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目次
UNITED STATES
証券取引委員会
ワシントンDC20549
________________________________________________________________
フォーム10-Q
________________________________________________________________________________________________________________________________
 
☑      証券取引法第13条または15条（d）に基づく四半期報告書
 
報告期間が終了した2023年6月30日をもって2024年9月30日
 
または
 
☐      証券取引法第13条または15(d)条に基づく移行報告書
 
報告書番号：1-14569
________________________________________________________________

プレーンズオールアメリカンパイプライン、L.P.
（会社設立時の指定名）
デラウェア 76-0582150
（設立または組織の州または管轄区域） （国税庁雇用者識別番号）

333 Clay Street, スイート1600
ヒューストン, テキサス州 77002
（主要経営事務所の住所）（郵便番号）
(713) 646-4100
（登録者の電話番号（市外局番を含む））
________________________________________________________________
法第12条（b）に基づく登録証券
各クラスの名称取引シンボル登録されている各取引所の名称
コモンユニットPAAナスダック
 
申請者が、(1) 前口上書13条または15(d)の規定に基づいて過去12ヶ月間(またはそのような短い期間の報告が必要な場合はそのような期間)に提出すべきすべての報告書を提出したこと、および(2) 過去90日間にわたってそのような報告書の提出要件の対象となっているかどうかをチェックマークで示す。☑ はい  ☐ いいえ
規定に基づき、申請者が過去12か月間（または申請者がこれらのファイルを提出する必要があったより短い期間）に提出すべきあらゆるインタラクティブ・データ・ファイルを電子的に提出したかどうかをチェックマークで示してください。 ☑ はい  ☐ いいえ
登録者が大量加速提出者、加速提出者、非加速提出者、報告書提出規模の小さい企業、または新興成長企業のいずれであるかをチェックマークで示してください。 「大量加速提出者」、「加速提出者」、「報告書提出規模の小さい企業」、「新興成長企業」の定義については、Exchange Actの規則120億2を参照してください。
大型加速ファイラー☑ 加速度ファイラー☐
非加速度ファイラー☐ 小規模報告会社☐
 新興成長企業☐
 新興成長企業の場合、会計基準に関してセクション13(a)に基づいて提供される新しいまたは改訂された財務会計基準の遵守に対する拡張移行期間を使用しないことを選択した場合は、チェックマークで示してください。☐ 
登録者が取引所法第120億2条で定義されるシェル企業であるかどうかをチェックマークで示してください。☐はい☑ いいえ
2024年10月31日現在、 703,669,059 一般的な未発行株式。


目次
プレーンズオールアメリカンパイプライン、L.P.および子会社
目次
 ページ
 
 
 
  
  
 

2
目次
第I部。財務情報 
第1項。 未監査の要約連結財務諸表
プレーンズオールアメリカンパイプライン、L.P.および子会社
連結簡易貸借対照表
(百万単位で、単位データを除く)
9月30日,
2024		12月31日
2023
 (未監査)
資産  
流動資産  
現金及び現金同等物$640 $450 
売掛金およびその他の債権（手形、受取手形）の合計額3,952 3,760 
在庫436 548 
その他の流動資産141 155 
流動資産合計5,169 4,913 
固定資産21,464 21,143 
累計償却費(5,813)(5,361)
有形固定資産、正味額15,651 15,782 
その他の資産  
非連結事業体への投資2,846 2,820 
無形資産、純額1,674 1,875 
Linefill991 976 
Long-term operating lease right-of-use assets, net298 313 
新規買の在庫257 265 
その他の新規買資産（純）269 411 
総資産$27,155 $27,355 
負債およびパートナー資本  
流動負債  
取引債務$3,675 $3,844 
短期債務765 446 
その他の流動負債696 713 
流動負債合計5,136 5,003 
長期負債  
優先債債権, 純7,140 7,242 
その他の長期債務、純額72 63 
新規買オペレーティングリース債務269 274 
その他の長期負債および未払金1,006 1,041 
長期負債の合計 8,487 8,620 
コミットメントおよびコンティンジェンシーズ（注9）
パートナーズ資本  
シリーズAの優先出資者（71,090,468 と 71,090,468 単位の発行数: それぞれ）
1,513 1,509 
シリーズbの優先出資者（800,000 と 800,000 それぞれの発行残高はユニットです)
787 787 
一般出資者 (703,669,059 と 701,008,749 それぞれの発行残高はユニットです)
7,935 8,126 
非支配株主持分を除く合計パートナー資本10,235 10,422 
非支配株主持分3,297 3,310 
総パートナーズ・キャピタル13,532 13,732 
総負債およびパートナーズ・キャピタル$27,155 $27,355 
添付の注記は、これらの要約された連結財務諸表の一部を構成しています。
3
目次
プレーンズオールアメリカンパイプライン、L.P.および子会社
簡易合算損益計算書
(百万単位、1ユニットあたりのデータを除く)
終了した三ヶ月間
9月30日,		終了した9か月間
9月30日,
 2024202320242023
 (未監査)(未監査)
収益    
製品販売収益$12,282 $11,581 $36,321 $34,726 
サービスの収益461 490 1,350 1,288 
収益合計12,743 12,071 37,671 36,014 
コストおよび費用    
購入と関連費用11,557 11,106 34,333 32,972 
フィールド運用コスト483 372 1,191 1,062 
一般管理費用98 92 287 263 
減価償却費および償却費257 260 769 776 
(儲け)/資産売却による損失, 調整後
1 7 1 (144)
総費用及び経費12,396 11,837 36,581 34,929 
営業利益347 234 1,090 1,085 
その他の収入/(費用)    
無から抜けたエンティティにおける株主資産益97 99 298 277 
持分法関連投資の利益
— 29 — 28 
利子費用（$ の資本利息相殺後）2, $3, $7および1,3888、それぞれ）
(113)(97)(318)(290)
その他の収入、純額
26 — 45 85 
税引前利益357 265 1,115 1,185 
現在の所得税費用(20)(22)(143)(104)
繰延所得税(費用)/収益
(25)36 21 22 
当期純利益312 279 993 1,103 
非支配持分に帰属する当期純利益(92)(76)(257)(185)
PAAに帰属する当期純利益$220 $203 $736 $918 
当期純利益（1株当たり）（注3）：    
普通出資者に割り当てられる当期純利益―基本と希薄$157 $140 $540 $728 
基本および希薄の加重平均普通受益証券数702 700 702 699 
普通株1株当たり当期純利益（基本および希薄）$0.22 $0.20 $0.77 $1.04 


The accompanying notes are an integral part of these condensed consolidated financial statements.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in millions)
 
Three Months Ended
September 30,		Nine Months Ended
September 30,
 2024202320242023
 (unaudited)(unaudited)
Net income$312 $279 $993 $1,103 
Other comprehensive income/(loss)
36 (35)(68)50 
Comprehensive income348 244 925 1,153 
Comprehensive income attributable to noncontrolling interests
(92)(76)(257)(185)
Comprehensive income attributable to PAA$256 $168 $668 $968 
 
The accompanying notes are an integral part of these condensed consolidated financial statements.


PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)
(in millions)

Derivative
Instruments		Translation
Adjustments		OtherTotal
 (unaudited)
Balance at December 31, 2023$(81)$(755)$— $(836)
Reclassification adjustments6 — — 6 
Unrealized gain on hedges9 — — 9 
Currency translation adjustments— (84)— (84)
Other— — 1 1 
Total period activity15 (84)1 (68)
Balance at September 30, 2024$(66)$(839)$1 $(904)

Derivative
Instruments		Translation
Adjustments		OtherTotal
 (unaudited)
Balance at December 31, 2022$(107)$(846)$(1)$(954)
Reclassification adjustments8 — — 8 
Unrealized gain on hedges40 — — 40 
Currency translation adjustments— 2 — 2 
Total period activity48 2 — 50 
Balance at September 30, 2023$(59)$(844)$(1)$(904)
 
The accompanying notes are an integral part of these condensed consolidated financial statements.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
Nine Months Ended
September 30,
 20242023
 (unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES  
Net income$993 $1,103 
Reconciliation of net income to net cash provided by operating activities:  
Depreciation and amortization769 776 
(Gains)/losses on asset sales, net1 (144)
Deferred income tax benefit(21)(22)
Gain on foreign currency revaluation(16)(4)
Settlement of terminated interest rate hedging instruments (Note 7)57 80 
Change in fair value of Preferred Distribution Rate Reset Option (Note 7)— (58)
Equity earnings in unconsolidated entities(298)(277)
Distributions on earnings from unconsolidated entities383 351 
Gain on investment in unconsolidated entities— (28)
Other52 53 
Changes in assets and liabilities, net of acquisitions(157)(114)
Net cash provided by operating activities1,763 1,716 
CASH FLOWS FROM INVESTING ACTIVITIES  
Cash paid in connection with acquisitions, net of cash acquired(144)(289)
Investments in unconsolidated entities(4)(28)
Additions to property, equipment and other(453)(404)
Cash paid for purchases of linefill(21)(19)
Proceeds from sales of assets8 286 
Cash received from sales of linefill— 9 
Investments in related party notes (Note 8)(629)— 
Other investing activities3 1 
Net cash used in investing activities(1,240)(444)
CASH FLOWS FROM FINANCING ACTIVITIES  
Net repayments under commercial paper program (Note 5)(433)— 
Proceeds from the issuance of senior notes (Note 5)650 — 
Repayments of senior notes— (400)
Proceeds from the issuance of related party notes (Note 8)629 — 
Distributions paid to Series A preferred unitholders (Note 6)(131)(123)
Distributions paid to Series B preferred unitholders (Note 6)(59)(55)
Distributions paid to common unitholders (Note 6)(668)(560)
Distributions paid to noncontrolling interests (Note 6)(310)(237)
Contributions from noncontrolling interests40 53 
Other financing activities(48)(87)
Net cash used in financing activities(330)(1,409)
Effect of translation adjustment(3)(4)
Net increase/(decrease) in cash and cash equivalents and restricted cash190 (141)
Cash and cash equivalents and restricted cash, beginning of period450 401 
Cash and cash equivalents and restricted cash, end of period$640 $260 
Cash paid for:  
Interest, net of amounts capitalized$269 $247 
Income taxes, net of amounts refunded$236 $28 
The accompanying notes are an integral part of these condensed consolidated financial statements.
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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL
(in millions)

 Limited PartnersPartners’
Capital Excluding Noncontrolling Interests		Noncontrolling InterestsTotal
Partners’
Capital
Preferred UnitholdersCommon
Unitholders
Series ASeries B
 (unaudited)
Balance at December 31, 2023$1,509 $787 $8,126 $10,422 $3,310 $13,732 
Net income131 59 546 736 257 993 
Distributions (Note 6)(131)(59)(668)(858)(310)(1,168)
Other comprehensive loss— — (68)(68)— (68)
Contributions from noncontrolling interests— — — — 40 40 
Other4 — (1)3 — 3 
Balance at September 30, 2024$1,513 $787 $7,935 $10,235 $3,297 $13,532 
Limited PartnersPartners’
Capital Excluding Noncontrolling Interests		Noncontrolling InterestsTotal
Partners’
Capital
Preferred UnitholdersCommon
Unitholders
Series ASeries B
(unaudited)
Balance at June 30, 2024$1,512 $787 $7,977 $10,276 $3,302 $13,578 
Net income44 19 157 220 92 312 
Distributions (Note 6)(44)(19)(223)(286)(113)(399)
Other comprehensive income— — 36 36 — 36 
Contributions from noncontrolling interests— — — — 16 16 
Other1 — (12)(11)— (11)
Balance at September 30, 2024$1,513 $787 $7,935 $10,235 $3,297 $13,532 

The accompanying notes are an integral part of these condensed consolidated financial statements.
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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL
(continued)
(in millions)


 Limited PartnersPartners’
Capital Excluding Noncontrolling Interests		Noncontrolling InterestsTotal
Partners’
Capital
Preferred UnitholdersCommon
Unitholders
Series ASeries B
 (unaudited)
Balance at December 31, 2022$1,505 $787 $7,765 $10,057 $3,268 $13,325 
Net income129 56 733 918 185 1,103 
Distributions(129)(56)(560)(745)(237)(982)
Other comprehensive income— — 50 50 — 50 
Contributions from noncontrolling interests— — — — 53 53 
Other3 — 2 5 (3)2 
Balance at September 30, 2023$1,508 $787 $7,990 $10,285 $3,266 $13,551 
Limited PartnersPartners’
Capital Excluding Noncontrolling Interests		Noncontrolling InterestsTotal
Partners’
Capital
Preferred UnitholdersCommon
Unitholders
Series ASeries B
(unaudited)
Balance at June 30, 2023$1,507 $787 $8,085 $10,379 $3,223 $13,602 
Net income44 19 140 203 76 279 
Distributions(44)(19)(187)(250)(86)(336)
Other comprehensive loss— — (35)(35)— (35)
Contributions from noncontrolling interests— — — — 53 53 
Other1 — (13)(12)— (12)
Balance at September 30, 2023$1,508 $787 $7,990 $10,285 $3,266 $13,551 

The accompanying notes are an integral part of these condensed consolidated financial statements.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 
Note 1—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 crude oil 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 September 30, 2024, AAP also owned a limited partner interest in us through its ownership of approximately 232.9 million of our common units (approximately 30% of our total outstanding common units and Series A preferred units combined). Plains All American GP LLC (“GP LLC”), a Delaware limited liability company, is AAP’s general partner. Plains GP Holdings, L.P. (“PAGP”) is the sole and managing member of GP LLC, and, at September 30, 2024, owned an approximate 85% 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. References to “Plains entities,” as the context requires, include any or all of PAA and its subsidiaries and our general partner.
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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Definitions
 
Additional defined terms may be 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
OECD
=
Organisation for Economic Co-operation and Development
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 2023 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, 2023 was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the three and nine months ended September 30, 2024 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.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Recent Accounting Pronouncements, Disclosure Rules and Other Legislation

Except as discussed in our 2023 Annual Report on Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the nine months ended September 30, 2024 that are of significance or potential significance to us.

SEC Climate Disclosure Rules

In March 2024, the SEC adopted final rules (“climate disclosure rules”) requiring registrants to disclose, among other things, information about material climate-related risks and their impact on a registrant’s strategy, business model and outlook; information about material direct and indirect greenhouse gas emissions (Scope 1 and Scope 2), which are subject to assurance requirements; and the financial statement effects of severe weather events and other natural conditions. Such disclosure requirements will begin phasing in for annual periods beginning in 2025. In April 2024, the SEC stayed the climate disclosure rules pending resolution of legal challenges. We are currently evaluating the climate disclosure rules to determine the impact on our related disclosures.

International Tax Reform

Recently, several countries, including Canada, have enacted legislation to implement key aspects of the global minimum top-up tax in accordance with the Pillar Two model rules of the OECD tax framework. We continue to evaluate the new legislation, but do not currently expect a material impact on our financial position, results of operations or cash flows.

Note 2—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 2023 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
September 30,		Nine Months Ended
September 30,
2024202320242023
Crude Oil segment revenues from contracts with customers
Sales$12,046 $11,525 $35,560 $33,843 
Transportation321 333 915 839 
Terminalling, Storage and Other100 99 286 284 
Total Crude Oil segment revenues from contracts with customers$12,467 $11,957 $36,761 $34,966 

Three Months Ended
September 30,		Nine Months Ended
September 30,
2024202320242023
NGL segment revenues from contracts with customers
Sales$292 $283 $1,194 $1,168 
Transportation8 7 26 23 
Terminalling, Storage and Other18 23 59 74 
Total NGL segment revenues from contracts with customers$318 $313 $1,279 $1,265 

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 September 30, 2024Crude OilNGLTotal
Revenues from contracts with customers$12,467 $318 $12,785 
Other revenues(23)70 47 
Total revenues of reportable segments$12,444 $388 $12,832 
Intersegment revenues elimination(89)
Total revenues$12,743 
Three Months Ended September 30, 2023Crude OilNGLTotal
Revenues from contracts with customers$11,957 $313 $12,270 
Other revenues(23)(71)(94)
Total revenues of reportable segments$11,934 $242 $12,176 
Intersegment revenues elimination(105)
Total revenues$12,071 
Nine Months Ended September 30, 2024Crude OilNGLTotal
Revenues from contracts with customers$36,761 $1,279 $38,040 
Other revenues
— (90)(90)
Total revenues of reportable segments$36,761 $1,189 $37,950 
Intersegment revenues elimination
(279)
Total revenues$37,671 
Nine Months Ended September 30, 2023Crude OilNGLTotal
Revenues from contracts with customers$34,966 $1,265 $36,231 
Other revenues
22 47 69 
Total revenues of reportable segments$34,988 $1,312 $36,300 
Intersegment revenues elimination
(286)
Total revenues$36,014 

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 DeficienciesFinancial Statement ClassificationSeptember 30,
2024		December 31,
2023
Billed and collectedOther current liabilities$68 $77 

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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, 2023$228 
Amounts recognized as revenue(37)
Additions36 
Other(5)
Balance at September 30, 2024$222 

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 September 30, 2024 (in millions):

Remainder of 202420252026202720282029 and Thereafter
Pipeline revenues supported by minimum volume commitments and capacity agreements (1)
$98 $400 $267 $225 $181 $245 
Terminalling, storage and other agreement revenues66 239 194 175 142 801 
Total$164 $639 $461 $400 $323 $1,046 
(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

At September 30, 2024 and December 31, 2023, 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.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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):
September 30,
2024		December 31,
2023
Trade accounts receivable arising from revenues from contracts with customers
$4,043 $3,999 
Other trade accounts receivables and other receivables (1)
7,740 7,535 
Impact due to contractual rights of offset with counterparties(7,831)(7,774)
Trade accounts receivable and other receivables, net$3,952 $3,760 
(1)The balance is comprised primarily of accounts receivable associated with buy/sell arrangements that are not within the scope of ASC 606.

Note 3—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 11 and Note 17 to our Consolidated Financial Statements included in Part IV of our 2023 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 nine months ended September 30, 2024 and 2023 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
September 30,		Nine Months Ended
September 30,
 2024202320242023
Basic and Diluted Net Income per Common Unit    
Net income attributable to PAA$220 $203 $736 $918 
Distributions to Series A preferred unitholders
(44)(44)(131)(129)
Distributions to Series B preferred unitholders
(19)(19)(59)(56)
Amounts allocated to participating securities(1)(1)(9)(8)
Other
1 1 3 3 
Net income allocated to common unitholders (1)
$157 $140 $540 $728 
Basic and diluted weighted average common units outstanding702 700 702 699 
Basic and diluted net income per common unit$0.22 $0.20 $0.77 $1.04 
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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(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.

Note 4—Inventory, Linefill and Long-term Inventory
 
Inventory, linefill and long-term inventory consisted of the following (barrels in thousands and carrying value in millions):

 September 30, 2024December 31, 2023
 VolumesUnit of
Measure		Carrying
Value
Price/
Unit (1)
VolumesUnit of
Measure		Carrying
Value
Price/
Unit (1)
Inventory        
Crude oil2,618 barrels$180 $68.75 5,877 barrels$383 $65.17 
NGL9,425 barrels238 $25.25 5,957 barrels154 $25.85 
OtherN/A 18 N/AN/A 11 N/A
Inventory subtotal  436    548  
Linefill        
Crude oil15,644 barrels925 $59.13 15,409 barrels909 $58.99 
NGL2,243 barrels66 $29.42 2,168 barrels67 $30.90 
Linefill subtotal  991    976  
Long-term inventory        
Crude oil3,240 barrels221 $68.21 3,256 barrels232 $71.25 
NGL1,355 barrels36 $26.57 1,326 barrels33 $24.89 
Long-term inventory subtotal  257    265  
Total  $1,684    $1,789  
(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.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 5—Debt
 
Debt consisted of the following (in millions):

September 30,
2024		December 31,
2023
SHORT-TERM DEBT  
Commercial paper notes, bearing a weighted-average interest rate of 5.8% (1)
$— $433 
Senior notes:
3.60% senior notes due November 2024 (2)
750 — 
Other15 13 
Total short-term debt765 446 
LONG-TERM DEBT
Senior notes, net of unamortized discounts and debt issuance costs of $43 and $41, respectively (2)
7,140 7,242 
Other72 63 
Total long-term debt7,212 7,305 
Total debt (3)
$7,977 $7,751 
(1)We classified these commercial paper notes as short-term as of December 31, 2023, as these notes were primarily designated as working capital borrowings, were required to be repaid within one year and were primarily for hedged NGL and crude oil inventory and NYMEX and ICE margin deposits.
(2)As of December 31, 2023, we classified our $750 million, 3.60% senior notes due November 2024 as long-term based on our ability and intent to refinance the notes on a long-term basis at that time. We redeemed these senior notes on November 1, 2024.
(3)Our fixed-rate senior notes had a face value of approximately $7.9 billion and $7.3 billion as of September 30, 2024 and December 31, 2023, respectively. We estimated the aggregate fair value of these notes as of September 30, 2024 and December 31, 2023 to be approximately $7.7 billion and $6.9 billion, respectively. Our fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near the end of the reporting period. We estimate that the carrying value of outstanding borrowings under our commercial paper program approximates fair value as interest rates reflect current market rates. The fair value estimates for our senior notes and commercial paper program are based upon observable market data and are classified in Level 2 of the fair value hierarchy.

Senior Notes

In June 2024, we completed the offering of $650 million, 5.70% senior notes due September 2034 at a public offering price of 99.953%. Interest payments are due on March 15 and September 15 of each year, commencing on March 15, 2025.

Credit Facilities

In August 2024, we amended our credit facility agreements to, among other things, extend the maturity dates of our senior secured hedged inventory facility and senior unsecured revolving credit facility by one year to August 2027 and August 2029, respectively, for each extending lender. The maturity dates with respect to the non-extending lender under our senior secured hedged inventory facility and senior unsecured revolving credit facility (which represents a commitment of approximately $64 million out of total commitments of $1.35 billion from all lenders under each facility) remain August 2026 and August 2027, respectively.

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Borrowings and Repayments
 
Total borrowings under our commercial paper program for the nine months ended September 30, 2024 and 2023 were approximately $20.7 billion and $4.9 billion, respectively. Total repayments under our commercial paper program were approximately $21.1 billion and $4.9 billion for the nine months ended September 30, 2024 and 2023, respectively. The variance in total gross borrowings and repayments is impacted by various business and financial factors including, but not limited to, the timing, average term and method of general partnership borrowing activities.

Letters of Credit
 
In connection with our merchant activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil and NGL. Additionally, we issue letters of credit to support insurance programs, derivative transactions, including hedging-related margin obligations, and construction activities. At September 30, 2024 and December 31, 2023, we had outstanding letters of credit of $108 million and $205 million, respectively.

Note 6—Partners’ Capital and Distributions
 
Units Outstanding
 
The following tables present the activity for our preferred and common units:

 Limited Partners
 Series A Preferred UnitsSeries B Preferred UnitsCommon Units
Outstanding at December 31, 202371,090,468 800,000 701,008,749 
Issuances of common units under equity-indexed compensation plans— — 62,282 
Outstanding at March 31, 202471,090,468 800,000 701,071,031 
Issuances of common units under equity-indexed compensation plans— — 10,268 
Outstanding at June 30, 202471,090,468 800,000 701,081,299 
Issuances of common units under equity-indexed compensation plans— — 2,587,760 
Outstanding at September 30, 202471,090,468 800,000 703,669,059 
 
 Limited Partners
 Series A Preferred UnitsSeries B Preferred UnitsCommon Units
Outstanding at December 31, 202271,090,468 800,000 698,354,498 
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 
Issuances of common units under equity-indexed compensation plans— — 2,602,506 
Outstanding at September 30, 202371,090,468 800,000 700,992,512 

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Distributions

Series A Preferred Unit Distributions. Distributions on the Series A preferred units accumulate and are payable quarterly within 45 days following the end of each quarter. See Note 11 to our Consolidated Financial Statements included in Part IV of our 2023 Annual Report on Form 10-K for additional information regarding Series A preferred unit distributions. The following table details distributions to our Series A preferred unitholders paid during or pertaining to the first nine months of 2024 (in millions, except per unit data):

Series A Preferred Unitholders
Distribution Payment DateCash DistributionDistribution per Unit
November 14, 2024 (1)
$44 $0.615 
August 14, 2024$44 $0.615 
May 15, 2024$44 $0.615 
February 14, 2024$44 $0.615 
(1)Payable to unitholders of record at the close of business on October 31, 2024 for the period from July 1, 2024 through September 30, 2024. At September 30, 2024, 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 11 to our Consolidated Financial Statements included in Part IV of our 2023 Annual Report on Form 10-K for additional information regarding 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 DateCash Distribution Distribution per Unit
November 15, 2024 (1)
$19 $24.25 
August 15, 2024$20 $24.77 
May 15, 2024$19 $24.20 
February 15, 2024$20 $24.92 
(1)Payable to unitholders of record at the close of business on November 1, 2024 for the period from August 15, 2024 through November 14, 2024. At September 30, 2024, 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 nine months of 2024 (in millions, except per unit data):

Distributions
Distribution per Common Unit
Common UnitholdersTotal Cash Distribution
Distribution Payment DatePublicAAP
November 14, 2024 (1)
$149 $74 $223 $0.3175 
August 14, 2024$149 $74 $223 $0.3175 
May 15, 2024$149 $74 $223 $0.3175 
February 14, 2024$149 $74 $223 $0.3175 
(1)Payable to unitholders of record at the close of business on October 31, 2024 for the period from July 1, 2024 through September 30, 2024.
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Noncontrolling Interests in Subsidiaries

As of September 30, 2024, 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”).

Distributions to Noncontrolling Interests

The following table details distributions paid to noncontrolling interests during the periods presented (in millions):

Three Months Ended
September 30,		Nine Months Ended
September 30,
2024202320242023
Permian JV$87 $67 $235 $178 
Cactus II
20 14 56 43 
Red River6 5 19 16 
$113 $86 $310 $237 

Note 7—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 September 30, 2024 and December 31, 2023, 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.

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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 September 30, 2024, net derivative positions related to these activities included:
 
•A net long position of 14.1 million barrels associated with our crude oil purchases, which was unwound ratably during October 2024 to match monthly average pricing.
•A net short time spread position of 3.2 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through November 2025.
•A net crude oil basis spread position of 5.7 million barrels at multiple locations through December 2025. These derivatives allow us to lock in grade and location basis differentials.
•A net short position of 17.2 million barrels through December 2028 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 September 30, 2024:

Notional Volume
(Short)/LongRemaining Tenor
Natural gas purchases
37.8 Bcf
December 2025
Propane sales
(6.6) MMbls
December 2025
Butane sales
(1.5) MMbls
September 2025
Condensate sales
(1.4) MMbls
March 2025
Fuel gas requirements (1)
2.7 Bcf
December 2025
Power supply requirements (1)
2.1 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.

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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
September 30,		Nine Months Ended
September 30,
 2024202320242023
Product sales revenues$29 $(142)$(195)$(24)
Field operating costs(9)(17)(35)(30)
   Net gain/(loss) from commodity derivative activity
$20 $(159)$(230)$(54)

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):

September 30,
2024		December 31,
2023
Initial margin$104 $77 
Variation margin posted/(returned)
46 (65)
Letters of credit
(33)(25)
   Net broker receivable/(payable)
$117 $(13)

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.

September 30, 2024December 31, 2023
Effect of Collateral NettingNet Carrying Value Presented on the Balance SheetEffect of Collateral NettingNet Carrying Value Presented on the Balance Sheet
Commodity DerivativesCommodity Derivatives
AssetsLiabilitiesAssetsLiabilities
Derivative Assets
Other current assets$59 $(83)$117 $93 $153 $(79)$(13)$61 
Other long-term assets, net1 — — 1 3 — — 3 
Derivative Liabilities
Other current liabilities3 (45)— (42)1 (64)— (63)
Other long-term liabilities and deferred credits3 (26)— (23)1 (15)— (14)
Total$66 $(154)$117 $29 $158 $(158)$(13)$(13)

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.

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The following table summarizes the terms of our outstanding interest rate derivatives as of September 30, 2024 (notional amounts in millions):

Hedged TransactionNumber and Types of
Derivatives Employed		Notional
Amount		Expected
Termination Date		Average Rate
Locked		Accounting
Treatment
Anticipated interest payments
8 forward starting swaps
(30-year)
$200 6/15/20263.09%Cash flow hedge
 
During the nine months ended September 30, 2024, we terminated $100 million of notional interest hedging instruments for proceeds of $57 million, which was recorded in AOCI. As of September 30, 2024, there was a net loss of $66 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 September 30, 2024; 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
September 30,		Nine Months Ended
September 30,
 2024202320242023
Interest rate derivatives, net$(9)$38 $9 $40 

At September 30, 2024, the net fair value of our interest rate hedges, which were included in “Other long-term assets, net” on our Condensed Consolidated Balance Sheet, totaled $7 million. At December 31, 2023, the net fair value of these hedges totaled $51 million and $4 million, which were included in “Other current assets” and “Other long-term assets, net”, respectively.
 
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 September 30, 2024Fair Value as of December 31, 2023
Recurring Fair Value Measures (1)
Level 1Level 2TotalLevel 1Level 2Total
Commodity derivatives$(21)$(67)$(88)$9 $(9)$— 
Interest rate derivatives— 7 7 — 55 55 
Total net derivative asset/(liability)$(21)$(60)$(81)$9 $46 $55 
(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.
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Rollforward of Level 3 Net Asset/(Liability)
 
The Preferred Distribution Rate Reset Option was accounted for as an embedded derivative that was bifurcated from the related host contract and recorded at fair value. The Preferred Distribution Rate Reset Option was settled in January 2023 when we received notice that the Series A preferred unitholders elected the Preferred Distribution Rate Reset Option, which resulted in a gain of $58 million recognized in “Other income, net” in our Condensed Consolidated Statement of Operations for the nine months ended September 30, 2023. See Note 12 to our Consolidated Financial Statements included in Part IV of our 2023 Annual Report on Form 10-K for additional information regarding the Preferred Distribution Rate Reset Option.

The following table provides a reconciliation of changes in fair value of the beginning and ending balances for the Preferred Distribution Rate Reset Option embedded derivative, which was classified as Level 3 in the fair value hierarchy (in millions):

Nine Months Ended
September 30, 2023
Beginning Balance$(189)
Net gains/(losses) for the period included in earnings
58 
Settlements131 
Ending Balance$— 
Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period$— 

Note 8—Related Party Transactions
 
See Note 16 to our Consolidated Financial Statements included in Part IV of our 2023 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

We and certain Plains entities have issued promissory notes to facilitate financing. In March 2023, we assigned PAGP our interest in an existing unsecured promissory note due from a consolidated subsidiary (“March 2023 note payable”) with a face value of CAD$500 million (approximately $370 million). Concurrently, PAGP issued an unsecured promissory note to us (“March 2023 note receivable”) for the same face value amount. Both notes are due April 2027 and bear interest at a rate of 8.25% per annum, payable semi-annually.

In July 2024, a consolidated subsidiary issued additional unsecured promissory notes to PAGP (collectively with the March 2023 note payable, the “related party notes payable”) with a face value of CAD$865 million (approximately $629 million). Concurrently, PAGP issued unsecured promissory notes to us (collectively with the March 2023 note receivable, the “related party notes receivable”) for the same face value amount. These notes are due September 2034 and bear interest at a rate of 6.50% per annum, payable semi-annually. In connection with the July 2024 issuance of related party notes, we received cash from PAGP of $629 million, which is reflected in “Proceeds from the issuance of related party notes” (a component of cash flows from financing activities), and we paid an equal and offsetting amount of cash to PAGP, which is reflected in “Investments in related party notes” (a component of cash flows from investing activities) on our Condensed Consolidated Statement of Cash Flows.

Accrued and unpaid interest receivable/payable was $11 million and $10 million as of September 30, 2024 and December 31, 2023, respectively. Interest income/expense on the related party notes totaled $16 million and $31 million for the three and nine months ended September 30, 2024, respectively, and $8 million and $18 million for the three and nine months ended September 30, 2023, respectively.

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As of September 30, 2024 and December 31, 2023, our outstanding related party notes receivable and related party notes payable balances were as follows (in millions):

September 30,
2024		December 31,
2023
Related party notes receivable (1)
$1,011 $379 
Related party notes payable (1)
$1,011 $379 
(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 nine months ended September 30, 2024 and 2023, 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
September 30,		Nine Months Ended
September 30,
 2024202320242023
Revenues from related parties$12 $13 $34 $37 
Purchases and related costs from related parties$103 $103 $296 $302 

Our receivable and payable amounts with these related parties as reflected on our Condensed Consolidated Balance Sheets were as follows (in millions):

September 30,
2024		December 31,
2023
Trade accounts receivable and other receivables, net from related parties (1)
$46 $63 
Trade accounts payable to related parties (1) (2)
$70 $72 
(1)Includes amounts related to transportation and storage services and amounts owed to us or advanced to us related to investment capital projects of equity method investees where we serve as construction manager.
(2)We have agreements to store crude oil at facilities and transport crude oil or utilize capacity on pipelines that are owned by equity method investees. A portion of our commitment to transport is supported by crude oil buy/sell or other agreements with third parties with commensurate quantities.

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Note 9—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.

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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.
 
Our estimated undiscounted reserve for environmental liabilities (excluding liabilities related to the Line 901 incident, as discussed further below) were reflected on our Condensed Consolidated Balance Sheets as follows (in millions):

September 30,
2024		December 31,
2023
Other current liabilities$14 $10 
Other long-term liabilities and deferred credits$45 $46 
Total$59 $56 


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 was determined by the Unified Command to be complete in 2016, and the Unified Command was 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, most of which have been resolved. Set forth below is a brief summary of actions and matters that are currently pending or recently resolved.
     
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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 appealed the Court’s rulings. The Appellate Court’s order resulted in approximately $275,000 of claims being remanded to the trial court for further adjudication and the affirmation of the trial court’s dismissal of all other claims.
    
We also received 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. Most of these lawsuits have been settled or dismissed by the court. We recently settled the following two lawsuits (the “2024 Settlements”): (i) a lawsuit in 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; and (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. In connection with the 2024 Settlements, we recognized additional costs related to the Line 901 incident of $120 million. Our remaining Line 901 lawsuits include various lawsuits filed in California Superior Court in Santa Barbara County by 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, which have not yet been set for trial, and believe we have strong defenses.



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In a separate class action lawsuit that was pending in United States District Court for the Central District of California, the plaintiffs claimed two different classes of claimants were damaged by the release: (i) commercial fishermen who landed fish in certain specified fishing blocks in the waters off the coast of Southern California or persons or businesses who resold commercial seafood caught in those areas; and (ii) owners and lessees of residential beachfront properties, or properties with a private easement to a beach, where plaintiffs claim oil from the spill washed up. In 2022, in order to fully and finally resolve all claims and litigation for both classes, we reached an agreement to settle this case in exchange for a payment of $230 million (the “Class Action Settlement”). The Class Action Settlement was formally approved by the trial court on September 20, 2022, and we made the $230 million settlement payment on October 27, 2022 and the lawsuit was subsequently dismissed.

Plains formally submitted claims for reimbursement of the Class Action Settlement to our insurance carriers on November 7, 2022. To date, we have received payment of approximately $3.6 million from one insurer, which represents the final payment obligation of such insurer and brings the total amount collected from all insurers under such program to $275 million of the $500 million policy limits as of September 30, 2024. Insurers responsible for $185 million of the remaining $225 million of coverage have 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 accepted nor denied coverage. We have initiated final and binding arbitration proceedings against all of the insurers responsible for the remaining $225 million of coverage with respect to which we have not received reimbursement. With respect to our reimbursement claim against insurers representing $175 million of the $225 million total reimbursement claim, a binding arbitration hearing was concluded in early October and we expect a decision from the arbitration panel in January 2025. We continue to 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 (including the arbitration proceeding for which a hearing was completed in October) 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.

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In connection with the foregoing, including the Class Action Settlement and the 2024 Settlements, 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 September 30, 2024, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $870 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 2024 Settlements), 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 (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.

We recognized costs, net of amounts probable of recovery from insurance carriers, of $120 million during the nine months ended September 30, 2024. We did not recognize any such costs during the nine months ended September 30, 2023. As of September 30, 2024, we had a remaining undiscounted gross liability of approximately $94 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 September 30, 2024, 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 $370 million. Through September 30, 2024, 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 September 30, 2024, we have recognized a 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 classified the related receivable amounts as short-term and long-term based on the resolution status of the process as of the balance sheet date. As of September 30, 2024, we have classified $175 million of the receivable as a short-term asset in “Trade accounts receivable and other receivables, net” with the remaining $50 million recognized as a long-term asset in “Other long-term assets, net” on our Condensed Consolidated Balance Sheet. As of December 31, 2023, we classified $225 million as a long-term asset in “Other long-term assets, net” 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.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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. (“PNGS”) 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. A bifurcated bench and jury trial was held in May of 2024, with the jury deciding claims asserted against PAA (“PAA claims”) and the court to decide the claims asserted against PNGS (“PNGS claims”). The jury found PAA liable but awarded $0 damages on the PAA claims. We are still awaiting a verdict from the court on the PNGS claims and an entry of judgement on the PAA claims. We expect that the outcome of the lawsuit will not have a material adverse effect on our financial condition, results of operations or cash flows.

Note 10—Segment Information

We manage our operations through two operating segments, which are also our reportable segments: Crude Oil and NGL. See Note 19 to our Consolidated Financial Statements included in Part IV of our 2023 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 (“Segment amounts attributable to noncontrolling interests”).
 
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The following tables reflect certain financial data for each segment (in millions):

Crude OilNGLIntersegment Revenues
Elimination		Total
Three Months Ended September 30, 2024
Revenues (1):
   
Product sales$12,009 $357 $(84)$12,282 
Services435 31 (5)461 
Total revenues$12,444 $388 $(89)$12,743 
Equity earnings in unconsolidated entities$97 $— $97 
Segment Adjusted EBITDA$577 $73 $650 
Maintenance capital expenditures$48 $21 $69 
Three Months Ended September 30, 2023
Revenues (1):
Product sales$11,481 $201 $(101)$11,581 
Services453 41 (4)490 
Total revenues$11,934 $242 $(105)$12,071 
Equity earnings in unconsolidated entities$99 $— $99 
Segment Adjusted EBITDA$553 $99 $652 
Maintenance capital expenditures$39 $21 $60 
Nine Months Ended September 30, 2024
Revenues (1):
Product sales$35,515 $1,069 $(263)$36,321 
Services1,246 120 (16)1,350 
Total revenues$36,761 $1,189 $(279)$37,671 
Equity earnings in unconsolidated entities$298 $— $298 
Segment Adjusted EBITDA$1,707 $326 $2,033 
Maintenance capital expenditures$135 $53 $188 
Nine Months Ended September 30, 2023
Revenues (1):
Product sales$33,815 $1,182 $(271)$34,726 
Services1,173 130 (15)1,288 
Total revenues$34,988 $1,312 $(286)$36,014 
Equity earnings in unconsolidated entities$277 $— $277 
Segment Adjusted EBITDA$1,600 $352 $1,952 
Maintenance capital expenditures$107 $62 $169 
(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.

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Segment Adjusted EBITDA Reconciliation

The following table reconciles Segment Adjusted EBITDA to Net income attributable to PAA (in millions):

Three Months Ended
September 30,		Nine Months Ended
September 30,
 2024202320242023
Segment Adjusted EBITDA$650 $652 $2,033 $1,952 
Adjustments: (1)
Depreciation and amortization of unconsolidated entities (2)
(22)(21)(59)(67)
Derivative activities and inventory valuation adjustments (3)
105 (196)(78)(201)
Long-term inventory costing adjustments (4)
(31)58 (8)27 
Deficiencies under minimum volume commitments, net (5)
(15)(14)(10)(5)
Equity-indexed compensation expense (6)
(9)(10)(28)(28)
Foreign currency revaluation (7)
(2)15 22 — 
Line 901 incident (8)
(120)— (120)— 
Transaction-related expenses (9)
— (1)— (1)
Segment amounts attributable to noncontrolling interests (10)
146 117 406 317 
Depreciation and amortization(257)(260)(769)(776)
Gains/(losses) on asset sales, net
(1)(7)(1)144 
Gain on investment in unconsolidated entities
— 29 — 28 
Interest expense, net(113)(97)(318)(290)
Other income, net
26 — 45 85 
Income before tax357 265 1,115 1,185 
Income tax (expense)/benefit
(45)14 (122)(82)
Net income312 279 993 1,103 
Net income attributable to noncontrolling interests(92)(76)(257)(185)
Net income attributable to PAA$220 $203 $736 $918 
(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.
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(5)We, and certain of our equity method investees, have certain agreements that require counterparties to deliver, transport or throughput a minimum volume over an agreed upon period. Substantially all of such agreements were entered into with counterparties to economically support the return on capital expenditure necessary to construct the related asset. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote. We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue or equity earnings, as a selected item impacting comparability. Our CODM views the inclusion of the contractually committed revenues associated with that period as meaningful to Segment Adjusted EBITDA as the related asset has been constructed, is standing ready to provide the committed service and the fixed operating costs are included in the current period results.
(6)Our total equity-indexed compensation expense includes expense associated with awards that will be settled in units and awards that will be settled in cash. The awards that will be settled in units are included in our diluted net income per unit calculation when the applicable performance criteria have been met. We exclude compensation expense associated with these awards in determining Segment Adjusted EBITDA as the dilutive impact of the outstanding awards is included in our diluted net income per unit calculation, as applicable. The portion of compensation expense associated with awards that will be settled in cash is not excluded in determining Segment Adjusted EBITDA. See Note 17 to our Consolidated Financial Statements included in Part IV of our 2023 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)Includes expenses associated with the Rattler Permian Transaction in the third quarter of 2023. See Note 7 to our Consolidated Financial Statements included in Part IV of our 2023 Annual Report on Form 10-K for information regarding this transaction.
(10)Reflects amounts attributable to noncontrolling interests in the Permian JV, Cactus II and Red River.

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Item 2.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
Introduction
 
The following discussion is intended to provide investors with an understanding of our financial condition and results of our operations and should be read in conjunction with our historical Consolidated Financial Statements and accompanying notes and Management’s Discussion and Analysis of Financial Condition and Results of Operations as presented in our 2023 Annual Report on Form 10-K. For more detailed information regarding the basis of presentation for the following financial information, see the Condensed Consolidated Financial Statements and related notes that are contained in Part I, Item 1 of this Quarterly Report on Form 10-Q.
 
Our discussion and analysis includes the following:
 
•Executive Summary
•Results of Operations 
•Liquidity and Capital Resources 
•Recent Accounting Pronouncements
•Forward-Looking Statements
 
Executive Summary
 
Company Overview
 
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 crude oil midstream service providers in North America, we own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and 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 crude oil and NGL.

Overview of Operating Results

During the first nine months of 2024, we recognized net income attributable to PAA of $736 million compared to $918 million during the first nine months of 2023. Results from our operations increased for the first nine months of 2024 over the comparable 2023 period due to more favorable results from our Crude Oil segment, partially offset by less favorable results from our NGL segment. Net income for the 2023 period includes favorable impacts from gains on asset sales and the mark-to-market adjustment of the Preferred Distribution Rate Reset Option, contributing to the relative decrease in net income in 2024. In addition, the 2024 results were impacted by an increase in costs associated with settlements related to the Line 901 incident that occurred in May 2015 and higher income tax expense.

See the “Results of Operations” section below for further discussion. 

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Results of Operations
 
Consolidated Results

The following table sets forth an overview of our consolidated financial results calculated in accordance with GAAP (in millions, except per unit data): 

Three Months Ended
September 30,		VarianceNine Months Ended
September 30,		Variance
 20242023$%20242023$%
Product sales revenues$12,282 $11,581 $701 6 %$36,321 $34,726 $1,595 5 %
Services revenues461 490 (29)(6)%1,350 1,288 62 5 %
Purchases and related costs(11,557)(11,106)(451)(4)%(34,333)(32,972)(1,361)(4)%
Field operating costs(483)(372)(111)(30)%(1,191)(1,062)(129)(12)%
General and administrative expenses(98)(92)(6)(7)%(287)(263)(24)(9)%
Depreciation and amortization(257)(260)3 1 %(769)(776)7 1 %
Gains/(losses) on asset sales, net(1)(7)6 86 %(1)144 (145)(101)%
Equity earnings in unconsolidated entities97 99 (2)(2)%298 277 21 8 %
Gain on investment in unconsolidated entities
— 29 (29)(100)%— 28 (28)(100)%
Interest expense, net (1)
(113)(97)(16)(16)%(318)(290)(28)(10)%
Other income, net (1)
26 — 26 **45 85 (40)(47)%
Income tax (expense)/benefit
(45)14 (59)**(122)(82)(40)(49)%
Net income312 279 33 12 %993 1,103 (110)(10)%
Net income attributable to noncontrolling interests
(92)(76)(16)(21)%(257)(185)(72)(39)%
Net income attributable to PAA$220 $203 $17 8 %$736 $918 $(182)(20)%
Basic and diluted net income per common unit$0.22 $0.20 $0.02 10 %$0.77 $1.04 $(0.27)(26)%
Basic and diluted weighted average common units outstanding702 700 2 — %702 699 3 — %
**    Indicates that variance as a percentage is not meaningful.
(1)“Interest expense, net” and “Other income, net” each include $16 million and $31 million for the three and nine months ended September 30, 2024, respectively, related to interest on promissory notes by and among PAA and certain Plains entities.

Revenues and Purchases

Fluctuations in our consolidated revenues and purchases and related costs are primarily associated with our merchant activities and are generally explained by changes in commodity prices and the impact of gains and losses related to derivative instruments used to manage our commodity price exposure. Because both product sales revenues and purchases and related costs are generally based off of the same pricing indices, the market price of the commodities will not necessarily have an impact on the absolute margins related to those sales and purchases.

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A majority of our sales and purchases are indexed to the prompt month price of the NYMEX Light, Sweet crude oil futures contract (“NYMEX Price”). The following table presents the range of the NYMEX Price over the last two years (in dollars per barrel):

NYMEX Price
 LowHighAverage
Three Months Ended September 30, 2024$66 $84 $75 
Three Months Ended September 30, 2023$70 $94 $82 
Nine Months Ended September 30, 2024$66 $87 $78 
Nine Months Ended September 30, 2023$67 $94 $77 

Product sales revenues and purchases increased for the three months ended September 30, 2024 compared to the same period in 2023 primarily due to higher crude oil sales volumes in the 2024 period, partially offset by lower commodity prices.

Product sales revenues and purchases increased for the nine months ended September 30, 2024 compared to the same period in 2023 due to higher commodity prices in the 2024 period, primarily in the first half of 2024, as well as higher crude oil sales volumes.

Revenues from services decreased for the three months ended September 30, 2024 compared to the same period in 2023 primarily due to timing of revenue recognition in 2023, partially offset by higher revenues from pipeline volumes and the impact of acquisitions.

Revenues from services increased for the nine months ended September 30, 2024 compared to the same period in 2023 primarily due to higher pipeline volumes and tariff escalations, as well as the impact of acquisitions, partially offset by timing of revenue recognition in the third quarter of 2023.

See further discussion of our net revenues (revenues less purchases and related costs) in the “—Analysis of Operating Segments” section below.

Field Operating Costs

See discussion of field operating costs in the “—Analysis of Operating Segments” section below.

General and Administrative Expenses

The increase in general and administrative expenses for the three and nine months ended September 30, 2024 compared to the same periods in 2023 was primarily due to (i) higher employee-related costs and (ii) higher information systems costs due to ongoing systems conversion and integration work.

Gains/(Losses) on Asset Sales, Net

The net gain on asset sales for the nine months ended September 30, 2023 was primarily comprised of a gain of approximately $140 million related to the sale of our Keyera Fort Saskatchewan facility in the first quarter of 2023. See Note 7 to our Consolidated Financial Statements included in Part IV of our 2023 Annual Report on Form 10-K for additional information.

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Equity Earnings

See discussion of Equity earnings in unconsolidated entities in the “—Analysis of Operating Segments” section below.

Interest Expense, Net and Other Income, Net

For the three and nine months ended September 30, 2024, “Interest expense, net” and “Other income, net” each include interest expense and interest income associated with promissory notes payable and receivable by and among PAA and certain Plains entities, which is the primary driver of the increase in interest expense compared to the same periods in 2023 and is a component of the variance in other income year-over-year. These amounts are excluded from our non-GAAP performance measures Adjusted EBITDA and Implied DCF. As such, the interest expense and interest income associated with these notes is presented on a net basis in the reconciliation of these metrics to Net Income. See the “—Non-GAAP Financial Measures” section below.

The following table summarizes the components impacting Interest expense, net (in millions):

Three Months Ended
September 30,		Nine Months Ended
September 30,
2024202320242023
Interest expense on third-party borrowings
$99 $100 $294 $298 
Interest expense on related party promissory notes (1)
16 — 31 — 
Capitalized interest
(2)(3)(7)(8)
$113 $97 $318 $290 
(1)Represents interest expense associated with promissory notes by and among PAA and certain Plains entities, as described above.

The following table summarizes the components impacting Other income, net (in millions):

Three Months Ended
September 30,		Nine Months Ended
September 30,
 2024202320242023
Interest income on related party promissory notes (1)
$16 $— $31 $— 
Interest income from other sources
7 10 16 22 
Net gain/(loss) on foreign currency revaluation (2)
1 (10)(6)4 
Gain on mark-to-market adjustment of Preferred Distribution Rate Reset Option embedded derivative (3)
— — — 58 
Other2 — 4 1 
$26 $— $45 $85 
(1)Represents interest income associated with promissory notes by and among PAA and certain Plains entities, as described above.
(2)The activity during the periods presented was primarily related to the impact from the change in the CAD to USD exchange rate on the portion of our intercompany net investment that is not long-term in nature.
(3)See Note 7 to our Condensed Consolidated Financial Statements for additional information.

Income Tax (Expense)/Benefit

The net unfavorable income tax variance for the three months ended September 30, 2024 compared to the same period in 2023 was primarily due to higher year-over-year income within our Canadian operations as impacted by fluctuations of derivative mark-to-market valuations.

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The net unfavorable income tax variance for the nine months ended September 30, 2024 compared to the same period in 2023 was primarily due to higher income tax expense in the second quarter of 2024 associated with Canadian withholding tax on dividends from our Canadian entities to other Plains entities.

Noncontrolling Interests

The increase in amounts attributable to noncontrolling interests for the three and nine months ended September 30, 2024 compared to the same periods in 2023 was primarily due to higher volumes, as well as contributions from acquisitions completed by the Permian JV.

Non-GAAP Financial Measures
 
To supplement our financial information presented in accordance with GAAP, management uses additional measures known as “non-GAAP financial measures” in its evaluation of past performance and prospects for the future and to assess the amount of cash that is available for distributions, debt repayments, common equity repurchases and other general partnership purposes. The primary additional measures used by management are Adjusted EBITDA, Adjusted EBITDA attributable to PAA, Implied distributable cash flow (“DCF”), Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions.

Our definition and calculation of certain non-GAAP financial measures may not be comparable to similarly-titled measures of other companies. Adjusted EBITDA, Adjusted EBITDA attributable to PAA and Implied DCF are reconciled to Net Income, and Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions are reconciled to Net Cash Provided by Operating Activities, the most directly comparable measures as reported in accordance with GAAP, and should be viewed in addition to, and not in lieu of, our Condensed Consolidated Financial Statements and accompanying notes. See “—Liquidity and Capital Resources—Non-GAAP Financial Liquidity Measures” for additional information regarding Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions.

Non-GAAP Financial Performance Measures

Adjusted EBITDA is defined as earnings before interest expense, income tax (expense)/benefit, depreciation and amortization (including our proportionate share of depreciation and amortization, including write-downs related to cancelled projects and impairments, of unconsolidated entities), gains and losses on asset sales, gains or losses on investments in unconsolidated entities and interest income on promissory notes by and among PAA and certain Plains entities, adjusted for certain selected items impacting comparability. Adjusted EBITDA attributable to PAA excludes the portion of Adjusted EBITDA that is attributable to noncontrolling interests.

Management believes that the presentation of Adjusted EBITDA, Adjusted EBITDA attributable to PAA and Implied DCF provides useful information to investors regarding our performance and results of operations because these measures, when used to supplement related GAAP financial measures, (i) provide additional information about our core operating performance and ability to fund distributions to our unitholders through cash generated by our operations, (ii) provide investors with the same financial analytical framework upon which management bases financial, operational, compensation and planning/budgeting decisions and (iii) present measures that investors, rating agencies and debt holders have indicated are useful in assessing us and our results of operations. These non-GAAP financial performance measures may exclude, for example, (i) charges for obligations that are expected to be settled with the issuance of equity instruments, (ii) 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, (iii) long-term inventory costing adjustments, (iv) items that are not indicative of our core operating results and/or (v) other items that we believe should be excluded in understanding our core operating performance. These measures may further be adjusted to include amounts related to deficiencies associated with minimum volume commitments whereby we have billed the counterparties for their deficiency obligation and such amounts are recognized as deferred revenue in “Other current liabilities” in our Condensed Consolidated Financial Statements. We also adjust for amounts billed by our equity method investees related to deficiencies under minimum volume commitments. Such amounts are presented net of applicable amounts subsequently recognized into revenue. We have defined all such items as “selected items impacting comparability.” We do not necessarily consider all of our selected items impacting comparability to be non-recurring, infrequent or unusual, but we believe that an understanding of these selected items impacting comparability is material to the evaluation of our operating results and prospects.

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Although we present selected items impacting comparability that management considers in evaluating our performance, you should also be aware that the items presented do not represent all items that affect comparability between the periods presented. Variations in our operating results are also caused by changes in volumes, prices, exchange rates, mechanical interruptions, acquisitions, divestitures, investment capital projects and numerous other factors as discussed, as applicable, in “—Analysis of Operating Segments.”

The following tables set forth the reconciliation of the non-GAAP financial performance measures Adjusted EBITDA, Adjusted EBITDA attributable to PAA and Implied DCF to Net Income (in millions): 

Three Months Ended
September 30,		VarianceNine Months Ended
September 30,		Variance
 20242023$%20242023$%
Net income$312 $279 $33 12 %$993 $1,103 $(110)(10)%
Interest expense, net of certain items (1)
97 97 — — %287 290 (3)(1)%
Income tax expense/(benefit)
45 (14)59 **122 82 40 49 %
Depreciation and amortization
257 260 (3)(1)%769 776 (7)(1)%
(Gains)/losses on asset sales, net
1 7 (6)(86)%1 (144)145 101 %
Gain on investment in unconsolidated entities
— (29)29 100 %— (28)28 100 %
Depreciation and amortization of unconsolidated entities (2)
22 21 1 5 %59 67 (8)(12)%
Selected Items Impacting Comparability:
Derivative activities and inventory valuation adjustments
(105)196 (301)**78 201 (123)**
Long-term inventory costing adjustments
31 (58)89 **8 (27)35 **
Deficiencies under minimum volume commitments, net
15 14 1 **10 5 5 **
Equity-indexed compensation expense
9 10 (1)**28 28 — **
Foreign currency revaluation
2 (15)17 **(22)— (22)**
Line 901 incident
120 — 120 **120 — 120 **
Transaction-related expenses
— 1 (1)**— 1 (1)**
Selected Items Impacting Comparability - Segment Adjusted EBITDA (3)
72 148 (76)**222 208 14 **
Mark-to-market adjustment of Preferred Distribution Rate Reset Option embedded derivative (4)
— — — **— (58)58 **
Foreign currency revaluation (5)
(1)10 (11)**6 (4)10 **
Selected Items Impacting Comparability - Adjusted EBITDA (6)
71 158 (87)**228 146 82 **
Adjusted EBITDA (6)
$805 $779 $26 3 %$2,459 $2,292 $167 7 %
Adjusted EBITDA attributable to noncontrolling interests (7)
(146)(117)(29)(25)%(408)(318)(90)(28)%
Adjusted EBITDA attributable to PAA$659 $662 $(3)— %$2,051 $1,974 $77 4 %
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Three Months Ended
September 30,		VarianceNine Months Ended
September 30,		Variance
 20242023$%20242023$%
Adjusted EBITDA (6) (8)
$805 $779 $26 3 %$2,459 $2,292 $167 7 %
Interest expense, net of certain non-cash and other items (9)
(94)(92)(2)(2)%(274)(275)1 — %
Maintenance capital (10)
(69)(60)(9)(15)%(188)(169)(19)(11)%
Investment capital of noncontrolling interests (11)
(21)(23)2 9 %(62)(63)1 2 %
Current income tax expense
(20)(22)2 9 %(143)(104)(39)(38)%
Distributions from unconsolidated entities in excess of/(less than) adjusted equity earnings (12)
4 (2)6 **11 (21)32 **
Distributions to noncontrolling interests (13)
(113)(86)(27)(31)%(310)(237)(73)(31)%
Implied DCF$492 $494 $(2)— %$1,493 $1,423 $70 5 %
Preferred unit distributions (13)
(64)(63)(1)(2)%(190)(178)(12)(7)%
Implied DCF Available to Common Unitholders$428 $431 $(3)(1)%$1,303 $1,245 $58 5 %
Common unit cash distributions (13)
(223)(187)(668)(560)
Implied DCF Excess (14)
$205 $244 $635 $685 
**    Indicates that variance as a percentage is not meaningful.
(1)Represents “Interest expense, net” as reported on our Condensed Consolidated Statements of Operations, net of interest income associated with promissory notes by and among PAA and certain Plains entities.
(2)We exclude our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities when reviewing Adjusted EBITDA, similar to our consolidated assets.
(3)For a more detailed discussion of these selected items impacting comparability, see the footnotes to the Segment Adjusted EBITDA Reconciliation table in Note 10 to our Condensed Consolidated Financial Statements.
(4)The Preferred Distribution Rate Reset Option of our Series A preferred units was accounted for as an embedded derivative and recorded at fair value in our Condensed Consolidated Financial Statements. The associated gains and losses are not integral to our results and were thus classified as a selected item impacting comparability. See Note 7 to our Condensed Consolidated Financial Statements for additional information regarding the Preferred Distribution Rate Reset Option.
(5)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. The associated gains and losses are not integral to our results and were thus classified as a selected item impacting comparability.
(6)“Other income, net” on our Condensed Consolidated Statements of Operations, excluding interest income associated with promissory notes by and among PAA and certain Plains entities, adjusted for selected items impacting comparability (“Adjusted other income, net”) is included in Adjusted EBITDA and excluded from Segment Adjusted EBITDA.
(7)Reflects amounts attributable to noncontrolling interests in the Permian JV, Cactus II and Red River.
(8)See the table above for a reconciliation from Net Income to Adjusted EBITDA.
(9)Amount excludes certain non-cash items impacting interest expense such as amortization of debt issuance costs and terminated interest rate swaps and is net of interest income associated with promissory notes by and among PAA and certain Plains entities.
(10)Maintenance capital expenditures are defined as capital expenditures for the replacement and/or refurbishment of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets.
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(11)Investment capital expenditures attributable to noncontrolling interests that reduce Implied DCF available to PAA common unitholders.
(12)Comprised of cash distributions received from unconsolidated entities less equity earnings in unconsolidated entities (adjusted for our proportionate share of depreciation and amortization, including write-downs related to cancelled projects, and selected items impacting comparability of unconsolidated entities). 
(13)Cash distributions paid during the period presented.
(14)Excess DCF is retained to establish reserves for debt repayment, future distributions, common equity repurchases, capital expenditures and other partnership purposes.

Analysis of Operating Segments
 
We manage our operations through two operating segments: Crude Oil and NGL. Our CODM (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Adjusted EBITDA, segment volumes and maintenance capital investment. See Note 10 to our Condensed Consolidated Financial Statements for our definition of Segment Adjusted EBITDA and a reconciliation of Segment Adjusted EBITDA to Net income attributable to PAA. See Note 19 to our Consolidated Financial Statements included in Part IV of our 2023 Annual Report on Form 10-K for our definition of maintenance capital.

Crude Oil Segment
 
Our Crude Oil segment operations generally consist of gathering and transporting crude oil using pipelines (including gathering systems), trucks and, at times, on barges or railcars, in addition to providing terminalling, storage and other related services utilizing our integrated assets across the United States and Canada. Our assets provide services to third parties as well as to our merchant activities. Our merchant activities include the purchase of crude oil supply and the movement of this supply on our assets or third-party assets to sales locations, including our terminals, third-party connecting carriers, regional hubs or to refineries. Our merchant activities are governed by our risk management policies.

Our Crude Oil segment generates revenue through a combination of tariffs, pipeline capacity agreements and other transportation fees, month-to-month and multi-year storage and terminalling agreements and the sale of gathered and bulk-purchased crude oil. Tariffs and other fees on our pipeline systems are typically based on volumes transported and vary by receipt point and delivery point. Fees for our terminalling and storage services are based on capacity leases and throughput volumes. Generally, results from our merchant activities are impacted by (i) increases or decreases in our lease gathering crude oil purchases volumes and (ii) volatility in commodity price differentials, particularly grade and location differentials, as well as time spreads. The segment results also include the direct fixed and variable field costs of operating the crude oil assets, as well as an allocation of indirect operating costs.

The following tables set forth our operating results from our Crude Oil segment:

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Operating Results (1)
Three Months Ended
September 30,		VarianceNine Months Ended
September 30,		Variance
(in millions)20242023$%20242023$%
Revenues$12,444 $11,934 $510 4 %$36,761 $34,988 $1,773 5 %
Purchases and related costs(11,529)(11,069)(460)(4)%(34,014)(32,499)(1,515)(5)%
Field operating costs(400)(266)(134)(50)%(938)(779)(159)(20)%
Segment general and administrative expenses (2)
(78)(71)(7)(10)%(223)(203)(20)(10)%
Equity earnings in unconsolidated entities97 99 (2)(2)%298 277 21 8 %
Adjustments (3):
Depreciation and amortization of unconsolidated entities22 21 1 **59 67 (8)**
Derivative activities and inventory valuation adjustments(13)76 (89)**20 69 (49)**
Long-term inventory costing adjustments34 (67)101 **10 (36)46 **
Deficiencies under minimum volume commitments, net15 14 1 **10 5 5 **
Equity-indexed compensation expense9 10 (1)**28 27 1 **
Foreign currency revaluation2 (12)14 **(18)— (18)**
Line 901 incident120 — 120 **120 — 120 **
Transaction-related expenses— 1 (1)**— 1 (1)**
Segment amounts attributable to noncontrolling interests(146)(117)(29)**(406)(317)(89)**
Segment Adjusted EBITDA$577 $553 $24 4 %$1,707 $1,600 $107 7 %
Maintenance capital expenditures$48 $39 $9 23 %$135 $107 $28 26 %

Three Months Ended
September 30,		VarianceNine Months Ended
September 30,		Variance
Average Volumes20242023Volumes%20242023Volumes%
Crude oil pipeline tariff (by region) (4)
        
Permian Basin (5)
6,944 6,114 830 14 %6,692 6,237 455 7 %
Rocky Mountain (5)
443 329 114 35 %479 345 134 39 %
Other (5)
1,779 1,816 (37)(2)%1,731 1,728 3 — %
Total crude oil pipeline tariff 9,166 8,259 907 11 %8,902 8,310 592 7 %
Commercial crude oil storage capacity (5)(6)
72 72 — — %72 72 — — %
Crude oil lease gathering purchases (4)
1,600 1,455 145 10 %1,560 1,430 130 9 %
**    Indicates that variance as a percentage is not meaningful.
(1)Revenues and costs and expenses include intersegment amounts. 
(2)Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.
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(3)Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results. See Note 10 to our Condensed Consolidated Financial Statements for additional discussion of such adjustments.
(4)Average daily volumes in thousands of barrels per day calculated as the total volumes (attributable to our interest for assets owned by unconsolidated entities or through undivided joint interests) for the period divided by the number of days in the period. Volumes associated with acquisitions represent total volumes for the number of days we actually owned the assets divided by the number of days in the period. 
(5)Includes volumes (attributable to our interest) from assets owned by unconsolidated entities.
(6)Average monthly capacity in millions of barrels per day calculated as total volumes for the period divided by the number of months in the period.
 
Segment Adjusted EBITDA

Crude Oil Segment Adjusted EBITDA increased for the three and nine months ended September 30, 2024 compared to the same periods in 2023 primarily due to higher tariff volumes on our pipelines, tariff escalations and contributions from acquisitions, partially offset by fewer market-based opportunities.

The following is a more detailed discussion of the significant factors impacting Segment Adjusted EBITDA for the three and nine months ended September 30, 2024 compared to the same periods in 2023.

Net Revenues and Equity Earnings. Our results were favorably impacted by (i) volume growth across our pipeline systems driven by increased production in the Permian Basin region as well as increased movements from the Rocky Mountain region to Cushing, Oklahoma, (ii) the benefit of tariff escalations and (iii) contributions from acquisitions.

Additionally, our results for the three and nine months ended September 30, 2024 compared to the same periods in 2023 reflect fewer crude oil market-based opportunities.

Field Operating Costs. For the three and nine months ended September 30, 2024 compared to the same periods in 2023, we recognized higher expenses associated with (i) an increase in costs associated with settlements related to the Line 901 incident that occurred in May 2015 (which impact field operating costs, but are excluded from Segment Adjusted EBITDA, and thus are reflected as an “Adjustment” in the table above), (ii) employee-related costs primarily resulting from higher average headcount and salaries, (iii) property taxes due to the impact of favorable adjustments in 2023 and (iv) incremental operating costs associated with acquisitions, partially offset by (v) decreased costs resulting from lower third-party trucked volumes. Field operating costs for the nine months ended September 30, 2024 compared to the same period in 2023 were also favorably impacted by lower utilities-related costs as a result of lower prices, partially offset by higher volumes and an increase in the amount of drag reducing agents used.

Maintenance Capital

The increase in maintenance capital spending for the three and nine months ended September 30, 2024 compared to the same periods in 2023 was primarily due to higher costs resulting from increased pipeline integrity activities and trucking lease buyouts. Additionally, the three months ended September 30, 2024 compared to the same 2023 period was further impacted by timing of tank integrity activities.

NGL Segment
 
Our NGL segment operations involve natural gas processing and NGL fractionation, storage, transportation and terminalling. Our NGL revenues are primarily derived from a combination of (i) providing gathering, fractionation, storage, and/or terminalling services to third-party customers for a fee, and (ii) our merchant activities of extracting NGL mix from the gas stream processed at our Empress straddle plant facility as well as acquiring NGL mix, which is then transported, stored and fractionated into finished products and sold to customers. The commodity exposure associated with our merchant activities is governed by our risk management policies.

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Generally, our segment results are impacted by (i) increases or decreases in our NGL sales volumes, (ii) volatility in commodity price differentials, primarily the differential between the price of natural gas and the extracted NGL (“frac spread”), as well as location differentials and time spreads, (iii) the quality and volume of natural gas transported on third-party assets through our Empress straddle plant and (iv) our share of the NGLs received from a third-party straddle plant.

Our NGL operations are sensitive to weather-related demand, particularly during the approximate five-month peak heating season of November through March, and temperature differences from period-to-period may have a significant effect on NGL demand, and thus our financial performance, as well as the impact of comparative performance between financial reporting periods that bisect the five-month peak heating season.
 
The following tables set forth our operating results from our NGL segment:

Operating Results (1)
Three Months Ended
September 30,		VarianceNine Months Ended
September 30,		Variance
(in millions)20242023$%20242023$%
Revenues$388 $242 $146 60 %$1,189 $1,312 $(123)(9)%
Purchases and related costs(117)(142)25 18 %(598)(759)161 21 %
Field operating costs(83)(106)23 22 %(253)(283)30 11 %
Segment general and administrative expenses (2)
(20)(21)1 5 %(64)(60)(4)(7)%
Adjustments (3):
Derivative activities(92)120 (212)**58 132 (74)**
Long-term inventory costing adjustments(3)9 (12)**(2)9 (11)**
Equity-indexed compensation expense— — — **— 1 (1)**
Foreign currency revaluation— (3)3 **(4)— (4)**
Segment Adjusted EBITDA$73 $99 $(26)(26)%$326 $352 $(26)(7)%
Maintenance capital expenditures$21 $21 $— — %$53 $62 $(9)(15)%

 Three Months Ended
September 30,		VarianceNine Months Ended
September 30,		Variance
Average Volumes
(in thousands of barrels per day) (4)
20242023Volumes%20242023Volumes%
NGL fractionation131 107 24 22 %129 111 18 16 %
NGL pipeline tariff195 193 2 1 %210 178 32 18 %
Propane and butane sales59 44 15 34 %80 73 7 10 %
**    Indicates that variance as a percentage is not meaningful.
(1)Revenues and costs and expenses include intersegment amounts. 
(2)Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period. 
(3)Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results. See Note 10 to our Condensed Consolidated Financial Statements for additional discussion of such adjustments.
(4)Average daily volumes are calculated as total volumes (attributable to our interest for assets owned through undivided joint interests) for the period divided by the number of days in the period. 
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Segment Adjusted EBITDA

NGL Segment Adjusted EBITDA decreased for the three and nine months ended September 30, 2024 compared to the same periods in 2023 primarily as a result of the impact of lower realized frac spreads, partially offset by higher propane and butane sales volumes. The nine months ended September 30, 2024 compared to the same period in 2023 further benefited from incremental margins from iso-to-normal butane spreads in the first half of 2024.

Significant variances in the components of Segment Adjusted EBITDA are discussed in more detail below.

Net Revenues. Net revenues include the impact of derivative activities and long-term inventory costing adjustments, which are excluded from Segment Adjusted EBITDA, and thus are reflected as an “Adjustment” in the table above. Excluding such impacts, net revenues decreased for the three and nine months ended September 30, 2024 compared to the same periods in 2023.

The decrease in net revenues for the three and nine months ended September 30, 2024 compared to the same periods in 2023 was primarily due to (i) lower realized frac spreads and (ii) lower field operating cost recoveries at our Empress straddle plants realized through our commercial agreements, partially offset by (iii) higher propane and butane sales volumes.

The nine months ended September 30, 2024 compared to the same period in 2023 further benefited from incremental margins from iso-to-normal butane spreads in the first half of 2024.

Field Operating Costs. The decrease in field operating costs for the three and nine months ended September 30, 2024 compared to the same periods in 2023 was primarily due to (i) decreased utilities-related costs largely as a result of lower prices and (ii) a decrease in unrealized mark-to-market losses on power hedges (which impact our field operating costs, but are excluded from Segment Adjusted EBITDA, and thus are reflected as an “Adjustment” in the table above), partially offset by (iii) higher maintenance costs and (iv) higher employee-related costs primarily resulting from higher average headcount and salaries. The decrease in utilities-related costs was partially offset by the lower benefit to net revenues of operating cost recoveries realized through commercial agreements.

Maintenance Capital

The decrease in maintenance capital spending for the nine months ended September 30, 2024 compared to the same period in 2023 was primarily due to timing of equipment repairs and replacement projects for certain of our pipeline systems and fractionation facilities.

Liquidity and Capital Resources
 
General
 
Our primary sources of liquidity are (i) cash flow from operating activities and (ii) borrowings under our credit facilities or commercial paper program. In addition, we may supplement these primary sources of liquidity with proceeds from asset sales, and in the past have utilized funds received from sales of equity and debt securities. Our primary cash requirements include, but are not limited to, (i) ordinary course of business uses, such as the payment of amounts related to the purchase of crude oil, NGL and other products, payment of other expenses and interest payments on outstanding debt, (ii) investment and maintenance capital activities, (iii) acquisitions of assets or businesses, (iv) repayment of principal on our long-term debt and (v) distributions to our unitholders and noncontrolling interests. In addition, we may use cash for repurchases of common equity. We generally expect to fund our short-term cash requirements through cash flow generated from operating activities and/or borrowings under our credit facilities or commercial paper program. In addition, we generally expect to fund our long-term needs, such as those resulting from investment capital activities, acquisitions or refinancing our long-term debt, through a variety of sources, which may include any or a combination of the sources listed above.

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As of September 30, 2024, we had a working capital surplus of $33 million and approximately $3.3 billion of liquidity available to meet our ongoing operating, investing and financing needs, subject to continued covenant compliance, as noted below (in millions):

 As of
September 30, 2024
Availability under senior unsecured revolving credit facility (1) (2)
$1,350 
Availability under senior secured hedged inventory facility (1) (2)
1,316 
Amounts outstanding under commercial paper program— 
Subtotal2,666 
Cash and cash equivalents (3)
636 
Total$3,302 
(1)Represents availability prior to giving effect to borrowings outstanding under our commercial paper program, which reduce available capacity under our credit facilities.
(2)Available capacity under our senior unsecured revolving credit facility and senior secured hedged inventory facility was reduced by outstanding letters of credit issued under these facilities of less than $1 million and $34 million, respectively.
(3)Excludes restricted cash of $4 million.

In August 2024, we amended our credit facility agreements to, among other things, extend the maturity dates of our senior secured hedged inventory facility and senior unsecured revolving credit facility by one year to August 2027 and August 2029, respectively, for each extending lender. The maturity dates with respect to the non-extending lender under our senior secured hedged inventory facility and senior unsecured revolving credit facility (which represents a commitment of approximately $64 million out of total commitments of $1.35 billion from all lenders under each facility) remain August 2026 and August 2027, respectively.

Usage of our credit facilities, and, in turn, our commercial paper program, is subject to ongoing compliance with covenants. The credit agreements for our revolving credit facilities (which impact our ability to access our commercial paper program because they provide the financial backstop that supports our short-term credit ratings) and the indentures governing our senior notes contain cross-default provisions. A default under our credit agreements or indentures would permit the lenders to accelerate the maturity of the outstanding debt. As long as we are in compliance with the provisions in our credit agreements, our ability to make distributions of available cash is not restricted. We were in compliance with the covenants contained in our credit agreements and indentures as of September 30, 2024.

We believe that we have, and will continue to have, the ability to access our commercial paper program and credit facilities, which we use to meet our short-term cash needs. We believe that our financial position remains strong and we have sufficient liquid assets, cash flow from operating activities and borrowing capacity under our credit agreements to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. We are, however, subject to business and operational risks that could adversely affect our cash flow, including extended disruptions in the financial markets and/or energy price volatility resulting from current macroeconomic and geopolitical conditions, including actions by the Organization of Petroleum Exporting Countries (OPEC). A prolonged material decrease in our cash flows would likely produce an adverse effect on our borrowing capacity and cost of borrowing. Our borrowing capacity and borrowing costs are also impacted by our credit rating. See Item 1A. “Risk Factors” included in our 2023 Annual Report on Form 10-K for further discussion regarding risks that may impact our liquidity and capital resources.

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Non-GAAP Financial Liquidity Measures

Management uses the non-GAAP financial liquidity measures Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions to assess the amount of cash that is available for distributions, debt repayments, common equity repurchases and other general partnership purposes. Adjusted Free Cash Flow is defined as Net cash provided by operating activities, less Net cash provided by/(used in) investing activities, which primarily includes acquisition, investment and maintenance capital expenditures, investments in unconsolidated entities and the impact from the purchase and sale of linefill, net of proceeds from the sales of assets and further impacted by distributions to and contributions from noncontrolling interests and proceeds from the issuance of related party notes. Adjusted Free Cash Flow is further reduced by cash distributions paid to our preferred and common unitholders to arrive at Adjusted Free Cash Flow after Distributions. Also see “Results of Operations–Non-GAAP Financial Measures” above for more information about our non-GAAP measures.

The following table sets forth the reconciliation of the non-GAAP financial liquidity measures Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions from Net Cash Provided by Operating Activities (in millions):

Nine Months Ended
September 30,
20242023
Net cash provided by operating activities$1,763 $1,716 
Adjustments to reconcile net cash provided by operating activities to adjusted free cash flow:
Net cash used in investing activities (1)
(1,240)(444)
Cash contributions from noncontrolling interests40 53 
Cash distributions paid to noncontrolling interests (2)
(310)(237)
Proceeds from the issuance of related party notes (1)
629 — 
Adjusted Free Cash Flow
$882 $1,088 
Cash distributions (3)
(858)(738)
Adjusted Free Cash Flow after Distributions (4)
$24 $350 
(1)PAA and certain Plains entities have issued promissory notes by and among such entities to facilitate financing. “Proceeds from the issuance of related party notes” has an equal and offsetting cash outflow associated with our investment in related party notes, which is included as a component of “Net cash used in investing activities.” See Note 8 to our Condensed Consolidated Financial Statements for additional information on our related party notes.
(2)Cash distributions paid during the period presented.
(3)Cash distributions paid to our preferred and common unitholders during the period presented.
(4)Excess Adjusted Free Cash Flow after Distributions is retained to establish reserves for future distributions, capital expenditures, debt reduction and other partnership purposes. Adjusted Free Cash Flow after Distributions shortages, if any, may be funded from previously established reserves, cash on hand or from borrowings under our credit facilities or commercial paper program.

Cash Flow from Operating Activities
 
For a comprehensive discussion of the primary drivers of cash flow from operating activities, including the impact of varying market conditions and the timing of settlement of our derivatives, see Item 7. “Liquidity and Capital Resources—Cash Flow from Operating Activities” included in our 2023 Annual Report on Form 10-K.
 
Net cash provided by operating activities for the first nine months of 2024 and 2023 was $1.763 billion and $1.716 billion, respectively, and primarily resulted from earnings from our operations.
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Investing Activities

Capital Expenditures
 
In addition to our operating needs, we also use cash for our investment capital projects, maintenance capital activities and acquisition activities. We fund these expenditures with cash generated by operating activities, financing activities and/or proceeds from asset sales. The following table summarizes our investment, maintenance and acquisition capital expenditures (in millions):

Nine Months Ended
September 30,
 20242023
Investment capital (1) (2) (3)
$295 $285 
Maintenance capital (1) (3)
188 169 
Acquisition capital (2) (4)
146 295 
 $629 $749 
(1)Capital expenditures made to expand the existing operating and/or earnings capacity of our assets are classified as “Investment capital”. Capital expenditures made to replace and/or refurbish partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets are classified as “Maintenance capital”.
(2)Contributions to unconsolidated entities, accounted for under the equity method of accounting, that are related to investment capital projects by such entities are recognized in “Investment capital”. Acquisitions of initial investments or additional interests in unconsolidated entities are included in “Acquisition capital”.
(3)Investment capital and maintenance capital, net to our 65% interest in the Permian JV, was approximately $232 million and $174 million, respectively, for the nine months ended September 30, 2024, and approximately $221 million and $158 million, respectively, for the nine months ended September 30, 2023.
(4)Acquisition capital, net to our 65% interest in the Permian JV, was approximately $141 million and $192 million for the nine months ended September 30, 2024 and 2023, respectively. Acquisition capital for the 2024 period primarily included the acquisition of additional ownership interests in equity method investees. Acquisition capital for the 2023 period was mainly comprised of the Rattler Permian Transaction. See Note 7 to our Consolidated Financial Statements included in Part IV of our 2023 Annual Report on Form 10-K for information regarding this transaction.

2024 Investment and Maintenance Capital. Total investment capital for the year ending December 31, 2024 is projected to be approximately $455 million ($360 million net to our interest). Approximately half of our projected investment capital expenditures are expected to be invested in the Permian JV assets. Additionally, maintenance capital for 2024 is projected to be approximately $270 million ($250 million net to our interest). We expect to fund our 2024 investment and maintenance capital expenditures primarily with retained cash flow.

Divestitures

Proceeds from the sale of assets have generally been used to fund our investment capital projects and reduce debt levels. The following table summarizes the proceeds received during the first nine months of 2024 and 2023 from sales of assets (in millions):

Nine Months Ended
September 30,
20242023
Proceeds from divestitures (1)
$8 $286 
(1)Represents proceeds, including working capital adjustments, net of transaction costs. The proceeds from divestitures for the nine months ended September 30, 2023 were primarily from the sale of our 21% non-operated/undivided joint interest in the Keyera Fort Saskatchewan facility in February 2023. See Note 7 to our Consolidated Financial Statements included in Part IV of our 2023 Annual Report on Form 10-K for additional discussion of this transaction.

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Ongoing Activities Related to Strategic Transactions

We are continuously engaged in the evaluation of potential transactions that support our current business strategy. In the past, such transactions have included the acquisition of assets that complement our existing footprint, the sale of non-core assets, the sale of partial interests in assets to strategic joint venture partners, and large investment capital projects. With respect to a potential acquisition or divestiture, we may conduct an auction process or participate in an auction process conducted by a third-party or we may negotiate a transaction with one or a limited number of potential sellers (in the case of an acquisition) or buyers (in the case of a divestiture). Such transactions could have a material effect on our financial condition and results of operations.

We typically do not announce a transaction until after we have executed a definitive agreement. In certain cases, in order to protect our business interests or for other reasons, we may defer public announcement of a transaction until closing or a later date. Past experience has demonstrated that discussions and negotiations regarding a potential transaction can advance or terminate in a short period of time. Moreover, the closing of any transaction for which we have entered into a definitive agreement may be subject to customary and other closing conditions, which may not ultimately be satisfied or waived. Accordingly, we can give no assurance that our current or future efforts with respect to any such transactions will be successful, and we can provide no assurance that our financial expectations with respect to such transactions will ultimately be realized. See Item 1A. “Risk Factors—Risks Related to Our Business—Acquisitions and divestitures involve risks that may adversely affect our business” included in our 2023 Annual Report on Form 10-K.

Related Party Promissory Notes

In July 2024, we and certain Plains entities issued promissory notes to facilitate financing. The cash outflow associated with our investment in CAD$865 million ($629 million) of notes has an equal and offsetting cash inflow associated with proceeds from our issuance of notes for the same face value amount, which is included as a component of financing activities. See Note 8 to our Condensed Consolidated Financial Statements for additional information on our related party notes.

Financing Activities

Our financing activities primarily relate to funding investment capital projects, acquisitions and refinancing of our debt maturities, as well as short-term working capital (including borrowings for NYMEX and ICE margin deposits) and hedged inventory borrowings related to our NGL business and contango market activities.

Borrowings and Repayments Under Credit Agreements

During the nine months ended September 30, 2024, we had net repayments under our commercial paper program of $433 million. The net repayments resulted primarily from cash flow from operating activities and proceeds from the issuance of $650 million, 5.70% senior notes in June 2024, which offset borrowings during the period related to funding needs for capital investments, inventory purchases and other general partnership purposes.

We had no net borrowings or repayments under our credit facilities or commercial paper program during the nine months ended September 30, 2023.

Senior Notes

In June 2024, we completed the offering of $650 million, 5.70% senior notes due September 2034 at a public offering price of 99.953%. Interest payments are due on March 15 and September 15 of each year, commencing on March 15, 2025. We used the net proceeds from this offering of $643 million, after deducting the underwriting discount and offering expenses, along with other cash on hand, to repay on November 1, 2024 the principal amount of our $750 million, 3.60% senior notes due November 2024. Prior to such repayment, we used a portion of the net proceeds from the offering to repay outstanding borrowings under our commercial paper program and for general partnership purposes.

Common Equity Repurchase Program

There were no repurchases under the Common Equity Repurchase Program (the “Program”) during the nine months ended September 30, 2024 or 2023. The remaining available capacity under the Program as of September 30, 2024 was $198 million.
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Registration Statements

We periodically access the capital markets for both equity and debt financing. We have filed with the SEC a universal shelf registration statement that, subject to effectiveness at the time of use, allows us to issue up to a specified amount of debt or equity securities (“Traditional Shelf”), under which we had approximately $1.1 billion of unsold securities available at September 30, 2024. We did not conduct any offerings under our Traditional Shelf during the nine months ended September 30, 2024. We also have access to a universal shelf registration statement (“WKSI Shelf”), which provides us with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and our capital needs. The offering of $650 million, 5.70% senior notes in June 2024 was conducted under our WKSI Shelf.

Distributions to Our Unitholders

Series A preferred unitholders. On November 14, 2024, we will pay a quarterly cash distribution of approximately $0.615 per unit to Series A preferred unitholders of record at the close of business on October 31, 2024 for the period from July 1, 2024 through September 30, 2024.

Series B preferred unitholders. On November 15, 2024, we will pay a quarterly cash distribution of approximately $24.25 per unit to Series B preferred unitholders of record at the close of business on November 1, 2024 for the period from August 15, 2024 through November 14, 2024.

Common Unitholders. On November 14, 2024, we will pay a quarterly cash distribution of $0.3175 per common unit ($1.27 per unit on an annualized basis) to common unitholders of record at the close of business on October 31, 2024 for the period from July 1, 2024 through September 30, 2024, which is unchanged from the distribution per unit paid in August of 2024.

See Note 6 to our Condensed Consolidated Financial Statements for details of distributions paid during or pertaining to the first nine months of 2024, including distributions to our preferred unitholders.

Distributions to Noncontrolling Interests

Distributions to noncontrolling interests represent amounts paid on interests in consolidated entities that are not owned by us. As of September 30, 2024, noncontrolling interests in our subsidiaries consisted of (i) a 35% interest in the Permian JV, (ii) a 30% interest in Cactus II and (iii) a 33% interest in Red River. See Note 6 to our Condensed Consolidated Financial Statements for details of distributions paid to noncontrolling interests during the nine months ended September 30, 2024.

Related Party Promissory Notes

In July 2024, we and certain Plains entities issued promissory notes to facilitate financing. The cash inflow associated with proceeds from our issuance of CAD$865 million ($629 million) of notes has an equal and offsetting cash outflow associated with our investment in notes for the same face value amount, which is included as a component of investing activities. See Note 8 to our Condensed Consolidated Financial Statements for additional information on our related party notes.

Contingencies
 
For a discussion of contingencies that may impact us, see Note 9 to our Condensed Consolidated Financial Statements.

Commitments
 
Purchase Obligations. In the ordinary course of doing business, we purchase crude oil and NGL from third parties under contracts, the majority of which range in term from thirty-day evergreen to five years, with a limited number of contracts with remaining terms extending up to 10 years. We establish a margin for these purchases by entering into various types of physical and financial sale and exchange transactions through which we seek to maintain a position that is substantially balanced between purchases on the one hand and sales and future delivery obligations on the other. We do not expect to use a significant amount of internal capital to meet these obligations, as the obligations will be funded by corresponding sales to entities that we deem creditworthy or who have provided credit support we consider adequate.

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The following table includes our best estimate of the amount and timing of these payments as of September 30, 2024 (in millions):

Remainder of 202420252026202720282029 and ThereafterTotal
Crude oil, NGL and other purchases (1)
$7,062 $22,115 $19,623 $17,408 $14,812 $38,225 $119,245 
(1)Amounts are primarily based on estimated volumes and market prices based on average activity during September 2024. The actual physical volume purchased and actual settlement prices will vary from the assumptions used in the table. Uncertainties involved in these estimates include levels of production at the wellhead, weather conditions, changes in market prices and other conditions beyond our control.

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, NGL and natural gas. Our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the product is purchased. Generally, these letters of credit are issued for periods of up to seventy days and are terminated upon completion of each transaction. Additionally, we issue letters of credit to support insurance programs, derivative transactions, including hedging-related margin obligations, and construction activities. At September 30, 2024 and December 31, 2023, we had outstanding letters of credit of approximately $108 million and $205 million, respectively.

Recent Accounting Pronouncements

See Note 1 to our Condensed Consolidated Financial Statements.
 
FORWARD-LOOKING STATEMENTS

All statements included in this report, other than statements of historical fact, are forward-looking statements, including but not limited to statements incorporating the words “anticipate,” “believe,” “estimate,” “expect,” “plan,” “intend” and “forecast,” as well as similar expressions and statements regarding our business strategy, plans and objectives for future operations. The absence of such words, expressions or statements, however, does not mean that the statements are not forward-looking. Any such forward-looking statements reflect our current views with respect to future events, based on what we believe to be reasonable assumptions. Certain factors could cause actual results or outcomes to differ materially from the results or outcomes anticipated in the forward-looking statements. The most important of these factors include, but are not limited to:

•general economic, market or business conditions in the United States and elsewhere (including the potential for a recession or significant slowdown in economic activity levels, the risk of persistently high inflation and continued supply chain issues, the impact of global public health events, such as pandemics, on demand and growth, and the timing, pace and extent of economic recovery) that impact (i) demand for crude oil, drilling and production activities and therefore the demand for the midstream services we provide and (ii) commercial opportunities available to us;
•declines in global crude oil demand and/or crude oil prices or other factors that correspondingly lead to a significant reduction of North American crude oil and natural gas liquids (“NGL”) production (whether due to reduced producer cash flow to fund drilling activities or the inability of producers to access capital, or both, the unavailability of pipeline and/or storage capacity, the shutting-in of production by producers, government-mandated pro-ration orders, or other factors), which in turn could result in significant declines in the actual or expected volume of crude oil and NGL shipped, processed, purchased, stored, fractionated and/or gathered at or through the use of our assets and/or the reduction of the margins we can earn or the commercial opportunities that might otherwise be available to us;
•fluctuations in refinery capacity and other factors affecting demand for various grades of crude oil and NGL and resulting changes in pricing conditions or transportation throughput requirements;
•unanticipated changes in crude oil and NGL market structure, grade differentials and volatility (or lack thereof);
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•the effects of competition and capacity overbuild in areas where we operate, including downward pressure on rates, volumes and margins, contract renewal risk and the risk of loss of business to other midstream operators who are willing or under pressure to aggressively reduce transportation rates in order to capture or preserve customers;
•negative societal sentiment regarding the hydrocarbon energy industry and the continued development and consumption of hydrocarbons, which could influence consumer preferences and governmental or regulatory actions that adversely impact our business;
•environmental liabilities, litigation or other events that are not covered by an indemnity, insurance or existing reserves;
•the occurrence of a natural disaster, catastrophe, terrorist attack (including eco-terrorist attacks) or other event that materially impacts our operations, including cyber or other attacks on our or our service providers’ electronic and computer systems;
•weather interference with business operations or project construction, including the impact of extreme weather events or conditions (including wildfires and drought);
•the impact of current and future laws, rulings, legislation, governmental regulations, executive orders, trade policies, accounting standards and statements, and related interpretations that (i) prohibit, restrict or regulate the development of oil and gas resources and the related infrastructure on lands dedicated to or served by our pipelines or (ii) negatively impact our ability to develop, operate or repair midstream assets;
•negative impacts on production levels in the Permian Basin or elsewhere due to issues associated with (or laws, rules or regulations relating to) hydraulic fracturing and related activities (including wastewater injection or disposal), including earthquakes, subsidence, expansion or other issues;
•the pace of development of natural gas or other infrastructure and its impact on expected crude oil production growth in the Permian Basin;
•loss of key personnel and inability to attract and retain new talent;
•disruptions to futures markets for crude oil, NGL and other petroleum products, which may impair our ability to execute our commercial or hedging strategies;
•the effectiveness of our risk management activities;
•shortages or cost increases of supplies, materials or labor;
•maintenance of our credit ratings and ability to receive open credit from our suppliers and trade counterparties;
•the successful operation of joint ventures and joint operating arrangements we enter into from time to time, whether relating to assets operated by us or by third parties, and the successful integration and future performance of acquired assets or businesses;
•the availability of, and our ability to consummate, acquisitions, divestitures, joint ventures or other strategic opportunities;
•the refusal or inability of our customers or counterparties to perform their obligations under their contracts with us (including commercial contracts, asset sale agreements and other agreements), whether justified or not and whether due to financial constraints (such as reduced creditworthiness, liquidity issues or insolvency), market constraints, legal constraints (including governmental orders or guidance), the exercise of contractual or common law rights that allegedly excuse their performance (such as force majeure or similar claims) or other factors;
•our inability to perform our obligations under our contracts, whether due to non-performance by third parties, including our customers or counterparties, market constraints, third-party constraints, supply chain issues, legal constraints (including governmental orders or guidance), or other factors or events;
•the incurrence of costs and expenses related to unexpected or unplanned capital or maintenance expenditures, third-party claims or other factors;
•failure to implement or capitalize, or delays in implementing or capitalizing, on investment capital projects, whether due to permitting delays, permitting withdrawals or other factors;
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•tightened capital markets or other factors that increase our cost of capital or limit our ability to obtain debt or equity financing on satisfactory terms to fund additional acquisitions, investment capital projects, working capital requirements and the repayment or refinancing of indebtedness;
•the amplification of other risks caused by volatile or closed financial markets, capital constraints, liquidity concerns and inflation;
•the use or availability of third-party assets upon which our operations depend and over which we have little or no control;
•the currency exchange rate of the Canadian dollar to the United States dollar;
•inability to recognize current revenue attributable to deficiency payments received from customers who fail to ship or move more than minimum contracted volumes until the related credits expire or are used;
•significant under-utilization of our assets and facilities;
•increased costs, or lack of availability, of insurance;
•fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our long-term incentive plans;
•risks related to the development and operation of our assets; and
•other factors and uncertainties inherent in the transportation, storage, terminalling and marketing of crude oil, as well as in the processing, transportation, fractionation, storage and marketing of NGL.
 
Other factors described herein, as well as factors that are unknown or unpredictable, could also have a material adverse effect on future results. Please read “Risk Factors” discussed in Item 1A of our 2023 Annual Report on Form 10-K. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.
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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to various market risks, including commodity price risk and interest rate risk. We use various derivative instruments to manage such risks and, in certain circumstances, to realize incremental margin during volatile market conditions. Our risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring our exchange-cleared and over-the-counter positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity. We have a risk management function that has direct responsibility and authority for our risk policies, related controls around commercial activities and certain aspects of corporate risk management. Our risk management function also approves all new risk management strategies through a formal process. The following discussion addresses each category of risk.
 
Commodity Price Risk
 
We use derivative instruments to hedge price risk associated with the following commodities:
 
•Crude oil
 
We utilize crude oil derivatives to hedge commodity price risk inherent in our pipeline, terminalling and merchant activities. Our objectives for these derivatives include hedging anticipated purchases and sales, stored inventory and basis differentials. We manage these exposures with various instruments including futures, forwards, swaps and options.

•Natural gas
 
We utilize natural gas derivatives to hedge commodity price risk inherent in our natural gas processing assets (natural gas purchase component of the frac spread). Additionally, we utilize natural gas derivatives to hedge anticipated operational fuel gas requirements related to our natural gas processing and NGL fractionation plants. We manage these exposures with various instruments including futures, swaps and options.
 
•NGL and other
 
We utilize NGL derivatives, primarily propane and butane derivatives, to hedge commodity price risk inherent in our commercial activities, including the sale of the individual specification products extracted in our natural gas processing assets (sale of specification NGL products component of the frac spread), as well as other net sales of NGL inventory, held mainly at our owned NGL storage terminals. Our objectives for these derivatives include hedging anticipated purchases and sales and stored inventory. We manage these exposures with various instruments including futures, forwards, swaps and options.
 
See Note 7 to our Condensed Consolidated Financial Statements for further discussion regarding our hedging strategies and objectives.

The fair value of our commodity derivatives and the change in fair value as of September 30, 2024 that would be expected from a 10% price increase or decrease is shown in the table below (in millions):

Fair ValueEffect of 10%
Price Increase		Effect of 10%
Price Decrease
Crude oil$(23)$52 $(51)
Natural gas(39)$4 $(4)
NGL and other(26)$(49)$49 
Total fair value$(88)  
 
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The fair values presented in the table above reflect the sensitivity of the derivative instruments only and do not include the effect of the underlying hedged commodity. Price-risk sensitivities were calculated by assuming an across-the-board 10% increase or decrease in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of an actual 10% change in near-term commodity prices, the fair value of our derivative portfolio would typically change less than that shown in the table as changes in near-term prices are not typically mirrored in delivery months further out.
 
Interest Rate Risk
 
Debt. Our use of variable rate debt and any forecasted issuances of fixed rate debt expose us to interest rate risk. Therefore, from time to time, we use interest rate derivatives to hedge interest rate risk associated with anticipated interest payments and, in certain cases, outstanding debt instruments. All of our senior notes are fixed rate notes and thus are not subject to interest rate risk. We did not have any variable rate debt outstanding at September 30, 2024. The average interest rate on variable rate debt that was outstanding during the nine months ended September 30, 2024 was 5.8%, based upon rates in effect during such period. The fair value of our interest rate derivatives was a net asset of $7 million as of September 30, 2024. A 10% increase in the forward SOFR curve as of September 30, 2024 would have resulted in an increase of $12 million to the fair value of our interest rate derivatives. A 10% decrease in the forward SOFR curve as of September 30, 2024 would have resulted in a decrease of $12 million to the fair value of our interest rate derivatives. See Note 7 to our Condensed Consolidated Financial Statements for a discussion of our interest rate risk hedging activities.

Series B Preferred Units. Distributions on the Series B preferred units accumulate and are payable quarterly in arrears on the 15th day of February, May, August and November. Distributions on the Series B preferred units accumulate based on the applicable three-month SOFR, plus certain adjustments. Based upon the Series B preferred units outstanding at September 30, 2024 and the liquidation preference of $1,000 per unit, a change of 100 basis points in interest rates would increase or decrease the annual distributions on the Series B preferred units by approximately $8 million. See Note 11 to our Consolidated Financial Statements included in Part IV of our 2023 Annual Report on Form 10-K for additional information regarding our Series B preferred unit distributions.

Item 4. CONTROLS AND PROCEDURES
 
Disclosure Controls and Procedures
 
We maintain written disclosure controls and procedures, which we refer to as our “DCP.” Our DCP is designed to ensure that information required to be disclosed by us in reports that we file under the Securities Exchange Act of 1934 (the “Exchange Act”) is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow for timely decisions regarding required disclosure.
 
Applicable SEC rules require an evaluation of the effectiveness of our DCP. Management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our DCP as of September 30, 2024, the end of the period covered by this report, and, based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our DCP is effective.
 
Changes in Internal Control over Financial Reporting
 
In addition to the information concerning our DCP, we are required to disclose certain changes in internal control over financial reporting. There have been no changes in our internal control over financial reporting during the third quarter of 2024 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
 
Certifications
 
The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a) are filed with this report as Exhibits 31.1 and 31.2. The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. 1350 are furnished with this report as Exhibits 32.1 and 32.2.

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PART II. OTHER INFORMATION

Item 1.   LEGAL PROCEEDINGS
 
The information required by this item is included in Note 9 to our Condensed Consolidated Financial Statements, and is incorporated herein by reference thereto.
 
Item 1A. RISK FACTORS
 
For a discussion of our risk factors, see Item 1A. of our 2023 Annual Report on Form 10-K. Those risks and uncertainties are not the only ones facing us and there may be additional matters of which we are unaware or that we currently consider immaterial. All of those risks and uncertainties could adversely affect our business, financial condition and/or results of operations.
 
Item 2.   UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
 
Sales of Unregistered Securities

The Omnibus Agreement, entered into as part of the Simplification Transactions, which closed on November 15, 2016, provides for the mechanics by which (i) the total number of PAGP’s outstanding Class A shares will equal the number of AAP units held by PAGP, and (ii) the total number of our common units held by AAP will equal the sum of the number of outstanding Class A units of AAP (“AAP units”) and the number of AAP units that are issuable to the holders of vested and earned Class B units of AAP (“AAP Management Units”). As such, we are obligated to issue common units to AAP in connection with PAGP’s issuance of Class A shares upon PAGP LTIP award vestings. During the three months ended September 30, 2024, we issued 202,002 common units to AAP in connection with PAGP LTIP award vestings. This issuance was exempt from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereof.

Issuer Purchases of Equity Securities

None.
    
Item 3.   DEFAULTS UPON SENIOR SECURITIES
 
None.
 
Item 4.   MINE SAFETY DISCLOSURES
 
Not applicable.
 
Item 5.   OTHER INFORMATION
 
During the quarter ended September 30, 2024, none of our directors or officers (as defined in Rule 16a-1(f) of the Securities Exchange Act of 1934) adopted or terminated a Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement (as such terms are defined in Item 408 of Regulation S-K).
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Item 6.   EXHIBITS
 
Exhibit No.Description
3.1—
3.2—
3.3—
3.4—
3.5—
3.6—
3.7—
3.8—
3.9—
3.10—
3.11—
3.12—
3.13—
3.14—
3.15—
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3.16—
3.17—
3.18—
3.19—
3.20—
3.21—
3.22—
4.1—
4.2—
4.3—
4.4—
4.5—
4.6—
4.7—
4.8—
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4.9—
4.10—
4.11—
4.12—
4.13—
4.14—
4.15—
4.16—
4.17—
10.1—
10.2—
10.3* †
—
10.4* †
—
31.1 †—
31.2 †—
32.1 ††—
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32.2 ††—
101.INS†—XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH†—Inline XBRL Taxonomy Extension Schema Document
101.CAL†—Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF†—Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB†—Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE†—Inline XBRL Taxonomy Extension Presentation Linkbase Document
104†—Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
†    Filed herewith.
††    Furnished herewith.
*    Management compensatory plan or arrangement.

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SIGNATURES
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 PLAINS ALL AMERICAN PIPELINE, L.P.
   
 By:PAA GP LLC,
  its general partner
   
 By:Plains AAP, L.P.,
  its sole member
   
 By:Plains All American GP LLC,
  its general partner
   
 By:
/s/ Willie Chiang
  Willie Chiang,
  Chief Executive Officer of Plains All American GP LLC
  (Principal Executive Officer)
   
November 8, 2024  
   
 By:
/s/ Al Swanson
  Al Swanson,
  Executive Vice President and Chief Financial Officer of Plains All American GP LLC
  (Principal Financial Officer)
   
November 8, 2024  
   
 By:
/s/ Chris Herbold
  Chris Herbold,
  Senior Vice President, Finance and Chief Accounting Officer of Plains All American GP LLC
  (Principal Accounting Officer)
  
November 8, 2024 



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