Cover
Cover - USD ($) $ in Billions | 12 Months Ended | ||
Dec. 31, 2023 | Feb. 16, 2024 | Jun. 30, 2023 | |
Cover [Abstract] | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2023 | ||
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 | ||
Document Financial Statement Error Correction | false | ||
Entity Shell Company | false | ||
Entity Public Float | $ 6.4 | ||
Entity Common Stock Outstanding (in units) | 701,071,031 | ||
Documents Incorporated by Reference | Portions of the registrant’s definitive Proxy Statement to be filed pursuant to Regulation 14A pertaining to the 2024 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 | 2023 | ||
Document Fiscal Period Focus | FY |
Audit Information
Audit Information | 12 Months Ended |
Dec. 31, 2023 | |
Audit Information [Abstract] | |
Auditor Firm ID | 238 |
Auditor Name | PricewaterhouseCoopers LLP |
Auditor Location | Houston, Texas |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
CURRENT ASSETS | ||
Cash and cash equivalents | $ 450 | $ 401 |
Trade accounts receivable and other receivables, net | 3,760 | 3,907 |
Inventory | 548 | 729 |
Other current assets | 155 | 318 |
Total current assets | 4,913 | 5,355 |
PROPERTY AND EQUIPMENT | 21,143 | 20,020 |
Accumulated depreciation | (5,361) | (4,770) |
Property and equipment, net | 15,782 | 15,250 |
OTHER ASSETS | ||
Investments in unconsolidated entities | 2,820 | 3,084 |
Intangible assets, net | 1,875 | 2,145 |
Linefill | 976 | 961 |
Long-term operating lease right-of-use assets, net | 313 | 349 |
Long-term inventory | 265 | 284 |
Other long-term assets, net | 411 | 464 |
Total assets | 27,355 | 27,892 |
CURRENT LIABILITIES | ||
Trade accounts payable | 3,844 | 4,044 |
Short-term debt | 446 | 1,159 |
Other current liabilities | 713 | 688 |
Total current liabilities | 5,003 | 5,891 |
LONG-TERM LIABILITIES | ||
Senior notes, net | 7,242 | 7,237 |
Other long-term debt, net | 63 | 50 |
Long-term operating lease liabilities | 274 | 308 |
Other long-term liabilities and deferred credits | 1,041 | 1,081 |
Total long-term liabilities | 8,620 | 8,676 |
COMMITMENTS AND CONTINGENCIES (NOTE 18) | ||
PARTNERS’ CAPITAL | ||
Total partners’ capital excluding noncontrolling interests | 10,422 | 10,057 |
Noncontrolling interests | 3,310 | 3,268 |
Total partners’ capital | 13,732 | 13,325 |
Total liabilities and partners’ capital | 27,355 | 27,892 |
Series A Preferred Units | ||
PARTNERS’ CAPITAL | ||
Partners' capital | 1,509 | 1,505 |
Series B Preferred Units | ||
PARTNERS’ CAPITAL | ||
Partners' capital | 787 | 787 |
Common Units | ||
PARTNERS’ CAPITAL | ||
Partners' capital | $ 8,126 | $ 7,765 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 |
Series A Preferred Units | ||||
Units outstanding (in units) | 71,090,468 | 71,090,468 | 71,090,468 | 71,090,468 |
Series B Preferred Units | ||||
Units outstanding (in units) | 800,000 | 800,000 | 800,000 | 800,000 |
Common Units | ||||
Units outstanding (in units) | 701,008,749 | 698,354,498 | 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, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
REVENUES | |||
Total revenues | $ 48,712 | $ 57,342 | $ 42,078 |
COSTS AND EXPENSES | |||
Purchases and related costs | 44,531 | 53,176 | 38,504 |
Field operating costs | 1,425 | 1,315 | 1,065 |
General and administrative expenses | 350 | 325 | 292 |
Depreciation and amortization | 1,048 | 965 | 774 |
(Gains)/losses on asset sales and asset impairments, net (Note 6, Note 7) | (152) | 269 | 592 |
Total costs and expenses | 47,202 | 56,050 | 41,227 |
OPERATING INCOME | 1,510 | 1,292 | 851 |
OTHER INCOME/(EXPENSE) | |||
Equity earnings in unconsolidated entities | 369 | 403 | 274 |
Gains/(losses) on investments in unconsolidated entities, net (Note 7, Note 8) | 28 | 346 | 2 |
Interest expense (net of capitalized interest of $10, $5 and $18, respectively) | (386) | (405) | (425) |
Other income/(expense), net | 102 | (219) | 19 |
INCOME BEFORE TAX | 1,623 | 1,417 | 721 |
Current income tax expense | (145) | (84) | (50) |
Deferred income tax (expense)/benefit | 24 | (105) | (23) |
NET INCOME | 1,502 | 1,228 | 648 |
Net income attributable to noncontrolling interests | (272) | (191) | (55) |
NET INCOME ATTRIBUTABLE TO PAA | 1,230 | 1,037 | 593 |
NET INCOME PER COMMON UNIT (NOTE 4): | |||
Net income allocated to common unitholders — Basic | 976 | 831 | 393 |
Net income allocated to common unitholders — Diluted | $ 976 | $ 831 | $ 393 |
Common Units | |||
NET INCOME PER COMMON UNIT (NOTE 4): | |||
Basic weighted average common units outstanding (in units) | 699 | 701 | 716 |
Diluted weighted average common units outstanding (in units) | 699 | 701 | 716 |
Basic net income per common unit (in dollars per unit) | $ 1.40 | $ 1.19 | $ 0.55 |
Diluted net income per common unit (in dollars per unit) | $ 1.40 | $ 1.19 | $ 0.55 |
Product sales revenues | |||
REVENUES | |||
Total revenues | $ 46,974 | $ 55,948 | $ 40,883 |
Services revenues | |||
REVENUES | |||
Total revenues | $ 1,738 | $ 1,394 | $ 1,195 |
CONSOLIDATED STATEMENTS OF OP_2
CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Income Statement [Abstract] | |||
Interest expense, capitalized interest | $ 10 | $ 5 | $ 18 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Statement of Comprehensive Income [Abstract] | |||
Net income | $ 1,502 | $ 1,228 | $ 648 |
Other comprehensive income/(loss) | 118 | (101) | 65 |
Comprehensive income | 1,620 | 1,127 | 713 |
Comprehensive income attributable to noncontrolling interests | (272) | (191) | (55) |
Comprehensive income attributable to PAA | $ 1,348 | $ 936 | $ 658 |
CONSOLIDATED STATEMENTS OF CHAN
CONSOLIDATED STATEMENTS OF CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Changes in Accumulated Other Comprehensive Income/(Loss) | |||
Beginning balance | $ 13,325 | $ 12,810 | $ 9,738 |
Total period activity | 118 | (101) | 65 |
Ending balance | 13,732 | 13,325 | 12,810 |
Derivative Instruments | |||
Changes in Accumulated Other Comprehensive Income/(Loss) | |||
Beginning balance | (107) | (208) | (258) |
Reclassification adjustments | 11 | 7 | 31 |
Unrealized gain on hedges | 15 | 94 | 19 |
Total period activity | 26 | 101 | 50 |
Ending balance | (81) | (107) | (208) |
Translation Adjustments | |||
Changes in Accumulated Other Comprehensive Income/(Loss) | |||
Beginning balance | (846) | (642) | (657) |
Currency translation adjustments | 91 | (204) | 15 |
Total period activity | 91 | (204) | 15 |
Ending balance | (755) | (846) | (642) |
Other | |||
Changes in Accumulated Other Comprehensive Income/(Loss) | |||
Beginning balance | (1) | (3) | (3) |
Other | 1 | 2 | |
Total period activity | 1 | 2 | |
Ending balance | (1) | (3) | |
Total | |||
Changes in Accumulated Other Comprehensive Income/(Loss) | |||
Beginning balance | (954) | (853) | (918) |
Reclassification adjustments | 11 | 7 | 31 |
Unrealized gain on hedges | 15 | 94 | 19 |
Currency translation adjustments | 91 | (204) | 15 |
Other | 1 | 2 | |
Total period activity | 118 | (101) | 65 |
Ending balance | $ (836) | $ (954) | $ (853) |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
CASH FLOWS FROM OPERATING ACTIVITIES | |||
Net income | $ 1,502 | $ 1,228 | $ 648 |
Reconciliation of net income to net cash provided by operating activities: | |||
Depreciation and amortization | 1,048 | 965 | 774 |
(Gains)/losses on asset sales and asset impairments, net (Note 6, Note 7) | (152) | 269 | 592 |
Equity-indexed compensation expense | 50 | 40 | 23 |
Deferred income tax expense/(benefit) | (24) | 105 | 23 |
Gains on sales of linefill | (2) | (35) | |
(Gain)/loss on foreign currency revaluation | 8 | 41 | (7) |
Settlement of terminated interest rate hedging instruments | 80 | 42 | |
Change in fair value of Preferred Distribution Rate Reset Option (Note 12) | (58) | 189 | (14) |
Equity earnings in unconsolidated entities | (369) | (403) | (274) |
Distributions on earnings from unconsolidated entities | 458 | 488 | 431 |
(Gains)/losses on investments in unconsolidated entities, net (Note 7, Note 8) | (28) | (346) | (2) |
Other | 20 | 16 | 29 |
Changes in assets and liabilities, net of acquisitions: | |||
Trade accounts receivable and other | 213 | 649 | (2,179) |
Inventory | 223 | (10) | (18) |
Trade accounts payable and other | (242) | (830) | 1,970 |
Net cash provided by operating activities | 2,727 | 2,408 | 1,996 |
CASH FLOWS FROM INVESTING ACTIVITIES | |||
Cash paid in connection with acquisitions, net of cash acquired (Note 7) | (425) | (149) | (32) |
Investments in unconsolidated entities (Note 8) | (33) | (14) | (94) |
Additions to property, equipment and other | (559) | (455) | (336) |
Cash paid for purchases of linefill | (23) | (84) | (37) |
Proceeds from sales of assets (Note 7) | 328 | 60 | 881 |
Cash received from sales of linefill | 9 | 72 | 3 |
Other investing activities | 1 | 44 | 1 |
Net cash provided by/(used in) investing activities | (702) | (526) | 386 |
CASH FLOWS FROM FINANCING ACTIVITIES | |||
Net borrowings/(repayments) under commercial paper program (Note 10) | 433 | (545) | |
Net repayments under senior secured hedged inventory facility (Note 10) | (167) | ||
Repayment of GO Zone term loans (Note 10) | (200) | ||
Repayments of senior notes (Note 10) | (1,100) | (750) | |
Repurchase of common units (Note 11) | (74) | (178) | |
Distributions paid to noncontrolling interests (Note 11) | (333) | (298) | (14) |
Contributions from noncontrolling interests | 106 | 26 | 1 |
Other financing activities | (93) | (53) | (166) |
Net cash used in financing activities | (1,976) | (1,931) | (1,984) |
Effect of translation adjustment | (3) | (5) | |
Net increase/(decrease) in cash and cash equivalents and restricted cash | 49 | (52) | 393 |
Cash and cash equivalents and restricted cash, beginning of period | 401 | 453 | 60 |
Cash and cash equivalents and restricted cash, end of period | 450 | 401 | 453 |
Cash paid for: | |||
Interest, net of amounts capitalized | 377 | 393 | 401 |
Income taxes, net of amounts refunded | 69 | 112 | 76 |
Series A Preferred Units | |||
CASH FLOWS FROM FINANCING ACTIVITIES | |||
Distributions paid to unitholders (Note 11) | (166) | (149) | (149) |
Series B Preferred Units | |||
CASH FLOWS FROM FINANCING ACTIVITIES | |||
Distributions paid to unitholders (Note 11) | (75) | (49) | (49) |
Common Units | |||
CASH FLOWS FROM FINANCING ACTIVITIES | |||
Distributions paid to unitholders (Note 11) | $ (748) | $ (584) | $ (517) |
CONSOLIDATED STATEMENTS OF CH_2
CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL - USD ($) $ in Millions | Total | Plains Oryx Permian Basin LLC Joint Venture Transaction | Cactus II Pipeline LLC | Partners’ Capital Excluding Noncontrolling Interests | Partners’ Capital Excluding Noncontrolling Interests Plains Oryx Permian Basin LLC Joint Venture Transaction | Noncontrolling Interests | Noncontrolling Interests Plains Oryx Permian Basin LLC Joint Venture Transaction | Noncontrolling Interests Cactus II Pipeline LLC | Limited Partners Series A Preferred Units Partners’ Capital Excluding Noncontrolling Interests | Limited Partners Series B Preferred Units Partners’ Capital Excluding Noncontrolling Interests | Limited Partners Common Units Partners’ Capital Excluding Noncontrolling Interests | Limited Partners Common Units Partners’ Capital Excluding Noncontrolling Interests Plains Oryx Permian Basin LLC Joint Venture Transaction |
Beginning balance at Dec. 31, 2020 | $ 9,738 | $ 9,593 | $ 145 | $ 1,505 | $ 787 | $ 7,301 | ||||||
Increase (Decrease) in Partners' Capital [Roll Forward] | ||||||||||||
Net income | 648 | 593 | 55 | 149 | 49 | 395 | ||||||
Distributions (Note 11) | (729) | (715) | (14) | (149) | (49) | (517) | ||||||
Other comprehensive income/(loss) | 65 | 65 | 65 | |||||||||
Equity-indexed compensation expense | 19 | 19 | 19 | |||||||||
Repurchase of common units (Note 11) | (178) | (178) | (178) | |||||||||
Contributions from noncontrolling interests | 1 | 1 | ||||||||||
Partners' capital impact of business combination (Note 7) | $ 3,256 | $ 605 | $ 2,651 | $ 605 | ||||||||
Other | (10) | (10) | (10) | |||||||||
Ending balance at Dec. 31, 2021 | 12,810 | 9,972 | 2,838 | 1,505 | 787 | 7,680 | ||||||
Increase (Decrease) in Partners' Capital [Roll Forward] | ||||||||||||
Net income | 1,228 | 1,037 | 191 | 149 | 52 | 836 | ||||||
Distributions (Note 11) | (1,083) | (785) | (298) | (149) | (52) | (584) | ||||||
Other comprehensive income/(loss) | (101) | (101) | (101) | |||||||||
Equity-indexed compensation expense | 32 | 32 | 32 | |||||||||
Repurchase of common units (Note 11) | (74) | (74) | (74) | |||||||||
Contributions from noncontrolling interests | 26 | 26 | ||||||||||
Partners' capital impact of business combination (Note 7) | $ (26) | $ 526 | $ (10) | $ (16) | $ 526 | $ (10) | ||||||
Other | (13) | (14) | 1 | (14) | ||||||||
Ending balance at Dec. 31, 2022 | 13,325 | 10,057 | 3,268 | 1,505 | 787 | 7,765 | ||||||
Increase (Decrease) in Partners' Capital [Roll Forward] | ||||||||||||
Net income | 1,502 | 1,230 | 272 | 173 | 76 | 981 | ||||||
Distributions (Note 11) | (1,330) | (997) | (333) | (173) | (76) | (748) | ||||||
Other comprehensive income/(loss) | 118 | 118 | 118 | |||||||||
Equity-indexed compensation expense | 36 | 36 | 36 | |||||||||
Contributions from noncontrolling interests | 106 | 106 | ||||||||||
Other | (25) | (22) | (3) | 4 | (26) | |||||||
Ending balance at Dec. 31, 2023 | $ 13,732 | $ 10,422 | $ 3,310 | $ 1,509 | $ 787 | $ 8,126 |
Organization and Basis of Conso
Organization and Basis of Consolidation and Presentation | 12 Months Ended |
Dec. 31, 2023 | |
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 19 for further discussion of our operating segments. Our non-economic general partner interest is held by PAA GP LLC (“PAA GP”), a Delaware limited liability company, whose sole member is Plains AAP, L.P. (“AAP”), a Delaware limited partnership. In addition to its ownership of PAA GP, as of December 31, 2023, AAP also owned a limited partner interest in us through its ownership of approximately 232.7 million of our common units (approximately 30% 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, 2023, owned an approximate 84% 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 SOFR = Secured Overnight Financing Rate 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, 2023 and 2022, 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, 2023, 2022 and 2021. All significant intercompany balances and transactions have been eliminated in consolidation, and certain reclassifications have been made to information from previous years to conform to the current presentation. The accompanying consolidated financial statements include the accounts of PAA and all of its wholly owned subsidiaries and those entities that it controls. Investments in entities over which we have significant influence but not control are accounted for by the equity method. We apply proportionate consolidation for pipelines and other assets in which we own undivided joint interests. Subsequent Events 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, 2023 | |
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, 2023, 2022 and 2021, the revaluation of foreign currency transactions and monetary assets and liabilities resulted in the recognition of a net loss of $8 million, a net loss of $41 million and a net gain of $7 million, respectively, in our Consolidated Statements of Operations. Cash and Cash Equivalents Cash and cash equivalents consist of all unrestricted demand deposits and funds invested in highly liquid instruments with original maturities of three months or less and typically exceed federally insured limits. We periodically assess the financial condition of the institutions where these funds are held and believe that our credit risk is minimal. In accordance with our policy, 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, 2023 and 2022, trade accounts payable included $26 million and $25 million, respectively, of outstanding checks that were reclassified from cash and cash equivalents. 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 11 for additional discussion regarding our noncontrolling interests. Asset Retirement Obligations FASB guidance establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including estimates related to (i) the time of the liability recognition, (ii) initial measurement of the liability, (iii) allocation of asset retirement cost to expense, (iv) subsequent measurement of the liability and (v) financial statement disclosures. FASB guidance also requires that the cost for asset retirement should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. Some of our assets, primarily 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, 2023, 2022 and 2021 (in millions): December 31, 2023 2022 2021 Beginning balance $ 122 $ 143 $ 135 Liabilities incurred 2 2 2 Liabilities settled (1) (1) (26) (1) Accretion expense 4 4 4 Revisions in estimated cash flows (1) (1) 3 Ending balance $ 126 $ 122 $ 143 (1) The 2022 amount primarily relates to the transfer of liabilities to the third party purchaser associated with the sale of Line 901 and the Sisquoc to Pentland portion of Line 903 pipeline. See Note 7 and Note 18 for additional information. 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 and interest rate derivatives includes adjustments for credit risk. Our credit adjustment methodology uses market observable inputs and requires judgment. There were no changes to any of our valuation techniques during the period. See Note 12 for further discussion. Other Significant Accounting Policies See the respective footnotes for our accounting policies regarding (i) revenues and accounts receivable, (ii) net income per common unit, (iii) inventory, linefill and long-term inventory, (iv) property and equipment, (v) acquisitions, (vi) investments in unconsolidated entities, (vii) intangible assets, (viii) income allocation for partners’ capital presentation purposes, (ix) derivatives and risk management activities, (x) leases, (xi) income taxes, (xii) equity-indexed compensation and (xiii) legal and environmental matters. Recent Accounting Pronouncements In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures , which requires, among other things, disaggregated information about effective tax rate reconciliation and income taxes paid (net of refunds received) on an annual basis. The guidance is effective prospectively for annual periods beginning after December 15, 2024 with retrospective or early adoption permitted. We intend to provide the required disclosures prospectively for annual periods beginning after December 15, 2024. In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which requires disaggregated disclosure of significant segment expenses and other amounts included within the reported measure of segment profit or loss for each reportable segment on an annual and interim basis. The guidance is effective retrospectively for annual periods beginning after December 15, 2023, and interim periods in fiscal years beginning after December 15, 2024 with early adoption permitted. We intend to provide the required disclosures beginning with our annual report for the year ended December 31, 2024. In August 2023, the FASB issued ASU 2023-05, Business Combinations—Joint Venture Formations (Subtopic 805-60): Recognition and Initial Measurement , which requires a newly-formed joint venture to apply a new basis of accounting to its contributed net assets, resulting in the joint venture initially measuring its contributed net assets at fair value on the formation date. This guidance is effective prospectively for all joint ventures with a formation date on or after January 1, 2025, with early adoption permitted. We intend to adopt this guidance for joint venture formations on January 1, 2025. 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 adopted this guidance as of January 1, 2023, 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 was effective prospectively upon issuance through December 31, 2022. In December 2022, the FASB issued ASU 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848, |
Revenues and Accounts Receivabl
Revenues and Accounts Receivable | 12 Months Ended |
Dec. 31, 2023 | |
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, 2023 2022 2021 Crude Oil segment revenues from contracts with customers Sales $ 45,621 $ 53,822 $ 39,635 Transportation 1,144 745 484 Terminalling, Storage and Other 381 362 431 Total Crude Oil segment revenues from contracts with customers $ 47,146 $ 54,929 $ 40,550 Year Ended December 31, 2023 2022 2021 NGL segment revenues from contracts with customers Sales $ 1,729 $ 2,414 $ 2,292 Transportation 30 30 25 Terminalling, Storage and Other 94 100 82 Total NGL segment revenues from contracts with customers $ 1,853 $ 2,544 $ 2,399 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. 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 total revenues of reportable segments and total revenues as disclosed in our Consolidated Statements of Operations (in millions): Year Ended December 31, 2023 Crude Oil NGL Total Revenues from contracts with customers $ 47,146 $ 1,853 $ 48,999 Other revenues 28 82 110 Total revenues of reportable segments $ 47,174 $ 1,935 $ 49,109 Intersegment revenues elimination (397) Total revenues $ 48,712 Year Ended December 31, 2022 Crude Oil NGL Total Revenues from contracts with customers $ 54,929 $ 2,544 $ 57,473 Other revenues 151 217 368 Total revenues of reportable segments $ 55,080 $ 2,761 $ 57,841 Intersegment revenues elimination (499) Total revenues $ 57,342 Year Ended December 31, 2021 Crude Oil NGL Total Revenues from contracts with customers $ 40,550 $ 2,399 $ 42,949 Other revenues (80) (431) (511) Total revenues of reportable segments $ 40,470 $ 1,968 $ 42,438 Intersegment revenues elimination (360) Total revenues $ 42,078 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 2023 2022 Billed and collected Other current liabilities $ 77 $ 104 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, 2021 $ 141 Amounts recognized as revenue (26) Additions (1) 145 Other (31) Balance at December 31, 2022 $ 229 Amounts recognized as revenue (42) Additions 38 Other 3 Balance at December 31, 2023 $ 228 (1) Includes approximately $122 million associated with a gas processing agreement that was entered into in conjunction with the purchase of an additional ownership interest in certain straddle plants. Such amount is expected to be recognized as revenue over a 50-year term. See Note 7 for additional information. Remaining Performance Obligations . The information below includes the amount of consideration allocated to partially and wholly unsatisfied remaining performance obligations under contracts that existed 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 contracts 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, 2023 (in millions): 2024 2025 2026 2027 2028 2029 and Thereafter Pipeline revenues supported by minimum volume commitments and capacity agreements (1) $ 375 $ 329 $ 156 $ 109 $ 80 $ 194 Terminalling, storage and other agreement revenues 234 149 114 101 83 688 Total $ 609 $ 478 $ 270 $ 210 $ 163 $ 882 (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 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, 2023 and 2022, 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, 2023 2022 Trade accounts receivable arising from revenues from contracts with customers $ 3,999 $ 4,141 Other trade accounts receivables and other receivables (1) 7,535 7,216 Impact due to contractual rights of offset with counterparties (7,774) (7,450) Trade accounts receivable and other receivables, net $ 3,760 $ 3,907 (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 Per Common Unit
Net Income Per Common Unit | 12 Months Ended |
Dec. 31, 2023 | |
Earnings Per Share [Abstract] | |
Net Income Per Common Unit | Net Income Per Common Unit After consideration of distributions to preferred unitholders, basic and diluted net income per common unit is determined pursuant to the two-class method as prescribed in FASB guidance. This method is an earnings allocation formula that is used to determine allocations to our limited partners and participating securities according to distributions pertaining to the current period’s net income and participation rights in undistributed earnings or distributions in excess of earnings. Under the two-class method, net income is reduced by distributions pertaining to the period, and all remaining earnings or distributions in excess of earnings are then allocated to our common unitholders and participating securities based on their respective rights to share in distributions, regardless of whether those earnings would actually be distributed during a particular period from an economic or practical perspective. Participating securities include equity-indexed compensation plan awards that have vested DERs, which entitle the grantee to a cash payment equal to the cash distribution paid on our outstanding common units. We calculate basic and diluted net income per common unit by dividing net income attributable to PAA (after deducting amounts allocated to the preferred unitholders and participating securities) by the basic and diluted weighted average number of common units outstanding during the period. The diluted weighted average number of common units is computed based on the weighted average number of common units plus the effect of potentially dilutive securities outstanding during the period, which include (i) our Series A preferred units and (ii) our equity-indexed compensation plan awards. See Note 11 for additional information regarding our Series A preferred units. See Note 17 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 per common unit for the years ended December 31, 2023, 2022 and 2021 as the effect was antidilutive for all 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 are deemed to be dilutive during the year are reduced by a hypothetical common unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. The following table sets forth the computation of basic and diluted net income per common unit (in millions, except per unit data): Year Ended December 31, 2023 2022 2021 Basic and Diluted Net Income per Common Unit Net income attributable to PAA $ 1,230 $ 1,037 $ 593 Distributions to Series A preferred unitholders (173) (149) (149) Distributions to Series B preferred unitholders (76) (52) (49) Amounts allocated to participating securities (10) (5) (2) Other 5 — — Net income allocated to common unitholders (1) $ 976 $ 831 $ 393 Basic and diluted weighted average common units outstanding 699 701 716 Basic and diluted net income per common unit $ 1.40 $ 1.19 $ 0.55 (1) We calculate net income allocated to common unitholders based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings (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 Long-te
Inventory, Linefill and Long-term Inventory | 12 Months Ended |
Dec. 31, 2023 | |
Inventory Disclosure [Abstract] | |
Inventory, Linefill and Long-term Inventory | Inventory, Linefill 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. No adjustments were recorded during the years ended December 31, 2023, 2022 or 2021. Linefill in assets we own is recorded at historical cost and consists of crude oil and NGL. We classify as linefill (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 and (ii) barrels that represent the minimum working requirements in tanks and caverns that we own. Linefill 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 2023, 2022 and 2021, we did not recognize any material impairments of linefill. 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 long-term inventory consisted of the following (barrels in thousands and carrying value in millions): December 31, 2023 December 31, 2022 Volumes Unit of Carrying Price/ Unit (1) Volumes Unit of Carrying Price/ Unit (1) Inventory Crude oil 5,877 barrels $ 383 $ 65.17 6,713 barrels $ 452 $ 67.33 NGL 5,957 barrels 154 $ 25.85 7,285 barrels 270 $ 37.06 Other N/A 11 N/A N/A 7 N/A Inventory subtotal 548 729 Linefill Crude oil 15,409 barrels 909 $ 58.99 15,480 barrels 906 $ 58.53 NGL 2,168 barrels 67 $ 30.90 1,876 barrels 55 $ 29.32 Linefill subtotal 976 961 Long-term inventory Crude oil 3,256 barrels 232 $ 71.25 3,102 barrels 246 $ 79.30 NGL 1,326 barrels 33 $ 24.89 1,066 barrels 38 $ 35.65 Long-term inventory subtotal 265 284 Total $ 1,789 $ 1,974 (1) Price per unit of measure is comprised of a weighted average associated with various grades, qualities and locations. Accordingly, these prices may not coincide with any published benchmarks for such products. |
Property and Equipment
Property and Equipment | 12 Months Ended |
Dec. 31, 2023 | |
Property, Plant and Equipment [Abstract] | |
Property and Equipment | Property and Equipment In accordance with our capitalization policy, expenditures made to expand the existing operating and/or earnings capacity of our assets are capitalized, as are certain costs directly related to the construction of such assets, including related internal labor costs, engineering costs and interest costs. 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, 2023 2022 Crude oil pipeline systems 10 - 50 $ 14,265 $ 13,303 Crude oil storage and terminal facilities 10 - 50 2,664 2,631 NGL storage, terminal, fractionation and processing facilities 10 - 50 2,554 2,445 NGL pipeline systems 10 - 50 506 458 Office property and equipment and rolling stock 2 - 50 556 656 Construction in progress N/A 257 201 Land and other N/A 341 326 Property and equipment, gross (1) 21,143 20,020 Accumulated depreciation (5,361) (4,770) Property and equipment, net $ 15,782 $ 15,250 (1) We include rights-of-way, which are intangible assets, within property and equipment. We calculate our depreciation using the straight-line method, based on estimated useful lives and salvage values of our assets. Depreciation expense for the years ended December 31, 2023, 2022 and 2021 was $733 million, $707 million and $652 million, respectively. As of December 31, 2023, 2022 and 2021, we incurred liabilities of $55 million, $46 million and $48 million, respectively, for construction in progress that had not been paid. 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. We did not recognize any material impairments during the year ended December 31, 2023. During the third quarter of 2022, we temporarily ceased service on a crude oil pipeline in California as a precautionary measure following a routine inspection and initiated a program of additional tests and inspections. After assessing the results of such tests and the changing operating conditions of our California assets, we determined that we had a triggering event due to the effect on future cash flows for certain of our assets that required us to assess the recoverability of our carrying value of our California crude oil assets (which includes the temporarily idled pipeline) reported in our Crude Oil segment. 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. We recognized a non-cash loss of approximately $330 million, which amount is reflected in “ (Gains)/losses on asset sales and asset impairments, net (Gains)/losses on asset sales and asset impairments, net |
Acquisitions, Divestitures and
Acquisitions, Divestitures and Other Transactions | 12 Months Ended |
Dec. 31, 2023 | |
Business Combination and Asset Acquisition [Abstract] | |
Acquisitions, Divestitures and Other Transactions | Acquisitions, Divestitures and Other Transactions Acquisitions Rattler Permian Transaction In the third quarter of 2023, we completed a transaction with Rattler Midstream Operating LLC (“Rattler”) pursuant to which the Permian JV acquired the remaining 43% interest in OMOG JV Holdings LLC (“OMOG”) and certain gathering assets in the Southern Delaware basin. The transaction had an aggregate purchase price of $294 million ($191 million net to our 65% interest in the Permian JV). As a result of the transaction, the Permian JV now owns 100% of OMOG and its subsidiaries and such entities are reflected as consolidated subsidiaries in our Consolidated Financial Statements. Prior to this transaction, the Permian JV’s 57% interest in OMOG was accounted for as an equity method investment. The transaction was accounted for as a business combination using the acquisition method of accounting. In accordance with applicable accounting guidance, the fair value of the assets acquired and liabilities assumed following the transaction was utilized as the consideration transferred for the purchase price allocation. As a result of us obtaining control over OMOG, the Permian JV’s previously-held 57% interest in OMOG was remeasured to its fair value of $239 million based upon a valuation of the acquired business, as of the date of acquisition. We considered multiple factors in determining the fair value of the previously-held equity method investment, including, (i) the price negotiated with Rattler for its 43% interest in OMOG and (ii) a discounted cash flow approach. The discounted cash flow approach utilized a discount rate of approximately 11%, based on the estimate of the risk that a theoretical market participant would assign to the business. The remeasurement of the Permian JV’s investment in OMOG to fair value resulted in a gain of $29 million. This gain has been recognized in the line item “Gains/(losses) on investments in unconsolidated entities, net” on our Consolidated Statement of Operations. The determination of the fair value of the assets and liabilities assumed was estimated in accordance with applicable accounting guidance. The analysis was performed based on estimates that are reflective of market participant assumptions. While the purchase price for the transaction was $294 million, all of the OMOG assets and liabilities were remeasured to fair value and therefore, the fair value of the assets and liabilities that are now consolidated on the balance sheet as a result of this transaction is $532 million. The following table reflects our determination of the fair value of the assets acquired and liabilities assumed in connection with the transaction (in millions): Identifiable Assets Acquired and Liabilities Assumed: Estimated Useful Lives Recognized Amount Property and equipment 3-30 $ 484 Intangible assets 10 34 Working capital and other assets and liabilities N/A 14 $ 532 The fair value of the tangible assets is a Level 3 measurement in the fair value hierarchy and was determined using the 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 discount rates varying from approximately 21% to 23%, 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 transported and the estimated tariff rates for transportation were also key assumptions in the valuation of the intangible assets. Projected future volumes and estimated tariff rates were based on current contracts in place with assumptions for forecasted rate increases and contract renewals. 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 10 years. The value assigned to such intangible assets will be amortized to earnings under the declining balance method of amortization. Amortization expense was approximately $4 million during the year ended December 31, 2023, and the future amortization expense through 2028 is estimated as follows (in millions): 2024 $ 8 2025 $ 10 2026 $ 4 2027 $ 3 2028 $ 2 Pro forma financial information assuming the acquisition had occurred as of the beginning of the calendar year prior to the year of the acquisition, as well as the revenues and earnings generated during the period since the acquisition date, were not material for disclosure purposes. Cactus II In November 2022, we and Enbridge Inc. (“Enbridge”) purchased Western Midstream Partners, LP (“WES”)’s 15% interest in Cactus II Pipeline, LLC (“Cactus II”) for an aggregate amount of $265 million. Enbridge acquired 10% and we acquired 5% of Cactus II, with each paying a proportionate share ($177 million and $88 million, respectively) of the aggregate purchase price. We and Enbridge are now the sole owners of Cactus II, with 70% and 30% respective ownership interests. We will continue to serve as operator. We previously accounted for our 65% interest in Cactus II as an equity method investment. In addition to the change in ownership, there were changes in governance which led to a change in control. We now control Cactus II and reflect Cactus II as a consolidated subsidiary in our Consolidated Financial Statements, with Enbridge’s 30% interest reflected as a noncontrolling interest. The acquisition was accounted for as a business combination achieved in stages, or a “step acquisition”, using the acquisition method of accounting. As the majority owner and the controlling entity, we are considered the acquirer and the Cactus II predecessor business was recorded based on the fair value of the assets acquired and liabilities assumed, with Enbridge’s 30% interest in Cactus II of $526 million recognized as noncontrolling interest in partners’ capital. As a result of us obtaining control over Cactus II, our previously held 65% interest in Cactus II was remeasured to its fair value of $1.140 billion based upon a valuation of the acquired business, as of the date of acquisition. We considered multiple factors in determining the fair value of the previously held equity method investment, including, (i) the price negotiated with WES for its 15% interest in Cactus II and (ii) a discounted cash flow approach. The discounted cash flow approach utilized a discount rate of approximately 14%, based on the estimate of the risk that a theoretical market participant would assign to the business. Prior to the acquisition, we had a preexisting relationship with Cactus II, through one of our consolidated joint ventures, for certain capacity lease agreements. The portion of the fair value of Cactus II associated with these agreements is eliminated in consolidation. Accounting for such impact, the remeasurement of our investment in Cactus II to fair value resulted in a gain of $370 million. This gain has been recognized in the line item “Gains/(losses) on investments in unconsolidated entities, net” on our Consolidated Statement of Operations In accordance with applicable accounting guidance, the fair value of Cactus II following the acquisition is utilized as the consideration transferred for the purchase price allocation. The consideration transferred of $1.556 billion excludes the value associated with the capacity lease agreements described above as such value is eliminated for our Consolidated Financial Statements. 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 following table reflects our 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 3-50 $ 1,174 Intangible assets 20 428 Working capital and other assets and liabilities N/A (46) $ 1,556 The fair value of the tangible assets is a Level 3 measurement in the fair value hierarchy and was determined using a market approach for rights-of-way and a cost approach for other tangible assets, which were 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 18%, 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 transported and the estimated tariff rates for transportation were also key assumptions in the valuation of the intangible assets. Projected future volumes and estimated tariff rates were based on current contracts in place with assumptions for forecasted rate increases and contract renewals. 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 $61 million and $13 million during the years ended December 31, 2023 and 2022, respectively, and the future amortization expense through 2027 is estimated as follows (in millions): 2024 $ 51 2025 $ 47 2026 $ 32 2027 $ 32 Pro forma financial information assuming the step acquisition had occurred as of the beginning of the calendar year prior to the year of the step acquisition, as well as the revenues and earnings generated during the period since the step acquisition date, were not material for disclosure purposes. Other Acquisitions In November 2023, we acquired a crude oil gathering system in the Northern Delaware Basin from a subsidiary of LM Energy Partners for approximately $135 million (approximately $88 million net to our 65% interest in the Permian JV), subject to certain adjustments. This transaction was accounted for as an asset acquisition since substantially all of the value of the assets acquired was concentrated in a single asset. During the year ended December 31, 2022, we also completed the following acquisitions: • the acquisition in July 2022 of the remaining 50% interest in Advantage Pipeline Holdings LLC (“Advantage”) for $74 million (approximately $48 million net to our 65% interest in the Permian JV), including cash paid for working capital. As a result of this transaction, we now own 100% of Advantage and its subsidiaries and such entities are reflected as consolidated subsidiaries in our Consolidated Financial Statements. • the acquisition in October 2022 of an additional ownership interest in certain straddle plants included in our NGL segment in a non-cash transaction whereby we agreed to provide processing capacity over a 50-year term at specified terms and conditions. This transaction was accounted for as an asset acquisition. The fair value of the straddle plant assets acquired and liabilities assumed was approximately $122 million, and we recognized an equally offsetting contract liability that will be amortized on a straight-line basis into “Services revenue” over the 50-year term of the agreement. 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. 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 $3.230 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 $7.529 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 $ 2,635 Partners’ capital, excluding noncontrolling interests 595 $ 3,230 The fair value of the $3.230 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 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 discounted cash flow approach utilized a discount rate of 12%, 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 discounted cash flow 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 following table reflects our 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 Working capital and other assets and liabilities N/A (6) $ 3,230 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 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 $138 million, $142 million and $28 million during the years ended December 31, 2023, 2022 and 2021, respectively, and the future amortization expense through 2026 is estimated as follows (in millions): 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. 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, monthly distributions of available cash will be paid 65% to PAA and 35% to Oryx. Through the third quarter of 2022, the Permian JV made quarterly distributions, but starting in December 2022, the Permian JV began making monthly distributions to the members after renegotiation of the MSA. 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, 2021. 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, 2021; 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 Total revenues $ 42,359 Net income attributable to PAA $ 524 Net income allocated to common unitholders $ 324 Basic and diluted net income per common unit $ 0.45 Divestitures In February 2023, we sold our 21% non-operated/undivided joint interest in the Keyera Fort Saskatchewan facility to Keyera Corporation for approximately $270 million. As of December 31, 2022, we classified the assets related to this transaction (primarily “Property and equipment” in our NGL segment), valued at the lower of the carrying amount or fair value less costs to sell, of approximately $130 million as assets held for sale on our Consolidated Balance Sheet (in “Other current assets”). Upon the sale of this facility, we recognized a gain of approximately $140 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, 2022, we sold certain non-core assets for total proceeds of $60 million. The assets sold primarily consisted of land and related assets in Long Beach, California, as well as Line 901 and the Sisquoc to Pentland portion of Line 903. These assets were previously reported in our Crude Oil segment. We recognized gains of $61 million related to these asset sales, a portion of which relates to the transfer of an asset retirement obligation to the purchaser. Such amounts are included in “(Gains)/losses on asset sales and asset impairments, net” on our Consolidated Statement of Operations. 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. |
Investments in Unconsolidated E
Investments in Unconsolidated Entities | 12 Months Ended |
Dec. 31, 2023 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Investments in Unconsolidated Entities | Investments in Unconsolidated Entities Investments in entities over which we have significant influence but not control are accounted for 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, 2023 Investment Balance Entity (1) Type of Operation 2023 2022 BridgeTex Pipeline Company, LLC (“BridgeTex”) Crude Oil Pipeline 20% $ 363 $ 403 Capline Pipeline Company LLC (“Capline”) Crude Oil Pipeline 54% 535 539 Diamond Pipeline LLC Crude Oil Pipeline 50% 450 460 Eagle Ford Pipeline LLC Crude Oil Pipeline 50% 370 371 Eagle Ford Terminals Corpus Christi LLC Crude Oil Terminal and Dock 50% 116 118 OMOG JV LLC (“OMOG”) (2) Crude Oil Pipeline —% — 211 Saddlehorn Pipeline Company, LLC Crude Oil Pipeline 30% 192 197 White Cliffs Pipeline, LLC Crude Oil Pipeline 36% 138 150 Wink to Webster Pipeline LLC (“W2W Pipeline”) (3) Crude Oil Pipeline 16% 380 357 Other investments 276 278 Total Investments in Unconsolidated Entities $ 2,820 $ 3,084 (1) The financial results from these entities are reported in our Crude Oil segment. (2) In the third quarter of 2023, we acquired the remaining 43% interest in OMOG. We now reflect OMOG and its subsidiaries as consolidated subsidiaries in our Consolidated Financial Statements. See Note 7 for additional information. (3) 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. Acquisitions During the fourth quarter of 2022, through a non-monetary transaction, we acquired an additional interest in OMOG in exchange for the contribution of portions of two pipeline systems. After the transaction, our ownership interest in OMOG increased to 57% from 40%. Subsequent to this transaction, we continued to account for OMOG as an equity method investment because the joint venture partner still retained substantive participating rights. The transaction resulted in a loss of approximately $25 million, which represents the difference between the fair value and historical book value of the assets contributed. This loss is reflected in “Gains/(losses) on investments in unconsolidated entities, net” on our Consolidated Statement of Operations. In the third quarter of 2023, we acquired the remaining 43% interest in OMOG. We now reflect OMOG and its subsidiaries as consolidated subsidiaries in our Consolidated Financial Statements. See Note 7 for additional information. In July 2022, we acquired the remaining 50% interest in Advantage. Prior to the acquisition, our 50% interest in Advantage was accounted for as an equity method investment. See Note 7 for additional information. In November 2022, we acquired an additional 5% interest in Cactus II which, combined with changes in governance, resulted in our obtaining control of the entity. We now reflect Cactus II as a consolidated subsidiary in our Consolidated Financial Statements. See Note 7 for additional information. 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. During the years ended December 31, 2023, 2022 and 2021, we made cash contributions of $29 million, $13 million and $82 million, respectively, to certain of our equity method investees. We capitalize interest costs associated with contributions to unconsolidated entities for projects under development and construction. Our contributions to these entities (including capitalized interest costs) increase the carrying value of our investments and are reflected in our Consolidated Statements of Cash Flows as cash used in investing activities. Basis Differences Our investments in unconsolidated entities exceeded our share of the underlying equity in the net assets of such entities by $229 million and $204 million at December 31, 2023 and 2022, 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, 2023 and 2022 was attributable to goodwill related to our ownership interest in BridgeTex and Capline 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, 2023 2022 Current assets $ 528 $ 471 Noncurrent assets $ 7,194 $ 7,579 Current liabilities $ 476 $ 252 Noncurrent liabilities $ 5 $ 8 Year Ended December 31, 2023 2022 2021 Revenues $ 1,667 $ 1,726 $ 1,320 Operating income $ 921 $ 1,004 $ 505 Net income $ 947 $ 1,011 $ 506 |
Intangible Asset, Net
Intangible Asset, Net | 12 Months Ended |
Dec. 31, 2023 | |
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, 2023 December 31, 2022 Estimated Useful Cost Accumulated Net Cost Accumulated Net Customer contracts and relationships 1 – 29 $ 2,789 $ (932) $ 1,857 $ 2,817 $ (695) $ 2,122 Other agreements 15 – 70 30 (12) 18 35 (12) 23 Intangible assets (1) $ 2,819 $ (944) $ 1,875 $ 2,852 $ (707) $ 2,145 (1) We include rights-of-way, which are intangible assets, 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, 2023. The majority of our finite-lived intangible assets are amortized under the declining balance method. Amortization expense for finite-lived intangible assets for the years ended December 31, 2023, 2022 and 2021 was $308 million, $254 million and $122 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): 2024 $ 272 2025 $ 249 2026 $ 210 2027 $ 187 2028 $ 165 |
Debt
Debt | 12 Months Ended |
Dec. 31, 2023 | |
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 5.8% (1) $ 433 $ — Senior notes: 2.85% senior notes due January 2023 — 400 3.85% senior notes due October 2023 — 700 Other 13 59 Total short-term debt 446 1,159 LONG-TERM DEBT Senior notes: 3.60% senior notes due November 2024 (2) 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 499 499 4.30% senior notes due January 2043 348 348 4.70% senior notes due June 2044 687 687 4.90% senior notes due February 2045 649 649 Unamortized discounts and debt issuance costs (41) (46) Senior notes, net of unamortized discounts and debt issuance costs 7,242 7,237 Other long-term debt: Other 63 50 Total long-term debt 7,305 7,287 Total debt (3) $ 7,751 $ 8,446 (1) We classified these commercial paper notes as short-term as of December 31, 2023, as these notes were primarily designated as working capital borrowings, were required to be repaid within one year and were primarily for hedged NGL and crude oil inventory and NYMEX and ICE margin deposits. (2) As of December 31, 2023, we classified our 3.60%, $750 million senior notes due November 2024 as long-term based on our ability and intent to refinance these notes on a long-term basis. (3) Our fixed-rate senior notes had a face value of approximately $7.3 billion and $8.4 billion at December 31, 2023 and 2022, respectively. We estimated the aggregate fair value of these notes to be approximately $6.9 billion and $7.6 billion at December 31, 2023 and 2022, respectively. Our fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near the end of the reporting period. We estimate that the carrying value of outstanding borrowings under our commercial paper program approximates fair value as interest rates reflect current market rates. The fair value estimates for our senior notes and commercial paper program are based upon observable market data and are classified in Level 2 of the fair value hierarchy. Commercial Paper Program We have a commercial paper program under which we may issue (and have outstanding at any time) up to $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 . We have a credit agreement that provides for a senior secured hedged inventory facility with a committed borrowing capacity of $1.35 billion. 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 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. In August 2023, we extended the maturity date of the facility to August 2026 for each existing lender. Senior unsecured revolving credit facility. We have a credit agreement that provides for a senior unsecured revolving credit facility with a committed borrowing capacity of $1.35 billion, of which $400 million is available for the issuance of letters of credit. 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 credit agreement provides for one or more one-year extensions, subject to applicable approval and other terms and conditions. In August 2023, we extended the maturity date of the facility to August 2028 for each extending lender. The maturity date with respect to the non-extending lender (which represents a commitment of approximately $64 million out of total commitments of $1.35 billion from all lenders) remains August 2027. GO Zone term loans . In August 2021, in connection with the sale of the Southern Pines natural gas storage facility, we repaid $200 million of term loans (the “Go Zone term loans”) that were initially assumed in connection with our acquisition of that 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 Repayments. During the three years ended December 31, 2023, we repaid the following senior unsecured notes in full (in millions): Year Description Repayment Date 2023 $700 million 3.85% Senior Notes due October 2023 October 2023 (1) 2023 $400 million 2.85% Senior Notes due January 2023 January 2023 (1) 2022 $750 million 3.65% Senior Notes due June 2022 March 2022 (1) (1) We repaid these senior notes with cash on hand and borrowings under our commercial paper program. Maturities The weighted average maturity of our senior notes outstanding at December 31, 2023 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) 2024 $ 750 2025 $ 1,000 2026 $ 750 2027 $ — 2028 $ — 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, 2023, 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, 2023, 2022 and 2021 were approximately $18.1 billion, $25.0 billion and $32.5 billion, respectively. Total repayments under our credit facilities and commercial paper program were approximately $17.7 billion, $25.0 billion and $33.2 billion for the years ended December 31, 2023, 2022 and 2021, 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. 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, 2023 and 2022, we had outstanding letters of credit of $205 million and $102 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, 2023 | |
Partners' Capital Notes [Abstract] | |
Partners' Capital and Distributions | Partners’ Capital and Distributions Units Outstanding At December 31, 2023, partners’ capital consisted of outstanding common units and Series A and Series B preferred units, which represent limited partner interests in us and 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, to unitholders of record within 45 days following the end of each quarter. The initial Series A preferred unit distribution was equal to $0.525 per unit ($2.10 per unit annualized). After the fifth anniversary of the January 28, 2016 issuance date (the “Issuance Date”) of the Series A preferred units, the holders of the Series A preferred units, acting by majority vote, had the option to 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 was accounted for as an embedded derivative. See Note 12 for additional information. In January 2023, the Series A preferred unitholders elected the Preferred Distribution Rate Reset Option. Effective January 31, 2023, the new Series A preferred unit distribution rate is equal to 9.375% per annum of the original Issue Price (approximately $2.46 per unit annualized). The quarterly distribution paid in May 2023 reflected a pro-rated amount of approximately $0.585 per unit. We may redeem all or any portion of the outstanding Series A preferred units (subject to certain redemption size limitations and limited to two redemption transactions) in exchange for cash, common units (valued at 95% of the volume-weighted average price of our common units for a trading 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. 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). The Series A preferred units vote on an as-converted basis with our common units on the election of directors 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. 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, 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. Through November 15, 2022, distributions on the Series B preferred units were paid semiannually in arrears on the 15th day of May and November. After November 15, 2022, distributions are payable 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 was 6.125% per year of the liquidation preference per unit (equal to $61.25 per unit per year). From November 15, 2022 through August 14, 2023, distributions on the Series B preferred units accumulated for each distribution period at a percentage of the liquidation preference equal to the applicable three-month LIBOR plus a spread of 4.11% per annum. Beginning August 15, 2023, distributions on the Series B preferred units accumulate based on the applicable three-month SOFR, plus a credit spread adjustment of 0.26121%, plus 4.11% per annum. The distribution rate for the quarterly distribution paid on February 15, 2024 was 9.75093% per annum ($24.92 per Series B preferred unit). At any time, 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, 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 Repurchase and cancellation of common units under the Common Equity Repurchase Program — — (7,251,361) Issuances of common units under equity-indexed compensation plans — — 614,319 Outstanding at December 31, 2022 71,090,468 800,000 698,354,498 Issuances of common units under equity-indexed compensation plans — — 2,654,251 Outstanding at December 31, 2023 71,090,468 800,000 701,008,749 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 16 for additional information regarding our ownership of PAGP Class C shares. There were no repurchases under the Program during the year ended December 31, 2023. During the years ended December 31, 2022 and 2021, we repurchased common units under the Program through open market purchases for a total purchase price of $74 million and $178 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, 2023, the remaining available capacity under the Program was $198 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. 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 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 Series A Preferred Unit Distributions. The following table details distributions paid to our Series A preferred unitholders during the years presented (in millions, except unit data): Series A Preferred Unitholders Year Cash Distribution Distribution per Unit 2023 $ 166 $ 2.34 2022 $ 149 $ 2.10 2021 $ 149 $ 2.10 On February 14, 2024, we paid a cash distribution of $44 million to our Series A preferred unitholders. At December 31, 2023, such amount was accrued as distributions payable in “Other current liabilities” on our Consolidated Balance Sheet. Series B Preferred Unit Distributions. The following table details distributions paid to our Series B preferred unitholders during the years presented (in millions, except unit data): Series B Preferred Unitholders Year Cash Distribution Distribution per Unit 2023 $ 75 $ 93.43 2022 $ 49 $ 61.25 2021 $ 49 $ 61.25 On February 15, 2024, we paid a cash distribution of $20 million ($24.92 per unit) to our Series B preferred unitholders. At December 31, 2023, approximately $10 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 2023 $ 492 $ 256 $ 748 $ 1.0700 2022 $ 383 $ 201 $ 584 $ 0.8325 2021 $ 341 $ 176 $ 517 $ 0.7200 On January 8, 2024, we declared a cash distribution of $0.3175 per unit on our outstanding common units. The total distribution of $223 million was paid on February 14, 2024 to unitholders of record at the close of business on January 31, 2024, for the period from October 1, 2023 through December 31, 2023. Of this amount, approximately $74 million was paid to AAP. Noncontrolling Interests in Subsidiaries As of December 31, 2023, noncontrolling interests in our subsidiaries consisted of (i) a 35% interest in the Permian JV, (ii) a 30% interest in Cactus II and (iii) a 33% interest in Red River Pipeline Company LLC (“Red River”). The transactions resulting in the recognition of noncontrolling interests in the Permian JV and Cactus II are described below. In November 2022, we acquired an additional 5% interest in Cactus II which, combined with changes in governance, resulted in our obtaining control of the entity. We own 70% of Cactus II and reflect the entity as a consolidated subsidiary in our Consolidated Financial Statements, with Enbridge’s 30% interest accounted for as a noncontrolling interest. This transaction resulted in the recognition of partners’ capital attributable to noncontrolling interests of approximately $526 million. See Note 7 for more details regarding this transaction. 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 $2.6 billion and an increase to our partners’ capital excluding noncontrolling interests of approximately $595 million. See Note 7 for more details regarding this transaction. Distributions to Noncontrolling Interests Pursuant to the terms of the governing documents for the Permian JV, with the exception of the initial distribution paid in the first quarter of 2022, distributions of available cash from the Permian JV are subject to a tiered modified sharing arrangement. See Note 7 for additional information. Cash available for distribution is cash on hand less the amount of cash required to fund normal operations and capital projects. Distributions from Cactus II and Red River are paid in proportion to each owners interest in the entity. The following table details distributions paid to noncontrolling interests during the years presented (in millions): 2023 2022 2021 Permian JV (1) $ 249 $ 273 $ — Cactus II 63 4 — Red River 21 21 14 $ 333 $ 298 $ 14 (1) The initial distribution from the Permian JV was paid during the first quarter of 2022, with approximately $54 million paid to noncontrolling interests. |
Derivatives and Risk Management
Derivatives and Risk Management Activities | 12 Months Ended |
Dec. 31, 2023 | |
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 commodity price risk and interest 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 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 or interest 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, 2023 and 2022, 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 are described below. 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, 2023, net derivative positions related to these activities included: • A net long position of 6.3 million barrels associated with our crude oil purchases, which was unwound ratably during January 2024 to match monthly average pricing. • A net short time spread position of 5.6 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through January 2025. • A net crude oil basis spread position of 2.3 million barrels at multiple locations through December 2024. These derivatives allow us to lock in grade and location basis differentials. • A net short position of 18.2 million barrels through March 2025 related to anticipated net sales of crude oil and NGL inventory. 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, 2023. Notional Volume Remaining Tenor Natural gas purchases 78.2 Bcf December 2025 Propane sales (14.1) MMbls December 2025 Butane sales (2.5) MMbls December 2024 Condensate sales (3.1) MMbls December 2024 Fuel gas requirements (1) 7.1 Bcf December 2024 Power supply requirements (1) 2.4 TWh December 2030 (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, 2023 2022 2021 Product sales revenues $ 13 $ 179 $ (710) Field operating costs (45) 59 71 Net gain/(loss) from commodity derivative activity $ (32) $ 238 $ (639) 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, 2023 2022 Initial margin $ 77 $ 93 Variation margin returned (65) (236) Letters of credit (25) (25) Net broker payable $ (13) $ (168) 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, 2023 December 31, 2022 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 $ 153 $ (79) $ (13) $ 61 $ 300 $ (71) $ (168) $ 61 Other long-term assets, net 3 — — 3 9 (5) — 4 Derivative Liabilities Other current liabilities 1 (64) — (63) 2 (13) — (11) Other long-term liabilities and deferred credits 1 (15) — (14) — — — — Total $ 158 $ (158) $ (13) $ (13) $ 311 $ (89) $ (168) $ 54 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, 2023 (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 6/15/2026 3.09 % Cash flow hedge Anticipated interest payments 4 forward starting swaps (30-year) $ 100 6/14/2024 0.74 % Cash flow hedge During the year ended December 31, 2023, we terminated $200 million of notional interest hedging instruments previously expected to terminate in June 2023 for proceeds of $80 million, of which $73 million was recorded in AOCI. As of December 31, 2023, there was a net loss of $81 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. The early termination did not result in an impact to the relationship between the hedging instrument and hedged item. We estimate that substantially all of the remaining deferred loss will be reclassified to earnings through 2056 as the underlying hedged transactions impact earnings. A portion of these amounts is based on market prices as of December 31, 2023; 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, 2023 2022 2021 Interest rate derivatives, net $ 15 $ 94 $ 19 At December 31, 2023, the net fair value of our interest rate hedges, which were included in “Other current assets” and “Other long-term assets, net” on our Consolidated Balance Sheet, totaled $51 million and $4 million, respectively. At December 31, 2022, the net fair value of these hedges totaled $75 million and $45 million, which were included in “Other current assets” and “Other long-term assets, net”, respectively. Preferred Distribution Rate Reset Option In January 2023, we received notice that the Series A preferred unitholders elected the Preferred Distribution Rate Reset Option. Prior to this election, the Preferred Distribution Rate Reset Option was accounted for as an embedded derivative. 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 embedded derivative was required to be bifurcated from the related host contract, our partnership agreement, and recorded at fair value on our Consolidated Balance Sheet. The fair value of the Preferred Distribution Rate Reset Option, which was included in “ Other long-term liabilities and deferred credits 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, 2023 Fair Value as of December 31, 2022 Recurring Fair Value Measures (1) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Commodity derivatives $ 9 $ (9) $ — $ — $ (7) $ 229 $ — $ 222 Interest rate derivatives — 55 — 55 — 120 — 120 Preferred Distribution Rate Reset Option — — — — — — (189) (189) Total net derivative asset/(liability) $ 9 $ 46 $ — $ 55 $ (7) $ 349 $ (189) $ 153 (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 and interest rate 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 the Preferred Distribution Rate Reset Option contained in our partnership agreement which was classified as an embedded derivative. As discussed above, the Preferred Distribution Rate Reset Option was settled on January 31, 2023. The fair value of the Preferred Distribution Rate Reset Option was based on a Monte Carlo valuation model that estimated the fair value of the Series A preferred units with and without the Preferred Distribution Rate Reset Option. This model relied on assumptions for forecasts for the ten-year U.S. Treasury rate, our common unit price, and default probabilities which impacted timing estimates as to when the option would be exercised. 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, 2023 2022 Beginning Balance $ (189) $ (2) Net gains/(losses) for the period included in earnings 58 (189) Settlements 131 2 Ending Balance $ — $ (189) Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period $ — $ (189) |
Leases
Leases | 12 Months Ended |
Dec. 31, 2023 | |
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 57 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 2023 2022 2021 Operating lease cost $ 86 $ 91 $ 96 Short-term lease cost 15 18 19 Other (1) 8 15 14 Total lease cost $ 109 $ 124 $ 129 (1) Includes finance lease costs, variable lease costs and sublease income. The following table presents information related to cash flows arising from lease transactions (in millions): Year Ended December 31, 2023 2022 2021 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases $ 81 $ 92 $ 91 Operating cash flows for finance leases $ 6 $ 6 $ 7 Financing cash flows for finance leases $ 11 $ 12 $ 11 Non-cash change in lease liabilities arising from obtaining new right-of-use assets or modifications: Operating leases $ 32 $ 43 $ 94 Finance leases $ 27 $ 2 $ 1 Information related to the weighted-average remaining lease term and discount rate is presented in the table below: December 31, 2023 2022 Weighted-average remaining lease term (in years): Operating leases 13 12 Finance leases 8 9 Weighted-average discount rate: Operating leases 4.9 % 4.3 % Finance leases 11.3 % 12.3 % 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 2023 2022 Assets Operating lease right-of-use assets Long-term operating lease right-of-use assets, net $ 313 $ 349 Finance lease right-of-use assets (1) Property and equipment $ 144 $ 124 Accumulated depreciation (46) (41) Property and equipment, net $ 98 $ 83 Total lease right-of-use assets $ 411 $ 432 Liabilities Operating lease liabilities Current Other current liabilities $ 69 $ 71 Noncurrent Long-term operating lease liabilities 274 308 Total operating lease liabilities $ 343 $ 379 Finance lease liabilities (1) Current Short-term debt $ 13 $ 10 Noncurrent Other long-term debt, net 63 50 Total finance lease liabilities $ 76 $ 60 Total lease liabilities $ 419 $ 439 (1) Includes right-of-use assets of $28 million and $30 million and lease liabilities of $34 million and $35 million as of December 31, 2023 and 2022, 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, 2023 reconciled to our lease liabilities on our Consolidated Balance Sheet (amounts in millions): Operating Finance (2) Future minimum lease payments (1) : 2024 $ 80 $ 20 2025 68 17 2026 51 13 2027 43 12 2028 34 15 Thereafter 238 48 Total 514 125 Less: Present value discount (171) (49) Lease liabilities $ 343 $ 76 (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 2024 through 2028 and approximately $45 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, 2023 2022 2021 Operating lease revenue (1) $ 32 $ 29 $ 28 (1) These amounts are included in “ Services revenues The table below presents the maturity of lease payments for operating lease agreements in effect as of December 31, 2023. 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 18 years. The following table presents the undiscounted cash flows expected to be received related to these agreements (in millions): 2024 2025 2026 2027 2028 Thereafter Future minimum lease revenue $ 24 $ 18 $ 15 $ 16 $ 16 $ 154 |
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 57 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 2023 2022 2021 Operating lease cost $ 86 $ 91 $ 96 Short-term lease cost 15 18 19 Other (1) 8 15 14 Total lease cost $ 109 $ 124 $ 129 (1) Includes finance lease costs, variable lease costs and sublease income. The following table presents information related to cash flows arising from lease transactions (in millions): Year Ended December 31, 2023 2022 2021 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases $ 81 $ 92 $ 91 Operating cash flows for finance leases $ 6 $ 6 $ 7 Financing cash flows for finance leases $ 11 $ 12 $ 11 Non-cash change in lease liabilities arising from obtaining new right-of-use assets or modifications: Operating leases $ 32 $ 43 $ 94 Finance leases $ 27 $ 2 $ 1 Information related to the weighted-average remaining lease term and discount rate is presented in the table below: December 31, 2023 2022 Weighted-average remaining lease term (in years): Operating leases 13 12 Finance leases 8 9 Weighted-average discount rate: Operating leases 4.9 % 4.3 % Finance leases 11.3 % 12.3 % 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 2023 2022 Assets Operating lease right-of-use assets Long-term operating lease right-of-use assets, net $ 313 $ 349 Finance lease right-of-use assets (1) Property and equipment $ 144 $ 124 Accumulated depreciation (46) (41) Property and equipment, net $ 98 $ 83 Total lease right-of-use assets $ 411 $ 432 Liabilities Operating lease liabilities Current Other current liabilities $ 69 $ 71 Noncurrent Long-term operating lease liabilities 274 308 Total operating lease liabilities $ 343 $ 379 Finance lease liabilities (1) Current Short-term debt $ 13 $ 10 Noncurrent Other long-term debt, net 63 50 Total finance lease liabilities $ 76 $ 60 Total lease liabilities $ 419 $ 439 (1) Includes right-of-use assets of $28 million and $30 million and lease liabilities of $34 million and $35 million as of December 31, 2023 and 2022, 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, 2023 reconciled to our lease liabilities on our Consolidated Balance Sheet (amounts in millions): Operating Finance (2) Future minimum lease payments (1) : 2024 $ 80 $ 20 2025 68 17 2026 51 13 2027 43 12 2028 34 15 Thereafter 238 48 Total 514 125 Less: Present value discount (171) (49) Lease liabilities $ 343 $ 76 (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 2024 through 2028 and approximately $45 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, 2023 2022 2021 Operating lease revenue (1) $ 32 $ 29 $ 28 (1) These amounts are included in “ Services revenues The table below presents the maturity of lease payments for operating lease agreements in effect as of December 31, 2023. 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 18 years. The following table presents the undiscounted cash flows expected to be received related to these agreements (in millions): 2024 2025 2026 2027 2028 Thereafter Future minimum lease revenue $ 24 $ 18 $ 15 $ 16 $ 16 $ 154 |
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 57 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 2023 2022 2021 Operating lease cost $ 86 $ 91 $ 96 Short-term lease cost 15 18 19 Other (1) 8 15 14 Total lease cost $ 109 $ 124 $ 129 (1) Includes finance lease costs, variable lease costs and sublease income. The following table presents information related to cash flows arising from lease transactions (in millions): Year Ended December 31, 2023 2022 2021 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases $ 81 $ 92 $ 91 Operating cash flows for finance leases $ 6 $ 6 $ 7 Financing cash flows for finance leases $ 11 $ 12 $ 11 Non-cash change in lease liabilities arising from obtaining new right-of-use assets or modifications: Operating leases $ 32 $ 43 $ 94 Finance leases $ 27 $ 2 $ 1 Information related to the weighted-average remaining lease term and discount rate is presented in the table below: December 31, 2023 2022 Weighted-average remaining lease term (in years): Operating leases 13 12 Finance leases 8 9 Weighted-average discount rate: Operating leases 4.9 % 4.3 % Finance leases 11.3 % 12.3 % 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 2023 2022 Assets Operating lease right-of-use assets Long-term operating lease right-of-use assets, net $ 313 $ 349 Finance lease right-of-use assets (1) Property and equipment $ 144 $ 124 Accumulated depreciation (46) (41) Property and equipment, net $ 98 $ 83 Total lease right-of-use assets $ 411 $ 432 Liabilities Operating lease liabilities Current Other current liabilities $ 69 $ 71 Noncurrent Long-term operating lease liabilities 274 308 Total operating lease liabilities $ 343 $ 379 Finance lease liabilities (1) Current Short-term debt $ 13 $ 10 Noncurrent Other long-term debt, net 63 50 Total finance lease liabilities $ 76 $ 60 Total lease liabilities $ 419 $ 439 (1) Includes right-of-use assets of $28 million and $30 million and lease liabilities of $34 million and $35 million as of December 31, 2023 and 2022, 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, 2023 reconciled to our lease liabilities on our Consolidated Balance Sheet (amounts in millions): Operating Finance (2) Future minimum lease payments (1) : 2024 $ 80 $ 20 2025 68 17 2026 51 13 2027 43 12 2028 34 15 Thereafter 238 48 Total 514 125 Less: Present value discount (171) (49) Lease liabilities $ 343 $ 76 (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 2024 through 2028 and approximately $45 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, 2023 2022 2021 Operating lease revenue (1) $ 32 $ 29 $ 28 (1) These amounts are included in “ Services revenues The table below presents the maturity of lease payments for operating lease agreements in effect as of December 31, 2023. 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 18 years. The following table presents the undiscounted cash flows expected to be received related to these agreements (in millions): 2024 2025 2026 2027 2028 Thereafter Future minimum lease revenue $ 24 $ 18 $ 15 $ 16 $ 16 $ 154 |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2023 | |
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, 2023 and 2022, 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, 2023, 2022, and 2021 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, 2023 2022 2021 Current income tax expense: State income tax $ 2 $ 1 $ 2 Canadian federal and provincial income tax 143 83 48 Total current income tax expense $ 145 $ 84 $ 50 Deferred income tax expense/(benefit): Canadian federal and provincial income tax $ (24) $ 105 $ 23 Total deferred income tax expense/(benefit) $ (24) $ 105 $ 23 Total income tax expense $ 121 $ 189 $ 73 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, 2023 2022 2021 Income before tax $ 1,623 $ 1,417 $ 721 Partnership earnings not subject to Canadian tax (1,136) (686) (370) $ 487 $ 731 $ 351 Canadian federal and provincial corporate tax rate 24% 24% 24% Income tax expense at statutory rate $ 117 $ 175 $ 84 Canadian permanent differences $ 2 $ 13 $ (13) State income tax 2 1 2 Total income tax expense $ 121 $ 189 $ 73 Deferred tax assets and liabilities are aggregated by the applicable tax paying entity and jurisdiction and result from the following (in millions): December 31, 2023 2022 Deferred tax assets: Lease liabilities $ 40 $ 45 Other 45 16 Total deferred tax assets 85 61 Deferred tax liabilities: Property and equipment in excess of tax values (573) (515) Derivative instruments (6) (46) Lease assets (38) (42) Other (3) (3) Total deferred tax liabilities (620) (606) Net deferred tax liabilities $ (535) $ (545) Balance sheet classification of deferred tax assets/(liabilities): Other long-term liabilities and deferred credits $ (535) $ (545) $ (535) $ (545) Generally, tax returns for our Canadian entities are open to audit from 2017 through 2023. Our U.S. and state tax years are generally open to examination from 2020 to 2023. As of December 31, 2023, in reference to tax years 2012 to 2018, 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 $165 million (based on the exchange rate as of December 31, 2023). 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 $87 million (based on the exchange rate as of December 31, 2023) 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, 2023, 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, 2023 | |
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 26%, 20% and 15% of our revenues for the years ended December 31, 2023, 2022 and 2021, respectively. BP p.l.c. and its subsidiaries accounted for 10% of our revenues for the years ended December 31, 2023 and 2021. Marathon Petroleum Corporation and its subsidiaries accounted for 12% of our revenues for the year ended December 31, 2021. No other customers accounted for 10% or more of our revenues during any of the three years ended December 31, 2023. 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, 2023 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Related Party Transactions Ownership of PAGP Class C Shares As of December 31, 2023 and 2022, we owned 539,445,289 and 528,442,538, respectively, Class C shares of PAGP. Each Class C share represents a non-economic limited partner interest in PAGP. 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 (other than AAP) and Series A preferred unitholders in such director elections. 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. 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 conduct 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, in a manner it deems in its sole discretion to be reasonable, determine the expenses that are allocable to us. Total costs reimbursed by us to our general partner for the years ended December 31, 2023, 2022 and 2021 were $546 million, $476 million and $467 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. Amounts paid on behalf of the PAGP Entities during the years ended December 31, 2023, 2022 and 2021 were not material; • 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. Promissory Notes with our General Partner In March 2023, PAGP issued an unsecured promissory note to us with a face value of CAD$500 million (“related party note receivable”). Concurrently, we assigned PAGP our interest in an existing unsecured promissory note for the same face value amount due from a consolidated subsidiary (“related party note payable”). Both notes are due April 2027 and bear interest at a rate of 8.25% per annum, payable semi-annually. Accrued and unpaid interest receivable/payable was $10 million as of December 31, 2023. Interest income/expense on the related party notes totaled $25 million for the year ended December 31, 2023. As of December 31, 2023, our outstanding related party note receivable and related party note payable balances were as follows (in millions): December 31, Related party note receivable (1) $ 379 Related party note payable (1) $ 379 (1) We have elected to present our related party notes with the same counterparty on a net basis on our Consolidated Balance Sheet because there is a legal right to offset and we intend to offset with the counterparty. Transactions with Other Related Parties Our other related parties include (i) entities in which we hold investments and account for under the equity method of accounting (see Note 8 for information regarding such entities) and (ii) principal owners and their affiliated 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, 2023, no entities met the criteria to be recognized 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, 2023, 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, 2023 2022 2021 Revenues from related parties $ 48 $ 45 $ 33 Purchases and related costs from related parties $ 404 $ 365 $ 385 Our receivable and payable amounts with these related parties as reflected on our Consolidated Balance Sheets were as follows (in millions): December 31, 2023 2022 Trade accounts receivable and other receivables, net from related parties (1) $ 63 $ 45 Trade accounts payable to related parties (1) (2) $ 72 $ 79 (1) Includes amounts related to 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, 2023 | |
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. 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, 2023 (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, 17.4 million awards are currently available for future grant. The remaining balance has already vested or is currently outstanding. As of December 31, 2023, 12.2 million LTIP awards were outstanding. Of the awards outstanding, 9.6 million include associated DERs. At December 31, 2023, certain of the outstanding LTIP awards were considered probable of vesting and such awards are expected to vest at various dates between May 2024 and August 2028. As of December 31, 2023, the outstanding awards that are considered probable of vesting have a remaining unrecognized fair value of approximately $73 million. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2023 | |
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, 2023 are summarized below (in millions): 2024 2025 2026 2027 2028 Thereafter Total Leases (1) $ 100 $ 85 $ 64 $ 55 $ 49 $ 286 $ 639 Other commitments (2) 367 336 249 217 117 425 1,711 Total $ 467 $ 421 $ 313 $ 272 $ 166 $ 711 $ 2,350 (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 13 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 $396 million, $336 million and $270 million for 2023, 2022 and 2021, 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 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 or insured. 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, 2023, our estimated undiscounted reserve for environmental liabilities (excluding liabilities related to the Line 901 incident, as discussed further below) totaled $56 million, of which $10 million was classified as short-term and $46 million was classified as long-term. At December 31, 2022, our estimated undiscounted reserve for environmental liabilities (excluding liabilities related to the Line 901 incident) totaled $55 million, of which $10 million was classified as short-term and $45 million was classified as long-term. Such short-term liabilities are reflected in “ Other current liabilities Other long-term liabilities and deferred credits 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, which resolved all regulatory claims related to the incident, 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. On October 13, 2022, Plains sold Line 901 and the Sisquoc to Pentland portion of Line 903 to Pacific Pipeline Company, an indirect wholly owned subsidiary of Exxon Mobil Corporation. As required by the terms of the Consent Decree, such purchaser assumed responsibility for compliance with the Consent Decree as it relates to the future ownership and operation of Line 901 and the Sisquoc to Pentland portion of Line 903. 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 and certain separately represented claimants have appealed the Court’s rulings. We also received several 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. In addition to the other lawsuits disclosed herein, the following lawsuits remain: (i) a lawsuit filed in the United States District Court for the Central District of California that was remanded to the California Superior Court in Santa Barbara County 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; (ii) a lawsuit filed by the California State Land Commission in California Superior Court in Santa Barbara County seeking lost royalties following the shut-down of Line 901, as well as costs related to the decommissioning of such platform, and (iii) lawsuits filed in California Superior Court in Santa Barbara County by 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 remaining lawsuits and believe we have strong defenses. Furthermore, 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. Additionally, a class action lawsuit was filed against us in United States District Court for the Central District of California in which the class 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. The purchaser of Line 901 and the Sisquoc to Pentland portion of Line 903 has assumed liability for these claims with respect to its interest in such acquired pipelines and Plains has been dismissed from this portion of the lawsuit. In the same proceeding, a small subset of plaintiffs are also claiming damages to compensate them for the alleged diminished value of their properties due to the stigma of the oil spill. We are vigorously defending against these stigma damages claims. In a separate class action lawsuit that was pending in United States District Court for the Central District of California, the plaintiffs claimed 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. In 2022, in order to fully and finally resolve all claims and litigation for both classes, we reached an agreement to settle this case in exchange for a payment of $230 million (the “Class Action Settlement”). The Class Action Settlement was formally approved by the trial court on September 20, 2022, and we made the $230 million settlement payment on October 27, 2022 and the lawsuit was subsequently dismissed. Plains formally submitted claims for reimbursement of the Class Action Settlement to our insurance carriers on November 7, 2022. To date, we have received payment of approximately $3.6 million from one insurer, which represents the final payment obligation of such insurer and brings the total amount collected from all insurers under such program to $275 million of the $500 million policy limits as of December 31, 2023. Insurers responsible for $185 million of the remaining $225 million of coverage formally communicated a denial of coverage for the Class Action Settlement generally alleging that some or all damages encompassed by the Class Action Settlement are not covered by their policies and that all or some portion of the $275 million for which Plains has already received insurance reimbursement does not properly exhaust the underlying policies that paid those sums. The insurer responsible for the final $40 million of coverage under such insurance program has not formally responded to our reimbursement demands. We have initiated final and binding arbitration proceedings against the insurers responsible for $175 million of coverage and intend to vigorously pursue recovery from our insurers of all amounts for which we have claimed reimbursement. We believe that our claim for reimbursement from our insurers of the Class Action Settlement payment is strong and that our ultimate recovery of such amounts is probable. Our belief is based on: (i) our analysis of the terms of the underlying insurance policies as applied to the facts and circumstances that comprise our claim for reimbursement, (ii) our experience with the cost submissions and timely collection of claims for the $275 million collected to date for this incident under the same insurance program as the denied claims, including from some of the same insurers who are now denying claims, (iii) our extensive legal review and assessment of the insurer’s claimed basis for denial of coverage, which review and assessment includes the advice of external legal counsel experienced in these type of matters and solidly supports our belief that our insurers are required to provide coverage based on the terms of the policies and the nature of our claims, and (iv) the financial strength of the insurance carriers as determined by an independent credit ratings agency. Various factors could impact the timing and amount of recovery of our insurance receivable, including future developments that adversely impact our assessment of the strength of our coverage claims, the outcome of any dispute resolution proceedings with respect to our coverage claims and the extent to which insurers may become insolvent in the future. An unfavorable resolution could have a material impact on our results of operations. In connection with the foregoing, including the Class Action Settlement, we have made adjustments to our total estimated Line 901 costs and the portion of such costs that we believe are probable of recovery from insurance carriers, net of deductibles. Effective as of December 31, 2023, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $750 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, certain third-party claims settlements (including the Class Action Settlement), and estimated costs associated with our remaining Line 901 lawsuits and claims as described above, as well as estimates for certain legal fees and statutory interest where applicable. 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. During the years ended December 31, 2023, 2022 and 2021, we recognized costs, net of amounts probable of recovery from insurance carriers, of $10 million, $95 million and $15 million, respectively. As of December 31, 2023 and 2022, we had a remaining undiscounted gross liability of approximately $94 million and $105 million, respectively, related to the Line 901 incident, which aggregate amounts are reflected in “Current liabilities” on our Consolidated Balance Sheet. As discussed above, we maintain insurance coverage, which is subject to certain exclusions and deductibles, in the event of such liabilities. As of December 31, 2023, our incurred costs for the Line 901 incident have exceeded our insurance coverage limit of $500 million related to our 2015 insurance program applicable to the Line 901 incident by $250 million. Through December 31, 2023, we had collected, subject to customary reservations, approximately $280 million out of the $505 million of release costs that we believe are probable of recovery from insurance carriers (including the 2015 insurance program and our directors and officers (D&O) insurance policies), net of deductibles. Therefore, as of December 31, 2023, we have recognized a long-term receivable of approximately $225 million for the portion of the release costs that we believe is probable of recovery from insurance, net of deductibles and amounts already collected. We anticipate that the process to enforce our coverage claims with respect to the Class Action Settlement will take time and, accordingly, have recognized such amount as a long-term asset in “Other assets” 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 legal, professional and regulatory costs during future periods. Taking into account the costs that we have included in our total estimate of costs for the Line 901 incident and considering what we regard as very strong defenses to the claims made in our remaining Line 901 lawsuits, we do not believe the ultimate resolution of such remaining lawsuits will have a material adverse effect on our consolidated financial condition, results of operations or cash flows. Other Litigation Matters. On July 19, 2022 Hartree Natural Gas Storage, LLC (“Hartree”) filed a lawsuit under seal in the Superior Court for the State of Delaware asserting claims against PAA Natural Gas Storage, L.P. and PAA arising out of a Membership Interest Purchase Agreement relating to the 2021 sale of the Pine Prairie Energy Center natural gas storage facility to Hartree. We believe the claims are without merit and that the outcome of the lawsuit will not have a material adverse effect on our financial condition, results of operations or cash flows. We intend to vigorously defend against the claims asserted in this lawsuit. |
Segment Information
Segment Information | 12 Months Ended |
Dec. 31, 2023 | |
Segment Reporting [Abstract] | |
Segment Information | Segment Information Our operating segments, Crude Oil and NGL, 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. Our crude oil and NGL marketing activities are 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 (our Chief Executive Officer) 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 (including write-downs related to cancelled projects and impairments) 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 either related to investing activities (such as the purchase of linefill) or purchases of long-term inventory, 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 (“Segment amounts attributable to noncontrolling interests”). 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, 2023 Revenues (1) : Product sales $ 45,587 $ 1,765 $ (378) $ 46,974 Services 1,587 170 (19) 1,738 Total revenues $ 47,174 $ 1,935 $ (397) $ 48,712 Equity earnings in unconsolidated entities $ 369 $ — $ 369 Segment Adjusted EBITDA $ 2,163 $ 522 $ 2,685 Investment and acquisition capital expenditures (2) (3) $ 765 $ 65 $ 830 Maintenance capital expenditures (3) $ 145 $ 86 $ 231 As of December 31, 2023 Investments in unconsolidated entities $ 2,820 $ — $ 2,820 Crude Oil NGL Intersegment Revenues Total Year Ended December 31, 2022 Revenues (1) : Product sales $ 53,840 $ 2,575 $ (467) $ 55,948 Services 1,240 186 (32) 1,394 Total revenues $ 55,080 $ 2,761 $ (499) $ 57,342 Equity earnings in unconsolidated entities $ 403 $ — $ 403 Segment Adjusted EBITDA $ 1,986 $ 518 $ 2,504 Investment and acquisition capital expenditures (2) (3) $ 461 $ 157 $ 618 Maintenance capital expenditures (3) $ 112 $ 99 $ 211 As of December 31, 2022 Investments in unconsolidated entities $ 3,084 $ — $ 3,084 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 (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 attributable to PAA (in millions): Year Ended December 31, 2023 2022 2021 Segment Adjusted EBITDA $ 2,685 $ 2,504 $ 2,194 Adjustments (1) : Depreciation and amortization of unconsolidated entities (2) (87) (85) (123) Derivative activities and inventory valuation adjustments (3) (159) 280 271 Long-term inventory costing adjustments (4) (35) 4 94 Deficiencies under minimum volume commitments, net (5) (12) (7) 7 Equity-indexed compensation expense (6) (36) (32) (19) Foreign currency revaluation (7) (24) (4) 4 Line 901 incident (8) (10) (95) (15) Transaction-related expenses (9) (1) — (16) Segment amounts attributable to noncontrolling interests (10) 454 364 94 Depreciation and amortization (1,048) (965) (774) Gains/(losses) on asset sales and asset impairments, net 152 (269) (592) Gains/(losses) on investments in unconsolidated entities, net 28 346 2 Interest expense, net (386) (405) (425) Other income/(expense), net 102 (219) 19 Income before tax 1,623 1,417 721 Income tax expense (121) (189) (73) Net income 1,502 1,228 648 Net income attributable to noncontrolling interests (272) (191) (55) Net income attributable to PAA $ 1,230 $ 1,037 $ 593 (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 and impairments) 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 (i) investing activities, such as the purchase of linefill, and (ii) purchases of long-term inventory. 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 investees, 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 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 or equity earnings, 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 be settled in cash is not excluded in determining Segment Adjusted EBITDA. See Note 17 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 18 for additional information regarding the Line 901 incident. (9) Includes expenses associated with the Rattler Permian Transaction in 2023 and the Permian JV transaction in 2021. 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, 2023 and 2021 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), Cactus II (beginning November 2022) and Red River. 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) 2023 2022 2021 United States $ 42,308 $ 46,903 $ 34,458 Canada 6,404 10,439 7,620 $ 48,712 $ 57,342 $ 42,078 (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) 2023 2022 United States $ 18,591 $ 18,655 Canada 3,820 3,802 $ 22,411 $ 22,457 (1) Excludes long-term derivative assets and long-term deferred tax assets. |
Pay vs Performance Disclosure
Pay vs Performance Disclosure - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Pay vs Performance Disclosure | |||
Net Income (Loss) | $ 1,230 | $ 1,037 | $ 593 |
Insider Trading Arrangements
Insider Trading Arrangements | 3 Months Ended |
Dec. 31, 2023 | |
Trading Arrangements, by Individual | |
Rule 10b5-1 Arrangement Adopted | false |
Non-Rule 10b5-1 Arrangement Adopted | false |
Rule 10b5-1 Arrangement Terminated | false |
Non-Rule 10b5-1 Arrangement Terminated | false |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2023 | |
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, 2023 and 2022, 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, 2023, 2022 and 2021. All significant intercompany balances and transactions have been eliminated in consolidation, and certain reclassifications have been made to information from previous years to conform to the current presentation. The accompanying consolidated financial statements include the accounts of PAA and all of its wholly owned subsidiaries and those entities that it controls. Investments in entities over which we have significant influence but not control are accounted for by the equity method. We apply proportionate consolidation for pipelines and other assets in which we own undivided joint interests. |
Use of Estimates | Use of Estimates The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, as well as the disclosure of contingent assets and liabilities at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenues and expenses during the reporting period. We make significant estimates with respect to (i) estimated fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets, (ii) 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 | Cash and Cash Equivalents Cash and cash equivalents consist of all unrestricted demand deposits and funds invested in highly liquid instruments with original maturities of three months or less and typically exceed federally insured limits. We periodically assess the financial condition of the institutions where these funds are held and believe that our credit risk is minimal. |
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 11 for additional discussion regarding our noncontrolling interests. |
Asset Retirement Obligations | Asset Retirement Obligations FASB guidance establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including estimates related to (i) the time of the liability recognition, (ii) initial measurement of the liability, (iii) allocation of asset retirement cost to expense, (iv) subsequent measurement of the liability and (v) financial statement disclosures. FASB guidance also requires that the cost for asset retirement should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. Some of our assets, primarily 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 Measurements |
Recent Accounting Pronouncements | Recent Accounting Pronouncements In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures , which requires, among other things, disaggregated information about effective tax rate reconciliation and income taxes paid (net of refunds received) on an annual basis. The guidance is effective prospectively for annual periods beginning after December 15, 2024 with retrospective or early adoption permitted. We intend to provide the required disclosures prospectively for annual periods beginning after December 15, 2024. In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which requires disaggregated disclosure of significant segment expenses and other amounts included within the reported measure of segment profit or loss for each reportable segment on an annual and interim basis. The guidance is effective retrospectively for annual periods beginning after December 15, 2023, and interim periods in fiscal years beginning after December 15, 2024 with early adoption permitted. We intend to provide the required disclosures beginning with our annual report for the year ended December 31, 2024. In August 2023, the FASB issued ASU 2023-05, Business Combinations—Joint Venture Formations (Subtopic 805-60): Recognition and Initial Measurement , which requires a newly-formed joint venture to apply a new basis of accounting to its contributed net assets, resulting in the joint venture initially measuring its contributed net assets at fair value on the formation date. This guidance is effective prospectively for all joint ventures with a formation date on or after January 1, 2025, with early adoption permitted. We intend to adopt this guidance for joint venture formations on January 1, 2025. 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 adopted this guidance as of January 1, 2023, 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 was effective prospectively upon issuance through December 31, 2022. In December 2022, the FASB issued ASU 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848, |
Revenue Recognition | Revenue Recognition 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. Transportation Revenues. 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. 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. Contract Balances Remaining Performance Obligations 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 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. |
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 Per Common Unit | After consideration of distributions to preferred unitholders, basic and diluted net income per common unit is determined pursuant to the two-class method as prescribed in FASB guidance. This method is an earnings allocation formula that is used to determine allocations to our limited partners and participating securities according to distributions pertaining to the current period’s net income and participation rights in undistributed earnings or distributions in excess of earnings. Under the two-class method, net income is reduced by distributions pertaining to the period, and all remaining earnings or distributions in excess of earnings are then allocated to our common unitholders and participating securities based on their respective rights to share in distributions, regardless of whether those earnings would actually be distributed during a particular period from an economic or practical perspective. Participating securities include equity-indexed compensation plan awards that have vested DERs, which entitle the grantee to a cash payment equal to the cash distribution paid on our outstanding common units. We calculate basic and diluted net income per common unit by dividing net income attributable to PAA (after deducting amounts allocated to the preferred unitholders and participating securities) by the basic and diluted weighted average number of common units outstanding during the period. The diluted weighted average number of common units is computed based on the weighted average number of common units plus the effect of potentially dilutive securities outstanding during the period, which include (i) our Series A preferred units and (ii) our equity-indexed compensation plan awards. See Note 11 for additional information regarding our Series A preferred units. See Note 17 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 per common unit for the years ended December 31, 2023, 2022 and 2021 as the effect was antidilutive for all 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 are deemed to be dilutive during the year are 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. We calculate net income allocated to common unitholders based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings (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 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. No adjustments were recorded during the years ended December 31, 2023, 2022 or 2021. Linefill in assets we own is recorded at historical cost and consists of crude oil and NGL. We classify as linefill (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 and (ii) barrels that represent the minimum working requirements in tanks and caverns that we own. Linefill 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 2023, 2022 and 2021, we did not recognize any material impairments of linefill. 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, as are certain costs directly related to the construction of such assets, including related internal labor costs, engineering costs and interest costs. 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. |
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. |
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. During the years ended December 31, 2023, 2022 and 2021, we made cash contributions of $29 million, $13 million and $82 million, respectively, to certain of our equity method investees. We capitalize interest costs associated with contributions to unconsolidated entities for projects under development and construction. Our contributions to these entities (including capitalized interest costs) increase the carrying value of our investments and are reflected in our Consolidated Statements of Cash Flows as cash used in investing activities. Basis Differences Our investments in unconsolidated entities exceeded our share of the underlying equity in the net assets of such entities by $229 million and $204 million at December 31, 2023 and 2022, 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, 2023 and 2022 was attributable to goodwill related to our ownership interest in BridgeTex and Capline 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. 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. |
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 commodity price risk and interest 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 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 or interest 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 57 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. |
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 Affiliates |
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 | Our operating segments, Crude Oil and NGL, 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. Our crude oil and NGL marketing activities are 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 (our Chief Executive Officer) 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 (including write-downs related to cancelled projects and impairments) 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 either related to investing activities (such as the purchase of linefill) or purchases of long-term inventory, 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 (“Segment amounts attributable to noncontrolling interests”). 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, 2023 | |
Accounting Policies [Abstract] | |
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, 2023, 2022 and 2021 (in millions): December 31, 2023 2022 2021 Beginning balance $ 122 $ 143 $ 135 Liabilities incurred 2 2 2 Liabilities settled (1) (1) (26) (1) Accretion expense 4 4 4 Revisions in estimated cash flows (1) (1) 3 Ending balance $ 126 $ 122 $ 143 (1) The 2022 amount primarily relates to the transfer of liabilities to the third party purchaser associated with the sale of Line 901 and the Sisquoc to Pentland portion of Line 903 pipeline. See Note 7 and Note 18 for additional information. |
Revenues and Accounts Receiva_2
Revenues and Accounts Receivable (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Revenue from Contract with Customer [Abstract] | |
Schedule of 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, 2023 2022 2021 Crude Oil segment revenues from contracts with customers Sales $ 45,621 $ 53,822 $ 39,635 Transportation 1,144 745 484 Terminalling, Storage and Other 381 362 431 Total Crude Oil segment revenues from contracts with customers $ 47,146 $ 54,929 $ 40,550 Year Ended December 31, 2023 2022 2021 NGL segment revenues from contracts with customers Sales $ 1,729 $ 2,414 $ 2,292 Transportation 30 30 25 Terminalling, Storage and Other 94 100 82 Total NGL segment revenues from contracts with customers $ 1,853 $ 2,544 $ 2,399 Year Ended December 31, 2023 Crude Oil NGL Total Revenues from contracts with customers $ 47,146 $ 1,853 $ 48,999 Other revenues 28 82 110 Total revenues of reportable segments $ 47,174 $ 1,935 $ 49,109 Intersegment revenues elimination (397) Total revenues $ 48,712 Year Ended December 31, 2022 Crude Oil NGL Total Revenues from contracts with customers $ 54,929 $ 2,544 $ 57,473 Other revenues 151 217 368 Total revenues of reportable segments $ 55,080 $ 2,761 $ 57,841 Intersegment revenues elimination (499) Total revenues $ 57,342 Year Ended December 31, 2021 Crude Oil NGL Total Revenues from contracts with customers $ 40,550 $ 2,399 $ 42,949 Other revenues (80) (431) (511) Total revenues of reportable segments $ 40,470 $ 1,968 $ 42,438 Intersegment revenues elimination (360) Total revenues $ 42,078 |
Schedule of 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 2023 2022 Billed and collected Other current liabilities $ 77 $ 104 |
Schedule of Contracts with Customers, Change in Asset and Liability Balance | The following table presents the changes in the liability balance associated with contracts with customers (in millions): Contract Liabilities Balance at December 31, 2021 $ 141 Amounts recognized as revenue (26) Additions (1) 145 Other (31) Balance at December 31, 2022 $ 229 Amounts recognized as revenue (42) Additions 38 Other 3 Balance at December 31, 2023 $ 228 (1) Includes approximately $122 million associated with a gas processing agreement that was entered into in conjunction with the purchase of an additional ownership interest in certain straddle plants. Such amount is expected to be recognized as revenue over a 50-year term. See Note 7 for additional information. 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, 2023 2022 Trade accounts receivable arising from revenues from contracts with customers $ 3,999 $ 4,141 Other trade accounts receivables and other receivables (1) 7,535 7,216 Impact due to contractual rights of offset with counterparties (7,774) (7,450) Trade accounts receivable and other receivables, net $ 3,760 $ 3,907 (1) The balance is comprised primarily of accounts receivable associated with buy/sell arrangements that are not within the scope of ASC 606. |
Schedule of 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, 2023 (in millions): 2024 2025 2026 2027 2028 2029 and Thereafter Pipeline revenues supported by minimum volume commitments and capacity agreements (1) $ 375 $ 329 $ 156 $ 109 $ 80 $ 194 Terminalling, storage and other agreement revenues 234 149 114 101 83 688 Total $ 609 $ 478 $ 270 $ 210 $ 163 $ 882 (1) Calculated as volumes committed under contracts multiplied by the current applicable tariff rate. |
Net Income Per Common Unit (Tab
Net Income Per Common Unit (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Earnings Per Share [Abstract] | |
Computation of Basic and Diluted Net Income per Common Unit | The following table sets forth the computation of basic and diluted net income per common unit (in millions, except per unit data): Year Ended December 31, 2023 2022 2021 Basic and Diluted Net Income per Common Unit Net income attributable to PAA $ 1,230 $ 1,037 $ 593 Distributions to Series A preferred unitholders (173) (149) (149) Distributions to Series B preferred unitholders (76) (52) (49) Amounts allocated to participating securities (10) (5) (2) Other 5 — — Net income allocated to common unitholders (1) $ 976 $ 831 $ 393 Basic and diluted weighted average common units outstanding 699 701 716 Basic and diluted net income per common unit $ 1.40 $ 1.19 $ 0.55 (1) We calculate net income allocated to common unitholders based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings (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 Long-_2
Inventory, Linefill and Long-term Inventory (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Inventory Disclosure [Abstract] | |
Schedule of Inventory | Inventory, linefill and long-term inventory consisted of the following (barrels in thousands and carrying value in millions): December 31, 2023 December 31, 2022 Volumes Unit of Carrying Price/ Unit (1) Volumes Unit of Carrying Price/ Unit (1) Inventory Crude oil 5,877 barrels $ 383 $ 65.17 6,713 barrels $ 452 $ 67.33 NGL 5,957 barrels 154 $ 25.85 7,285 barrels 270 $ 37.06 Other N/A 11 N/A N/A 7 N/A Inventory subtotal 548 729 Linefill Crude oil 15,409 barrels 909 $ 58.99 15,480 barrels 906 $ 58.53 NGL 2,168 barrels 67 $ 30.90 1,876 barrels 55 $ 29.32 Linefill subtotal 976 961 Long-term inventory Crude oil 3,256 barrels 232 $ 71.25 3,102 barrels 246 $ 79.30 NGL 1,326 barrels 33 $ 24.89 1,066 barrels 38 $ 35.65 Long-term inventory subtotal 265 284 Total $ 1,789 $ 1,974 (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. |
Schedule of Linefill and Long-term Inventory | Inventory, linefill and long-term inventory consisted of the following (barrels in thousands and carrying value in millions): December 31, 2023 December 31, 2022 Volumes Unit of Carrying Price/ Unit (1) Volumes Unit of Carrying Price/ Unit (1) Inventory Crude oil 5,877 barrels $ 383 $ 65.17 6,713 barrels $ 452 $ 67.33 NGL 5,957 barrels 154 $ 25.85 7,285 barrels 270 $ 37.06 Other N/A 11 N/A N/A 7 N/A Inventory subtotal 548 729 Linefill Crude oil 15,409 barrels 909 $ 58.99 15,480 barrels 906 $ 58.53 NGL 2,168 barrels 67 $ 30.90 1,876 barrels 55 $ 29.32 Linefill subtotal 976 961 Long-term inventory Crude oil 3,256 barrels 232 $ 71.25 3,102 barrels 246 $ 79.30 NGL 1,326 barrels 33 $ 24.89 1,066 barrels 38 $ 35.65 Long-term inventory subtotal 265 284 Total $ 1,789 $ 1,974 (1) Price per unit of measure is comprised of a weighted average associated with various grades, qualities and locations. Accordingly, these prices may not coincide with any published benchmarks for such products. |
Property and Equipment (Tables)
Property and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Property, Plant and Equipment [Abstract] | |
Schedule of 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, 2023 2022 Crude oil pipeline systems 10 - 50 $ 14,265 $ 13,303 Crude oil storage and terminal facilities 10 - 50 2,664 2,631 NGL storage, terminal, fractionation and processing facilities 10 - 50 2,554 2,445 NGL pipeline systems 10 - 50 506 458 Office property and equipment and rolling stock 2 - 50 556 656 Construction in progress N/A 257 201 Land and other N/A 341 326 Property and equipment, gross (1) 21,143 20,020 Accumulated depreciation (5,361) (4,770) Property and equipment, net $ 15,782 $ 15,250 (1) We include rights-of-way, which are intangible assets, within property and equipment. |
Acquisitions, Divestitures an_2
Acquisitions, Divestitures and Other Transactions (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
OMOG JV LLC and Southern Delaware Gathering Assets | |
Business Acquisition [Line Items] | |
Schedule of Assets Acquired and Liabilities Assumed | The following table reflects our determination of the fair value of the assets acquired and liabilities assumed in connection with the transaction (in millions): Identifiable Assets Acquired and Liabilities Assumed: Estimated Useful Lives Recognized Amount Property and equipment 3-30 $ 484 Intangible assets 10 34 Working capital and other assets and liabilities N/A 14 $ 532 |
OMOG JV LLC and Southern Delaware Gathering Assets | Customer relationships | |
Business Acquisition [Line Items] | |
Schedule of Amortization Expense | Amortization expense was approximately $4 million during the year ended December 31, 2023, and the future amortization expense through 2028 is estimated as follows (in millions): 2024 $ 8 2025 $ 10 2026 $ 4 2027 $ 3 2028 $ 2 |
Cactus II Pipeline LLC | |
Business Acquisition [Line Items] | |
Schedule of Assets Acquired and Liabilities Assumed | The following table reflects our 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 3-50 $ 1,174 Intangible assets 20 428 Working capital and other assets and liabilities N/A (46) $ 1,556 |
Cactus II Pipeline LLC | Customer relationships | |
Business Acquisition [Line Items] | |
Schedule of Amortization Expense | Amortization expense was approximately $61 million and $13 million during the years ended December 31, 2023 and 2022, respectively, and the future amortization expense through 2027 is estimated as follows (in millions): 2024 $ 51 2025 $ 47 2026 $ 32 2027 $ 32 |
Plains Oryx Permian Basin LLC | Modified Sharing Arrangement | |
Business Acquisition [Line Items] | |
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% |
Plains Oryx Permian Basin LLC | Oryx Midstream Holdings LLC | Joint Venture Transaction | |
Business Acquisition [Line Items] | |
Schedule of Assets Acquired and Liabilities Assumed | The following table reflects our 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 Working capital and other assets and liabilities N/A (6) $ 3,230 |
Schedule of Partners' Capital | The following table presents the amounts recognized in partners’ capital associated with this transaction (in millions): Recognized Amount Noncontrolling interests $ 2,635 Partners’ capital, excluding noncontrolling interests 595 $ 3,230 |
Schedule of 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, 2021; 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 Total revenues $ 42,359 Net income attributable to PAA $ 524 Net income allocated to common unitholders $ 324 Basic and diluted net income per common unit $ 0.45 |
Plains Oryx Permian Basin LLC | Customer relationships | Joint Venture Transaction | |
Business Acquisition [Line Items] | |
Schedule of Amortization Expense | Amortization expense was approximately $138 million, $142 million and $28 million during the years ended December 31, 2023, 2022 and 2021, respectively, and the future amortization expense through 2026 is estimated as follows (in millions): 2024 $ 127 2025 $ 117 2026 $ 106 |
Investments in Unconsolidated_2
Investments in Unconsolidated Entities (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Schedule of 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, 2023 Investment Balance Entity (1) Type of Operation 2023 2022 BridgeTex Pipeline Company, LLC (“BridgeTex”) Crude Oil Pipeline 20% $ 363 $ 403 Capline Pipeline Company LLC (“Capline”) Crude Oil Pipeline 54% 535 539 Diamond Pipeline LLC Crude Oil Pipeline 50% 450 460 Eagle Ford Pipeline LLC Crude Oil Pipeline 50% 370 371 Eagle Ford Terminals Corpus Christi LLC Crude Oil Terminal and Dock 50% 116 118 OMOG JV LLC (“OMOG”) (2) Crude Oil Pipeline —% — 211 Saddlehorn Pipeline Company, LLC Crude Oil Pipeline 30% 192 197 White Cliffs Pipeline, LLC Crude Oil Pipeline 36% 138 150 Wink to Webster Pipeline LLC (“W2W Pipeline”) (3) Crude Oil Pipeline 16% 380 357 Other investments 276 278 Total Investments in Unconsolidated Entities $ 2,820 $ 3,084 (1) The financial results from these entities are reported in our Crude Oil segment. (2) In the third quarter of 2023, we acquired the remaining 43% interest in OMOG. We now reflect OMOG and its subsidiaries as consolidated subsidiaries in our Consolidated Financial Statements. See Note 7 for additional information. (3) 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. 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, 2023 2022 Current assets $ 528 $ 471 Noncurrent assets $ 7,194 $ 7,579 Current liabilities $ 476 $ 252 Noncurrent liabilities $ 5 $ 8 Year Ended December 31, 2023 2022 2021 Revenues $ 1,667 $ 1,726 $ 1,320 Operating income $ 921 $ 1,004 $ 505 Net income $ 947 $ 1,011 $ 506 |
Intangible Asset, Net (Tables)
Intangible Asset, Net (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Schedule of Components of Intangible Assets, Net of Accumulated Amortization | Intangible assets, net of accumulated amortization, consisted of the following (in millions): December 31, 2023 December 31, 2022 Estimated Useful Cost Accumulated Net Cost Accumulated Net Customer contracts and relationships 1 – 29 $ 2,789 $ (932) $ 1,857 $ 2,817 $ (695) $ 2,122 Other agreements 15 – 70 30 (12) 18 35 (12) 23 Intangible assets (1) $ 2,819 $ (944) $ 1,875 $ 2,852 $ (707) $ 2,145 (1) We include rights-of-way, which are intangible assets, within property and equipment. See Note 6 for a discussion of property and equipment. |
Schedule of 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): 2024 $ 272 2025 $ 249 2026 $ 210 2027 $ 187 2028 $ 165 |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
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 5.8% (1) $ 433 $ — Senior notes: 2.85% senior notes due January 2023 — 400 3.85% senior notes due October 2023 — 700 Other 13 59 Total short-term debt 446 1,159 LONG-TERM DEBT Senior notes: 3.60% senior notes due November 2024 (2) 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 499 499 4.30% senior notes due January 2043 348 348 4.70% senior notes due June 2044 687 687 4.90% senior notes due February 2045 649 649 Unamortized discounts and debt issuance costs (41) (46) Senior notes, net of unamortized discounts and debt issuance costs 7,242 7,237 Other long-term debt: Other 63 50 Total long-term debt 7,305 7,287 Total debt (3) $ 7,751 $ 8,446 (1) We classified these commercial paper notes as short-term as of December 31, 2023, as these notes were primarily designated as working capital borrowings, were required to be repaid within one year and were primarily for hedged NGL and crude oil inventory and NYMEX and ICE margin deposits. (2) As of December 31, 2023, we classified our 3.60%, $750 million senior notes due November 2024 as long-term based on our ability and intent to refinance these notes on a long-term basis. (3) Our fixed-rate senior notes had a face value of approximately $7.3 billion and $8.4 billion at December 31, 2023 and 2022, respectively. We estimated the aggregate fair value of these notes to be approximately $6.9 billion and $7.6 billion at December 31, 2023 and 2022, respectively. Our fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near the end of the reporting period. We estimate that the carrying value of outstanding borrowings under our commercial paper program approximates fair value as interest rates reflect current market rates. The fair value estimates for our senior notes and commercial paper program are based upon observable market data and are classified in Level 2 of the fair value hierarchy. |
Schedule of Senior Unsecured Notes | During the three years ended December 31, 2023, we repaid the following senior unsecured notes in full (in millions): Year Description Repayment Date 2023 $700 million 3.85% Senior Notes due October 2023 October 2023 (1) 2023 $400 million 2.85% Senior Notes due January 2023 January 2023 (1) 2022 $750 million 3.65% Senior Notes due June 2022 March 2022 (1) (1) We repaid these senior notes with cash on hand and borrowings under our commercial paper program. |
Schedule of 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) 2024 $ 750 2025 $ 1,000 2026 $ 750 2027 $ — 2028 $ — Thereafter $ 4,783 |
Partners' Capital and Distrib_2
Partners' Capital and Distributions (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Partners Capital and Distribution [Line Items] | |
Schedule of Activity for Preferred Units 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, 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 Repurchase and cancellation of common units under the Common Equity Repurchase Program — — (7,251,361) Issuances of common units under equity-indexed compensation plans — — 614,319 Outstanding at December 31, 2022 71,090,468 800,000 698,354,498 Issuances of common units under equity-indexed compensation plans — — 2,654,251 Outstanding at December 31, 2023 71,090,468 800,000 701,008,749 |
Schedule of Distributions to Noncontrolling Interests | The following table details distributions paid to noncontrolling interests during the years presented (in millions): 2023 2022 2021 Permian JV (1) $ 249 $ 273 $ — Cactus II 63 4 — Red River 21 21 14 $ 333 $ 298 $ 14 (1) The initial distribution from the Permian JV was paid during the first quarter of 2022, with approximately $54 million paid to noncontrolling interests. |
Series A Preferred Units | |
Partners Capital and Distribution [Line Items] | |
Schedule of Distributions | Series A Preferred Unit Distributions. The following table details distributions paid to our Series A preferred unitholders during the years presented (in millions, except unit data): Series A Preferred Unitholders Year Cash Distribution Distribution per Unit 2023 $ 166 $ 2.34 2022 $ 149 $ 2.10 2021 $ 149 $ 2.10 |
Series B Preferred Units | |
Partners Capital and Distribution [Line Items] | |
Schedule of Distributions | Series B Preferred Unit Distributions. The following table details distributions paid to our Series B preferred unitholders during the years presented (in millions, except unit data): Series B Preferred Unitholders Year Cash Distribution Distribution per Unit 2023 $ 75 $ 93.43 2022 $ 49 $ 61.25 2021 $ 49 $ 61.25 |
Common Units | |
Partners Capital and Distribution [Line Items] | |
Schedule of 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 2023 $ 492 $ 256 $ 748 $ 1.0700 2022 $ 383 $ 201 $ 584 $ 0.8325 2021 $ 341 $ 176 $ 517 $ 0.7200 |
Derivatives and Risk Manageme_2
Derivatives and Risk Management Activities (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Derivatives and Risk Management Activities | |
Schedule of 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, 2023 2022 2021 Product sales revenues $ 13 $ 179 $ (710) Field operating costs (45) 59 71 Net gain/(loss) from commodity derivative activity $ (32) $ 238 $ (639) |
Schedule of Net Broker Receivable (Payable) | The following table provides the components of our net broker receivable/(payable) (in millions): December 31, 2023 2022 Initial margin $ 77 $ 93 Variation margin returned (65) (236) Letters of credit (25) (25) Net broker payable $ (13) $ (168) |
Schedule 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, 2023 December 31, 2022 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 $ 153 $ (79) $ (13) $ 61 $ 300 $ (71) $ (168) $ 61 Other long-term assets, net 3 — — 3 9 (5) — 4 Derivative Liabilities Other current liabilities 1 (64) — (63) 2 (13) — (11) Other long-term liabilities and deferred credits 1 (15) — (14) — — — — Total $ 158 $ (158) $ (13) $ (13) $ 311 $ (89) $ (168) $ 54 |
Schedule of 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, 2023 2022 2021 Interest rate derivatives, net $ 15 $ 94 $ 19 |
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, 2023 Fair Value as of December 31, 2022 Recurring Fair Value Measures (1) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Commodity derivatives $ 9 $ (9) $ — $ — $ (7) $ 229 $ — $ 222 Interest rate derivatives — 55 — 55 — 120 — 120 Preferred Distribution Rate Reset Option — — — — — — (189) (189) Total net derivative asset/(liability) $ 9 $ 46 $ — $ 55 $ (7) $ 349 $ (189) $ 153 (1) Derivative assets and liabilities are presented above on a net basis but do not include related cash margin deposits. |
Schedule of 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, 2023 2022 Beginning Balance $ (189) $ (2) Net gains/(losses) for the period included in earnings 58 (189) Settlements 131 2 Ending Balance $ — $ (189) Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period $ — $ (189) |
Commodity Derivatives | |
Derivatives and Risk Management Activities | |
Schedule 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, 2023. Notional Volume Remaining Tenor Natural gas purchases 78.2 Bcf December 2025 Propane sales (14.1) MMbls December 2025 Butane sales (2.5) MMbls December 2024 Condensate sales (3.1) MMbls December 2024 Fuel gas requirements (1) 7.1 Bcf December 2024 Power supply requirements (1) 2.4 TWh December 2030 (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, 2023 (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 6/15/2026 3.09 % Cash flow hedge Anticipated interest payments 4 forward starting swaps (30-year) $ 100 6/14/2024 0.74 % Cash flow hedge |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
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 2023 2022 2021 Operating lease cost $ 86 $ 91 $ 96 Short-term lease cost 15 18 19 Other (1) 8 15 14 Total lease cost $ 109 $ 124 $ 129 (1) Includes finance lease costs, variable lease costs and sublease income. The following table presents information related to cash flows arising from lease transactions (in millions): Year Ended December 31, 2023 2022 2021 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases $ 81 $ 92 $ 91 Operating cash flows for finance leases $ 6 $ 6 $ 7 Financing cash flows for finance leases $ 11 $ 12 $ 11 Non-cash change in lease liabilities arising from obtaining new right-of-use assets or modifications: Operating leases $ 32 $ 43 $ 94 Finance leases $ 27 $ 2 $ 1 Information related to the weighted-average remaining lease term and discount rate is presented in the table below: December 31, 2023 2022 Weighted-average remaining lease term (in years): Operating leases 13 12 Finance leases 8 9 Weighted-average discount rate: Operating leases 4.9 % 4.3 % Finance leases 11.3 % 12.3 % |
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 2023 2022 Assets Operating lease right-of-use assets Long-term operating lease right-of-use assets, net $ 313 $ 349 Finance lease right-of-use assets (1) Property and equipment $ 144 $ 124 Accumulated depreciation (46) (41) Property and equipment, net $ 98 $ 83 Total lease right-of-use assets $ 411 $ 432 Liabilities Operating lease liabilities Current Other current liabilities $ 69 $ 71 Noncurrent Long-term operating lease liabilities 274 308 Total operating lease liabilities $ 343 $ 379 Finance lease liabilities (1) Current Short-term debt $ 13 $ 10 Noncurrent Other long-term debt, net 63 50 Total finance lease liabilities $ 76 $ 60 Total lease liabilities $ 419 $ 439 (1) Includes right-of-use assets of $28 million and $30 million and lease liabilities of $34 million and $35 million as of December 31, 2023 and 2022, 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, 2023 reconciled to our lease liabilities on our Consolidated Balance Sheet (amounts in millions): Operating Finance (2) Future minimum lease payments (1) : 2024 $ 80 $ 20 2025 68 17 2026 51 13 2027 43 12 2028 34 15 Thereafter 238 48 Total 514 125 Less: Present value discount (171) (49) Lease liabilities $ 343 $ 76 (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 2024 through 2028 and approximately $45 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, 2023 reconciled to our lease liabilities on our Consolidated Balance Sheet (amounts in millions): Operating Finance (2) Future minimum lease payments (1) : 2024 $ 80 $ 20 2025 68 17 2026 51 13 2027 43 12 2028 34 15 Thereafter 238 48 Total 514 125 Less: Present value discount (171) (49) Lease liabilities $ 343 $ 76 (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 2024 through 2028 and approximately $45 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, 2023 2022 2021 Operating lease revenue (1) $ 32 $ 29 $ 28 (1) These amounts are included in “ Services revenues |
Schedule of Lessor Future Revenues Maturity | The following table presents the undiscounted cash flows expected to be received related to these agreements (in millions): 2024 2025 2026 2027 2028 Thereafter Future minimum lease revenue $ 24 $ 18 $ 15 $ 16 $ 16 $ 154 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Income Tax Disclosure [Abstract] | |
Schedule of Components of Income Tax Expense | Components of income tax expense are as follows (in millions): Year Ended December 31, 2023 2022 2021 Current income tax expense: State income tax $ 2 $ 1 $ 2 Canadian federal and provincial income tax 143 83 48 Total current income tax expense $ 145 $ 84 $ 50 Deferred income tax expense/(benefit): Canadian federal and provincial income tax $ (24) $ 105 $ 23 Total deferred income tax expense/(benefit) $ (24) $ 105 $ 23 Total income tax expense $ 121 $ 189 $ 73 |
Schedule 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, 2023 2022 2021 Income before tax $ 1,623 $ 1,417 $ 721 Partnership earnings not subject to Canadian tax (1,136) (686) (370) $ 487 $ 731 $ 351 Canadian federal and provincial corporate tax rate 24% 24% 24% Income tax expense at statutory rate $ 117 $ 175 $ 84 Canadian permanent differences $ 2 $ 13 $ (13) State income tax 2 1 2 Total income tax expense $ 121 $ 189 $ 73 |
Schedule of 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, 2023 2022 Deferred tax assets: Lease liabilities $ 40 $ 45 Other 45 16 Total deferred tax assets 85 61 Deferred tax liabilities: Property and equipment in excess of tax values (573) (515) Derivative instruments (6) (46) Lease assets (38) (42) Other (3) (3) Total deferred tax liabilities (620) (606) Net deferred tax liabilities $ (535) $ (545) Balance sheet classification of deferred tax assets/(liabilities): Other long-term liabilities and deferred credits $ (535) $ (545) $ (535) $ (545) |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Related Party Transactions [Abstract] | |
Schedule of Related Party Transactions | As of December 31, 2023, our outstanding related party note receivable and related party note payable balances were as follows (in millions): December 31, Related party note receivable (1) $ 379 Related party note payable (1) $ 379 (1) We have elected to present our related party notes with the same counterparty on a net basis on our Consolidated Balance Sheet because there is a legal right to offset and we intend to offset with the counterparty. During the three years ended December 31, 2023, 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, 2023 2022 2021 Revenues from related parties $ 48 $ 45 $ 33 Purchases and related costs from related parties $ 404 $ 365 $ 385 Our receivable and payable amounts with these related parties as reflected on our Consolidated Balance Sheets were as follows (in millions): December 31, 2023 2022 Trade accounts receivable and other receivables, net from related parties (1) $ 63 $ 45 Trade accounts payable to related parties (1) (2) $ 72 $ 79 (1) Includes amounts related to 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, 2023 | |
Share-Based Payment Arrangement [Abstract] | |
Schedule of LTIP Awards Authorized | The following is a summary of the awards authorized under our LTIPs as of December 31, 2023 (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, 17.4 million awards are currently available for future grant. The remaining balance has already vested or is currently outstanding. |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
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, 2023 are summarized below (in millions): 2024 2025 2026 2027 2028 Thereafter Total Leases (1) $ 100 $ 85 $ 64 $ 55 $ 49 $ 286 $ 639 Other commitments (2) 367 336 249 217 117 425 1,711 Total $ 467 $ 421 $ 313 $ 272 $ 166 $ 711 $ 2,350 (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 13 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 $396 million, $336 million and $270 million for 2023, 2022 and 2021, 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 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, 2023 | |
Segment Reporting [Abstract] | |
Schedule of 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, 2023 Revenues (1) : Product sales $ 45,587 $ 1,765 $ (378) $ 46,974 Services 1,587 170 (19) 1,738 Total revenues $ 47,174 $ 1,935 $ (397) $ 48,712 Equity earnings in unconsolidated entities $ 369 $ — $ 369 Segment Adjusted EBITDA $ 2,163 $ 522 $ 2,685 Investment and acquisition capital expenditures (2) (3) $ 765 $ 65 $ 830 Maintenance capital expenditures (3) $ 145 $ 86 $ 231 As of December 31, 2023 Investments in unconsolidated entities $ 2,820 $ — $ 2,820 Crude Oil NGL Intersegment Revenues Total Year Ended December 31, 2022 Revenues (1) : Product sales $ 53,840 $ 2,575 $ (467) $ 55,948 Services 1,240 186 (32) 1,394 Total revenues $ 55,080 $ 2,761 $ (499) $ 57,342 Equity earnings in unconsolidated entities $ 403 $ — $ 403 Segment Adjusted EBITDA $ 1,986 $ 518 $ 2,504 Investment and acquisition capital expenditures (2) (3) $ 461 $ 157 $ 618 Maintenance capital expenditures (3) $ 112 $ 99 $ 211 As of December 31, 2022 Investments in unconsolidated entities $ 3,084 $ — $ 3,084 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 (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. |
Schedule of Reconciliation of Segment Adjusted EBITDA to Net Income/(Loss) Attributable to PAA | The following table reconciles Segment Adjusted EBITDA to Net income attributable to PAA (in millions): Year Ended December 31, 2023 2022 2021 Segment Adjusted EBITDA $ 2,685 $ 2,504 $ 2,194 Adjustments (1) : Depreciation and amortization of unconsolidated entities (2) (87) (85) (123) Derivative activities and inventory valuation adjustments (3) (159) 280 271 Long-term inventory costing adjustments (4) (35) 4 94 Deficiencies under minimum volume commitments, net (5) (12) (7) 7 Equity-indexed compensation expense (6) (36) (32) (19) Foreign currency revaluation (7) (24) (4) 4 Line 901 incident (8) (10) (95) (15) Transaction-related expenses (9) (1) — (16) Segment amounts attributable to noncontrolling interests (10) 454 364 94 Depreciation and amortization (1,048) (965) (774) Gains/(losses) on asset sales and asset impairments, net 152 (269) (592) Gains/(losses) on investments in unconsolidated entities, net 28 346 2 Interest expense, net (386) (405) (425) Other income/(expense), net 102 (219) 19 Income before tax 1,623 1,417 721 Income tax expense (121) (189) (73) Net income 1,502 1,228 648 Net income attributable to noncontrolling interests (272) (191) (55) Net income attributable to PAA $ 1,230 $ 1,037 $ 593 (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 and impairments) 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 (i) investing activities, such as the purchase of linefill, and (ii) purchases of long-term inventory. 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 investees, 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 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 or equity earnings, 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 be settled in cash is not excluded in determining Segment Adjusted EBITDA. See Note 17 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 18 for additional information regarding the Line 901 incident. (9) Includes expenses associated with the Rattler Permian Transaction in 2023 and the Permian JV transaction in 2021. 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, 2023 and 2021 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), Cactus II (beginning November 2022) and Red River. |
Schedule of 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) 2023 2022 2021 United States $ 42,308 $ 46,903 $ 34,458 Canada 6,404 10,439 7,620 $ 48,712 $ 57,342 $ 42,078 (1) Revenues are primarily attributed to each region based on where the services are provided or the product is shipped. |
Schedule of Long-lived Assets Attributable to Geographic Areas | December 31, Long-Lived Assets (1) 2023 2022 United States $ 18,591 $ 18,655 Canada 3,820 3,802 $ 22,411 $ 22,457 (1) Excludes long-term derivative assets and long-term deferred tax assets. |
Organization and Basis of Con_2
Organization and Basis of Consolidation and Presentation (Details) shares in Millions | 12 Months Ended |
Dec. 31, 2023 segment shares | |
Organization and basis of presentation | |
Operating segments number | segment | 2 |
AAP | PAGP | |
Organization and basis of presentation | |
Ownership interest (as a percent) | 84% |
PAA | AAP | |
Organization and basis of presentation | |
Ownership interest (in units) | shares | 232.7 |
Ownership interest (as a percent) | 30% |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies - Various Policies (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Foreign Currency Transactions/Translation | |||
Gain (loss) on revaluation of foreign currency transactions and monetary assets and liabilities | $ (8) | $ (41) | $ 7 |
Cash and Cash Equivalents and Restricted Cash | |||
Outstanding checks included in accounts payable that were reclassified from cash and cash equivalents | $ 26 | $ 25 |
Summary of Significant Accoun_5
Summary of Significant Accounting Policies - Asset Retirement Obligations (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Beginning balance | $ 122 | $ 143 | $ 135 |
Liabilities incurred | 2 | 2 | 2 |
Liabilities settled | (1) | (26) | (1) |
Accretion expense | 4 | 4 | 4 |
Revisions in estimated cash flows | (1) | (1) | 3 |
Ending balance | $ 126 | $ 122 | $ 143 |
Revenues and Accounts Receiva_3
Revenues and Accounts Receivable - Disaggregation of Revenue (Details) - Operating Segments - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Disaggregation of Revenue [Line Items] | |||
Revenue from contracts with customers | $ 48,999 | $ 57,473 | $ 42,949 |
Crude Oil | |||
Disaggregation of Revenue [Line Items] | |||
Revenue from contracts with customers | 47,146 | 54,929 | 40,550 |
Crude Oil | Sales | |||
Disaggregation of Revenue [Line Items] | |||
Revenue from contracts with customers | 45,621 | 53,822 | 39,635 |
Crude Oil | Transportation | |||
Disaggregation of Revenue [Line Items] | |||
Revenue from contracts with customers | 1,144 | 745 | 484 |
Crude Oil | Terminalling, Storage and Other | |||
Disaggregation of Revenue [Line Items] | |||
Revenue from contracts with customers | 381 | 362 | 431 |
NGL | |||
Disaggregation of Revenue [Line Items] | |||
Revenue from contracts with customers | 1,853 | 2,544 | 2,399 |
NGL | Sales | |||
Disaggregation of Revenue [Line Items] | |||
Revenue from contracts with customers | 1,729 | 2,414 | 2,292 |
NGL | Transportation | |||
Disaggregation of Revenue [Line Items] | |||
Revenue from contracts with customers | 30 | 30 | 25 |
NGL | Terminalling, Storage and Other | |||
Disaggregation of Revenue [Line Items] | |||
Revenue from contracts with customers | $ 94 | $ 100 | $ 82 |
Revenues and Accounts Receiva_4
Revenues and Accounts Receivable - Segment Revenue (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Disaggregation of Revenue [Line Items] | |||
Total revenues | $ 48,712 | $ 57,342 | $ 42,078 |
Operating Segments | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | 48,999 | 57,473 | 42,949 |
Other revenues | 110 | 368 | (511) |
Total revenues | 49,109 | 57,841 | 42,438 |
Operating Segments | Crude Oil | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | 47,146 | 54,929 | 40,550 |
Other revenues | 28 | 151 | (80) |
Total revenues | 47,174 | 55,080 | 40,470 |
Operating Segments | NGL | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from contracts with customers | 1,853 | 2,544 | 2,399 |
Other revenues | 82 | 217 | (431) |
Total revenues | 1,935 | 2,761 | 1,968 |
Intersegment revenues elimination | |||
Disaggregation of Revenue [Line Items] | |||
Total revenues | $ (397) | $ (499) | $ (360) |
Revenues and Accounts Receiva_5
Revenues and Accounts Receivable - Counterparty Deficiencies (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 |
Contract With Customer, Asset And Liability [Line Items] | |||
Counterparty deficiencies, billed and collected | $ 228 | $ 229 | $ 141 |
Minimum Volume Commitments | |||
Contract With Customer, Asset And Liability [Line Items] | |||
Counterparty deficiencies, billed and collected | $ 77 | $ 104 |
Revenues and Accounts Receiva_6
Revenues and Accounts Receivable - Contract Balances (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Change in Contract Liabilities [Roll Forward] | ||
Beginning balance | $ 229 | $ 141 |
Amounts recognized as revenue | (42) | (26) |
Additions | 38 | 145 |
Other | 3 | (31) |
Ending balance | $ 228 | 229 |
Gas Processing Agreement That Was Entered Into In Conjunction With The Purchase Of An Additional Ownership Interest In Certain Straddle Plants | ||
Change in Contract Liabilities [Roll Forward] | ||
Additions | $ 122 | |
Revenue recognition term (in years) | 50 years |
Revenues and Accounts Receiva_7
Revenues and Accounts Receivable - Performance Obligations (Details) $ in Millions | Dec. 31, 2023 USD ($) |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2024-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | $ 609 |
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 | $ 478 |
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 | $ 270 |
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 | $ 210 |
Remaining performance obligation, expected timing of satisfaction, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2028-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | $ 163 |
Remaining performance obligation, expected timing of satisfaction, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2029-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | $ 882 |
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: 2024-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | $ 375 |
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 | $ 329 |
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 | $ 156 |
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 | $ 109 |
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: 2028-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | $ 80 |
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: 2029-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | $ 194 |
Remaining performance obligation, expected timing of satisfaction, period | |
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 | $ 234 |
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 | $ 149 |
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 | $ 114 |
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 | $ 101 |
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: 2028-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | $ 83 |
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: 2029-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | $ 688 |
Remaining performance obligation, expected timing of satisfaction, period |
Revenues and Accounts Receiva_8
Revenues and Accounts Receivable - Narrative (Details) | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Revenue from Contract with Customer [Abstract] | ||
Substantially all trade accounts receivable, net, maximum age of balances past their scheduled invoice date (in days) | 30 days | 30 days |
Revenues and Accounts Receiva_9
Revenues and Accounts Receivable - Trade Accounts Receivable and Other Receivables (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Revenue from Contract with Customer [Abstract] | ||
Trade accounts receivable arising from revenues from contracts with customers | $ 3,999 | $ 4,141 |
Other trade accounts receivables and other receivables | 7,535 | 7,216 |
Impact due to contractual rights of offset with counterparties | (7,774) | (7,450) |
Trade accounts receivable and other receivables, net | $ 3,760 | $ 3,907 |
Net Income Per Common Unit (Det
Net Income Per Common Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Basic and Diluted Net Income per Common Unit | |||
Net income attributable to PAA | $ 1,230 | $ 1,037 | $ 593 |
Amounts allocated to participating securities | (10) | (5) | (2) |
Other | 5 | ||
Net income allocated to common unitholders — Basic | 976 | 831 | 393 |
Net income allocated to common unitholders — Diluted | 976 | 831 | 393 |
Series A Preferred Units | |||
Basic and Diluted Net Income per Common Unit | |||
Distributions to preferred unitholders | $ (173) | $ (149) | $ (149) |
Series A Preferred Units | Weighted Average | |||
Net Income Per Common Unit | |||
Antidilutive securities excluded from computation of net income per common unit (in units) | 71 | 71 | 71 |
Series B Preferred Units | |||
Basic and Diluted Net Income per Common Unit | |||
Distributions to preferred unitholders | $ (76) | $ (52) | $ (49) |
Common Units | |||
Basic and Diluted Net Income per Common Unit | |||
Basic weighted average common units outstanding (in units) | 699 | 701 | 716 |
Diluted weighted average common units outstanding (in units) | 699 | 701 | 716 |
Basic net income per common unit (in dollars per unit) | $ 1.40 | $ 1.19 | $ 0.55 |
Diluted net income per common unit (in dollars per unit) | $ 1.40 | $ 1.19 | $ 0.55 |
Inventory, Linefill and Long-_3
Inventory, Linefill and Long-term Inventory - Narrative (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Inventory Disclosure [Abstract] | |||
Charge related to the write-down of inventory | $ 0 | $ 0 | $ 0 |
Inventory, Linefill and Long-_4
Inventory, Linefill and Long-term Inventory - Components of Inventory, Linefill and Long-term Inventory (Details) bbl in Thousands, $ in Millions | Dec. 31, 2023 USD ($) $ / bbl bbl | Dec. 31, 2022 USD ($) $ / bbl bbl |
Inventory by category | ||
Inventory subtotal, carrying value | $ 548 | $ 729 |
Linefill subtotal, carrying value | 976 | 961 |
Long-term inventory subtotal, carrying value | 265 | 284 |
Total | $ 1,789 | $ 1,974 |
Crude oil | ||
Inventory by category | ||
Inventory, Volumes (in barrels) | bbl | 5,877 | 6,713 |
Linefill, Volumes (in barrels) | bbl | 15,409 | 15,480 |
Long-term inventory, Volumes (in barrels) | bbl | 3,256 | 3,102 |
Inventory subtotal, carrying value | $ 383 | $ 452 |
Linefill subtotal, carrying value | 909 | 906 |
Long-term inventory subtotal, carrying value | $ 232 | $ 246 |
Inventory (Price/Unit of measure) (in dollars per unit) | $ / bbl | 65.17 | 67.33 |
Linefill (Price/Unit of measure) (in dollars per unit) | $ / bbl | 58.99 | 58.53 |
Long-term inventory (Price/Unit of measure) (in dollars per unit) | $ / bbl | 71.25 | 79.30 |
NGL | ||
Inventory by category | ||
Inventory, Volumes (in barrels) | bbl | 5,957 | 7,285 |
Linefill, Volumes (in barrels) | bbl | 2,168 | 1,876 |
Long-term inventory, Volumes (in barrels) | bbl | 1,326 | 1,066 |
Inventory subtotal, carrying value | $ 154 | $ 270 |
Linefill subtotal, carrying value | 67 | 55 |
Long-term inventory subtotal, carrying value | $ 33 | $ 38 |
Inventory (Price/Unit of measure) (in dollars per unit) | $ / bbl | 25.85 | 37.06 |
Linefill (Price/Unit of measure) (in dollars per unit) | $ / bbl | 30.90 | 29.32 |
Long-term inventory (Price/Unit of measure) (in dollars per unit) | $ / bbl | 24.89 | 35.65 |
Other | ||
Inventory by category | ||
Inventory subtotal, carrying value | $ 11 | $ 7 |
Property and Equipment - Compon
Property and Equipment - Components of Property and Equipment, Net (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Property and Equipment | ||
Property and equipment, gross | $ 21,143 | $ 20,020 |
Accumulated depreciation | (5,361) | (4,770) |
Property and equipment, net | 15,782 | 15,250 |
Pipeline systems | Crude Oil | ||
Property and Equipment | ||
Property and equipment, gross | 14,265 | 13,303 |
Pipeline systems | NGL | ||
Property and Equipment | ||
Property and equipment, gross | $ 506 | 458 |
Pipeline systems | Minimum | Crude Oil | ||
Property and Equipment | ||
Estimated Useful Lives (Years) | 10 years | |
Pipeline systems | Minimum | NGL | ||
Property and Equipment | ||
Estimated Useful Lives (Years) | 10 years | |
Pipeline systems | Maximum | Crude Oil | ||
Property and Equipment | ||
Estimated Useful Lives (Years) | 50 years | |
Pipeline systems | Maximum | NGL | ||
Property and Equipment | ||
Estimated Useful Lives (Years) | 50 years | |
Crude oil storage and terminal facilities | Crude Oil | ||
Property and Equipment | ||
Property and equipment, gross | $ 2,664 | 2,631 |
Crude oil storage and terminal facilities | Minimum | Crude Oil | ||
Property and Equipment | ||
Estimated Useful Lives (Years) | 10 years | |
Crude oil storage and terminal facilities | Maximum | Crude Oil | ||
Property and Equipment | ||
Estimated Useful Lives (Years) | 50 years | |
NGL storage, terminal, fractionation and processing facilities | NGL | ||
Property and Equipment | ||
Property and equipment, gross | $ 2,554 | 2,445 |
NGL storage, terminal, fractionation and processing facilities | Minimum | NGL | ||
Property and Equipment | ||
Estimated Useful Lives (Years) | 10 years | |
NGL storage, terminal, fractionation and processing facilities | Maximum | NGL | ||
Property and Equipment | ||
Estimated Useful Lives (Years) | 50 years | |
Office property and equipment and rolling stock | ||
Property and Equipment | ||
Property and equipment, gross | $ 556 | 656 |
Office property and equipment and rolling stock | Minimum | ||
Property and Equipment | ||
Estimated Useful Lives (Years) | 2 years | |
Office property and equipment and rolling stock | Maximum | ||
Property and Equipment | ||
Estimated Useful Lives (Years) | 50 years | |
Construction in progress | ||
Property and Equipment | ||
Property and equipment, gross | $ 257 | 201 |
Land and other | ||
Property and Equipment | ||
Property and equipment, gross | $ 341 | $ 326 |
Property and Equipment - Narrat
Property and Equipment - Narrative (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Sep. 30, 2022 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Property and Equipment | ||||
Depreciation expense | $ 733 | $ 707 | $ 652 | |
Construction in progress expenditures incurred but not yet paid | $ 55 | $ 46 | 48 | |
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 (as a percent) | 15% | |||
Crude Oil | California assets | ||||
Property and Equipment | ||||
Non-cash impairment losses, long-lived assets | $ 330 | |||
Impairment, long-lived asset, held-for-use, statement of income [extensible enumeration] | Gains/(losses) on asset sales and asset impairments, net | |||
Crude Oil | Crude oil storage terminal assets | ||||
Property and Equipment | ||||
Non-cash impairment losses, long-lived assets | $ 220 | |||
Impairment, long-lived asset, held-for-use, statement of income [extensible enumeration] | Gains/(losses) on asset sales and asset impairments, net |
Acquisitions, Divestitures an_3
Acquisitions, Divestitures and Other Transactions - Rattler Permian Transaction Narrative (Details) - USD ($) $ in Millions | 1 Months Ended | 3 Months Ended | |||
Nov. 30, 2023 | Jul. 31, 2022 | Sep. 30, 2023 | Jun. 30, 2023 | Sep. 30, 2022 | |
OMOG JV LLC (“OMOG”) | |||||
Business Acquisition [Line Items] | |||||
Ownership Interest in Unconsolidated Entity Prior to Acquisition (as a percent) | 40% | ||||
OMOG JV LLC (“OMOG”) | Plains Oryx Permian Basin LLC | |||||
Business Acquisition [Line Items] | |||||
Ownership Interest in Unconsolidated Entity Prior to Acquisition (as a percent) | 57% | ||||
Plains Oryx Permian Basin LLC | |||||
Business Acquisition [Line Items] | |||||
Consolidated subsidiary, ownership interest held by the parent (as a percent) | 65% | 65% | 65% | ||
OMOG JV LLC and Southern Delaware Gathering Assets | |||||
Business Acquisition [Line Items] | |||||
Business acquisition amount, net to our interest in the Permian JV | $ 191 | ||||
Consideration transferred | 294 | ||||
Business combination, consideration transferred, including equity interest in acquire held prior to combination | $ 532 | ||||
OMOG JV LLC and Southern Delaware Gathering Assets | Level 3 | Measurement Input, Discount Rate | Valuation Technique, Discounted Cash Flow | Minimum | Intangible Assets | |||||
Business Acquisition [Line Items] | |||||
Business combination, measurement input | 0.21 | ||||
OMOG JV LLC and Southern Delaware Gathering Assets | Level 3 | Measurement Input, Discount Rate | Valuation Technique, Discounted Cash Flow | Maximum | Intangible Assets | |||||
Business Acquisition [Line Items] | |||||
Business combination, measurement input | 0.23 | ||||
OMOG JV LLC and Southern Delaware Gathering Assets | Rattler | Plains Oryx Permian Basin LLC | |||||
Business Acquisition [Line Items] | |||||
Cash consideration, including working capital and other adjustments | $ 294 | ||||
OMOG JV LLC (“OMOG”) | |||||
Business Acquisition [Line Items] | |||||
Additional interest acquired (as a percent) | 43% | ||||
Fair value amount | $ 239 | ||||
OMOG JV LLC (“OMOG”) | Plains Oryx Permian Basin LLC | |||||
Business Acquisition [Line Items] | |||||
Business combination, step acquisition, equity interest in acquiree, including subsequent acquisition (as a percent) | 100% | ||||
Business combination, step acquisition, equity interest in acquire (as a percent) | 57% | ||||
OMOG JV LLC (“OMOG”) | Gains/(losses) on investments in unconsolidated entities, net | |||||
Business Acquisition [Line Items] | |||||
Equity interest in acquiree, remeasurement gain | $ 29 | ||||
OMOG JV LLC (“OMOG”) | Level 3 | Measurement Input, Discount Rate | Valuation Technique, Discounted Cash Flow | |||||
Business Acquisition [Line Items] | |||||
Business combination, measurement input | 0.11 | ||||
OMOG JV LLC (“OMOG”) | Rattler | |||||
Business Acquisition [Line Items] | |||||
Additional interest acquired (as a percent) | 43% | ||||
OMOG JV LLC (“OMOG”) | Rattler | Plains Oryx Permian Basin LLC | |||||
Business Acquisition [Line Items] | |||||
Additional interest acquired (as a percent) | 43% |
Acquisitions, Divestitures an_4
Acquisitions, Divestitures and Other Transactions - Schedule of Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Millions | Sep. 30, 2023 | Nov. 30, 2022 | Oct. 31, 2021 |
OMOG JV LLC and Southern Delaware Gathering Assets | |||
Business Acquisition [Line Items] | |||
Finite-lived intangible asset, useful life (in years) | 10 years | ||
Property and equipment | $ 484 | ||
Intangible assets | 34 | ||
Working capital and other assets and liabilities | 14 | ||
Identifiable assets acquired and liabilities assumed | $ 532 | ||
OMOG JV LLC and Southern Delaware Gathering Assets | Minimum | |||
Business Acquisition [Line Items] | |||
Estimated Useful Lives (Years) | 3 years | ||
OMOG JV LLC and Southern Delaware Gathering Assets | Maximum | |||
Business Acquisition [Line Items] | |||
Estimated Useful Lives (Years) | 30 years | ||
Cactus II Pipeline LLC | |||
Business Acquisition [Line Items] | |||
Finite-lived intangible asset, useful life (in years) | 20 years | ||
Property and equipment | $ 1,174 | ||
Intangible assets | 428 | ||
Working capital and other assets and liabilities | (46) | ||
Identifiable assets acquired and liabilities assumed | $ 1,556 | ||
Cactus II Pipeline LLC | Minimum | |||
Business Acquisition [Line Items] | |||
Estimated Useful Lives (Years) | 3 years | ||
Cactus II Pipeline LLC | Maximum | |||
Business Acquisition [Line Items] | |||
Estimated Useful Lives (Years) | 50 years | ||
Plains Oryx Permian Basin LLC | Oryx Midstream Holdings LLC | Joint Venture Transaction | |||
Business Acquisition [Line Items] | |||
Finite-lived intangible asset, useful life (in years) | 20 years | ||
Property and equipment | $ 1,886 | ||
Intangible assets | 1,247 | ||
Investment in unconsolidated entities | 103 | ||
Working capital and other assets and liabilities | (6) | ||
Identifiable assets acquired and liabilities assumed | $ 3,230 | ||
Plains Oryx Permian Basin LLC | Oryx Midstream Holdings LLC | Joint Venture Transaction | Minimum | |||
Business Acquisition [Line Items] | |||
Estimated Useful Lives (Years) | 3 years | ||
Plains Oryx Permian Basin LLC | Oryx Midstream Holdings LLC | Joint Venture Transaction | Maximum | |||
Business Acquisition [Line Items] | |||
Estimated Useful Lives (Years) | 30 years |
Acquisitions, Divestitures an_5
Acquisitions, Divestitures and Other Transactions - Schedule of Amortization Expense (Details) - USD ($) $ in Millions | 12 Months Ended | |||||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Sep. 30, 2023 | Nov. 30, 2022 | Oct. 31, 2021 | |
Business Acquisition [Line Items] | ||||||
Expected amortization, year one | $ 272 | |||||
Expected amortization, year two | 249 | |||||
Expected amortization, year three | 210 | |||||
Expected amortization, year four | 187 | |||||
Expected amortization, year five | 165 | |||||
OMOG JV LLC and Southern Delaware Gathering Assets | ||||||
Business Acquisition [Line Items] | ||||||
Finite-lived intangible asset, useful life (in years) | 10 years | |||||
OMOG JV LLC and Southern Delaware Gathering Assets | Customer relationships | ||||||
Business Acquisition [Line Items] | ||||||
Finite-lived intangible asset, useful life (in years) | 10 years | |||||
Amortization | 4 | |||||
Expected amortization, year one | 8 | |||||
Expected amortization, year two | 10 | |||||
Expected amortization, year three | 4 | |||||
Expected amortization, year four | 3 | |||||
Expected amortization, year five | 2 | |||||
Cactus II Pipeline LLC | ||||||
Business Acquisition [Line Items] | ||||||
Finite-lived intangible asset, useful life (in years) | 20 years | |||||
Cactus II Pipeline LLC | Customer relationships | ||||||
Business Acquisition [Line Items] | ||||||
Finite-lived intangible asset, useful life (in years) | 20 years | |||||
Amortization | 61 | $ 13 | ||||
Expected amortization, year one | 51 | |||||
Expected amortization, year two | 47 | |||||
Expected amortization, year three | 32 | |||||
Expected amortization, year four | 32 | |||||
Plains Oryx Permian Basin LLC | Customer relationships | Joint Venture Transaction | ||||||
Business Acquisition [Line Items] | ||||||
Finite-lived intangible asset, useful life (in years) | 20 years | |||||
Amortization | 138 | $ 142 | $ 28 | |||
Expected amortization, year one | 127 | |||||
Expected amortization, year two | 117 | |||||
Expected amortization, year three | $ 106 |
Acquisitions, Divestitures an_6
Acquisitions, Divestitures and Other Transactions - Cactus II Narrative (Details) $ in Millions | 1 Months Ended | ||
Nov. 30, 2022 USD ($) | Dec. 31, 2023 | Oct. 31, 2022 | |
Cactus II Pipeline LLC | |||
Business Acquisition [Line Items] | |||
Ownership Interest in Unconsolidated Entity Prior to Acquisition (as a percent) | 65% | ||
Cactus II Pipeline LLC | |||
Business Acquisition [Line Items] | |||
Noncontrolling interest, ownership (as a percent) | 30% | ||
Cactus II Pipeline LLC | Enbridge | |||
Business Acquisition [Line Items] | |||
Noncontrolling interest, ownership (as a percent) | 30% | ||
Cactus II Pipeline LLC | |||
Business Acquisition [Line Items] | |||
Additional interest acquired (as a percent) | 5% | ||
Business combination, step acquisition, equity interest in acquiree, including subsequent acquisition (as a percent) | 70% | ||
Business combination, step acquisition, equity interest in acquire (as a percent) | 65% | ||
Fair value amount | $ 1,140 | ||
Consideration transferred | 1,556 | ||
Cactus II Pipeline LLC | Gains/(losses) on investments in unconsolidated entities, net | |||
Business Acquisition [Line Items] | |||
Equity interest in acquiree, remeasurement gain | 370 | ||
Cactus II Pipeline LLC | Noncontrolling Interests | |||
Business Acquisition [Line Items] | |||
Noncontrolling interest, increase from business combination | $ 526 | ||
Cactus II Pipeline LLC | Level 3 | Measurement Input, Discount Rate | Valuation Technique, Discounted Cash Flow | |||
Business Acquisition [Line Items] | |||
Business combination, measurement input | 0.14 | ||
Cactus II Pipeline LLC | Level 3 | Measurement Input, Discount Rate | Valuation Technique, Discounted Cash Flow | Intangible Assets | |||
Business Acquisition [Line Items] | |||
Business combination, measurement input | 0.18 | ||
Cactus II Pipeline LLC | Western Midstream Partners, LP | |||
Business Acquisition [Line Items] | |||
Payments to acquire businesses, gross | $ 88 | ||
Cactus II Pipeline LLC | Plains and Enbridge | Western Midstream Partners, LP | |||
Business Acquisition [Line Items] | |||
Additional interest acquired (as a percent) | 15% | ||
Payments to acquire businesses, gross | $ 265 | ||
Cactus II Pipeline LLC | Enbridge | |||
Business Acquisition [Line Items] | |||
Additional interest acquired (as a percent) | 10% | ||
Cactus II Pipeline LLC | Enbridge | Western Midstream Partners, LP | |||
Business Acquisition [Line Items] | |||
Payments to acquire businesses, gross | $ 177 |
Acquisitions, Divestitures an_7
Acquisitions, Divestitures and Other Transactions - Other Acquisitions Narrative (Details) - USD ($) $ in Millions | 1 Months Ended | 3 Months Ended | ||
Nov. 30, 2023 | Oct. 31, 2022 | Jul. 31, 2022 | Sep. 30, 2023 | |
Certain Straddle Plants | NGL | ||||
Business Acquisition [Line Items] | ||||
Obligation, processing capacity term (in years) | 50 years | |||
Asset acquisition, consideration transferred | $ 122 | |||
Revenue recognition term (in years) | 50 years | |||
Northern Delaware Basin Gathering System | ||||
Business Acquisition [Line Items] | ||||
Asset acquisition amount, net to our interest in the Permian JV | $ 88 | |||
Plains Oryx Permian Basin LLC | ||||
Business Acquisition [Line Items] | ||||
Consolidated subsidiary, ownership interest held by the parent (as a percent) | 65% | 65% | 65% | |
Advantage Pipeline Holdings LLC | ||||
Business Acquisition [Line Items] | ||||
Cash consideration, including working capital and other adjustments | $ 74 | |||
Business acquisition amount, net to our interest in the Permian JV | $ 48 | |||
Additional interest acquired (as a percent) | 50% | |||
Business combination, step acquisition, equity interest in acquiree, including subsequent acquisition (as a percent) | 100% | |||
Subsidiary of LM Energy Partners | Plains Oryx Permian Basin LLC | Northern Delaware Basin Gathering System | ||||
Business Acquisition [Line Items] | ||||
Asset acquisition, consideration transferred | $ 135 |
Acquisitions, Divestitures an_8
Acquisitions, Divestitures and Other Transactions - Asset Exchange Narrative (Details) $ in Millions | 1 Months Ended | 12 Months Ended | ||
Jun. 30, 2021 USD ($) plant | Dec. 31, 2023 USD ($) | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | |
Business Acquisition [Line Items] | ||||
Gain on divestiture of assets | $ 152 | $ (269) | $ (592) | |
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 an_9
Acquisitions, Divestitures and Other Transactions - Joint Venture Transaction Narrative (Details) - USD ($) $ in Millions | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||
Nov. 30, 2023 | Jul. 31, 2022 | Oct. 31, 2021 | Sep. 30, 2023 | Dec. 31, 2023 | Dec. 31, 2021 | |
Joint Venture Transaction | Plains Oryx Permian Basin LLC | Level 3 | ||||||
Business Acquisition [Line Items] | ||||||
Identifiable assets acquired and liabilities assumed | $ 3,230 | |||||
Joint Venture Transaction | Plains Oryx Permian Basin LLC | Level 3 | Measurement Input, Discount Rate | Valuation Technique, Discounted Cash Flow | ||||||
Business Acquisition [Line Items] | ||||||
Business combination, measurement input | 0.12 | |||||
Joint Venture Transaction | Plains Oryx Permian Basin LLC | 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 | 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 | Level 3 | Measurement Input, Market Multiple | Valuation, Market Approach | Maximum | ||||||
Business Acquisition [Line Items] | ||||||
Business combination, measurement input | 11 | |||||
Joint Venture Transaction | Plains Oryx Permian Basin LLC | Plains Oryx Permian Basin LLC | ||||||
Business Acquisition [Line Items] | ||||||
Members' equity | $ 7,529 | |||||
Joint Venture Transaction | Oryx Midstream Holdings LLC | Plains Oryx Permian Basin LLC | ||||||
Business Acquisition [Line Items] | ||||||
Consideration transferred | 3,230 | |||||
Identifiable assets acquired and liabilities assumed | $ 3,230 | |||||
Transaction-related costs | $ 17 | |||||
Schedule of Partners' Capital | The following table presents the amounts recognized in partners’ capital associated with this transaction (in millions): Recognized Amount Noncontrolling interests $ 2,635 Partners’ capital, excluding noncontrolling interests 595 $ 3,230 | |||||
Schedule of 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, 2021; 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 Total revenues $ 42,359 Net income attributable to PAA $ 524 Net income allocated to common unitholders $ 324 Basic and diluted net income per common unit $ 0.45 | |||||
Modified Sharing Arrangement | Plains Oryx Permian Basin LLC | ||||||
Business Acquisition [Line Items] | ||||||
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% | |||||
Modified Sharing Arrangement | Oryx Midstream Holdings LLC | Plains Oryx Permian Basin LLC | ||||||
Business Acquisition [Line Items] | ||||||
Distribution percentage after termination of modified sharing arrangement | 65% | |||||
Modified Sharing Arrangement | Oryx Midstream Holdings LLC | Plains Oryx Permian Basin LLC | Maximum | ||||||
Business Acquisition [Line Items] | ||||||
Modified revenue sharing arrangement, term | 10 years | |||||
Modified Sharing Arrangement | Oryx Midstream Holdings LLC | Plains Oryx Permian Basin LLC | Plains Oryx Permian Basin LLC | ||||||
Business Acquisition [Line Items] | ||||||
Distribution percentage after termination of modified sharing arrangement | 35% | |||||
Plains Oryx Permian Basin LLC | ||||||
Business Acquisition [Line Items] | ||||||
Consolidated subsidiary, ownership interest held by the parent (as a percent) | 65% | 65% | 65% | |||
Noncontrolling interest, ownership (as a percent) | 35% | |||||
Plains Oryx Permian Basin LLC | Joint Venture Transaction | ||||||
Business Acquisition [Line Items] | ||||||
Consolidated subsidiary, ownership interest held by the parent (as a percent) | 65% | |||||
Plains Oryx Permian Basin LLC | Joint Venture Transaction | Plains Oryx Permian Basin LLC | ||||||
Business Acquisition [Line Items] | ||||||
Noncontrolling interest, ownership (as a percent) | 35% | |||||
Plains Oryx Permian Basin LLC | Joint Venture Transaction | Oryx Midstream Holdings LLC | ||||||
Business Acquisition [Line Items] | ||||||
Noncontrolling interest, ownership (as a percent) | 35% | |||||
PAA | Stonepeak Infrastructure Partners | Stonepeak Infrastructure Partners, Affiliates | Series A Preferred Units | ||||||
Business Acquisition [Line Items] | ||||||
Ownership interest (as a percent) | 8.90% | |||||
PAA | Stonepeak Infrastructure Partners | Stonepeak Infrastructure Partners, Affiliates | Maximum | Limited Partners | ||||||
Business Acquisition [Line Items] | ||||||
Ownership interest (as a percent) | 1% |
Acquisitions, Divestitures a_10
Acquisitions, Divestitures and Other Transactions - Partners' Capital (Details) - Plains Oryx Permian Basin LLC - Joint Venture Transaction - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | |
Oct. 31, 2021 | Dec. 31, 2022 | Dec. 31, 2021 | |
Business Acquisition [Line Items] | |||
Partners’ capital, excluding noncontrolling interests | $ (26) | $ 3,256 | |
Noncontrolling Interests | |||
Business Acquisition [Line Items] | |||
Partners’ capital, excluding noncontrolling interests | (16) | 2,651 | |
Partners’ Capital Excluding Noncontrolling Interests | |||
Business Acquisition [Line Items] | |||
Partners’ capital, excluding noncontrolling interests | $ 595 | $ (10) | $ 605 |
Oryx Midstream Holdings LLC | Noncontrolling Interests | |||
Business Acquisition [Line Items] | |||
Noncontrolling interests | 2,635 | ||
Oryx Midstream Holdings LLC | |||
Business Acquisition [Line Items] | |||
Partners’ capital, excluding noncontrolling interests | $ 3,230 |
Acquisitions, Divestitures a_11
Acquisitions, Divestitures and Other Transactions - Modified Sharing Arrangement (Details) - Plains Oryx Permian Basin LLC - Modified Sharing Arrangement | Dec. 31, 2023 |
Up to $300 | |
Business Acquisition [Line Items] | |
Modified sharing arrangement, distribution (as a percent) | 50% |
$300 - $428 | |
Business Acquisition [Line Items] | |
Modified sharing arrangement, distribution (as a percent) | 100% |
$428 - $815 | |
Business Acquisition [Line Items] | |
Modified sharing arrangement, distribution (as a percent) | 65% |
$815 and above | |
Business Acquisition [Line Items] | |
Modified sharing arrangement, distribution (as a percent) | 70% |
Oryx Midstream Holdings LLC | Up to $300 | |
Business Acquisition [Line Items] | |
Modified sharing arrangement, distribution (as a percent) | 50% |
Oryx Midstream Holdings LLC | $428 - $815 | |
Business Acquisition [Line Items] | |
Modified sharing arrangement, distribution (as a percent) | 35% |
Oryx Midstream Holdings LLC | $815 and above | |
Business Acquisition [Line Items] | |
Modified sharing arrangement, distribution (as a percent) | 30% |
Acquisitions, Divestitures a_12
Acquisitions, Divestitures and Other Transactions - Pro Forma (Details) - Plains Oryx Permian Basin LLC - Oryx Midstream Holdings LLC - Joint Venture Transaction $ / shares in Units, $ in Millions | 12 Months Ended |
Dec. 31, 2021 USD ($) $ / shares | |
Business Acquisition [Line Items] | |
Total revenues | $ 42,359 |
Net income attributable to PAA | 524 |
Net income allocated to common unitholders | $ 324 |
Basic net income per common unit (in dollar per unit) | $ / shares | $ 0.45 |
Diluted net income per common unit (in dollar per unit) | $ / shares | $ 0.45 |
Acquisitions, Divestitures a_13
Acquisitions, Divestitures and Other Transactions - Divestitures Narrative (Details) - USD ($) $ in Millions | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||||
Feb. 28, 2023 | Aug. 31, 2021 | Jun. 30, 2021 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Jul. 31, 2021 | |
Divestitures | |||||||
Gains/(losses) on asset sales and asset impairments, net | $ 152 | $ (269) | $ (592) | ||||
Proceeds from sales of assets | 328 | 60 | $ 881 | ||||
Deferred losses on hedges remaining in other comprehensive income | $ (10,422) | (10,057) | |||||
Assets Sold Primarily Consisted Of Land And Related Assets In Long Beach, California, As Well As Line 901 And The Sisquoc To Pentland Portion Of Line 903 | Disposed of by Sale | (Gains)/Losses On Asset Sales and Asset Impairments, Net | |||||||
Divestitures | |||||||
Gain from sale of assets | 61 | ||||||
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 | ||||||
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 | Held for Sale | Derivative Instruments | |||||||
Divestitures | |||||||
Deferred losses on hedges remaining in other comprehensive income | $ 18 | ||||||
Crude Oil | Assets Sold Primarily Consisted Of Land And Related Assets In Long Beach, California, As Well As Line 901 And The Sisquoc To Pentland Portion Of Line 903 | Disposed of by Sale | |||||||
Divestitures | |||||||
Proceeds from sales of assets | 60 | ||||||
Crude Oil | Pine Prairie and Southern Pines Natural Gas Storage Facilities | Disposed of by Sale | |||||||
Divestitures | |||||||
Proceeds from sales of assets | $ 850 | ||||||
Keyera Fort Saskatchewan Facility | |||||||
Divestitures | |||||||
Non-operated/undivided joint interest rate, sold | 21% | ||||||
Proceeds from divestiture of interest in joint venture | $ 270 | ||||||
Gains/(losses) on asset sales and asset impairments, net | $ 140 | ||||||
Keyera Fort Saskatchewan Facility | Other current assets | |||||||
Divestitures | |||||||
Assets held-for-sale | $ 130 |
Investments in Unconsolidated_3
Investments in Unconsolidated Entities - Equity Method Investments (Details) $ in Millions | 3 Months Ended | 12 Months Ended | ||||||
Dec. 31, 2022 USD ($) Pipeline | Dec. 31, 2023 USD ($) | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | Nov. 30, 2022 | Sep. 30, 2022 | Jul. 31, 2022 | Jun. 30, 2022 | |
Investments in Unconsolidated Entities | ||||||||
Investments in unconsolidated entities | $ 3,084 | $ 2,820 | $ 3,084 | $ 3,805 | ||||
Gains/(losses) on investments in unconsolidated entities, net | 28 | 346 | 2 | |||||
Capital contributions to equity method investees excluding capitalized interest | 29 | 13 | $ 82 | |||||
Amount by which investments in unconsolidated entities exceeded our share of the underlying equity in the net assets | 204 | $ 229 | 204 | |||||
Advantage Pipeline Holdings LLC | ||||||||
Investments in Unconsolidated Entities | ||||||||
Additional interest acquired (as a percent) | 50% | |||||||
Cactus II Pipeline LLC | ||||||||
Investments in Unconsolidated Entities | ||||||||
Additional interest acquired (as a percent) | 5% | |||||||
BridgeTex Pipeline Company, LLC (“BridgeTex”) | ||||||||
Investments in Unconsolidated Entities | ||||||||
Ownership interest in unconsolidated entity (as a percent) | 20% | |||||||
Investments in unconsolidated entities | 403 | $ 363 | 403 | |||||
Capline Pipeline Company LLC (“Capline”) | ||||||||
Investments in Unconsolidated Entities | ||||||||
Ownership interest in unconsolidated entity (as a percent) | 54% | |||||||
Investments in unconsolidated entities | 539 | $ 535 | 539 | |||||
Diamond Pipeline LLC | ||||||||
Investments in Unconsolidated Entities | ||||||||
Ownership interest in unconsolidated entity (as a percent) | 50% | |||||||
Investments in unconsolidated entities | 460 | $ 450 | 460 | |||||
Eagle Ford Pipeline LLC | ||||||||
Investments in Unconsolidated Entities | ||||||||
Ownership interest in unconsolidated entity (as a percent) | 50% | |||||||
Investments in unconsolidated entities | 371 | $ 370 | 371 | |||||
Eagle Ford Terminals Corpus Christi LLC | ||||||||
Investments in Unconsolidated Entities | ||||||||
Ownership interest in unconsolidated entity (as a percent) | 50% | |||||||
Investments in unconsolidated entities | 118 | $ 116 | 118 | |||||
OMOG JV LLC (“OMOG”) | ||||||||
Investments in Unconsolidated Entities | ||||||||
Ownership interest in unconsolidated entity (as a percent) | 40% | |||||||
Investments in unconsolidated entities | $ 211 | $ 211 | ||||||
OMOG JV LLC (“OMOG”) | Acquisition of Additional Interest in Exchange for Contribution of Pipeline Assets | ||||||||
Investments in Unconsolidated Entities | ||||||||
Ownership interest in unconsolidated entity (as a percent) | 57% | 57% | ||||||
Number of pipelines or partial pipelines contributed | Pipeline | 2 | |||||||
Gains/(losses) on investments in unconsolidated entities, net | $ (25) | |||||||
Saddlehorn Pipeline Company, LLC | ||||||||
Investments in Unconsolidated Entities | ||||||||
Ownership interest in unconsolidated entity (as a percent) | 30% | |||||||
Investments in unconsolidated entities | 197 | $ 192 | $ 197 | |||||
White Cliffs Pipeline, LLC | ||||||||
Investments in Unconsolidated Entities | ||||||||
Ownership interest in unconsolidated entity (as a percent) | 36% | |||||||
Investments in unconsolidated entities | 150 | $ 138 | 150 | |||||
Wink to Webster Pipeline LLC (“W2W Pipeline”) | ||||||||
Investments in Unconsolidated Entities | ||||||||
Ownership interest in unconsolidated entity (as a percent) | 16% | |||||||
Investments in unconsolidated entities | 357 | $ 380 | 357 | |||||
Other investments | ||||||||
Investments in Unconsolidated Entities | ||||||||
Investments in unconsolidated entities | $ 278 | $ 276 | $ 278 | |||||
Advantage Pipeline Holdings LLC | ||||||||
Investments in Unconsolidated Entities | ||||||||
Ownership interest in unconsolidated entity (as a percent) | 50% |
Investments in Unconsolidated_4
Investments in Unconsolidated Entities - Summarized Financial Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Investments in Unconsolidated Entities | |||
Current assets | $ 4,913 | $ 5,355 | |
Current liabilities | 5,003 | 5,891 | |
Noncurrent liabilities | 8,620 | 8,676 | |
Revenues | 48,712 | 57,342 | $ 42,078 |
Operating income | 1,510 | 1,292 | 851 |
Equity Method Investment, Nonconsolidated Investee | |||
Investments in Unconsolidated Entities | |||
Current assets | 528 | 471 | |
Noncurrent assets | 7,194 | 7,579 | |
Current liabilities | 476 | 252 | |
Noncurrent liabilities | 5 | 8 | |
Revenues | 1,667 | 1,726 | 1,320 |
Operating income | 921 | 1,004 | 505 |
Net income | $ 947 | $ 1,011 | $ 506 |
Intangible Asset, Net - Schedul
Intangible Asset, Net - Schedule of Intangible Assets (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Finite-Lived Intangible Assets | ||
Cost | $ 2,819 | $ 2,852 |
Accumulated Amortization | (944) | (707) |
Net | 1,875 | 2,145 |
Customer contracts and relationships | ||
Finite-Lived Intangible Assets | ||
Cost | 2,789 | 2,817 |
Accumulated Amortization | (932) | (695) |
Net | $ 1,857 | 2,122 |
Customer contracts and relationships | Minimum | ||
Finite-Lived Intangible Assets | ||
Finite-lived intangible asset, useful life (in years) | 1 year | |
Customer contracts and relationships | Maximum | ||
Finite-Lived Intangible Assets | ||
Finite-lived intangible asset, useful life (in years) | 29 years | |
Other agreements | ||
Finite-Lived Intangible Assets | ||
Cost | $ 30 | 35 |
Accumulated Amortization | (12) | (12) |
Net | $ 18 | $ 23 |
Other agreements | Minimum | ||
Finite-Lived Intangible Assets | ||
Finite-lived intangible asset, useful life (in years) | 15 years | |
Other agreements | Maximum | ||
Finite-Lived Intangible Assets | ||
Finite-lived intangible asset, useful life (in years) | 70 years |
Intangible Asset, Net - Amortiz
Intangible Asset, Net - Amortization Expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |||
Amortization expense for finite-lived intangible assets | $ 308 | $ 254 | $ 122 |
Estimated amortization expense related to finite-lived intangible assets for the next five years | |||
Expected amortization, year one | 272 | ||
Expected amortization, year two | 249 | ||
Expected amortization, year three | 210 | ||
Expected amortization, year four | 187 | ||
Expected amortization, year five | $ 165 |
Debt - Schedule of Debt (Detail
Debt - Schedule of Debt (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Oct. 31, 2023 | Jan. 31, 2023 | Dec. 31, 2022 |
SHORT-TERM DEBT | ||||
Short-term debt | $ 446 | $ 1,159 | ||
LONG-TERM DEBT | ||||
Senior notes, net of unamortized discounts and debt issuance costs | 7,242 | 7,237 | ||
Noncurrent portion of other long-term debt | 63 | 50 | ||
Total long-term debt | 7,305 | 7,287 | ||
Total debt | 7,751 | 8,446 | ||
Senior notes | ||||
LONG-TERM DEBT | ||||
Unamortized discounts and debt issuance costs | (41) | (46) | ||
Senior notes, net of unamortized discounts and debt issuance costs | 7,242 | 7,237 | ||
Debt instrument face value | 7,300 | 8,400 | ||
Senior notes | Level 2 | ||||
LONG-TERM DEBT | ||||
Debt instrument fair value | $ 6,900 | 7,600 | ||
Senior notes | 2.85% senior notes due January 2023 | ||||
SHORT-TERM DEBT | ||||
Debt instrument, interest rate (as a percent) | 2.85% | |||
Senior notes | 3.85% senior notes due October 2023 | ||||
SHORT-TERM DEBT | ||||
Debt instrument, interest rate (as a percent) | 3.85% | |||
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% | |||
LONG-TERM DEBT | ||||
Long-term debt, before deducting unamortized discounts and debt issuance costs | $ 1,000 | 1,000 | ||
Senior notes | 3.80% senior notes due September 2030 | ||||
SHORT-TERM DEBT | ||||
Debt instrument, interest rate (as a percent) | 3.80% | |||
LONG-TERM DEBT | ||||
Long-term debt, before deducting unamortized discounts and debt issuance costs | $ 750 | 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 | ||
Other long-term debt | ||||
LONG-TERM DEBT | ||||
Noncurrent portion of other long-term debt | 63 | 50 | ||
Line of Credit | Commercial paper notes | ||||
SHORT-TERM DEBT | ||||
Short-term notes and borrowings | $ 433 | |||
Weighted average interest rate, short-term (as a percent) | 5.80% | |||
Senior notes | 2.85% senior notes due January 2023 | ||||
SHORT-TERM DEBT | ||||
Short-term notes and borrowings | $ 400 | |||
Debt instrument, interest rate (as a percent) | 2.85% | |||
Senior notes | 3.85% senior notes due October 2023 | ||||
SHORT-TERM DEBT | ||||
Short-term notes and borrowings | $ 700 | |||
Debt instrument, interest rate (as a percent) | 3.85% | |||
Other | ||||
SHORT-TERM DEBT | ||||
Short-term debt | $ 13 | $ 59 |
Debt - Commercial Paper and Cre
Debt - Commercial Paper and Credit Facilities (Details) $ in Millions | 1 Months Ended | 12 Months Ended | ||
Aug. 31, 2021 USD ($) | Dec. 31, 2023 USD ($) extension | Dec. 31, 2021 USD ($) | Aug. 31, 2023 USD ($) | |
Debt Instrument [Line Items] | ||||
Repayments of debt | $ 200 | |||
GO Zone Term Loans | Term Loan | ||||
Debt Instrument [Line Items] | ||||
Repayments of debt | $ 200 | |||
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 | |||
Number of years by which maturity date of credit facility may be extended (in years) | 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 | |||
Number of years by which maturity date of credit facility may be extended (in years) | 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 | |||
Senior Unsecured Revolving Credit Facility, Maturiting in August 2027 | ||||
Debt Instrument [Line Items] | ||||
Committed borrowing capacity | $ 64 |
Debt - Senior Notes (Details)
Debt - Senior Notes (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | |||
Oct. 31, 2023 | Jan. 31, 2023 | Mar. 31, 2022 | Dec. 31, 2023 | Dec. 31, 2022 | |
Debt Instrument [Line Items] | |||||
Repayments of senior notes | $ 1,100 | $ 750 | |||
Senior notes | 3.85% senior notes due October 2023 | |||||
Debt Instrument [Line Items] | |||||
Repayments of senior notes | $ 700 | ||||
Debt instrument, interest rate (as a percent) | 3.85% | ||||
Senior notes | 2.85% senior notes due January 2023 | |||||
Debt Instrument [Line Items] | |||||
Repayments of senior notes | $ 400 | ||||
Debt instrument, interest rate (as a percent) | 2.85% | ||||
Senior notes | 3.65% senior notes due June 2022 | |||||
Debt Instrument [Line Items] | |||||
Repayments of senior notes | $ 750 | ||||
Debt instrument, interest rate (as a percent) | 3.65% | ||||
Consolidated finance subsidiary co-issuer | |||||
Debt Instrument [Line Items] | |||||
Consolidated subsidiary, ownership interest held by the parent (as a percent) | 100% |
Debt - Maturities (Details)
Debt - Maturities (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2023 USD ($) | |
Debt Disclosure [Abstract] | |
Weighted-average maturity of long-term debt | 10 years |
Maturities | |
2024 | $ 750 |
2025 | 1,000 |
2026 | 750 |
2027 | 0 |
2028 | 0 |
Thereafter | $ 4,783 |
Debt - Debt Covenants (Details)
Debt - Debt Covenants (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 USD ($) | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | |
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 | $ 205 | $ 102 | |
Letters of credit | Maximum | |||
Debt Instrument [Line Items] | |||
Periods for which letters of credit are issued (in days) | 70 days | ||
Credit Agreements and Commercial Paper Program | |||
Debt Instrument [Line Items] | |||
Total borrowings | $ 18,100 | 25,000 | $ 32,500 |
Total repayments | $ 17,700 | $ 25,000 | $ 33,200 |
Partners' Capital and Distrib_3
Partners' Capital and Distributions - Preferred Unit Issuance (Details) | 1 Months Ended | 12 Months Ended | ||||||||
Feb. 15, 2024 $ / shares | Jan. 31, 2023 $ / shares | Oct. 10, 2017 $ / shares | May 31, 2023 $ / shares | Dec. 31, 2023 transaction $ / shares | Dec. 31, 2022 $ / shares | Dec. 31, 2021 $ / shares | Aug. 15, 2023 | Nov. 15, 2022 $ / shares | Jan. 28, 2016 $ / shares | |
Partners Capital and Distribution [Line Items] | ||||||||||
Number of days after end of quarter within which distributions must be paid to unitholders (in days) | 45 days | |||||||||
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) | $ 0.585 | $ 0.525 | ||||||||
Annualized distribution rate (in dollars per unit) | $ 2.46 | $ 2.10 | ||||||||
Distribution rate reset, basis spread on variable rate (as a percent) | 5.85% | |||||||||
Distribution rate (as a percent) | 9.375% | |||||||||
Number of redemptions transactions limited to | transaction | 2 | |||||||||
Value of common units if exchanged for redemption of preferred units, as a percentage of weighted average price (as a percent) | 95% | |||||||||
Redemption price as a percentage of issue price (as a percent) | 110% | |||||||||
Series A preferred unit conversion ratio | 1 | |||||||||
Series A Preferred Units | Cash Distribution | ||||||||||
Partners Capital and Distribution [Line Items] | ||||||||||
Distribution per unit (in dollars per unit) | $ 2.34 | $ 2.10 | $ 2.10 | |||||||
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 | |||||||||
Dividend rate percentage (as a percent) | 6.125% | |||||||||
Distribution rate (in dollars per unit) | $ 61.25 | |||||||||
Preferred unit, distribution percentage spread (as a percent) | 4.11% | 4.11% | ||||||||
Preferred unit, credit percentage spread (as a percent) | 0.26121% | |||||||||
Redemption price (in dollars per unit) | $ 1,000 | |||||||||
Series B Preferred Units | Cash Distribution | ||||||||||
Partners Capital and Distribution [Line Items] | ||||||||||
Distribution per unit (in dollars per unit) | $ 93.43 | $ 61.25 | $ 61.25 | |||||||
Series B Preferred Units | Subsequent Event | ||||||||||
Partners Capital and Distribution [Line Items] | ||||||||||
Dividend rate percentage (as a percent) | 9.75093% | |||||||||
Series B Preferred Units | Subsequent Event | Cash Distribution | ||||||||||
Partners Capital and Distribution [Line Items] | ||||||||||
Distribution per unit (in dollars per unit) | $ 24.92 |
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, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Series A Preferred Units | |||
Activity for preferred units and common units | |||
Outstanding, beginning of period (in units) | 71,090,468 | 71,090,468 | 71,090,468 |
Outstanding, end of period (in units) | 71,090,468 | 71,090,468 | 71,090,468 |
Series B Preferred Units | |||
Activity for preferred units and common units | |||
Outstanding, beginning of period (in units) | 800,000 | 800,000 | 800,000 |
Outstanding, end of period (in units) | 800,000 | 800,000 | 800,000 |
Common Units | |||
Activity for preferred units and common units | |||
Outstanding, beginning of period (in units) | 698,354,498 | 704,991,540 | 722,380,416 |
Repurchase and cancellation of common units under the Common Equity Repurchase Program (in units) | (7,251,361) | (18,061,583) | |
Issuance of common units under equity-indexed compensation plans (in units) | 2,654,251 | 614,319 | 672,707 |
Outstanding, end of period (in units) | 701,008,749 | 698,354,498 | 704,991,540 |
Partners' Capital and Distrib_5
Partners' Capital and Distributions - Common Equity Repurchase Program (Details) - Common Equity Repurchase Program - Common Units - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Nov. 30, 2020 | |
Partners Capital and Distribution [Line Items] | ||||
Stock repurchase program, authorized amount | $ 500 | |||
Common equity repurchase program, repurchased amount | $ 0 | $ 74 | $ 178 | |
Common equity repurchase program, remaining amount | $ 198 | |||
Maximum | ||||
Partners Capital and Distribution [Line Items] | ||||
Stock repurchase program, authorized amount | $ 500 |
Partners' Capital and Distrib_6
Partners' Capital and Distributions - Income Allocation and Distributions to Unitholders (Details) | 12 Months Ended |
Dec. 31, 2023 | |
Partners' Capital Notes [Abstract] | |
Net income allocation (as a percent) | 100% |
Number of days after end of quarter within which distributions must be paid to unitholders (in days) | 45 days |
Partners' Capital and Distrib_7
Partners' Capital and Distributions - Preferred Unit Distributions (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||||
Feb. 15, 2024 | Feb. 14, 2024 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Series A Preferred Units | Other current liabilities | |||||
Partners Capital and Distribution [Line Items] | |||||
Distributions payable | $ 44 | ||||
Series B Preferred Units | Other current liabilities | |||||
Partners Capital and Distribution [Line Items] | |||||
Distributions payable | 10 | ||||
Cash Distribution | Series A Preferred Units | |||||
Partners Capital and Distribution [Line Items] | |||||
Cash distribution | $ 166 | $ 149 | $ 149 | ||
Distribution per unit (in dollars per unit) | $ 2.34 | $ 2.10 | $ 2.10 | ||
Cash Distribution | Series A Preferred Units | Subsequent Event | |||||
Partners Capital and Distribution [Line Items] | |||||
Cash distribution | $ 44 | ||||
Cash Distribution | Series B Preferred Units | |||||
Partners Capital and Distribution [Line Items] | |||||
Cash distribution | $ 75 | $ 49 | $ 49 | ||
Distribution per unit (in dollars per unit) | $ 93.43 | $ 61.25 | $ 61.25 | ||
Cash Distribution | Series B Preferred Units | Subsequent Event | |||||
Partners Capital and Distribution [Line Items] | |||||
Cash distribution | $ 20 | ||||
Distribution per unit (in dollars per unit) | $ 24.92 |
Partners' Capital and Distrib_8
Partners' Capital and Distributions - Common Unit Distributions (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||||
Feb. 14, 2024 | Jan. 08, 2024 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Distribution Made to Limited Partner [Line Items] | |||||
Distributions paid | $ 1,330 | $ 1,083 | $ 729 | ||
Common Units | Cash Distribution | |||||
Distribution Made to Limited Partner [Line Items] | |||||
Distributions paid | $ 748 | $ 584 | $ 517 | ||
Distributions per common unit (in dollars per unit) | $ 1.0700 | $ 0.8325 | $ 0.7200 | ||
Common Units | Cash Distribution | Fourth Quarter Distribution | Subsequent Event | |||||
Distribution Made to Limited Partner [Line Items] | |||||
Distributions paid | $ 223 | ||||
Distribution per common unit declared (in dollars per unit) | $ 0.3175 | ||||
Common Units | Cash Distribution | Public | |||||
Distribution Made to Limited Partner [Line Items] | |||||
Distributions paid | $ 492 | $ 383 | $ 341 | ||
Common Units | Cash Distribution | AAP | |||||
Distribution Made to Limited Partner [Line Items] | |||||
Distributions paid | $ 256 | $ 201 | $ 176 | ||
Common Units | Cash Distribution | AAP | Fourth Quarter Distribution | Subsequent Event | |||||
Distribution Made to Limited Partner [Line Items] | |||||
Distributions paid | $ 74 |
Partners' Capital and Distrib_9
Partners' Capital and Distributions - Noncontrolling Interests in Subsidiaries (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | |||
Nov. 30, 2022 | Oct. 31, 2021 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2023 | |
Plains Oryx Permian Basin LLC | Joint Venture Transaction | |||||
Partners Capital and Distribution [Line Items] | |||||
Partners’ capital, excluding noncontrolling interests | $ (26) | $ 3,256 | |||
Plains Oryx Permian Basin LLC | Noncontrolling Interests | Joint Venture Transaction | |||||
Partners Capital and Distribution [Line Items] | |||||
Partners’ capital, excluding noncontrolling interests | (16) | 2,651 | |||
Plains Oryx Permian Basin LLC | Noncontrolling Interests | Joint Venture Transaction | Oryx Midstream Holdings LLC | |||||
Partners Capital and Distribution [Line Items] | |||||
Noncontrolling interest, increase from business combination | $ 2,635 | ||||
Plains Oryx Permian Basin LLC | Partners’ Capital Excluding Noncontrolling Interests | Joint Venture Transaction | |||||
Partners Capital and Distribution [Line Items] | |||||
Partners’ capital, excluding noncontrolling interests | 595 | (10) | $ 605 | ||
Cactus II Pipeline LLC | |||||
Partners Capital and Distribution [Line Items] | |||||
Additional interest acquired (as a percent) | 5% | ||||
Business combination, step acquisition, equity interest in acquiree, including subsequent acquisition (as a percent) | 70% | ||||
Partners’ capital, excluding noncontrolling interests | 526 | ||||
Cactus II Pipeline LLC | Noncontrolling Interests | |||||
Partners Capital and Distribution [Line Items] | |||||
Noncontrolling interest, increase from business combination | $ 526 | ||||
Partners’ capital, excluding noncontrolling interests | $ 526 | ||||
Oryx Midstream Holdings LLC | Plains Oryx Permian Basin LLC | Joint Venture Transaction | |||||
Partners Capital and Distribution [Line Items] | |||||
Partners’ capital, excluding noncontrolling interests | $ 3,230 | ||||
Plains Oryx Permian Basin LLC | |||||
Partners Capital and Distribution [Line Items] | |||||
Noncontrolling interest, ownership (as a percent) | 35% | ||||
Plains Oryx Permian Basin LLC | Oryx Midstream Holdings LLC | Joint Venture Transaction | |||||
Partners Capital and Distribution [Line Items] | |||||
Noncontrolling interest, ownership (as a percent) | 35% | ||||
Noncontrolling interest, ownership (as a parent) | 65% | ||||
Cactus II Pipeline LLC | |||||
Partners Capital and Distribution [Line Items] | |||||
Noncontrolling interest, ownership (as a percent) | 30% | ||||
Cactus II Pipeline LLC | Enbridge | |||||
Partners Capital and Distribution [Line Items] | |||||
Noncontrolling interest, ownership (as a percent) | 30% | ||||
Red River Pipeline Company LLC | |||||
Partners Capital and Distribution [Line Items] | |||||
Noncontrolling interest, ownership (as a percent) | 33% |
Partners' Capital and Distri_10
Partners' Capital and Distributions - Distributions to Noncontrolling Interests (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2022 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Partners Capital and Distribution [Line Items] | ||||
Distributions paid | $ 1,330 | $ 1,083 | $ 729 | |
Noncontrolling Interests | ||||
Partners Capital and Distribution [Line Items] | ||||
Distributions paid | 333 | 298 | 14 | |
Cash Distribution | Noncontrolling Interests | Consolidated Joint Venture Entities | ||||
Partners Capital and Distribution [Line Items] | ||||
Distributions paid | 333 | 298 | 14 | |
Cash Distribution | Noncontrolling Interests | Plains Oryx Permian Basin LLC | ||||
Partners Capital and Distribution [Line Items] | ||||
Distributions paid | $ 54 | 249 | 273 | |
Cash Distribution | Noncontrolling Interests | Cactus II Pipeline LLC | ||||
Partners Capital and Distribution [Line Items] | ||||
Distributions paid | 63 | 4 | ||
Cash Distribution | Noncontrolling Interests | Red River | ||||
Partners Capital and Distribution [Line Items] | ||||
Distributions paid | $ 21 | $ 21 | $ 14 |
Derivatives and Risk Manageme_3
Derivatives and Risk Management Activities - Commodity Price Risk Hedging (Details) bbl in Millions | 12 Months Ended |
Dec. 31, 2023 TWh bbl Bcf | |
Crude Oil Purchases | Long | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Bcf) | 6.3 |
Time Spread on Hedging Anticipated Crude Oil Lease Gathering Purchases | Short | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Bcf) | 5.6 |
Crude Oil Basis Spread Position | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Bcf) | 2.3 |
Anticipated Net Sales of Crude Oil and NGL Inventory | Short | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Bcf) | 18.2 |
Natural Gas Purchases for Processing and Operational Needs | Long | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Bcf) | Bcf | 78.2 |
Propane Contracts Related to Subsequent Sale of Products | Short | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Bcf) | 14.1 |
Butane Contracts Related to Subsequent Sale of Products | Short | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Bcf) | 2.5 |
Condensate Contracts Related to Subsequent Sale of Products | Short | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Bcf) | 3.1 |
Fuel Gas Requirements | Long | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Bcf) | Bcf | 7.1 |
Power Supply Requirements | Long | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in terawatt hours) | TWh | 2.4 |
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, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Impact of derivative activities recognized in earnings | |||
Total gain (loss) on derivatives recognized in net income | $ (32) | $ 238 | $ (639) |
Product sales revenues | |||
Impact of derivative activities recognized in earnings | |||
Total gain (loss) on derivatives recognized in net income | 13 | 179 | (710) |
Field operating costs | |||
Impact of derivative activities recognized in earnings | |||
Total gain (loss) on derivatives recognized in net income | $ (45) | $ 59 | $ 71 |
Derivatives and Risk Manageme_5
Derivatives and Risk Management Activities - Broker Receivable/Payable (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Derivative assets and liabilities | ||
Initial margin | $ 77 | $ 93 |
Variation margin returned | (65) | (236) |
Letters of credit | (205) | (102) |
Net broker payable | (13) | (168) |
Exchange Traded | ||
Derivative assets and liabilities | ||
Letters of credit | $ (25) | $ (25) |
Derivatives and Risk Manageme_6
Derivatives and Risk Management Activities - Offsetting Asset and Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Derivative Asset Positions | ||
Effect of Collateral Netting | $ (13) | $ (168) |
Commodity Derivatives | ||
Derivative Asset Positions | ||
Effect of Collateral Netting | (13) | (168) |
Derivative Liability Positions | ||
Gross Position - Asset | 158 | 311 |
Gross Position - Liability | (158) | (89) |
Net Carrying Value Presented on the Balance Sheet, Total | (13) | 54 |
Other current assets | Commodity Derivatives | ||
Derivative Asset Positions | ||
Gross Position - Asset | 153 | 300 |
Gross Position - Liability | (79) | (71) |
Effect of Collateral Netting | (13) | (168) |
Net Carrying Value Presented on the Balance Sheet | 61 | 61 |
Other long-term assets, net | Commodity Derivatives | ||
Derivative Asset Positions | ||
Gross Position - Asset | 3 | 9 |
Gross Position - Liability | (5) | |
Net Carrying Value Presented on the Balance Sheet | 3 | 4 |
Other current liabilities | Commodity Derivatives | ||
Derivative Liability Positions | ||
Gross Position - Asset | 1 | 2 |
Gross Position - Liability | (64) | (13) |
Net Carrying Value Presentation on the Balance Sheet | (63) | (11) |
Other long-term liabilities and deferred credits | Commodity Derivatives | ||
Derivative Liability Positions | ||
Gross Position - Asset | 1 | 0 |
Gross Position - Liability | (15) | 0 |
Net Carrying Value Presentation on the Balance Sheet | $ (14) | $ 0 |
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, 2023 USD ($) contract | |
8 forward starting swaps (30-year), 3.09% | |
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) | 3.09% |
4 forward starting swaps (30-year), 0.74% | |
Interest Rate Derivatives [Abstract] | |
Number of interest rate derivatives | contract | 4 |
Term of derivative contract | 30 years |
Notional amount of derivatives | $ | $ 100 |
Average rate locked (percent) | 0.74% |
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, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Derivatives, Fair Value [Line Items] | |||
Proceeds from settlement of interest rate hedging instruments | $ 80 | $ 42 | |
Other current assets | |||
Derivatives, Fair Value [Line Items] | |||
Interest Rate Cash Flow Hedge Derivative at Fair Value, Net | 51 | 75 | |
Other long-term assets, net | |||
Derivatives, Fair Value [Line Items] | |||
Interest Rate Cash Flow Hedge Derivative at Fair Value, Net | 4 | 45 | |
Interest Rate Swap Terminated | Cash Flow Hedging | |||
Derivatives, Fair Value [Line Items] | |||
Notional amount of derivatives | 200 | ||
Proceeds from settlement of interest rate hedging instruments | 80 | ||
Interest Rate Derivatives | |||
Derivatives, Fair Value [Line Items] | |||
Interest rate derivatives, net | 15 | $ 94 | $ 19 |
AOCI Cash Flow Hedge | |||
Derivatives, Fair Value [Line Items] | |||
Net gain/(loss) deferred in AOCI | (81) | ||
AOCI Cash Flow Hedge | Interest Rate Swap Terminated | Cash Flow Hedging | |||
Derivatives, Fair Value [Line Items] | |||
Net gain/(loss) deferred in AOCI | $ 73 |
Derivatives and Risk Manageme_9
Derivatives and Risk Management Activities - Preferred Distribution Rate (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Jan. 31, 2023 | |
Derivatives and Risk Management Activities | ||||
Gain/(loss) recognized | $ 58 | $ (189) | $ 14 | |
Preferred Distribution Rate Reset Option | Derivatives Not Designated as a Hedge | ||||
Derivatives and Risk Management Activities | ||||
Derivative liability | $ 189 | $ 131 | ||
Derivative liability, statement of financial position [extensible enumeration] | Other long-term liabilities and deferred credits | |||
Preferred Distribution Rate Reset Option | Derivatives Not Designated as a Hedge | Other Income/(Expense), Net | ||||
Derivatives and Risk Management Activities | ||||
Gain/(loss) recognized | $ 58 | $ (189) | $ 14 |
Derivatives and Risk Managem_10
Derivatives and Risk Management Activities - Fair Value (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Level 3 | ||
Rollforward of Level 3 Net Asset/(Liability) | ||
Beginning Balance | $ (189) | $ (2) |
Net gains/(losses) for the period included in earnings | $ 58 | $ (189) |
Net gains/(losses) for the period included in earnings [Extensible Enumeration] | Total revenues | Total revenues |
Settlements | $ 131 | $ 2 |
Ending Balance | (189) | |
Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period | $ (189) | |
Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period [Extensible Enumeration] | Other income/(expense), net | Other income/(expense), net |
Recurring Fair Value Measures | ||
Recurring Fair Value Measurements | ||
Total net derivative asset/(liability) | $ 55 | $ 153 |
Recurring Fair Value Measures | Commodity Derivatives | ||
Recurring Fair Value Measurements | ||
Total net derivative asset/(liability) | 222 | |
Recurring Fair Value Measures | Interest Rate Derivatives | ||
Recurring Fair Value Measurements | ||
Total net derivative asset/(liability) | 55 | 120 |
Recurring Fair Value Measures | Preferred Distribution Rate Reset Option | ||
Recurring Fair Value Measurements | ||
Total net derivative asset/(liability) | (189) | |
Recurring Fair Value Measures | Level 1 | ||
Recurring Fair Value Measurements | ||
Total net derivative asset/(liability) | 9 | (7) |
Recurring Fair Value Measures | Level 1 | Commodity Derivatives | ||
Recurring Fair Value Measurements | ||
Total net derivative asset/(liability) | 9 | (7) |
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) | 46 | 349 |
Recurring Fair Value Measures | Level 2 | Commodity Derivatives | ||
Recurring Fair Value Measurements | ||
Total net derivative asset/(liability) | (9) | 229 |
Recurring Fair Value Measures | Level 2 | Interest Rate Derivatives | ||
Recurring Fair Value Measurements | ||
Total net derivative asset/(liability) | 55 | 120 |
Recurring Fair Value Measures | Level 2 | Preferred Distribution Rate Reset Option | ||
Recurring Fair Value Measurements | ||
Total net derivative asset/(liability) | 0 | 0 |
Recurring Fair Value Measures | Level 3 | ||
Recurring Fair Value Measurements | ||
Total net derivative asset/(liability) | (189) | |
Recurring Fair Value Measures | Level 3 | Commodity Derivatives | ||
Recurring Fair Value Measurements | ||
Total net derivative asset/(liability) | 0 | 0 |
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) | $ (189) |
Leases - Narrative (Details)
Leases - Narrative (Details) | 12 Months Ended |
Dec. 31, 2023 | |
Minimum | |
Lessee, Lease, Description [Line Items] | |
Lessee, leases, term of contract (in years) | 1 year |
Lessee, leases, renewal term (in years) | 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 (in years) | 57 years |
Lessee, leases, renewal term (in years) | 25 years |
Lessor, Lease, Description [Line Items] | |
Lessor, operating lease, term of contract | 18 years |
Equity Method Investees | Agreement to Store at Facilities Owned by Equity Method Investee | Equity Method Investee That Owns Leased Storage Tanks | |
Lessee, Lease, Description [Line Items] | |
Ownership interest in unconsolidated entity (as a percent) | 50% |
Leases - Lease Costs (Details)
Leases - Lease Costs (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Leases [Abstract] | |||
Operating lease cost | $ 86 | $ 91 | $ 96 |
Short-term lease cost | 15 | 18 | 19 |
Other | 8 | 15 | 14 |
Total lease cost | $ 109 | $ 124 | $ 129 |
Leases - Other Information (Det
Leases - Other Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Leases [Abstract] | |||
Operating cash flows for operating leases | $ 81 | $ 92 | $ 91 |
Operating cash flows for finance leases | 6 | 6 | 7 |
Financing cash flows for finance leases | 11 | 12 | 11 |
Non-cash change in lease liabilities arising from obtaining new right of use assets or modifications, operating leases | 32 | 43 | 94 |
Non-cash change in lease liabilities arising from obtaining new right of use assets or modifications, finance leases | $ 27 | $ 2 | $ 1 |
Weighted-average remaining lease term (in years): | |||
Operating lease, weighted-average lease term | 13 years | 12 years | |
Finance lease, weighted-average lease term | 8 years | 9 years | |
Weighted-average discount rate: | |||
Operating lease, weighted-average discount rate | 4.90% | 4.30% | |
Finance lease, weighted-average discount rate | 11.30% | 12.30% |
Leases - Assets and Liabilities
Leases - Assets and Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Lessee, Lease, Assets and Liabilities [Line Items] | ||
Long-term operating lease right-of-use assets, net | $ 313 | $ 349 |
Finance lease right-of-use assets, gross | 144 | 124 |
Finance lease right-of-use assets, accumulated depreciation | (46) | (41) |
Finance lease right-of-use assets, net | $ 98 | $ 83 |
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 | $ 411 | $ 432 |
Operating lease liabilities | ||
Operating lease liabilities, current | $ 69 | $ 71 |
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration] | Other current liabilities | Other current liabilities |
Long-term operating lease liabilities | $ 274 | $ 308 |
Total operating lease liabilities | 343 | 379 |
Finance lease liabilities | ||
Finance lease liabilities, current | $ 13 | $ 10 |
Finance Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration] | Short-term debt | Short-term debt |
Finance lease liabilities, noncurrent | $ 63 | $ 50 |
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration] | Other long-term debt, net | Other long-term debt, net |
Total finance lease liabilities | $ 76 | $ 60 |
Total lease liabilities | 419 | 439 |
Equity Method Investees | Agreement to Store at Facilities Owned by Equity Method Investee | Equity Method Investee That Owns Leased Storage Tanks | ||
Lessee, Lease, Assets and Liabilities [Line Items] | ||
Finance lease right-of-use assets, net | 28 | 30 |
Finance lease liabilities | ||
Total finance lease liabilities | $ 34 | $ 35 |
Ownership interest in unconsolidated entity (as a percent) | 50% |
Leases - Maturity of Lease Liab
Leases - Maturity of Lease Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Operating | ||
2024 | $ 80 | |
2025 | 68 | |
2026 | 51 | |
2027 | 43 | |
2028 | 34 | |
Thereafter | 238 | |
Total | 514 | |
Less: Present value discount | (171) | |
Lease liabilities | 343 | $ 379 |
Finance | ||
2024 | 20 | |
2025 | 17 | |
2026 | 13 | |
2027 | 12 | |
2028 | 15 | |
Thereafter | 48 | |
Total | 125 | |
Less: Present value discount | (49) | |
Lease liabilities | 76 | 60 |
Equity Method Investees | Agreement to Store at Facilities Owned by Equity Method Investee | Equity Method Investee That Owns Leased Storage Tanks | ||
Finance | ||
2024 | 6 | |
2025 | 6 | |
2026 | 6 | |
2027 | 6 | |
2028 | 6 | |
Thereafter | 45 | |
Lease liabilities | $ 34 | $ 35 |
Ownership interest in unconsolidated entity (as a percent) | 50% |
Leases - Lessor Operating Lease
Leases - Lessor Operating Lease Revenue (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Lessor, Lease, Description [Line Items] | |||
Operating lease revenue | $ 32 | $ 29 | $ 28 |
Services | |||
Lessor, Lease, Description [Line Items] | |||
Operating lease, lease income, statement of income [extensible enumeration] | Total revenues | Total revenues | Total revenues |
Leases - Lessor Future Minimum
Leases - Lessor Future Minimum Lease Revenue (Details) $ in Millions | Dec. 31, 2023 USD ($) |
Leases [Abstract] | |
2024 | $ 24 |
2025 | 18 |
2026 | 15 |
2027 | 16 |
2028 | 16 |
Thereafter | $ 154 |
Income Taxes - Components (Deta
Income Taxes - Components (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Current income tax expense: | |||
State income tax | $ 2 | $ 1 | $ 2 |
Canadian federal and provincial income tax | 143 | 83 | 48 |
Total current income tax expense | 145 | 84 | 50 |
Deferred income tax expense/(benefit): | |||
Canadian federal and provincial income tax | (24) | 105 | 23 |
Total deferred income tax expense/(benefit) | (24) | 105 | 23 |
Total income tax expense | $ 121 | $ 189 | $ 73 |
Income Taxes - Reconciliation a
Income Taxes - Reconciliation and Deferred Tax Assets (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Income Tax Examination [Line Items] | |||
Income before tax | $ 1,623 | $ 1,417 | $ 721 |
Partnership earnings not subject to Canadian tax | (1,136) | (686) | (370) |
Partnership earnings subject to Canadian tax | $ 487 | $ 731 | $ 351 |
Canadian federal and provincial corporate tax rate | 24% | 24% | 24% |
Income tax expense at statutory rate | $ 117 | $ 175 | $ 84 |
Canadian permanent differences | 2 | 13 | (13) |
State income tax | 2 | 1 | 2 |
Total income tax expense | 121 | 189 | $ 73 |
Deferred tax assets: | |||
Lease liabilities | 40 | 45 | |
Other | 45 | 16 | |
Total deferred tax assets | 85 | 61 | |
Deferred tax liabilities: | |||
Property and equipment in excess of tax values | (573) | (515) | |
Derivative instruments | (6) | (46) | |
Lease assets | (38) | (42) | |
Other | (3) | (3) | |
Total deferred tax liabilities | (620) | (606) | |
Net deferred tax liabilities | (535) | (545) | |
Other long-term liabilities and deferred credits | |||
Deferred tax liabilities: | |||
Other long-term liabilities and deferred credits | $ (535) | $ (545) |
Income Taxes - Narrative (Detai
Income Taxes - Narrative (Details) - Canadian Tax Authorities - Foreign $ in Millions | Dec. 31, 2023 USD ($) |
Income Tax Examination [Line Items] | |
Amount of assessments received, including penalty and interest | $ 165 |
Other long-term assets, net | |
Income Tax Examination [Line Items] | |
Amount of disputed assessments paid | $ 87 |
Major Customers and Concentra_2
Major Customers and Concentration of Credit Risk (Details) - Revenues - Customer Concentration Risk | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
ExxonMobil Corporation | |||
Major Customers and Concentration of Credit Risk | |||
Major customer percentage of total revenue (as a percent) | 26% | 20% | 15% |
BP p.l.c and subsidiaries | |||
Major Customers and Concentration of Credit Risk | |||
Major customer percentage of total revenue (as a percent) | 10% | 10% | |
Marathon Petroleum Corporation | |||
Major Customers and Concentration of Credit Risk | |||
Major customer percentage of total revenue (as a percent) | 12% |
Related Party Transactions - Na
Related Party Transactions - Narrative (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
GP | |||
Related Party Transactions | |||
Costs reimbursed to general partner | $ 546 | $ 476 | $ 467 |
Principal Owner | AAP | Minimum | |||
Related Party Transactions | |||
Ownership interest (as a percent) | 10% | ||
Class C Shares | PAGP | |||
Related Party Transactions | |||
Ownership interest (in units) | 539,445,289 | 528,442,538 |
Related Party Transactions - Pr
Related Party Transactions - Promissory Notes with our General Partner (Details) $ in Millions, $ in Millions | 10 Months Ended | 12 Months Ended | |||
Dec. 31, 2023 USD ($) | Dec. 31, 2023 USD ($) | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | Dec. 31, 2023 CAD ($) | |
Related Party Transactions | |||||
Related party interest expense | $ 386 | $ 405 | $ 425 | ||
8.25% note due April 2027 | PAGP | GP | |||||
Related Party Transactions | |||||
Related party note receivable | $ 379 | 379 | $ 500 | ||
Related party note payable | $ 379 | 379 | $ 500 | ||
Related party note payable and receivable interest rate (as a percent) | 8.25% | ||||
Related party interest receivable | $ 10 | 10 | |||
Related party interest payable | $ 10 | 10 | |||
Related party interest income | 25 | ||||
Related party interest expense | $ 25 |
Related Party Transactions - Tr
Related Party Transactions - Transactions with Other Related Parties (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Related Party Transactions | |||
Revenues from related parties | $ 48,712 | $ 57,342 | $ 42,078 |
Purchases and related costs from related parties | 404 | 365 | 385 |
Trade accounts receivable and other receivables, net from related parties | 3,760 | 3,907 | |
Trade accounts payable to related parties | 3,844 | 4,044 | |
Affiliated Entity | |||
Related Party Transactions | |||
Revenues from related parties | 48 | 45 | $ 33 |
Trade accounts receivable and other receivables, net from related parties | 63 | 45 | |
Trade accounts payable to related parties | $ 72 | $ 79 |
Equity-Indexed Compensation P_3
Equity-Indexed Compensation Plans (Details) shares in Millions, $ in Millions | Dec. 31, 2023 USD ($) shares |
Equity-Indexed Compensation Plans | |
LTIP awards authorized (in units) | 43.5 |
LTIP awards available (in units) | 17.4 |
LTIP awards outstanding (in units) | 12.2 |
LTIP awards outstanding including DERs (in units) | 9.6 |
Probable vesting, unrecognized fair value | $ | $ 73 |
Plains All American 2021 Long-Term Incentive Plan | |
Equity-Indexed Compensation Plans | |
LTIP awards authorized (in units) | 28.8 |
Plains All American PNG Successor Long-Term Incentive Plan | |
Equity-Indexed Compensation Plans | |
LTIP awards authorized (in units) | 1.3 |
Plains All American GP LLC 2006 Long-Term Incentive Tracking Unit Plan | |
Equity-Indexed Compensation Plans | |
LTIP awards authorized (in units) | 13.4 |
Commitments and Contingencies -
Commitments and Contingencies - Commitments (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Leases | |||
2024 | $ 100 | ||
2025 | 85 | ||
2026 | 64 | ||
2027 | 55 | ||
2028 | 49 | ||
Thereafter | 286 | ||
Total | 639 | ||
Other commitments | |||
2024 | 367 | ||
2025 | 336 | ||
2026 | 249 | ||
2027 | 217 | ||
2028 | 117 | ||
Thereafter | 425 | ||
Total | 1,711 | ||
Total | |||
2024 | 467 | ||
2025 | 421 | ||
2026 | 313 | ||
2027 | 272 | ||
2028 | 166 | ||
Thereafter | 711 | ||
Total | 2,350 | ||
Expenses associated with agreements | $ 396 | $ 336 | $ 270 |
Commitments and Contingencies_2
Commitments and Contingencies - Legal, Environmental or Regulatory (Details) | 1 Months Ended | 9 Months Ended | 12 Months Ended | 14 Months Ended | 104 Months Ended | |||||||
Oct. 27, 2022 USD ($) | Oct. 14, 2020 USD ($) | Sep. 30, 2021 USD ($) | May 31, 2015 bbl | Sep. 20, 2022 USD ($) | Dec. 31, 2023 USD ($) | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | Dec. 31, 2023 USD ($) | Dec. 31, 2023 USD ($) | Apr. 25, 2019 USD ($) | Sep. 07, 2018 count | |
Line 901 Incident | ||||||||||||
Legal, Environmental or Regulatory Matters | ||||||||||||
Estimated size of release (in bbl) | bbl | 2,934 | |||||||||||
Estimated size of release to reach Pacific Ocean (in bbl) | bbl | 598 | |||||||||||
Recoveries from insurance carriers | $ 280,000,000 | |||||||||||
Aggregate total estimated costs | $ 750,000,000 | $ 750,000,000 | 750,000,000 | |||||||||
Significant costs related to legal and environmental remediation matters | 10,000,000 | $ 95,000,000 | $ 15,000,000 | |||||||||
Total release costs probable of recovery | 505,000,000 | 505,000,000 | 505,000,000 | |||||||||
Line 901 Incident | Civil Penalties | Judicial Ruling | ||||||||||||
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 | Judicial Ruling | ||||||||||||
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 | |||||||||||
Line 901 Incident | May 2016 Indictment | Judicial Ruling | ||||||||||||
Legal, Environmental or Regulatory Matters | ||||||||||||
Fines or penalties assessed | $ 3,350,000 | |||||||||||
Line 901 Incident | May 2016 Indictment | Maximum | Judicial Ruling | ||||||||||||
Legal, Environmental or Regulatory Matters | ||||||||||||
Amount awarded to claimants by court | $ 150,000 | |||||||||||
Line 901 Incident | Class Action Lawsuit Claim of Damages | Pending Litigation | ||||||||||||
Legal, Environmental or Regulatory Matters | ||||||||||||
Litigation settlement agreement amount, subject to approval | $ 230,000,000 | |||||||||||
Line 901 Incident | Class Action Lawsuit Claim of Damages | Settled Litigation | ||||||||||||
Legal, Environmental or Regulatory Matters | ||||||||||||
Payments for legal settlements | $ 230,000,000 | |||||||||||
Line 901 2015 Insurance Program | ||||||||||||
Legal, Environmental or Regulatory Matters | ||||||||||||
Recoveries from insurance carriers | 275,000,000 | |||||||||||
Coverage limit under insurance program | 500,000,000 | 500,000,000 | 500,000,000 | |||||||||
Exceeded coverage limit under insurance program | 250,000,000 | 250,000,000 | 250,000,000 | |||||||||
Claim for Reimbursement From Insurance | ||||||||||||
Legal, Environmental or Regulatory Matters | ||||||||||||
Recoveries from insurance carriers | 3,600,000 | |||||||||||
Receivable for remaining portion of release costs probable of recovery from insurance | 225,000,000 | 225,000,000 | 225,000,000 | |||||||||
Denial of Insurance Coverage | ||||||||||||
Legal, Environmental or Regulatory Matters | ||||||||||||
Receivable for remaining portion of release costs probable of recovery from insurance | 185,000,000 | 185,000,000 | 185,000,000 | |||||||||
Response to Request for Reimbursement Not Received | ||||||||||||
Legal, Environmental or Regulatory Matters | ||||||||||||
Receivable for remaining portion of release costs probable of recovery from insurance | 40,000,000 | 40,000,000 | 40,000,000 | |||||||||
Arbitration Proceedings Against Insurers | ||||||||||||
Legal, Environmental or Regulatory Matters | ||||||||||||
Receivable for remaining portion of release costs probable of recovery from insurance | 175,000,000 | 175,000,000 | 175,000,000 | |||||||||
Other long-term assets, net | Line 901 Incident | ||||||||||||
Legal, Environmental or Regulatory Matters | ||||||||||||
Receivable for remaining portion of release costs probable of recovery from insurance | 225,000,000 | 225,000,000 | 225,000,000 | |||||||||
Current liabilities | Line 901 Incident | ||||||||||||
Legal, Environmental or Regulatory Matters | ||||||||||||
Remaining undiscounted liability | 94,000,000 | 105,000,000 | 94,000,000 | 94,000,000 | ||||||||
Excluding Line 901 Incident | ||||||||||||
Legal, Environmental or Regulatory Matters | ||||||||||||
Estimated undiscounted reserve for environmental liabilities | 56,000,000 | 55,000,000 | 56,000,000 | 56,000,000 | ||||||||
Estimated undiscounted reserve for environmental liabilities, short-term | $ 10,000,000 | $ 10,000,000 | $ 10,000,000 | $ 10,000,000 | ||||||||
Estimated undiscounted reserve for environmental liabilities, short-term [Extensible Enumeration] | Other current liabilities | Other current liabilities | Other current liabilities | Other current liabilities | ||||||||
Estimated undiscounted reserve for environmental liabilities, long-term | $ 46,000,000 | $ 45,000,000 | $ 46,000,000 | $ 46,000,000 | ||||||||
Estimated undiscounted reserve for environmental liabilities, long-term [Extensible Enumeration] | Other long-term liabilities and deferred credits | Other long-term liabilities and deferred credits | Other long-term liabilities and deferred credits | Other long-term liabilities and deferred credits | ||||||||
Amounts probable of recovery under insurance and from third parties under indemnification agreements | $ 4,000,000 | $ 4,000,000 | $ 4,000,000 | $ 4,000,000 | ||||||||
Excluding Line 901 Incident | 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 | $ 1,000,000 | $ 1,000,000 |
Segment Information - Segment F
Segment Information - Segment Financial Data (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Revenue | |||
Revenues | $ 48,712 | $ 57,342 | $ 42,078 |
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments | |||
Equity earnings in unconsolidated entities | 369 | 403 | 274 |
Segment Adjusted EBITDA | 2,685 | 2,504 | 2,194 |
Investment and acquisition capital expenditures | 830 | 618 | 269 |
Maintenance capital expenditures | 231 | 211 | 168 |
Investments in unconsolidated entities | 2,820 | 3,084 | 3,805 |
Product sales revenues | |||
Revenue | |||
Revenues | 46,974 | 55,948 | 40,883 |
Services | |||
Revenue | |||
Revenues | 1,738 | 1,394 | 1,195 |
Operating Segments | |||
Revenue | |||
Revenues | 49,109 | 57,841 | 42,438 |
Intersegment Revenues Elimination | |||
Revenue | |||
Revenues | (397) | (499) | (360) |
Intersegment Revenues Elimination | Product sales revenues | |||
Revenue | |||
Revenues | (378) | (467) | (341) |
Intersegment Revenues Elimination | Services | |||
Revenue | |||
Revenues | (19) | (32) | (19) |
Crude Oil | |||
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments | |||
Equity earnings in unconsolidated entities | 369 | 403 | 274 |
Segment Adjusted EBITDA | 2,163 | 1,986 | 1,909 |
Investment and acquisition capital expenditures | 765 | 461 | 212 |
Maintenance capital expenditures | 145 | 112 | 100 |
Investments in unconsolidated entities | 2,820 | 3,084 | 3,805 |
Crude Oil | Operating Segments | |||
Revenue | |||
Revenues | 47,174 | 55,080 | 40,470 |
Crude Oil | Operating Segments | Product sales revenues | |||
Revenue | |||
Revenues | 45,587 | 53,840 | 39,395 |
Crude Oil | Operating Segments | Services | |||
Revenue | |||
Revenues | 1,587 | 1,240 | 1,075 |
NGL | |||
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments | |||
Segment Adjusted EBITDA | 522 | 518 | 285 |
Investment and acquisition capital expenditures | 65 | 157 | 57 |
Maintenance capital expenditures | 86 | 99 | 68 |
NGL | Operating Segments | |||
Revenue | |||
Revenues | 1,935 | 2,761 | 1,968 |
NGL | Operating Segments | Product sales revenues | |||
Revenue | |||
Revenues | 1,765 | 2,575 | 1,829 |
NGL | Operating Segments | Services | |||
Revenue | |||
Revenues | $ 170 | $ 186 | $ 139 |
Segment Information - Reconcili
Segment Information - Reconciliation of Segment Adjusted EBITDA (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items] | |||
Segment Adjusted EBITDA | $ 2,685 | $ 2,504 | $ 2,194 |
Adjustments: | |||
Depreciation and amortization of unconsolidated entities | (87) | (85) | (123) |
Derivative activities and inventory valuation adjustments | (159) | 280 | 271 |
Long-term inventory costing adjustments | (35) | 4 | 94 |
Deficiencies under minimum volume commitments, net | (12) | (7) | 7 |
Equity-indexed compensation expense | (36) | (32) | (19) |
Foreign currency revaluation | (24) | (4) | 4 |
Transaction-related expenses | (1) | (16) | |
Segment amounts attributable to noncontrolling interests | 454 | 364 | 94 |
Depreciation and amortization | (1,048) | (965) | (774) |
Gains/(losses) on asset sales and asset impairments, net | 152 | (269) | (592) |
Gains/(losses) on investments in unconsolidated entities, net | 28 | 346 | 2 |
Interest expense, net | (386) | (405) | (425) |
Other income/(expense), net | 102 | (219) | 19 |
INCOME BEFORE TAX | 1,623 | 1,417 | 721 |
Income tax expense | (121) | (189) | (73) |
NET INCOME | 1,502 | 1,228 | 648 |
Net income attributable to noncontrolling interests | (272) | (191) | (55) |
NET INCOME ATTRIBUTABLE TO PAA | 1,230 | 1,037 | 593 |
Line 901 Incident | |||
Adjustments: | |||
Line 901 incident | $ (10) | $ (95) | $ (15) |
Segment Information - Geographi
Segment Information - Geographic Data (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Geographic Data | |||
Revenues | $ 48,712 | $ 57,342 | $ 42,078 |
Long-lived assets | 22,411 | 22,457 | |
United States | |||
Geographic Data | |||
Revenues | 42,308 | 46,903 | 34,458 |
Long-lived assets | 18,591 | 18,655 | |
Canada | |||
Geographic Data | |||
Revenues | 6,404 | 10,439 | $ 7,620 |
Long-lived assets | $ 3,820 | $ 3,802 |