Cover
Cover - USD ($) $ in Billions | 12 Months Ended | ||
Dec. 31, 2021 | Feb. 22, 2022 | Jun. 30, 2021 | |
Cover [Abstract] | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2021 | ||
Current Fiscal Year End Date | --12-31 | ||
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 | NASDAQ | ||
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 Small Business | false | ||
Entity Emerging Growth Company | false | ||
ICFR Auditor Attestation Flag | true | ||
Entity Shell Company | false | ||
Entity Public Float | $ 5.3 | ||
Entity Common Stock Outstanding (in shares) | 705,043,477 | ||
Documents Incorporated by Reference | Portions of the registrant’s definitive Proxy Statement to be filed pursuant to Regulation 14A pertaining to the 2022 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 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2021 | ||
Document Fiscal Period Focus | FY |
Audit Information
Audit Information | 12 Months Ended |
Dec. 31, 2021 | |
Audit Information [Abstract] | |
Auditor Name | PricewaterhouseCoopers LLP |
Auditor Firm ID | 238 |
Auditor Location | Houston, Texas |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
CURRENT ASSETS | ||
Cash and cash equivalents | $ 449 | $ 22 |
Restricted cash | 4 | 38 |
Trade accounts receivable and other receivables, net | 4,705 | 2,553 |
Inventory | 783 | 647 |
Other current assets | 196 | 405 |
Total current assets | 6,137 | 3,665 |
PROPERTY AND EQUIPMENT | 19,257 | 18,585 |
Accumulated depreciation | (4,354) | (3,974) |
Property and equipment, net | 14,903 | 14,611 |
OTHER ASSETS | ||
Investments in unconsolidated entities | 3,805 | 3,764 |
Intangible assets, net | 1,960 | 805 |
Linefill and base gas | 907 | 982 |
Long-term operating lease right-of-use assets, net | 393 | 378 |
Long-term inventory | 253 | 130 |
Other long-term assets, net | 251 | 162 |
Total assets | 28,609 | 24,497 |
CURRENT LIABILITIES | ||
Trade accounts payable | 4,810 | 2,437 |
Short-term debt | 822 | 831 |
Other current liabilities | 600 | 985 |
Total current liabilities | 6,232 | 4,253 |
LONG-TERM LIABILITIES | ||
Senior notes, net | 8,329 | 9,071 |
Other long-term debt, net | 69 | 311 |
Long-term operating lease liabilities | 339 | 317 |
Other long-term liabilities and deferred credits | 830 | 807 |
Total long-term liabilities | 9,567 | 10,506 |
COMMITMENTS AND CONTINGENCIES (NOTE 19) | ||
PARTNERS’ CAPITAL | ||
Total partners’ capital excluding noncontrolling interests | 9,972 | 9,593 |
Noncontrolling interests | 2,838 | 145 |
Total partners’ capital | 12,810 | 9,738 |
Total liabilities and partners’ capital | 28,609 | 24,497 |
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 | $ 7,680 | $ 7,301 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares | Dec. 31, 2021 | Dec. 31, 2020 |
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) | 704,991,540 | 722,380,416 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
REVENUES | |||
Total revenues | $ 42,078 | $ 23,290 | $ 33,669 |
COSTS AND EXPENSES | |||
Purchases and related costs | 38,504 | 20,431 | 29,452 |
Field operating costs | 1,065 | 1,076 | 1,303 |
General and administrative expenses | 292 | 271 | 297 |
Depreciation and amortization | 774 | 653 | 601 |
(Gains)/losses on asset sales and asset impairments, net (Note 6, Note 7) | 592 | 719 | 28 |
Goodwill impairment losses (Note 8) | 0 | 2,515 | 0 |
Total costs and expenses | 41,227 | 25,665 | 31,681 |
OPERATING INCOME/(LOSS) | 851 | (2,375) | 1,988 |
OTHER INCOME/(EXPENSE) | |||
Equity earnings in unconsolidated entities | 274 | 355 | 388 |
Gain on/(impairment of) investments in unconsolidated entities, net (Note 9) | 2 | (182) | 271 |
Interest expense (net of capitalized interest of $18, $24 and $34, respectively) | (425) | (436) | (425) |
Other income, net | 19 | 39 | 24 |
INCOME/(LOSS) BEFORE TAX | 721 | (2,599) | 2,246 |
Current income tax expense | (50) | (51) | (112) |
Deferred income tax (expense)/benefit | (23) | 70 | 46 |
NET INCOME/(LOSS) | 648 | (2,580) | 2,180 |
Net income attributable to noncontrolling interests | (55) | (10) | (9) |
NET INCOME/(LOSS) ATTRIBUTABLE TO PAA | 593 | (2,590) | 2,171 |
NET INCOME/(LOSS) PER COMMON UNIT (NOTE 4): | |||
Net income/(loss) allocated to common unitholders — Basic | 393 | (2,790) | 1,967 |
Net income/(loss) allocated to common unitholders — Diluted | $ 393 | $ (2,790) | $ 2,119 |
Common Units | |||
NET INCOME/(LOSS) PER COMMON UNIT (NOTE 4): | |||
Basic weighted average common units outstanding (in units) | 716 | 728 | 727 |
Basic net income/(loss) per common unit (in dollars per unit) | $ 0.55 | $ (3.83) | $ 2.70 |
Diluted weighted average common units outstanding (in units) | 716 | 728 | 800 |
Diluted net income/(loss) per common unit (in dollars per unit) | $ 0.55 | $ (3.83) | $ 2.65 |
Product sales revenues | |||
REVENUES | |||
Total revenues | $ 40,883 | $ 22,058 | $ 32,272 |
Services revenues | |||
REVENUES | |||
Total revenues | $ 1,195 | $ 1,232 | $ 1,397 |
CONSOLIDATED STATEMENTS OF OP_2
CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Income Statement [Abstract] | |||
Capitalized interest | $ 18 | $ 24 | $ 34 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Statement of Comprehensive Income [Abstract] | |||
Net income/(loss) | $ 648 | $ (2,580) | $ 2,180 |
Other comprehensive income | 65 | 15 | 97 |
Comprehensive income/(loss) | 713 | (2,565) | 2,277 |
Comprehensive income attributable to noncontrolling interests | (55) | (10) | (9) |
Comprehensive income/(loss) attributable to PAA | $ 658 | $ (2,575) | $ 2,268 |
CONSOLIDATED STATEMENTS OF CHAN
CONSOLIDATED STATEMENTS OF CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Balance, beginning of period | $ 9,738 | $ 13,195 | $ 12,002 |
Changes in Accumulated Other Comprehensive Income/(Loss) | |||
Total period activity | 65 | 15 | 97 |
Balance, end of period | 12,810 | 9,738 | 13,195 |
Derivative Instruments | |||
Balance, beginning of period | (258) | (259) | (177) |
Changes in Accumulated Other Comprehensive Income/(Loss) | |||
Reclassification adjustments | 31 | 11 | 9 |
Unrealized gain/(loss) on hedges | 19 | (10) | (91) |
Total period activity | 50 | 1 | (82) |
Balance, end of period | (208) | (258) | (259) |
Translation Adjustments | |||
Balance, beginning of period | (657) | (674) | (853) |
Changes in Accumulated Other Comprehensive Income/(Loss) | |||
Currency translation adjustments | 15 | 17 | 179 |
Total period activity | 15 | 17 | 179 |
Balance, end of period | (642) | (657) | (674) |
Other | |||
Balance, beginning of period | (3) | ||
Changes in Accumulated Other Comprehensive Income/(Loss) | |||
Other | (3) | ||
Total period activity | (3) | ||
Balance, end of period | (3) | (3) | |
Total | |||
Balance, beginning of period | (918) | (933) | (1,030) |
Changes in Accumulated Other Comprehensive Income/(Loss) | |||
Reclassification adjustments | 31 | 11 | 9 |
Unrealized gain/(loss) on hedges | 19 | (10) | (91) |
Currency translation adjustments | 15 | 17 | 179 |
Other | (3) | ||
Total period activity | 65 | 15 | 97 |
Balance, end of period | $ (853) | $ (918) | $ (933) |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
CASH FLOWS FROM OPERATING ACTIVITIES | |||
Net income/(loss) | $ 648 | $ (2,580) | $ 2,180 |
Reconciliation of net income/(loss) to net cash provided by operating activities: | |||
Depreciation and amortization | 774 | 653 | 601 |
(Gains)/losses on asset sales and asset impairments, net (Note 6, Note 7) | 592 | 719 | 28 |
Goodwill impairment losses (Note 8) | 0 | 2,515 | 0 |
Equity-indexed compensation expense | 23 | 15 | 34 |
Inventory valuation adjustments (Note 5) | 0 | 233 | 11 |
Deferred income tax expense/(benefit) | 23 | (70) | (46) |
Settlement of terminated interest rate hedging instruments | (100) | (55) | |
Equity earnings in unconsolidated entities | (274) | (355) | (388) |
Distributions on earnings from unconsolidated entities | 431 | 472 | 401 |
(Gain on)/impairment of investments in unconsolidated entities, net (Note 9) | (2) | 182 | (271) |
Other | 8 | (12) | 21 |
Changes in assets and liabilities, net of acquisitions: | |||
Trade accounts receivable and other | (2,179) | 1,432 | (1,158) |
Inventory | (18) | (304) | (5) |
Trade accounts payable and other | 1,970 | (1,286) | 1,151 |
Net cash provided by operating activities | 1,996 | 1,514 | 2,504 |
CASH FLOWS FROM INVESTING ACTIVITIES | |||
Cash paid in connection with acquisitions, net of cash acquired (Note 7) | (32) | (310) | (50) |
Investments in unconsolidated entities (Note 9) | (94) | (461) | (524) |
Additions to property, equipment and other | (336) | (738) | (1,181) |
Proceeds from sales of assets (Note 7) | 881 | 429 | 77 |
Other investing activities | (33) | (13) | (87) |
Net cash provided by/(used in) investing activities | 386 | (1,093) | (1,765) |
CASH FLOWS FROM FINANCING ACTIVITIES | |||
Net borrowings/(repayments) under commercial paper program (Note 11) | (545) | 456 | 93 |
Net borrowings/(repayments) under senior secured hedged inventory facility (Note 11) | (167) | (160) | 325 |
Repayment of GO Zone term loans (Note 11) | (200) | ||
Proceeds from the issuance of senior notes (Note 11) | 748 | 998 | |
Repayments of senior notes (Note 11) | (617) | (1,000) | |
Repurchase of common units (Note 12) | (178) | (50) | |
Sale of noncontrolling interest in a subsidiary (Note 12) | 128 | ||
Other financing activities | (179) | 41 | (62) |
Net cash used in financing activities | (1,984) | (435) | (720) |
Effect of translation adjustment | (5) | (8) | (3) |
Net increase/(decrease) in cash and cash equivalents and restricted cash | 393 | (22) | 16 |
Cash and cash equivalents and restricted cash, beginning of period | 60 | 82 | 66 |
Cash and cash equivalents and restricted cash, end of period | 453 | 60 | 82 |
Cash paid for: | |||
Interest, net of amounts capitalized | 401 | 428 | 397 |
Income taxes, net of amounts refunded | 76 | 111 | 136 |
Series A Preferred Units | |||
CASH FLOWS FROM FINANCING ACTIVITIES | |||
Distributions paid to unitholders (Note 12) | (149) | (149) | (149) |
Series B Preferred Units | |||
CASH FLOWS FROM FINANCING ACTIVITIES | |||
Distributions paid to unitholders (Note 12) | (49) | (49) | (49) |
Common Units | |||
CASH FLOWS FROM FINANCING ACTIVITIES | |||
Distributions paid to unitholders (Note 12) | $ (517) | $ (655) | $ (1,004) |
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 UnitsLimited PartnersPartners’ Capital Excluding Noncontrolling Interests |
Balance, beginning of period at Dec. 31, 2018 | $ 12,002 | $ 12,002 | $ 1,505 | $ 787 | $ 9,710 | |
Increase (Decrease) in Partners' Capital [Roll Forward] | ||||||
Net income/(loss) | 2,180 | 2,171 | $ 9 | 149 | 49 | 1,973 |
Distributions (Note 12) | (1,208) | (1,202) | (6) | (149) | (49) | (1,004) |
Other comprehensive income | 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 |
Increase (Decrease) in Partners' Capital [Roll Forward] | ||||||
Net income/(loss) | (2,580) | (2,590) | 10 | 149 | 49 | (2,788) |
Distributions (Note 12) | (863) | (853) | (10) | (149) | (49) | (655) |
Other comprehensive income | 15 | 15 | 15 | |||
Equity-indexed compensation expense | 19 | 19 | 19 | |||
Repurchase of common units (Note 12) | (50) | (50) | (50) | |||
Partners' Capital Account, Contributions (Note 12) | 12 | 12 | ||||
Other | (10) | (10) | (10) | |||
Balance, end of period at Dec. 31, 2020 | 9,738 | 9,593 | 145 | 1,505 | 787 | 7,301 |
Increase (Decrease) in Partners' Capital [Roll Forward] | ||||||
Net income/(loss) | 648 | 593 | 55 | 149 | 49 | 395 |
Distributions (Note 12) | (729) | (715) | (14) | (149) | (49) | (517) |
Other comprehensive income | 65 | 65 | 65 | |||
Equity-indexed compensation expense | 19 | 19 | 19 | |||
Repurchase of common units (Note 12) | (178) | (178) | (178) | |||
Partners' Capital Account, Contributions (Note 12) | 1 | 1 | ||||
Plains Oryx Permian Basin LLC joint venture formation (Note 7) | 3,256 | 605 | 2,651 | 605 | ||
Other | (10) | (10) | (10) | |||
Balance, end of period at Dec. 31, 2021 | $ 12,810 | $ 9,972 | $ 2,838 | $ 1,505 | $ 787 | $ 7,680 |
Organization and Basis of Conso
Organization and Basis of Consolidation and Presentation | 12 Months Ended |
Dec. 31, 2021 | |
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. Our business model integrates large-scale supply aggregation capabilities with the ownership and operation of critical midstream infrastructure systems that connect major producing regions to key demand centers and export terminals. As one of the largest midstream service providers in North America, we own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and natural gas liquids (“NGL”) producing basins (including the Permian Basin) and transportation corridors and at major market hubs in the United States and Canada. Our assets and the services we provide are primarily focused on and conducted through two operating segments: Crude Oil and NGL. See Note 20 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, 2021, AAP also owned a limited partner interest in us through its ownership of approximately 241.5 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, 2021, owned an approximate 81% 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 Btu = British thermal unit 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 SEC = United States Securities and Exchange Commission TWh = Terawatt hour U.S. = United States 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, 2021 and 2020, 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, 2021, 2020 and 2019. 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, as discussed further below. 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. Reclassification of Prior Period Information During the fourth quarter of 2021, we effected changes in the primary financial information provided to our Chief Operating Decision Maker (“CODM”) (our Chief Executive Officer) for assessing performance and allocating resources to present two operating segments, Crude Oil and NGL. Prior to the fourth quarter of 2021, this information was organized into three operating segments: Transportation, Facilities and Supply and Logistics. See Note 20 for further discussion of our operating segments. In connection with this change, we changed the presentation of Revenues on our Consolidated Statements of Operations. “Product sales revenues” include amounts that were previously presented as “Supply and Logistics segment revenues,” while “Services revenues” includes amounts previously presented as “Transportation segment revenues” and “Facilities segment revenues.” In October 2021, we and Oryx Midstream Holdings LLC (“Oryx Midstream”) completed the merger, in a cashless, debt-free transaction, of our respective Permian Basin assets, operations and commercial activities into a newly formed joint venture, Plains Oryx Permian Basin LLC (the “Permian JV”). See Note 7 for more details regarding this transaction. Due to the increase in intangible assets associated with this transaction, we present “Intangible assets, net” as a separate line item on our Consolidated Balance Sheets. Such amounts were previously reported in “Other long-term assets, net” on our Consolidated Balance Sheets. COVID-19 Many uncertainties remain with respect to the novel coronavirus (“COVID-19”) pandemic, including uncertainty regarding the length of time the pandemic will continue, as well as the timing, pace and extent of an economic recovery in the United States, Canada and elsewhere, and how such uncertainties will impact the energy industry and our business. As a result, these matters may affect our estimates and assumptions on amounts reported in the financial statements and accompanying notes in the near term. Subsequent Events 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, 2021 | |
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) fair value of derivatives, (iii) accruals and contingent liabilities, (iv) property and equipment, depreciation and amortization expense and asset retirement obligations, (v) impairment assessments of property and equipment, investments in unconsolidated entities and intangible assets and (vi) 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 and NGL sold to customers, (ii) fees incurred for storage and transportation, whether by pipeline, truck or rail 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. For the years ended December 31, 2021, 2020 and 2019, the revaluation of foreign currency transactions and monetary assets and liabilities resulted in the recognitions of net gains of $7 million, $16 million and $1 million, respectively, in our Consolidated Statements of Operations. 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, 2021 and 2020, trade accounts payable included $19 million and $27 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 Sheets that sum to the total of the amounts shown on our Consolidated Statements of Cash Flows (in millions): December 31, 2021 2020 Cash and cash equivalents $ 449 $ 22 Restricted cash 4 38 Total cash and cash equivalents and restricted cash $ 453 $ 60 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 our pipelines, certain processing and fractionation facilities and terminals assets, 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, storage or other 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 estimate 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, substantially all of which is reflected in “Other long-term liabilities and deferred credits” on our Consolidated Balance Sheets as of December 31, 2021, 2020 and 2019 (in millions): December 31, 2021 2020 2019 Beginning balance $ 135 $ 137 $ 109 Liabilities incurred 2 12 3 Liabilities settled (1) (1) (3) Accretion expense 4 5 5 Revisions in estimated cash flows 3 (18) 23 Ending balance $ 143 $ 135 $ 137 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/(loss) 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) intangible assets, (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 October 2021, the FASB issued ASU 2021-08, Business Combinations (Topic 805): Accounting for Contract Assets and Contract Liabilities from Contracts with Customers . This guidance requires that an acquirer recognize and measure contract assets and contract liabilities acquired in a business combination in accordance with Topic 606, Revenue from Contracts with Customers, as if it had originated the contracts. The guidance is effective prospectively for interim and annual periods beginning after December 15, 2022, with early adoption permitted. We have not adopted this guidance as of December 31, 2021, but do not anticipate that our adoption will have a material impact on our financial position, results of operations or cash flows. In July 2021, the FASB issued ASU 2021-05, Lessors - Certain Leases with Variable Lease Payments (Topic 842) w hich modifies the lease classification requirements for lessors in Topic 842, which we adopted on the effective date of January 1, 2019. The amendments require lessors to classify and account for a lease with variable lease payments that do not depend on a reference index or a rate as an operating lease at lease commencement if another classification (i.e., sales-type or direct financing) would result in the recognition of a day-one loss. For entities that have adopted Topic 842, the guidance is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2021, with early adoption permitted. We have elected to early adopt the guidance on a prospective basis as of July 1, 2021. Our adoption did not have a material impact on our financial position, results of operations or cash flows. In August 2020, the FASB issued ASU 2020-06, Debt—Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging—Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity , which simplifies accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity, by eliminating two of the three models that require separate accounting for embedded conversion features and the settlement assessment that entities are required to perform to determine whether a contract qualifies for equity classification. This guidance is effective for interim and annual periods beginning after December 15, 2021, with early adoption permitted. We adopted this guidance effective January 1, 2021, and our adoption did not have a material impact on our financial position, results of operations or cash flows. In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting , which provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. This guidance is effective prospectively upon issuance through December 31, 2022 and may be applied from the beginning of an interim period that includes the issuance date of this ASU. We will apply applicable expedients and exceptions to contract modifications through December 31, 2022. In December 2019, the FASB issued ASU 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 adopted this guidance effective January 1, 2021, and our adoption did not have a material impact on our financial position, results of operations or cash flows. |
Revenues and Accounts Receivabl
Revenues and Accounts Receivable | 12 Months Ended |
Dec. 31, 2021 | |
Revenue from Contract with Customer [Abstract] | |
Revenues and Accounts Receivable | Revenues and Accounts Receivable Revenue Recognition 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. Revenues from Contracts with Customers. The following tables present our revenues from contracts with customers disaggregated by segment and type of activity (in millions): Year Ended December 31, 2021 2020 2019 Crude Oil segment revenues from contracts with customers Sales $ 39,635 $ 21,250 $ 30,156 Transportation 484 570 722 Terminalling, Storage and Other 431 507 505 Total Crude Oil segment revenues from contracts with customers $ 40,550 $ 22,327 $ 31,383 Year Ended December 31, 2021 2020 2019 NGL segment revenues from contracts with customers Sales $ 2,292 $ 1,350 $ 2,211 Transportation 25 29 32 Terminalling, Storage and Other 82 96 80 Total NGL segment revenues from contracts with customers $ 2,399 $ 1,475 $ 2,323 Sales Revenues. Revenues from sales of crude oil and NGL are recognized at the time title to the product sold transfers to the purchaser, which occurs upon delivery of the product to the purchaser or its designee. The consideration received under these contracts is variable based on commodity prices. Inventory exchanges under buy/sell transactions are excluded from sales revenues in our Consolidated Statements of Operations. 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. See “ Contract Balances ” below for further discussion of contract liabilities associated with these agreements. The following table presents amounts in Other current assets and deferred revenue associated with these agreements (in millions): December 31, 2021 2020 Other current assets $ — $ 229 Deferred revenue (1) $ — $ 361 (1) Included in “Other current liabilities” on our Consolidated Balance Sheet. 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 Revenues. Transportation revenues include revenues from transporting crude oil and NGL on pipelines 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. Terminalling, Storage and Other Revenues. Revenues in this category include (i) fees that are generated when we receive liquids from one connecting source and deliver the applicable product to another connecting carrier, (ii) fees from storage capacity agreements, (iii) fees from loading and unloading services at our terminals and (iv) fees from natural gas and condensate processing services and from NGL fractionation and isomerization service. 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 loading/unloading 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. We recognize loading and unloading fees when the volumes are delivered or received. Natural gas storage related activities fees were recognized in the period the natural gas moved across our header system. Fees from NGL fractionation and isomerization services and gas processing services are recognized in the period when the services are performed. Reconciliation to Total Revenues of Reportable Segments. The following disclosures only include information regarding revenues associated with consolidated entities; revenues from entities accounted for by the equity method are not included. 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, 2021 Crude Oil NGL Total Revenues from contracts with customers $ 40,550 $ 2,399 $ 42,949 Other items in revenues (80) (431) (511) Total revenues of reportable segments $ 40,470 $ 1,968 $ 42,438 Intersegment revenues elimination (360) Total revenues $ 42,078 Year Ended December 31, 2020 Crude Oil NGL Total Revenues from contracts with customers $ 22,327 $ 1,475 $ 23,802 Other items in revenues (128) (115) (243) Total revenues of reportable segments $ 22,199 $ 1,360 $ 23,559 Intersegment revenues elimination (269) Total revenues $ 23,290 Year Ended December 31, 2019 Crude Oil NGL Total Revenues from contracts with customers $ 31,383 $ 2,323 $ 33,706 Other items in revenues 272 116 388 Total revenues of reportable segments $ 31,655 $ 2,439 $ 34,094 Intersegment revenues elimination (425) Total revenues $ 33,669 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. The following table presents counterparty deficiencies associated with contracts with customers and buy/sell arrangements that include minimum volume commitments for which we had remaining performance obligations and the customers still had the ability to meet their obligations (in millions): December 31, Counterparty Deficiencies Financial Statement Classification 2021 2020 Billed and collected Liability $ 63 $ 73 Unbilled (1) N/A 16 4 Total $ 79 $ 77 (1) Amounts were related to deficiencies for which the counterparties had not met their contractual minimum commitments and are 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 liability balance associated with contracts with customers (in millions): Contract Liabilities Balance at December 31, 2019 $ 354 Amounts recognized as revenue (1) (246) Additions (2) 393 Balance at December 31, 2020 $ 501 Amounts recognized as revenue (2) (393) Additions 33 Balance at December 31, 2021 $ 141 (1) Includes approximately $155 million associated with crude oil sales agreements that were entered into in conjunction with storage arrangements and future inventory exchanges. Such agreements were entered into in 2019 and recognized as revenue in the first quarter of 2020. (2) Includes approximately $361 million associated with crude oil sales agreements that were entered into in conjunction with storage arrangements and future inventory exchanges. Such amount was recognized as revenue in the first quarter of 2021. Remaining Performance Obligations . The information below includes the amount of consideration allocated to partially and wholly unsatisfied remaining performance obligations under contracts that exist as of the end of the periods 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. 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, 2021 (in millions): 2022 2023 2024 2025 2026 2027 and Thereafter Pipeline revenues supported by minimum volume commitments and capacity agreements (1) $ 179 $ 174 $ 158 $ 131 $ 86 $ 379 Terminalling, storage and other agreement revenues 237 170 130 63 45 197 Total $ 416 $ 344 $ 288 $ 194 $ 131 $ 576 (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 ASC 606 or do not meet the requirements for presentation as remaining performance obligations. The following are examples of contracts that are not included in the table above because they are not within the scope of ASC 606 or do not meet the requirements for presentation: • Minimum volume commitments on certain of our joint venture pipeline systems; • Acreage dedications; • Buy/sell arrangements with future committed volumes; • Short-term contracts and those with variable consideration due to the election of practical expedients, 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 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 merchant 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, merchant 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 merchant 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 our receivables net of expected credit losses. We do not write-off accounts receivable balances until we have exhausted substantially all collection efforts. At December 31, 2021 and 2020, substantially all of our trade accounts receivable were less than 30 days past their invoice date. Our expected credit losses are immaterial. Although we consider our credit procedures to be adequate to mitigate any significant credit losses, the actual amount of current and future credit losses 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, 2021 2020 Trade accounts receivable arising from revenues from contracts with customers $ 4,031 $ 2,317 Other trade accounts receivables and other receivables (1) 5,126 2,818 Impact due to contractual rights of offset with counterparties (4,452) (2,582) Trade accounts receivable and other receivables, net $ 4,705 $ 2,553 (1) The balance is comprised primarily of accounts receivable associated with buy/sell arrangements that are not within the scope of ASC 606. |
Net Income_(Loss) Per Common Un
Net Income/(Loss) Per Common Unit | 12 Months Ended |
Dec. 31, 2021 | |
Earnings Per Share [Abstract] | |
Net Income/(Loss) Per Common Unit | Net Income/(Loss) Per Common Unit After consideration of distributions to preferred unitholders (whether paid in cash or in-kind), basic and diluted net income/(loss) 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/(loss) per common unit by dividing net income/(loss) 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. Participating securities include equity-indexed compensation plan awards that have vested distribution equivalent rights, which entitle the grantee to a cash payment equal to the cash distribution paid on our outstanding common units. 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 approximately 71 million Series A preferred units, on a weighted-average basis, were excluded from the calculation of diluted net income/(loss) per common unit for the year ended December 31, 2021 and 2020 as the effect was antidilutive for both periods. Our equity-indexed compensation plan awards that contemplate the issuance of common units are considered potentially 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 year 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. For the twelve months ended December 31, 2021 and 2020, approximately 0.5 million and 0.3 million equity-indexed compensation plan awards, respectively, on a weighted-average basis, were excluded from the computation of diluted net loss per common unit as the effect did not change the presentation of diluted net income/(loss) per common unit or the effect was antidilutive. The following table sets forth the computation of basic and diluted net income/(loss) per common unit (in millions, except per unit data): Year Ended December 31, 2021 2020 2019 Basic Net Income/(Loss) per Common Unit Net income/(loss) attributable to PAA $ 593 $ (2,590) $ 2,171 Distributions to Series A preferred unitholders (149) (149) (149) Distributions to Series B preferred unitholders (49) (49) (49) Distributions to participating securities (2) (2) (3) Other — — (3) Net income/(loss) allocated to common unitholders (1) $ 393 $ (2,790) $ 1,967 Basic weighted average common units outstanding 716 728 727 Basic net income/(loss) per common unit $ 0.55 $ (3.83) $ 2.70 Diluted Net Income/(Loss) per Common Unit Net income/(loss) attributable to PAA $ 593 $ (2,590) $ 2,171 Distributions to Series A preferred unitholders (149) (149) — Distributions to Series B preferred unitholders (49) (49) (49) Distributions to participating securities (2) (2) (3) Net income/(loss) allocated to common unitholders (1) $ 393 $ (2,790) $ 2,119 Basic weighted average common units outstanding 716 728 727 Effect of dilutive securities: Series A preferred units — — 71 Equity-indexed compensation plan awards — — 2 Diluted weighted average common units outstanding 716 728 800 Diluted net income/(loss) per common unit $ 0.55 $ (3.83) $ 2.65 (1) We calculate net income/(loss) allocated to common unitholders based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings (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, 2021 | |
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, including long-term 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 year ended December 31, 2021, no adjustments were recorded. During the years ended December 31, 2020 and 2019, we recorded charges of $233 million (of which $40 million was associated with our long-term inventory) and $11 million, respectively, related to the write down of our crude oil and NGL 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 and NGL inventory. Such gains were recorded to “Product sales 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. Following the sale of our Pine Prairie and Southern Pines natural gas storage facilities in August of 2021, we no longer own natural gas storage facilities. See Note 7 for additional information. 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 2021, 2020 and 2019, we did not recognize any material 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, 2021 December 31, 2020 Volumes Unit of Carrying Price/ Unit (1) Volumes Unit of Carrying Price/ Unit (1) Inventory Crude oil 8,041 barrels $ 544 $ 67.65 13,450 barrels $ 441 $ 32.79 NGL 6,982 barrels 234 $ 33.51 12,302 barrels 199 $ 16.18 Other N/A 5 N/A N/A 7 N/A Inventory subtotal 783 647 Linefill and base gas Crude oil 15,199 barrels 862 $ 56.71 14,669 barrels 828 $ 56.45 NGL 1,633 barrels 45 $ 27.56 1,640 barrels 44 $ 26.83 Natural gas (2) — Mcf — $ — 25,576 Mcf 110 $ 4.30 Linefill and base gas subtotal 907 982 Long-term inventory Crude oil 2,973 barrels 209 $ 70.30 2,499 barrels 111 $ 44.42 NGL 1,135 barrels 44 $ 38.77 1,185 barrels 19 $ 16.03 Long-term inventory subtotal 253 130 Total $ 1,943 $ 1,759 (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. (2) Base gas with a carrying value of $110 million was included in the sale of our natural gas storage facilities, which closed in August 2021. See Note 7 for additional information. |
Property and Equipment
Property and Equipment | 12 Months Ended |
Dec. 31, 2021 | |
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, 2021, 2020 and 2019, capitalized interest recorded to property and equipment was $6 million, $8 million and $14 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, 2021 2020 Pipelines and related facilities (1) (2) 10 - 50 $ 12,765 $ 11,112 Storage, terminal and rail facilities (2) 10 - 50 5,100 6,042 Trucking equipment and other 2 - 15 502 524 Construction in progress N/A 248 272 Office property and equipment 2 - 50 312 293 Land and other N/A 330 342 Property and equipment, gross 19,257 18,585 Accumulated depreciation (4,354) (3,974) Property and equipment, net $ 14,903 $ 14,611 (1) We include rights-of-way, which are intangible assets, in our Pipelines and related facilities amounts within property and equipment. (2) Useful lives changed to 10 to 50 years in 2021. See below for additional information. 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, 2021, 2020 and 2019 was $652 million, $563 million and $525 million, respectively. During the first quarter of 2021, we modified the useful lives of our Pipelines and related facilities and Storage, terminal and rail facilities to useful lives of 10 to 50 years from useful lives of 10 to 70 years to reflect current expectations given our future operating and commercial outlook. These depreciable life adjustments will prospectively increase depreciation expense. For the year ended December 31, 2021, these reductions in useful lives increased depreciation expense by approximately $72 million, which resulted in a decrease to both basic and diluted net income per common unit of approximately $0.10 from what these amounts would have been absent the change in useful lives. As of December 31, 2021, 2020 and 2019, we incurred liabilities for construction in progress that had not been paid of $48 million, $51 million and $120 million, respectively. Impairment of Long-Lived Assets (Held and Used) 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. During the year ended December 31, 2021, we recognized approximately $220 million of non-cash impairment losses related to certain crude oil storage terminal assets included in our Crude Oil segment. This amount is reflected in “(Gains)/losses on asset sales and asset impairments, net” on our Consolidated Statements of Operations. Decreased demand for our services related to changing market conditions resulted in decreases in expected future cash flows for certain of our assets, which was a triggering event that required us to assess the recoverability of our carrying value of such long-lived assets. As a result of our impairment review, we wrote off the portion of the carrying amount of these long-lived assets that exceeded their fair value. Our estimated fair value (which we consider a Level 3 measurement in the fair value hierarchy) was primarily based upon an assumption for the amount for which the relevant assets and land could be sold. During the year ended December 31, 2020, we recognized approximately $541 million of non-cash impairment losses, reflected in “(Gains)/losses on asset sales and asset impairments, net” on our Consolidated Statement of Operations. Of our impairment losses, approximately $415 million was associated with certain pipeline assets in our Crude Oil segment located in the Mid-Continent region. The macroeconomic and geopolitical conditions that occurred in 2020, including the collapse of oil prices driven by both the decrease in demand caused by the COVID-19 pandemic and excess supply, as well as changing market conditions and expected lower crude oil production in certain regions, resulted in expected decreases in future cash flows for certain of our assets, which was a triggering event that required us to assess the recoverability of our carrying value of such long-lived assets. As a result of our impairment review, we wrote off the portion of the carrying amount of these long-lived assets that exceeded their fair value. Our estimated fair values (which we consider a Level 3 measurement in the fair value hierarchy) were based upon a discounted cash flow approach utilizing various assumptions and the application of a discount rate of approximately 14%, which represents our estimate of the cost of capital of a theoretical market participant. Such assumptions included (but were not limited to) (i) future commodity volumes (consistent with historical information and estimates of future drilling and completion activity), (ii) tariff rates, (iii) future commodity prices (based on relevant indices and applicable quality and location differentials), and (iv) estimated fixed and variable costs. The remaining impairment losses were associated with idled or underutilized assets, primarily in our Crude Oil segment, including certain pipelines located in the Western region and other long-lived assets, for which it has been determined that it is unlikely that opportunities will exist in the future to recover our investment in these assets. We wrote off substantially all of the carrying value of these assets. We did not recognize any material impairments during the year ended December 31, 2019. |
Acquisitions, Divestitures and
Acquisitions, Divestitures and Other Transactions | 12 Months Ended |
Dec. 31, 2021 | |
Business Combinations [Abstract] | |
Acquisitions, Divestitures and Other Transactions | Acquisitions, Divestitures and Other Transactions Joint Venture Transaction In October 2021, we and Oryx Midstream completed the merger, in a cashless, debt-free transaction, of our respective Permian Basin assets, operations and commercial activities into a newly formed joint venture, the Permian JV. The Permian JV includes all of Oryx Midstream’s Permian Basin assets and, with the exception of our long-haul pipeline systems and certain of our intra-basin terminal assets, the vast majority of our assets located within the Permian Basin. We own 65% of the Permian JV, operate the combined assets and reflect the Permian JV as a consolidated subsidiary in our consolidated financial statements. The formation of the joint venture was accounted for as a business combination using the acquisition method of accounting. As the majority owner and the controlling entity, we are considered the acquirer and the transfer of our predecessor business to the joint venture was accounted for at historical cost, while the Oryx Midstream predecessor business was recorded based on the fair value of the assets acquired and liabilities assumed. In accordance with applicable accounting guidance, the fair value of Oryx Midstream’s ownership interest in the joint venture following the formation of $3.256 billion is utilized as the consideration transferred for the purchase price allocation. The combination of the historical cost and fair value, discussed above, resulted in net assets of the joint venture of approximately $7.575 billion upon formation. Oryx Midstream’s 35% interest in the net assets of the Permian JV was recognized as noncontrolling interest in partners’ capital. The difference between the noncontrolling interest recognized and the fair value of Oryx Midstream’s assets acquired and liabilities assumed was recorded as an increase to our partners’ capital excluding noncontrolling interests. The following table presents the amounts recognized in partners’ capital associated with this transaction (in millions): Recognized Amount Noncontrolling interests $ 2,651 Partners’ capital, excluding noncontrolling interests 605 $ 3,256 The fair value of the $3.256 billion consideration is a Level 3 measurement in the fair value hierarchy and was determined by valuing both the enterprise value of Oryx Midstream’s Permian Basin business and the enterprise value of our Permian Basin assets that were contributed to the joint venture. The enterprise value of Oryx Midstream’s Permian Basin business was calculated by weighting the results of (i) a discounted cash flow (“DCF”) approach and (ii) a guideline public company method (“GPCM”). The value of our Permian Basin assets that were contributed to the joint venture was based on a GPCM. The DCF approach utilized a discount rate of 11.75%, based on our estimate of the risk that a theoretical market participant would assign to the business. The projection of future crude volumes gathered and transported was also a key assumption in the DCF approach and was based on projected rig activity on the associated acreage. The GPCM applies market multiples to estimated earnings to derive the fair value. The GPCM values for Oryx Midstream’s Permian Basin business and for our Permian Basin assets that were contributed to the joint venture assumed market multiples ranging from 9.5 to 11.0, which were derived from assumptions of market multiples for similar businesses. The determination of the fair value of the assets acquired and liabilities assumed was estimated in accordance with the applicable accounting guidance. The analysis was performed based on estimates that are reflective of market participant assumptions. The determination of these values is preliminary, pending finalization of working capital balances, and we expect to finalize our fair value determination in 2022. The following table reflects our preliminary determination of the fair value of those assets and liabilities (in millions): Identifiable Assets Acquired and Liabilities Assumed Estimated Useful Lives Recognized Amount Property and equipment 3-30 $ 1,886 Intangible assets 20 1,247 Investment in unconsolidated entities N/A 103 Linefill N/A 5 Working capital and other assets and liabilities N/A 15 $ 3,256 The fair value of the tangible assets is a Level 3 measurement in the fair value hierarchy and was determined using a cost approach based on costs incurred on similar recent construction projects. The fair value of the intangible assets is also a Level 3 measurement in the fair value hierarchy and was determined by applying a discounted cash flow approach. Such approach utilized a discount rate of approximately 16%, based on our estimate of the risk that a theoretical market participant would assign to the respective intangible assets. The projection of future crude oil volumes gathered and transported was also a key assumption in the valuation of the intangible assets and was based on projected rig activity on the associated acreage. The fair value of intangible assets is comprised of customer relationships that will be amortized over their useful lives, which have a remaining weighted average life of approximately 20 years. The value assigned to such intangible assets will be amortized to earnings under the declining balance method of amortization. Amortization expense was approximately $28 million during the year ended December 31, 2021, and the future amortization expense through 2026 is estimated as follows (in millions): 2022 $ 142 2023 $ 138 2024 $ 127 2025 $ 117 2026 $ 106 During the year ended December 31, 2021, we incurred approximately $17 million of transaction-related costs associated with the joint venture formation transaction. Such costs are reflected as a component of “General and administrative expenses” on our Consolidated Statements of Operations. Quarterly distributions of available cash from the Permian JV to us and Oryx Midstream are subject to a tiered modified sharing arrangement (“MSA”) for up to ten years. Pursuant to the terms of the governing documents for the Permian JV, the MSA will terminate in October 2031, or sooner if Oryx Midstream exercises its right to terminate the MSA at any time by delivery of written notice to us. Upon termination of the MSA, quarterly distributions of available cash will be paid 65% to PAA and 35% to Oryx. Under the MSA, distributions will be allocated as follows (in millions): Available Cash Distributions Percentages Tier Annualized PAA Oryx 1 Up to $300 50% 50% 2 $300 - $428 100% —% 3 $428 - $815 65% 35% 4 $815 and above 70% 30% Oryx Midstream is a portfolio company of Stonepeak Infrastructure Partners (“Stonepeak”). Affiliates of Stonepeak own approximately 8.9% of our outstanding Series A preferred units, which equates to less than 1% of our outstanding common units and Series A preferred units (our “common unit equivalents”) combined. Pro Forma and Other Financial Results Financial results of the Permian JV have been included in the results of operations within the Crude Oil segment since the date of the formation. Disclosure of the revenues and earnings from the Oryx Midstream predecessor business for the period subsequent to the joint venture formation is not practicable as it is not being operated as a standalone subsidiary. The following selected unaudited pro forma results of operations were derived from the historical financial statements of PAA and Oryx Midstream, and gives effect to the joint venture formation as if it had occurred on January 1, 2020. The pro forma results of operations do not include any cost savings or other synergies that may result from the Permian JV or any estimated costs that have been or will be incurred by us to integrate Oryx Midstream’s assets. These results are not necessarily indicative of the results that might have actually occurred had the merger taken place on January 1, 2020; furthermore, this financial information is not intended to be a projection of future results (in millions, except per unit amounts): Year ended December 31, 2021 2020 Total revenues $ 42,359 $ 23,536 Net income/(loss) attributable to PAA $ 524 $ (2,898) Net income/(loss) allocated to common unitholders $ 324 $ (3,098) Basic and diluted net income/(loss) per common unit $ 0.45 $ (4.26) Asset Exchange In June 2021, we closed on an asset exchange agreement (the “Asset Exchange”) with Inter Pipeline Ltd., through which we acquired additional interests in two straddle plants included in our NGL segment that we currently operate, in exchange for a pipeline and related storage and truck offload facilities previously included in our Crude Oil segment and cash consideration of $32 million, including working capital and other adjustments. We recognized a gain of $106 million on the divestiture of the pipeline and related storage and truck offload facilities, which is included in “(Gains)/losses on asset sales and asset impairments, net” on our Consolidated Statement of Operations, based on the difference between the fair value of the divested assets and their carrying value. Acquisitions In February 2020, we acquired Felix Midstream LLC, now known as FM Gathering LLC (“FM Gathering”) from Felix Energy Holdings II, LLC for approximately $300 million, net of working capital and other adjustments. FM Gathering 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 are included in our Crude Oil segment. This acquisition was accounted for using the acquisition method of accounting and the determination of the fair value of the assets acquired and liabilities assumed was determined in accordance with the applicable accounting guidance. The assets acquired primarily consisted of property and equipment of $115 million and intangible assets of $187 million. The fair value of the tangible assets is a Level 3 measurement in the fair value hierarchy and was determined using a cost approach. The cost approach was based on costs incurred on similar recent construction projects. The fair value of the intangible assets is also a Level 3 measurement in the fair value hierarchy and was determined by applying a discounted cash flow approach. Such approach utilized discount rates varying from 18% to 19%, based on our estimate of the risk that a theoretical market participant would assign to the respective intangible assets. 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. Divestitures In August 2021, we sold our Pine Prairie and Southern Pines natural gas storage facilities, which were included in our Crude Oil segment for periods prior to the sale, for net proceeds of approximately $850 million, including working capital adjustments. Prior to the sale, we classified the assets related to this transaction (primarily “Property and equipment”), valued at the lower of the carrying amount or fair value less costs to sell, of approximately $832 million as assets held for sale with approximately $18 million of deferred losses on hedges remaining in other comprehensive income until the closing of the sale. Upon classification of the assets to held for sale in the second quarter of 2021, we recognized a non-cash impairment loss of $475 million which is included in “(Gains)/losses on asset sales and asset impairments, net” on our Consolidated Statement of Operations. During the year ended December 31, 2020, we received cash proceeds of $451 million, primarily from the sale of: • certain Los Angeles Basin crude oil terminals previously included in our Crude Oil segment for proceeds of approximately $200 million, subject to certain adjustments; • certain NGL terminals previously included in our NGL segment for proceeds of approximately $163 million (including $22 million related to a multi-year supply agreement related to the sale), subject to certain adjustments; and • a 10% ownership interest in Saddlehorn Pipeline Company, LLC (“Saddlehorn”) for proceeds of approximately $78 million, including working capital adjustments (see Note 9 for additional information). We recognized a loss related to these assets sales of $178 million, including non-cash impairments recognized upon classification to assets held for sale, for the year ended December 31, 2020. Such amount is included in “(Gains)/losses on asset sales and asset impairments, net” on our Consolidated Statement of Operations. 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 is reflected in our Crude Oil segment for the period prior to the sale. 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. |
Goodwill
Goodwill | 12 Months Ended |
Dec. 31, 2021 | |
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 model. 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. During the first quarter of 2020, we recorded impairment losses of $2.515 billion related to goodwill. Our market capitalization declined significantly during the first quarter driven by macroeconomic and geopolitical conditions that occurred in 2020, including the collapse of oil prices driven by both the decrease in demand caused by the COVID-19 pandemic and excess supply, as well as changing market conditions and expected lower crude oil production in certain regions, that resulted in expected decreases in future cash flows for certain of our assets, which we concluded was a triggering event that required us to perform a quantitative impairment test as of March 31, 2020, utilizing a discounted cash flow approach. We applied a discount rate of approximately 14% in the determination of the fair value of each of our reporting units, which represents our estimate of the cost of capital of a theoretical market participant as of March 31, 2020. The fair values of the reporting units are Level 3 measurements in the fair value hierarchy and were based on various inputs, as discussed below. The discounted cash flows for each reporting unit were based on six years of projected cash flows and terminal values that we believe would be applied by a theoretical market participant in similar market transactions. The discounted cash flows for the respective reporting units utilized various other assumptions, including, but not limited to (i) volumes (based on historical information and estimates of future drilling and completion activity, as well as expectations of future demand recovery), (ii) tariff and storage rates, (iii) future commodity prices (based on relevant indices and applicable quality and location differentials), and (iv) estimated fixed and variable costs. We used a range of cash flows for the discounted cash flow calculations based on differing potential market scenarios, but for each of the reporting units, the ultimate outcome of the impairment test was unchanged by the various points within the range of cash flows. As a result of the impairment test, we concluded that the carrying value of each of our reporting units exceeded their respective fair values, resulting in a goodwill impairment charge for the entire goodwill balance for each reporting unit. Prior to the year ended December 31, 2020, we did not recognize any impairments of goodwill. Goodwill by segment and changes in goodwill is reflected in the following table (in millions): Crude Oil NGL Total Balance at December 31, 2019 $ 2,300 $ 240 $ 2,540 Acquisitions 2 — 2 Goodwill, gross $ 2,302 $ 240 $ 2,542 Impairments (2,287) (228) (2,515) Foreign currency translation adjustments (15) (12) (27) Accumulated impairment losses (2,302) (240) (2,542) Balance at December 31, 2020 $ — $ — $ — |
Investments in Unconsolidated E
Investments in Unconsolidated Entities | 12 Months Ended |
Dec. 31, 2021 | |
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 Interest at December 31, 2021 Investment Balance Entity (1) Type of Operation 2021 2020 BridgeTex Pipeline Company, LLC (“BridgeTex”) Crude Oil Pipeline 20% $ 406 $ 421 Cactus II Pipeline LLC (“Cactus II”) Crude Oil Pipeline 65% 737 752 Capline Pipeline Company LLC Crude Oil Pipeline (2) 54% 531 514 Diamond Pipeline LLC (“Diamond”) Crude Oil Pipeline 50% 464 480 Eagle Ford Pipeline LLC (“Eagle Ford Pipeline”) Crude Oil Pipeline 50% 363 372 Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Terminals”) Crude Oil Terminal and Dock 50% 120 122 OMOG JV LLC (3) Crude Oil Pipeline 40% 102 — Saddlehorn Crude Oil Pipeline 30% 209 208 White Cliffs Pipeline, LLC Crude Oil Pipeline 36% 171 192 Wink to Webster Pipeline LLC (“W2W Pipeline”) (4) Crude Oil Pipeline (5) 16% 345 330 Other investments 357 373 Total Investments in Unconsolidated Entities $ 3,805 $ 3,764 (1) The financial results from these entities are reported in our Crude Oil segment. (2) The Capline pipeline was out of service during 2020 and a majority of 2021 pending the reversal of the pipeline system. The pipeline reversal project was completed with interim service beginning in mid-December 2021 and full service beginning in January 2022. (3) Our ownership in this entity was acquired as part of the assets contributed by Oryx Midstream in the formation of the Permian JV in October 2021. See Note 7 for additional information. (4) Although we own less than 20% of W2W Pipeline, we use the equity method to account for the investment because we believe we have significant influence over the financial and operating decisions of the company. (5) The pipeline system was in partial service during 2021 and another phase of the pipeline construction project was completed in the first quarter of 2022. Impairments During the year ended December 31, 2020, we recognized losses as a result of the write-down of certain of our investments in unconsolidated entities, as discussed further below. Such amounts are reflected in “Gain on/(impairment of) investments in unconsolidated entities, net” on our Consolidated Statement of Operations. STACK. During the third quarter of 2020, we determined that there was an other-than-temporary impairment of our investment in STACK Pipeline LLC as a result of a continued decline of drilling activity and related volumes of crude oil in its area of operation. We recognized a loss of $91 million related to the write-down of the portion of the carrying amount of our investment that exceeded its fair value. The estimated fair value (which we consider a Level 3 measurement in the fair value hierarchy) was based on a discounted cash flow approach utilizing various assumptions and the application of a discount rate of approximately 14%, which represents our estimate of the cost of capital of a theoretical market participant. Such assumptions included (but were not limited to) (i) volumes (consistent with historical information and estimates of future drilling and completion activity), (ii) tariff rates, (iii) future commodity prices (based on relevant indices and applicable quality and location differentials), and (iv) estimated fixed and variable costs. Red Oak . In June 2019, we formed Red Oak Pipeline LLC (“Red Oak”), a joint venture with a subsidiary of Phillips 66 and in which we own a 50% interest, to develop a new crude oil pipeline project. In 2020, the partners of Red Oak determined that the project would not proceed as previously contemplated. We determined that there was an other-than-temporary impairment of our investment in Red Oak, and we recognized a loss of $69 million related to the write-down of our investment in Red Oak to the estimated residual value of our share of the net assets during the second quarter of 2020. Other investments. During the first quarter of 2020, we also recognized a loss of $43 million related to the write-down of certain of our investments included in “Other investments” in the table above due to an other-than-temporary impairment related to a decline in market conditions. Formations 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 Crude Oil 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/(impairment of) investment in unconsolidated entities, net” 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. Divestitures Saddlehorn. In February 2020, we sold a 10% ownership interest in Saddlehorn for proceeds of approximately $78 million and have retained a 30% ownership interest. We recorded a gain of approximately $21 million related to this sale, which is included in “Gain on/(impairment of) investments in unconsolidated entities, net” on our Consolidated Statement of Operations. We continue to account for our remaining interest 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 investment 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, 2021, 2020 and 2019, we made cash contributions of $82 million, $445 million and $504 million, respectively, to certain of our equity method investees. In addition, we capitalized interest of $12 million, $16 million and $20 million during the years ended December 31, 2021, 2020 and 2019, respectively, related to contributions to unconsolidated entities for projects under development and construction. Basis Differences Our investments in unconsolidated entities exceeded our share of the underlying equity in the net assets of such entities by $223 million and $170 million at December 31, 2021 and 2020, 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, 2021 and 2020 was attributable to goodwill related to our ownership interest in BridgeTex and Capline LLC with the remaining basis difference primarily related to capitalized interest incurred during construction of the assets of our unconsolidated entities. 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, 2021 2020 Current assets $ 509 $ 580 Noncurrent assets $ 8,879 $ 8,769 Current liabilities $ 366 $ 343 Noncurrent liabilities $ 15 $ 10 Year Ended December 31, 2021 2020 2019 Revenues $ 1,320 $ 1,360 $ 1,469 Operating income $ 505 $ 828 $ 994 Net income $ 506 $ 826 $ 995 |
Intangible Asset, Net
Intangible Asset, Net | 12 Months Ended |
Dec. 31, 2021 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Intangible Asset, Net | Intangible Assets, Net Intangible assets, net of accumulated amortization, consisted of the following (in millions): December 31, 2021 December 31, 2020 Estimated Useful Cost Accumulated Net Cost Accumulated Net Customer contracts and relationships (1) 3 – 31 $ 2,445 $ (510) $ 1,935 $ 1,291 $ (519) $ 772 Other agreements 1 – 70 36 (11) 25 63 (30) 33 Intangible assets (2) $ 2,481 $ (521) $ 1,960 $ 1,354 $ (549) $ 805 (1) The increase in intangible assets related to Customer contracts and relationships in 2021 is associated with the assets acquired in the formation of the Permian JV. See Note 7 for additional information. (2) 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, 2021. Amortization expense for finite-lived intangible assets for the years ended December 31, 2021, 2020 and 2019 was $122 million, $90 million and $76 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): 2022 $ 240 2023 $ 232 2024 $ 220 2025 $ 207 2026 $ 187 |
Debt
Debt | 12 Months Ended |
Dec. 31, 2021 | |
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 0.7% (1) $ — $ 547 Senior secured hedged inventory facility, bearing a weighted-average interest rate of 1.2% (1) — 167 Senior notes: 3.65% senior notes due June 2022 (2) 750 — Other 72 117 Total short-term debt 822 831 LONG-TERM DEBT Senior notes: 3.65% senior notes due June 2022 — 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 1,000 3.80% senior notes due September 2030 750 750 6.70% senior notes due May 2036 250 250 6.65% senior notes due January 2037 600 600 5.15% senior notes due June 2042 (3) 499 499 4.30% senior notes due January 2043 (3) 348 348 4.70% senior notes due June 2044 (3) 687 687 4.90% senior notes due February 2045 (3) 649 649 Unamortized discounts and debt issuance costs (54) (62) Senior notes, net of unamortized discounts and debt issuance costs 8,329 9,071 Other long-term debt: GO Zone term loans, net of debt issuance costs of $1, bearing a weighted-average interest rate of 1.3% (4) — 199 Other 69 112 Total long-term debt 8,398 9,382 Total debt (5) $ 9,220 $ 10,213 (1) We classified these commercial paper notes and credit facility borrowings as short-term as of December 31, 2020, 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) In January 2022, we provided notice of our intention to redeem these senior notes on March 1, 2022. (3) During the year ended December 31, 2020, we repurchased $17 million of our outstanding senior notes on the open market and recognized a gain of $3 million on these transactions, which is included in “Other income/(expense), net” on our Consolidated Statement of Operations. (4) The GO Zone term loans were initially assumed by one of our subsidiaries in connection with the acquisition of the Southern Pines natural gas storage facility. The loans were repaid in August 2021 in connection with the sale of that facility. See Note 7 for additional information. (5) Our fixed-rate senior notes had a face value of approximately $9.1 billion at both December 31, 2021 and 2020. We estimated the aggregate fair value of these notes to be approximately $9.9 billion at both December 31, 2021 and 2020. 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, 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 $2.7 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 . In August 2021, we entered into an amended credit agreement which replaced our $1.4 billion senior secured hedged inventory facility scheduled to mature in August 2022 with a $1.35 billion senior secured hedged inventory facility with an initial maturity date of August 2024. Subject to obtaining additional or increased lender commitments and other terms and conditions, the committed capacity of the facility may be increased to $1.9 billion. The amended credit agreement provides for the issuance of letters of credit of up to $400 million. 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 certain floating rate indices as defined in the credit agreement, in each case plus a margin based on our credit rating at the applicable time. The amended credit agreement also provides for one or more one-year extensions, subject to applicable approval and other terms and conditions. Senior unsecured revolving credit facility. In August 2021, we entered into a new unsecured credit agreement that provides for a senior unsecured revolving credit facility with a committed borrowing capacity of $1.35 billion, of which $400 million is available for the issuance of letters of credit. The new credit agreement replaced our previous credit agreement that provided for a $1.6 billion senior unsecured revolving credit facility and was scheduled to mature in August 2024. Subject to obtaining additional or increased lender commitments and other terms and conditions, the committed capacity may be increased to $2.1 billion. Borrowings accrue interest based, at our election, on certain floating rate indices as defined in the credit agreement, in each case plus a margin based on our credit rating at the applicable time. The new credit agreement has an initial maturity date of August 2026 and provides for one or more one-year extensions, subject to applicable approval and other terms and conditions. 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 accrued interest, based on certain floating rate indices, 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 GO Zone term loans were repaid in August 2021 in connection with the sale of the Southern Pines natural gas storage facility. See Note 7 for additional information. 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, 2021 (in millions): Year Description Maturity Face Value Interest Payment Dates 2020 3.80% Senior Notes issued at 99.794% of face value September 2030 $ 750 March 15 and September 15 2019 3.55% Senior Notes issued at 99.801% of face value December 2029 $ 1,000 June 15 and December 15 Senior Notes Repayments. During the three years ended December 31, 2021, we repaid the following senior unsecured notes in full (in millions): Year Description Repayment Date 2020 $600 million 5.00% Senior Notes due February 2021 November 2020 (1) 2019 $500 million 2.60% Senior Notes due December 2019 November 2019 (2) 2019 $500 million 5.75% Senior Notes due January 2020 December 2019 (2) (1) We repaid these senior notes with proceeds from our 3.80% senior notes issued in June 2020 and cash on hand. (2) We repaid these senior notes with proceeds from our 3.55% senior notes issued in September 2019 and cash on hand. Maturities The weighted average maturity of our senior notes outstanding at December 31, 2021 was approximately 10 years. The following table presents the aggregate contractually scheduled maturities of such senior notes for the next five years and thereafter. The amounts presented exclude unamortized discounts and debt issuance costs. Calendar Year Payment (in millions) 2022 $ 750 2023 $ 1,100 2024 $ 750 2025 $ 1,000 2026 $ 750 Thereafter $ 4,783 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 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 and senior secured hedged inventory facility treat a change of control as an event of default and also require us to maintain a debt-to-EBITDA coverage ratio that, on a trailing four-quarter basis, will not be greater than 5.00 to 1.00 (or 5.50 to 1.00 on all outstanding debt during an acquisition period (generally, the period consisting of three fiscal quarters following an acquisition greater than $150 million)). 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, 2021, 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, 2021, 2020 and 2019 were approximately $32.5 billion, $29.3 billion and $13.3 billion, respectively. Total repayments under our credit facilities and commercial paper program were approximately $33.2 billion, $29.0 billion and $12.9 billion for the years ended December 31, 2021, 2020 and 2019, 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 merchant activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil and NGL. 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 or NGL 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, 2021 and 2020, we had outstanding letters of credit of $98 million and $129 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, 2021 | |
Partners' Capital Notes [Abstract] | |
Partners' Capital and Distributions | Partners’ Capital and Distributions Units Outstanding At December 31, 2021, 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. 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, 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 Repurchase and cancellation of common units under the Common Equity Repurchase Program — — (6,222,748) Issuances of common units under equity-indexed compensation plans — — 574,588 Outstanding at December 31, 2020 71,090,468 800,000 722,380,416 Repurchase and cancellation of common units under the Common Equity Repurchase Program — — (18,061,583) Issuances of common units under equity-indexed compensation plans — — 672,707 Outstanding at December 31, 2021 71,090,468 800,000 704,991,540 Common Equity Repurchase Program. In November 2020, the board of directors of PAGP GP approved a $500 million common equity repurchase program (the “Program”) to be utilized as an additional method of returning capital to investors. The Program authorizes the repurchase from time to time of up to $500 million of our common units and/or PAGP Class A shares via open market purchases or negotiated transactions conducted in accordance with applicable regulatory requirements. No time limit has been set for completion of the Program, and the Program may be suspended or discontinued at any time. The Program does not obligate us or PAGP to acquire a particular number of common units or PAGP Class A shares. Any common units or PAGP Class A shares that are repurchased will be canceled. PAGP Class C shares held by us associated with any publicly held common units that are repurchased will also be canceled. See Note 17 for additional information regarding our ownership of PAGP Class C shares. We repurchased 18,061,583 and 6,222,748 common units under the Program through open market purchases that settled during the years ended December 31, 2021 and 2020, respectively. The total purchase price of these units was $178 million and $50 million, respectively, including commissions and fees. The repurchased common units were canceled immediately upon acquisition, as were the PAGP Class C shares held by us associated with the repurchased common units. At December 31, 2021, the remaining available capacity under the Program was $272 million. 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. Distributions to Unitholders 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 years presented (in millions, except unit data): Cash Distributions Year Series A Preferred Unitholders Series B Preferred Unitholders 2021 $ 149 $ 49 2020 $ 149 $ 49 2019 $ 149 $ 49 On February 14, 2022, we paid a cash distribution of $37 million to our Series A preferred unitholders. At December 31, 2021, such amount was accrued as distributions payable in “Other current liabilities” on our Consolidated Balance Sheet. At December 31, 2021, 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 years presented (in millions, except per unit data): Distributions Paid Distributions per common unit Year Public AAP Total 2021 $ 341 $ 176 $ 517 $ 0.72 2020 $ 432 $ 223 $ 655 $ 0.90 2019 $ 632 $ 372 $ 1,004 $ 1.38 On January 10, 2022, we declared a cash distribution of $0.18 per unit on our outstanding common units. The total distribution of $127 million was paid on February 14, 2022 to unitholders of record at the close of business on January 31, 2022, for the period from October 1, 2021 through December 31, 2021. Of this amount, approximately $43 million was paid to AAP. Noncontrolling Interests in Subsidiaries As of December 31, 2021, noncontrolling interests in our subsidiaries consisted of (i) a 35% interest in the Permian JV and (ii) a 33% interest in Red River Pipeline Company LLC (“Red River LLC”). The transactions resulting in the recognition of such noncontrolling interests are described below. In October 2021, we formed a joint venture, the Permian JV, with Oryx Midstream. We own 65% of the Permian JV and consolidate based on control, with Oryx Midstream’s 35% interest accounted for as a noncontrolling interest. This transaction resulted in the recognition of partners’ capital attributable to noncontrolling interests of approximately $2.7 billion and an increase to our partners’ capital excluding noncontrolling interests of approximately $605 million. See Note 7 for more details regarding this transaction. In May 2019, we formed a joint venture, 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. Noncontrolling Interest Contributions and Distributions During the years ended December 31, 2021 and 2020, we received contributions from noncontrolling interests in Red River LLC of $1 million and $12 million, respectively, related to the Red River pipeline capacity expansion. During the years ended December 31, 2021, 2020 and 2019, we paid distributions of $14 million, $10 million and $6 million, respectively, to noncontrolling interests in Red River LLC. |
Derivatives and Risk Management
Derivatives and Risk Management Activities | 12 Months Ended |
Dec. 31, 2021 | |
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. We use various derivative instruments to optimize our profits while managing our exposure to (i) commodity price risk, (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. Our policy is to use derivative instruments for risk management purposes and not for the purpose of speculating on changes in commodity prices, interest rates or currency exchange rates. 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. 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 in a hedging relationship for accounting purposes 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. 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. At December 31, 2021 and 2020, 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 exchange-traded derivatives transacted through a clearing brokerage account, as described below, we do not require our non-cleared derivative counterparties to post collateral with us. 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 material 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, 2021, net derivative positions related to these activities included: • A net long position of 8.4 million barrels associated with our crude oil purchases, which was unwound ratably during January 2022 to match monthly average pricing. • A net short time spread position of 5.7 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through December 2022. • A net crude oil basis spread position of 7.3 million barrels at multiple locations through December 2022. These derivatives allow us to lock in grade and location basis differentials. • A net short position of 19.2 million barrels through December 2023 related to anticipated net sales of crude oil and NGL inventory. 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, 2021. Notional Volume Remaining Tenor Natural gas purchases 73.4 Bcf December 2023 Propane sales (13.7) MMbls December 2023 Butane sales (3.3) MMbls December 2023 Condensate sales (1.5) MMbls December 2023 Fuel gas requirements (1) 7.5 Bcf December 2022 Power supply requirements (1) 0.6 TWh December 2023 (1) Positions to hedge a portion of our power supply and fuel gas 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. Our commodity derivatives are not designated in a hedging relationship for accounting purposes; as such, changes in the fair value are reported in earnings. The following table summarizes the impact of our commodity derivatives recognized in earnings (in millions): Year Ended December 31, 2021 2020 2019 Product sales revenues $ (710) $ (302) $ 310 Field operating costs 71 5 14 Net gain/(loss) from commodity derivative activity $ (639) $ (297) $ 324 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) (in millions): December 31, 2021 2020 Initial margin $ 133 $ 91 Variation margin posted/(returned) 173 290 Letters of credit (47) (63) Net broker receivable/(payable) $ 259 $ 318 The following table reflects the Consolidated Balance Sheet line items that include the fair values of our commodity derivative assets and liabilities and the effect of the collateral netting. Such amounts are presented on a gross basis, before the effects of counterparty netting. However, we have elected to present our commodity derivative assets and liabilities with the same counterparty on a net basis on our Consolidated Balance Sheet when the legal right of offset exists. Amounts in the table below are presented in millions. December 31, 2021 December 31, 2020 Effect of Collateral Netting Net Carrying Value Presented on the Balance Sheet Effect of Collateral Netting Net Carrying Value Presented on the Balance Sheet Commodity Derivatives Commodity Derivatives Assets Liabilities Assets Liabilities Derivative Assets Other current assets $ 90 $ (210) $ 259 $ 139 $ 71 $ (314) $ 318 $ 75 Other long-term assets, net 3 — — 3 5 — — 5 Derivative Liabilities Other current liabilities 4 (24) — (20) 9 (40) — (31) Other long-term liabilities and deferred credits 3 (9) — (6) — (32) — (32) Total $ 100 $ (243) $ 259 $ 116 $ 85 $ (386) $ 318 $ 17 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, 2021 (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 6/15/2023 1.38 % Cash flow hedge Anticipated interest payments 8 forward starting swaps (30-year) $ 200 6/14/2024 0.73 % Cash flow hedge As of December 31, 2021, there was a net loss of $208 million deferred in AOCI. The deferred net loss recorded in AOCI is expected to be reclassified to future earnings contemporaneously with interest expense accruals associated with underlying debt instruments. We estimate that substantially all of the remaining deferred loss will be reclassified to earnings through 2054 as the underlying hedged transactions impact earnings. A portion of these amounts is based on market prices as of December 31, 2021; 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, 2021 2020 2019 Interest rate derivatives, net $ 19 $ (10) $ (91) At December 31, 2021, the net fair value of our interest rate hedges, which were included in “Other long-term assets, net” on our Consolidated Balance Sheet, totaled $65 million. At December 31, 2020, the net fair value of these hedges totaled $46 million and was included in “Other long-term assets, net.” 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. This embedded derivative is not designated in a hedging relationship for accounting purposes and corresponding changes in fair value are recognized in “Other income/(expense), net” in our Consolidated Statement of Operations. For the years ended December 31, 2021, 2020 and 2019 we recognized net gains of $14 million, $20 million and $2 million, respectively. The fair value of the Preferred Distribution Rate Reset Option, which was included in “Other long-term liabilities and deferred credits” on our Consolidated Balance Sheets, totaled less than $1 million and $14 million at December 31, 2021 and 2020, respectively. See Note 12 for additional information regarding our Series A preferred units and the Preferred Distribution Rate Reset Option. 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, 2021 Fair Value as of December 31, 2020 Recurring Fair Value Measures (1) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Commodity derivatives $ (17) $ (124) $ (2) $ (143) $ (143) $ (143) $ (15) $ (301) Interest rate derivatives — 65 — 65 — 46 — 46 Preferred Distribution Rate Reset Option and Other — — — — — 2 (14) (12) Total net derivative asset/(liability) $ (17) $ (59) $ (2) $ (78) $ (143) $ (95) $ (29) $ (267) (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 Product sales 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. 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, 2021 2020 Beginning Balance $ (29) $ (51) Net gains/(losses) for the period included in earnings 15 12 Settlements 12 10 Ending Balance $ (2) $ (29) Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period $ 15 $ 12 |
Leases
Leases | 12 Months Ended |
Dec. 31, 2021 | |
Leases [Abstract] | |
Leases | Leases Lessee We evaluate all agreements entered into or modified that convey to us 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 we obtain the right to direct the use of identified property or equipment. 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. We have elected the non-lease component separation practical expedient for certain classes of assets where we are the lessee. Our lease agreements have remaining lease terms ranging from one year to approximately 59 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 25 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, including both amounts recognized in income and amounts capitalized (in millions): Year Ended December 31, Lease Cost 2021 2020 2019 Operating lease cost $ 96 $ 111 $ 125 Short-term lease cost 19 31 35 Other (1) (2) 14 8 — Total lease cost $ 129 $ 150 $ 160 (1) Includes finance lease costs, variable lease costs and sublease income. (2) Includes approximately $8 million and $6 million for the years ended December 31, 2021 and 2020, respectively, associated with leased storage tanks owned by an equity method investee, in which we own a 50% interest. The following table presents information related to cash flows arising from lease transactions (in millions): Year Ended December 31, 2021 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases $ 91 $ 108 $ 116 Operating cash flows for finance leases $ 7 $ 5 $ 1 Financing cash flows for finance leases $ 11 $ 19 $ 18 Non-cash change in lease liabilities arising from obtaining new right-of-use assets or modifications: Operating leases $ 94 $ 5 $ 77 Finance leases (1) $ 1 $ 32 $ 27 (1) Includes $25 million and $12 million for the years ended December 31, 2020 and 2019, respectively, 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: December 31, 2021 2020 Weighted-average remaining lease term (in years): Operating leases 11 12 Finance leases 9 9 Weighted-average discount rate: Operating leases 4.2 % 4.5 % Finance leases 11.6 % 11.1 % The following table presents the amount and location of our operating and finance lease right-of-use assets and liabilities on our Consolidated Balance Sheets (in millions): December 31, Leases Balance Sheet Location 2021 2020 Assets Operating lease right-of-use assets Long-term operating lease right-of-use assets, net $ 393 $ 378 Finance lease right-of-use assets (1) Property and equipment $ 136 $ 141 Accumulated depreciation (37) (27) Property and equipment, net $ 99 $ 114 Total lease right-of-use assets $ 492 $ 492 Liabilities Operating lease liabilities Current Other current liabilities $ 77 $ 78 Noncurrent Long-term operating lease liabilities 339 317 Total operating lease liabilities $ 416 $ 395 Finance lease liabilities (1) Current Short-term debt $ 12 $ 11 Noncurrent Other long-term debt, net 59 70 Total finance lease liabilities $ 71 $ 81 Total lease liabilities $ 487 $ 476 (1) Includes right-of-use assets of $33 million and $35 million and lease liabilities of $35 million and $36 million as of December 31, 2021 and 2020, respectively, 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, 2021 reconciled to our lease liabilities on our Consolidated Balance Sheet (amounts in millions): Operating Finance (2) Future minimum lease payments (1) : 2022 $ 92 $ 18 2023 75 15 2024 63 14 2025 50 12 2026 38 7 Thereafter 252 60 Total 570 126 Less: Present value discount (154) (55) Lease liabilities $ 416 $ 71 (1) Excludes future minimum payments for short-term and other immaterial leases not included on our Consolidated Balance Sheet. (2) Includes payments of approximately $6 million for each of the years ending 2022 through 2026 and approximately $58 million thereafter associated with leased storage tanks owned by an equity method investee, in which we own a 50% interest. Lessor We evaluate all agreements entered into or modified 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. We have elected the non-lease component separation practical expedient for all classes of assets where we are the lessor. We enter into agreements to conduct activities associated with (i) providing storage services primarily for crude oil and NGL 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. The following table presents our lease revenue for the periods indicated (in millions): Year Ended December 31, 2021 2020 2019 Operating lease revenue (1) $ 28 $ 19 $ 17 (1) These amounts are included in “Services revenues” on our Consolidated Statements of Operations. The table below presents the maturity of lease payments for operating lease agreements in effect as of December 31, 2021. 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 one year to 20 years. The following table presents the undiscounted cash flows expected to be received related to these agreements (in millions): 2022 2023 2024 2025 2026 Thereafter Future minimum lease revenue $ 29 $ 22 $ 20 $ 20 $ 20 $ 197 |
Leases | Leases Lessee We evaluate all agreements entered into or modified that convey to us 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 we obtain the right to direct the use of identified property or equipment. 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. We have elected the non-lease component separation practical expedient for certain classes of assets where we are the lessee. Our lease agreements have remaining lease terms ranging from one year to approximately 59 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 25 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, including both amounts recognized in income and amounts capitalized (in millions): Year Ended December 31, Lease Cost 2021 2020 2019 Operating lease cost $ 96 $ 111 $ 125 Short-term lease cost 19 31 35 Other (1) (2) 14 8 — Total lease cost $ 129 $ 150 $ 160 (1) Includes finance lease costs, variable lease costs and sublease income. (2) Includes approximately $8 million and $6 million for the years ended December 31, 2021 and 2020, respectively, associated with leased storage tanks owned by an equity method investee, in which we own a 50% interest. The following table presents information related to cash flows arising from lease transactions (in millions): Year Ended December 31, 2021 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases $ 91 $ 108 $ 116 Operating cash flows for finance leases $ 7 $ 5 $ 1 Financing cash flows for finance leases $ 11 $ 19 $ 18 Non-cash change in lease liabilities arising from obtaining new right-of-use assets or modifications: Operating leases $ 94 $ 5 $ 77 Finance leases (1) $ 1 $ 32 $ 27 (1) Includes $25 million and $12 million for the years ended December 31, 2020 and 2019, respectively, 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: December 31, 2021 2020 Weighted-average remaining lease term (in years): Operating leases 11 12 Finance leases 9 9 Weighted-average discount rate: Operating leases 4.2 % 4.5 % Finance leases 11.6 % 11.1 % The following table presents the amount and location of our operating and finance lease right-of-use assets and liabilities on our Consolidated Balance Sheets (in millions): December 31, Leases Balance Sheet Location 2021 2020 Assets Operating lease right-of-use assets Long-term operating lease right-of-use assets, net $ 393 $ 378 Finance lease right-of-use assets (1) Property and equipment $ 136 $ 141 Accumulated depreciation (37) (27) Property and equipment, net $ 99 $ 114 Total lease right-of-use assets $ 492 $ 492 Liabilities Operating lease liabilities Current Other current liabilities $ 77 $ 78 Noncurrent Long-term operating lease liabilities 339 317 Total operating lease liabilities $ 416 $ 395 Finance lease liabilities (1) Current Short-term debt $ 12 $ 11 Noncurrent Other long-term debt, net 59 70 Total finance lease liabilities $ 71 $ 81 Total lease liabilities $ 487 $ 476 (1) Includes right-of-use assets of $33 million and $35 million and lease liabilities of $35 million and $36 million as of December 31, 2021 and 2020, respectively, 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, 2021 reconciled to our lease liabilities on our Consolidated Balance Sheet (amounts in millions): Operating Finance (2) Future minimum lease payments (1) : 2022 $ 92 $ 18 2023 75 15 2024 63 14 2025 50 12 2026 38 7 Thereafter 252 60 Total 570 126 Less: Present value discount (154) (55) Lease liabilities $ 416 $ 71 (1) Excludes future minimum payments for short-term and other immaterial leases not included on our Consolidated Balance Sheet. (2) Includes payments of approximately $6 million for each of the years ending 2022 through 2026 and approximately $58 million thereafter associated with leased storage tanks owned by an equity method investee, in which we own a 50% interest. Lessor We evaluate all agreements entered into or modified 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. We have elected the non-lease component separation practical expedient for all classes of assets where we are the lessor. We enter into agreements to conduct activities associated with (i) providing storage services primarily for crude oil and NGL 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. The following table presents our lease revenue for the periods indicated (in millions): Year Ended December 31, 2021 2020 2019 Operating lease revenue (1) $ 28 $ 19 $ 17 (1) These amounts are included in “Services revenues” on our Consolidated Statements of Operations. The table below presents the maturity of lease payments for operating lease agreements in effect as of December 31, 2021. 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 one year to 20 years. The following table presents the undiscounted cash flows expected to be received related to these agreements (in millions): 2022 2023 2024 2025 2026 Thereafter Future minimum lease revenue $ 29 $ 22 $ 20 $ 20 $ 20 $ 197 |
Leases | Leases Lessee We evaluate all agreements entered into or modified that convey to us 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 we obtain the right to direct the use of identified property or equipment. 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. We have elected the non-lease component separation practical expedient for certain classes of assets where we are the lessee. Our lease agreements have remaining lease terms ranging from one year to approximately 59 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 25 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, including both amounts recognized in income and amounts capitalized (in millions): Year Ended December 31, Lease Cost 2021 2020 2019 Operating lease cost $ 96 $ 111 $ 125 Short-term lease cost 19 31 35 Other (1) (2) 14 8 — Total lease cost $ 129 $ 150 $ 160 (1) Includes finance lease costs, variable lease costs and sublease income. (2) Includes approximately $8 million and $6 million for the years ended December 31, 2021 and 2020, respectively, associated with leased storage tanks owned by an equity method investee, in which we own a 50% interest. The following table presents information related to cash flows arising from lease transactions (in millions): Year Ended December 31, 2021 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases $ 91 $ 108 $ 116 Operating cash flows for finance leases $ 7 $ 5 $ 1 Financing cash flows for finance leases $ 11 $ 19 $ 18 Non-cash change in lease liabilities arising from obtaining new right-of-use assets or modifications: Operating leases $ 94 $ 5 $ 77 Finance leases (1) $ 1 $ 32 $ 27 (1) Includes $25 million and $12 million for the years ended December 31, 2020 and 2019, respectively, 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: December 31, 2021 2020 Weighted-average remaining lease term (in years): Operating leases 11 12 Finance leases 9 9 Weighted-average discount rate: Operating leases 4.2 % 4.5 % Finance leases 11.6 % 11.1 % The following table presents the amount and location of our operating and finance lease right-of-use assets and liabilities on our Consolidated Balance Sheets (in millions): December 31, Leases Balance Sheet Location 2021 2020 Assets Operating lease right-of-use assets Long-term operating lease right-of-use assets, net $ 393 $ 378 Finance lease right-of-use assets (1) Property and equipment $ 136 $ 141 Accumulated depreciation (37) (27) Property and equipment, net $ 99 $ 114 Total lease right-of-use assets $ 492 $ 492 Liabilities Operating lease liabilities Current Other current liabilities $ 77 $ 78 Noncurrent Long-term operating lease liabilities 339 317 Total operating lease liabilities $ 416 $ 395 Finance lease liabilities (1) Current Short-term debt $ 12 $ 11 Noncurrent Other long-term debt, net 59 70 Total finance lease liabilities $ 71 $ 81 Total lease liabilities $ 487 $ 476 (1) Includes right-of-use assets of $33 million and $35 million and lease liabilities of $35 million and $36 million as of December 31, 2021 and 2020, respectively, 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, 2021 reconciled to our lease liabilities on our Consolidated Balance Sheet (amounts in millions): Operating Finance (2) Future minimum lease payments (1) : 2022 $ 92 $ 18 2023 75 15 2024 63 14 2025 50 12 2026 38 7 Thereafter 252 60 Total 570 126 Less: Present value discount (154) (55) Lease liabilities $ 416 $ 71 (1) Excludes future minimum payments for short-term and other immaterial leases not included on our Consolidated Balance Sheet. (2) Includes payments of approximately $6 million for each of the years ending 2022 through 2026 and approximately $58 million thereafter associated with leased storage tanks owned by an equity method investee, in which we own a 50% interest. Lessor We evaluate all agreements entered into or modified 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. We have elected the non-lease component separation practical expedient for all classes of assets where we are the lessor. We enter into agreements to conduct activities associated with (i) providing storage services primarily for crude oil and NGL 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. The following table presents our lease revenue for the periods indicated (in millions): Year Ended December 31, 2021 2020 2019 Operating lease revenue (1) $ 28 $ 19 $ 17 (1) These amounts are included in “Services revenues” on our Consolidated Statements of Operations. The table below presents the maturity of lease payments for operating lease agreements in effect as of December 31, 2021. 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 one year to 20 years. The following table presents the undiscounted cash flows expected to be received related to these agreements (in millions): 2022 2023 2024 2025 2026 Thereafter Future minimum lease revenue $ 29 $ 22 $ 20 $ 20 $ 20 $ 197 |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2021 | |
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, 2021 and 2020, 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, 2021, 2020, and 2019 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, 2021 2020 2019 Current income tax expense: State income tax $ 2 $ — $ 3 Canadian federal and provincial income tax 48 51 109 Total current income tax expense $ 50 $ 51 $ 112 Deferred income tax expense/(benefit): Canadian federal and provincial income tax $ 23 $ (70) $ (46) Total deferred income tax expense/(benefit) $ 23 $ (70) $ (46) Total income tax expense/(benefit) $ 73 $ (19) $ 66 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, 2021 2020 2019 Income/(loss) before tax $ 721 $ (2,599) $ 2,246 Partnership (earnings)/loss not subject to current Canadian tax (370) 2,221 (1,769) $ 351 $ (378) $ 477 Canadian federal and provincial corporate tax rate 24% 24% 26% Income tax expense/(benefit) at statutory rate $ 84 $ (91) $ 124 Canadian permanent differences and rate changes $ (13) $ 72 $ (61) State income tax 2 — 3 Total income tax expense/(benefit) $ 73 $ (19) $ 66 The Canadian permanent differences and rate changes for the year ended December 31, 2020 primarily related to an impairment of goodwill that was recognized during the year. A portion of the goodwill that was impaired had no basis for Canadian income tax purposes and thus was not a deductible expense in determining taxable income, resulting in a permanent difference for Canadian tax purposes. See Note 8 for additional information regarding this impairment. 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. In the fourth quarter of 2020, the Alberta government changed the timing of the rate reduction to decrease the corporate income tax rate to 8% starting July 1, 2020. Deferred tax assets and liabilities are aggregated by the applicable tax paying entity and jurisdiction and result from the following (in millions): December 31, 2021 2020 Deferred tax assets: Derivative instruments $ 39 $ 45 Lease liabilities 48 39 Net operating losses 2 2 Other 17 16 Total deferred tax assets 106 102 Deferred tax liabilities: Property and equipment in excess of tax values (531) (475) Lease assets (47) (38) Other (3) (3) Total deferred tax liabilities (581) (516) Net deferred tax liabilities $ (475) $ (414) Balance sheet classification of deferred tax assets/(liabilities): Other long-term assets, net $ 2 $ 2 Other long-term liabilities and deferred credits (477) (416) $ (475) $ (414) As of December 31, 2021, 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 2017 through 2021. Our U.S. and state tax years are generally open to examination from 2018 to 2021. As of December 31, 2021, in reference to tax years 2008 to 2016, we had 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 $120 million (based on the exchange rate as of December 31, 2021). 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 $101 million (based on the exchange rate as of December 31, 2021) 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, 2021, 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. |
Major Customers and Concentrati
Major Customers and Concentration of Credit Risk | 12 Months Ended |
Dec. 31, 2021 | |
Risks and Uncertainties [Abstract] | |
Major Customers and Concentration of Credit Risk | Major Customers and Concentration of Credit Risk ExxonMobil Corporation and its subsidiaries accounted for 15%, 12% and 12% of our revenues for the years ended December 31, 2021, 2020 and 2019, respectively. Marathon Petroleum Corporation and its subsidiaries accounted for 12%, 13% and 12% of our revenues for the years ended December 31, 2021, 2020 and 2019, respectively. BP p.l.c. and its subsidiaries accounted for 10% of our revenues for the year ended December 31, 2021. Phillips 66 Company and its subsidiaries accounted for 11% of our revenues for the year ended December 31, 2019. No other customers accounted for 10% or more of our revenues during any of the three years ended December 31, 2021. The majority of revenues from these customers pertain to our Crude Oil segment merchant activities, and sales to these customers occur at multiple locations. If we were to lose one or more of these customers, there is risk that we would not be able to identify and access a replacement market at a comparable margin. 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, 2021 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Related Party Transactions Ownership of PAGP Class C Shares As of December 31, 2021 and 2020, we owned 534,596,831 and 547,717,762, respectively, Class C shares of PAGP. Each Class C share represents a non-economic limited partner interest in PAGP. The number of Class C shares that we own is equal to the number of outstanding common units and Series A preferred units that are entitled to vote, pro rata with the holders of PAGP Class A and Class B shares, for the election of eligible PAGP GP directors. The Class C shares function as a “pass-through” voting mechanism through which we vote at the direction of and as proxy for our common unitholders and Series A preferred unitholders in such director elections. Common units held by AAP and Series B preferred units are not entitled to vote in the election of 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, 2021, 2020 and 2019 were $467 million, $553 million and $580 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 $5 million, $5 million and $4 million during the years ended December 31, 2021, 2020 and 2019, respectively; • the ability of PAGP to issue additional Class A shares and use the net proceeds therefrom to purchase a like number of AAP units from AAP, and the corresponding ability of AAP to use the net proceeds therefrom to purchase a like number of our common units from us; and • the ability of PAGP to lend proceeds of any future indebtedness incurred by it to AAP, and AAP’s corresponding ability to lend such proceeds to us, in each case on substantially the same terms as incurred by PAGP. 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 translate 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, 2021, no entities met the criteria to be recognized as 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. Additionally, as a result of various transactions by Occidental Petroleum Corporation or its subsidiaries (“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. Following these transactions, we no longer recognize EMG or Oxy as a principal owner. In August 2021, the board of directors of PAGP GP approved and adopted an amendment to PAGP GP’s limited liability company agreement (the “Amendment”) which eliminated all previously negotiated “director designation” rights and requires that all directors be subject to public election, including Kayne Anderson Capital Advisors, L.P.’s (“Kayne Anderson”) legacy contractual right to designate an individual to serve on the PAGP GP board without being subject to public election. The Amendment also eliminated all previously negotiated rights, including Kayne Anderson’s right, to appoint a PAGP GP board observer under certain circumstances. As a result of these changes, we no longer recognize Kayne Anderson and its affiliates as related parties. During the three years ended December 31, 2021, we recognized sales and transportation revenues, purchased petroleum products and utilized transportation and storage services from our related parties. These transactions were conducted at posted tariff rates or prices that we believe approximate market. The impact to our Consolidated Statements of Operations from these transactions is included below (in millions): Year Ended December 31, 2021 2020 2019 Revenues from related parties (1) $ 33 $ 46 $ 692 Purchases and related costs from related parties (1) $ 385 $ 451 $ 223 (1) 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, 2021 2020 Trade accounts receivable and other receivables, net from related parties (1) $ 41 $ 34 Trade accounts payable to related parties (1) (2) $ 72 $ 88 (1) Includes amounts related to crude oil purchases and sales, transportation and storage services and amounts owed to us or advanced to us related to investment capital projects of equity method investees where we serve as construction manager. (2) We have agreements to store crude oil at facilities and transport crude oil or utilize capacity on pipelines that are owned by equity method investees. A portion of our commitment to transport is supported by crude oil buy/sell or other agreements with third parties with commensurate quantities. |
Equity-Indexed Compensation Pla
Equity-Indexed Compensation Plans | 12 Months Ended |
Dec. 31, 2021 | |
Share-based Payment Arrangement [Abstract] | |
Equity-Indexed Compensation Plans | Equity-Indexed Compensation Plans Our equity-indexed compensation plans primarily include LTIPs. 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. Plains All American 2021 Long-Term Incentive Plan. In May 2021, PAA unitholders approved the Plains All American 2021 Long-Term Incentive Plan, which amends, restates, and renames the Plains All American 2013 Long-Term Incentive Plan and authorizes an incremental 20 million PAA common units deliverable upon vesting of awards granted under the plan. 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 for equity-classified awards is calculated in a similar manner on the respective grant dates. These fair values are 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, (iii) market conditions or (iv) a combination of time-based vesting criteria and performance conditions. 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 have been if we had been accruing for these awards since the grant date. For awards with market conditions, the probable outcomes are determined on the respective dates that the fair values are calculated, and the resulting expense is accrued over the service period. The following is a summary of the awards authorized under our LTIPs as of December 31, 2021 (in millions): LTIP LTIP Plains All American 2021 Long-Term Incentive Plan 28.8 Plains All American PNG Successor Long-Term Incentive Plan 1.3 Plains All American GP LLC 2006 Long-Term Incentive Tracking Unit Plan 13.4 Total (1) 43.5 (1) Of the 43.5 million total awards authorized, 22.7 million awards are currently available. The remaining balance has already vested or is currently outstanding. As of December 31, 2021, 10.7 million LTIP awards were outstanding. Of the awards outstanding, 7.6 million include associated DERs. At December 31, 2021, certain of the outstanding LTIP awards were considered probable of vesting and such awards are expected to vest at various dates between January 2022 and August 2026. As of December 31, 2021, the outstanding awards that are considered probable of vesting have a remaining unrecognized fair value of approximately $44 million. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2021 | |
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, 2021 are summarized below (in millions): 2022 2023 2024 2025 2026 Thereafter Total Leases (1) $ 110 $ 90 $ 77 $ 62 $ 45 $ 312 $ 696 Other commitments (2) 327 307 298 282 211 624 2,049 Total $ 437 $ 397 $ 375 $ 344 $ 256 $ 936 $ 2,745 (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 storage, transportation and pipeline throughput agreements, as well as certain rights-of-way easements. Expense associated with our storage, transportation and pipeline throughput agreements was approximately $270 million, $265 million and $236 million for 2021, 2020 and 2019, respectively. A majority of the storage, transportation and pipeline throughput commitments are associated with agreements to store crude oil at facilities and transport crude oil on pipelines owned by equity method investees, in which we own a 50% interest, at posted tariff rates or prices that we believe approximate market. A portion of our commitment to transport is supported by crude oil buy/sell or other agreements with third parties with commensurate quantities. Loss Contingencies — General To the extent we are able to assess the likelihood of a negative outcome for a contingency, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue an undiscounted liability equal to the estimated amount. If a range of probable loss amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then we accrue an undiscounted liability equal to the minimum amount in the range. In addition, we estimate legal fees that we expect to incur associated with loss contingencies and accrue those costs when they are material and probable of being incurred. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss. Legal Proceedings — General In the ordinary course of business, we are involved in various legal proceedings, including those arising from regulatory and environmental matters. In connection with determining the probability of loss associated with such legal proceedings and whether any potential losses associated therewith are estimable, we take into account what we believe to be all relevant known facts and circumstances, and what we believe to be reasonable assumptions regarding the application of those facts and circumstances to existing agreements, laws and regulations. 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. Accordingly, we can provide no assurance that the outcome of the various legal proceedings that we are currently involved in, or will become involved with in the future, will not, individually or in the aggregate, have a material adverse effect on our consolidated financial condition, results of operations or cash flows. Environmental — General 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). Assets we have acquired or will acquire in the future may have environmental remediation liabilities for which we are not indemnified. Although 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. We also may discover environmental impacts from past releases that were previously unidentified. 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 we believe are 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, 2021, our estimated undiscounted reserve for environmental liabilities (excluding liabilities related to the Line 901 incident, as discussed further below) totaled $57 million, of which $11 million was classified as short-term and $46 million was classified as long-term. At December 31, 2020, our estimated undiscounted reserve for environmental liabilities (excluding liabilities related to the Line 901 incident) totaled $55 million, of which $8 million was classified as short-term and $47 million was classified as long-term. Such short-term liabilities are reflected in “Other current liabilities” and long-term liabilities are reflected in “Other long-term liabilities and deferred credits” on our Consolidated Balance Sheets. At December 31, 2021 and 2020, we had recorded receivables (excluding receivables related to the Line 901 incident) totaling $11 million and $6 million, respectively, for amounts probable of recovery under insurance and from third parties under indemnification agreements, $1 million of which for each period is reflected in “Other long-term assets, net” and the remainder is reflected in “Trade accounts receivable and other receivables, net” 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, and as set forth in the Consent Decree described below, 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, the majority of which have been resolved. Set forth below is a brief summary of actions and matters that are currently pending or recently resolved: 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 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”). Additionally, various government agencies sought to collect civil fines and penalties under applicable state and federal regulations. On March 13, 2020, the United States and the People of the State of California filed a civil complaint against Plains All American Pipeline, L.P. and Plains Pipeline L.P. along with a pre-negotiated settlement agreement in the form of a Consent Decree (the “Consent Decree”) that was signed by the United States Department of Justice, Environmental and Natural Resources Division, the United States Department of Transportation, Pipeline and Hazardous Materials Safety Administration, the EPA, CDFW, the California Department of Parks and Recreation, the California State Lands Commission, the California Department of Forestry and Fire Protection’s Office of the State Fire Marshal, Central Coast Regional Water Quality Control Board, and Regents of the University of California. The Consent Decree was approved and entered by the Federal District Court for the Central District of California on October 14, 2020. Pursuant to the terms of the Consent Decree, Plains paid $24 million in civil penalties and $22.325 million as compensation for injuries to, destruction of, loss of, or loss of use of natural resources resulting from the Line 901 incident. The Consent Decree also contains requirements for implementing certain agreed-upon injunctive relief, as well as requirements for potentially restarting Line 901 and the Sisquoc to Pentland portion of Line 903. The Consent Decree resolved all regulatory claims related to the incident. Following an investigation and grand jury proceedings, in May of 2016, PAA was 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. Fifteen charges from the May 2016 Indictment were the subject of a jury trial in California Superior Court in Santa Barbara County, and 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 remaining counts were subsequently dismissed by the Court. 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. In September 2021, the Superior Court concluded a series of hearings on the issue of whether there were any “direct victims” of the spill that are entitled to restitution under applicable criminal law. Through a series of final orders issued at the trial court level and without affecting any rights of the claimants under civil law, the Court dismissed the vast majority of the claims and ruled that the claimants were not entitled to restitution under applicable criminal laws. The Court did award an aggregate amount of less than $150,000 to a handful of claimants and we settled with approximately 40 claimants before the hearings for aggregate consideration that is not material. The prosecution has appealed the Court’s rulings. 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 received a number of claims through the claims line and we have processed those claims and made payments as appropriate. Nine class action lawsuits were filed against us; however, after various claims were either dismissed or consolidated, two proceedings remain pending in the United States District Court for the Central District of California. In the first proceeding, the plaintiffs claim two different classes of claimants were damaged by the release: (i) commercial fishermen who landed fish in certain specified fishing blocks in the waters off the coast of Southern California or persons or businesses who resold commercial seafood caught in those areas; and (ii) owners and lessees of residential beachfront properties, or properties with a private easement to a beach, where plaintiffs claim oil from the spill washed up. We are vigorously defending against those claims. This case is set for trial to begin in June of 2022. In the second proceeding, the plaintiffs seek a declaratory judgment that Plains’ right-of-way agreements would not allow Plains to lay a new pipeline to replace Line 901 and/or the non-operating segment of Line 903 without paying additional compensation. No trial date has been set in that action. In addition, four unitholder derivative lawsuits were filed by certain purported investors in the Partnership against PAGP and certain of the Partnership’s affiliates, officers and directors. After various claims were either dismissed or consolidated, one proceeding against PAGP remains pending in Delaware Chancery Court. Generally, the plaintiffs claim that PAGP failed to exercise proper oversight over the Partnership’s pipeline integrity efforts. We will continue to vigorously defend against the claim. No trial date has been set in this action. We have also received several other individual lawsuits and claims from companies, governmental agencies and individuals alleging damages arising out of the Line 901 incident. These lawsuits and claims generally seek restitution, compensatory and punitive damages, and/or injunctive relief. The majority of these lawsuits have been settled or dismissed by the court. Remaining claims include claims for lost revenue or profit asserted by a former oil producer that declared bankruptcy and shut in its offshore production platform following the Line 901 incident, a state agency that received royalties on oil produced from that platform until it was abandoned by its owner, and various companies and individuals who provided labor, goods, or services associated with oil production activities they claim were disrupted following the Line 901 incident. We are vigorously defending these suits. We may be subject to additional claims and lawsuits, which could materially impact the liabilities and costs we currently expect to incur as a result of the Line 901 incident. Taking the foregoing into account, as of December 31, 2021, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $495 million, which includes actual and projected emergency response and clean-up costs, natural resource damage assessments, fines and penalties payable pursuant to the Consent Decree and certain third-party claims settlements, as well as estimates for 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 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 and (ii) 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, with respect to potential losses that we regard as only reasonably possible or remote, we have made assumptions regarding the strength of our legal position based on our assessment of the relevant facts and applicable law and precedent; if our assumptions regarding such matters turn out to be inaccurate (i.e., we are found to be liable under circumstances where we regard the likelihood of loss as being only reasonably possible or remote), we could be responsible for significant costs and expenses that are not currently included in our estimates and accruals. In addition, for any potential losses that we regard as probable and for which we have accrued an estimate of the potential losses, our estimates regarding damages, legal fees, court costs and interest could turn out to be inaccurate and the actual losses we incur could be significantly higher than the amounts included in our estimates and accruals. Also, the amount of time it takes for us to resolve all of the current and future lawsuits and claims 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. 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, 2021, we had a remaining undiscounted gross liability of $103 million related to this event, which is reflected in “Trade accounts payable” and “Other current liabilities” on our Consolidated Balance Sheet. 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, 2021, we had collected, subject to customary reservations, $250 million out of the approximate $355 million of release costs that we believe are probable of recovery from insurance carriers, net of deductibles. Therefore, as of December 31, 2021, we have recognized a receivable of approximately $105 million for the portion of the release costs that we believe is probable of recovery from insurance, net of deductibles and amounts already collected. Such amount is recognized as a current asset in “Trade accounts receivable and other receivables, net” on our Consolidated Balance Sheet. 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 legal, professional and regulatory costs during future periods. 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. 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. 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 have established adequate reserves and liquidity to the extent such risks are not insured, costs incurred in excess of these reserves may be higher or we may not receive insurance proceeds in a timely manner, which may potentially have a material adverse effect on our financial conditions, results of operations or cash flows. |
Segment Information
Segment Information | 12 Months Ended |
Dec. 31, 2021 | |
Segment Reporting [Abstract] | |
Segment Information | Segment Information During the fourth quarter of 2021, we effected changes in the primary financial information provided to our CODM (our Chief Executive Officer) for assessing performance and allocating resources to present two operating segments, Crude Oil and NGL. Prior to the fourth quarter of 2021, this information was organized into three operating segments: Transportation, Facilities and Supply and Logistics. The change in our segments is reflective of a change in how our CODM views our business and stems primarily from (i) a multi-year transition in the midstream energy industry driven by increased competition that has reduced the stand alone earnings opportunities of our supply and logistics activities such that those activities now primarily support our effort to increase the utilization of our Crude Oil and NGL assets and (ii) internal changes regarding the oversight and reporting of our assets and related results of operations. All segment data and related disclosures for earlier periods presented herein have been recast to reflect the new segment reporting structure. Our operating segments, which are also our reportable segments, are organized by product as our Crude Oil and NGL businesses are generally impacted by different market fundamentals and require the use of different assets and business strategies. The Crude Oil segment includes our crude oil pipelines, crude oil storage and marine terminals and related crude oil marketing activities. The NGL segment includes our NGL pipelines, NGL storage, natural gas processing and NGL fractionation facilities and related NGL marketing activities. In our historical segment reporting, our marketing activities were presented separately from our other operating activities. Our crude oil and NGL marketing activities are now included in the respective reporting segments as their primary purpose is to support the utilization of our assets by entering into transactions that facilitate increased volumes handled by our assets, resulting in additional earnings for each of our segments. Our CODM evaluates segment performance based on measures including Segment Adjusted EBITDA (as defined below) and maintenance capital. 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 (d) our proportionate share of the depreciation and amortization expense of unconsolidated entities, further adjusted (e) 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 and (f) to exclude the portion of all preceding items that is attributable to noncontrolling interests (“Adjusted EBITDA attributable to noncontrolling interests”). During the fourth quarter of 2021, we modified our definition of Segment Adjusted EBITDA to exclude amounts attributable to noncontrolling interests. In connection with the Permian JV formation in October 2021, our CODM determined this modification resulted in amounts that were more meaningful to evaluate segment performance. Amounts attributable to noncontrolling interests for periods prior have been recast to reflect this modification. 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 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 investment 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. Assets are not reviewed by our CODM on a segmented basis; therefore, such information is not presented. The following tables reflect certain financial data for each segment (in millions): Crude Oil NGL Intersegment Revenues Total Year Ended December 31, 2021 Revenues (1) : Product sales $ 39,395 $ 1,829 $ (341) $ 40,883 Services 1,075 139 (19) 1,195 Total revenues $ 40,470 $ 1,968 $ (360) $ 42,078 Equity earnings in unconsolidated entities $ 274 $ — $ 274 Segment Adjusted EBITDA $ 1,909 $ 285 $ 2,194 Investment and acquisition capital expenditures (2) (3) $ 212 $ 57 $ 269 Maintenance capital expenditures (3) $ 100 $ 68 $ 168 As of December 31, 2021 Investments in unconsolidated entities $ 3,805 $ — $ 3,805 Crude Oil NGL Intersegment Revenues Total Year Ended December 31, 2020 Revenues (1) : Product sales $ 21,089 $ 1,218 $ (249) $ 22,058 Services 1,110 142 (20) 1,232 Total revenues $ 22,199 $ 1,360 $ (269) $ 23,290 Equity earnings in unconsolidated entities $ 355 $ — $ 355 Segment Adjusted EBITDA $ 2,216 $ 327 $ 2,543 Investment and acquisition capital expenditures (2) (3) $ 1,182 $ 49 $ 1,231 Maintenance capital expenditures (3) $ 171 $ 45 $ 216 As of December 31, 2020 Investments in unconsolidated entities $ 3,764 $ — $ 3,764 Crude Oil NGL Intersegment Revenues Total Year Ended December 31, 2019 Revenues (1) : Product sales $ 30,375 $ 2,302 $ (405) $ 32,272 Services 1,280 137 (20) 1,397 Total revenues $ 31,655 $ 2,439 $ (425) $ 33,669 Equity earnings in unconsolidated entities $ 388 $ — $ 388 Segment Adjusted EBITDA $ 2,753 $ 467 $ 3,220 Investment and acquisition capital expenditures (2) (3) $ 1,332 $ 58 $ 1,390 Maintenance capital expenditures (3) $ 248 $ 39 $ 287 As of December 31, 2019 Investments in unconsolidated entities $ 3,683 $ — $ 3,683 (1) Segment revenues include intersegment amounts that are eliminated in Purchases and related costs. 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. (2) Investment and acquisition capital expenditures, including investments in unconsolidated entities. (3) These amounts combined represent total capital expenditures. Segment Adjusted EBITDA Reconciliation The following table reconciles Segment Adjusted EBITDA to Net income/(loss) attributable to PAA (in millions): Year Ended December 31, 2021 2020 2019 Segment Adjusted EBITDA $ 2,194 $ 2,543 $ 3,220 Adjustments (1) : Depreciation and amortization of unconsolidated entities (2) (123) (73) (62) Gains/(losses) from derivative activities and inventory valuation adjustments (3) 271 (480) (160) Long-term inventory costing adjustments (4) 94 (44) 20 Deficiencies under minimum volume commitments, net (5) 7 (74) 18 Equity-indexed compensation expense (6) (19) (19) (17) Net gain/(loss) on foreign currency revaluation (7) 4 3 (14) Line 901 incident (8) (15) — (10) Significant transaction-related expenses (9) (16) (3) — Adjusted EBITDA attributable to noncontrolling interests (10) 94 14 10 Depreciation and amortization (774) (653) (601) Gains/(losses) on asset sales and asset impairments, net (592) (719) (28) Goodwill impairment losses — (2,515) — Gain on/(impairment of) investments in unconsolidated entities, net 2 (182) 271 Interest expense, net (425) (436) (425) Other income, net 19 39 24 Income/(loss) before tax 721 (2,599) 2,246 Income tax (expense)/benefit (73) 19 (66) Net income/(loss) 648 (2,580) 2,180 Net income attributable to noncontrolling interests (55) (10) (9) Net income/(loss) attributable to PAA $ 593 $ (2,590) $ 2,171 (1) Represents adjustments utilized by our CODM in the evaluation of segment results. (2) Includes our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects) of 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 differences in the timing of earnings from the derivative instruments and the underlying transactions and exclude the related gains and losses in determining Segment Adjusted EBITDA such that the earnings from the derivative instruments and the underlying transactions impact Segment Adjusted EBITDA in the same period. 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 write-downs of such inventory that result from price declines from Segment Adjusted EBITDA. (5) We, and certain of our equity method investments, 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) Our total equity-indexed compensation expense includes expense associated with awards that will be settled in units and awards that will be settled in cash. The awards that will be settled in units are included in our diluted net income per unit calculation when the applicable performance criteria have been met. We exclude compensation expense associated with these awards in determining Segment Adjusted EBITDA as the dilutive impact of the outstanding awards is included in our diluted net income per unit calculation, as applicable. The portion of compensation expense associated with awards that will settle in cash is not excluded in determining Segment Adjusted EBITDA. See Note 18 for information regarding our equity-indexed compensation plans. (7) During the periods presented, there were fluctuations in the value of CAD to USD, resulting in the realization of foreign exchange gains and losses on the settlement of foreign currency transactions as well as the revaluation of monetary assets and liabilities denominated in a foreign currency. These gains and losses are not integral to our core operating performance and were therefore excluded in determining Segment Adjusted EBITDA. (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 expenses associated with the Permian JV transaction in 2021 and the Felix Midstream LLC acquisition in 2020. See Note 7 for additional discussion. An adjustment for these non-recurring expenses is included in the calculation of Segment Adjusted EBITDA for the years ended December 31, 2021 and 2020 as our CODM does not view such expenses as integral to understanding our core segment operating performance. (10) Reflects amounts attributable to noncontrolling interests in the Permian JV (beginning October 2021) and Red River LLC. 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) 2021 2020 2019 United States $ 34,458 $ 17,942 $ 27,162 Canada 7,620 5,348 6,507 $ 42,078 $ 23,290 $ 33,669 (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) 2021 2020 United States $ 18,273 $ 16,887 Canada 4,094 3,892 $ 22,367 $ 20,779 (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, 2021 | |
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, 2021 and 2020, 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, 2021, 2020 and 2019. 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, as discussed further below. 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) fair value of derivatives, (iii) accruals and contingent liabilities, (iv) property and equipment, depreciation and amortization expense and asset retirement obligations, (v) impairment assessments of property and equipment, investments in unconsolidated entities and intangible assets and (vi) 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 and NGL sold to customers, (ii) fees incurred for storage and transportation, whether by pipeline, truck or rail 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, 2021 and 2020, trade accounts payable included $19 million and $27 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 our pipelines, certain processing and fractionation facilities and terminals assets, 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, storage or other 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 estimate 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 October 2021, the FASB issued ASU 2021-08, Business Combinations (Topic 805): Accounting for Contract Assets and Contract Liabilities from Contracts with Customers . This guidance requires that an acquirer recognize and measure contract assets and contract liabilities acquired in a business combination in accordance with Topic 606, Revenue from Contracts with Customers, as if it had originated the contracts. The guidance is effective prospectively for interim and annual periods beginning after December 15, 2022, with early adoption permitted. We have not adopted this guidance as of December 31, 2021, but do not anticipate that our adoption will have a material impact on our financial position, results of operations or cash flows. In July 2021, the FASB issued ASU 2021-05, Lessors - Certain Leases with Variable Lease Payments (Topic 842) w hich modifies the lease classification requirements for lessors in Topic 842, which we adopted on the effective date of January 1, 2019. The amendments require lessors to classify and account for a lease with variable lease payments that do not depend on a reference index or a rate as an operating lease at lease commencement if another classification (i.e., sales-type or direct financing) would result in the recognition of a day-one loss. For entities that have adopted Topic 842, the guidance is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2021, with early adoption permitted. We have elected to early adopt the guidance on a prospective basis as of July 1, 2021. Our adoption did not have a material impact on our financial position, results of operations or cash flows. In August 2020, the FASB issued ASU 2020-06, Debt—Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging—Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity , which simplifies accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity, by eliminating two of the three models that require separate accounting for embedded conversion features and the settlement assessment that entities are required to perform to determine whether a contract qualifies for equity classification. This guidance is effective for interim and annual periods beginning after December 15, 2021, with early adoption permitted. We adopted this guidance effective January 1, 2021, and our adoption did not have a material impact on our financial position, results of operations or cash flows. In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting , which provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. This guidance is effective prospectively upon issuance through December 31, 2022 and may be applied from the beginning of an interim period that includes the issuance date of this ASU. We will apply applicable expedients and exceptions to contract modifications through December 31, 2022. In December 2019, the FASB issued ASU 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 adopted this guidance effective January 1, 2021, and our adoption did not have a material impact on our financial position, results of operations or cash flows. |
Revenue Recognition | Revenue RecognitionWe 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.Revenues from sales of crude oil and NGL are recognized at the time title to the product sold transfers to the purchaser, which occurs upon delivery of the product to the purchaser or its designee. The consideration received under these contracts is variable based on commodity prices. Inventory exchanges under buy/sell transactions are excluded from sales revenues in our Consolidated Statements of Operations.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.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 revenues include revenues from transporting crude oil and NGL on pipelines 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.Revenues in this category include (i) fees that are generated when we receive liquids from one connecting source and deliver the applicable product to another connecting carrier, (ii) fees from storage capacity agreements, (iii) fees from loading and unloading services at our terminals and (iv) fees from natural gas and condensate processing services and from NGL fractionation and isomerization service. 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 loading/unloading 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. We recognize loading and unloading fees when the volumes are delivered or received. Natural gas storage related activities fees were recognized in the period the natural gas moved across our header system. Fees from NGL fractionation and isomerization services and gas processing services are recognized in the period when the services are performed. Reconciliation to Total Revenues of Reportable Segments. The following disclosures only include information regarding revenues associated with consolidated entities; revenues from entities accounted for by the equity method are not included. 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. |
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 merchant 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/(Loss) Per Common Unit | After consideration of distributions to preferred unitholders (whether paid in cash or in-kind), basic and diluted net income/(loss) 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/(loss) per common unit by dividing net income/(loss) 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. Participating securities include equity-indexed compensation plan awards that have vested distribution equivalent rights, which entitle the grantee to a cash payment equal to the cash distribution paid on our outstanding common units. 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 approximately 71 million Series A |
Inventory, Linefill and Base Gas and Long-term Inventory | Inventory, including long-term 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 year ended December 31, 2021, no adjustments were recorded. During the years ended December 31, 2020 and 2019, we recorded charges of $233 million (of which $40 million was associated with our long-term inventory) and $11 million, respectively, related to the write down of our crude oil and NGL 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 and NGL inventory. Such gains were recorded to “Product sales 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. Following the sale of our Pine Prairie and Southern Pines natural gas storage facilities in August of 2021, we no longer own natural gas storage facilities. See Note 7 for additional information. 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 2021, 2020 and 2019, we did not recognize any material 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, 2021, 2020 and 2019, capitalized interest recorded to property and equipment was $6 million, $8 million and $14 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 (Held and Used) | Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value in accordance with FASB guidance with respect to the accounting for the impairment or disposal of long-lived assets. Under this guidance, a long-lived asset is tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. We periodically evaluate property and equipment and other long-lived assets for impairment when events or circumstances indicate that the carrying value of these assets may not be recoverable. The evaluation is highly dependent on the underlying assumptions of related cash flows. The subjective assumptions used to determine the existence of an impairment in carrying value include: • whether there is an indication of impairment; • the grouping of assets; • the intention of “holding,” “abandoning” or “selling” an asset; • the forecast of undiscounted expected future cash flow over the asset’s estimated useful life; and • if an impairment exists, the fair value of the asset or asset group. |
Goodwill | Goodwill represents the future economic benefits arising from assets acquired in a business combination that are not individually identified and separately recognized. In accordance with FASB guidance, we test goodwill to determine whether an impairment has occurred at least annually (as of June 30) and on an interim basis if it is more likely than not that a reporting unit’s fair value is less than its carrying value. Goodwill is tested for impairment at a level of reporting referred to as a reporting unit. A reporting unit is an operating segment or one level below an operating segment for which discrete financial information is available and regularly reviewed by segment management. Our reporting units are our operating segments. FASB guidance 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 model. 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 investment 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, 2021, 2020 and 2019, we made cash contributions of $82 million, $445 million and $504 million, respectively, to certain of our equity method investees. In addition, we capitalized interest of $12 million, $16 million and $20 million during the years ended December 31, 2021, 2020 and 2019, respectively, related to contributions to unconsolidated entities for projects under development and construction. Basis Differences Our investments in unconsolidated entities exceeded our share of the underlying equity in the net assets of such entities by $223 million and $170 million at December 31, 2021 and 2020, 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, 2021 and 2020 was attributable to goodwill related to our ownership interest in BridgeTex and Capline LLC with the remaining basis difference primarily related to capitalized interest incurred during construction of the assets of our unconsolidated entities. |
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 merchant activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil and NGL. 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 or NGL 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 | 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. |
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. We use various derivative instruments to optimize our profits while managing our exposure to (i) commodity price risk, (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. Our policy is to use derivative instruments for risk management purposes and not for the purpose of speculating on changes in commodity prices, interest rates or currency exchange rates. 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.Cash settlements associated with our derivative activities are classified within the same category as the related hedged item in our Consolidated Statements of Cash Flows. |
Derivative Hedge Accounting Documentation | When we apply hedge accounting, our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. |
Derivative Hedge Effectiveness Determination | 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 in a hedging relationship for accounting purposes are recognized in earnings each period. |
Lessee | Lessee We evaluate all agreements entered into or modified that convey to us 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 we obtain the right to direct the use of identified property or equipment. 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. We have elected the non-lease component separation practical expedient for certain classes of assets where we are the lessee. Our lease agreements have remaining lease terms ranging from one year to approximately 59 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 25 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 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. We have elected the non-lease component separation practical expedient for all classes of assets where we are the lessor. We enter into agreements to conduct activities associated with (i) providing storage services primarily for crude oil and NGL 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. |
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 | Reimbursement of Our General Partner and its AffiliatesOur 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 for equity-classified awards is calculated in a similar manner on the respective grant dates. These fair values are 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, (iii) market conditions or (iv) a combination of time-based vesting criteria and performance conditions. 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 have been if we had been accruing for these awards since the grant date. For awards with market conditions, the probable outcomes are determined on the respective dates that the fair values are calculated, and the resulting expense is accrued over the service period. |
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. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss. |
Environmental Matters | We record environmental liabilities when environmental assessments and/or remedial efforts are probable and the amounts can be reasonably estimated. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We do not discount our environmental remediation liabilities to present value. We also record environmental liabilities assumed in business combinations based on the estimated fair value of the environmental obligations caused by past operations of the acquired company. We record receivables for amounts we believe are 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. |
Segment Reporting | During the fourth quarter of 2021, we effected changes in the primary financial information provided to our CODM (our Chief Executive Officer) for assessing performance and allocating resources to present two operating segments, Crude Oil and NGL. Prior to the fourth quarter of 2021, this information was organized into three operating segments: Transportation, Facilities and Supply and Logistics. The change in our segments is reflective of a change in how our CODM views our business and stems primarily from (i) a multi-year transition in the midstream energy industry driven by increased competition that has reduced the stand alone earnings opportunities of our supply and logistics activities such that those activities now primarily support our effort to increase the utilization of our Crude Oil and NGL assets and (ii) internal changes regarding the oversight and reporting of our assets and related results of operations. All segment data and related disclosures for earlier periods presented herein have been recast to reflect the new segment reporting structure. Our operating segments, which are also our reportable segments, are organized by product as our Crude Oil and NGL businesses are generally impacted by different market fundamentals and require the use of different assets and business strategies. The Crude Oil segment includes our crude oil pipelines, crude oil storage and marine terminals and related crude oil marketing activities. The NGL segment includes our NGL pipelines, NGL storage, natural gas processing and NGL fractionation facilities and related NGL marketing activities. In our historical segment reporting, our marketing activities were presented separately from our other operating activities. Our crude oil and NGL marketing activities are now included in the respective reporting segments as their primary purpose is to support the utilization of our assets by entering into transactions that facilitate increased volumes handled by our assets, resulting in additional earnings for each of our segments. Our CODM evaluates segment performance based on measures including Segment Adjusted EBITDA (as defined below) and maintenance capital. 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 (d) our proportionate share of the depreciation and amortization expense of unconsolidated entities, further adjusted (e) 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 and (f) to exclude the portion of all preceding items that is attributable to noncontrolling interests (“Adjusted EBITDA attributable to noncontrolling interests”). During the fourth quarter of 2021, we modified our definition of Segment Adjusted EBITDA to exclude amounts attributable to noncontrolling interests. In connection with the Permian JV formation in October 2021, our CODM determined this modification resulted in amounts that were more meaningful to evaluate segment performance. Amounts attributable to noncontrolling interests for periods prior have been recast to reflect this modification. 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 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 investment 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. Assets are not reviewed by our CODM on a segmented basis; therefore, such information is not presented. |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
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 Sheets that sum to the total of the amounts shown on our Consolidated Statements of Cash Flows (in millions): December 31, 2021 2020 Cash and cash equivalents $ 449 $ 22 Restricted cash 4 38 Total cash and cash equivalents and restricted cash $ 453 $ 60 |
Schedule of change in asset retirement obligation | The following table presents the change in the liability for asset retirement obligations, substantially all of which is reflected in “Other long-term liabilities and deferred credits” on our Consolidated Balance Sheets as of December 31, 2021, 2020 and 2019 (in millions): December 31, 2021 2020 2019 Beginning balance $ 135 $ 137 $ 109 Liabilities incurred 2 12 3 Liabilities settled (1) (1) (3) Accretion expense 4 5 5 Revisions in estimated cash flows 3 (18) 23 Ending balance $ 143 $ 135 $ 137 |
Revenues and Accounts Receiva_2
Revenues and Accounts Receivable (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of revenue | Revenues from Contracts with Customers. The following tables present our revenues from contracts with customers disaggregated by segment and type of activity (in millions): Year Ended December 31, 2021 2020 2019 Crude Oil segment revenues from contracts with customers Sales $ 39,635 $ 21,250 $ 30,156 Transportation 484 570 722 Terminalling, Storage and Other 431 507 505 Total Crude Oil segment revenues from contracts with customers $ 40,550 $ 22,327 $ 31,383 Year Ended December 31, 2021 2020 2019 NGL segment revenues from contracts with customers Sales $ 2,292 $ 1,350 $ 2,211 Transportation 25 29 32 Terminalling, Storage and Other 82 96 80 Total NGL segment revenues from contracts with customers $ 2,399 $ 1,475 $ 2,323 Year Ended December 31, 2021 Crude Oil NGL Total Revenues from contracts with customers $ 40,550 $ 2,399 $ 42,949 Other items in revenues (80) (431) (511) Total revenues of reportable segments $ 40,470 $ 1,968 $ 42,438 Intersegment revenues elimination (360) Total revenues $ 42,078 Year Ended December 31, 2020 Crude Oil NGL Total Revenues from contracts with customers $ 22,327 $ 1,475 $ 23,802 Other items in revenues (128) (115) (243) Total revenues of reportable segments $ 22,199 $ 1,360 $ 23,559 Intersegment revenues elimination (269) Total revenues $ 23,290 Year Ended December 31, 2019 Crude Oil NGL Total Revenues from contracts with customers $ 31,383 $ 2,323 $ 33,706 Other items in revenues 272 116 388 Total revenues of reportable segments $ 31,655 $ 2,439 $ 34,094 Intersegment revenues elimination (425) Total revenues $ 33,669 |
Contracts with customers, change in contract asset and liability balance | The following table presents amounts in Other current assets and deferred revenue associated with these agreements (in millions): December 31, 2021 2020 Other current assets $ — $ 229 Deferred revenue (1) $ — $ 361 (1) Included in “Other current liabilities” on our Consolidated Balance Sheet. Contract Liabilities Balance at December 31, 2019 $ 354 Amounts recognized as revenue (1) (246) Additions (2) 393 Balance at December 31, 2020 $ 501 Amounts recognized as revenue (2) (393) Additions 33 Balance at December 31, 2021 $ 141 (1) Includes approximately $155 million associated with crude oil sales agreements that were entered into in conjunction with storage arrangements and future inventory exchanges. Such agreements were entered into in 2019 and recognized as revenue in the first quarter of 2020. (2) Includes approximately $361 million associated with crude oil sales agreements that were entered into in conjunction with storage arrangements and future inventory exchanges. Such amount was recognized as revenue in the first quarter of 2021. 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, 2021 2020 Trade accounts receivable arising from revenues from contracts with customers $ 4,031 $ 2,317 Other trade accounts receivables and other receivables (1) 5,126 2,818 Impact due to contractual rights of offset with counterparties (4,452) (2,582) Trade accounts receivable and other receivables, net $ 4,705 $ 2,553 (1) The balance is comprised primarily of accounts receivable associated with buy/sell arrangements that are not within the scope of ASC 606. |
Contract with customer, counterparty deficiencies | The following table presents counterparty deficiencies associated with contracts with customers and buy/sell arrangements that include minimum volume commitments for which we had remaining performance obligations and the customers still had the ability to meet their obligations (in millions): December 31, Counterparty Deficiencies Financial Statement Classification 2021 2020 Billed and collected Liability $ 63 $ 73 Unbilled (1) N/A 16 4 Total $ 79 $ 77 (1) Amounts were related to deficiencies for which the counterparties had not met their contractual minimum commitments and are not reflected in our Consolidated Financial Statements as we had not yet billed or collected such amounts. |
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, 2021 (in millions): 2022 2023 2024 2025 2026 2027 and Thereafter Pipeline revenues supported by minimum volume commitments and capacity agreements (1) $ 179 $ 174 $ 158 $ 131 $ 86 $ 379 Terminalling, storage and other agreement revenues 237 170 130 63 45 197 Total $ 416 $ 344 $ 288 $ 194 $ 131 $ 576 (1) Calculated as volumes committed under contracts multiplied by the current applicable tariff rate. |
Net Income_(Loss) Per Common _2
Net Income/(Loss) Per Common Unit (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
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/(loss) per common unit (in millions, except per unit data): Year Ended December 31, 2021 2020 2019 Basic Net Income/(Loss) per Common Unit Net income/(loss) attributable to PAA $ 593 $ (2,590) $ 2,171 Distributions to Series A preferred unitholders (149) (149) (149) Distributions to Series B preferred unitholders (49) (49) (49) Distributions to participating securities (2) (2) (3) Other — — (3) Net income/(loss) allocated to common unitholders (1) $ 393 $ (2,790) $ 1,967 Basic weighted average common units outstanding 716 728 727 Basic net income/(loss) per common unit $ 0.55 $ (3.83) $ 2.70 Diluted Net Income/(Loss) per Common Unit Net income/(loss) attributable to PAA $ 593 $ (2,590) $ 2,171 Distributions to Series A preferred unitholders (149) (149) — Distributions to Series B preferred unitholders (49) (49) (49) Distributions to participating securities (2) (2) (3) Net income/(loss) allocated to common unitholders (1) $ 393 $ (2,790) $ 2,119 Basic weighted average common units outstanding 716 728 727 Effect of dilutive securities: Series A preferred units — — 71 Equity-indexed compensation plan awards — — 2 Diluted weighted average common units outstanding 716 728 800 Diluted net income/(loss) per common unit $ 0.55 $ (3.83) $ 2.65 (1) We calculate net income/(loss) allocated to common unitholders based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings (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, 2021 | |
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, 2021 December 31, 2020 Volumes Unit of Carrying Price/ Unit (1) Volumes Unit of Carrying Price/ Unit (1) Inventory Crude oil 8,041 barrels $ 544 $ 67.65 13,450 barrels $ 441 $ 32.79 NGL 6,982 barrels 234 $ 33.51 12,302 barrels 199 $ 16.18 Other N/A 5 N/A N/A 7 N/A Inventory subtotal 783 647 Linefill and base gas Crude oil 15,199 barrels 862 $ 56.71 14,669 barrels 828 $ 56.45 NGL 1,633 barrels 45 $ 27.56 1,640 barrels 44 $ 26.83 Natural gas (2) — Mcf — $ — 25,576 Mcf 110 $ 4.30 Linefill and base gas subtotal 907 982 Long-term inventory Crude oil 2,973 barrels 209 $ 70.30 2,499 barrels 111 $ 44.42 NGL 1,135 barrels 44 $ 38.77 1,185 barrels 19 $ 16.03 Long-term inventory subtotal 253 130 Total $ 1,943 $ 1,759 (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. (2) Base gas with a carrying value of $110 million was included in the sale of our natural gas storage facilities, which closed in August 2021. See Note 7 for additional information. |
Property and Equipment (Tables)
Property and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
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, 2021 2020 Pipelines and related facilities (1) (2) 10 - 50 $ 12,765 $ 11,112 Storage, terminal and rail facilities (2) 10 - 50 5,100 6,042 Trucking equipment and other 2 - 15 502 524 Construction in progress N/A 248 272 Office property and equipment 2 - 50 312 293 Land and other N/A 330 342 Property and equipment, gross 19,257 18,585 Accumulated depreciation (4,354) (3,974) Property and equipment, net $ 14,903 $ 14,611 (1) We include rights-of-way, which are intangible assets, in our Pipelines and related facilities amounts within property and equipment. (2) Useful lives changed to 10 to 50 years in 2021. See below for additional information. |
Acquisitions, Divestitures an_2
Acquisitions, Divestitures and Other Transactions (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Business Combinations [Abstract] | |
Schedule of partners' capital | The following table presents the amounts recognized in partners’ capital associated with this transaction (in millions): Recognized Amount Noncontrolling interests $ 2,651 Partners’ capital, excluding noncontrolling interests 605 $ 3,256 |
Schedule of assets acquired and liabilities assumed | The following table reflects our preliminary determination of the fair value of those assets and liabilities (in millions): Identifiable Assets Acquired and Liabilities Assumed Estimated Useful Lives Recognized Amount Property and equipment 3-30 $ 1,886 Intangible assets 20 1,247 Investment in unconsolidated entities N/A 103 Linefill N/A 5 Working capital and other assets and liabilities N/A 15 $ 3,256 |
Schedule of amortization expense | Amortization expense was approximately $28 million during the year ended December 31, 2021, and the future amortization expense through 2026 is estimated as follows (in millions): 2022 $ 142 2023 $ 138 2024 $ 127 2025 $ 117 2026 $ 106 |
Schedule of modified revenue sharing arrangement | Under the MSA, distributions will be allocated as follows (in millions): Available Cash Distributions Percentages Tier Annualized PAA Oryx 1 Up to $300 50% 50% 2 $300 - $428 100% —% 3 $428 - $815 65% 35% 4 $815 and above 70% 30% |
Pro forma information | These results are not necessarily indicative of the results that might have actually occurred had the merger taken place on January 1, 2020; furthermore, this financial information is not intended to be a projection of future results (in millions, except per unit amounts): Year ended December 31, 2021 2020 Total revenues $ 42,359 $ 23,536 Net income/(loss) attributable to PAA $ 524 $ (2,898) Net income/(loss) allocated to common unitholders $ 324 $ (3,098) Basic and diluted net income/(loss) per common unit $ 0.45 $ (4.26) |
Goodwill (Tables)
Goodwill (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
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): Crude Oil NGL Total Balance at December 31, 2019 $ 2,300 $ 240 $ 2,540 Acquisitions 2 — 2 Goodwill, gross $ 2,302 $ 240 $ 2,542 Impairments (2,287) (228) (2,515) Foreign currency translation adjustments (15) (12) (27) Accumulated impairment losses (2,302) (240) (2,542) Balance at December 31, 2020 $ — $ — $ — |
Investments in Unconsolidated_2
Investments in Unconsolidated Entities (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Investments in and summarized financial information for entities accounted for under the equity method of accounting | Our investments in unconsolidated entities consisted of the following (in millions, except percentage data): Ownership Interest at December 31, 2021 Investment Balance Entity (1) Type of Operation 2021 2020 BridgeTex Pipeline Company, LLC (“BridgeTex”) Crude Oil Pipeline 20% $ 406 $ 421 Cactus II Pipeline LLC (“Cactus II”) Crude Oil Pipeline 65% 737 752 Capline Pipeline Company LLC Crude Oil Pipeline (2) 54% 531 514 Diamond Pipeline LLC (“Diamond”) Crude Oil Pipeline 50% 464 480 Eagle Ford Pipeline LLC (“Eagle Ford Pipeline”) Crude Oil Pipeline 50% 363 372 Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Terminals”) Crude Oil Terminal and Dock 50% 120 122 OMOG JV LLC (3) Crude Oil Pipeline 40% 102 — Saddlehorn Crude Oil Pipeline 30% 209 208 White Cliffs Pipeline, LLC Crude Oil Pipeline 36% 171 192 Wink to Webster Pipeline LLC (“W2W Pipeline”) (4) Crude Oil Pipeline (5) 16% 345 330 Other investments 357 373 Total Investments in Unconsolidated Entities $ 3,805 $ 3,764 (1) The financial results from these entities are reported in our Crude Oil segment. (2) The Capline pipeline was out of service during 2020 and a majority of 2021 pending the reversal of the pipeline system. The pipeline reversal project was completed with interim service beginning in mid-December 2021 and full service beginning in January 2022. (3) Our ownership in this entity was acquired as part of the assets contributed by Oryx Midstream in the formation of the Permian JV in October 2021. See Note 7 for additional information. (4) Although we own less than 20% of W2W Pipeline, we use the equity method to account for the investment because we believe we have significant influence over the financial and operating decisions of the company. (5) The pipeline system was in partial service during 2021 and another phase of the pipeline construction project was completed in the first quarter of 2022. 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, 2021 2020 Current assets $ 509 $ 580 Noncurrent assets $ 8,879 $ 8,769 Current liabilities $ 366 $ 343 Noncurrent liabilities $ 15 $ 10 Year Ended December 31, 2021 2020 2019 Revenues $ 1,320 $ 1,360 $ 1,469 Operating income $ 505 $ 828 $ 994 Net income $ 506 $ 826 $ 995 |
Intangible Asset, Net (Tables)
Intangible Asset, Net (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Components of intangible assets, net of accumulated amortization | Intangible assets, net of accumulated amortization, consisted of the following (in millions): December 31, 2021 December 31, 2020 Estimated Useful Cost Accumulated Net Cost Accumulated Net Customer contracts and relationships (1) 3 – 31 $ 2,445 $ (510) $ 1,935 $ 1,291 $ (519) $ 772 Other agreements 1 – 70 36 (11) 25 63 (30) 33 Intangible assets (2) $ 2,481 $ (521) $ 1,960 $ 1,354 $ (549) $ 805 (1) The increase in intangible assets related to Customer contracts and relationships in 2021 is associated with the assets acquired in the formation of the Permian JV. See Note 7 for additional information. (2) 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): 2022 $ 240 2023 $ 232 2024 $ 220 2025 $ 207 2026 $ 187 |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
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 0.7% (1) $ — $ 547 Senior secured hedged inventory facility, bearing a weighted-average interest rate of 1.2% (1) — 167 Senior notes: 3.65% senior notes due June 2022 (2) 750 — Other 72 117 Total short-term debt 822 831 LONG-TERM DEBT Senior notes: 3.65% senior notes due June 2022 — 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 1,000 3.80% senior notes due September 2030 750 750 6.70% senior notes due May 2036 250 250 6.65% senior notes due January 2037 600 600 5.15% senior notes due June 2042 (3) 499 499 4.30% senior notes due January 2043 (3) 348 348 4.70% senior notes due June 2044 (3) 687 687 4.90% senior notes due February 2045 (3) 649 649 Unamortized discounts and debt issuance costs (54) (62) Senior notes, net of unamortized discounts and debt issuance costs 8,329 9,071 Other long-term debt: GO Zone term loans, net of debt issuance costs of $1, bearing a weighted-average interest rate of 1.3% (4) — 199 Other 69 112 Total long-term debt 8,398 9,382 Total debt (5) $ 9,220 $ 10,213 (1) We classified these commercial paper notes and credit facility borrowings as short-term as of December 31, 2020, 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) In January 2022, we provided notice of our intention to redeem these senior notes on March 1, 2022. (3) During the year ended December 31, 2020, we repurchased $17 million of our outstanding senior notes on the open market and recognized a gain of $3 million on these transactions, which is included in “Other income/(expense), net” on our Consolidated Statement of Operations. (4) The GO Zone term loans were initially assumed by one of our subsidiaries in connection with the acquisition of the Southern Pines natural gas storage facility. The loans were repaid in August 2021 in connection with the sale of that facility. See Note 7 for additional information. (5) Our fixed-rate senior notes had a face value of approximately $9.1 billion at both December 31, 2021 and 2020. We estimated the aggregate fair value of these notes to be approximately $9.9 billion at both December 31, 2021 and 2020. 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, 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. |
Issuances of senior unsecured notes | The table below summarizes our issuances of senior unsecured notes during the three years ended December 31, 2021 (in millions): Year Description Maturity Face Value Interest Payment Dates 2020 3.80% Senior Notes issued at 99.794% of face value September 2030 $ 750 March 15 and September 15 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 2020 $600 million 5.00% Senior Notes due February 2021 November 2020 (1) 2019 $500 million 2.60% Senior Notes due December 2019 November 2019 (2) 2019 $500 million 5.75% Senior Notes due January 2020 December 2019 (2) (1) We repaid these senior notes with proceeds from our 3.80% senior notes issued in June 2020 and cash on hand. (2) We repaid these senior notes with proceeds from our 3.55% senior notes issued in September 2019 and cash on hand. |
Aggregate maturities of long-term debt | The following table presents the aggregate contractually scheduled maturities of such senior notes for the next five years and thereafter. The amounts presented exclude unamortized discounts and debt issuance costs. Calendar Year Payment (in millions) 2022 $ 750 2023 $ 1,100 2024 $ 750 2025 $ 1,000 2026 $ 750 Thereafter $ 4,783 |
Partners' Capital and Distrib_2
Partners' Capital and Distributions (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
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, 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 Repurchase and cancellation of common units under the Common Equity Repurchase Program — — (6,222,748) Issuances of common units under equity-indexed compensation plans — — 574,588 Outstanding at December 31, 2020 71,090,468 800,000 722,380,416 Repurchase and cancellation of common units under the Common Equity Repurchase Program — — (18,061,583) Issuances of common units under equity-indexed compensation plans — — 672,707 Outstanding at December 31, 2021 71,090,468 800,000 704,991,540 |
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 years presented (in millions, except unit data): Cash Distributions Year Series A Preferred Unitholders Series B Preferred Unitholders 2021 $ 149 $ 49 2020 $ 149 $ 49 2019 $ 149 $ 49 |
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 years presented (in millions, except unit data): Cash Distributions Year Series A Preferred Unitholders Series B Preferred Unitholders 2021 $ 149 $ 49 2020 $ 149 $ 49 2019 $ 149 $ 49 |
Common Units | |
Partners Capital and Distribution [Line Items] | |
Schedule of distributions paid | The following table details distributions paid to common unitholders during the years presented (in millions, except per unit data): Distributions Paid Distributions per common unit Year Public AAP Total 2021 $ 341 $ 176 $ 517 $ 0.72 2020 $ 432 $ 223 $ 655 $ 0.90 2019 $ 632 $ 372 $ 1,004 $ 1.38 |
Derivatives and Risk Manageme_2
Derivatives and Risk Management Activities (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Derivatives and Risk Management Activities | |
Impact of derivative activities recognized in earnings | The following table summarizes the impact of our commodity derivatives recognized in earnings (in millions): Year Ended December 31, 2021 2020 2019 Product sales revenues $ (710) $ (302) $ 310 Field operating costs 71 5 14 Net gain/(loss) from commodity derivative activity $ (639) $ (297) $ 324 |
Schedule of net broker receivable (payable) | The following table provides the components of our net broker receivable/(payable) (in millions): December 31, 2021 2020 Initial margin $ 133 $ 91 Variation margin posted/(returned) 173 290 Letters of credit (47) (63) Net broker receivable/(payable) $ 259 $ 318 |
Summary of derivative assets and liabilities on Consolidated Balance Sheets on a gross basis | The following table reflects the Consolidated Balance Sheet line items that include the fair values of our commodity derivative assets and liabilities and the effect of the collateral netting. Such amounts are presented on a gross basis, before the effects of counterparty netting. However, we have elected to present our commodity derivative assets and liabilities with the same counterparty on a net basis on our Consolidated Balance Sheet when the legal right of offset exists. Amounts in the table below are presented in millions. December 31, 2021 December 31, 2020 Effect of Collateral Netting Net Carrying Value Presented on the Balance Sheet Effect of Collateral Netting Net Carrying Value Presented on the Balance Sheet Commodity Derivatives Commodity Derivatives Assets Liabilities Assets Liabilities Derivative Assets Other current assets $ 90 $ (210) $ 259 $ 139 $ 71 $ (314) $ 318 $ 75 Other long-term assets, net 3 — — 3 5 — — 5 Derivative Liabilities Other current liabilities 4 (24) — (20) 9 (40) — (31) Other long-term liabilities and deferred credits 3 (9) — (6) — (32) — (32) Total $ 100 $ (243) $ 259 $ 116 $ 85 $ (386) $ 318 $ 17 |
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, 2021 2020 2019 Interest rate derivatives, net $ 19 $ (10) $ (91) |
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, 2021 Fair Value as of December 31, 2020 Recurring Fair Value Measures (1) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Commodity derivatives $ (17) $ (124) $ (2) $ (143) $ (143) $ (143) $ (15) $ (301) Interest rate derivatives — 65 — 65 — 46 — 46 Preferred Distribution Rate Reset Option and Other — — — — — 2 (14) (12) Total net derivative asset/(liability) $ (17) $ (59) $ (2) $ (78) $ (143) $ (95) $ (29) $ (267) (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, 2021 2020 Beginning Balance $ (29) $ (51) Net gains/(losses) for the period included in earnings 15 12 Settlements 12 10 Ending Balance $ (2) $ (29) Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period $ 15 $ 12 |
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, 2021. Notional Volume Remaining Tenor Natural gas purchases 73.4 Bcf December 2023 Propane sales (13.7) MMbls December 2023 Butane sales (3.3) MMbls December 2023 Condensate sales (1.5) MMbls December 2023 Fuel gas requirements (1) 7.5 Bcf December 2022 Power supply requirements (1) 0.6 TWh December 2023 (1) Positions to hedge a portion of our power supply and fuel gas requirements at our Canadian natural gas processing and fractionation plants. |
Interest Rate Derivatives | |
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, 2021 (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 6/15/2023 1.38 % Cash flow hedge Anticipated interest payments 8 forward starting swaps (30-year) $ 200 6/14/2024 0.73 % Cash flow hedge |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Leases [Abstract] | |
Schedule of lease costs and other lessee information | The following table presents components of lease cost, including both amounts recognized in income and amounts capitalized (in millions): Year Ended December 31, Lease Cost 2021 2020 2019 Operating lease cost $ 96 $ 111 $ 125 Short-term lease cost 19 31 35 Other (1) (2) 14 8 — Total lease cost $ 129 $ 150 $ 160 (1) Includes finance lease costs, variable lease costs and sublease income. (2) Includes approximately $8 million and $6 million for the years ended December 31, 2021 and 2020, respectively, associated with leased storage tanks owned by an equity method investee, in which we own a 50% interest. The following table presents information related to cash flows arising from lease transactions (in millions): Year Ended December 31, 2021 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases $ 91 $ 108 $ 116 Operating cash flows for finance leases $ 7 $ 5 $ 1 Financing cash flows for finance leases $ 11 $ 19 $ 18 Non-cash change in lease liabilities arising from obtaining new right-of-use assets or modifications: Operating leases $ 94 $ 5 $ 77 Finance leases (1) $ 1 $ 32 $ 27 (1) Includes $25 million and $12 million for the years ended December 31, 2020 and 2019, respectively, 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: December 31, 2021 2020 Weighted-average remaining lease term (in years): Operating leases 11 12 Finance leases 9 9 Weighted-average discount rate: Operating leases 4.2 % 4.5 % Finance leases 11.6 % 11.1 % |
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 Sheets (in millions): December 31, Leases Balance Sheet Location 2021 2020 Assets Operating lease right-of-use assets Long-term operating lease right-of-use assets, net $ 393 $ 378 Finance lease right-of-use assets (1) Property and equipment $ 136 $ 141 Accumulated depreciation (37) (27) Property and equipment, net $ 99 $ 114 Total lease right-of-use assets $ 492 $ 492 Liabilities Operating lease liabilities Current Other current liabilities $ 77 $ 78 Noncurrent Long-term operating lease liabilities 339 317 Total operating lease liabilities $ 416 $ 395 Finance lease liabilities (1) Current Short-term debt $ 12 $ 11 Noncurrent Other long-term debt, net 59 70 Total finance lease liabilities $ 71 $ 81 Total lease liabilities $ 487 $ 476 (1) Includes right-of-use assets of $33 million and $35 million and lease liabilities of $35 million and $36 million as of December 31, 2021 and 2020, respectively, 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, 2021 reconciled to our lease liabilities on our Consolidated Balance Sheet (amounts in millions): Operating Finance (2) Future minimum lease payments (1) : 2022 $ 92 $ 18 2023 75 15 2024 63 14 2025 50 12 2026 38 7 Thereafter 252 60 Total 570 126 Less: Present value discount (154) (55) Lease liabilities $ 416 $ 71 (1) Excludes future minimum payments for short-term and other immaterial leases not included on our Consolidated Balance Sheet. (2) Includes payments of approximately $6 million for each of the years ending 2022 through 2026 and approximately $58 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, 2021 reconciled to our lease liabilities on our Consolidated Balance Sheet (amounts in millions): Operating Finance (2) Future minimum lease payments (1) : 2022 $ 92 $ 18 2023 75 15 2024 63 14 2025 50 12 2026 38 7 Thereafter 252 60 Total 570 126 Less: Present value discount (154) (55) Lease liabilities $ 416 $ 71 (1) Excludes future minimum payments for short-term and other immaterial leases not included on our Consolidated Balance Sheet. (2) Includes payments of approximately $6 million for each of the years ending 2022 through 2026 and approximately $58 million thereafter associated with leased storage tanks owned by an equity method investee, in which we own a 50% interest. |
Schedule of lessor operating lease revenue | The following table presents our lease revenue for the periods indicated (in millions): Year Ended December 31, 2021 2020 2019 Operating lease revenue (1) $ 28 $ 19 $ 17 (1) These amounts are included in “Services revenues” on our Consolidated Statements of Operations. |
Schedule of lessor future revenues maturity | The following table presents the undiscounted cash flows expected to be received related to these agreements (in millions): 2022 2023 2024 2025 2026 Thereafter Future minimum lease revenue $ 29 $ 22 $ 20 $ 20 $ 20 $ 197 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Income Tax Disclosure [Abstract] | |
Components of income tax expense | Components of income tax expense are as follows (in millions): Year Ended December 31, 2021 2020 2019 Current income tax expense: State income tax $ 2 $ — $ 3 Canadian federal and provincial income tax 48 51 109 Total current income tax expense $ 50 $ 51 $ 112 Deferred income tax expense/(benefit): Canadian federal and provincial income tax $ 23 $ (70) $ (46) Total deferred income tax expense/(benefit) $ 23 $ (70) $ (46) Total income tax expense/(benefit) $ 73 $ (19) $ 66 |
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, 2021 2020 2019 Income/(loss) before tax $ 721 $ (2,599) $ 2,246 Partnership (earnings)/loss not subject to current Canadian tax (370) 2,221 (1,769) $ 351 $ (378) $ 477 Canadian federal and provincial corporate tax rate 24% 24% 26% Income tax expense/(benefit) at statutory rate $ 84 $ (91) $ 124 Canadian permanent differences and rate changes $ (13) $ 72 $ (61) State income tax 2 — 3 Total income tax expense/(benefit) $ 73 $ (19) $ 66 |
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, 2021 2020 Deferred tax assets: Derivative instruments $ 39 $ 45 Lease liabilities 48 39 Net operating losses 2 2 Other 17 16 Total deferred tax assets 106 102 Deferred tax liabilities: Property and equipment in excess of tax values (531) (475) Lease assets (47) (38) Other (3) (3) Total deferred tax liabilities (581) (516) Net deferred tax liabilities $ (475) $ (414) Balance sheet classification of deferred tax assets/(liabilities): Other long-term assets, net $ 2 $ 2 Other long-term liabilities and deferred credits (477) (416) $ (475) $ (414) |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Related Party Transactions [Abstract] | |
Schedule of related party transactions | During the three years ended December 31, 2021, we recognized sales and transportation revenues, purchased petroleum products and utilized transportation and storage services from our related parties. These transactions were conducted at posted tariff rates or prices that we believe approximate market. The impact to our Consolidated Statements of Operations from these transactions is included below (in millions): Year Ended December 31, 2021 2020 2019 Revenues from related parties (1) $ 33 $ 46 $ 692 Purchases and related costs from related parties (1) $ 385 $ 451 $ 223 (1) 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, 2021 2020 Trade accounts receivable and other receivables, net from related parties (1) $ 41 $ 34 Trade accounts payable to related parties (1) (2) $ 72 $ 88 (1) Includes amounts related to crude oil purchases and sales, transportation and storage services and amounts owed to us or advanced to us related to investment capital projects of equity method investees where we serve as construction manager. (2) We have agreements to store crude oil at facilities and transport crude oil or utilize capacity on pipelines that are owned by equity method investees. A portion of our commitment to transport is supported by crude oil buy/sell or other agreements with third parties with commensurate quantities. |
Equity-Indexed Compensation P_2
Equity-Indexed Compensation Plans (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
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, 2021 (in millions): LTIP LTIP Plains All American 2021 Long-Term Incentive Plan 28.8 Plains All American PNG Successor Long-Term Incentive Plan 1.3 Plains All American GP LLC 2006 Long-Term Incentive Tracking Unit Plan 13.4 Total (1) 43.5 (1) Of the 43.5 million total awards authorized, 22.7 million awards are currently available. The remaining balance has already vested or is currently outstanding. |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
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, 2021 are summarized below (in millions): 2022 2023 2024 2025 2026 Thereafter Total Leases (1) $ 110 $ 90 $ 77 $ 62 $ 45 $ 312 $ 696 Other commitments (2) 327 307 298 282 211 624 2,049 Total $ 437 $ 397 $ 375 $ 344 $ 256 $ 936 $ 2,745 (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 storage, transportation and pipeline throughput agreements, as well as certain rights-of-way easements. Expense associated with our storage, transportation and pipeline throughput agreements was approximately $270 million, $265 million and $236 million for 2021, 2020 and 2019, respectively. A majority of the storage, transportation and pipeline throughput commitments are associated with agreements to store crude oil at facilities and transport crude oil on pipelines owned by equity method investees, in which we own a 50% interest, at posted tariff rates or prices that we believe approximate market. A portion of our commitment to transport is supported by crude oil buy/sell or other agreements with third parties with commensurate quantities. |
Segment Information (Tables)
Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Segment Reporting [Abstract] | |
Segment financial data | The following tables reflect certain financial data for each segment (in millions): Crude Oil NGL Intersegment Revenues Total Year Ended December 31, 2021 Revenues (1) : Product sales $ 39,395 $ 1,829 $ (341) $ 40,883 Services 1,075 139 (19) 1,195 Total revenues $ 40,470 $ 1,968 $ (360) $ 42,078 Equity earnings in unconsolidated entities $ 274 $ — $ 274 Segment Adjusted EBITDA $ 1,909 $ 285 $ 2,194 Investment and acquisition capital expenditures (2) (3) $ 212 $ 57 $ 269 Maintenance capital expenditures (3) $ 100 $ 68 $ 168 As of December 31, 2021 Investments in unconsolidated entities $ 3,805 $ — $ 3,805 Crude Oil NGL Intersegment Revenues Total Year Ended December 31, 2020 Revenues (1) : Product sales $ 21,089 $ 1,218 $ (249) $ 22,058 Services 1,110 142 (20) 1,232 Total revenues $ 22,199 $ 1,360 $ (269) $ 23,290 Equity earnings in unconsolidated entities $ 355 $ — $ 355 Segment Adjusted EBITDA $ 2,216 $ 327 $ 2,543 Investment and acquisition capital expenditures (2) (3) $ 1,182 $ 49 $ 1,231 Maintenance capital expenditures (3) $ 171 $ 45 $ 216 As of December 31, 2020 Investments in unconsolidated entities $ 3,764 $ — $ 3,764 Crude Oil NGL Intersegment Revenues Total Year Ended December 31, 2019 Revenues (1) : Product sales $ 30,375 $ 2,302 $ (405) $ 32,272 Services 1,280 137 (20) 1,397 Total revenues $ 31,655 $ 2,439 $ (425) $ 33,669 Equity earnings in unconsolidated entities $ 388 $ — $ 388 Segment Adjusted EBITDA $ 2,753 $ 467 $ 3,220 Investment and acquisition capital expenditures (2) (3) $ 1,332 $ 58 $ 1,390 Maintenance capital expenditures (3) $ 248 $ 39 $ 287 As of December 31, 2019 Investments in unconsolidated entities $ 3,683 $ — $ 3,683 (1) Segment revenues include intersegment amounts that are eliminated in Purchases and related costs. 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. (2) Investment and acquisition capital expenditures, including investments in unconsolidated entities. (3) These amounts combined represent total capital expenditures. |
Reconciliation of Segment Adjusted EBITDA to Net income/(loss) attributable to PAA | The following table reconciles Segment Adjusted EBITDA to Net income/(loss) attributable to PAA (in millions): Year Ended December 31, 2021 2020 2019 Segment Adjusted EBITDA $ 2,194 $ 2,543 $ 3,220 Adjustments (1) : Depreciation and amortization of unconsolidated entities (2) (123) (73) (62) Gains/(losses) from derivative activities and inventory valuation adjustments (3) 271 (480) (160) Long-term inventory costing adjustments (4) 94 (44) 20 Deficiencies under minimum volume commitments, net (5) 7 (74) 18 Equity-indexed compensation expense (6) (19) (19) (17) Net gain/(loss) on foreign currency revaluation (7) 4 3 (14) Line 901 incident (8) (15) — (10) Significant transaction-related expenses (9) (16) (3) — Adjusted EBITDA attributable to noncontrolling interests (10) 94 14 10 Depreciation and amortization (774) (653) (601) Gains/(losses) on asset sales and asset impairments, net (592) (719) (28) Goodwill impairment losses — (2,515) — Gain on/(impairment of) investments in unconsolidated entities, net 2 (182) 271 Interest expense, net (425) (436) (425) Other income, net 19 39 24 Income/(loss) before tax 721 (2,599) 2,246 Income tax (expense)/benefit (73) 19 (66) Net income/(loss) 648 (2,580) 2,180 Net income attributable to noncontrolling interests (55) (10) (9) Net income/(loss) attributable to PAA $ 593 $ (2,590) $ 2,171 (1) Represents adjustments utilized by our CODM in the evaluation of segment results. (2) Includes our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects) of 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 differences in the timing of earnings from the derivative instruments and the underlying transactions and exclude the related gains and losses in determining Segment Adjusted EBITDA such that the earnings from the derivative instruments and the underlying transactions impact Segment Adjusted EBITDA in the same period. 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 write-downs of such inventory that result from price declines from Segment Adjusted EBITDA. (5) We, and certain of our equity method investments, 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) Our total equity-indexed compensation expense includes expense associated with awards that will be settled in units and awards that will be settled in cash. The awards that will be settled in units are included in our diluted net income per unit calculation when the applicable performance criteria have been met. We exclude compensation expense associated with these awards in determining Segment Adjusted EBITDA as the dilutive impact of the outstanding awards is included in our diluted net income per unit calculation, as applicable. The portion of compensation expense associated with awards that will settle in cash is not excluded in determining Segment Adjusted EBITDA. See Note 18 for information regarding our equity-indexed compensation plans. (7) During the periods presented, there were fluctuations in the value of CAD to USD, resulting in the realization of foreign exchange gains and losses on the settlement of foreign currency transactions as well as the revaluation of monetary assets and liabilities denominated in a foreign currency. These gains and losses are not integral to our core operating performance and were therefore excluded in determining Segment Adjusted EBITDA. (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 expenses associated with the Permian JV transaction in 2021 and the Felix Midstream LLC acquisition in 2020. See Note 7 for additional discussion. An adjustment for these non-recurring expenses is included in the calculation of Segment Adjusted EBITDA for the years ended December 31, 2021 and 2020 as our CODM does not view such expenses as integral to understanding our core segment operating performance. (10) Reflects amounts attributable to noncontrolling interests in the Permian JV (beginning October 2021) and Red River LLC. |
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) 2021 2020 2019 United States $ 34,458 $ 17,942 $ 27,162 Canada 7,620 5,348 6,507 $ 42,078 $ 23,290 $ 33,669 (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) 2021 2020 United States $ 18,273 $ 16,887 Canada 4,094 3,892 $ 22,367 $ 20,779 (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 | 3 Months Ended | 9 Months Ended | 12 Months Ended |
Dec. 31, 2021segment | Sep. 30, 2021segment | Dec. 31, 2021segmentshares | |
Organization and basis of presentation | |||
Operating segments number | segment | 2 | 3 | 2 |
AAP | PAGP | |||
Organization and basis of presentation | |||
Limited partner interest | 81.00% | ||
PAA | AAP | |||
Organization and basis of presentation | |||
Limited partner interest (in units) | shares | 241.5 | ||
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, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Foreign Currency Transactions/Translation | |||
Gain on revaluation of foreign currency transactions and monetary assets and liabilities | $ 7 | $ 16 | $ 1 |
Cash and Cash Equivalents and Restricted Cash | |||
Outstanding checks included in accounts payable that were reclassified from cash and cash equivalents | $ 19 | $ 27 |
Summary of Significant Accoun_5
Summary of Significant Accounting Policies - Cash and Restricted Cash (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Accounting Policies [Abstract] | ||||
Cash and cash equivalents | $ 449 | $ 22 | ||
Restricted cash | 4 | 38 | ||
Total cash and cash equivalents and restricted cash | $ 453 | $ 60 | $ 82 | $ 66 |
Summary of Significant Accoun_6
Summary of Significant Accounting Policies - Asset Retirement Obligations (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Beginning balance | $ 135 | $ 137 | $ 109 |
Liabilities incurred | 2 | 12 | 3 |
Liabilities settled | (1) | (1) | (3) |
Accretion expense | 4 | 5 | 5 |
Revisions in estimated cash flows | 3 | (18) | 23 |
Ending balance | $ 143 | $ 135 | $ 137 |
Revenues and Accounts Receiva_3
Revenues and Accounts Receivable - Disaggregation of Revenue (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Crude Oil | |||
Disaggregation of Revenue [Line Items] | |||
Revenue from contracts with customers | $ 40,550 | $ 22,327 | $ 31,383 |
Crude Oil | Product sales | |||
Disaggregation of Revenue [Line Items] | |||
Revenue from contracts with customers | 39,635 | 21,250 | 30,156 |
Crude Oil | Transportation | |||
Disaggregation of Revenue [Line Items] | |||
Revenue from contracts with customers | 484 | 570 | 722 |
Crude Oil | Terminalling, Storage and Other | |||
Disaggregation of Revenue [Line Items] | |||
Revenue from contracts with customers | 431 | 507 | 505 |
NGL | |||
Disaggregation of Revenue [Line Items] | |||
Revenue from contracts with customers | 2,399 | 1,475 | 2,323 |
NGL | Product sales | |||
Disaggregation of Revenue [Line Items] | |||
Revenue from contracts with customers | 2,292 | 1,350 | 2,211 |
NGL | Transportation | |||
Disaggregation of Revenue [Line Items] | |||
Revenue from contracts with customers | 25 | 29 | 32 |
NGL | Terminalling, Storage and Other | |||
Disaggregation of Revenue [Line Items] | |||
Revenue from contracts with customers | $ 82 | $ 96 | $ 80 |
Revenues and Accounts Receiva_4
Revenues and Accounts Receivable - Agreement Balances (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Contract With Customer, Asset And Liability [Line Items] | |||
Other current assets | $ 196 | $ 405 | |
Deferred revenue | 141 | 501 | $ 354 |
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 | 0 | 229 | |
Deferred revenue | $ 0 | $ 361 |
Revenues and Accounts Receiva_5
Revenues and Accounts Receivable - Segment Revenue (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Disaggregation of Revenue [Line Items] | |||
Total revenues | $ 42,078 | $ 23,290 | $ 33,669 |
Crude Oil | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | 40,550 | 22,327 | 31,383 |
NGL | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | 2,399 | 1,475 | 2,323 |
Operating Segments | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | 42,949 | 23,802 | 33,706 |
Other items in revenues | (511) | (243) | 388 |
Total revenues | 42,438 | 23,559 | 34,094 |
Operating Segments | Crude Oil | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | 40,550 | 22,327 | 31,383 |
Other items in revenues | (80) | (128) | 272 |
Total revenues | 40,470 | 22,199 | 31,655 |
Operating Segments | NGL | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | 2,399 | 1,475 | 2,323 |
Other items in revenues | (431) | (115) | 116 |
Total revenues | 1,968 | 1,360 | 2,439 |
Intersegment revenues elimination | |||
Disaggregation of Revenue [Line Items] | |||
Total revenues | $ (360) | $ (269) | $ (425) |
Revenues and Accounts Receiva_6
Revenues and Accounts Receivable - Counterparty Deficiencies (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Contract With Customer, Asset And Liability [Line Items] | |||
Contract liability, deferred revenue | $ 141 | $ 501 | $ 354 |
Minimum Volume Commitments | |||
Contract With Customer, Asset And Liability [Line Items] | |||
Contract liability, deferred revenue | 63 | 73 | |
Counterparty deficiencies unbilled and uncollected | 16 | 4 | |
Counterparty deficiencies | $ 79 | $ 77 |
Revenues and Accounts Receiva_7
Revenues and Accounts Receivable - Contract Balances (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2021 | Mar. 31, 2020 | Dec. 31, 2021 | Dec. 31, 2020 | |
Change in Contract Liabilities [Roll Forward] | ||||
Beginning balance | $ 501 | $ 354 | $ 501 | $ 354 |
Amounts recognized as revenue | (393) | (246) | ||
Additions | 33 | 393 | ||
Ending balance | 141 | 501 | ||
Crude Oil Sales Agreements Entered Into In Conjunction WIth Storage Arrangements And Future Inventory Exchanges | ||||
Change in Contract Liabilities [Roll Forward] | ||||
Beginning balance | 361 | 361 | ||
Additions | $ 361 | $ 155 | ||
Ending balance | $ 0 | $ 361 |
Revenues and Accounts Receiva_8
Revenues and Accounts Receivable - Performance Obligations (Details) $ in Millions | Dec. 31, 2021USD ($) |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2022-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | $ 416 |
Remaining performance obligation, expected timing of satisfaction, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2023-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | $ 344 |
Remaining performance obligation, expected timing of satisfaction, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2024-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | $ 288 |
Remaining performance obligation, expected timing of satisfaction, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2025-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | $ 194 |
Remaining performance obligation, expected timing of satisfaction, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2026-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | $ 131 |
Remaining performance obligation, expected timing of satisfaction, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2027-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | $ 576 |
Remaining performance obligation, expected timing of satisfaction, period | |
Pipeline revenues supported by minimum volume commitments and 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 | $ 179 |
Remaining performance obligation, expected timing of satisfaction, period | 1 year |
Pipeline revenues supported by minimum volume commitments and 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 | $ 174 |
Remaining performance obligation, expected timing of satisfaction, period | 1 year |
Pipeline revenues supported by minimum volume commitments and 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 | $ 158 |
Remaining performance obligation, expected timing of satisfaction, period | 1 year |
Pipeline revenues supported by minimum volume commitments and 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 | $ 131 |
Remaining performance obligation, expected timing of satisfaction, period | 1 year |
Pipeline revenues supported by minimum volume commitments and capacity agreements | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2026-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | $ 86 |
Remaining performance obligation, expected timing of satisfaction, period | 1 year |
Pipeline revenues supported by minimum volume commitments and capacity agreements | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2027-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | $ 379 |
Remaining performance obligation, expected timing of satisfaction, period | |
Terminalling, storage and other agreement 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 | $ 237 |
Remaining performance obligation, expected timing of satisfaction, period | 1 year |
Terminalling, storage and other agreement 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 | $ 170 |
Remaining performance obligation, expected timing of satisfaction, period | 1 year |
Terminalling, storage and other agreement 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 | $ 130 |
Remaining performance obligation, expected timing of satisfaction, period | 1 year |
Terminalling, storage and other agreement 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 | $ 63 |
Remaining performance obligation, expected timing of satisfaction, period | 1 year |
Terminalling, storage and other agreement revenues | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2026-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | $ 45 |
Remaining performance obligation, expected timing of satisfaction, period | 1 year |
Terminalling, storage and other agreement revenues | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2027-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | $ 197 |
Remaining performance obligation, expected timing of satisfaction, period |
Revenues and Accounts Receiva_9
Revenues and Accounts Receivable - Narrative (Details) | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Revenue from Contract with Customer [Abstract] | ||
General payment terms | 30 days | |
Substantially all trade accounts receivable, net, maximum age of balances past their scheduled invoice date | 30 days | 30 days |
Revenues and Accounts Receiv_10
Revenues and Accounts Receivable - Contract Assets and Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Revenue from Contract with Customer [Abstract] | ||
Trade accounts receivable arising from revenues from contracts with customers | $ 4,031 | $ 2,317 |
Other trade accounts receivables and other receivables | 5,126 | 2,818 |
Impact due to contractual rights of offset with counterparties | (4,452) | (2,582) |
Trade accounts receivable and other receivables, net | $ 4,705 | $ 2,553 |
Net Income_(Loss) Per Common _3
Net Income/(Loss) Per Common Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Basic Net Income/(Loss) per Common Unit | |||
Net income/(loss) attributable to PAA | $ 593 | $ (2,590) | $ 2,171 |
Distributions to participating securities | (2) | (2) | (3) |
Other | 0 | 0 | (3) |
Net income/(loss) allocated to common unitholders | 393 | (2,790) | 1,967 |
Diluted Net Income/(Loss) per Common Unit | |||
Net income/(loss) attributable to PAA | 593 | (2,590) | 2,171 |
Distributions to participating securities | (2) | (2) | (3) |
Net income/(loss) allocated to common unitholders | $ 393 | $ (2,790) | 2,119 |
Equity-indexed Compensation Plan Award | Weighted Average | |||
Net Income Per Common Unit | |||
Antidilutive securities excluded from computation of earnings per unit (in units) | 0.5 | 0.3 | |
Series A Preferred Units | |||
Basic Net Income/(Loss) per Common Unit | |||
Distributions to preferred unitholders | $ (149) | $ (149) | (149) |
Diluted Net Income/(Loss) per Common Unit | |||
Distributions to preferred unitholders | $ (149) | $ (149) | 0 |
Series A Preferred Units | Weighted Average | |||
Net Income Per Common Unit | |||
Antidilutive securities excluded from computation of earnings per unit (in units) | 71 | 71 | |
Series B Preferred Units | |||
Basic Net Income/(Loss) per Common Unit | |||
Distributions to preferred unitholders | $ (49) | $ (49) | (49) |
Diluted Net Income/(Loss) per Common Unit | |||
Distributions to preferred unitholders | $ (49) | $ (49) | $ (49) |
Common Units | |||
Basic Net Income/(Loss) per Common Unit | |||
Basic weighted average common units outstanding (in units) | 716 | 728 | 727 |
Basic net income/(loss) per common unit (in dollars per unit) | $ 0.55 | $ (3.83) | $ 2.70 |
Diluted Net Income/(Loss) per Common Unit | |||
Basic weighted average common units outstanding (in units) | 716 | 728 | 727 |
Effect of dilutive securities: | |||
Series A preferred units (in units) | 0 | 0 | 71 |
Equity-indexed compensation plan awards (in units) | 0 | 0 | 2 |
Diluted weighted average common units outstanding (in units) | 716 | 728 | 800 |
Diluted net income/(loss) per common unit (in dollars per unit) | $ 0.55 | $ (3.83) | $ 2.65 |
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, 2021USD ($)$ / bbl$ / McfbblMcf | Dec. 31, 2020USD ($)$ / bbl$ / McfbblMcf | Dec. 31, 2019USD ($) | Jun. 30, 2021USD ($) | |
Inventory-related disclosures | ||||
Charge related to the write-down of inventory | $ 0 | $ 233 | $ 11 | |
Charge related to the write-down of inventory, long-term inventory | 40 | |||
Inventory by category | ||||
Inventory | 783 | 647 | ||
Linefill and base gas | 907 | 982 | ||
Long-term inventory | 253 | 130 | ||
Total | $ 1,943 | $ 1,759 | ||
Crude oil | ||||
Inventory by category | ||||
Inventory, Volumes (in barrels or in Mcf) | bbl | 8,041 | 13,450 | ||
Linefill and base gas, Volumes (in barrels or in Mcf) | bbl | 15,199 | 14,669 | ||
Long-term inventory, Volumes (in barrels or in Mcf) | bbl | 2,973 | 2,499 | ||
Inventory | $ 544 | $ 441 | ||
Linefill and base gas | 862 | 828 | ||
Long-term inventory | $ 209 | $ 111 | ||
Inventory, Price/Unit of measure (in dollars per unit) | $ / bbl | 67.65 | 32.79 | ||
Linefill and base gas, Price/Unit of measure (in dollars per unit) | $ / bbl | 56.71 | 56.45 | ||
Long-term inventory, Price/Unit of measure (in dollars per unit) | $ / bbl | 70.30 | 44.42 | ||
NGL | ||||
Inventory by category | ||||
Inventory, Volumes (in barrels or in Mcf) | bbl | 6,982 | 12,302 | ||
Linefill and base gas, Volumes (in barrels or in Mcf) | bbl | 1,633 | 1,640 | ||
Long-term inventory, Volumes (in barrels or in Mcf) | bbl | 1,135 | 1,185 | ||
Inventory | $ 234 | $ 199 | ||
Linefill and base gas | 45 | 44 | ||
Long-term inventory | $ 44 | $ 19 | ||
Inventory, Price/Unit of measure (in dollars per unit) | $ / bbl | 33.51 | 16.18 | ||
Linefill and base gas, Price/Unit of measure (in dollars per unit) | $ / bbl | 27.56 | 26.83 | ||
Long-term inventory, Price/Unit of measure (in dollars per unit) | $ / bbl | 38.77 | 16.03 | ||
Natural gas | ||||
Inventory by category | ||||
Linefill and base gas, Volumes (in barrels or in Mcf) | Mcf | 0 | 25,576 | ||
Linefill and base gas | $ 0 | $ 110 | ||
Linefill and base gas, Price/Unit of measure (in dollars per unit) | $ / Mcf | 0 | 4.30 | ||
Natural gas | Disposed of by sale | Pine Prairie and Southern Pines Natural Gas Storage Facilities | ||||
Inventory by category | ||||
Linefill and base gas | $ 110 | |||
Other | ||||
Inventory by category | ||||
Inventory | $ 5 | $ 7 |
Property and Equipment (Details
Property and Equipment (Details) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2021 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Property and Equipment | ||||
Capitalized interest | $ 18 | $ 24 | $ 34 | |
Property and equipment, gross | 19,257 | 18,585 | ||
Accumulated depreciation | (4,354) | (3,974) | ||
Property and equipment, net | 14,903 | 14,611 | ||
Depreciation expense | 652 | 563 | 525 | |
Construction in progress expenditures incurred but not yet paid | 48 | $ 51 | $ 120 | |
Level 3 | Measurement Input, Discount Rate | Valuation Technique, Discounted Cash Flow | ||||
Property and Equipment | ||||
Discount rate, asset impairment analysis, cost of capital, theoretical market participant | 14.00% | |||
(Gains)/losses on asset sales and asset impairments, net | ||||
Property and Equipment | ||||
Non-cash impairment losses, long-lived assets | $ 541 | |||
Crude Oil | Pipelines and related facilities | ||||
Property and Equipment | ||||
Non-cash impairment losses, long-lived assets | $ 415 | |||
Crude Oil | (Gains)/losses on asset sales and asset impairments, net | Crude Oil Storage Terminal Assets | ||||
Property and Equipment | ||||
Non-cash impairment losses, long-lived assets | 220 | |||
Service Life | ||||
Property and Equipment | ||||
Depreciation expense | $ 72 | |||
Common Units | ||||
Property and Equipment | ||||
Impact to basic net income per common unit (in dollars per unit) | $ 0.55 | $ (3.83) | $ 2.70 | |
Impact to diluted net income per common unit (in dollars per unit) | 0.55 | $ (3.83) | $ 2.65 | |
Common Units | Service Life | ||||
Property and Equipment | ||||
Impact to basic net income per common unit (in dollars per unit) | (0.10) | |||
Impact to diluted net income per common unit (in dollars per unit) | $ (0.10) | |||
Pipelines and related facilities | ||||
Property and Equipment | ||||
Property and equipment, gross | $ 12,765 | $ 11,112 | ||
Pipelines and related facilities | Minimum | ||||
Property and Equipment | ||||
Estimated Useful Lives (in years) | 10 years | |||
Pipelines and related facilities | Maximum | ||||
Property and Equipment | ||||
Estimated Useful Lives (in years) | 50 years | |||
Storage, terminal and rail facilities | ||||
Property and Equipment | ||||
Property and equipment, gross | $ 5,100 | 6,042 | ||
Storage, terminal and rail facilities | Minimum | ||||
Property and Equipment | ||||
Estimated Useful Lives (in years) | 10 years | |||
Storage, terminal and rail facilities | Maximum | ||||
Property and Equipment | ||||
Estimated Useful Lives (in years) | 50 years | |||
Trucking equipment and other | ||||
Property and Equipment | ||||
Property and equipment, gross | $ 502 | 524 | ||
Trucking equipment and other | Minimum | ||||
Property and Equipment | ||||
Estimated Useful Lives (in years) | 2 years | |||
Trucking equipment and other | Maximum | ||||
Property and Equipment | ||||
Estimated Useful Lives (in years) | 15 years | |||
Construction in progress | ||||
Property and Equipment | ||||
Property and equipment, gross | $ 248 | 272 | ||
Office property and equipment | ||||
Property and Equipment | ||||
Property and equipment, gross | $ 312 | 293 | ||
Office property and equipment | Minimum | ||||
Property and Equipment | ||||
Estimated Useful Lives (in years) | 2 years | |||
Office property and equipment | Maximum | ||||
Property and Equipment | ||||
Estimated Useful Lives (in years) | 50 years | |||
Land and other | ||||
Property and Equipment | ||||
Property and equipment, gross | $ 330 | $ 342 | ||
Pipeline and related facilities and Storage, terminal and rail facilities | Minimum | ||||
Property and Equipment | ||||
Estimated Useful Lives (in years) | 10 years | |||
Pipeline and related facilities and Storage, terminal and rail facilities | Minimum | Service Life | ||||
Property and Equipment | ||||
Estimated Useful Lives (in years) | 10 years | |||
Pipeline and related facilities and Storage, terminal and rail facilities | Maximum | ||||
Property and Equipment | ||||
Estimated Useful Lives (in years) | 70 years | |||
Pipeline and related facilities and Storage, terminal and rail facilities | Maximum | Service Life | ||||
Property and Equipment | ||||
Estimated Useful Lives (in years) | 50 years | |||
Property and equipment | ||||
Property and Equipment | ||||
Capitalized interest | $ 6 | $ 8 | $ 14 |
Acquisitions, Divestitures an_3
Acquisitions, Divestitures and Other Transactions - Joint Venture Transaction (Details) $ in Millions | 1 Months Ended | 3 Months Ended | 12 Months Ended | |
Oct. 31, 2021USD ($) | Dec. 31, 2021USD ($) | Dec. 31, 2021USD ($) | Dec. 31, 2020USD ($) | |
Business Acquisition [Line Items] | ||||
Amortization expense | $ 1,960 | $ 1,960 | $ 805 | |
Customer relationships | ||||
Business Acquisition [Line Items] | ||||
Amortization expense | $ 1,935 | $ 1,935 | $ 772 | |
Customer relationships | Minimum | ||||
Business Acquisition [Line Items] | ||||
Estimated Useful Lives (in years) | 3 years | |||
Customer relationships | Maximum | ||||
Business Acquisition [Line Items] | ||||
Estimated Useful Lives (in years) | 31 years | |||
Joint Venture Transaction | Plains Oryx Permian Basin LLC (Permian JV) | Customer relationships | ||||
Business Acquisition [Line Items] | ||||
Estimated Useful Lives (in years) | 20 years | |||
Amortization | $ 28 | |||
Joint Venture Transaction | Plains Oryx Permian Basin LLC (Permian JV) | Level 3 | ||||
Business Acquisition [Line Items] | ||||
Identifiable assets acquired and liabilities assumed | $ 3,256 | |||
Joint Venture Transaction | Plains Oryx Permian Basin LLC (Permian JV) | Level 3 | Measurement Input, Discount Rate | Valuation Technique, Discounted Cash Flow | ||||
Business Acquisition [Line Items] | ||||
Business combination, measurement input | 0.1175 | |||
Joint Venture Transaction | Plains Oryx Permian Basin LLC (Permian JV) | Level 3 | Measurement Input, Discount Rate | Valuation Technique, Discounted Cash Flow | Intangible Assets | ||||
Business Acquisition [Line Items] | ||||
Business combination, measurement input | 0.16 | |||
Joint Venture Transaction | Plains Oryx Permian Basin LLC (Permian JV) | Level 3 | Measurement Input, Market Multiple | Valuation, Market Approach | Minimum | ||||
Business Acquisition [Line Items] | ||||
Business combination, measurement input | 9.5 | |||
Joint Venture Transaction | Plains Oryx Permian Basin LLC (Permian JV) | Level 3 | Measurement Input, Market Multiple | Valuation, Market Approach | Maximum | ||||
Business Acquisition [Line Items] | ||||
Business combination, measurement input | 11 | |||
Plains Oryx Permian Basin LLC (Permian JV) | Joint Venture Transaction | ||||
Business Acquisition [Line Items] | ||||
Consolidated subsidiary, ownership interest held by the parent (as a percent) | 65.00% | |||
Plains Oryx Permian Basin LLC (Permian JV) | Joint Venture Transaction | Oryx Midstream Holdings LLC | ||||
Business Acquisition [Line Items] | ||||
Noncontrolling interest, ownership percentage | 35.00% | |||
Oryx Midstream Holdings LLC | Joint Venture Transaction | Plains Oryx Permian Basin LLC (Permian JV) | ||||
Business Acquisition [Line Items] | ||||
Identifiable assets acquired and liabilities assumed | $ 3,256 | |||
Estimated Useful Lives (in years) | 20 years | |||
Transaction-related costs | $ 17 | |||
Purchase price | $ 3,256 | |||
Oryx Midstream Holdings LLC | Plains Oryx Permian Basin LLC (Permian JV) | Joint Venture Transaction | ||||
Business Acquisition [Line Items] | ||||
Consolidated subsidiary, ownership interest held by the parent (as a percent) | 65.00% | |||
Stonepeak Infrastructure Partners | PAA | Series A Preferred Units | Stonepeak Infrastructure Partners, Affiliates | ||||
Business Acquisition [Line Items] | ||||
Limited partner interest | 8.90% | |||
Stonepeak Infrastructure Partners | PAA | Maximum | Limited Partners | Stonepeak Infrastructure Partners, Affiliates | ||||
Business Acquisition [Line Items] | ||||
Limited partner interest | 1.00% |
Acquisitions, Divestitures an_4
Acquisitions, Divestitures and Other Transactions - Partners' Capital (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended |
Oct. 31, 2021 | Dec. 31, 2021 | |
Business Acquisition [Line Items] | ||
Plains Oryx Permian Basin LLC joint venture formation (Note 7) | $ 3,256 | |
Noncontrolling Interests | ||
Business Acquisition [Line Items] | ||
Plains Oryx Permian Basin LLC joint venture formation (Note 7) | 2,651 | |
Partners’ Capital Excluding Noncontrolling Interests | ||
Business Acquisition [Line Items] | ||
Plains Oryx Permian Basin LLC joint venture formation (Note 7) | $ 605 | |
Joint Venture Transaction | Plains Oryx Permian Basin LLC (Permian JV) | ||
Business Acquisition [Line Items] | ||
Members' Equity | $ 7,575 | |
Plains Oryx Permian Basin LLC (Permian JV) | Joint Venture Transaction | Noncontrolling Interests | Oryx Midstream Holdings LLC | ||
Business Acquisition [Line Items] | ||
Plains Oryx Permian Basin LLC joint venture formation (Note 7) | 2,651 | |
Plains Oryx Permian Basin LLC (Permian JV) | Joint Venture Transaction | Partners’ Capital Excluding Noncontrolling Interests | ||
Business Acquisition [Line Items] | ||
Plains Oryx Permian Basin LLC joint venture formation (Note 7) | 605 | |
Plains Oryx Permian Basin LLC (Permian JV) | Oryx Midstream Holdings LLC | Joint Venture Transaction | ||
Business Acquisition [Line Items] | ||
Plains Oryx Permian Basin LLC joint venture formation (Note 7) | $ 3,256 |
Acquisitions, Divestitures an_5
Acquisitions, Divestitures and Other Transactions - Assets Acquired and Liabilities Assumed (Details) - Plains Oryx Permian Basin LLC (Permian JV) - Joint Venture Transaction $ in Millions | 1 Months Ended |
Oct. 31, 2021USD ($) | |
Level 3 | |
Business Acquisition [Line Items] | |
Identifiable assets acquired and liabilities assumed | $ 3,256 |
Oryx Midstream Holdings LLC | |
Business Acquisition [Line Items] | |
Property and equipment | 1,886 |
Intangible assets | 1,247 |
Investment in unconsolidated entities | 103 |
Linefill | 5 |
Working capital and other assets and liabilities | 15 |
Identifiable assets acquired and liabilities assumed | $ 3,256 |
Estimated Useful Lives (in years) | 20 years |
Oryx Midstream Holdings LLC | Minimum | |
Business Acquisition [Line Items] | |
Estimated Useful Lives (in years) | 3 years |
Oryx Midstream Holdings LLC | Maximum | |
Business Acquisition [Line Items] | |
Estimated Useful Lives (in years) | 30 years |
Acquisitions, Divestitures an_6
Acquisitions, Divestitures and Other Transactions - Future Amortization Expense (Details) $ in Millions | Dec. 31, 2021USD ($) |
Business Acquisition [Line Items] | |
2022 | $ 240 |
2023 | 232 |
2024 | 220 |
2025 | 207 |
2026 | 187 |
Customer relationships | Plains Oryx Permian Basin LLC (Permian JV) | Joint Venture Transaction | |
Business Acquisition [Line Items] | |
2022 | 142 |
2023 | 138 |
2024 | 127 |
2025 | 117 |
2026 | $ 106 |
Acquisitions, Divestitures an_7
Acquisitions, Divestitures and Other Transactions - Modified Sharing Arrangement (Details) - Plains Oryx Permian Basin LLC (Permian JV) - Modified Sharing Arrangement [Member] | 12 Months Ended |
Dec. 31, 2021 | |
Oryx Midstream Holdings LLC | |
Business Acquisition [Line Items] | |
Distribution percentage after termination of modified sharing arrangement | 0.65 |
Oryx Midstream Holdings LLC | Maximum | |
Business Acquisition [Line Items] | |
Modified revenue sharing arrangement, term | 10 years |
Up to $300 | |
Business Acquisition [Line Items] | |
Modified sharing arrangement, distribution percentage | 50.00% |
$300 - $428 | |
Business Acquisition [Line Items] | |
Modified sharing arrangement, distribution percentage | 100.00% |
$428 - $815 | |
Business Acquisition [Line Items] | |
Modified sharing arrangement, distribution percentage | 65.00% |
$815 and above | |
Business Acquisition [Line Items] | |
Modified sharing arrangement, distribution percentage | 70.00% |
Oryx Midstream Holdings LLC | Oryx Midstream Holdings LLC | |
Business Acquisition [Line Items] | |
Distribution percentage after termination of modified sharing arrangement | 0.35 |
Oryx Midstream Holdings LLC | Up to $300 | |
Business Acquisition [Line Items] | |
Modified sharing arrangement, distribution percentage | 50.00% |
Oryx Midstream Holdings LLC | $300 - $428 | |
Business Acquisition [Line Items] | |
Modified sharing arrangement, distribution percentage | 0.00% |
Oryx Midstream Holdings LLC | $428 - $815 | |
Business Acquisition [Line Items] | |
Modified sharing arrangement, distribution percentage | 35.00% |
Oryx Midstream Holdings LLC | $815 and above | |
Business Acquisition [Line Items] | |
Modified sharing arrangement, distribution percentage | 30.00% |
Acquisitions, Divestitures an_8
Acquisitions, Divestitures and Other Transactions - Pro Forma (Details) - Plains Oryx Permian Basin LLC (Permian JV) - Oryx Midstream Holdings LLC - Joint Venture Transaction - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Business Acquisition [Line Items] | ||
Total revenues | $ 42,359 | $ 23,536 |
Net income/(loss) attributable to PAA | 524 | (2,898) |
Net income/(loss) allocated to common unitholders | $ 324 | $ (3,098) |
Basic net income/(loss) per common unit (in shares) | $ 0.45 | $ (4.26) |
Diluted net income/(loss) per common unit (in shares) | $ 0.45 | $ (4.26) |
Acquisitions, Divestitures an_9
Acquisitions, Divestitures and Other Transactions - Asset Exchange (Details) $ in Millions | 1 Months Ended | 12 Months Ended | ||
Jun. 30, 2021USD ($)plant | Dec. 31, 2021USD ($) | Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | |
Business Acquisition [Line Items] | ||||
Gain on divestiture of assets | $ (592) | $ (719) | $ (28) | |
(Gains)/losses on asset sales and asset impairments, net | ||||
Business Acquisition [Line Items] | ||||
Gain on divestiture of assets | $ 178 | |||
Inter Pipeline Ltd | Asset Exchange Transaction | (Gains)/losses on asset sales and asset impairments, net | ||||
Business Acquisition [Line Items] | ||||
Gain on divestiture of assets | $ 106 | |||
Additional Interests in Straddle Plants | Inter Pipeline Ltd | Asset Exchange Transaction | ||||
Business Acquisition [Line Items] | ||||
Cash consideration, including working capital and other adjustments | $ 32 | |||
Additional Interests in Straddle Plants | Inter Pipeline Ltd | NGL | Asset Exchange Transaction | ||||
Business Acquisition [Line Items] | ||||
Number of straddle plants, additional interests acquired | plant | 2 |
Acquisitions, Divestitures a_10
Acquisitions, Divestitures and Other Transactions - Acquisitions (Details) $ in Millions | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||
Feb. 29, 2020USD ($) | Jun. 30, 2019USD ($) | Dec. 31, 2021USD ($) | Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | |
Business Acquisition [Line Items] | |||||
Payments to acquire businesses | $ 32 | $ 310 | $ 50 | ||
Crude Oil Terminal | |||||
Business Acquisition [Line Items] | |||||
Cash consideration | $ 44 | ||||
FM Gathering LLC | |||||
Business Acquisition [Line Items] | |||||
Payments to acquire businesses | $ 300 | ||||
Property and equipment acquired | 115 | ||||
Intangible assets acquired | $ 187 | ||||
FM Gathering LLC | Minimum | Level 3 | Measurement Input, Discount Rate | Valuation Technique, Discounted Cash Flow | Intangible Assets | |||||
Business Acquisition [Line Items] | |||||
Business combination, measurement input | 0.18 | ||||
FM Gathering LLC | Maximum | Level 3 | Measurement Input, Discount Rate | Valuation Technique, Discounted Cash Flow | Intangible Assets | |||||
Business Acquisition [Line Items] | |||||
Business combination, measurement input | 0.19 |
Acquisitions, Divestitures a_11
Acquisitions, Divestitures and Other Transactions - Divestitures (Details) - USD ($) $ in Millions | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||||
Aug. 31, 2021 | Feb. 29, 2020 | Jun. 30, 2021 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Jul. 31, 2021 | |
Divestitures | |||||||
Proceeds from sales of assets | $ 881 | $ 429 | $ 77 | ||||
Deferred losses on hedges remaining in other comprehensive income | (9,972) | (9,593) | |||||
Proceeds from sale, including proceeds attributable to agreements entered into in conjunction with sale of productive assets | 451 | ||||||
Gains/(losses) on asset sales and asset impairments, net | $ (592) | (719) | (28) | ||||
Crude Oil | Natural Gas, Storage | |||||||
Divestitures | |||||||
Proceeds from sales of assets | $ 850 | ||||||
(Gains)/losses on asset sales and asset impairments, net | |||||||
Divestitures | |||||||
Gains/(losses) on asset sales and asset impairments, net | 178 | ||||||
Pine Prairie and Southern Pines Natural Gas Storage Facilities | Held for sale | |||||||
Divestitures | |||||||
Assets held for sale, current | $ 832 | ||||||
Pine Prairie and Southern Pines Natural Gas Storage Facilities | Disposed of by sale | (Gains)/losses on asset sales and asset impairments, net | |||||||
Divestitures | |||||||
Non-cash impairment losses upon classification to assets held for sale | $ 475 | ||||||
Los Angeles Basin Crude Oil Terminals | Disposed of by sale | Crude Oil | |||||||
Divestitures | |||||||
Proceeds from sales of assets | 200 | ||||||
NGL Terminals | Disposed of by sale | |||||||
Divestitures | |||||||
Proceeds attributable to multi-year supply agreement entered into in conjunction with sale of assets | 22 | ||||||
NGL Terminals | Disposed of by sale | NGL | |||||||
Divestitures | |||||||
Proceeds from sale, including proceeds attributable to agreements entered into in conjunction with sale of productive assets | $ 163 | ||||||
North Dakota Storage Terminals | Disposed of by sale | Crude Oil | |||||||
Divestitures | |||||||
Proceeds from sales of assets | 77 | ||||||
North Dakota Storage Terminals | Disposed of by sale | (Gains)/losses on asset sales and asset impairments, net | |||||||
Divestitures | |||||||
Recognized gains/(losses) related to sale of assets, net | 16 | ||||||
Recognized gains related to sale of assets | 31 | ||||||
Recognized losses related to sale of assets | $ 47 | ||||||
Saddlehorn Pipeline Company, LLC | |||||||
Divestitures | |||||||
Ownership percentage sold | 10.00% | 10.00% | |||||
Proceeds from sale of interest in unconsolidated entity | $ 78 | $ 78 | |||||
Derivative Instruments | Pine Prairie and Southern Pines Natural Gas Storage Facilities | Held for sale | |||||||
Divestitures | |||||||
Deferred losses on hedges remaining in other comprehensive income | $ 18 |
Goodwill (Details)
Goodwill (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2020 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Changes in goodwill | ||||
Balance at beginning of period | $ 2,540 | $ 0 | $ 2,540 | |
Acquisitions | 2 | |||
Goodwill, gross | 2,542 | |||
Goodwill impairment losses | 2,515 | 0 | 2,515 | $ 0 |
Foreign currency translation adjustments | (27) | |||
Accumulated impairment losses | (2,542) | |||
Balance at end of period | 0 | 2,540 | ||
Operating Segments | Crude Oil | ||||
Changes in goodwill | ||||
Balance at beginning of period | 2,300 | 0 | 2,300 | |
Acquisitions | 2 | |||
Goodwill, gross | 2,302 | |||
Goodwill impairment losses | 2,287 | |||
Foreign currency translation adjustments | (15) | |||
Accumulated impairment losses | (2,302) | |||
Balance at end of period | 0 | 2,300 | ||
Operating Segments | NGL | ||||
Changes in goodwill | ||||
Balance at beginning of period | $ 240 | $ 0 | 240 | |
Acquisitions | 0 | |||
Goodwill, gross | 240 | |||
Goodwill impairment losses | 228 | |||
Foreign currency translation adjustments | (12) | |||
Accumulated impairment losses | (240) | |||
Balance at end of period | $ 0 | $ 240 | ||
Level 3 | Valuation Technique, Discounted Cash Flow | ||||
Goodwill | ||||
Goodwill impairment analysis, projected cash flows, period | 6 years | |||
Level 3 | Valuation Technique, Discounted Cash Flow | Measurement Input, Discount Rate | ||||
Goodwill | ||||
Goodwill impairment analysis, discount rate, cost of capital, theoretical market participant | 14.00% |
Investments in Unconsolidated_3
Investments in Unconsolidated Entities - Equity Method Investments (Details) - USD ($) $ in Millions | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||||||
Feb. 29, 2020 | Sep. 30, 2020 | Jun. 30, 2020 | Mar. 31, 2020 | Mar. 31, 2019 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Jun. 30, 2019 | |
Investments in Unconsolidated Entities | |||||||||
Investments in unconsolidated entities | $ 3,805 | $ 3,764 | $ 3,683 | ||||||
Capital contributions to equity method investees excluding capitalized interest | 82 | 445 | 504 | ||||||
Capitalized interest related to contributions to unconsolidated entities | 18 | 24 | 34 | ||||||
Amount by which investments in unconsolidated entities exceeded our share of the underlying equity in the net assets | 223 | 170 | |||||||
Equity Method Investees | |||||||||
Investments in Unconsolidated Entities | |||||||||
Capitalized interest related to contributions to unconsolidated entities | $ 12 | $ 16 | 20 | ||||||
Capline Pipeline Company LLC | Capline pipeline system | |||||||||
Investments in Unconsolidated Entities | |||||||||
Percentage of Capline pipeline system owned | 100.00% | ||||||||
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 | ||||||||
Level 3 | Measurement Input, Discount Rate | Valuation Technique, Discounted Cash Flow | |||||||||
Investments in Unconsolidated Entities | |||||||||
Discount rate, asset impairment analysis, cost of capital, theoretical market participant | 14.00% | ||||||||
BridgeTex Pipeline Company, LLC (“BridgeTex”) | |||||||||
Investments in Unconsolidated Entities | |||||||||
Ownership interest in unconsolidated entity | 20.00% | ||||||||
Investments in unconsolidated entities | $ 406 | $ 421 | |||||||
Cactus II Pipeline LLC (“Cactus II”) | |||||||||
Investments in Unconsolidated Entities | |||||||||
Ownership interest in unconsolidated entity | 65.00% | ||||||||
Investments in unconsolidated entities | $ 737 | 752 | |||||||
Capline Pipeline Company LLC | |||||||||
Investments in Unconsolidated Entities | |||||||||
Ownership interest in unconsolidated entity | 54.00% | ||||||||
Investments in unconsolidated entities | $ 531 | 514 | |||||||
Fair value of investment in unconsolidated entity | $ 444 | ||||||||
Capline Pipeline Company LLC | Gain on/(impairment of) investments in unconsolidated entities, net | |||||||||
Investments in Unconsolidated Entities | |||||||||
Gain from remeasurement to fair value of retained investment | $ 269 | ||||||||
Diamond Pipeline LLC (“Diamond”) | |||||||||
Investments in Unconsolidated Entities | |||||||||
Ownership interest in unconsolidated entity | 50.00% | ||||||||
Investments in unconsolidated entities | $ 464 | 480 | |||||||
Eagle Ford Pipeline LLC (“Eagle Ford Pipeline”) | |||||||||
Investments in Unconsolidated Entities | |||||||||
Ownership interest in unconsolidated entity | 50.00% | ||||||||
Investments in unconsolidated entities | $ 363 | 372 | |||||||
Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Terminals”) | |||||||||
Investments in Unconsolidated Entities | |||||||||
Ownership interest in unconsolidated entity | 50.00% | ||||||||
Investments in unconsolidated entities | $ 120 | 122 | |||||||
OMOG JV LLC | |||||||||
Investments in Unconsolidated Entities | |||||||||
Ownership interest in unconsolidated entity | 40.00% | ||||||||
Investments in unconsolidated entities | $ 102 | ||||||||
Saddlehorn | |||||||||
Investments in Unconsolidated Entities | |||||||||
Ownership interest in unconsolidated entity | 30.00% | 30.00% | |||||||
Investments in unconsolidated entities | $ 209 | $ 208 | |||||||
Ownership percentage sold | 10.00% | 10.00% | |||||||
Proceeds from sale of interest in unconsolidated entity | $ 78 | $ 78 | |||||||
Saddlehorn | Gain on/(impairment of) investments in unconsolidated entities, net | |||||||||
Investments in Unconsolidated Entities | |||||||||
Gain on sale of investment in unconsolidated entities | $ 21 | ||||||||
White Cliffs Pipeline, LLC | |||||||||
Investments in Unconsolidated Entities | |||||||||
Ownership interest in unconsolidated entity | 36.00% | ||||||||
Investments in unconsolidated entities | $ 171 | 192 | |||||||
Wink to Webster Pipeline LLC (“W2W Pipeline”) | |||||||||
Investments in Unconsolidated Entities | |||||||||
Ownership interest in unconsolidated entity | 16.00% | ||||||||
Investments in unconsolidated entities | $ 345 | 330 | |||||||
Other investments | |||||||||
Investments in Unconsolidated Entities | |||||||||
Investments in unconsolidated entities | $ 357 | $ 373 | |||||||
Write down of investments | $ 43 | ||||||||
STACK Pipeline LLC (“STACK”) | |||||||||
Investments in Unconsolidated Entities | |||||||||
Write down of investments | $ 91 | ||||||||
STACK Pipeline LLC (“STACK”) | Level 3 | Measurement Input, Discount Rate | Valuation Technique, Discounted Cash Flow | |||||||||
Investments in Unconsolidated Entities | |||||||||
Discount rate, asset impairment analysis, cost of capital, theoretical market participant | 14.00% | ||||||||
Red Oak Pipeline LLC (“Red Oak”) | |||||||||
Investments in Unconsolidated Entities | |||||||||
Ownership interest in unconsolidated entity | 50.00% | ||||||||
Write down of investments | $ 69 |
Investments in Unconsolidated_4
Investments in Unconsolidated Entities - Summarized Financial Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Investments in Unconsolidated Entities | |||
Current assets | $ 6,137 | $ 3,665 | |
Current liabilities | 6,232 | 4,253 | |
Noncurrent liabilities | 9,567 | 10,506 | |
Revenues | 42,078 | 23,290 | $ 33,669 |
Operating income | 851 | (2,375) | 1,988 |
Equity Method Investment, Nonconsolidated Investee | |||
Investments in Unconsolidated Entities | |||
Current assets | 509 | 580 | |
Noncurrent assets | 8,879 | 8,769 | |
Current liabilities | 366 | 343 | |
Noncurrent liabilities | 15 | 10 | |
Revenues | 1,320 | 1,360 | 1,469 |
Operating income | 505 | 828 | 994 |
Net income | $ 506 | $ 826 | $ 995 |
Intangible Asset, Net - Schedul
Intangible Asset, Net - Schedule of Intangible Assets (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Finite-Lived Intangible Assets | ||
Cost | $ 2,481 | $ 1,354 |
Accumulated Amortization | (521) | (549) |
Net | 1,960 | 805 |
Customer contracts and relationships | ||
Finite-Lived Intangible Assets | ||
Cost | 2,445 | 1,291 |
Accumulated Amortization | (510) | (519) |
Net | $ 1,935 | 772 |
Customer contracts and relationships | Minimum | ||
Finite-Lived Intangible Assets | ||
Estimated useful lives | 3 years | |
Customer contracts and relationships | Maximum | ||
Finite-Lived Intangible Assets | ||
Estimated useful lives | 31 years | |
Other agreements | ||
Finite-Lived Intangible Assets | ||
Cost | $ 36 | 63 |
Accumulated Amortization | (11) | (30) |
Net | $ 25 | $ 33 |
Other agreements | Minimum | ||
Finite-Lived Intangible Assets | ||
Estimated useful lives | 1 year | |
Other agreements | Maximum | ||
Finite-Lived Intangible Assets | ||
Estimated useful lives | 70 years |
Intangible Asset, Net - Amortiz
Intangible Asset, Net - Amortization Expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |||
Amortization expense for finite-lived intangible assets | $ 122 | $ 90 | $ 76 |
Estimated amortization expense related to finite-lived intangible assets for the next five years | |||
2022 | 240 | ||
2023 | 232 | ||
2024 | 220 | ||
2025 | 207 | ||
2026 | $ 187 |
Debt - Schedule of Debt (Detail
Debt - Schedule of Debt (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2021 | Dec. 31, 2019 | |
SHORT-TERM DEBT | |||
Short-term debt | $ 831 | $ 822 | |
LONG-TERM DEBT | |||
Senior notes, net of unamortized discounts and debt issuance costs | 9,071 | 8,329 | |
Noncurrent portion of other long-term debt | 311 | 69 | |
Total long-term debt | 9,382 | 8,398 | |
Total debt | 10,213 | 9,220 | |
Senior notes | |||
LONG-TERM DEBT | |||
Unamortized discounts and debt issuance costs | (62) | (54) | |
Senior notes, net of unamortized discounts and debt issuance costs | 9,071 | 8,329 | |
Senior notes repurchase amount | 17 | ||
Debt instrument face value | 9,100 | 9,100 | |
Senior notes | Other income/(expense), net | |||
LONG-TERM DEBT | |||
Gain on repurchase of senior notes | 3 | ||
Senior notes | Level 2 | |||
LONG-TERM DEBT | |||
Debt instrument fair value | 9,900 | $ 9,900 | |
Senior notes | 3.65% senior notes due June 2022 | |||
SHORT-TERM DEBT | |||
Debt instrument, interest rate (as a percent) | 3.65% | ||
LONG-TERM DEBT | |||
Long-term debt, before deducting unamortized discounts and debt issuance costs | 750 | $ 0 | |
Senior notes | 2.85% senior notes due January 2023 | |||
SHORT-TERM DEBT | |||
Debt instrument, interest rate (as a percent) | 2.85% | ||
LONG-TERM DEBT | |||
Long-term debt, before deducting unamortized discounts and debt issuance costs | 400 | $ 400 | |
Senior notes | 3.85% senior notes due October 2023 | |||
SHORT-TERM DEBT | |||
Debt instrument, interest rate (as a percent) | 3.85% | ||
LONG-TERM DEBT | |||
Long-term debt, before deducting unamortized discounts and debt issuance costs | 700 | $ 700 | |
Senior notes | 3.60% senior notes due November 2024 | |||
SHORT-TERM DEBT | |||
Debt instrument, interest rate (as a percent) | 3.60% | ||
LONG-TERM DEBT | |||
Long-term debt, before deducting unamortized discounts and debt issuance costs | 750 | $ 750 | |
Senior notes | 4.65% senior notes due October 2025 | |||
SHORT-TERM DEBT | |||
Debt instrument, interest rate (as a percent) | 4.65% | ||
LONG-TERM DEBT | |||
Long-term debt, before deducting unamortized discounts and debt issuance costs | 1,000 | $ 1,000 | |
Senior notes | 4.50% senior notes due December 2026 | |||
SHORT-TERM DEBT | |||
Debt instrument, interest rate (as a percent) | 4.50% | ||
LONG-TERM DEBT | |||
Long-term debt, before deducting unamortized discounts and debt issuance costs | 750 | $ 750 | |
Senior notes | 3.55% senior notes due December 2029 | |||
SHORT-TERM DEBT | |||
Debt instrument, interest rate (as a percent) | 3.55% | 3.55% | |
LONG-TERM DEBT | |||
Long-term debt, before deducting unamortized discounts and debt issuance costs | $ 1,000 | $ 1,000 | |
Debt instrument face value | $ 1,000 | ||
Senior notes | 3.80% senior notes due September 2030 | |||
SHORT-TERM DEBT | |||
Debt instrument, interest rate (as a percent) | 3.80% | 3.80% | |
LONG-TERM DEBT | |||
Long-term debt, before deducting unamortized discounts and debt issuance costs | $ 750 | $ 750 | |
Debt instrument face value | 750 | ||
Senior notes | 6.70% senior notes due May 2036 | |||
SHORT-TERM DEBT | |||
Debt instrument, interest rate (as a percent) | 6.70% | ||
LONG-TERM DEBT | |||
Long-term debt, before deducting unamortized discounts and debt issuance costs | 250 | $ 250 | |
Senior notes | 6.65% senior notes due January 2037 | |||
SHORT-TERM DEBT | |||
Debt instrument, interest rate (as a percent) | 6.65% | ||
LONG-TERM DEBT | |||
Long-term debt, before deducting unamortized discounts and debt issuance costs | 600 | $ 600 | |
Senior notes | 5.15% senior notes due June 2042 | |||
SHORT-TERM DEBT | |||
Debt instrument, interest rate (as a percent) | 5.15% | ||
LONG-TERM DEBT | |||
Long-term debt, before deducting unamortized discounts and debt issuance costs | 499 | $ 499 | |
Senior notes | 4.30% senior notes due January 2043 | |||
SHORT-TERM DEBT | |||
Debt instrument, interest rate (as a percent) | 4.30% | ||
LONG-TERM DEBT | |||
Long-term debt, before deducting unamortized discounts and debt issuance costs | 348 | $ 348 | |
Senior notes | 4.70% senior notes due June 2044 | |||
SHORT-TERM DEBT | |||
Debt instrument, interest rate (as a percent) | 4.70% | ||
LONG-TERM DEBT | |||
Long-term debt, before deducting unamortized discounts and debt issuance costs | 687 | $ 687 | |
Senior notes | 4.90% senior notes due February 2045 | |||
SHORT-TERM DEBT | |||
Debt instrument, interest rate (as a percent) | 4.90% | ||
LONG-TERM DEBT | |||
Long-term debt, before deducting unamortized discounts and debt issuance costs | 649 | $ 649 | |
Term Loan | GO Zone Term Loans | |||
LONG-TERM DEBT | |||
Noncurrent portion of other long-term debt | 199 | ||
Debt issuance costs | $ 1 | ||
Weighted average long term debt interest rate | 1.30% | ||
Other long-term debt | |||
LONG-TERM DEBT | |||
Noncurrent portion of other long-term debt | $ 112 | 69 | |
Line of Credit | Commercial Paper | |||
SHORT-TERM DEBT | |||
Short-term notes and borrowings | $ 547 | 0 | |
Weighted average interest rate, short-term (as a percent) | 0.70% | ||
Line of Credit | Senior secured hedged inventory facility | |||
SHORT-TERM DEBT | |||
Short-term notes and borrowings | $ 167 | 0 | |
Weighted average interest rate, short-term (as a percent) | 1.20% | ||
Senior notes | 3.65% senior notes due June 2022 | |||
SHORT-TERM DEBT | |||
Short-term notes and borrowings | $ 0 | $ 750 | |
Debt instrument, interest rate (as a percent) | 3.65% | ||
Other | |||
SHORT-TERM DEBT | |||
Short-term debt | $ 117 | $ 72 |
Debt - Commercial Paper and Cre
Debt - Commercial Paper and Credit Facilities (Details) $ in Millions | 1 Months Ended | |||
Aug. 31, 2021USD ($)extension | Dec. 31, 2021USD ($) | Jul. 31, 2021USD ($) | Aug. 31, 2018USD ($)debtInstrument | |
Commercial Paper | ||||
Debt Instrument [Line Items] | ||||
Maximum aggregate borrowing capacity | $ 2,700 | |||
Senior secured hedged inventory facility | ||||
Debt Instrument [Line Items] | ||||
Maximum aggregate borrowing capacity | $ 1,900 | |||
Committed borrowing capacity | $ 1,350 | $ 1,400 | ||
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 | |||
Senior unsecured revolving credit facility | ||||
Debt Instrument [Line Items] | ||||
Maximum aggregate borrowing capacity | 2,100 | |||
Committed borrowing capacity | $ 1,350 | $ 1,600 | ||
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 | |||
Senior unsecured revolving credit facility | Letters of credit | ||||
Debt Instrument [Line Items] | ||||
Committed borrowing capacity | $ 400 | |||
GO Zone Term Loans | Term Loan | ||||
Debt Instrument [Line Items] | ||||
Number of debt instruments | debtInstrument | 2 | |||
GO Zone Term Loan Series 2009 | Term Loan | ||||
Debt Instrument [Line Items] | ||||
Debt instrument face value | $ 100 | |||
GO Zone Term Loan Series 2010 | Term Loan | ||||
Debt Instrument [Line Items] | ||||
Debt instrument face value | $ 100 |
Debt - Senior Notes (Details)
Debt - Senior Notes (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Debt Instrument [Line Items] | |||
Repayments of senior notes | $ 617 | $ 1,000 | |
Senior notes | |||
Debt Instrument [Line Items] | |||
Debt instrument face value | $ 9,100 | $ 9,100 | |
Senior notes | 3.80% senior notes due September 2030 | |||
Debt Instrument [Line Items] | |||
Debt instrument, interest rate (as a percent) | 3.80% | 3.80% | |
Offering price percentage | 99.794% | ||
Debt instrument face value | $ 750 | ||
Senior notes | 3.55% senior notes due December 2029 | |||
Debt Instrument [Line Items] | |||
Debt instrument, interest rate (as a percent) | 3.55% | 3.55% | |
Offering price percentage | 99.801% | ||
Debt instrument face value | $ 1,000 | ||
Senior notes | 5.00% senior notes due February 2021 | |||
Debt Instrument [Line Items] | |||
Debt instrument, interest rate (as a percent) | 5.00% | ||
Repayments of senior notes | $ 600 | ||
Senior notes | 2.60% senior notes due December 2019 | |||
Debt Instrument [Line Items] | |||
Debt instrument, interest rate (as a percent) | 2.60% | ||
Repayments of senior notes | $ 500 | ||
Senior notes | 5.75% senior notes due January 2020 | |||
Debt Instrument [Line Items] | |||
Debt instrument, interest rate (as a percent) | 5.75% | ||
Repayments of senior notes | $ 500 | ||
Consolidated finance subsidiary co-issuer | |||
Debt Instrument [Line Items] | |||
Consolidated subsidiary, ownership interest held by the parent (as a percent) | 100.00% |
Debt - Maturities (Details)
Debt - Maturities (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2021USD ($) | |
Debt Disclosure [Abstract] | |
Weighted-average maturity of long-term debt | 10 years |
Maturities | |
2022 | $ 750 |
2023 | 1,100 |
2024 | 750 |
2025 | 1,000 |
2026 | 750 |
Thereafter | $ 4,783 |
Debt - Debt Covenants (Details)
Debt - Debt Covenants (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021USD ($) | Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | |
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 | 98 | $ 129 | |
Credit agreements and commercial paper program | |||
Debt Instrument [Line Items] | |||
Total borrowings | 32,500 | 29,300 | $ 13,300 |
Total repayments | $ 33,200 | $ 29,000 | $ 12,900 |
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) | Oct. 10, 2017$ / shares | Jan. 28, 2016count$ / shares | Dec. 31, 2021$ / shares | Nov. 15, 2022$ / shares |
Series A Preferred Units | ||||
Partners Capital and Distribution [Line Items] | ||||
Shares issued, price per share (in dollars per unit) | $ 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 (in dollars per unit) | $ 61.25 | |||
Redemption price (in dollars per unit) | $ 1,020 | |||
Redemption price percentage | 102.00% | |||
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, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
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) | 722,380,416 | ||
Balance, end of period (in units) | 704,991,540 | 722,380,416 | |
Limited Partners | Series A Preferred Units | |||
Increase (Decrease) in Partners' Capital [Roll Forward] | |||
Balance, beginning of period (in units) | 71,090,468 | 71,090,468 | 71,090,468 |
Balance, end of period (in units) | 71,090,468 | 71,090,468 | 71,090,468 |
Limited Partners | Series B Preferred Units | |||
Increase (Decrease) in Partners' Capital [Roll Forward] | |||
Balance, beginning of period (in units) | 800,000 | 800,000 | 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) | 722,380,416 | 728,028,576 | 726,361,924 |
Repurchase and cancellation of common units under the Common Equity Repurchase Program (in units) | (18,061,583) | (6,222,748) | |
Issuance of common units under equity-indexed compensation plans (in units) | 672,707 | 574,588 | 1,666,652 |
Balance, end of period (in units) | 704,991,540 | 722,380,416 | 728,028,576 |
Partners' Capital and Distrib_5
Partners' Capital and Distributions - Common Equity Repurchase Program (Details) - Common Equity Repurchase Program - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Nov. 30, 2020 | |
Partners Capital and Distribution [Line Items] | |||
Stock repurchase program, authorized amount | $ 500 | ||
Total purchase price of common units repurchased | $ 178 | $ 50 | |
Common equity repurchase program, remaining amount | $ 272 | ||
Maximum | |||
Partners Capital and Distribution [Line Items] | |||
Stock repurchase program, authorized amount | $ 500 |
Partners' Capital and Distrib_6
Partners' Capital and Distributions - Income Allocation (Details) | Dec. 31, 2021 |
Partners' Capital Notes [Abstract] | |
Net income allocation | 100.00% |
Partners' Capital and Distrib_7
Partners' Capital and Distributions - Preferred Unit Distributions (Details) - USD ($) $ in Millions | Feb. 14, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Partners Capital and Distribution [Line Items] | ||||
Number of days after end of quarter within which distributions must be paid to unitholders | 45 days | |||
Cash Distribution | Series A Preferred Units | ||||
Partners Capital and Distribution [Line Items] | ||||
Preferred unit dividends | $ 149 | $ 149 | $ 149 | |
Cash Distribution | Series B Preferred Units | ||||
Partners Capital and Distribution [Line Items] | ||||
Preferred unit dividends | 49 | $ 49 | $ 49 | |
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_8
Partners' Capital and Distributions - Common Unit Distributions (Details) - Common Units - Cash Distribution - USD ($) $ / shares in Units, $ in Millions | Feb. 14, 2022 | Jan. 10, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Distribution Made to Limited Partner [Line Items] | |||||
Distributions paid to limited partners | $ 517 | $ 655 | $ 1,004 | ||
Distributions per common unit (in dollars per unit) | $ 0.72 | $ 0.90 | $ 1.38 | ||
Public | |||||
Distribution Made to Limited Partner [Line Items] | |||||
Distributions paid to limited partners | $ 341 | $ 432 | $ 632 | ||
AAP | |||||
Distribution Made to Limited Partner [Line Items] | |||||
Distributions paid to limited partners | $ 176 | $ 223 | $ 372 | ||
Fourth quarter distribution | Subsequent Event | |||||
Distribution Made to Limited Partner [Line Items] | |||||
Distributions paid to limited partners | $ 127 | ||||
Distribution per common unit declared (in dollars per unit) | $ 0.18 | ||||
Fourth quarter distribution | Subsequent Event | AAP | |||||
Distribution Made to Limited Partner [Line Items] | |||||
Distributions paid to limited partners | $ 43 |
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 | ||||
Oct. 31, 2021 | May 31, 2019 | Mar. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Partners Capital and Distribution [Line Items] | |||||||
Noncontrolling interests | $ 2,838 | $ 2,838 | $ 145 | ||||
Increase in partners' capital | $ 9,972 | 9,972 | 9,593 | ||||
Proceeds from noncontrolling interests | $ 128 | ||||||
Contributions | 1 | 12 | |||||
Distributions from noncontrolling interests | 729 | 863 | 1,208 | ||||
Noncontrolling Interests | |||||||
Partners Capital and Distribution [Line Items] | |||||||
Contributions | 1 | 12 | |||||
Distributions from noncontrolling interests | $ 14 | 10 | 6 | ||||
Plains Oryx Permian Basin LLC (Permian JV) | Joint Venture Transaction | |||||||
Partners Capital and Distribution [Line Items] | |||||||
Consolidated subsidiary, ownership interest held by the parent | 65.00% | ||||||
Plains Oryx Permian Basin LLC (Permian JV) | Oryx Midstream Holdings LLC | Joint Venture Transaction | |||||||
Partners Capital and Distribution [Line Items] | |||||||
Noncontrolling interest, ownership percentage by parent | 35.00% | 35.00% | 35.00% | ||||
Consolidated subsidiary, ownership interest held by the parent | 65.00% | ||||||
Noncontrolling interests | $ 2,700 | ||||||
Increase in partners' capital | $ 605 | ||||||
Red River Pipeline Company LLC | Delek Logistics Partners, LP | |||||||
Partners Capital and Distribution [Line Items] | |||||||
Noncontrolling interest, ownership percentage | 33.00% | 33.00% | 33.00% | ||||
Proceeds from noncontrolling interests | $ 128 | ||||||
Red River Pipeline Company LLC | Noncontrolling Interests | |||||||
Partners Capital and Distribution [Line Items] | |||||||
Contributions | $ 1 | 12 | |||||
Distributions from noncontrolling interests | $ 14 | $ 10 | $ 6 | ||||
Plains Oryx Permian Basin LLC (Permian JV) | Oryx Midstream Holdings LLC | Noncontrolling Interests | Subsequent Event | |||||||
Partners Capital and Distribution [Line Items] | |||||||
Distributions from noncontrolling interests | $ 54 |
Derivatives and Risk Manageme_3
Derivatives and Risk Management Activities - Commodity Price Risk Hedging (Details) bbl in Millions | 12 Months Ended |
Dec. 31, 2021TWhMMBblsbblBcf | |
Crude oil purchases | Long | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Bcf) | 8.4 |
Time spread on hedging anticipated crude oil lease gathering purchases | Short | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Bcf) | 5.7 |
Crude oil basis spread position | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Bcf) | 7.3 |
Anticipated net sales of crude oil and NGL inventory | Short | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Bcf) | 19.2 |
Natural gas purchases for processing and operational needs | Long | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Bcf) | Bcf | 73.4 |
Propane contracts related to subsequent sale of products | Short | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Bcf) | MMBbls | 13.7 |
Butane contracts related to subsequent sale of products | Short | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Bcf) | MMBbls | 3.3 |
Condensate contracts related to subsequent sale of products | Short | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Bcf) | MMBbls | 1.5 |
Fuel gas requirements | Long | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Bcf) | Bcf | 7.5 |
Power supply requirements | Long | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in terawatt hours) | TWh | 0.6 |
Derivatives and Risk Manageme_4
Derivatives and Risk Management Activities - Financial Impact (Details) - Derivatives Not Designated as a Hedge - Commodity Derivatives - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Impact of derivative activities recognized in earnings | |||
Total gain (loss) on derivatives recognized in net income | $ (639) | $ (297) | $ 324 |
Product sales revenues | |||
Impact of derivative activities recognized in earnings | |||
Total gain (loss) on derivatives recognized in net income | (710) | (302) | 310 |
Field operating costs | |||
Impact of derivative activities recognized in earnings | |||
Total gain (loss) on derivatives recognized in net income | $ 71 | $ 5 | $ 14 |
Derivatives and Risk Manageme_5
Derivatives and Risk Management Activities - Assets and Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Derivative assets and liabilities | ||
Initial margin | $ 133 | $ 91 |
Variation margin posted/(returned) | 173 | 290 |
Letters of credit | (98) | (129) |
Net broker receivable/(payable) | 259 | 318 |
Exchange Traded | ||
Derivative assets and liabilities | ||
Letters of credit | $ (47) | $ (63) |
Derivatives and Risk Manageme_6
Derivatives and Risk Management Activities - Offsetting (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Derivative Asset Positions | ||
Effect of Collateral Netting | $ 259 | $ 318 |
Commodity Derivatives | ||
Derivative Asset Positions | ||
Effect of Collateral Netting | 259 | 318 |
Derivative Liability Positions | ||
Gross Position - Asset | 100 | 85 |
Gross Position - Liability | (243) | (386) |
Net Carrying Value Presented on the Balance Sheet, Total | 116 | 17 |
Other current assets | Commodity Derivatives | ||
Derivative Asset Positions | ||
Gross Position - Asset | 90 | 71 |
Gross Position - Liability | (210) | (314) |
Effect of Collateral Netting | 259 | 318 |
Net Carrying Value Presented on the Balance Sheet | 139 | 75 |
Other long-term assets, net | Commodity Derivatives | ||
Derivative Asset Positions | ||
Gross Position - Asset | 3 | 5 |
Gross Position - Liability | 0 | 0 |
Net Carrying Value Presented on the Balance Sheet | 3 | 5 |
Other current liabilities | Commodity Derivatives | ||
Derivative Liability Positions | ||
Gross Position - Asset | 4 | 9 |
Gross Position - Liability | (24) | (40) |
Net Carrying Value Presentation on the Balance Sheet | (20) | (31) |
Other long-term liabilities and deferred credits | Commodity Derivatives | ||
Derivative Liability Positions | ||
Gross Position - Asset | 3 | 0 |
Gross Position - Liability | (9) | (32) |
Net Carrying Value Presentation on the Balance Sheet | $ (6) | $ (32) |
Derivatives and Risk Manageme_7
Derivatives and Risk Management Activities - Interest Rate Risk Hedging (Details) - Cash Flow Hedging $ in Millions | 12 Months Ended |
Dec. 31, 2021USD ($)contract | |
8 forward starting interest rate swaps (30-year), 1.38% | |
Interest Rate Derivatives [Abstract] | |
Number of interest rate derivatives | contract | 8 |
Term of derivative contract | 30 years |
Notional amount of derivatives | $ | $ 200 |
Average rate locked (percent) | 1.38% |
8 forward starting interest rate swaps (30-year), 0.73% | |
Interest Rate Derivatives [Abstract] | |
Number of interest rate derivatives | contract | 8 |
Term of derivative contract | 30 years |
Notional amount of derivatives | $ | $ 200 |
Average rate locked (percent) | 0.73% |
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, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Other long-term assets, net | |||
Derivatives, Fair Value [Line Items] | |||
Interest rate fair value hedge liability at fair value | $ 65 | $ 46 | |
AOCI cash flow hedge | |||
Derivatives, Fair Value [Line Items] | |||
Net loss deferred in AOCI | 208 | ||
Interest Rate Derivatives | |||
Derivatives, Fair Value [Line Items] | |||
Net unrealized gain/(loss) recognized in AOCI | $ 19 | $ (10) | $ (91) |
Derivatives and Risk Manageme_9
Derivatives and Risk Management Activities - Preferred Distribution Rate (Details) - Preferred Distribution Rate Reset Option - Derivatives Not Designated as a Hedge - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Other long-term liabilities and deferred credits | |||
Derivatives and Risk Management Activities | |||
Derivative liability | $ 14 | ||
Other long-term liabilities and deferred credits | Maximum | |||
Derivatives and Risk Management Activities | |||
Derivative liability | $ 1 | ||
Other income/(expense), net | |||
Derivatives and Risk Management Activities | |||
Gain/(loss) recognized | $ 14 | $ 20 | $ 2 |
Derivatives and Risk Managem_10
Derivatives and Risk Management Activities - Fair Value (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Level 3 | ||
Rollforward of Level 3 Net Asset/(Liability) | ||
Beginning Balance | $ (29) | $ (51) |
Net gains/(losses) for the period included in earnings | 15 | 12 |
Settlements | 12 | 10 |
Ending Balance | (2) | (29) |
Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period | 15 | 12 |
Recurring Fair Value Measures | ||
Recurring Fair Value Measurements | ||
Total net derivative asset/(liability) | (78) | (267) |
Recurring Fair Value Measures | Commodity Derivatives | ||
Recurring Fair Value Measurements | ||
Total net derivative asset/(liability) | (143) | (301) |
Recurring Fair Value Measures | Interest Rate Derivatives | ||
Recurring Fair Value Measurements | ||
Total net derivative asset/(liability) | 65 | 46 |
Recurring Fair Value Measures | Preferred Distribution Rate Reset Option | ||
Recurring Fair Value Measurements | ||
Total net derivative asset/(liability) | (12) | |
Recurring Fair Value Measures | Level 1 | ||
Recurring Fair Value Measurements | ||
Total net derivative asset/(liability) | (17) | (143) |
Recurring Fair Value Measures | Level 1 | Commodity Derivatives | ||
Recurring Fair Value Measurements | ||
Total net derivative asset/(liability) | (17) | (143) |
Recurring Fair Value Measures | Level 1 | Interest Rate Derivatives | ||
Recurring Fair Value Measurements | ||
Total net derivative asset/(liability) | 0 | 0 |
Recurring Fair Value Measures | Level 1 | Preferred Distribution Rate Reset Option | ||
Recurring Fair Value Measurements | ||
Total net derivative asset/(liability) | 0 | 0 |
Recurring Fair Value Measures | Level 2 | ||
Recurring Fair Value Measurements | ||
Total net derivative asset/(liability) | (59) | (95) |
Recurring Fair Value Measures | Level 2 | Commodity Derivatives | ||
Recurring Fair Value Measurements | ||
Total net derivative asset/(liability) | (124) | (143) |
Recurring Fair Value Measures | Level 2 | Interest Rate Derivatives | ||
Recurring Fair Value Measurements | ||
Total net derivative asset/(liability) | 65 | 46 |
Recurring Fair Value Measures | Level 2 | Preferred Distribution Rate Reset Option | ||
Recurring Fair Value Measurements | ||
Total net derivative asset/(liability) | 0 | 2 |
Recurring Fair Value Measures | Level 3 | ||
Recurring Fair Value Measurements | ||
Total net derivative asset/(liability) | (2) | (29) |
Recurring Fair Value Measures | Level 3 | Commodity Derivatives | ||
Recurring Fair Value Measurements | ||
Total net derivative asset/(liability) | (2) | (15) |
Recurring Fair Value Measures | Level 3 | Interest Rate Derivatives | ||
Recurring Fair Value Measurements | ||
Total net derivative asset/(liability) | 0 | 0 |
Recurring Fair Value Measures | Level 3 | Preferred Distribution Rate Reset Option | ||
Recurring Fair Value Measurements | ||
Total net derivative asset/(liability) | $ 0 | $ (14) |
Leases - Narrative Information
Leases - Narrative Information (Details) | 12 Months Ended |
Dec. 31, 2021 | |
Equity Method Investees | Agreement to store at facilities owned by equity method investee | |
Lessee, Lease, Description [Line Items] | |
Ownership interest in unconsolidated entity | 50.00% |
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 | 1 year |
Maximum | |
Lessee, Lease, Description [Line Items] | |
Lessee, leases, term of contract | 59 years |
Lessee, leases, renewal term | 25 years |
Lessor, Lease, Description [Line Items] | |
Lessor, operating lease, term of contract | 20 years |
Leases - Lease Costs (Details)
Leases - Lease Costs (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Lessee, Lease, Description [Line Items] | |||
Operating lease cost | $ 96 | $ 111 | $ 125 |
Short-term lease cost | 19 | 31 | 35 |
Other | 14 | 8 | 0 |
Total lease cost | 129 | 150 | $ 160 |
Agreement to store at facilities owned by equity method investee | Equity Method Investees | |||
Lessee, Lease, Description [Line Items] | |||
Other | $ 8 | $ 6 | |
Ownership interest in unconsolidated entity | 50.00% |
Leases - Other Information (Det
Leases - Other Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Lessee, Lease, Description [Line Items] | |||
Operating cash flows for operating leases | $ 91 | $ 108 | $ 116 |
Operating cash flows for finance leases | 7 | 5 | 1 |
Financing cash flows for finance leases | 11 | 19 | 18 |
Non-cash change in lease liabilities arising from obtaining new right of use assets or modifications, operating leases | 94 | 5 | 77 |
Non-cash change in lease liabilities arising from obtaining new right of use assets or modifications, finance leases | $ 1 | $ 32 | 27 |
Weighted-average remaining lease term (in years): | |||
Operating lease, weighted-average lease term | 11 years | 12 years | |
Finance lease, weighted-average lease term | 9 years | 9 years | |
Weighted-average discount rate: | |||
Operating lease, weighted-average discount rate | 4.20% | 4.50% | |
Finance lease, weighted-average discount rate | 11.60% | 11.10% | |
Equity Method Investees | Agreement to store at facilities owned by equity method investee | |||
Lessee, Lease, Description [Line Items] | |||
Non-cash change in lease liabilities arising from obtaining new right of use assets or modifications, finance leases | $ 25 | $ 12 | |
Ownership interest in unconsolidated entity | 50.00% |
Leases - Assets and Liabilities
Leases - Assets and Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Lessee, Lease, Assets and Liabilities [Line Items] | ||
Long-term operating lease right-of-use assets, net | $ 393 | $ 378 |
Finance lease right-of-use assets, gross | 136 | 141 |
Finance lease right-of-use assets, accumulated depreciation | (37) | (27) |
Finance lease right-of-use assets, net | $ 99 | $ 114 |
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration] | Property, Plant, and Equipment and Finance Lease Right-of-Use Asset, after Accumulated Depreciation and Amortization | Property, Plant, and Equipment and Finance Lease Right-of-Use Asset, after Accumulated Depreciation and Amortization |
Total lease right-of-use assets | $ 492 | $ 492 |
Operating lease liabilities | ||
Operating lease liabilities, current | $ 77 | $ 78 |
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration] | Other current liabilities | Other current liabilities |
Long-term operating lease liabilities | $ 339 | $ 317 |
Total operating lease liabilities | 416 | 395 |
Finance lease liabilities | ||
Finance lease liabilities, current | $ 12 | $ 11 |
Finance Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration] | Short-term debt | Short-term debt |
Finance lease liabilities, noncurrent | $ 59 | $ 70 |
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration] | Other long-term debt, net | Other long-term debt, net |
Total finance lease liabilities | $ 71 | $ 81 |
Total lease liabilities | 487 | 476 |
Equity Method Investees | Agreement to store at facilities owned by equity method investee | ||
Lessee, Lease, Assets and Liabilities [Line Items] | ||
Finance lease right-of-use assets, net | 33 | 35 |
Finance lease liabilities | ||
Total finance lease liabilities | $ 35 | $ 36 |
Ownership interest in unconsolidated entity | 50.00% |
Leases - Maturity of Lease Liab
Leases - Maturity of Lease Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Operating | ||
2022 | $ 92 | |
2023 | 75 | |
2024 | 63 | |
2025 | 50 | |
2026 | 38 | |
Thereafter | 252 | |
Total | 570 | |
Less: Present value discount | (154) | |
Lease liabilities | 416 | $ 395 |
Finance | ||
2022 | 18 | |
2023 | 15 | |
2024 | 14 | |
2025 | 12 | |
2026 | 7 | |
Thereafter | 60 | |
Total | 126 | |
Less: Present value discount | (55) | |
Lease liabilities | 71 | 81 |
Equity Method Investees | Agreement to store at facilities owned by equity method investee | ||
Finance | ||
2022 | 6 | |
2023 | 6 | |
2024 | 6 | |
2025 | 6 | |
2026 | 6 | |
Thereafter | 58 | |
Lease liabilities | $ 35 | $ 36 |
Ownership interest in unconsolidated entity | 50.00% |
Leases - Lessor Operating Lease
Leases - Lessor Operating Lease Revenue (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Leases [Abstract] | |||
Operating lease revenue | $ 28 | $ 19 | $ 17 |
Leases - Lessor Future Minimum
Leases - Lessor Future Minimum Lease Revenue (Details) $ in Millions | Dec. 31, 2021USD ($) |
Leases [Abstract] | |
2022 | $ 29 |
2023 | 22 |
2024 | 20 |
2025 | 20 |
2026 | 20 |
Thereafter | $ 197 |
Income Taxes - Components (Deta
Income Taxes - Components (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Current income tax expense: | |||
State income tax | $ 2 | $ 0 | $ 3 |
Canadian federal and provincial income tax | 48 | 51 | 109 |
Total current income tax expense | 50 | 51 | 112 |
Deferred income tax expense/(benefit): | |||
Canadian federal and provincial income tax | 23 | (70) | (46) |
Total deferred income tax expense/(benefit) | 23 | (70) | (46) |
Total income tax expense/(benefit) | $ 73 | $ (19) | $ 66 |
Income Taxes - Reconciliation a
Income Taxes - Reconciliation and Deferred Tax Assets (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Income Tax Examination [Line Items] | |||
Income/(loss) before tax | $ 721 | $ (2,599) | $ 2,246 |
Partnership (earnings)/loss not subject to current Canadian tax | (370) | 2,221 | (1,769) |
Partnership earnings subject to current Canadian tax | $ 351 | $ (378) | $ 477 |
Canadian federal and provincial corporate tax rate | 24.00% | 24.00% | 26.00% |
Income tax expense/(benefit) at statutory rate | $ 84 | $ (91) | $ 124 |
Canadian permanent differences and rate changes | (13) | 72 | (61) |
State income tax | 2 | 0 | 3 |
Total income tax expense/(benefit) | 73 | (19) | $ 66 |
Deferred tax assets: | |||
Derivative instruments | 39 | 45 | |
Lease liabilities | 48 | 39 | |
Net operating losses | 2 | 2 | |
Other | 17 | 16 | |
Total deferred tax assets | 106 | 102 | |
Deferred tax liabilities: | |||
Property and equipment in excess of tax values | (531) | (475) | |
Lease assets | (47) | (38) | |
Other | (3) | (3) | |
Total deferred tax liabilities | (581) | (516) | |
Net deferred tax liabilities | (475) | (414) | |
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 | $ (477) | $ (416) |
Income Taxes - Narrative (Detai
Income Taxes - Narrative (Details) - USD ($) $ in Millions | Jul. 01, 2020 | Jun. 30, 2019 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2021 |
Income Tax Examination [Line Items] | ||||||
Canadian federal and provincial corporate tax rate | 24.00% | 24.00% | 26.00% | |||
Foreign | ||||||
Income Tax Examination [Line Items] | ||||||
Net operating loss carryforwards | $ 9 | $ 9 | ||||
Alberta Government, Canada | ||||||
Income Tax Examination [Line Items] | ||||||
Canadian federal and provincial corporate tax rate | 8.00% | 12.00% | 8.00% | |||
Deferred tax benefit from change in tax rate | $ 60 | |||||
Canadian Tax Authorities | Foreign | ||||||
Income Tax Examination [Line Items] | ||||||
Amount of assessments received, including penalty and interest | 120 | $ 120 | ||||
Canadian Tax Authorities | Other long-term assets, net | Foreign | ||||||
Income Tax Examination [Line Items] | ||||||
Amount of disputed assessments paid | $ 101 | $ 101 |
Major Customers and Concentra_2
Major Customers and Concentration of Credit Risk (Details) - Revenues - Customer Concentration Risk | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
ExxonMobil Corporation | |||
Major Customers and Concentration of Credit Risk | |||
Major customer percentage of total revenue | 15.00% | 12.00% | 12.00% |
Marathon Petroleum Corporation | |||
Major Customers and Concentration of Credit Risk | |||
Major customer percentage of total revenue | 12.00% | 13.00% | 12.00% |
BP p.l.c and subsidiaries | |||
Major Customers and Concentration of Credit Risk | |||
Major customer percentage of total revenue | 10.00% | ||
Phillips 66 | |||
Major Customers and Concentration of Credit Risk | |||
Major customer percentage of total revenue | 11.00% |
Related Party Transactions (Det
Related Party Transactions (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Related Party Transactions | |||
Revenues from related parties | $ 33 | $ 46 | $ 692 |
Purchases and related costs from related parties | 385 | 451 | 223 |
Trade accounts receivable and other receivables, net from related parties | 41 | 34 | |
Trade accounts payable to related parties | 72 | 88 | |
GP | |||
Related Party Transactions | |||
Costs reimbursed to general partner | 467 | 553 | 580 |
Omnibus Agreement | |||
Related Party Transactions | |||
Expenses paid on behalf of affiliates | $ 5 | $ 5 | $ 4 |
PAGP | Class C Shares | |||
Related Party Transactions | |||
Class C Shares of PAGP Owned (in units) | 534,596,831 | 547,717,762 | |
AAP | Principal Owner | Minimum | |||
Related Party Transactions | |||
Limited partner interest | 10.00% |
Equity-Indexed Compensation P_3
Equity-Indexed Compensation Plans - Plan Information (Details) - USD ($) $ in Millions | Dec. 31, 2021 | May 31, 2021 |
Equity-Indexed Compensation Plans | ||
LTIP awards authorized (in units) | 43,500,000 | |
LTIP awards available (in units) | 22,700,000 | |
LTIP awards outstanding (in units) | 10,700,000 | |
LTIP awards outstanding including DERs (in units) | 7,600,000 | |
Probable vesting, unrecognized fair value | $ 44 | |
Plains All American 2021 Long-Term Incentive Plan | ||
Equity-Indexed Compensation Plans | ||
LTIP awards authorized (in units) | 28,800,000 | 20,000,000 |
Plains All American PNG Successor Long-Term Incentive Plan | ||
Equity-Indexed Compensation Plans | ||
LTIP awards authorized (in units) | 1,300,000 | |
Plains All American GP LLC 2006 Long-Term Incentive Tracking Unit Plan | ||
Equity-Indexed Compensation Plans | ||
LTIP awards authorized (in units) | 13,400,000 |
Commitments and Contingencies -
Commitments and Contingencies - Commitments (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Leases | |||
2022 | $ 110 | ||
2023 | 90 | ||
2024 | 77 | ||
2025 | 62 | ||
2026 | 45 | ||
Thereafter | 312 | ||
Total | 696 | ||
Other commitments | |||
2022 | 327 | ||
2023 | 307 | ||
2024 | 298 | ||
2025 | 282 | ||
2026 | 211 | ||
Thereafter | 624 | ||
Total | 2,049 | ||
Total | |||
2022 | 437 | ||
2023 | 397 | ||
2024 | 375 | ||
2025 | 344 | ||
2026 | 256 | ||
Thereafter | 936 | ||
Total | 2,745 | ||
Expenses associated with agreements | $ 270 | $ 265 | $ 236 |
Agreements to store at facilities or transport on pipelines owned by equity method investees | Equity Method Investees | |||
Total | |||
Ownership interest in unconsolidated entity | 50.00% |
Commitments and Contingencies_2
Commitments and Contingencies - Legal, Environmental or Regulatory (Details) | Oct. 14, 2020USD ($) | May 31, 2015bbl | Dec. 31, 2021USD ($) | Dec. 31, 2021USD ($)lawsuit | Dec. 31, 2020USD ($) | Apr. 25, 2019USD ($) | Sep. 07, 2018count |
Legal, Environmental or Regulatory Matters | |||||||
Estimated undiscounted reserve for environmental liabilities | $ 57,000,000 | $ 57,000,000 | $ 55,000,000 | ||||
Estimated undiscounted reserve for environmental liabilities, short-term | 11,000,000 | 11,000,000 | 8,000,000 | ||||
Amounts probable of recovery under insurance and from third parties under indemnification agreements | 11,000,000 | 11,000,000 | 6,000,000 | ||||
Other long-term liabilities and deferred credits | |||||||
Legal, Environmental or Regulatory Matters | |||||||
Estimated undiscounted reserve for environmental liabilities, long-term | 46,000,000 | 46,000,000 | $ 47,000,000 | ||||
Other long-term assets, net | |||||||
Legal, Environmental or Regulatory Matters | |||||||
Amounts probable of recovery under insurance and from third parties under indemnification agreements | 1,000,000 | 1,000,000 | |||||
Line 901 Incident | |||||||
Legal, Environmental or Regulatory Matters | |||||||
Estimated undiscounted reserve for environmental liabilities | 103,000,000 | 103,000,000 | |||||
Amounts probable of recovery under insurance and from third parties under indemnification agreements | 105,000,000 | 105,000,000 | |||||
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 | 495,000,000 | 495,000,000 | |||||
Recoveries from insurance carriers | 250,000,000 | ||||||
Total release costs probable of recovery | 355,000,000 | $ 355,000,000 | |||||
Line 901 Incident | Civil Penalties | |||||||
Legal, Environmental or Regulatory Matters | |||||||
Penalties or compensation paid | $ 24,000,000 | ||||||
Line 901 Incident | Compensation for Injuries to, Destruction of, Loss of Use of, Natural Resources | |||||||
Legal, Environmental or Regulatory Matters | |||||||
Penalties or compensation paid | $ 22,325,000 | ||||||
Line 901 Incident | May 2016 Indictment | |||||||
Legal, Environmental or Regulatory Matters | |||||||
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 | ||||||
Fines or penalties assessed | $ 3,350,000 | ||||||
Line 901 Incident | May 2016 Indictment | Maximum | |||||||
Legal, Environmental or Regulatory Matters | |||||||
Amount awarded to claimants by Court | $ 150,000 | ||||||
Line 901 Incident | Class Action Lawsuits | |||||||
Legal, Environmental or Regulatory Matters | |||||||
Number of cases filed during the period | lawsuit | 9 | ||||||
Line 901 Incident | Unitholder Derivative Lawsuits | |||||||
Legal, Environmental or Regulatory Matters | |||||||
Number of cases filed during the period | lawsuit | 4 |
Segment Information - Segment F
Segment Information - Segment Financial Data (Details) $ in Millions | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||
Dec. 31, 2021USD ($)segment | Sep. 30, 2021segment | Dec. 31, 2021USD ($)segment | Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | |
Operating Segments | |||||
Operating segments number | segment | 2 | 3 | 2 | ||
Revenue | |||||
Revenues | $ 42,078 | $ 23,290 | $ 33,669 | ||
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments | |||||
Equity earnings in unconsolidated entities | 274 | 355 | 388 | ||
Segment Adjusted EBITDA | 2,194 | 2,543 | 3,220 | ||
Investment and acquisition capital expenditures | 269 | 1,231 | 1,390 | ||
Maintenance capital expenditures | 168 | 216 | 287 | ||
Investments in unconsolidated entities | $ 3,805 | 3,805 | 3,764 | 3,683 | |
Operating Segments | |||||
Revenue | |||||
Revenues | 42,438 | 23,559 | 34,094 | ||
Intersegment Revenues Elimination | |||||
Revenue | |||||
Revenues | (360) | (269) | (425) | ||
Product sales | |||||
Revenue | |||||
Revenues | 40,883 | 22,058 | 32,272 | ||
Product sales | Intersegment Revenues Elimination | |||||
Revenue | |||||
Revenues | (341) | (249) | (405) | ||
Services | |||||
Revenue | |||||
Revenues | 1,195 | 1,232 | 1,397 | ||
Services | Intersegment Revenues Elimination | |||||
Revenue | |||||
Revenues | (19) | (20) | (20) | ||
Crude Oil | |||||
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments | |||||
Equity earnings in unconsolidated entities | 274 | 355 | 388 | ||
Segment Adjusted EBITDA | 1,909 | 2,216 | 2,753 | ||
Investment and acquisition capital expenditures | 212 | 1,182 | 1,332 | ||
Maintenance capital expenditures | 100 | 171 | 248 | ||
Investments in unconsolidated entities | 3,805 | 3,805 | 3,764 | 3,683 | |
Crude Oil | Operating Segments | |||||
Revenue | |||||
Revenues | 40,470 | 22,199 | 31,655 | ||
Crude Oil | Product sales | Operating Segments | |||||
Revenue | |||||
Revenues | 39,395 | 21,089 | 30,375 | ||
Crude Oil | Services | Operating Segments | |||||
Revenue | |||||
Revenues | 1,075 | 1,110 | 1,280 | ||
NGL | |||||
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments | |||||
Equity earnings in unconsolidated entities | 0 | 0 | 0 | ||
Segment Adjusted EBITDA | 285 | 327 | 467 | ||
Investment and acquisition capital expenditures | 57 | 49 | 58 | ||
Maintenance capital expenditures | 68 | 45 | 39 | ||
Investments in unconsolidated entities | $ 0 | 0 | 0 | 0 | |
NGL | Operating Segments | |||||
Revenue | |||||
Revenues | 1,968 | 1,360 | 2,439 | ||
NGL | Product sales | Operating Segments | |||||
Revenue | |||||
Revenues | 1,829 | 1,218 | 2,302 | ||
NGL | Services | Operating Segments | |||||
Revenue | |||||
Revenues | $ 139 | $ 142 | $ 137 |
Segment Information - Reconcili
Segment Information - Reconciliation of Segment Adjusted EBITDA (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2020 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items] | ||||
Segment Adjusted EBITDA | $ 2,194 | $ 2,543 | $ 3,220 | |
Adjustments: | ||||
Depreciation and amortization of unconsolidated entities | (123) | (73) | (62) | |
Gains/(losses) from derivative activities, net of inventory valuation adjustments | 271 | (480) | (160) | |
Long-term inventory costing adjustments | 94 | (44) | 20 | |
Deficiencies under minimum volume commitments, net | 7 | (74) | 18 | |
Equity-indexed compensation expense | (19) | (19) | (17) | |
Net gain/(loss) on foreign currency revaluation | 4 | 3 | (14) | |
Significant transaction-related expenses | (16) | (3) | 0 | |
Adjusted EBITDA attributable to noncontrolling interests | 94 | 14 | 10 | |
Depreciation and amortization | (774) | (653) | (601) | |
Gains/(losses) on asset sales and asset impairments, net | (592) | (719) | (28) | |
Goodwill impairment losses | $ (2,515) | 0 | (2,515) | 0 |
Gain on/(impairment of) investments in unconsolidated entities, net | 2 | (182) | 271 | |
Interest expense, net | (425) | (436) | (425) | |
Other income, net | 19 | 39 | 24 | |
INCOME/(LOSS) BEFORE TAX | 721 | (2,599) | 2,246 | |
Income tax (expense)/benefit | (73) | 19 | (66) | |
NET INCOME/(LOSS) | 648 | (2,580) | 2,180 | |
Net income attributable to noncontrolling interests | (55) | (10) | (9) | |
NET INCOME/(LOSS) ATTRIBUTABLE TO PAA | 593 | (2,590) | 2,171 | |
Line 901 Incident | ||||
Adjustments: | ||||
Line 901 incident | $ (15) | $ 0 | $ (10) |
Segment Information - Geographi
Segment Information - Geographic Data (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Geographic Data | |||
Revenues | $ 42,078 | $ 23,290 | $ 33,669 |
Long-lived assets | 22,367 | 20,779 | |
United States | |||
Geographic Data | |||
Revenues | 34,458 | 17,942 | 27,162 |
Long-lived assets | 18,273 | 16,887 | |
Canada | |||
Geographic Data | |||
Revenues | 7,620 | 5,348 | $ 6,507 |
Long-lived assets | $ 4,094 | $ 3,892 |