) | $ / bbl	57.70	57.17
Long-term inventory, Price/Unit of measure (in dollars per unit) | $ / bbl	58.51	41.80
NGL
Inventory by category
Inventory, Volumes (in barrels or in Mcf) | bbl	7,574	10,384
Linefill and base gas, Volumes (in barrels or in Mcf) | bbl	1,701	1,730
Long-term inventory, Volumes (in barrels or in Mcf) | bbl	1,707	2,368
Inventory	$ 142	$ 262
Linefill and base gas	47	47
Long-term inventory	$ 30	$ 57
Inventory, Price/Unit of measure (in dollars per unit) | $ / bbl	18.75	25.23
Linefill and base gas, Price/Unit of measure (in dollars per unit) | $ / bbl	27.63	27.17
Long-term inventory, Price/Unit of measure (in dollars per unit) | $ / bbl	17.57	24.07
Natural gas
Inventory by category
Linefill and base gas, Volumes (in barrels or in Mcf) | Mcf	24,976	24,976
Linefill and base gas	$ 108	$ 108
Linefill and base gas, Price/Unit of measure (in dollars per unit) | $ / Mcf	4.32	4.32
Other
Inventory by category
Inventory	$ 12	$ 11

Property and Equipment (Details

Property and Equipment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Property and Equipment
Capitalized interest	$ 34	$ 30	$ 35
Property and equipment, gross	18,948	17,866
Accumulated depreciation	(3,593)	(3,079)
Property and equipment, net	15,355	14,787
Depreciation expense	525	454	463
Construction in progress expenditures incurred but not yet paid	120	206	127
Pipelines and related facilities
Property and Equipment
Property and equipment, gross	$ 11,114	10,137
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	$ 6,134	5,854
Storage, terminal and rail facilities | Minimum
Property and Equipment
Estimated useful lives	10 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	$ 486	410
Trucking equipment and other | Minimum
Property and Equipment
Estimated useful lives	2 years
Trucking equipment and other | Maximum
Property and Equipment
Estimated useful lives	15 years
Construction in progress
Property and Equipment
Property and equipment, gross	$ 518	795
Office property and equipment
Property and Equipment
Property and equipment, gross	$ 269	248
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	$ 427	422
Property and equipment
Property and Equipment
Capitalized interest	$ 14	$ 21	17
Rail And Other Terminal Assets | (Gains)/losses on asset sales and asset impairments, net | Facilities
Property and Equipment
Non-cash charge related to write-down of long-lived assets			$ 152

Acquisitions and Divestitures -

Acquisitions and Divestitures - Acquisitions (Details) $ in Millions	Feb. 14, 2017USD ($)amarket_interconnectcontractmi	Feb. 26, 2020USD ($)	Feb. 28, 2017USD ($)	Jun. 30, 2019USD ($)	Dec. 31, 2017bbl / d	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Apr. 03, 2017
Business Acquisition [Line Items]
Cash consideration						$ 50		$ 1,280
Amortization expense for finite-lived intangible assets						76	$ 66	54
Acquisition-related expenses								6
Crude Oil Terminal
Business Acquisition [Line Items]
Cash consideration				$ 44
Felix Midstream LLC | Subsequent Event
Business Acquisition [Line Items]
Cash consideration		$ 305
Alpha Holding Company, LLC
Business Acquisition [Line Items]
Cash consideration	$ 1,215
Length of gathering and transmission lines (in miles) | mi	515
Number of market interconnects | market_interconnect	5
Additional volume enhancements to gathering system (bbls per day) | bbl / d					350,000
Area of acreage dedication (gross acres) | a	315,000
Weighted-average useful life	20 years
Acquisition-related expenses								6
Propane Marine Terminal
Business Acquisition [Line Items]
Cash consideration			$ 41
Advantage Joint Venture
Business Acquisition [Line Items]
Ownership interest									50.00%
Acreage Dedication Contracts | Alpha Holding Company, LLC
Business Acquisition [Line Items]
Number of acreage dedication contracts acquired | contract	5
Weighted-average useful life	20 years
Amortization expense for finite-lived intangible assets						$ 34	$ 25	$ 10

Acquisitions and Divestitures_2

Acquisitions and Divestitures - Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Millions	Feb. 14, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Business Acquisition [Line Items]
Goodwill		$ 2,540	$ 2,521	$ 2,566
Alpha Holding Company, LLC
Business Acquisition [Line Items]
Property and equipment	$ 299
Intangible assets	646
Goodwill	269
Other assets and liabilities, net (including $4 million of cash acquired)	1
Identifiable assets acquired and liabilities assumed	1,215
Cash acquired	$ 4
Minimum | Alpha Holding Company, LLC
Business Acquisition [Line Items]
Estimated useful lives	3 years
Maximum | Alpha Holding Company, LLC
Business Acquisition [Line Items]
Estimated useful lives	70 years

Acquisitions and Divestitures_3

Acquisitions and Divestitures - Future Amortization Expense (Details) $ in Millions	Dec. 31, 2019USD ($)
Business Acquisition [Line Items]
2020	$ 77
2021	73
2022	74
Acreage Dedication Contracts | Alpha Holding Company, LLC
Business Acquisition [Line Items]
2020	42
2021	48
2022	$ 54

Acquisitions and Divestitures_4

Acquisitions and Divestitures - Divestitures (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended	12 Months Ended
	Jan. 31, 2020	Sep. 30, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Divestitures
Proceeds from sales of assets			$ 77	$ 1,334	$ 1,083
Disposed of by sale
Divestitures
Proceeds from sales of assets			77
Disposed of by sale | (Gains)/losses on asset sales and asset impairments, net
Divestitures
Recognized gains/(losses) related to sale of assets, net			16	120	43
Recognized gains related to sale of assets			31	146	123
Recognized losses related to sale of assets			$ 47	26	$ 80
Red River Pipeline
Divestitures
Ownership interest disposed of					40.00%
Los Angeles Basin Crude Oil Terminals | Disposed of by sale | Subsequent Event
Divestitures
Proceeds from sales of assets	$ 195
Recognized gains/(losses) related to sale of assets, net	$ 160
BridgeTex Pipeline Company, LLC (“BridgeTex”)
Divestitures
Ownership percentage sold		30.00%
Proceeds from sale of equity method investment		$ 868
Gain on sale of investment in unconsolidated entities				$ 200

Goodwill (Details)

Goodwill (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Changes in goodwill
Balance at beginning of period	$ 2,521	$ 2,566
Foreign currency translation adjustments	19	(32)
Divestitures		(13)
Balance at end of period	2,540	2,521
Operating Segments | Transportation
Changes in goodwill
Balance at beginning of period	1,040	1,070
Foreign currency translation adjustments	12	(19)
Divestitures		(11)
Balance at end of period	1,052	1,040
Operating Segments | Facilities
Changes in goodwill
Balance at beginning of period	978	988
Foreign currency translation adjustments	4	(8)
Divestitures		(2)
Balance at end of period	982	978
Operating Segments | Supply And Logistics
Changes in goodwill
Balance at beginning of period	503	508
Foreign currency translation adjustments	3	(5)
Balance at end of period	$ 506	$ 503

Investments in Unconsolidated_3

Investments in Unconsolidated Entities - Equity Method Investments (Details) shares in Millions, $ in Millions	Apr. 03, 2017USD ($)shares	Mar. 31, 2019USD ($)	Sep. 30, 2018USD ($)	Jun. 30, 2018USD ($)	Dec. 31, 2021USD ($)bbl	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Jun. 30, 2019
Investments in Unconsolidated Entities
Investments in unconsolidated entities						$ 3,683	$ 2,702	$ 2,756
Carrying value of undivided joint interest						15,355	14,787
Advance cash payment, pipeline capacity agreements						354	338	90
Value of units contributed								40
Capital contributions to equity method investees excluding capitalized interest						504	459	398
Capitalized interest related to contributions to unconsolidated entities						34	30	$ 35
Amount by which investments in unconsolidated entities exceeded our share of the underlying equity in the net assets						$ 349	467
Advantage Pipeline Holdings LLC (“Advantage Joint Venture”)
Investments in Unconsolidated Entities
Ownership interest	50.00%					50.00%
Investments in unconsolidated entities	$ 66.5					$ 76	72
Payments to acquire equity method investments	26
BridgeTex Pipeline Company, LLC (“BridgeTex”)
Investments in Unconsolidated Entities
Ownership interest			20.00%			20.00%
Investments in unconsolidated entities						$ 431	435
Proceeds from sale of equity method investment			$ 868
Ownership percentage sold			30.00%
Gain on sale of investment in unconsolidated entities							200
Cactus II Pipeline LLC (“Cactus II”)
Investments in Unconsolidated Entities
Ownership interest						65.00%
Investments in unconsolidated entities						$ 738	455
Reduction of property and equipment from deconsolidation				$ 74
Proceeds from sale of equity method investment				$ 26
Caddo Pipeline LLC
Investments in Unconsolidated Entities
Ownership interest						50.00%
Investments in unconsolidated entities						$ 65	65
Capline Pipeline Company LLC
Investments in Unconsolidated Entities
Ownership interest						54.00%
Investments in unconsolidated entities						$ 484
Fair value of investment in unconsolidated entity		$ 444
Capline Pipeline Company LLC | Gain on investment in unconsolidated entities
Investments in Unconsolidated Entities
Gain from remeasurement to fair value of retained investment						$ 269
Cheyenne Pipeline LLC (“Cheyenne”)
Investments in Unconsolidated Entities
Ownership interest						50.00%
Investments in unconsolidated entities						$ 44	44
Cushing Connect Pipeline & Terminal LLC
Investments in Unconsolidated Entities
Ownership interest						50.00%
Investments in unconsolidated entities						$ 23
Diamond Pipeline LLC (“Diamond”)
Investments in Unconsolidated Entities
Ownership interest						50.00%
Investments in unconsolidated entities						$ 476	479
Eagle Ford Pipeline LLC (“Eagle Ford Pipeline”)
Investments in Unconsolidated Entities
Ownership interest						50.00%
Investments in unconsolidated entities						$ 382	383
Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Terminals”)
Investments in Unconsolidated Entities
Ownership interest						50.00%
Investments in unconsolidated entities						$ 126	108
Midway Pipeline LLC
Investments in Unconsolidated Entities
Ownership interest						50.00%		50.00%
Investments in unconsolidated entities						$ 76	78
Red Oak Pipeline LLC (“Red Oak”)
Investments in Unconsolidated Entities
Ownership interest						50.00%			50.00%
Investments in unconsolidated entities						$ 20
Red Oak Pipeline LLC (“Red Oak”) | Forecast
Investments in Unconsolidated Entities
Future increase in investment from contribution					$ 155
Red Oak Pipeline LLC (“Red Oak”) | Sunrise II pipeline | Forecast
Investments in Unconsolidated Entities
Pipeline capacity to be contributed (in bbls) | bbl					260,000
Capacity lease agreement, term of contract					33 years
Saddlehorn Pipeline Company, LLC (“Saddlehorn”)
Investments in Unconsolidated Entities
Ownership interest						40.00%
Investments in unconsolidated entities						$ 234	215
Settoon Towing, LLC
Investments in Unconsolidated Entities
Ownership interest						50.00%
Investments in unconsolidated entities						$ 59	58
STACK Pipeline LLC (“STACK”)
Investments in Unconsolidated Entities
Ownership interest						50.00%
Investments in unconsolidated entities						$ 117	120
White Cliffs Pipeline, LLC
Investments in Unconsolidated Entities
Ownership interest						36.00%
Investments in unconsolidated entities						$ 196	190
Wink to Webster Pipeline LLC (“W2W Pipeline”)
Investments in Unconsolidated Entities
Ownership interest						16.00%
Investments in unconsolidated entities						$ 136
Equity Method Investees
Investments in Unconsolidated Entities
Capitalized interest related to contributions to unconsolidated entities						$ 20	$ 9	$ 18
Capline Pipeline Company LLC | Capline pipeline system
Investments in Unconsolidated Entities
Percentage of Capline pipeline system owned		100.00%
Advantage Joint Venture | Advantage Pipeline Holdings LLC (“Advantage Joint Venture”)
Investments in Unconsolidated Entities
Purchase price	$ 133
Oxy | Cactus II Pipeline LLC (“Cactus II”)
Investments in Unconsolidated Entities
Interest acquired				20.00%
Third Party | Cactus II Pipeline LLC (“Cactus II”)
Investments in Unconsolidated Entities
Interest acquired				15.00%
Common Units | Advantage Pipeline Holdings LLC (“Advantage Joint Venture”)
Investments in Unconsolidated Entities
Units contributed | shares	1.3
Value of units contributed	$ 40
Other long-term liabilities and deferred credits | Cactus II Pipeline LLC (“Cactus II”)
Investments in Unconsolidated Entities
Advance cash payment, pipeline capacity agreements				$ 100
Undivided joint interest in Capline pipeline system
Investments in Unconsolidated Entities
Undivided joint interest ownership percentage		54.00%
Carrying value of undivided joint interest		$ 175
Undivided joint interest in pipeline segment | Wink to Webster Pipeline LLC (“W2W Pipeline”) | Midland, Texas to Webster, Texas pipeline segment
Investments in Unconsolidated Entities
Undivided joint interest ownership percentage						71.00%
Undivided joint interest in pipeline segment | Enterprise Products Partners, L.P. | Midland, Texas to Webster, Texas pipeline segment
Investments in Unconsolidated Entities
Undivided joint interest ownership percentage						29.00%

Investments in Unconsolidated_4

Investments in Unconsolidated Entities - Summarized Financial Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Combined summarized financial information for unconsolidated entities
Current assets	$ 652	$ 357
Noncurrent assets	7,264	4,861
Current liabilities	298	170
Noncurrent liabilities	26	30
Revenues	1,469	1,235	$ 938
Operating income	994	824	650
Net income	$ 995	$ 824	$ 640

Other Long-Term Assets, Net - S

Other Long-Term Assets, Net - Schedule of Other Long-term Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Finite-Lived Intangible Assets
Finite-lived intangible assets, cost	$ 1,199	$ 1,209
Finite-lived intangible assets, accumulated amortization	(492)	(437)
Finite-lived intangible assets, net	707	772
Other Long-Term Assets, Net
Other, cost	152	144
Other, accumulated amortization	(1)
Other, net	151	144
Other long-term assets, cost	1,351	1,353
Other long-term assets, accumulated amortization	(493)	(437)
Other long-term assets, net	858	916
Customer contracts and relationships
Finite-Lived Intangible Assets
Finite-lived intangible assets, cost	1,134	1,152
Finite-lived intangible assets, accumulated amortization	(463)	(413)
Finite-lived intangible assets, net	$ 671	739
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
Finite-lived intangible assets, cost	$ 23	23
Finite-lived intangible assets, accumulated amortization	(18)	(16)
Finite-lived intangible assets, net	$ 5	7
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
Finite-lived intangible assets, cost	$ 42	34
Finite-lived intangible assets, accumulated amortization	(11)	(8)
Finite-lived intangible assets, net	$ 31	$ 26
Other agreements | Minimum
Finite-Lived Intangible Assets
Estimated Useful Lives	25 years
Other agreements | Maximum
Finite-Lived Intangible Assets
Estimated Useful Lives	70 years

Other Long-Term Assets, Net - A

Other Long-Term Assets, Net - Amortization Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Other Assets [Abstract]
Amortization expense for finite-lived intangible assets	$ 76	$ 66	$ 54
Estimated amortization expense related to finite-lived intangible assets for the next five years
2020	77
2021	73
2022	74
2023	69
2024	$ 67

Debt - Schedule of Debt (Detail

Debt - Schedule of Debt (Details) - USD ($)	Dec. 31, 2019	Dec. 31, 2018
SHORT-TERM DEBT
Short-term debt	$ 504,000,000	$ 66,000,000
LONG-TERM DEBT
Senior notes, net of unamortized discounts and debt issuance costs	8,939,000,000	8,941,000,000
Noncurrent portion of other long-term debt	248,000,000	202,000,000
Total long-term debt	9,187,000,000	9,143,000,000
Total debt	9,691,000,000	9,209,000,000
Other
SHORT-TERM DEBT
Short-term debt	86,000,000	66,000,000
Commercial Paper | Line of Credit
SHORT-TERM DEBT
Short-term notes and borrowings	$ 93,000,000
Weighted average interest rate, short-term (as a percent)	2.20%
Senior secured hedged inventory facility | Line of Credit
SHORT-TERM DEBT
Short-term notes and borrowings	$ 325,000,000
Weighted average interest rate, short-term (as a percent)	2.70%
Senior notes
LONG-TERM DEBT
Unamortized discounts and debt issuance costs	$ (61,000,000)	(59,000,000)
Senior notes, net of unamortized discounts and debt issuance costs	8,939,000,000	8,941,000,000
Debt instrument face value	9,000,000,000	9,000,000,000
Senior notes | Level 2
LONG-TERM DEBT
Debt instrument fair value	$ 9,300,000,000	8,600,000,000
Senior notes | 2.60% senior notes due December 2019
LONG-TERM DEBT
Long-term debt, before deducting unamortized discounts and debt issuance costs		$ 500,000,000
Debt instrument, interest rate (as a percent)	2.60%	2.60%
Debt instrument face value		$ 500,000,000
Senior notes | 5.75% senior notes due January 2020
LONG-TERM DEBT
Long-term debt, before deducting unamortized discounts and debt issuance costs		$ 500,000,000
Debt instrument, interest rate (as a percent)	5.75%	5.75%
Senior notes | 5.00% senior notes due February 2021
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%
Senior notes | 3.65% senior notes due June 2022
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%
Senior notes | 2.85% senior notes due January 2023
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%
Senior notes | 3.85% senior notes due October 2023
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%
Senior notes | 3.60% senior notes due November 2024
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%
Senior notes | 4.65% senior notes due October 2025
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%
Senior notes | 4.50% senior notes due December 2026
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)	4.50%	4.50%
Senior notes | 3.55% senior notes due December 2029
LONG-TERM DEBT
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 1,000,000,000
Debt instrument, interest rate (as a percent)	3.55%
Debt instrument face value	$ 1,000,000,000
Senior notes | 6.70% senior notes due May 2036
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%
Senior notes | 6.65% senior notes due January 2037
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%
Senior notes | 5.15% senior notes due June 2042
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%
Senior notes | 4.30% senior notes due January 2043
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%
Senior notes | 4.70% senior notes due June 2044
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%
Senior notes | 4.90% senior notes due February 2045
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%
Term Loan | GO Zone Term Loans
LONG-TERM DEBT
Noncurrent portion of other long-term debt	$ 199,000,000	$ 198,000,000
Debt issuance costs	$ 1,000,000	$ 2,000,000
Weighted average long term debt interest rate	2.60%	3.10%
Other long-term debt
LONG-TERM DEBT
Noncurrent portion of other long-term debt	$ 49,000,000	$ 4,000,000

Debt - Commercial Paper and Cre

Debt - Commercial Paper and Credit Facilities (Details)	12 Months Ended
	Dec. 31, 2019USD ($)extension	Aug. 31, 2018USD ($)debt_instrument
Commercial Paper
Debt Instrument [Line Items]
Maximum aggregate borrowing capacity	$ 3,000,000,000
Senior secured hedged inventory facility
Debt Instrument [Line Items]
Maximum aggregate borrowing capacity	1,900,000,000
Committed borrowing capacity	$ 1,400,000,000
Number of years by which maturity date of credit facility may be extended	1 year
Senior secured hedged inventory facility | Minimum
Debt Instrument [Line Items]
Credit facility extensions available | extension	1
Senior secured hedged inventory facility | Letters of credit
Debt Instrument [Line Items]
Committed borrowing capacity	$ 400,000,000
Senior unsecured revolving credit facility
Debt Instrument [Line Items]
Maximum aggregate borrowing capacity	2,100,000,000
Committed borrowing capacity	$ 1,600,000,000
Number of years by which maturity date of credit facility may be extended	1 year
Senior unsecured revolving credit facility | Minimum
Debt Instrument [Line Items]
Credit facility extensions available | extension	1
GO Zone Term Loans | Term Loan
Debt Instrument [Line Items]
Number of debt instruments | debt_instrument		2
GO Zone Term Loan Series 2009 | Term Loan
Debt Instrument [Line Items]
Debt instrument face value		$ 100,000,000
GO Zone Term Loan Series 2010 | Term Loan
Debt Instrument [Line Items]
Debt instrument face value		$ 100,000,000
Non-extending Lender | Senior secured hedged inventory facility
Debt Instrument [Line Items]
Committed borrowing capacity	$ 45,000,000

Debt - Senior Notes (Details)

Debt - Senior Notes (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2017	Dec. 31, 2018
Debt Instrument [Line Items]
Repayments of senior notes	$ 1,000,000,000	$ 1,350,000,000
Senior notes
Debt Instrument [Line Items]
Debt instrument face value	$ 9,000,000,000		$ 9,000,000,000
Senior notes | 3.55% senior notes due December 2029
Debt Instrument [Line Items]
Debt instrument, interest rate (as a percent)	3.55%
Offering price percentage	99.801%
Debt instrument face value	$ 1,000,000,000
Senior notes | 2.60% senior notes due December 2019
Debt Instrument [Line Items]
Debt instrument, interest rate (as a percent)	2.60%		2.60%
Debt instrument face value			$ 500,000,000
Repayments of senior notes	$ 500,000,000
Senior notes | 5.75% senior notes due January 2020
Debt Instrument [Line Items]
Debt instrument, interest rate (as a percent)	5.75%		5.75%
Repayments of senior notes	$ 500,000,000
Senior notes | 6.13% senior notes due January 2017
Debt Instrument [Line Items]
Debt instrument, interest rate (as a percent)		6.13%
Repayments of senior notes		$ 400,000,000
Senior notes | 6.50% senior notes due May 2018
Debt Instrument [Line Items]
Debt instrument, interest rate (as a percent)		6.50%
Repayments of senior notes		$ 600,000,000
Senior notes | 8.75% senior notes due May 2019
Debt Instrument [Line Items]
Debt instrument, interest rate (as a percent)		8.75%
Repayments of senior notes		$ 350,000,000
Consolidated finance subsidiary co-issuer
Debt Instrument [Line Items]
Consolidated subsidiary, ownership interest held by the parent (as a percent)	100.00%
Other income/(expense), net | Senior notes
Debt Instrument [Line Items]
Loss on early redemption of senior notes		$ 40,000,000

Debt - Maturities (Details)

Debt - Maturities (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Debt Disclosure [Abstract]
Weighted-average maturity of long-term debt	11 years
Maturities
2021	$ 600
2022	750
2023	1,300
2024	750
Thereafter	$ 5,800

Debt - Debt Covenants (Details)

Debt - Debt Covenants (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Debt Instrument [Line Items]
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
Outstanding letters of credit	157	$ 184
Credit agreements and commercial paper program
Debt Instrument [Line Items]
Total borrowings	13,300	45,400	$ 60,800
Total repayments	$ 12,900	$ 46,300	$ 61,500
Letters of credit | Maximum
Debt Instrument [Line Items]
Periods for which letters of credit are issued	70 days

Partners' Capital and Distrib_3

Partners' Capital and Distributions - Preferred Unit Issuance (Details) $ / shares in Units, $ in Millions	Oct. 10, 2017USD ($)$ / sharesshares	Jan. 28, 2016count$ / shares	Dec. 31, 2019$ / shares	Dec. 31, 2017USD ($)	Nov. 15, 2022$ / shares
Partners Capital and Distribution [Line Items]
Partners' capital account, public sale of units | $				$ 788
Series A Preferred Units
Partners Capital and Distribution [Line Items]
Shares issued, price per share		$ 26.25
Quarterly distributions per unit (in dollars per unit)			$ 0.525
Annualized distribution rate (in dollars per unit)			$ 2.10
Series A 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 | count		1
Distribution rate reset, basis spread on variable rate			5.85%
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%
Series B Preferred Units
Partners Capital and Distribution [Line Items]
Sale of units, price per unit (in dollars per unit)	$ 1,000
Liquidation preference (in dollars per unit)			$ 1,000
Distribution rate percentage			6.125%
Distribution rate (per unit)			$ 61.25
Redemption price (in dollars per unit)			$ 1,020
Redemption price percentage			102.00%
Sale of Series B preferred units (in units) | shares	800,000
Partners' capital account, public sale of units | $	$ 788
Series B Preferred Units | Forecast
Partners Capital and Distribution [Line Items]
Percentage spread on top of LIBOR for distribution					4.11%
Redemption price (in dollars per unit)					$ 1,000

Partners' Capital and Distrib_4

Partners' Capital and Distributions - Activity for Series A and B Preferred Units and Common Units (Details) - shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Series A Preferred Units
Increase (Decrease) in Partners' Capital [Roll Forward]
Balance, beginning of period (in units)	71,090,468
Balance, end of period (in units)	71,090,468	71,090,468
Series B Preferred Units
Increase (Decrease) in Partners' Capital [Roll Forward]
Balance, beginning of period (in units)	800,000
Balance, end of period (in units)	800,000	800,000
Common Units
Increase (Decrease) in Partners' Capital [Roll Forward]
Balance, beginning of period (in units)	726,361,924
Sale of common units (in units)			54,119,893
Balance, end of period (in units)	728,028,576	726,361,924
Limited Partners | Series A Preferred Units
Increase (Decrease) in Partners' Capital [Roll Forward]
Balance, beginning of period (in units)	71,090,468	69,696,542	64,388,853
Issuances of Series A preferred units in connection with in-kind distributions (in units)		1,393,926	5,307,689
Balance, end of period (in units)	71,090,468	71,090,468	69,696,542
Limited Partners | Series B Preferred Units
Increase (Decrease) in Partners' Capital [Roll Forward]
Balance, beginning of period (in units)	800,000	800,000
Sale of Series B preferred units (in units)			800,000
Balance, end of period (in units)	800,000	800,000	800,000
Limited Partners | Common Units
Increase (Decrease) in Partners' Capital [Roll Forward]
Balance, beginning of period (in units)	726,361,924	725,189,138	669,194,419
Sale of common units (in units)			54,119,893
Issuance of common units in connection with acquisition of interest in Advantage Joint Venture (Note 7) (in units)			1,252,269
Issuance of common units under equity-indexed compensation plans (in units)	1,666,652	1,172,786	622,557
Balance, end of period (in units)	728,028,576	726,361,924	725,189,138

Partners' Capital and Distrib_5

Partners' Capital and Distributions - Equity Offerings (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Partners Capital and Distribution [Line Items]
Issuance of units, net proceeds			$ 1,664
Continuous Offering Program
Partners Capital and Distribution [Line Items]
Commissions to sales agents			$ 1
Common Units
Partners Capital and Distribution [Line Items]
Issuance of units (in units)			54,119,893
Issuance of units, net proceeds			$ 1,664
Common Units | Continuous Offering Program
Partners Capital and Distribution [Line Items]
Issuance of units (in units)			4,033,567
Issuance of units, net proceeds			$ 129
Common Units | Omnibus Agreement
Partners Capital and Distribution [Line Items]
Issuance of units (in units)			50,086,326
Issuance of units, net proceeds			$ 1,535
AAP | Omnibus Agreement | Common Units
Partners Capital and Distribution [Line Items]
Issuance of common units (in units)	232,425	559,649
AAP | Omnibus Agreement | Common Units | Continuous Offering Program
Partners Capital and Distribution [Line Items]
Issuance of units (in units)			1,800,000
AAP | Omnibus Agreement | Common Units | Underwritten Offering
Partners Capital and Distribution [Line Items]
Issuance of units (in units)			48,300,000

Partners' Capital and Distrib_6

Partners' Capital and Distributions - Preferred Unit Distributions (Details) - USD ($) $ / shares in Units, $ in Millions	Feb. 14, 2020	Nov. 15, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Partners Capital and Distribution [Line Items]
Number of days after end of quarter within which distributions must be paid to unitholders			45 days
Series B Preferred Units
Partners Capital and Distribution [Line Items]
Dividends paid (in dollars per unit)		$ 5.9549
Cash Distribution | Series A Preferred Units
Partners Capital and Distribution [Line Items]
Preferred unit dividends			$ 149	$ 112
Cash Distribution | Series B Preferred Units
Partners Capital and Distribution [Line Items]
Preferred unit dividends			49	$ 49	$ 5
Unit Distribution | Series A Preferred Units
Partners Capital and Distribution [Line Items]
Unit distributions (in units)				1,393,926	5,307,689
Distributions paid to unitholders				$ 37	$ 139
Other current liabilities | Series B Preferred Units
Partners Capital and Distribution [Line Items]
Dividends payable			$ 6
Other current liabilities | Subsequent Event | Cash Distribution | Series A Preferred Units
Partners Capital and Distribution [Line Items]
Preferred unit dividends	$ 37

Partners' Capital and Distrib_7

Partners' Capital and Distributions - Common Unit Distributions (Details) - Common Units - USD ($) $ / shares in Units, $ in Millions	Feb. 14, 2020	Jan. 08, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Distribution Made to Limited Partner [Line Items]
Distributions per common unit (in dollars per unit)			$ 0.36	$ 0.36	$ 0.36	$ 0.30	$ 0.30	$ 0.30	$ 0.30	$ 0.30	$ 1.38	$ 1.20
Cash Distribution
Distribution Made to Limited Partner [Line Items]
Distributions paid to limited partners											$ 1,004	$ 871	$ 1,386
Distributions per common unit (in dollars per unit)											$ 1.38	$ 1.20	$ 1.95
Public | Cash Distribution
Distribution Made to Limited Partner [Line Items]
Distributions paid to limited partners											$ 632	$ 532	$ 849
AAP | Cash Distribution
Distribution Made to Limited Partner [Line Items]
Distributions paid to limited partners											$ 372	$ 339	$ 537
Fourth quarter distribution | Subsequent Event | Cash Distribution
Distribution Made to Limited Partner [Line Items]
Distributions paid to limited partners	$ 262
Distribution per common unit declared (in dollars per unit)		$ 0.36
Fourth quarter distribution | Subsequent Event | AAP | Cash Distribution
Distribution Made to Limited Partner [Line Items]
Distributions paid to limited partners	$ 90

Partners' Capital and Distrib_8

Partners' Capital and Distributions - Income Allocation (Details)	Dec. 31, 2019
Partners' Capital Notes [Abstract]
Net income allocation	100.00%

Partners' Capital and Distrib_9

Partners' Capital and Distributions - Noncontrolling Interests in Subsidiaries (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended	12 Months Ended
	May 31, 2019	Dec. 31, 2017	Dec. 31, 2019
Partners Capital and Distribution [Line Items]
Proceeds from noncontrolling interests			$ 128
Red River Pipeline Company LLC | Delek Logistics Partners, LP
Partners Capital and Distribution [Line Items]
Proceeds from noncontrolling interests	$ 128
Noncontrolling interest, ownership percentage by noncontrolling owners	33.00%
SLC Pipeline LLC
Partners Capital and Distribution [Line Items]
Ownership percentage sold		75.00%
Noncontrolling interests in subsidiaries derecognized upon sale		25.00%
Delek Logistics Partners, LP | Red River Pipeline Company LLC
Partners Capital and Distribution [Line Items]
Noncontrolling interest, ownership percentage by noncontrolling owners			33.00%

Derivatives and Risk Manageme_3

Derivatives and Risk Management Activities - Commodity Price Risk Hedging (Details) bbl in Millions	12 Months Ended
	Dec. 31, 2019TWhbblMMBblsBcf
Net long position associated with crude oil purchases
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Bcf)	10.2
Net short time spread position hedging anticipated crude oil lease gathering purchases
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Bcf)	9
Net crude oil grade basis position
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Bcf)	5.9
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 Bcf)	17.9
Positions hedging risk of not utilizing storage capacity
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Bcf)	1.2
Long natural gas position for natural gas purchases
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Bcf) | Bcf	46.4
Short propane position related to subsequent sale of products
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Bcf) | MMBbls	3.8
Short butane position related to subsequent sale of products
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Bcf) | MMBbls	1.9
Short condensate WTI position related to subsequent sale of products
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Bcf) | MMBbls	0.7
Long power position for power supply requirements
Commodity Price Risk Hedging:
Derivative position notional amount (in terawatt hours) | TWh	1

Derivatives and Risk Manageme_4

Derivatives and Risk Management Activities - Rate Risk Hedging (Details) - 12 months ended Dec. 31, 2019 $ in Millions, $ in Millions	USD ($)contract$ / $	CAD ($)contract$ / $
3.06%, 8 forward starting swaps (30-year) | Cash Flow Hedging
Currency Exchange Rate Risk Hedging:
Number of interest rate derivatives | contract	8	8
Term of derivative contract	30 years
Notional amount | $	$ 200
Average rate locked (percent)	3.06%	3.06%
Forward exchange contracts that exchange CAD for USD maturing in 2020
Currency Exchange Rate Risk Hedging:
Notional amount	$ 202	$ 266
Forward exchange contracts that exchange CAD for USD maturing in 2020 | Minimum
Currency Exchange Rate Risk Hedging:
Average exchange rate (cad per usd)	1	1
Forward exchange contracts that exchange CAD for USD maturing in 2020 | Maximum
Currency Exchange Rate Risk Hedging:
Average exchange rate (cad per usd)	1.31	1.31
Forward exchange contracts that exchange USD for CAD maturing in 2020
Currency Exchange Rate Risk Hedging:
Notional amount	$ 207	$ 274
Forward exchange contracts that exchange USD for CAD maturing in 2020 | Minimum
Currency Exchange Rate Risk Hedging:
Average exchange rate (cad per usd)	1	1
Forward exchange contracts that exchange USD for CAD maturing in 2020 | Maximum
Currency Exchange Rate Risk Hedging:
Average exchange rate (cad per usd)	1.32	1.32

Derivatives and Risk Manageme_5

Derivatives and Risk Management Activities - Financial Impact (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income	$ 325	$ 106	$ (198)
Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income	318	127	(180)
Field operating costs
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income	14	(2)	(10)
Depreciation and amortization
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income			(3)
Interest expense, net
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income	(9)	(5)	(18)
Other income/(expense), net
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income	2	(14)	13
Commodity Derivatives
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income	324	148	(201)
Foreign Currency Derivatives
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income	8	(23)	8
Preferred Distribution Rate Reset Option
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income	2	(14)	13
Interest Rate Derivatives
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income	(9)	(5)	(18)
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	310	150	(188)
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	14	(2)	(10)
Derivatives not designated as a Hedge | Commodity Derivatives | Depreciation and amortization
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income			(3)
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	8	(23)	8
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	2	(14)	13
Derivatives in Hedging Relationships | Interest Rate Derivatives | Interest expense, net
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income	$ (9)	$ (5)	$ (18)

Derivatives and Risk Manageme_6

Derivatives and Risk Management Activities - Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Derivative assets and liabilities
Asset derivatives fair value	$ 239	$ 480
Liability derivatives fair value	(186)	(262)
Initial margin	73	95
Variation margin posted/(returned)	(45)	(91)
Letters of credit	(157)	(184)
Net broker payable	(45)	(80)
Other current assets
Derivative assets and liabilities
Asset derivatives fair value	183	443
Liability derivatives fair value	(39)	(182)
Other long-term assets, net
Derivative assets and liabilities
Asset derivatives fair value	24	34
Liability derivatives fair value		(7)
Other current liabilities
Derivative assets and liabilities
Asset derivatives fair value	32
Liability derivatives fair value	(101)	(20)
Other long-term liabilities and deferred credits
Derivative assets and liabilities
Asset derivatives fair value		3
Liability derivatives fair value	(46)	(53)
Derivatives not designated as a Hedge
Derivative assets and liabilities
Asset derivatives fair value	239	478
Liability derivatives fair value	(142)	(253)
Derivatives not designated as a Hedge | Other current assets
Derivative assets and liabilities
Asset derivatives fair value	183	441
Liability derivatives fair value	(39)	(182)
Derivatives not designated as a Hedge | Other long-term assets, net
Derivative assets and liabilities
Asset derivatives fair value	24	34
Liability derivatives fair value		(7)
Derivatives not designated as a Hedge | Other current liabilities
Derivative assets and liabilities
Asset derivatives fair value	32
Liability derivatives fair value	(57)	(19)
Derivatives not designated as a Hedge | Other long-term liabilities and deferred credits
Derivative assets and liabilities
Asset derivatives fair value		3
Liability derivatives fair value	(46)	(45)
Derivatives not designated as a Hedge | Commodity Derivatives
Derivative assets and liabilities
Asset derivatives fair value	235	478
Liability derivatives fair value	(105)	(208)
Derivatives not designated as a Hedge | Commodity Derivatives | Other current assets
Derivative assets and liabilities
Asset derivatives fair value	179	441
Liability derivatives fair value	(37)	(182)
Derivatives not designated as a Hedge | Commodity Derivatives | Other long-term assets, net
Derivative assets and liabilities
Asset derivatives fair value	24	34
Liability derivatives fair value		(7)
Derivatives not designated as a Hedge | Commodity Derivatives | Other current liabilities
Derivative assets and liabilities
Asset derivatives fair value	32
Liability derivatives fair value	(56)	(10)
Derivatives not designated as a Hedge | Commodity Derivatives | Other long-term liabilities and deferred credits
Derivative assets and liabilities
Asset derivatives fair value		3
Liability derivatives fair value	(12)	(9)
Derivatives not designated as a Hedge | Foreign Currency Derivatives
Derivative assets and liabilities
Asset derivatives fair value	4
Liability derivatives fair value	(3)	(9)
Derivatives not designated as a Hedge | Foreign Currency Derivatives | Other current assets
Derivative assets and liabilities
Asset derivatives fair value	4
Liability derivatives fair value	(2)
Derivatives not designated as a Hedge | Foreign Currency Derivatives | Other current liabilities
Derivative assets and liabilities
Liability derivatives fair value	(1)	(9)
Derivatives not designated as a Hedge | Preferred Distribution Rate Reset Option
Derivative assets and liabilities
Liability derivatives fair value	(34)	(36)
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	(34)	(36)
Derivatives in Hedging Relationships | Interest Rate Derivatives
Derivative assets and liabilities
Asset derivatives fair value		2
Liability derivatives fair value	(44)	(9)
Derivatives in Hedging Relationships | Interest Rate Derivatives | Other current assets
Derivative assets and liabilities
Asset derivatives fair value		2
Derivatives in Hedging Relationships | Interest Rate Derivatives | Other current liabilities
Derivative assets and liabilities
Liability derivatives fair value	(44)	(1)
Derivatives in Hedging Relationships | Interest Rate Derivatives | Other long-term liabilities and deferred credits
Derivative assets and liabilities
Liability derivatives fair value		(8)
Exchange Traded
Derivative assets and liabilities
Letters of credit	$ (73)	$ (84)

Derivatives and Risk Manageme_7

Derivatives and Risk Management Activities - Offsetting (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Derivative Asset Positions
Gross Position - Asset	$ 239	$ 480
Netting Adjustment	(71)	(192)
Cash collateral paid/(received)	(45)	(80)
Net Position - Asset	123	208
Derivative Liability Positions
Gross Position - Liability	(186)	(262)
Netting Adjustment	71	192
Net Position - Liability	(115)	(70)
Other current assets
Derivative Asset Positions
Gross Position - Asset	183	443
Net Position - Asset	99	181
Derivative Liability Positions
Gross Position - Liability	(39)	(182)
Other long-term assets, net
Derivative Asset Positions
Gross Position - Asset	24	34
Net Position - Asset	24	27
Derivative Liability Positions
Gross Position - Liability		(7)
Other current liabilities
Derivative Asset Positions
Gross Position - Asset	32
Derivative Liability Positions
Gross Position - Liability	(101)	(20)
Net Position - Liability	(69)	(20)
Other long-term liabilities and deferred credits
Derivative Asset Positions
Gross Position - Asset		3
Derivative Liability Positions
Gross Position - Liability	(46)	(53)
Net Position - Liability	$ (46)	$ (50)

Derivatives and Risk Manageme_8

Derivatives and Risk Management Activities - Net Unrealized Gain/(Loss) Recognized in AOCI (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Net loss in reclassification to earnings	$ 10
Accumulated Gain (Loss), Net, Cash Flow Hedge, Parent
Derivatives, Fair Value [Line Items]
Net loss in AOCI	259
Interest Rate Derivatives
Derivatives, Fair Value [Line Items]
Net unrealized gain/(loss) recognized in AOCI	$ (91)	$ 38	$ (16)

Derivatives and Risk Manageme_9

Derivatives and Risk Management Activities - Fair Value (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Level 3
Rollforward of Level 3 Net Asset/(Liability)
Beginning Balance	$ (24)	$ (30)
Net gains/(losses) for the period included in earnings	10	(13)
Settlements	(11)	7
Derivatives entered into during the period	(26)	12
Ending Balance	(51)	(24)
Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period	(16)	(1)
Recurring Fair Value Measures
Recurring Fair Value Measurements
Net derivative asset/(liability)	53	218
Recurring Fair Value Measures | Commodity Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)	130	270
Recurring Fair Value Measures | Interest Rate Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)	(44)	(7)
Recurring Fair Value Measures | Foreign Currency Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)	1	(9)
Recurring Fair Value Measures | Preferred Distribution Rate Reset Option
Recurring Fair Value Measurements
Net derivative asset/(liability)	(34)	(36)
Recurring Fair Value Measures | Level 1
Recurring Fair Value Measurements
Net derivative asset/(liability)	42	171
Recurring Fair Value Measures | Level 1 | Commodity Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)	42	171
Recurring Fair Value Measures | Level 2
Recurring Fair Value Measurements
Net derivative asset/(liability)	62	71
Recurring Fair Value Measures | Level 2 | Commodity Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)	105	87
Recurring Fair Value Measures | Level 2 | Interest Rate Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)	(44)	(7)
Recurring Fair Value Measures | Level 2 | Foreign Currency Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)	1	(9)
Recurring Fair Value Measures | Level 3
Recurring Fair Value Measurements
Net derivative asset/(liability)	(51)	(24)
Recurring Fair Value Measures | Level 3 | Commodity Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)	(17)	12
Recurring Fair Value Measures | Level 3 | Preferred Distribution Rate Reset Option
Recurring Fair Value Measurements
Net derivative asset/(liability)	$ (34)	$ (36)

Leases - Narrative Information

Leases - Narrative Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Lessee, Lease, Description [Line Items]
Lease expense		$ 199	$ 207
Equity Method Investees
Lessee, Lease, Description [Line Items]
Lease not yet commenced, term of contract	16 years
Lease not yet commenced, future minimum lease payments	$ 66
Minimum
Lessee, Lease, Description [Line Items]
Lessee, leases, term of contract	1 year
Lessee, leases, renewal term	1 year
Lessor, Lease, Description [Line Items]
Lessor, operating lease, term of contract	2 years
Maximum
Lessee, Lease, Description [Line Items]
Lessee, leases, term of contract	60 years
Lessee, leases, renewal term	40 years
Lessor, Lease, Description [Line Items]
Lessor, operating lease, term of contract	22 years

Leases - Lease Costs (Details)

Leases - Lease Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Lessee, Lease, Description [Line Items]
Operating lease cost	$ 125
Short-term lease cost	35
Total lease cost	160
Lease expense		$ 199	$ 207
Maximum
Lessee, Lease, Description [Line Items]
Other	$ 1

Leases - Other Information (Det

Leases - Other Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Lessee, Lease, Description [Line Items]
Operating cash flows for operating leases	$ 116
Financing cash flows for finance leases	18
Non-cash change in lease liabilities arising from obtaining new right of use assets or modifications, operating leases	77
Non-cash change in lease liabilities arising from obtaining new right of use assets or modifications, finance leases	$ 27
Weighted-average remaining lease term (in years):
Operating lease, weighted-average lease term	11 years
Finance lease, weighted-average lease term	6 years
Weighted-average discount rate:
Operating lease, weighted-average discount rate	4.40%
Finance lease, weighted-average discount rate	7.10%
Equity Method Investees
Lessee, Lease, Description [Line Items]
Non-cash change in lease liabilities arising from obtaining new right of use assets or modifications, finance leases	$ 12

Leases - Assets and Liabilities

Leases - Assets and Liabilities (Details) $ in Millions	Dec. 31, 2019USD ($)
Lessee, Lease, Assets and Liabilities [Line Items]
Long-term operating lease right-of-use assets, net	$ 466
Total lease right-of-use assets	574
Operating lease liabilities
Long-term operating lease liabilities	387
Total operating lease liabilities	481
Finance lease liabilities
Total finance lease liabilities	67
Total lease liabilities	548
Equity Method Investees
Lessee, Lease, Assets and Liabilities [Line Items]
Finance lease right-of-use assets, net	12
Finance lease liabilities
Total finance lease liabilities	12
Property and equipment
Lessee, Lease, Assets and Liabilities [Line Items]
Finance lease right-of-use assets, gross	124
Accumulated depreciation
Lessee, Lease, Assets and Liabilities [Line Items]
Finance lease right-of-use assets, accumulated depreciation	(16)
Property and equipment, net
Lessee, Lease, Assets and Liabilities [Line Items]
Finance lease right-of-use assets, net	108
Other current liabilities
Operating lease liabilities
Operating lease liabilities, current	94
Short-term debt
Finance lease liabilities
Finance lease liabilities, current	18
Other long-term debt
Finance lease liabilities
Finance lease liabilities, noncurrent	$ 49

Leases - Maturity of Lease Liab

Leases - Maturity of Lease Liabilities (Details) $ in Millions	Dec. 31, 2019USD ($)
Operating
2020	$ 109
2021	87
2022	79
2023	60
2024	48
Thereafter	279
Total	662
Less: Present value discount	(181)
Lease liabilities	481
Finance
2020	21
2021	12
2022	12
2023	9
2024	9
Thereafter	29
Total	92
Less: Present value discount	(25)
Lease liabilities	67
Equity Method Investees
Finance
2020	2
2021	2
2022	2
2023	2
2024	2
Thereafter	23
Lease liabilities	$ 12

Leases - Lessor Revenue (Detail

Leases - Lessor Revenue (Details) $ in Millions	Dec. 31, 2019USD ($)
Leases [Abstract]
2020	$ 19
2021	22
2022	25
2023	21
2024	17
Thereafter	$ 208

Income Taxes - Components (Deta

Income Taxes - Components (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current income tax expense:
State income tax	$ 3	$ 3	$ 1
Canadian federal and provincial income tax	109	63	27
Total current income tax expense	112	66	28
Deferred income tax expense/(benefit):
Canadian federal and provincial income tax	(46)	132	16
Total deferred income tax expense/(benefit)	(46)	132	16
Total income tax expense	$ 66	$ 198	$ 44

Income Taxes - Reconciliation a

Income Taxes - Reconciliation and Deferred Tax Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Examination [Line Items]
Income before tax	$ 2,246	$ 2,414	$ 902
Partnership earnings not subject to current Canadian tax	(1,769)	(1,690)	(756)
Partnership earnings subject to current Canadian tax	$ 477	$ 724	$ 146
Canadian federal and provincial corporate tax rate	26.00%	27.00%	27.00%
Income tax at statutory rate	$ 124	$ 195	$ 39
Canadian withholding tax			2
Canadian permanent differences and rate changes	(61)		2
State income tax	3	3	1
Total income tax expense	66	198	$ 44
Deferred tax assets:
Lease liabilities	55	0
Net operating losses	2	2
Other	16	21
Total deferred tax assets	73	23
Deferred tax liabilities:
Property and equipment in excess of tax values	(472)	(449)
Derivative instruments	(22)	(31)
Lease assets	(53)
Other	(5)	(42)
Total deferred tax liabilities	(552)	(522)
Net deferred tax liabilities	(479)	(499)
Other long-term assets, net
Deferred tax liabilities:
Net deferred tax assets	2	2
Other long-term liabilities and deferred credits
Deferred tax liabilities:
Net deferred tax liabilities	$ (481)	$ (501)

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended			30 Months Ended
	Jun. 30, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jan. 01, 2022
Income Tax Examination [Line Items]
Canadian federal and provincial corporate tax rate		26.00%	27.00%	27.00%
Foreign
Income Tax Examination [Line Items]
Net operating loss carryforwards		$ 9
Canadian Tax Authorities | Foreign
Income Tax Examination [Line Items]
Amount of assessments received, including penalty and interest		78
Canadian Tax Authorities | Other long-term assets, net | Foreign
Income Tax Examination [Line Items]
Amount of disputed assessments paid		$ 48
Alberta Government, Canada
Income Tax Examination [Line Items]
Canadian federal and provincial corporate tax rate	12.00%
Deferred tax benefit from change in tax rate	$ 60
Alberta Government, Canada | Forecast
Income Tax Examination [Line Items]
Canadian federal and provincial corporate tax rate					8.00%

Major Customers and Concentra_2

Major Customers and Concentration of Credit Risk (Details) - Revenues - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Marathon Petroleum Corporation
Major Customers and Concentration of Credit Risk
Major customer percentage of total revenue	12.00%	14.00%	19.00%
ExxonMobil Corporation
Major Customers and Concentration of Credit Risk
Major customer percentage of total revenue	12.00%	14.00%	11.00%
Phillips 66
Major Customers and Concentration of Credit Risk
Major customer percentage of total revenue	11.00%		11.00%

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Related Party Transactions
Revenues from related parties		$ 692	$ 1,067	$ 927
Purchases and related costs from related parties		223	410	286
Trade accounts receivable and other receivables, net from related parties		134	144
Trade accounts payable to related parties		102	121
GP
Related Party Transactions
Costs reimbursed to general partner		$ 580	494	$ 489
Equity Method Investees | Agreement to Transport Crude Oil
Related Party Transactions
Ownership interest		50.00%
Common Units
Related Party Transactions
Issuance of units (in units)				54,119,893
Omnibus Agreement
Related Party Transactions
Expenses paid on behalf of affiliates		$ 4	$ 4	$ 4
Continuous Offering Program | Common Units
Related Party Transactions
Issuance of units (in units)				4,033,567
Continuous Offering Program | Omnibus Agreement | Common Units | AAP
Related Party Transactions
Issuance of units (in units)				1,800,000
Underwritten Offering | Omnibus Agreement | Common Units | AAP
Related Party Transactions
Issuance of units (in units)	48,300,000
PAGP | Class C Shares
Related Party Transactions
Class C Shares of PAGP Owned		549,538,139	516,938,280
AAP | Principal Owner
Related Party Transactions
Limited partner interest		10.00%

Equity-Indexed Compensation P_3

Equity-Indexed Compensation Plans - Plan Information (Details) - shares shares in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Equity-Indexed Compensation Plans
LTIP awards authorized (in units)	25.2
LTIP awards available (in units)	5.9
LTIP awards outstanding (in units)	7.1	6.8	7.3	8.9
LTIP awards outstanding including DERs (in units)	5.4
Plains All American 2013 Long-Term Incentive Plan
Equity-Indexed Compensation Plans
LTIP awards authorized (in units)	13.1
Plains All American PNG Successor Long-Term Incentive Plan
Equity-Indexed Compensation Plans
LTIP awards authorized (in units)	1.3
Plains All American GP LLC 2006 Long-Term Incentive Tracking Unit Plan
Equity-Indexed Compensation Plans
LTIP awards authorized (in units)	10.8

Equity-Indexed Compensation P_4

Equity-Indexed Compensation Plans - Liability and Activity (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Outstanding (in units)
Outstanding at beginning of period (in units)	6.8	7.3	8.9
Granted (in units)	3.9	1.7	0.9
Vested (in units)	(3.3)	(1.7)	(1.7)
Cancelled or forfeited (in units)	(0.3)	(0.5)	(0.8)
Outstanding at end of period (in units)	7.1	6.8	7.3
Weighted Average Grant Date Fair Value per Unit
Outstanding at beginning of period (in dollars per unit)	$ 22.19	$ 24.68	$ 29.62
Granted (in dollars per unit)	16.17	23.44	23.52
Vested (in dollars per unit)	22.44	32.42	42.12
Modified (in dollars per unit)		2.15	(6.04)
Cancelled or forfeited (in dollars per unit)	23.12	21.99	26.99
Outstanding at end of period (in dollars per unit)	$ 18.67	$ 22.19	$ 24.68
Units issued in connection with the settlement of vested awards, net of tax withholding (in units)	1.4	0.6	0.6
Units withheld for taxes (in units)	0.6	0.2	0.2
Vested awards settled in cash (in units)	1.3	0.9	0.9
Liability Awards
Equity-Indexed Compensation Plans
Accrued liability related to all outstanding LTIP awards and DERs	$ 13	$ 27
Other current liabilities | Liability Awards
Equity-Indexed Compensation Plans
Short-term accrued liability related to all outstanding LTIP awards and DERs	10	19
Other long-term liabilities and deferred credits | Liability Awards
Equity-Indexed Compensation Plans
Long-term accrued liability related to all outstanding LTIP awards and DERs	$ 3	$ 8

Equity-Indexed Compensation P_5

Equity-Indexed Compensation Plans - Compensation Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Other Consolidated Equity-Indexed Compensation Plan Information
Equity-indexed compensation expense	$ 34	$ 79	$ 41
LTIP unit-settled vestings	47	21	16
LTIP cash-settled vestings	31	$ 22	$ 25
Equity-Indexed Compensation Plan Fair Value Amortization
2020	22
2021	13
2022	7
2023	4
2024	2
Thereafter	4
Total	$ 52

Commitments and Contingencies -

Commitments and Contingencies - Commitments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Leases
2020	$ 130
2021	99
2022	91
2023	69
2024	57
Thereafter	308
Total	754
Other commitments
2020	272
2021	296
2022	292
2023	276
2024	271
Thereafter	968
Total	2,375
Total
2020	402
2021	395
2022	383
2023	345
2024	328
Thereafter	1,276
Total	3,129
Expenses associated with agreements	236	$ 228	$ 197
Agreements to Store, Process and Transport Crude Oil on Pipeline or at Facilities of Equity Method Investees | Equity Method Investees
Other commitments
Total	$ 1,800
Total
Ownership interest	50.00%

Commitments and Contingencies_2

Commitments and Contingencies - Legal, Environmental or Regulatory (Details)	Oct. 07, 2019count	Jul. 31, 2019USD ($)	May 31, 2015bbl	May 31, 2018count	Dec. 31, 2019USD ($)lawsuit	Apr. 25, 2019USD ($)	Dec. 31, 2018USD ($)	Sep. 07, 2018count	May 16, 2016count
Legal, Environmental or Regulatory Matters
Estimated undiscounted reserve for environmental liabilities					$ 140,000,000		$ 135,000,000
Amounts probable of recovery under insurance and from third parties under indemnification agreements					72,000,000		61,000,000
Other current liabilities
Legal, Environmental or Regulatory Matters
Estimated undiscounted reserve for environmental liabilities, short-term					60,000,000		43,000,000
Other long-term liabilities and deferred credits
Legal, Environmental or Regulatory Matters
Estimated undiscounted reserve for environmental liabilities, long-term					80,000,000		92,000,000
Trade accounts receivable and other receivables, net
Legal, Environmental or Regulatory Matters
Amounts probable of recovery under insurance and from third parties under indemnification agreements					35,000,000		28,000,000
Other long-term assets, net
Legal, Environmental or Regulatory Matters
Amounts probable of recovery under insurance and from third parties under indemnification agreements					37,000,000		$ 33,000,000
Line 901 Incident
Legal, Environmental or Regulatory Matters
Estimated undiscounted reserve for environmental liabilities					83,000,000
Amounts probable of recovery under insurance and from third parties under indemnification agreements					62,000,000
Estimated size of release (in bbl) | bbl			2,934
Estimated size of release to reach Pacific Ocean (in bbl) | bbl			598
Aggregate total estimated costs					390,000,000
Recoveries from insurance carriers					203,000,000
Total release costs probable of recovery					265,000,000
Line 901 Incident | Other current liabilities
Legal, Environmental or Regulatory Matters
Estimated undiscounted reserve for environmental liabilities, short-term					50,000,000
Line 901 Incident | Trade accounts receivable and other receivables, net
Legal, Environmental or Regulatory Matters
Amounts probable of recovery under insurance and from third parties under indemnification agreements					$ 28,000,000
Line 901 Incident | May 2016 Indictment
Legal, Environmental or Regulatory Matters
Total counts included in the indictment | count									46
Number of counts dismissed | count				31
Number of felony charges dismissed | count				1
Number of felony charges found guilty | count								1
Number of misdemeanor charges found guilty | count								8
Number of misdemeanor charges found guilty, reporting | count								1
Number of misdemeanor charges found guilty, strict liability discharge | count								1
Number of misdemeanor charges found guilty, strict liability animal takings | count								6
Number of misdemeanor charges not guilty, strict liability animal takings | count								1
Number of charges jury deadlocked | count								3
Number of charges jury deadlocked, felony discharges | count								2
Number of charges jury deadlocked, strict liability animal takings | count								1
Number of misdemeanor charges dropped | count								2
Fines or penalties assessed						$ 3,350,000
Indictment number of felony charges jury deadlocked later dismissed | count	2
Line 901 Incident | Class Action Lawsuits
Legal, Environmental or Regulatory Matters
Number of cases filed during the period | lawsuit					9
Number of cases consolidated into a single proceeding | lawsuit					6
Line 901 Incident | Unitholder Derivative Lawsuits
Legal, Environmental or Regulatory Matters
Number of cases filed during the period | lawsuit					4
San Joaquin Valley Air Pollution Control District
Legal, Environmental or Regulatory Matters
Fines or penalties assessed		$ 597,000
Reduced fine paid		$ 275,000
UNITED STATES | Line 901 Incident | Unitholder Derivative Lawsuits
Legal, Environmental or Regulatory Matters
Number of lawsuits dismissed | lawsuit					2
Texas | Line 901 Incident | Unitholder Derivative Lawsuits
Legal, Environmental or Regulatory Matters
Number of lawsuits dismissed | lawsuit					1

Quarterly Financial Data (Una_3

Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Total revenues	$ 9,154	$ 7,886	$ 8,253	$ 8,375	$ 8,786	$ 8,792	$ 8,080	$ 8,398	$ 33,669	$ 34,055	$ 26,223
Gross margin	403	566	526	790	1,399	567	168	460	2,285	2,593
Operating income	331	492	451	714	1,315	493	88	381	1,988	2,277	1,153
Net income	307	454	448	970	1,117	710	100	288	2,180	2,216	858
Net income attributable to PAA	$ 306	$ 449	$ 446	$ 970	$ 1,117	$ 710	$ 100	$ 288	$ 2,171	$ 2,216	$ 856
Common Units
Basic net income/(loss) per common unit (in dollars per unit)	$ 0.35	$ 0.55	$ 0.54	$ 1.26	$ 1.46	$ 0.91	$ 0.07	$ 0.33	$ 2.70	$ 2.77	$ 0.96
Diluted net income/(loss) per common unit (in dollars per unit)	0.35	0.55	0.54	1.20	1.38	0.87	0.07	0.33	2.65	2.71	$ 0.95
Cash distributions per common unit (in dollars per unit)	$ 0.36	$ 0.36	$ 0.36	$ 0.30	$ 0.30	$ 0.30	$ 0.30	$ 0.30	$ 1.38	$ 1.20

Operating Segments - Segment Fi

Operating Segments - Segment Financial Data (Details) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019USD ($)	Sep. 30, 2019USD ($)	Jun. 30, 2019USD ($)	Mar. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Sep. 30, 2018USD ($)	Jun. 30, 2018USD ($)	Mar. 31, 2018USD ($)	Dec. 31, 2019USD ($)segment	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Operating Segments
Operating segments number | segment									3
Revenues:
Revenues	$ 9,154	$ 7,886	$ 8,253	$ 8,375	$ 8,786	$ 8,792	$ 8,080	$ 8,398	$ 33,669	$ 34,055	$ 26,223
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Equity earnings in unconsolidated entities									388	375	290
Segment Adjusted EBITDA									3,230	2,681	2,081
Capital expenditures									1,387	1,888	2,458
Maintenance capital									287	252	247
Total assets	28,677				25,511				28,677	25,511	25,351
Investments in unconsolidated entities	3,683				2,702				3,683	2,702	2,756
Transportation
Revenues:
Revenues									788	648	612
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Equity earnings in unconsolidated entities									388	375	290
Segment Adjusted EBITDA									1,722	1,508	1,287
Capital expenditures									1,127	1,631	2,126
Maintenance capital									161	139	120
Total assets	14,902				13,288				14,902	13,288	12,661
Investments in unconsolidated entities	3,557				2,594				3,557	2,594	2,681
Facilities
Revenues:
Revenues									609	588	555
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Segment Adjusted EBITDA									705	711	734
Capital expenditures									227	234	312
Maintenance capital									97	100	114
Total assets	7,336				7,200				7,336	7,200	7,313
Investments in unconsolidated entities	126				108				126	108	75
Supply And Logistics
Revenues:
Revenues									32,272	32,819	25,056
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Segment Adjusted EBITDA									803	462	60
Capital expenditures									33	23	20
Maintenance capital									29	13	13
Total assets	$ 6,439				$ 5,023				6,439	5,023	5,377
Operating Segments Excluding Intersegment Elimination | Transportation
Revenues:
Revenues									1,259	1,116	1,021
Operating Segments Excluding Intersegment Elimination | Facilities
Revenues:
Revenues									609	588	555
Operating Segments Excluding Intersegment Elimination | Supply And Logistics
Revenues:
Revenues									32,272	32,819	25,056
Intersegment
Revenues:
Revenues									(2,098)	(1,918)	(1,733)
Intersegment | Transportation
Revenues:
Revenues									(1,061)	(874)	(697)
Intersegment | Facilities
Revenues:
Revenues									(562)	(573)	(618)
Intersegment | Supply And Logistics
Revenues:
Revenues									(4)	(3)	(9)
Intersegment Adjustment
Revenues:
Revenues									(471)	(468)	(409)
Operating Segments
Revenues:
Revenues									35,767	35,973	27,956
Operating Segments | Transportation
Revenues:
Revenues									2,320	1,990	1,718
Operating Segments | Facilities
Revenues:
Revenues									1,171	1,161	1,173
Operating Segments | Supply And Logistics
Revenues:
Revenues									$ 32,276	$ 32,822	$ 25,065

Operating Segments - Reconcilia

Operating Segments - Reconciliation of Segment Adjusted EBITDA (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Segment Adjusted EBITDA									$ 3,230	$ 2,681	$ 2,081
Adjustments:
Depreciation and amortization of unconsolidated entities									(62)	(56)	(45)
Gains/(losses) from derivative activities net of inventory valuation adjustments									(160)	519	46
Long-term inventory costing adjustments									20	(21)	24
Deficiencies under minimum volume commitments, net									18	(7)	(2)
Equity-indexed compensation expense									(17)	(55)	(23)
Net gain/(loss) on foreign currency revaluation									(14)	(3)	26
Significant acquisition-related expenses											(6)
Depreciation and amortization									(601)	(520)	(517)
Gains/(losses) on asset sales and asset impairments, net									(28)	114	(109)
Gain on investment in unconsolidated entities									271	200
Interest expense, net									(425)	(431)	(510)
Other income/(expense), net									24	(7)	(31)
INCOME BEFORE TAX									2,246	2,414	902
Income tax expense									(66)	(198)	(44)
NET INCOME	$ 307	$ 454	$ 448	$ 970	$ 1,117	$ 710	$ 100	$ 288	2,180	2,216	858
Net income attributable to noncontrolling interests									(9)		(2)
NET INCOME ATTRIBUTABLE TO PAA	$ 306	$ 449	$ 446	$ 970	$ 1,117	$ 710	$ 100	$ 288	2,171	$ 2,216	856
Line 901 Incident
Adjustments:
Line 901 incident									$ (10)		$ (32)

Operating Segments - Geographic

Operating Segments - Geographic Data (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Geographic Data
Revenues	$ 9,154	$ 7,886	$ 8,253	$ 8,375	$ 8,786	$ 8,792	$ 8,080	$ 8,398	$ 33,669	$ 34,055	$ 26,223
Long-lived assets	21,500				19,427				21,500	19,427
UNITED STATES
Geographic Data
Revenues									27,162	28,362	21,443
Long-lived assets	17,565				15,885				17,565	15,885
CANADA
Geographic Data
Revenues									6,507	5,693	$ 4,780
Long-lived assets	$ 3,935				$ 3,542				$ 3,935	$ 3,542