Cover Page
Cover Page - shares | 6 Months Ended | |
Jun. 30, 2023 | Jul. 31, 2023 | |
Cover [Abstract] | ||
Document Type | 10-Q | |
Document Quarterly Report | true | |
Document Period End Date | Jun. 30, 2023 | |
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 Current Reporting Status | Yes | |
Entity Interactive Data Current | Yes | |
Entity Filer Category | Large Accelerated Filer | |
Small Business Entity | false | |
Emerging Growth Company | false | |
Entity Shell Company | false | |
Entity Common Stock, Shares Outstanding (units) | 698,390,006 | |
Entity Central Index Key | 0001070423 | |
Amendment Flag | false | |
Current Fiscal Year End Date | --12-31 | |
Document Fiscal Year Focus | 2023 | |
Document Fiscal Period Focus | Q2 |
CONDENSED CONSOLIDATED BALANCE
CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Jun. 30, 2023 | Dec. 31, 2022 |
CURRENT ASSETS | ||
Cash and cash equivalents | $ 933 | $ 401 |
Trade accounts receivable and other receivables, net | 3,220 | 3,907 |
Inventory | 367 | 729 |
Other current assets | 137 | 318 |
Total current assets | 4,657 | 5,355 |
PROPERTY AND EQUIPMENT | 20,362 | 20,020 |
Accumulated depreciation | (5,141) | (4,770) |
Property and equipment, net | 15,221 | 15,250 |
OTHER ASSETS | ||
Investments in unconsolidated entities | 3,062 | 3,084 |
Intangible assets, net | 1,999 | 2,145 |
Linefill | 966 | 961 |
Long-term operating lease right-of-use assets, net | 339 | 349 |
Long-term inventory | 270 | 284 |
Other long-term assets, net | 386 | 464 |
Total assets | 26,900 | 27,892 |
CURRENT LIABILITIES | ||
Trade accounts payable | 3,295 | 4,044 |
Short-term debt | 709 | 1,159 |
Other current liabilities | 648 | 688 |
Total current liabilities | 4,652 | 5,891 |
LONG-TERM LIABILITIES | ||
Senior notes, net | 7,239 | 7,237 |
Other long-term debt, net | 49 | 50 |
Long-term operating lease liabilities | 299 | 308 |
Other long-term liabilities and deferred credits | 1,059 | 1,081 |
Total long-term liabilities | 8,646 | 8,676 |
COMMITMENTS AND CONTINGENCIES (NOTE 9) | ||
PARTNERS’ CAPITAL | ||
Total partners’ capital excluding noncontrolling interests | 10,379 | 10,057 |
Noncontrolling interests | 3,223 | 3,268 |
Total partners’ capital | 13,602 | 13,325 |
Total liabilities and partners’ capital | 26,900 | 27,892 |
Series A Preferred Units | ||
PARTNERS’ CAPITAL | ||
Partners' capital | 1,507 | 1,505 |
Series B Preferred Units | ||
PARTNERS’ CAPITAL | ||
Partners' capital | 787 | 787 |
Common Units | ||
PARTNERS’ CAPITAL | ||
Partners' capital | $ 8,085 | $ 7,765 |
CONDENSED CONSOLIDATED BALANC_2
CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares | Jun. 30, 2023 | Mar. 31, 2023 | Dec. 31, 2022 | Jun. 30, 2022 | Mar. 31, 2022 | Dec. 31, 2021 |
Series A Preferred Units | ||||||
Units outstanding (units) | 71,090,468 | 71,090,468 | 71,090,468 | 71,090,468 | 71,090,468 | 71,090,468 |
Series B Preferred Units | ||||||
Units outstanding (units) | 800,000 | 800,000 | 800,000 | 800,000 | 800,000 | 800,000 |
Common Units | ||||||
Units outstanding (units) | 698,390,006 | 698,390,006 | 698,354,498 | 697,939,946 | 702,668,178 | 704,991,540 |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2023 | Jun. 30, 2022 | Jun. 30, 2023 | Jun. 30, 2022 | |
REVENUES | ||||
Total revenues | $ 11,602 | $ 16,359 | $ 23,943 | $ 30,053 |
COSTS AND EXPENSES | ||||
Purchases and related costs | 10,544 | 15,324 | 21,867 | 28,109 |
Field operating costs | 333 | 307 | 690 | 653 |
General and administrative expenses | 85 | 78 | 171 | 160 |
Depreciation and amortization | 259 | 242 | 515 | 473 |
(Gains)/losses on asset sales and asset impairments, net | 3 | (3) | (150) | (46) |
Total costs and expenses | 11,224 | 15,948 | 23,093 | 29,349 |
OPERATING INCOME | 378 | 411 | 850 | 704 |
OTHER INCOME/(EXPENSE) | ||||
Equity earnings in unconsolidated entities | 89 | 104 | 178 | 201 |
Interest expense (net of capitalized interest of $3, $1, $5, and $2, respectively) | (95) | (99) | (193) | (206) |
Other income/(expense), net | 20 | (118) | 85 | (155) |
INCOME BEFORE TAX | 392 | 298 | 920 | 544 |
Current income tax expense | (20) | (30) | (81) | (48) |
Deferred income tax expense | (23) | (17) | (15) | (20) |
NET INCOME | 349 | 251 | 824 | 476 |
Net income attributable to noncontrolling interests | (56) | (48) | (109) | (86) |
NET INCOME ATTRIBUTABLE TO PAA | 293 | 203 | 715 | 390 |
NET INCOME PER COMMON UNIT (NOTE 3): | ||||
Net income allocated to common unitholders - Basic | 227 | 153 | 588 | 290 |
Net income allocated to common unitholders - Diluted | $ 227 | $ 153 | $ 588 | $ 290 |
Common Units | ||||
NET INCOME PER COMMON UNIT (NOTE 3): | ||||
Basic weighted average common units outstanding (units) | 698 | 702 | 698 | 703 |
Diluted weighted average common units outstanding (units) | 698 | 702 | 698 | 703 |
Basic net income per common unit (usd per unit) | $ 0.32 | $ 0.22 | $ 0.84 | $ 0.41 |
Diluted net income per common unit (usd per unit) | $ 0.32 | $ 0.22 | $ 0.84 | $ 0.41 |
Product sales revenues | ||||
REVENUES | ||||
Total revenues | $ 11,201 | $ 16,007 | $ 23,145 | $ 29,388 |
Services revenues | ||||
REVENUES | ||||
Total revenues | $ 401 | $ 352 | $ 798 | $ 665 |
CONDENSED CONSOLIDATED STATEM_2
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2023 | Jun. 30, 2022 | Jun. 30, 2023 | Jun. 30, 2022 | |
Income Statement [Abstract] | ||||
Interest expense, capitalized interest | $ 3 | $ 1 | $ 5 | $ 2 |
CONDENSED CONSOLIDATED STATEM_3
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2023 | Jun. 30, 2022 | Jun. 30, 2023 | Jun. 30, 2022 | |
Statement of Comprehensive Income [Abstract] | ||||
Net income | $ 349 | $ 251 | $ 824 | $ 476 |
Other comprehensive income/(loss) | 85 | (52) | 85 | 22 |
Comprehensive income | 434 | 199 | 909 | 498 |
Comprehensive income attributable to noncontrolling interests | (56) | (48) | (109) | (86) |
Comprehensive income attributable to PAA | $ 378 | $ 151 | $ 800 | $ 412 |
CONDENSED CONSOLIDATED STATEM_4
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2023 | Jun. 30, 2022 | Jun. 30, 2023 | Jun. 30, 2022 | |
Changes in Accumulated Other Comprehensive Income/(Loss) | ||||
Beginning balance | $ 13,483 | $ 12,854 | $ 13,325 | $ 12,810 |
Total period activity | 85 | (52) | 85 | 22 |
Ending balance | 13,602 | 12,719 | 13,602 | 12,719 |
Derivative Instruments | ||||
Changes in Accumulated Other Comprehensive Income/(Loss) | ||||
Beginning balance | (107) | (208) | ||
Reclassification adjustments | 5 | 6 | ||
Unrealized gain on hedges | 2 | 68 | ||
Total period activity | 7 | 74 | ||
Ending balance | (100) | (134) | (100) | (134) |
Translation Adjustments | ||||
Changes in Accumulated Other Comprehensive Income/(Loss) | ||||
Beginning balance | (846) | (642) | ||
Currency translation adjustments | 77 | (50) | ||
Total period activity | 77 | (50) | ||
Ending balance | (769) | (692) | (769) | (692) |
Other | ||||
Changes in Accumulated Other Comprehensive Income/(Loss) | ||||
Beginning balance | (1) | (3) | ||
Other | 1 | (2) | ||
Total period activity | 1 | (2) | ||
Ending balance | (5) | (5) | ||
Total | ||||
Changes in Accumulated Other Comprehensive Income/(Loss) | ||||
Beginning balance | (954) | (853) | ||
Reclassification adjustments | 5 | 6 | ||
Unrealized gain on hedges | 2 | 68 | ||
Currency translation adjustments | 77 | (50) | ||
Other | 1 | (2) | ||
Total period activity | 85 | 22 | ||
Ending balance | $ (869) | $ (831) | $ (869) | $ (831) |
CONDENSED CONSOLIDATED STATEM_5
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions | 6 Months Ended | |
Jun. 30, 2023 | Jun. 30, 2022 | |
CASH FLOWS FROM OPERATING ACTIVITIES | ||
Net income | $ 824 | $ 476 |
Reconciliation of net income to net cash provided by operating activities: | ||
Depreciation and amortization | 515 | 473 |
Gains on asset sales and asset impairments, net | (150) | (46) |
Deferred income tax expense | 15 | 20 |
Gains on sales of linefill | (2) | (30) |
Loss on foreign currency revaluation | 1 | 10 |
Settlement of terminated interest rate hedging instruments (Note 7) | 80 | |
Change in fair value of Preferred Distribution Rate Reset Option (Note 7) | (58) | 147 |
Equity earnings in unconsolidated entities | (178) | (201) |
Distributions on earnings from unconsolidated entities | 219 | 224 |
Other | 36 | 27 |
Changes in assets and liabilities, net of acquisitions | 329 | 32 |
Net cash provided by operating activities | 1,631 | 1,132 |
CASH FLOWS FROM INVESTING ACTIVITIES | ||
Investments in unconsolidated entities | (19) | (4) |
Additions to property, equipment and other | (267) | (190) |
Cash paid for purchases of linefill | (14) | (60) |
Proceeds from sales of assets | 284 | 57 |
Cash received from sales of linefill | 9 | 61 |
Other investing activities | 1 | 13 |
Net cash used in investing activities | (6) | (123) |
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Net borrowings under commercial paper program (Note 5) | 115 | |
Repayments of senior notes (Note 5) | (400) | (750) |
Repurchase of common units | (74) | |
Distributions paid to noncontrolling interests (Note 6) | (151) | (121) |
Other financing activities | (61) | 13 |
Net cash used in financing activities | (1,101) | (1,196) |
Effect of translation adjustment | 8 | 1 |
Net increase/(decrease) in cash and cash equivalents and restricted cash | 532 | (186) |
Cash and cash equivalents and restricted cash, beginning of period | 401 | 453 |
Cash and cash equivalents and restricted cash, end of period | 933 | 267 |
Cash paid for: | ||
Interest, net of amounts capitalized | 188 | 201 |
Income taxes, net of amounts refunded | 8 | 39 |
Series A Preferred Units | ||
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Distributions paid to unitholders (Note 6) | (79) | (74) |
Series B Preferred Units | ||
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Distributions paid to unitholders (Note 6) | (36) | (25) |
Common Units | ||
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Distributions paid to unitholders (Note 6) | $ (374) | $ (280) |
CONDENSED CONSOLIDATED STATEM_6
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL - USD ($) $ in Millions | Total | Partners’ Capital Excluding Noncontrolling Interests | Noncontrolling Interests | 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 |
Beginning balance at Dec. 31, 2021 | $ 12,810 | $ 9,972 | $ 2,838 | $ 1,505 | $ 787 | $ 7,680 |
Increase (Decrease) in Partners' Capital | ||||||
Net income | 476 | 390 | 86 | 74 | 25 | 291 |
Distributions (Note 6) | (500) | (379) | (121) | (74) | (25) | (280) |
Other comprehensive income/(loss) | 22 | 22 | 22 | |||
Repurchase of common units | (74) | (74) | (74) | |||
Other | (15) | 0 | (15) | 0 | ||
Ending balance at Jun. 30, 2022 | 12,719 | 9,931 | 2,788 | 1,505 | 787 | 7,639 |
Beginning balance at Mar. 31, 2022 | 12,854 | 10,043 | 2,811 | 1,505 | 787 | 7,751 |
Increase (Decrease) in Partners' Capital | ||||||
Net income | 251 | 203 | 48 | 37 | 12 | 154 |
Distributions (Note 6) | (264) | (202) | (62) | (37) | (12) | (153) |
Other comprehensive income/(loss) | (52) | (52) | (52) | |||
Repurchase of common units | (49) | (49) | (49) | |||
Other | (21) | (12) | (9) | (12) | ||
Ending balance at Jun. 30, 2022 | 12,719 | 9,931 | 2,788 | 1,505 | 787 | 7,639 |
Beginning balance at Dec. 31, 2022 | 13,325 | 10,057 | 3,268 | 1,505 | 787 | 7,765 |
Increase (Decrease) in Partners' Capital | ||||||
Net income | 824 | 715 | 109 | 85 | 36 | 594 |
Distributions (Note 6) | (646) | (495) | (151) | (85) | (36) | (374) |
Other comprehensive income/(loss) | 85 | 85 | 85 | |||
Other | 14 | 17 | (3) | 2 | 15 | |
Ending balance at Jun. 30, 2023 | 13,602 | 10,379 | 3,223 | 1,507 | 787 | 8,085 |
Beginning balance at Mar. 31, 2023 | 13,483 | 10,243 | 3,240 | 1,506 | 787 | 7,950 |
Increase (Decrease) in Partners' Capital | ||||||
Net income | 349 | 293 | 56 | 44 | 18 | 231 |
Distributions (Note 6) | (322) | (249) | (73) | (44) | (18) | (187) |
Other comprehensive income/(loss) | 85 | 85 | 85 | |||
Other | 7 | 7 | 1 | 6 | ||
Ending balance at Jun. 30, 2023 | $ 13,602 | $ 10,379 | $ 3,223 | $ 1,507 | $ 787 | $ 8,085 |
Organization and Basis of Conso
Organization and Basis of Consolidation and Presentation | 6 Months Ended |
Jun. 30, 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-Q 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 10 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 June 30, 2023, AAP also owned a limited partner interest in us through its ownership of approximately 240.8 million of our common units (approximately 31% of our total outstanding common units and Series A preferred units combined). Plains All American GP LLC (“GP LLC”), a Delaware limited liability company, is AAP’s general partner. Plains GP Holdings, L.P. (“PAGP”) is the sole and managing member of GP LLC, and, at June 30, 2023, owned an approximate 81% limited partner interest in AAP. PAA GP Holdings LLC (“PAGP GP”) is the general partner of PAGP. As the sole member of GP LLC, PAGP has responsibility for conducting our business and managing our operations; however, the board of directors of PAGP GP has ultimate responsibility for managing the business and affairs of PAGP, AAP and us. GP LLC employs our domestic officers and personnel; our Canadian officers and personnel are employed by our subsidiary, Plains Midstream Canada ULC. References to our “general partner,” as the context requires, include any or all of PAGP GP, PAGP, GP LLC, AAP and PAA GP. Definitions Additional defined terms are used in this Form 10-Q 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 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 LTIP = Long-term incentive plan Mcf = Thousand cubic feet MMbls = Million barrels 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 USD = United States dollar WTI = West Texas Intermediate Basis of Consolidation and Presentation The accompanying unaudited condensed consolidated interim financial statements and related notes thereto should be read in conjunction with our 2022 Annual Report on Form 10-K. The accompanying condensed 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. The financial statements have been prepared in accordance with the instructions for interim reporting as set forth by the SEC. The condensed consolidated balance sheet data as of December 31, 2022 was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the three and six months ended June 30, 2023 should not be taken as indicative of results to be expected for the entire year. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods have been reflected. 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. Subsequent Events Subsequent events have been evaluated through the financial statements issuance date and have been included in the following footnotes where applicable. Recent Accounting Pronouncements Except as discussed in our 2022 Annual Report on Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the six months ended June 30, 2023 that are of significance or potential significance to us. |
Revenues and Accounts Receivabl
Revenues and Accounts Receivable | 6 Months Ended |
Jun. 30, 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. See Note 3 to our Consolidated Financial Statements included in Part IV of our 2022 Annual Report on Form 10-K for additional information regarding our types of revenues and policies for revenue recognition. Revenues from Contracts with Customers. The following tables present our revenues from contracts with customers disaggregated by segment and type of activity (in millions): Three Months Ended Six Months Ended 2023 2022 2023 2022 Crude Oil segment revenues from contracts with customers Sales $ 10,937 $ 15,576 $ 22,318 $ 28,433 Transportation 255 175 505 330 Terminalling, Storage and Other 94 90 185 180 Total Crude Oil segment revenues from contracts with customers $ 11,286 $ 15,841 $ 23,008 $ 28,943 Three Months Ended Six Months Ended 2023 2022 2023 2022 NGL segment revenues from contracts with customers Sales $ 232 $ 499 $ 885 $ 1,344 Transportation 8 7 15 16 Terminalling, Storage and Other 23 20 52 45 Total NGL segment revenues from contracts with customers $ 263 $ 526 $ 952 $ 1,405 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 to total revenues of reportable segments and total revenues as disclosed in our Condensed Consolidated Statements of Operations (in millions): Three Months Ended June 30, 2023 Crude Oil NGL Total Revenues from contracts with customers $ 11,286 $ 263 $ 11,549 Other revenues 9 118 127 Total revenues of reportable segments $ 11,295 $ 381 $ 11,676 Intersegment revenues elimination (74) Total revenues $ 11,602 Three Months Ended June 30, 2022 Crude Oil NGL Total Revenues from contracts with customers $ 15,841 $ 526 $ 16,367 Other revenues 99 44 143 Total revenues of reportable segments $ 15,940 $ 570 $ 16,510 Intersegment revenues elimination (151) Total revenues $ 16,359 Six Months Ended June 30, 2023 Crude Oil NGL Total Revenues from contracts with customers $ 23,008 $ 952 $ 23,960 Other items in revenues 45 119 164 Total revenues of reportable segments $ 23,053 $ 1,071 $ 24,124 Intersegment revenues (181) Total revenues $ 23,943 Six Months Ended June 30, 2022 Crude Oil NGL Total Revenues from contracts with customers $ 28,943 $ 1,405 $ 30,348 Other items in revenues 76 (101) (25) Total revenues of reportable segments $ 29,019 $ 1,304 $ 30,323 Intersegment revenues (270) Total revenues $ 30,053 Minimum Volume Commitments. We have certain agreements that require counterparties to transport or throughput a minimum volume over an agreed upon period. 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): Counterparty Deficiencies Financial Statement Classification June 30, December 31, Billed and collected Other current liabilities $ 79 $ 104 Unbilled (1) N/A 1 1 Total $ 80 $ 105 (1) Amounts were related to deficiencies for which the counterparties had not met their contractual minimum commitments and are not reflected in our Condensed Consolidated Financial Statements as we had not yet billed or collected such amounts. Contract Balances . Our contract balances consist of amounts received associated with services or sales for which we have not yet completed the related performance obligation. The following table presents the changes in the liability balance associated with contracts with customers (in millions): Contract Liabilities Balance at December 31, 2022 $ 229 Amounts recognized as revenue (35) Additions 20 Other 2 Balance at June 30, 2023 $ 216 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 June 30, 2023 (in millions): Remainder of 2023 2024 2025 2026 2027 2028 and Thereafter Pipeline revenues supported by minimum volume commitments and capacity agreements (1) $ 182 $ 360 $ 391 $ 140 $ 101 $ 240 Terminalling, storage and other agreement revenues 137 217 134 106 96 771 Total $ 319 $ 577 $ 525 $ 246 $ 197 $ 1,011 (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; • Contracts within the scope of ASC Topic 842, Leases ; and • Contracts within the scope of ASC Topic 815, Derivatives and Hedging . 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 June 30, 2023 and December 31, 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 Condensed Consolidated Balance Sheets (in millions): June 30, December 31, Trade accounts receivable arising from revenues from contracts with customers $ 3,607 $ 4,141 Other trade accounts receivables and other receivables (1) 5,926 7,216 Impact due to contractual rights of offset with counterparties (6,313) (7,450) Trade accounts receivable and other receivables, net $ 3,220 $ 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 | 6 Months Ended |
Jun. 30, 2023 | |
Earnings Per Share [Abstract] | |
Net Income Per Common Unit | Net Income Per Common Unit We calculate basic and diluted net income per common unit by dividing net income attributable to PAA (after deducting amounts allocated to the preferred unitholders and participating securities) by the basic and diluted weighted average number of common units outstanding during the period. The diluted weighted average number of common units is computed based on the weighted average number of common units plus the effect of potentially dilutive securities outstanding during the period, which include (i) our Series A preferred units and (ii) our equity-indexed compensation plan awards. See Note 12 and Note 18 to our Consolidated Financial Statements included in Part IV of our 2022 Annual Report on Form 10-K for a discussion of our Series A preferred units and 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 each of the three and six months ended June 30, 2023 and 2022 as the effect was antidilutive. 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 period 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): Three Months Ended Six Months Ended 2023 2022 2023 2022 Basic and Diluted Net Income per Common Unit Net income attributable to PAA $ 293 $ 203 $ 715 $ 390 Distributions to Series A preferred unitholders (44) (37) (85) (74) Distributions to Series B preferred unitholders (18) (12) (36) (25) Amounts allocated to participating securities (5) (1) (8) (1) Other 1 — 2 — Net income allocated to common unitholders (1) $ 227 $ 153 $ 588 $ 290 Basic and diluted weighted average common units outstanding 698 702 698 703 Basic and diluted net income per common unit $ 0.32 $ 0.22 $ 0.84 $ 0.41 (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 | 6 Months Ended |
Jun. 30, 2023 | |
Inventory Disclosure [Abstract] | |
Inventory, Linefill and Long-term Inventory | Inventory, Linefill and Long-term Inventory Inventory, linefill and long-term inventory consisted of the following (barrels in thousands and carrying value in millions): June 30, 2023 December 31, 2022 Volumes Unit of Carrying Price/ Unit (1) Volumes Unit of Carrying Price/ Unit (1) Inventory Crude oil 3,150 barrels $ 213 $ 67.62 6,713 barrels $ 452 $ 67.33 NGL 5,084 barrels 144 $ 28.32 7,285 barrels 270 $ 37.06 Other N/A 10 N/A N/A 7 N/A Inventory subtotal 367 729 Linefill Crude oil 15,226 barrels 898 $ 58.98 15,480 barrels 906 $ 58.53 NGL 2,168 barrels 68 $ 31.37 1,876 barrels 55 $ 29.32 Linefill subtotal 966 961 Long-term inventory Crude oil 3,254 barrels 224 $ 68.84 3,102 barrels 246 $ 79.30 NGL 1,327 barrels 46 $ 34.66 1,066 barrels 38 $ 35.65 Long-term inventory subtotal 270 284 Total $ 1,603 $ 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. |
Debt
Debt | 6 Months Ended |
Jun. 30, 2023 | |
Debt Disclosure [Abstract] | |
Debt | Debt Debt consisted of the following (in millions): June 30, December 31, SHORT-TERM DEBT Senior notes: 2.85% senior notes due January 2023 (1) $ — $ 400 3.85% senior notes due October 2023 700 700 Other 9 59 Total short-term debt 709 1,159 LONG-TERM DEBT Senior notes, net of unamortized discounts and debt issuance costs of $44 and $46, respectively 7,239 7,237 Other 49 50 Total long-term debt 7,288 7,287 Total debt (2) $ 7,997 $ 8,446 (1) These senior notes were redeemed on January 31, 2023. (2) Our fixed-rate senior notes had a face value of approximately $8.0 billion and $8.4 billion as of June 30, 2023 and December 31, 2022, respectively. We estimated the aggregate fair value of these notes as of June 30, 2023 and December 31, 2022 to be approximately $7.3 billion and $7.6 billion, respectively. Our fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near the end of the reporting period. The fair value estimate for our senior notes is based upon observable market data and is classified in Level 2 of the fair value hierarchy. Borrowings and Repayments Total borrowings under our credit facilities and commercial paper program for the six months ended June 30, 2023 and 2022 were approximately $1.5 billion and $16.4 billion, respectively. Total repayments under our credit facilities and commercial paper program were approximately $1.5 billion and $16.3 billion for the six months ended June 30, 2023 and 2022, 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. On January 31, 2023, we redeemed our 2.85%, $400 million senior notes due January 2023. 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. Additionally, we issue letters of credit to support insurance programs, derivative transactions, including hedging-related margin obligations, and construction activities. At June 30, 2023 and December 31, 2022, we had outstanding letters of credit of $127 million and $102 million, respectively. |
Partners' Capital and Distribut
Partners' Capital and Distributions | 6 Months Ended |
Jun. 30, 2023 | |
Partners' Capital Notes [Abstract] | |
Partners' Capital and Distributions | Partners’ Capital and Distributions Units Outstanding The following tables present the activity for our preferred and common units: Limited Partners Series A Preferred Units Series B Preferred Units Common Units Outstanding at December 31, 2022 71,090,468 800,000 698,354,498 Issuances of common units under equity-indexed compensation plans — — 35,508 Outstanding at March 31, 2023 and June 30, 2023 71,090,468 800,000 698,390,006 Limited Partners Series A Preferred Units Series B Preferred Units Common Units 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 — — (2,375,299) Issuances of common units under equity-indexed compensation plans — — 51,937 Outstanding at March 31, 2022 71,090,468 800,000 702,668,178 Repurchase and cancellation of common units under the Common Equity Repurchase Program — — (4,876,062) Issuances of common units under equity-indexed compensation plans — — 147,830 Outstanding at June 30, 2022 71,090,468 800,000 697,939,946 Distributions Series A Preferred Unit Distributions . After the fifth anniversary of the January 28, 2016 issuance date of our Series A preferred units, the holders of our 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”). In January 2023, the Series A preferred unitholders elected the Preferred Distribution Rate Reset Option which resulted in an increase in the quarterly distribution rate to approximately $0.615 per unit. This new distribution rate was effective on January 31, 2023. The quarterly distribution paid in May 2023 reflected a pro-rated amount of approximately $0.585 per unit. The following table details distributions to our Series A preferred unitholders paid during or pertaining to the first six months of 2023 (in millions, except per unit data): Series A Preferred Unitholders Distribution Payment Date Cash Distribution Distribution per Unit August 14, 2023 (1) $ 44 $ 0.615 May 15, 2023 $ 42 $ 0.585 February 14, 2023 $ 37 $ 0.525 (1) Payable to unitholders of record at the close of business on July 31, 2023 for the period from April 1, 2023 through June 30, 2023. At June 30, 2023, such amount was accrued as distributions payable in “Other current liabilities” on our Condensed Consolidated Balance Sheet. Series B Preferred Unit Distributions . Distributions on the Series B preferred units accumulate and are payable quarterly in arrears on the 15th day of February, May, August and November. See Note 12 to our Consolidated Financial Statements included in Part IV of our 2022 Annual Report on Form 10-K for additional information regarding our Series B preferred unit distributions. The following table details distributions paid or to be paid to our Series B preferred unitholders (in millions, except per unit data): Series B Preferred Unitholders Distribution Payment Date Cash Distribution Distribution per Unit August 15, 2023 (1) $ 19 $ 24.10 May 15, 2023 $ 18 $ 22.18 February 15, 2023 $ 18 $ 22.27 (1) Payable to unitholders of record at the close of business on August 1, 2023 for the period from May 15, 2023 through August 14, 2023. At June 30, 2023, approximately $10 million of accrued distributions payable to our Series B preferred unitholders was included in “Other current liabilities” on our Condensed Consolidated Balance Sheet. Common Unit Distributions . The following table details distributions to our common unitholders paid during or pertaining to the first six months of 2023 (in millions, except per unit data): Distributions Cash Distribution per Common Unit Common Unitholders Total Cash Distribution Distribution Payment Date Public AAP August 14, 2023 (1) $ 123 $ 64 $ 187 $ 0.2675 May 15, 2023 $ 122 $ 65 $ 187 $ 0.2675 February 14, 2023 $ 122 $ 65 $ 187 $ 0.2675 (1) Payable to unitholders of record at the close of business on July 31, 2023 for the period from April 1, 2023 through June 30, 2023. Noncontrolling Interests in Subsidiaries As of June 30, 2023, noncontrolling interests in our subsidiaries consisted of (i) a 35% interest in Plains Oryx Permian Basin LLC (the “Permian JV”), (ii) a 30% interest in Cactus II Pipeline LLC (“Cactus II”) and (iii) a 33% interest in Red River Pipeline Company LLC (“Red River”). The following table details distributions paid to noncontrolling interests during the periods presented (in millions): Three Months Ended Six Months Ended 2023 2022 2023 2022 Permian JV $ 53 $ 58 $ 111 $ 112 Cactus II (1) 15 — 29 — Red River 5 4 11 9 $ 73 $ 62 $ 151 $ 121 (1) In November 2022, we acquired an additional interest in Cactus II which, combined with changes in the governance of this entity, resulted in our obtaining control of the entity. Subsequent to this transaction, we reflect Cactus II as a consolidated subsidiary. See Note 7 to our Consolidated Financial Statements included in Part IV of our 2022 Annual Report on Form 10-K for additional information on the Cactus II transaction. |
Derivatives and Risk Management
Derivatives and Risk Management Activities | 6 Months Ended |
Jun. 30, 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 Condensed 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 June 30, 2023 and December 31, 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 June 30, 2023, net derivative positions related to these activities included: • A net long position of 5.0 million barrels associated with our crude oil purchases, which was unwound ratably during July 2023 to match monthly average pricing. • A net short time spread position of 6.1 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through October 2024. • A net crude oil basis spread position of 1.9 million barrels at multiple locations through November 2024. These derivatives allow us to lock in grade and location basis differentials. • A net short position of 10.5 million barrels through June 2024 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 June 30, 2023: Notional Volume (Short)/Long Remaining Tenor Natural gas purchases 38.9 Bcf December 2023 Propane sales (7.5) MMbls December 2023 Butane sales (0.9) MMbls December 2023 Condensate sales (0.5) MMbls December 2023 Fuel gas requirements (1) 4.4 Bcf June 2024 Power supply requirements (1) 2.2 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): Three Months Ended Six Months Ended 2023 2022 2023 2022 Product sales revenues $ 119 $ 76 $ 118 $ (136) Field operating costs 6 8 (13) 21 Net gain/ (loss) from commodity derivative activity $ 125 $ 84 $ 105 $ (115) 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): June 30, December 31, Initial margin $ 46 $ 93 Variation margin returned (177) (236) Letters of credit (25) (25) Net broker payable $ (156) $ (168) The following table reflects the Condensed 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 Condensed Consolidated Balance Sheet when the legal right of offset exists. Amounts in the table below are presented in millions. June 30, 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 $ 221 $ (21) $ (156) $ 44 $ 300 $ (71) $ (168) $ 61 Other long-term assets, net 3 — — 3 9 (5) — 4 Derivative Liabilities Other current liabilities — (33) — (33) 2 (13) — (11) Other long-term liabilities and deferred credits 2 (9) — (7) — — — — Total $ 226 $ (63) $ (156) $ 7 $ 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 June 30, 2023 (notional amounts in millions): Hedged Transaction Number and Types of Notional Expected Average Rate Accounting 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 three months ended June 30, 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 June 30, 2023, there was a net loss of $100 million deferred in AOCI. The deferred net loss recorded in AOCI is expected to be reclassified to future earnings contemporaneously with interest expense accruals associated with underlying debt instruments. We estimate that substantially all of the remaining deferred loss will be reclassified to earnings through 2056 as the underlying hedged transactions impact earnings. A portion of these amounts is based on market prices as of June 30, 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): Three Months Ended Six Months Ended 2023 2022 2023 2022 Interest rate derivatives, net $ 8 $ 36 $ 2 $ 68 At June 30, 2023, the net fair value of our interest rate hedges, which were included in “Other current assets” and “Other long-term liabilities and deferred credits” on our Condensed Consolidated Balance Sheet, totaled $47 million and $5 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 Condensed 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 June 30, 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 $ 154 $ — $ 163 $ (7) $ 229 $ — $ 222 Interest rate derivatives — 42 — 42 — 120 — 120 Preferred Distribution Rate Reset Option — — — — — — (189) (189) Total net derivative asset/(liability) $ 9 $ 196 $ — $ 205 $ (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): Three Months Ended Six Months Ended 2023 2022 2023 2022 Beginning Balance $ — $ (44) $ (189) $ (2) Net gains/(losses) for the period included in earnings — (103) 58 (147) Settlements — — 131 2 Ending Balance $ — $ (147) $ — $ (147) Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period $ — $ (103) $ — $ (147) |
Related Party Transactions
Related Party Transactions | 6 Months Ended |
Jun. 30, 2023 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Related Party Transactions See Note 17 to our Consolidated Financial Statements included in Part IV of our 2022 Annual Report on Form 10-K for a complete discussion of related parties, including the determination of our related parties and nature of involvement with such related parties. 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 June 30, 2023. Interest income/expense on the related party notes totaled $7 million and $10 million for the three and six months ended June 30, 2023, respectively. As of June 30, 2023, our outstanding related party note receivable and related party note payable balances were as follows (in millions): June 30, Related party note receivable (1) $ 378 Related party note payable (1) $ 378 (1) We have elected to present our related party notes with the same counterparty on a net basis on our Condensed Consolidated Balance Sheet because there is a legal right to offset and we intend to offset with the counterparty. Transactions with Other Related Parties During the three and six months ended June 30, 2023 and 2022, we recognized sales and transportation revenues, purchased petroleum products and utilized transportation and storage services from related parties. These transactions were conducted at posted tariff rates or prices that we believe approximate market. The impact to our Condensed Consolidated Statements of Operations from these transactions is included below (in millions): Three Months Ended Six Months Ended 2023 2022 2023 2022 Revenues from related parties $ 12 $ 10 $ 23 $ 22 Purchases and related costs from related parties $ 101 $ 87 $ 200 $ 184 Our receivable and payable amounts with these related parties as reflected on our Condensed Consolidated Balance Sheets were as follows (in millions): June 30, December 31, Trade accounts receivable and other receivables, net from related parties (1) $ 76 $ 45 Trade accounts payable to related parties (1) (2) $ 72 $ 79 (1) Includes amounts related to transportation and storage services, amounts owed to us or advanced to us related to investment capital projects of equity method investees where we serve as construction manager and amounts related to crude oil purchases and sales. (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. |
Commitments and Contingencies
Commitments and Contingencies | 6 Months Ended |
Jun. 30, 2023 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and 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. 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 both June 30, 2023 and December 31, 2022, our estimated undiscounted reserve for environmental liabilities (excluding liabilities related to the Line 901 incident, as discussed further below) totaled $55 million, of which $10 million was classified as short-term and $45 million was classified as long-term for each period. 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. Nine class action lawsuits were filed against us; however, after various claims were either dismissed or consolidated, two proceedings remained pending in the United States District Court for the Central District of California. In the first proceeding, the plaintiffs seek a declaratory judgment that Plains’ right-of-way agreements would not allow Plains to lay a new pipeline to replace Line 901 and/or the non-operating segment of Line 903 without paying additional compensation. The purchaser of Line 901 and the Sisquoc to Pentland portion of Line 903 has joined this proceeding as a co-defendant with respect to its interest in such acquired pipelines. In the second proceeding, 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. 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 June 30, 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 yet responded to our reimbursement demand. We have initiated 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 and the Derivative 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 June 30, 2023, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $740 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 the Derivative 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 Condensed 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 six months ended June 30, 2022, we recognized costs, net of amounts probable of recovery from insurance carriers, of $85 million. We did not recognize any such costs during the six months ended June 30, 2023. As of June 30, 2023, we had a remaining undiscounted gross liability of approximately $98 million related to the Line 901 incident, which aggregate amount is reflected in “Current liabilities” on our Condensed 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 June 30, 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 $240 million. Through June 30, 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 June 30, 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 Condensed 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. Insurance Pipelines, terminals, trucks or other facilities or equipment may experience damage as a result of an accident, natural disaster, terrorist attack, cyber event or other event. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. Consistent with insurance coverage generally available in the industry, in certain circumstances our insurance policies provide limited coverage for losses or liabilities relating to gradual pollution, with broader coverage for sudden and accidental occurrences. We maintain various types and varying levels of insurance coverage to cover our operations and properties, and we self-insure certain risks, including gradual pollution, cybersecurity and named windstorms. To the extent we do maintain insurance coverage, such insurance does not cover every potential risk that might occur, associated with operating pipelines, terminals and other facilities and equipment, including the potential loss of significant revenues and cash flows. The occurrence of a significant event not fully insured, indemnified or reserved against, or the failure of a party to meet its insurance or indemnification obligations, could materially and adversely affect our operations and financial condition. While we strive to maintain adequate insurance coverage, our actual costs may exceed our coverage levels and insurance will not cover many types of interruptions that might occur, will not cover amounts up to applicable deductibles and will not cover all risks associated with certain of our assets and operations. With respect to our insurance coverage, our policies are subject to deductibles and retention levels that we consider reasonable and not excessive. Additionally, no assurance can be given that we will be able to maintain adequate insurance in the future at rates we consider reasonable. As a result, we may elect to self-insure or utilize higher deductibles in certain other insurance programs. In addition, although we believe that we have established adequate reserves and liquidity to the extent such risks are not insured, costs incurred in excess of these reserves may be higher or we may not receive insurance proceeds in a timely manner, which may potentially have a material adverse effect on our financial conditions, results of operations or cash flows. |
Segment Information
Segment Information | 6 Months Ended |
Jun. 30, 2023 | |
Segment Reporting [Abstract] | |
Segment Information | Segment Information We manage our operations through two operating segments, which are also our reportable segments: Crude Oil and NGL. See Note 20 to our Consolidated Financial Statements included in Part IV of our 2022 Annual Report on Form 10-K for a summary of the types of products and services from which each segment derives its revenues. 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 (“Adjusted EBITDA attributable to noncontrolling interests”). The following tables reflect certain financial data for each segment (in millions): Crude Oil NGL Intersegment Revenues Total Three Months Ended June 30, 2023 Revenues (1) : Product sales $ 10,925 $ 346 $ (70) $ 11,201 Services 370 35 (4) 401 Total revenues $ 11,295 $ 381 $ (74) $ 11,602 Equity earnings in unconsolidated entities $ 89 $ — $ 89 Segment Adjusted EBITDA $ 529 $ 62 $ 591 Maintenance capital expenditures $ 36 $ 26 $ 62 Three Months Ended June 30, 2022 Revenues (1) : Product sales $ 15,625 $ 525 $ (143) $ 16,007 Services 315 45 (8) 352 Total revenues $ 15,940 $ 570 $ (151) $ 16,359 Equity earnings in unconsolidated entities $ 104 $ — $ 104 Segment Adjusted EBITDA $ 494 $ 120 $ 614 Maintenance capital expenditures $ 25 $ 18 $ 43 Six Months Ended June 30, 2023 Revenues (1) : Product sales $ 22,333 $ 982 $ (170) $ 23,145 Services 720 89 (11) 798 Total revenues $ 23,053 $ 1,071 $ (181) $ 23,943 Equity earnings in unconsolidated entities $ 178 $ — $ 178 Segment Adjusted EBITDA $ 1,046 $ 254 $ 1,300 Maintenance capital expenditures $ 67 $ 42 $ 109 Six Months Ended June 30, 2022 Revenues (1) : Product sales $ 28,435 $ 1,207 $ (254) $ 29,388 Services 584 97 (16) 665 Total revenues $ 29,019 $ 1,304 $ (270) $ 30,053 Equity earnings in unconsolidated entities $ 201 $ — $ 201 Segment Adjusted EBITDA $ 946 $ 281 $ 1,227 Maintenance capital expenditures $ 45 $ 25 $ 70 (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. Segment Adjusted EBITDA Reconciliation The following table reconciles Segment Adjusted EBITDA to Net income attributable to PAA (in millions): Three Months Ended Six Months Ended 2023 2022 2023 2022 Segment Adjusted EBITDA $ 591 $ 614 $ 1,300 $ 1,227 Adjustments: (1) Depreciation and amortization of unconsolidated entities (2) (24) (17) (47) (37) Derivative activities and inventory valuation adjustments (3) 86 75 (6) (13) Long-term inventory costing adjustments (4) (2) 13 (31) 105 Deficiencies under minimum volume commitments, net (5) 2 (10) 9 (15) Equity-indexed compensation expense (6) (8) (7) (17) (15) Foreign currency revaluation (7) (19) (3) (15) (1) Line 901 incident (8) — — — (85) Adjusted EBITDA attributable to noncontrolling interests (9) 103 89 200 166 Depreciation and amortization (259) (242) (515) (473) Gains/(losses) on asset sales and asset impairments, net (3) 3 150 46 Interest expense, net (95) (99) (193) (206) Other income/(expense), net 20 (118) 85 (155) Income before tax 392 298 920 544 Income tax expense (43) (47) (96) (68) Net income 349 251 824 476 Net income attributable to noncontrolling interests (56) (48) (109) (86) Net income attributable to PAA $ 293 $ 203 $ 715 $ 390 (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 our capital expenditure necessary to construct the related asset. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote. We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue, as a selected item impacting comparability. Our CODM views the inclusion of the contractually committed revenues associated with that period as meaningful to Segment Adjusted EBITDA as the related asset has been constructed, is standing ready to provide the committed service and the fixed operating costs are included in the current period results. (6) Our total equity-indexed compensation expense includes expense associated with awards that will be settled in units and awards that will be settled in cash. The awards that will be settled in units are included in our diluted net income per unit calculation when the applicable performance criteria have been met. We exclude compensation expense associated with these awards in determining Segment Adjusted EBITDA as the dilutive impact of the outstanding awards is included in our diluted net income per unit calculation, as applicable. The portion of compensation expense associated with awards that will settle in cash is not excluded in determining Segment Adjusted EBITDA. See Note 18 to our Consolidated Financial Statements included in Part IV of our 2022 Annual Report on Form 10-K for a discussion 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 9 for additional information regarding the Line 901 incident. (9) Reflects amounts attributable to noncontrolling interests in the Permian JV, Cactus II and Red River. |
Acquisitions and Divestitures
Acquisitions and Divestitures | 6 Months Ended |
Jun. 30, 2023 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Acquisitions and Divestitures | Acquisitions and Divestitures Acquisitions OMOG Acquisition. On July 28, 2023, we acquired the remaining 43% interest in OMOG JV LLC (“OMOG”) for approximately $225 million ($145 million net to our 65% interest in the Permian JV). As a result of this transaction, we now own 100% of OMOG and its subsidiaries and such entities will be reflected as consolidated subsidiaries in our consolidated financial statements. Prior to this transaction, our 57% interest in OMOG was accounted for as an equity method investment. Divestitures |
Pay vs Performance Disclosure
Pay vs Performance Disclosure - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2023 | Jun. 30, 2022 | Jun. 30, 2023 | Jun. 30, 2022 | |
Pay vs Performance Disclosure | ||||
Net income attributable to PAA | $ 293 | $ 203 | $ 715 | $ 390 |
Insider Trading Arrangements
Insider Trading Arrangements | 3 Months Ended |
Jun. 30, 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 |
Revenues and Accounts Receiva_2
Revenues and Accounts Receivable (Tables) | 6 Months Ended |
Jun. 30, 2023 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of revenue | Revenues from Contracts with Customers. The following tables present our revenues from contracts with customers disaggregated by segment and type of activity (in millions): Three Months Ended Six Months Ended 2023 2022 2023 2022 Crude Oil segment revenues from contracts with customers Sales $ 10,937 $ 15,576 $ 22,318 $ 28,433 Transportation 255 175 505 330 Terminalling, Storage and Other 94 90 185 180 Total Crude Oil segment revenues from contracts with customers $ 11,286 $ 15,841 $ 23,008 $ 28,943 Three Months Ended Six Months Ended 2023 2022 2023 2022 NGL segment revenues from contracts with customers Sales $ 232 $ 499 $ 885 $ 1,344 Transportation 8 7 15 16 Terminalling, Storage and Other 23 20 52 45 Total NGL segment revenues from contracts with customers $ 263 $ 526 $ 952 $ 1,405 Three Months Ended June 30, 2023 Crude Oil NGL Total Revenues from contracts with customers $ 11,286 $ 263 $ 11,549 Other revenues 9 118 127 Total revenues of reportable segments $ 11,295 $ 381 $ 11,676 Intersegment revenues elimination (74) Total revenues $ 11,602 Three Months Ended June 30, 2022 Crude Oil NGL Total Revenues from contracts with customers $ 15,841 $ 526 $ 16,367 Other revenues 99 44 143 Total revenues of reportable segments $ 15,940 $ 570 $ 16,510 Intersegment revenues elimination (151) Total revenues $ 16,359 Six Months Ended June 30, 2023 Crude Oil NGL Total Revenues from contracts with customers $ 23,008 $ 952 $ 23,960 Other items in revenues 45 119 164 Total revenues of reportable segments $ 23,053 $ 1,071 $ 24,124 Intersegment revenues (181) Total revenues $ 23,943 Six Months Ended June 30, 2022 Crude Oil NGL Total Revenues from contracts with customers $ 28,943 $ 1,405 $ 30,348 Other items in revenues 76 (101) (25) Total revenues of reportable segments $ 29,019 $ 1,304 $ 30,323 Intersegment revenues (270) Total revenues $ 30,053 |
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): Counterparty Deficiencies Financial Statement Classification June 30, December 31, Billed and collected Other current liabilities $ 79 $ 104 Unbilled (1) N/A 1 1 Total $ 80 $ 105 (1) Amounts were related to deficiencies for which the counterparties had not met their contractual minimum commitments and are not reflected in our Condensed Consolidated Financial Statements as we had not yet billed or collected such amounts. |
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, 2022 $ 229 Amounts recognized as revenue (35) Additions 20 Other 2 Balance at June 30, 2023 $ 216 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 Condensed Consolidated Balance Sheets (in millions): June 30, December 31, Trade accounts receivable arising from revenues from contracts with customers $ 3,607 $ 4,141 Other trade accounts receivables and other receivables (1) 5,926 7,216 Impact due to contractual rights of offset with counterparties (6,313) (7,450) Trade accounts receivable and other receivables, net $ 3,220 $ 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. |
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 June 30, 2023 (in millions): Remainder of 2023 2024 2025 2026 2027 2028 and Thereafter Pipeline revenues supported by minimum volume commitments and capacity agreements (1) $ 182 $ 360 $ 391 $ 140 $ 101 $ 240 Terminalling, storage and other agreement revenues 137 217 134 106 96 771 Total $ 319 $ 577 $ 525 $ 246 $ 197 $ 1,011 |
Net Income Per Common Unit (Tab
Net Income Per Common Unit (Tables) | 6 Months Ended |
Jun. 30, 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): Three Months Ended Six Months Ended 2023 2022 2023 2022 Basic and Diluted Net Income per Common Unit Net income attributable to PAA $ 293 $ 203 $ 715 $ 390 Distributions to Series A preferred unitholders (44) (37) (85) (74) Distributions to Series B preferred unitholders (18) (12) (36) (25) Amounts allocated to participating securities (5) (1) (8) (1) Other 1 — 2 — Net income allocated to common unitholders (1) $ 227 $ 153 $ 588 $ 290 Basic and diluted weighted average common units outstanding 698 702 698 703 Basic and diluted net income per common unit $ 0.32 $ 0.22 $ 0.84 $ 0.41 (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) | 6 Months Ended |
Jun. 30, 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): June 30, 2023 December 31, 2022 Volumes Unit of Carrying Price/ Unit (1) Volumes Unit of Carrying Price/ Unit (1) Inventory Crude oil 3,150 barrels $ 213 $ 67.62 6,713 barrels $ 452 $ 67.33 NGL 5,084 barrels 144 $ 28.32 7,285 barrels 270 $ 37.06 Other N/A 10 N/A N/A 7 N/A Inventory subtotal 367 729 Linefill Crude oil 15,226 barrels 898 $ 58.98 15,480 barrels 906 $ 58.53 NGL 2,168 barrels 68 $ 31.37 1,876 barrels 55 $ 29.32 Linefill subtotal 966 961 Long-term inventory Crude oil 3,254 barrels 224 $ 68.84 3,102 barrels 246 $ 79.30 NGL 1,327 barrels 46 $ 34.66 1,066 barrels 38 $ 35.65 Long-term inventory subtotal 270 284 Total $ 1,603 $ 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): June 30, 2023 December 31, 2022 Volumes Unit of Carrying Price/ Unit (1) Volumes Unit of Carrying Price/ Unit (1) Inventory Crude oil 3,150 barrels $ 213 $ 67.62 6,713 barrels $ 452 $ 67.33 NGL 5,084 barrels 144 $ 28.32 7,285 barrels 270 $ 37.06 Other N/A 10 N/A N/A 7 N/A Inventory subtotal 367 729 Linefill Crude oil 15,226 barrels 898 $ 58.98 15,480 barrels 906 $ 58.53 NGL 2,168 barrels 68 $ 31.37 1,876 barrels 55 $ 29.32 Linefill subtotal 966 961 Long-term inventory Crude oil 3,254 barrels 224 $ 68.84 3,102 barrels 246 $ 79.30 NGL 1,327 barrels 46 $ 34.66 1,066 barrels 38 $ 35.65 Long-term inventory subtotal 270 284 Total $ 1,603 $ 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. |
Debt (Tables)
Debt (Tables) | 6 Months Ended |
Jun. 30, 2023 | |
Debt Disclosure [Abstract] | |
Schedule of debt | Debt consisted of the following (in millions): June 30, December 31, SHORT-TERM DEBT Senior notes: 2.85% senior notes due January 2023 (1) $ — $ 400 3.85% senior notes due October 2023 700 700 Other 9 59 Total short-term debt 709 1,159 LONG-TERM DEBT Senior notes, net of unamortized discounts and debt issuance costs of $44 and $46, respectively 7,239 7,237 Other 49 50 Total long-term debt 7,288 7,287 Total debt (2) $ 7,997 $ 8,446 (1) These senior notes were redeemed on January 31, 2023. |
Partners' Capital and Distrib_2
Partners' Capital and Distributions (Tables) | 6 Months Ended |
Jun. 30, 2023 | |
Limited Partners' Capital Account | |
Schedule of activity for preferred units and common units | The following tables present the activity for our preferred and common units: Limited Partners Series A Preferred Units Series B Preferred Units Common Units Outstanding at December 31, 2022 71,090,468 800,000 698,354,498 Issuances of common units under equity-indexed compensation plans — — 35,508 Outstanding at March 31, 2023 and June 30, 2023 71,090,468 800,000 698,390,006 Limited Partners Series A Preferred Units Series B Preferred Units Common Units 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 — — (2,375,299) Issuances of common units under equity-indexed compensation plans — — 51,937 Outstanding at March 31, 2022 71,090,468 800,000 702,668,178 Repurchase and cancellation of common units under the Common Equity Repurchase Program — — (4,876,062) Issuances of common units under equity-indexed compensation plans — — 147,830 Outstanding at June 30, 2022 71,090,468 800,000 697,939,946 |
Schedule of distributions to noncontrolling interests | The following table details distributions paid to noncontrolling interests during the periods presented (in millions): Three Months Ended Six Months Ended 2023 2022 2023 2022 Permian JV $ 53 $ 58 $ 111 $ 112 Cactus II (1) 15 — 29 — Red River 5 4 11 9 $ 73 $ 62 $ 151 $ 121 (1) In November 2022, we acquired an additional interest in Cactus II which, combined with changes in the governance of this entity, resulted in our obtaining control of the entity. Subsequent to this transaction, we reflect Cactus II as a consolidated subsidiary. See Note 7 to our Consolidated Financial Statements included in Part IV of our 2022 Annual Report on Form 10-K for additional information on the Cactus II transaction. |
Series A Preferred Units | |
Limited Partners' Capital Account | |
Schedule of distributions | The following table details distributions to our Series A preferred unitholders paid during or pertaining to the first six months of 2023 (in millions, except per unit data): Series A Preferred Unitholders Distribution Payment Date Cash Distribution Distribution per Unit August 14, 2023 (1) $ 44 $ 0.615 May 15, 2023 $ 42 $ 0.585 February 14, 2023 $ 37 $ 0.525 |
Series B Preferred Units | |
Limited Partners' Capital Account | |
Schedule of distributions | The following table details distributions paid or to be paid to our Series B preferred unitholders (in millions, except per unit data): Series B Preferred Unitholders Distribution Payment Date Cash Distribution Distribution per Unit August 15, 2023 (1) $ 19 $ 24.10 May 15, 2023 $ 18 $ 22.18 February 15, 2023 $ 18 $ 22.27 (1) Payable to unitholders of record at the close of business on August 1, 2023 for the period from May 15, 2023 through August 14, 2023. At June 30, 2023, approximately $10 million of accrued distributions payable to our Series B preferred unitholders was included in “Other current liabilities” on our Condensed Consolidated Balance Sheet. |
Common Units | |
Limited Partners' Capital Account | |
Schedule of distributions | The following table details distributions to our common unitholders paid during or pertaining to the first six months of 2023 (in millions, except per unit data): Distributions Cash Distribution per Common Unit Common Unitholders Total Cash Distribution Distribution Payment Date Public AAP August 14, 2023 (1) $ 123 $ 64 $ 187 $ 0.2675 May 15, 2023 $ 122 $ 65 $ 187 $ 0.2675 February 14, 2023 $ 122 $ 65 $ 187 $ 0.2675 (1) Payable to unitholders of record at the close of business on July 31, 2023 for the period from April 1, 2023 through June 30, 2023. |
Derivatives and Risk Manageme_2
Derivatives and Risk Management Activities (Tables) | 6 Months Ended |
Jun. 30, 2023 | |
Derivatives and Risk Management Activities | |
Impact of derivatives recognized in earnings | The following table summarizes the impact of our commodity derivatives recognized in earnings (in millions): Three Months Ended Six Months Ended 2023 2022 2023 2022 Product sales revenues $ 119 $ 76 $ 118 $ (136) Field operating costs 6 8 (13) 21 Net gain/ (loss) from commodity derivative activity $ 125 $ 84 $ 105 $ (115) |
Schedule of net broker receivable/(payable) | The following table provides the components of our net broker receivable/(payable) (in millions): June 30, December 31, Initial margin $ 46 $ 93 Variation margin returned (177) (236) Letters of credit (25) (25) Net broker payable $ (156) $ (168) |
Summary of derivative assets and liabilities on condensed consolidated balance sheets on a gross basis | The following table reflects the Condensed 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 Condensed Consolidated Balance Sheet when the legal right of offset exists. Amounts in the table below are presented in millions. June 30, 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 $ 221 $ (21) $ (156) $ 44 $ 300 $ (71) $ (168) $ 61 Other long-term assets, net 3 — — 3 9 (5) — 4 Derivative Liabilities Other current liabilities — (33) — (33) 2 (13) — (11) Other long-term liabilities and deferred credits 2 (9) — (7) — — — — Total $ 226 $ (63) $ (156) $ 7 $ 311 $ (89) $ (168) $ 54 |
Net unrealized gain/(loss) recognized in AOCI for derivatives | The following table summarizes the net unrealized gain/(loss) recognized in AOCI for derivatives (in millions): Three Months Ended Six Months Ended 2023 2022 2023 2022 Interest rate derivatives, net $ 8 $ 36 $ 2 $ 68 |
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 June 30, 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 $ 154 $ — $ 163 $ (7) $ 229 $ — $ 222 Interest rate derivatives — 42 — 42 — 120 — 120 Preferred Distribution Rate Reset Option — — — — — — (189) (189) Total net derivative asset/(liability) $ 9 $ 196 $ — $ 205 $ (7) $ 349 $ (189) $ 153 (1) Derivative assets and liabilities are presented above on a net basis but do not include related cash margin deposits. |
Reconciliation of changes in fair value of derivatives classified as level 3 | The following table provides a reconciliation of changes in fair value of the beginning and ending balances for our derivatives classified as Level 3 (in millions): Three Months Ended Six Months Ended 2023 2022 2023 2022 Beginning Balance $ — $ (44) $ (189) $ (2) Net gains/(losses) for the period included in earnings — (103) 58 (147) Settlements — — 131 2 Ending Balance $ — $ (147) $ — $ (147) Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period $ — $ (103) $ — $ (147) |
Commodity Derivatives | |
Derivatives and Risk Management Activities | |
Summary of open derivative positions | 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 June 30, 2023: Notional Volume (Short)/Long Remaining Tenor Natural gas purchases 38.9 Bcf December 2023 Propane sales (7.5) MMbls December 2023 Butane sales (0.9) MMbls December 2023 Condensate sales (0.5) MMbls December 2023 Fuel gas requirements (1) 4.4 Bcf June 2024 Power supply requirements (1) 2.2 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 outstanding interest rate derivatives | The following table summarizes the terms of our outstanding interest rate derivatives as of June 30, 2023 (notional amounts in millions): Hedged Transaction Number and Types of Notional Expected Average Rate Accounting 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 |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 6 Months Ended |
Jun. 30, 2023 | |
Related Party Transactions [Abstract] | |
Schedule of related party transactions | As of June 30, 2023, our outstanding related party note receivable and related party note payable balances were as follows (in millions): June 30, Related party note receivable (1) $ 378 Related party note payable (1) $ 378 (1) We have elected to present our related party notes with the same counterparty on a net basis on our Condensed Consolidated Balance Sheet because there is a legal right to offset and we intend to offset with the counterparty. The impact to our Condensed Consolidated Statements of Operations from these transactions is included below (in millions): Three Months Ended Six Months Ended 2023 2022 2023 2022 Revenues from related parties $ 12 $ 10 $ 23 $ 22 Purchases and related costs from related parties $ 101 $ 87 $ 200 $ 184 Our receivable and payable amounts with these related parties as reflected on our Condensed Consolidated Balance Sheets were as follows (in millions): June 30, December 31, Trade accounts receivable and other receivables, net from related parties (1) $ 76 $ 45 Trade accounts payable to related parties (1) (2) $ 72 $ 79 (1) Includes amounts related to transportation and storage services, amounts owed to us or advanced to us related to investment capital projects of equity method investees where we serve as construction manager and amounts related to crude oil purchases and sales. (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. |
Segment Information (Tables)
Segment Information (Tables) | 6 Months Ended |
Jun. 30, 2023 | |
Segment Reporting [Abstract] | |
Segment financial data | The following tables reflect certain financial data for each segment (in millions): Crude Oil NGL Intersegment Revenues Total Three Months Ended June 30, 2023 Revenues (1) : Product sales $ 10,925 $ 346 $ (70) $ 11,201 Services 370 35 (4) 401 Total revenues $ 11,295 $ 381 $ (74) $ 11,602 Equity earnings in unconsolidated entities $ 89 $ — $ 89 Segment Adjusted EBITDA $ 529 $ 62 $ 591 Maintenance capital expenditures $ 36 $ 26 $ 62 Three Months Ended June 30, 2022 Revenues (1) : Product sales $ 15,625 $ 525 $ (143) $ 16,007 Services 315 45 (8) 352 Total revenues $ 15,940 $ 570 $ (151) $ 16,359 Equity earnings in unconsolidated entities $ 104 $ — $ 104 Segment Adjusted EBITDA $ 494 $ 120 $ 614 Maintenance capital expenditures $ 25 $ 18 $ 43 Six Months Ended June 30, 2023 Revenues (1) : Product sales $ 22,333 $ 982 $ (170) $ 23,145 Services 720 89 (11) 798 Total revenues $ 23,053 $ 1,071 $ (181) $ 23,943 Equity earnings in unconsolidated entities $ 178 $ — $ 178 Segment Adjusted EBITDA $ 1,046 $ 254 $ 1,300 Maintenance capital expenditures $ 67 $ 42 $ 109 Six Months Ended June 30, 2022 Revenues (1) : Product sales $ 28,435 $ 1,207 $ (254) $ 29,388 Services 584 97 (16) 665 Total revenues $ 29,019 $ 1,304 $ (270) $ 30,053 Equity earnings in unconsolidated entities $ 201 $ — $ 201 Segment Adjusted EBITDA $ 946 $ 281 $ 1,227 Maintenance capital expenditures $ 45 $ 25 $ 70 (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. |
Reconciliation of segment adjusted EBITDA to net income attributable to PAA | The following table reconciles Segment Adjusted EBITDA to Net income attributable to PAA (in millions): Three Months Ended Six Months Ended 2023 2022 2023 2022 Segment Adjusted EBITDA $ 591 $ 614 $ 1,300 $ 1,227 Adjustments: (1) Depreciation and amortization of unconsolidated entities (2) (24) (17) (47) (37) Derivative activities and inventory valuation adjustments (3) 86 75 (6) (13) Long-term inventory costing adjustments (4) (2) 13 (31) 105 Deficiencies under minimum volume commitments, net (5) 2 (10) 9 (15) Equity-indexed compensation expense (6) (8) (7) (17) (15) Foreign currency revaluation (7) (19) (3) (15) (1) Line 901 incident (8) — — — (85) Adjusted EBITDA attributable to noncontrolling interests (9) 103 89 200 166 Depreciation and amortization (259) (242) (515) (473) Gains/(losses) on asset sales and asset impairments, net (3) 3 150 46 Interest expense, net (95) (99) (193) (206) Other income/(expense), net 20 (118) 85 (155) Income before tax 392 298 920 544 Income tax expense (43) (47) (96) (68) Net income 349 251 824 476 Net income attributable to noncontrolling interests (56) (48) (109) (86) Net income attributable to PAA $ 293 $ 203 $ 715 $ 390 (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 our capital expenditure necessary to construct the related asset. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote. We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue, as a selected item impacting comparability. Our CODM views the inclusion of the contractually committed revenues associated with that period as meaningful to Segment Adjusted EBITDA as the related asset has been constructed, is standing ready to provide the committed service and the fixed operating costs are included in the current period results. (6) Our total equity-indexed compensation expense includes expense associated with awards that will be settled in units and awards that will be settled in cash. The awards that will be settled in units are included in our diluted net income per unit calculation when the applicable performance criteria have been met. We exclude compensation expense associated with these awards in determining Segment Adjusted EBITDA as the dilutive impact of the outstanding awards is included in our diluted net income per unit calculation, as applicable. The portion of compensation expense associated with awards that will settle in cash is not excluded in determining Segment Adjusted EBITDA. See Note 18 to our Consolidated Financial Statements included in Part IV of our 2022 Annual Report on Form 10-K for a discussion 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 9 for additional information regarding the Line 901 incident. (9) Reflects amounts attributable to noncontrolling interests in the Permian JV, Cactus II and Red River. |
Organization and Basis of Con_2
Organization and Basis of Consolidation and Presentation (Details) shares in Millions | 6 Months Ended |
Jun. 30, 2023 segment shares | |
Organization | |
Operating segments number | segment | 2 |
AAP | PAGP | |
Organization | |
Ownership interest (as a percent) | 81% |
PAA | AAP | |
Organization | |
Ownership interest (units) | shares | 240.8 |
Ownership interest (as a percent) | 31% |
Revenues and Accounts Receiva_3
Revenues and Accounts Receivable - Disaggregation of Revenue (Details) - Operating Segments - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2023 | Jun. 30, 2022 | Jun. 30, 2023 | Jun. 30, 2022 | |
Disaggregation of Revenue | ||||
Revenue from contracts with customers | $ 11,549 | $ 16,367 | $ 23,960 | $ 30,348 |
Crude Oil | ||||
Disaggregation of Revenue | ||||
Revenue from contracts with customers | 11,286 | 15,841 | 23,008 | 28,943 |
Crude Oil | Sales | ||||
Disaggregation of Revenue | ||||
Revenue from contracts with customers | 10,937 | 15,576 | 22,318 | 28,433 |
Crude Oil | Transportation | ||||
Disaggregation of Revenue | ||||
Revenue from contracts with customers | 255 | 175 | 505 | 330 |
Crude Oil | Terminalling, Storage and Other | ||||
Disaggregation of Revenue | ||||
Revenue from contracts with customers | 94 | 90 | 185 | 180 |
NGL | ||||
Disaggregation of Revenue | ||||
Revenue from contracts with customers | 263 | 526 | 952 | 1,405 |
NGL | Sales | ||||
Disaggregation of Revenue | ||||
Revenue from contracts with customers | 232 | 499 | 885 | 1,344 |
NGL | Transportation | ||||
Disaggregation of Revenue | ||||
Revenue from contracts with customers | 8 | 7 | 15 | 16 |
NGL | Terminalling, Storage and Other | ||||
Disaggregation of Revenue | ||||
Revenue from contracts with customers | $ 23 | $ 20 | $ 52 | $ 45 |
Revenues and Accounts Receiva_4
Revenues and Accounts Receivable - Segment Revenue (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2023 | Jun. 30, 2022 | Jun. 30, 2023 | Jun. 30, 2022 | |
Disaggregation of Revenue | ||||
Total revenues | $ 11,602 | $ 16,359 | $ 23,943 | $ 30,053 |
Operating Segments | ||||
Disaggregation of Revenue | ||||
Revenues from contracts with customers | 11,549 | 16,367 | 23,960 | 30,348 |
Other revenues | 127 | 143 | 164 | (25) |
Total revenues | 11,676 | 16,510 | 24,124 | 30,323 |
Operating Segments | Crude Oil | ||||
Disaggregation of Revenue | ||||
Revenues from contracts with customers | 11,286 | 15,841 | 23,008 | 28,943 |
Other revenues | 9 | 99 | 45 | 76 |
Total revenues | 11,295 | 15,940 | 23,053 | 29,019 |
Operating Segments | NGL | ||||
Disaggregation of Revenue | ||||
Revenues from contracts with customers | 263 | 526 | 952 | 1,405 |
Other revenues | 118 | 44 | 119 | (101) |
Total revenues | 381 | 570 | 1,071 | 1,304 |
Intersegment revenues elimination | ||||
Disaggregation of Revenue | ||||
Total revenues | $ (74) | $ (151) | $ (181) | $ (270) |
Revenues and Accounts Receiva_5
Revenues and Accounts Receivable - Counterparty Deficiencies (Details) - USD ($) $ in Millions | Jun. 30, 2023 | Dec. 31, 2022 |
Minimum Volume Commitments | ||
Counterparty deficiencies, billed and collected | $ 216 | $ 229 |
Minimum Volume Commitments | ||
Minimum Volume Commitments | ||
Counterparty deficiencies, billed and collected | 79 | 104 |
Counterparty deficiencies, unbilled | 1 | 1 |
Counterparty deficiencies, total | $ 80 | $ 105 |
Revenues and Accounts Receiva_6
Revenues and Accounts Receivable - Contract Balances (Details) $ in Millions | 6 Months Ended |
Jun. 30, 2023 USD ($) | |
Change In Contract With Customer, Liability | |
Beginning balance | $ 229 |
Amounts recognized as revenue | (35) |
Additions | 20 |
Other | 2 |
Ending balance | $ 216 |
Revenues and Accounts Receiva_7
Revenues and Accounts Receivable - Performance Obligations (Details) $ in Millions | Jun. 30, 2023 USD ($) |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2023-07-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | $ 319 |
Remaining performance obligations, expected timing of satisfaction, period | 6 months |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2024-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | $ 577 |
Remaining performance obligations, 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 | $ 525 |
Remaining performance obligations, 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 | $ 246 |
Remaining performance obligations, 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 | $ 197 |
Remaining performance obligations, 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 | $ 1,011 |
Remaining performance obligations, 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: 2023-07-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | $ 182 |
Remaining performance obligations, expected timing of satisfaction, period | 6 months |
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 | $ 360 |
Remaining performance obligations, 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 | $ 391 |
Remaining performance obligations, 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 | $ 140 |
Remaining performance obligations, 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 | $ 101 |
Remaining performance obligations, 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 | $ 240 |
Remaining performance obligations, expected timing of satisfaction, period | |
Terminalling, storage and other agreement revenues | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2023-07-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | $ 137 |
Remaining performance obligations, expected timing of satisfaction, period | 6 months |
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 | $ 217 |
Remaining performance obligations, 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 | $ 134 |
Remaining performance obligations, 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 | $ 106 |
Remaining performance obligations, 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 | $ 96 |
Remaining performance obligations, 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 | $ 771 |
Remaining performance obligations, expected timing of satisfaction, period |
Revenues and Accounts Receiva_8
Revenues and Accounts Receivable - Narrative (Details) | 6 Months Ended | 12 Months Ended |
Jun. 30, 2023 | Dec. 31, 2022 | |
Revenue from Contract with Customer [Abstract] | ||
Substantially all trade accounts receivable, net, maximum age of balances past their invoice date | 30 days | 30 days |
Revenues and Accounts Receiva_9
Revenues and Accounts Receivable - Trade Accounts Receivable and Other Receivables (Details) - USD ($) $ in Millions | Jun. 30, 2023 | Dec. 31, 2022 |
Revenue from Contract with Customer [Abstract] | ||
Trade accounts receivable arising from revenues from contracts with customers | $ 3,607 | $ 4,141 |
Other trade accounts receivables and other receivables | 5,926 | 7,216 |
Impact due to contractual rights of offset with counterparties | (6,313) | (7,450) |
Trade accounts receivable and other receivables, net | $ 3,220 | $ 3,907 |
Net Income Per Common Unit (Det
Net Income Per Common Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2023 | Jun. 30, 2022 | Jun. 30, 2023 | Jun. 30, 2022 | |
Basic and Diluted Net Income per Common Unit | ||||
Net income attributable to PAA | $ 293 | $ 203 | $ 715 | $ 390 |
Amounts allocated to participating securities | (5) | (1) | (8) | (1) |
Other | 1 | 2 | ||
Net income allocated to common unitholders - Basic | 227 | 153 | 588 | 290 |
Net income allocated to common unitholders - Diluted | 227 | 153 | 588 | 290 |
Series A Preferred Units | ||||
Basic and Diluted Net Income per Common Unit | ||||
Distributions to preferred unitholders | $ (44) | $ (37) | $ (85) | $ (74) |
Series A Preferred Units | Weighted Average | ||||
Net Income/(Loss) Per Common Unit | ||||
Antidilutive securities excluded from computation of net income per common unit (units) | 71 | 71 | 71 | 71 |
Series B Preferred Units | ||||
Basic and Diluted Net Income per Common Unit | ||||
Distributions to preferred unitholders | $ (18) | $ (12) | $ (36) | $ (25) |
Common Units | ||||
Basic and Diluted Net Income per Common Unit | ||||
Basic weighted average common units outstanding (units) | 698 | 702 | 698 | 703 |
Diluted weighted average common units outstanding (units) | 698 | 702 | 698 | 703 |
Basic net income per common unit (usd per unit) | $ 0.32 | $ 0.22 | $ 0.84 | $ 0.41 |
Diluted net income per common unit (usd per unit) | $ 0.32 | $ 0.22 | $ 0.84 | $ 0.41 |
Inventory, Linefill and Long-_3
Inventory, Linefill and Long-term Inventory (Details) bbl in Thousands, $ in Millions | Jun. 30, 2023 USD ($) $ / bbl bbl | Dec. 31, 2022 USD ($) $ / bbl bbl |
Inventory by category | ||
Inventory subtotal, carrying value | $ 367 | $ 729 |
Linefill subtotal, carrying value | 966 | 961 |
Long-term inventory subtotal, carrying value | 270 | 284 |
Total | $ 1,603 | $ 1,974 |
Crude oil | ||
Inventory by category | ||
Inventory, volumes (in barrels) | bbl | 3,150 | 6,713 |
Linefill, volumes (in barrels) | bbl | 15,226 | 15,480 |
Long-term inventory, volumes (in barrels) | bbl | 3,254 | 3,102 |
Inventory subtotal, carrying value | $ 213 | $ 452 |
Linefill subtotal, carrying value | 898 | 906 |
Long-term inventory subtotal, carrying value | $ 224 | $ 246 |
Inventory (price/unit of measure) (usd per unit) | $ / bbl | 67.62 | 67.33 |
Linefill (price/unit of measure) (usd per unit) | $ / bbl | 58.98 | 58.53 |
Long-term inventory (price/unit of measure) (usd per unit) | $ / bbl | 68.84 | 79.30 |
NGL | ||
Inventory by category | ||
Inventory, volumes (in barrels) | bbl | 5,084 | 7,285 |
Linefill, volumes (in barrels) | bbl | 2,168 | 1,876 |
Long-term inventory, volumes (in barrels) | bbl | 1,327 | 1,066 |
Inventory subtotal, carrying value | $ 144 | $ 270 |
Linefill subtotal, carrying value | 68 | 55 |
Long-term inventory subtotal, carrying value | $ 46 | $ 38 |
Inventory (price/unit of measure) (usd per unit) | $ / bbl | 28.32 | 37.06 |
Linefill (price/unit of measure) (usd per unit) | $ / bbl | 31.37 | 29.32 |
Long-term inventory (price/unit of measure) (usd per unit) | $ / bbl | 34.66 | 35.65 |
Other | ||
Inventory by category | ||
Inventory subtotal, carrying value | $ 10 | $ 7 |
Debt - Components (Details)
Debt - Components (Details) - USD ($) $ in Millions | Jun. 30, 2023 | Jan. 31, 2023 | Dec. 31, 2022 |
SHORT-TERM DEBT | |||
Total short-term debt | $ 709 | $ 1,159 | |
LONG-TERM DEBT | |||
Senior notes, net | 7,239 | 7,237 | |
Other | 49 | 50 | |
Total long-term debt | 7,288 | 7,287 | |
Total debt | 7,997 | 8,446 | |
Senior Notes | |||
LONG-TERM DEBT | |||
Senior notes, net | 7,239 | 7,237 | |
Unamortized discounts and debt issuance costs | 44 | 46 | |
Debt instrument face value | 8,000 | 8,400 | |
Senior Notes | Level 2 | |||
LONG-TERM DEBT | |||
Debt instrument fair value | 7,300 | 7,600 | |
Other | |||
LONG-TERM DEBT | |||
Other | 49 | 50 | |
Other | |||
SHORT-TERM DEBT | |||
Total short-term debt | 9 | 59 | |
2.85% senior notes due January 2023 | Senior Notes | |||
SHORT-TERM DEBT | |||
Debt instrument, interest rate (as a percent) | 2.85% | ||
2.85% senior notes due January 2023 | Senior Notes | |||
SHORT-TERM DEBT | |||
Total short-term debt | $ 400 | ||
Debt instrument, interest rate (as a percent) | 2.85% | ||
3.85% senior notes due October 2023 | Senior Notes | |||
SHORT-TERM DEBT | |||
Total short-term debt | $ 700 | $ 700 | |
Debt instrument, interest rate (as a percent) | 3.85% |
Debt - Narrative (Details)
Debt - Narrative (Details) - USD ($) $ in Millions | 6 Months Ended | |||
Jan. 31, 2023 | Jun. 30, 2023 | Jun. 30, 2022 | Dec. 31, 2022 | |
Debt | ||||
Repayments of senior notes | $ 400 | $ 750 | ||
Outstanding letters of credit | 127 | $ 102 | ||
2.85% Senior Notes Due in January 2023 | Senior Notes | ||||
Debt | ||||
Debt instrument, interest rate (as a percent) | 2.85% | |||
Repayments of senior notes | $ 400 | |||
Credit Facilities and Commercial Paper Program | ||||
Debt | ||||
Total borrowings | 1,500 | 16,400 | ||
Total repayments | $ 1,500 | $ 16,300 |
Partners' Capital and Distrib_3
Partners' Capital and Distributions - Units Outstanding (Details) - shares | 3 Months Ended | 6 Months Ended | ||
Mar. 31, 2023 | Jun. 30, 2022 | Mar. 31, 2022 | Jun. 30, 2023 | |
Series A Preferred Units | ||||
Activity for preferred units and common units | ||||
Outstanding, beginning of period (units) | 71,090,468 | 71,090,468 | 71,090,468 | 71,090,468 |
Outstanding, end of period (units) | 71,090,468 | 71,090,468 | 71,090,468 | 71,090,468 |
Series B Preferred Units | ||||
Activity for preferred units and common units | ||||
Outstanding, beginning of period (units) | 800,000 | 800,000 | 800,000 | 800,000 |
Outstanding, end of period (units) | 800,000 | 800,000 | 800,000 | 800,000 |
Common Units | ||||
Activity for preferred units and common units | ||||
Outstanding, beginning of period (units) | 698,354,498 | 702,668,178 | 704,991,540 | 698,354,498 |
Repurchase and cancellation of common units under the Common Equity Repurchase Program (units) | (4,876,062) | (2,375,299) | ||
Issuances of common units under equity-indexed compensation plans (units) | 35,508 | 147,830 | 51,937 | 35,508 |
Outstanding, end of period (units) | 698,390,006 | 697,939,946 | 702,668,178 | 698,390,006 |
Partners' Capital and Distrib_4
Partners' Capital and Distributions - Preferred Unit Distributions (Details) - USD ($) $ / shares in Units, $ in Millions | Aug. 15, 2023 | Aug. 14, 2023 | May 15, 2023 | Feb. 15, 2023 | Feb. 14, 2023 | Jan. 31, 2023 | Jun. 30, 2023 |
Series A Preferred Units | |||||||
Partners Capital and Distribution | |||||||
Distribution rate reset, basis spread on variable rate (as a percent) | 5.85% | ||||||
Quarterly distributions per unit (usd per unit) | $ 0.615 | ||||||
Series A Preferred Units | Cash Distribution | |||||||
Partners Capital and Distribution | |||||||
Preferred distributions per unit (usd per unit) | $ 0.585 | $ 0.525 | |||||
Preferred unit distribution amount | $ 42 | $ 37 | |||||
Series A Preferred Units | Cash Distribution | Forecast | |||||||
Partners Capital and Distribution | |||||||
Preferred distributions per unit (usd per unit) | $ 0.615 | ||||||
Preferred unit distribution amount | $ 44 | ||||||
Series B Preferred Units | Cash Distribution | |||||||
Partners Capital and Distribution | |||||||
Preferred distributions per unit (usd per unit) | $ 22.18 | $ 22.27 | |||||
Preferred unit distribution amount | $ 18 | $ 18 | |||||
Series B Preferred Units | Cash Distribution | Other current liabilities | |||||||
Partners Capital and Distribution | |||||||
Amount accrued to distributions payable | $ 10 | ||||||
Series B Preferred Units | Cash Distribution | Forecast | |||||||
Partners Capital and Distribution | |||||||
Preferred distributions per unit (usd per unit) | $ 24.10 | ||||||
Preferred unit distribution amount | $ 19 |
Partners' Capital and Distrib_5
Partners' Capital and Distributions - Distributions (Details) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 6 Months Ended | |||||
Aug. 14, 2023 | May 15, 2023 | Feb. 14, 2023 | Jun. 30, 2023 | Jun. 30, 2022 | Jun. 30, 2023 | Jun. 30, 2022 | |
Partners Capital and Distribution | |||||||
Distributions paid | $ 322 | $ 264 | $ 646 | $ 500 | |||
Cash Distribution | Common Units | |||||||
Partners Capital and Distribution | |||||||
Distributions paid | $ 187 | $ 187 | |||||
Cash distribution per common unit, paid (usd per unit) | $ 0.2675 | $ 0.2675 | |||||
Forecast | Cash Distribution | Common Units | |||||||
Partners Capital and Distribution | |||||||
Distributions paid | $ 187 | ||||||
Cash distribution per common unit, paid (usd per unit) | $ 0.2675 | ||||||
Public | Cash Distribution | Common Units | |||||||
Partners Capital and Distribution | |||||||
Distributions paid | $ 122 | $ 122 | |||||
Public | Forecast | Cash Distribution | Common Units | |||||||
Partners Capital and Distribution | |||||||
Distributions paid | $ 123 | ||||||
AAP | Cash Distribution | Common Units | |||||||
Partners Capital and Distribution | |||||||
Distributions paid | $ 65 | $ 65 | |||||
AAP | Forecast | Cash Distribution | Common Units | |||||||
Partners Capital and Distribution | |||||||
Distributions paid | $ 64 |
Partners' Capital and Distrib_6
Partners' Capital and Distributions - Noncontrolling Interest in Subsidiaries (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2023 | Jun. 30, 2022 | Jun. 30, 2023 | Jun. 30, 2022 | |
Noncontrolling Interest | ||||
Distributions paid | $ 322 | $ 264 | $ 646 | $ 500 |
Permian JV | ||||
Noncontrolling Interest | ||||
Noncontrolling interests in subsidiaries (as a percent) | 35% | 35% | ||
Cactus II | ||||
Noncontrolling Interest | ||||
Noncontrolling interests in subsidiaries (as a percent) | 30% | 30% | ||
Red River | ||||
Noncontrolling Interest | ||||
Noncontrolling interests in subsidiaries (as a percent) | 33% | 33% | ||
Noncontrolling Interests | ||||
Noncontrolling Interest | ||||
Distributions paid | $ 73 | 62 | $ 151 | 121 |
Noncontrolling Interests | Cash Distribution | ||||
Noncontrolling Interest | ||||
Distributions paid | 73 | 62 | 151 | 121 |
Permian JV | Noncontrolling Interests | Cash Distribution | ||||
Noncontrolling Interest | ||||
Distributions paid | 53 | 58 | 111 | 112 |
Cactus II | Noncontrolling Interests | Cash Distribution | ||||
Noncontrolling Interest | ||||
Distributions paid | 15 | 29 | ||
Red River | Noncontrolling Interests | Cash Distribution | ||||
Noncontrolling Interest | ||||
Distributions paid | $ 5 | $ 4 | $ 11 | $ 9 |
Derivatives and Risk Manageme_3
Derivatives and Risk Management Activities - Commodity Price Risk Hedging (Details) bbl in Millions | 6 Months Ended |
Jun. 30, 2023 TWh Bcf bbl | |
Crude oil purchases | Long | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Bcf) | 5 |
Time spread on hedging anticipated crude oil lease gathering purchases | Short | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Bcf) | 6.1 |
Crude oil basis spread position | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Bcf) | 1.9 |
Anticipated net sales of crude oil and NGL inventory | Short | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Bcf) | 10.5 |
Natural gas purchases for processing and operational needs | Long | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Bcf) | Bcf | 38.9 |
Propane contracts related to subsequent sale of products | Short | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Bcf) | 7.5 |
Butane contracts related to subsequent sale of products | Short | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Bcf) | 0.9 |
Condensate sales contracts related to subsequent sale of products | Short | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Bcf) | 0.5 |
Fuel gas requirements | Long | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Bcf) | Bcf | 4.4 |
Power supply requirements | Long | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in Terawatt hours) | TWh | 2.2 |
Derivatives and Risk Manageme_4
Derivatives and Risk Management Activities - Financial Impact (Details) - Derivatives Not Designated as a Hedge - Commodity Derivatives - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2023 | Jun. 30, 2022 | Jun. 30, 2023 | Jun. 30, 2022 | |
Impact of derivative activities recognized in earnings | ||||
Net gain/ (loss) from commodity derivative activity | $ 125 | $ 84 | $ 105 | $ (115) |
Product sales revenues | ||||
Impact of derivative activities recognized in earnings | ||||
Net gain/ (loss) from commodity derivative activity | 119 | 76 | 118 | (136) |
Field operating costs | ||||
Impact of derivative activities recognized in earnings | ||||
Net gain/ (loss) from commodity derivative activity | $ 6 | $ 8 | $ (13) | $ 21 |
Derivatives and Risk Manageme_5
Derivatives and Risk Management Activities - Broker Receivable/Payable (Details) - USD ($) $ in Millions | Jun. 30, 2023 | Dec. 31, 2022 |
Offsetting Assets, Liabilities | ||
Initial margin | $ 46 | $ 93 |
Variation margin returned | (177) | (236) |
Letters of credit | (127) | (102) |
Net broker payable | (156) | (168) |
Exchange Traded | ||
Offsetting Assets, Liabilities | ||
Letters of credit | $ (25) | $ (25) |
Derivatives and Risk Manageme_6
Derivatives and Risk Management Activities - Offsetting Asset and Liabilities (Details) - USD ($) $ in Millions | Jun. 30, 2023 | Dec. 31, 2022 |
Derivative Assets | ||
Effect of Collateral Netting | $ (156) | $ (168) |
Commodity Derivatives | ||
Derivative Assets | ||
Effect of Collateral Netting | (156) | (168) |
Derivative Liabilities | ||
Gross Position - Assets | 226 | 311 |
Gross Position - Liabilities | (63) | (89) |
Net Carrying Value Presented on the Balance Sheet, Total | 7 | 54 |
Other current assets | Commodity Derivatives | ||
Derivative Assets | ||
Gross Position - Assets | 221 | 300 |
Gross Position - Liabilities | (21) | (71) |
Effect of Collateral Netting | (156) | (168) |
Net Carrying Value Presented on the Balance Sheet | 44 | 61 |
Other long-term assets, net | Commodity Derivatives | ||
Derivative Assets | ||
Gross Position - Assets | 3 | 9 |
Gross Position - Liabilities | (5) | |
Net Carrying Value Presented on the Balance Sheet | 3 | 4 |
Other current liabilities | Commodity Derivatives | ||
Derivative Liabilities | ||
Gross Position - Assets | 2 | |
Gross Position - Liabilities | (33) | (13) |
Net Carrying Value Presented on the Balance Sheet | (33) | (11) |
Other long-term liabilities and deferred credits | Commodity Derivatives | ||
Derivative Liabilities | ||
Gross Position - Assets | 2 | |
Gross Position - Liabilities | (9) | |
Net Carrying Value Presented on the Balance Sheet | $ (7) | $ 0 |
Derivatives and Risk Manageme_7
Derivatives and Risk Management Activities - Interest Rate Risk Hedging (Details) - Cash Flow Hedge $ in Millions | 6 Months Ended |
Jun. 30, 2023 USD ($) contract | |
8 forward starting swaps (30-year), 3.09% | |
Interest Rate Risk Hedging | |
Number of interest rate derivatives | contract | 8 |
Term of derivative contract | 30 years |
Notional amount of derivatives | $ | $ 200 |
Average rate locked (as a percent) | 3.09% |
4 forward starting swaps (30-year), 0.74% | |
Interest Rate Risk Hedging | |
Number of interest rate derivatives | contract | 4 |
Term of derivative contract | 30 years |
Notional amount of derivatives | $ | $ 100 |
Average rate locked (as a percent) | 0.74% |
Derivatives and Risk Manageme_8
Derivatives and Risk Management Activities - Net Unrealized Gain/(Loss) Recognized in AOCI (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2023 | Jun. 30, 2022 | Jun. 30, 2023 | Jun. 30, 2022 | Dec. 31, 2022 | |
Derivative assets and liabilities | |||||
Proceeds from settlement of interest rate hedging instruments | $ 80 | ||||
Other current assets | |||||
Derivative assets and liabilities | |||||
Net fair value of interest rate hedges | $ 47 | 47 | $ 75 | ||
Other long-term liabilities and deferred credits | |||||
Derivative assets and liabilities | |||||
Net fair value of interest rate hedges | (5) | (5) | |||
Other long-term assets, net | |||||
Derivative assets and liabilities | |||||
Net fair value of interest rate hedges | $ 45 | ||||
AOCI Cash Flow Hedge | |||||
Derivative assets and liabilities | |||||
Net gain/(loss) deferred in AOCI | (100) | (100) | |||
Interest rate derivatives | |||||
Derivative assets and liabilities | |||||
Interest rate derivatives, net | 8 | $ 36 | 2 | $ 68 | |
Cash Flow Hedge | Interest rate swaps terminated | |||||
Derivative assets and liabilities | |||||
Notional amount of derivatives | 200 | 200 | |||
Proceeds from settlement of interest rate hedging instruments | 80 | ||||
Cash Flow Hedge | Interest rate swaps terminated | AOCI Cash Flow Hedge | |||||
Derivative assets and liabilities | |||||
Net gain/(loss) deferred in AOCI | $ 73 | $ 73 |
Derivatives and Risk Manageme_9
Derivatives and Risk Management Activities - Preferred Distribution Rate Reset Option (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2022 | Jun. 30, 2023 | Jun. 30, 2022 | Jan. 31, 2023 | Dec. 31, 2022 | |
Derivatives and Risk Management Activities | |||||
Gain/(loss) recognized | $ 58 | $ (147) | |||
Preferred Distribution Rate Reset Option | Derivatives Not Designated as a Hedge | |||||
Derivatives and Risk Management Activities | |||||
Derivative liability | $ 131 | $ 189 | |||
Derivative liability [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 | $ (103) | $ 58 | $ (147) |
Derivatives and Risk Managem_10
Derivatives and Risk Management Activities - Fair Value (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2022 | Jun. 30, 2023 | Jun. 30, 2022 | Dec. 31, 2022 | |
Level 3 | ||||
Rollforward of Level 3 Net Asset/(Liability) | ||||
Beginning Balance | $ (44) | $ (189) | $ (2) | |
Net gains/(losses) for the period included in earnings | (103) | 58 | (147) | |
Settlements | 131 | 2 | ||
Ending Balance | (147) | 0 | (147) | |
Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period | $ (103) | $ (147) | ||
Recurring Fair Value Measures | ||||
Recurring Fair Value Measurements | ||||
Total net derivative asset/(liability) | 205 | $ 153 | ||
Recurring Fair Value Measures | Commodity derivatives | ||||
Recurring Fair Value Measurements | ||||
Total net derivative asset/(liability) | 163 | 222 | ||
Recurring Fair Value Measures | Interest rate derivatives | ||||
Recurring Fair Value Measurements | ||||
Total net derivative asset/(liability) | 42 | 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 2 | ||||
Recurring Fair Value Measurements | ||||
Total net derivative asset/(liability) | 196 | 349 | ||
Recurring Fair Value Measures | Level 2 | Commodity derivatives | ||||
Recurring Fair Value Measurements | ||||
Total net derivative asset/(liability) | 154 | 229 | ||
Recurring Fair Value Measures | Level 2 | Interest rate derivatives | ||||
Recurring Fair Value Measurements | ||||
Total net derivative asset/(liability) | 42 | 120 | ||
Recurring Fair Value Measures | Level 3 | ||||
Recurring Fair Value Measurements | ||||
Total net derivative asset/(liability) | $ 0 | (189) | ||
Recurring Fair Value Measures | Level 3 | Preferred Distribution Rate Reset Option | ||||
Recurring Fair Value Measurements | ||||
Total net derivative asset/(liability) | $ (189) |
Related Party Transactions - Pr
Related Party Transactions - Promissory Notes with our General Partner (Details) $ in Millions, $ in Millions | 3 Months Ended | 4 Months Ended | 6 Months Ended | |||
Jun. 30, 2023 USD ($) | Jun. 30, 2022 USD ($) | Jun. 30, 2023 USD ($) | Jun. 30, 2023 USD ($) | Jun. 30, 2022 USD ($) | Jun. 30, 2023 CAD ($) | |
Related Party Transaction [Line Items] | ||||||
Related party interest expense | $ 95 | $ 99 | $ 193 | $ 206 | ||
8.25% note due April 2027 | PAGP | General Partner | ||||||
Related Party Transaction [Line Items] | ||||||
Related party note receivable | 378 | $ 378 | 378 | $ 500 | ||
Related party note payable | 378 | $ 378 | 378 | $ 500 | ||
Related party note payable and receivable interest rate (as a percent) | 8.25% | |||||
Related party interest receivable | 10 | $ 10 | 10 | |||
Related party interest payable | 10 | $ 10 | 10 | |||
Related party interest income | 7 | 10 | ||||
Related party interest expense | $ 7 | $ 10 |
Related Party Transactions - Tr
Related Party Transactions - Transactions with Other Related Parties (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2023 | Jun. 30, 2022 | Jun. 30, 2023 | Jun. 30, 2022 | Dec. 31, 2022 | |
Related Party Transaction [Line Items] | |||||
Revenues from related parties | $ 11,602 | $ 16,359 | $ 23,943 | $ 30,053 | |
Purchases and related costs from related parties | 101 | 87 | 200 | 184 | |
Trade accounts receivable and other receivables, net from related parties | 3,220 | 3,220 | $ 3,907 | ||
Trade accounts payable to related parties | 3,295 | 3,295 | 4,044 | ||
Affiliated Entity | |||||
Related Party Transaction [Line Items] | |||||
Revenues from related parties | 12 | $ 10 | 23 | $ 22 | |
Trade accounts receivable and other receivables, net from related parties | 76 | 76 | 45 | ||
Trade accounts payable to related parties | $ 72 | $ 72 | $ 79 |
Commitments and Contingencies (
Commitments and Contingencies (Details) | 1 Months Ended | 6 Months Ended | 8 Months Ended | 9 Months Ended | 98 Months Ended | |||||||
Oct. 27, 2022 USD ($) | Oct. 14, 2020 USD ($) | Sep. 30, 2021 USD ($) | May 31, 2015 bbl | Jun. 30, 2023 USD ($) lawsuit | Jun. 30, 2022 USD ($) | Jun. 30, 2023 USD ($) lawsuit | Sep. 20, 2022 USD ($) | Jun. 30, 2023 USD ($) lawsuit | Dec. 31, 2022 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 | $ 740,000,000 | $ 740,000,000 | 740,000,000 | |||||||||
Significant costs related to legal and environmental remediation matters | 0 | $ 85,000,000 | ||||||||||
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 | ||||||||||||
Amount paid to plaintiff | $ 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 | ||||||||||||
Amount paid to plaintiff | $ 22,325,000 | |||||||||||
Line 901 Incident | May 2016 Indictment | ||||||||||||
Legal, Environmental or Regulatory Matters | ||||||||||||
Number of felony discharges 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 found 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 Lawsuits | ||||||||||||
Legal, Environmental or Regulatory Matters | ||||||||||||
Number of cases filed | lawsuit | 9 | |||||||||||
Line 901 Incident | Class Action Lawsuits | Pending Litigation | ||||||||||||
Legal, Environmental or Regulatory Matters | ||||||||||||
Number of proceedings pending | lawsuit | 2 | 2 | 2 | |||||||||
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 | 240,000,000 | 240,000,000 | 240,000,000 | |||||||||
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 | 98,000,000 | 98,000,000 | 98,000,000 | |||||||||
Excluding Line 901 Incident | ||||||||||||
Legal, Environmental or Regulatory Matters | ||||||||||||
Estimated undiscounted reserve for environmental liabilities | 55,000,000 | 55,000,000 | 55,000,000 | $ 55,000,000 | ||||||||
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 | $ 45,000,000 | $ 45,000,000 | $ 45,000,000 | $ 45,000,000 | ||||||||
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) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2023 USD ($) | Jun. 30, 2022 USD ($) | Jun. 30, 2023 USD ($) segment | Jun. 30, 2022 USD ($) | |
Segment Reporting Information | ||||
Operating segments number | segment | 2 | |||
Reportable segments number | segment | 2 | |||
Revenues: | ||||
Revenues | $ 11,602 | $ 16,359 | $ 23,943 | $ 30,053 |
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments | ||||
Equity earnings in unconsolidated entities | 89 | 104 | 178 | 201 |
Segment Adjusted EBITDA | 591 | 614 | 1,300 | 1,227 |
Maintenance capital expenditures | 62 | 43 | 109 | 70 |
Product sales | ||||
Revenues: | ||||
Revenues | 11,201 | 16,007 | 23,145 | 29,388 |
Services | ||||
Revenues: | ||||
Revenues | 401 | 352 | 798 | 665 |
Operating Segments | ||||
Revenues: | ||||
Revenues | 11,676 | 16,510 | 24,124 | 30,323 |
Intersegment Revenues Elimination | ||||
Revenues: | ||||
Revenues | (74) | (151) | (181) | (270) |
Intersegment Revenues Elimination | Product sales | ||||
Revenues: | ||||
Revenues | (70) | (143) | (170) | (254) |
Intersegment Revenues Elimination | Services | ||||
Revenues: | ||||
Revenues | (4) | (8) | (11) | (16) |
Crude Oil | ||||
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments | ||||
Equity earnings in unconsolidated entities | 89 | 104 | 178 | 201 |
Segment Adjusted EBITDA | 529 | 494 | 1,046 | 946 |
Maintenance capital expenditures | 36 | 25 | 67 | 45 |
Crude Oil | Operating Segments | ||||
Revenues: | ||||
Revenues | 11,295 | 15,940 | 23,053 | 29,019 |
Crude Oil | Operating Segments | Product sales | ||||
Revenues: | ||||
Revenues | 10,925 | 15,625 | 22,333 | 28,435 |
Crude Oil | Operating Segments | Services | ||||
Revenues: | ||||
Revenues | 370 | 315 | 720 | 584 |
NGL | ||||
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments | ||||
Segment Adjusted EBITDA | 62 | 120 | 254 | 281 |
Maintenance capital expenditures | 26 | 18 | 42 | 25 |
NGL | Operating Segments | ||||
Revenues: | ||||
Revenues | 381 | 570 | 1,071 | 1,304 |
NGL | Operating Segments | Product sales | ||||
Revenues: | ||||
Revenues | 346 | 525 | 982 | 1,207 |
NGL | Operating Segments | Services | ||||
Revenues: | ||||
Revenues | $ 35 | $ 45 | $ 89 | $ 97 |
Segment Information - Segment A
Segment Information - Segment Adjusted EBITDA Reconciliation (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2023 | Jun. 30, 2022 | Jun. 30, 2023 | Jun. 30, 2022 | |
Segment Reporting Information | ||||
Segment Adjusted EBITDA | $ 591 | $ 614 | $ 1,300 | $ 1,227 |
Adjustments: | ||||
Depreciation and amortization of unconsolidated entities | (24) | (17) | (47) | (37) |
Derivative activities and inventory valuation adjustments | 86 | 75 | (6) | (13) |
Long-term inventory costing adjustments | (2) | 13 | (31) | 105 |
Deficiencies under minimum volume commitments, net | 2 | (10) | 9 | (15) |
Equity-indexed compensation expense | (8) | (7) | (17) | (15) |
Foreign currency revaluation | (19) | (3) | (15) | (1) |
Adjusted EBITDA attributable to noncontrolling interests | 103 | 89 | 200 | 166 |
Depreciation and amortization | (259) | (242) | (515) | (473) |
Gains/(losses) on asset sales and asset impairments, net | (3) | 3 | 150 | 46 |
Interest expense, net | (95) | (99) | (193) | (206) |
Other income/(expense), net | 20 | (118) | 85 | (155) |
INCOME BEFORE TAX | 392 | 298 | 920 | 544 |
Income tax expense | (43) | (47) | (96) | (68) |
Net income | 349 | 251 | 824 | 476 |
Net income attributable to noncontrolling interests | (56) | (48) | (109) | (86) |
Net income attributable to PAA | $ 293 | $ 203 | 715 | 390 |
Line 901 Incident | ||||
Adjustments: | ||||
Line 901 incident | $ 0 | $ (85) |
Acquisitions and Divestitures (
Acquisitions and Divestitures (Details) $ in Millions | 1 Months Ended | 3 Months Ended | 6 Months Ended | ||||
Jul. 28, 2023 USD ($) | Feb. 28, 2023 USD ($) | Jun. 30, 2023 USD ($) | Jun. 30, 2022 USD ($) | Jun. 30, 2023 USD ($) | Jun. 30, 2022 USD ($) | Dec. 31, 2022 USD ($) | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations | |||||||
Gains/(losses) on asset sales and asset impairments, net | $ (3) | $ 3 | $ 150 | $ 46 | |||
Keyera Fort Saskatchewan Facility | |||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations | |||||||
Undivided joint interest ownership percentage, sold | 0.21 | ||||||
Proceeds from sale of undivided joint interest | $ 270 | ||||||
Gains/(losses) on asset sales and asset impairments, net | $ 140 | ||||||
Keyera Fort Saskatchewan Facility | Other current assets | |||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations | |||||||
Assets held for sale | $ 130 | ||||||
OMOG JV LLC | |||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations | |||||||
Ownership interest in unconsolidated entity prior to acquisition | 57% | 57% | |||||
Subsequent Event | OMOG JV LLC | |||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations | |||||||
Ownership interests acquired percentage | 43% | ||||||
Acquisition amount, net to our interest in the Permian JV | $ 145 | ||||||
Ownership interest after acquisition percentage | 100% | ||||||
Subsequent Event | OMOG JV LLC | Permian JV | |||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations | |||||||
Ownership interest in the Permian JV | 65% | ||||||
Subsequent Event | OMOG JV LLC | Permian JV | |||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations | |||||||
Acquisition amount | $ 225 |