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Item 7. Management’s Discussion and Analysis

2025-02-28 compared with 2024-02-29 · 188 added, 136 removed, 552 unchanged (37% of the section changed)

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• Recent Accounting Pronouncements

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A comparative discussion of our 2023 to 2022 operating results and performance measures can be found in Item 7.

“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations” included in our Annual Report on Form 10-K for the year ended December 31, 2022 filed with the SEC on March 1, 2023.

Executive Summary

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Our business model integrates large-scale supply aggregation capabilities with the ownership and operation of critical midstream infrastructure systems that connect major producing regions to key demand centers and export terminals.

As one of the largest midstream service providers in North America, we own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and NGL producing basins (including the Permian Basin) and transportation corridors and at major market hubs in the United States and Canada.

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.

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We believe reliable, affordable, and responsible energy resources are all critical components to maintain energy security and global stability, requiring all sources of energy including both hydrocarbons and renewables.

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Consistent with the forecast from the EIA’s Short-Term Energy Outlook (as depicted in the chart above), we expect crude oil demand to continue to increase, driven largely by our view that hydrocarbon-based fuels are the most efficient fuels for the transportation of people and goods, and hydrocarbon-based products provide the building blocks for modern civilization such as fertilizers, plastics and cement.

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production growth in 2024.

The remainder of the U.S.

unconventional plays continue to see modest growth.

We expect the Permian Basin to be a key contributor to global supply for years to come, based on strong economics and the recent wave of consolidation leading to more stable activity levels over a wide range of commodity price environments.

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Overview of Operating Results

We recognized net income attributable to PAA of $1.230 billion for the year ended December 31, 2023 compared to net income attributable to PAA of $1.037 billion for the year ended December 31, 2022.

Our results include the benefit of higher tariff volumes and tariff escalations on our crude oil pipelines in 2023, as well as the impact of acquisitions.

In addition, the 2022 comparative period includes higher costs from the increase in the accrual for estimated costs associated with the Line 901 incident.

Additionally, net income for 2023 includes favorable impacts from gains on asset sales and the mark-to-market adjustment of the Preferred Distribution Rate Reset Option compared to losses in the 2022 period, which were partially offset by the benefit to the 2022 period of a gain recognized associated with the remeasurement of our previously held 65% interest in Cactus II to fair value in connection with our acquisition of an additional 5% interest in Cactus II in November 2022.

We recognized net income attributable to PAA of $772 million for the year ended December 31, 2024 compared to net income attributable to PAA of $1.230 billion for the year ended December 31, 2023.

The decrease in net income attributable to PAA was largely driven by higher costs in the 2024 period associated with the Line 901 incident that occurred in May 2015 (including $225 million related to the write-off of a receivable for insurance proceeds in the fourth quarter of 2024 and $120 million related to settlements in the third quarter of 2024), losses on asset sales, asset impairments and other related items (as compared to gains from such items in the 2023 period), and higher income tax expense largely associated with Canadian withholding tax.

In addition, net income attributable to PAA for the 2023 period included the favorable impact of gains from the mark-to-market adjustment of the Preferred Distribution Rate Reset Option.

However, our Segment Adjusted EBITDA increased in 2024 compared to 2023 due to more favorable results from our Crude Oil segment, partially offset by lower contributions from our NGL segment.

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

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Index to Financial Statements

Results of Operations

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Depreciation and amortization (1,026) (1,048) 22 2 %

Gains/(losses) on asset sales and asset impairments, net 152 (269) 421 157 %

Gains/(losses) on asset sales, asset impairments and other, net

(160) 152 (312) (205) %

Equity earnings in unconsolidated entities 452 369 83 22 %

Gains/(losses) on investments in unconsolidated entities, net 28 346 (318) (92) %

Gain on investments in unconsolidated entities, net

15 28 (13) (46) %

Interest expense, net (1)

Other income/(expense), net 102 (219) 321 147 %

(430) (386) (44) (11) %

Other income, net (1)

65 102 (37) (36) %

Income tax expense (167) (121) (46) (38) %

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** Indicates that variance as a percentage is not meaningful.

(1) “Interest expense, net” and “Other income, net” each include $48 million for the year ended December 31, 2024 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 generally explained in large part by changes in commodity prices.

Our crude oil and NGL merchant activities are not directly affected by the absolute level of prices because the commodities that we buy and sell are generally indexed to the same pricing indices.

Both product sales revenues and purchases and related costs will fluctuate with market prices;

however, the absolute margins related to those sales and purchases will not necessarily have a corresponding increase or decrease.

Additionally, product sales revenues include the impact of gains and losses related to derivative instruments used to manage our exposure to commodity price risk associated with such sales and purchases.

A majority of our sales and purchases are indexed to West Texas Intermediate (“WTI”).

The following table presents the range of the NYMEX WTI benchmark price of crude oil over the last two years (in dollars per barrel):

Crude Oil Price

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.

A majority of our crude oil sales and purchases are indexed to the prompt month price of the NYMEX Light, Sweet crude oil futures contract (“NYMEX Price”) and our NGL sales are indexed to Mont Belvieu prices.

The following table presents the range of the NYMEX Price over the last two years (in dollars per barrel):

During the Year Ended December 31, Low High Average

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2023 $ 67 $ 94 $ 78

Product sales revenues and purchases decreased for the year ended December 31, 2023 compared to the year ended December 31, 2022 primarily due to lower commodity prices in 2023.

The impact of fluctuations of derivative mark-to-market valuations also resulted in lower product sales revenues in 2023 compared to 2022.

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Revenues from services increased for the year ended December 31, 2023 compared to the year ended December 31, 2022 primarily due to higher volumes and tariff escalations in 2023, as well as the impact of acquisitions, partially offset by the impact of lower commodity prices in 2023.

Product sales revenues and purchases increased for the year ended December 31, 2024 compared to the year ended December 31, 2023 primarily due to higher crude oil sales volumes.

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Revenues from services increased for the year ended December 31, 2024 compared to the year ended December 31, 2023 primarily due to higher pipeline volumes and tariff escalations, as well as the impact of acquisitions.

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

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General and Administrative Expenses

The increase in general and administrative expenses for the year ended December 31, 2023 compared to the year ended December 31, 2022 was primarily due to (i) higher employee-related costs, including an increase in equity-indexed compensation expense (a portion of which is excluded in the calculation of Adjusted EBITDA and Segment Adjusted EBITDA) due to a higher common unit price and higher number of outstanding units assumed probable of vesting and (ii) higher information systems costs due to ongoing systems integration work, partially offset by (iii) decreases across several categories.

Depreciation and Amortization

Depreciation and amortization expense increased for the year ended December 31, 2023 compared to the year ended December 31, 2022 largely driven by acquisitions, including an additional interest in Cactus II and the remaining 43% in OMOG.

See Note 7 to our Consolidated Financial Statements for additional information.

Gains/(Losses) on Asset Sales and Asset Impairments, Net

The net gain on asset sales and asset impairments for the year ended December 31, 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.

The net loss on asset sales and asset impairments for 2022 was primarily comprised of (i) a $330 million non-cash impairment charge recognized in the fourth quarter of 2022 related to certain crude oil assets in California, partially offset by (ii) gains recognized from the sale of land and related assets in Long Beach, California, as well as Line 901 and the Sisquoc to Pentland portion of Line 903, a portion of which relates to the transfer of an asset retirement obligation to the purchaser.

The increase in general and administrative expenses for the year ended December 31, 2024 compared to the year ended December 31, 2023 was primarily due to (i) higher employee-related costs, (ii) higher information systems costs due to ongoing systems integration work and (iii) higher office rent due to an operating cost abatement in the prior year.

Gains/(Losses) on Asset Sales, Asset Impairments and Other, Net

The net loss on asset sales and asset impairments for the year ended December 31, 2024 was primarily due to non-cash charges related to the write-down of certain of our long-lived U.S.

terminal assets included in our NGL segment due to asset impairments and accelerated depreciation in the fourth quarter of 2024.

The net gain on asset sales and asset impairments for the year ended December 31, 2023 was primarily related to the sale of our ownership interest in the Keyera Fort Saskatchewan facility in the first quarter of 2023.

See Note 6 and Note 7 to our Consolidated Financial Statements for additional information regarding these asset sales and asset impairments.

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

Gains/(Losses) on Investments in Unconsolidated Entities, Net

In the third quarter of 2023, we recognized a gain of $29 million related to the Permian JV’s acquisition of the remaining 43% interest in OMOG.

See Note 7 to our Consolidated Financial Statements for additional information regarding this transaction.

During the fourth quarter of 2022, we recognized (i) a gain of $370 million associated with the remeasurement of our previously held 65% interest in Cactus II to fair value in connection with our acquisition of an additional 5% interest in Cactus II in November 2022 and (ii) a loss of $25 million associated with the difference between the fair value and historical book value of assets contributed by the Permian JV in exchange for an additional interest in OMOG.

See Note 7 and Note 8 to our Consolidated Financial Statements for additional information regarding these transactions.

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Interest Expense, Net

The decrease in interest expense for the year ended December 31, 2023 compared to the year ended December 31, 2022 was primarily due to a lower weighted average debt balance during the 2023 period largely driven by the repayment of $750 million of senior notes in March 2022, $400 million of senior notes in January 2023 and $700 million of senior notes in October 2023.

Gain on Investments in Unconsolidated Entities, Net

In the fourth quarter of 2024, we recognized a gain of $15 million related to our acquisition of the remaining 50% interest in Midway Pipeline LLC.

In the third quarter of 2023, we recognized a gain of $29 million related to the Permian JV’s acquisition of the remaining 43% interest in OMOG JV Holdings LLC.

See Note 7 to our Consolidated Financial Statements for additional information regarding these transactions.

Interest Expense, Net and Other Income/(Expense), Net

For the year ended December 31, 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 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.

See Note 10 to our Consolidated Financial Statements for additional information regarding our debt and related activities during the periods presented.

Other Income/(Expense), Net

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

Year Ended December 31,

Interest expense on third-party borrowings

Interest expense on related party promissory notes (1)

Capitalized interest

(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/(expense), net (in millions):

Year Ended December 31,

Gain/(loss) on mark-to-market adjustment of Preferred Distribution Rate Reset Option embedded derivative (1)

Interest income on related party promissory notes (1)

Interest income from other sources

Net gain/(loss) on foreign currency revaluation (2)

$ 102 $ (219)

(1) See Note 12 to our Consolidated Financial Statements for additional information.

Gain on mark-to-market adjustment of Preferred Distribution Rate Reset Option embedded derivative (3)

(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 United States Dollar to Canadian dollar exchange rate on the portion of our intercompany net investment that is not long-term in nature.

(3) See Note 12 to our Consolidated Financial Statements for additional information.

Income Tax (Expense)/Benefit

The net favorable income tax variance for the year ended December 31, 2023 compared to the year ended December 31, 2022 was primarily due to lower year-over-year income within our Canadian operations as impacted by fluctuations of derivative mark-to-market valuations.

The favorable variance was partially offset by the tax impact of the Keyera Fort Saskatchewan divestiture.

See Note 7 to our Consolidated Financial Statements for additional information regarding this transaction.

The net unfavorable income tax variance for the year ended December 31, 2024 compared to the year ended December 31, 2023 was primarily due to higher income tax expense in 2024 associated with Canadian withholding tax on dividends from our Canadian entities to other Plains entities driven by timing of dividend payments, including proceeds from asset divestitures.

Noncontrolling Interests

The increase in amounts attributable to noncontrolling interests for the year ended December 31, 2023 compared to the year ended December 31, 2022 was due to (i) higher net income recognized by the Permian JV in the 2023 period and (ii) the consolidation of Cactus II in November 2022.

The increase in amounts attributable to noncontrolling interests for the year ended December 31, 2024 compared to the year ended December 31, 2023 was due to higher net income recognized by the Permian JV and Cactus II related to higher volumes, as well as contributions from acquisitions completed by the Permian JV.

See Note 7 to our Consolidated Financial Statements for additional information.

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Non-GAAP Financial Measures

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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 Consolidated Financial Statements and accompanying notes.

See “—Liquidity and Capital Resources—Liquidity Measures” for additional information regarding Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions.

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Performance Measures

Adjusted EBITDA is defined as earnings before interest expense, income taxes, 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 and asset impairments and gains or losses on investments in unconsolidated entities, adjusted for certain selected items impacting comparability.

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 (i) interest expense, (ii) income tax (expense)/benefit, (iii) depreciation and amortization (including our proportionate share of depreciation and amortization, including write-downs related to cancelled projects and impairments, of unconsolidated entities), (iv) gains and losses on asset sales, asset impairments and other, net, (v) gains on investments in unconsolidated entities, net and (vi) interest income on promissory notes by and among PAA and certain Plains entities, and adjusted for (vii) certain selected items impacting comparability.

Adjusted EBITDA attributable to PAA excludes the portion of Adjusted EBITDA that is attributable to noncontrolling interests.

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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.”

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

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Net income $ 1,113 $ 1,502 $ (389) (26) %

Interest expense, net 386 405 (19) (5) %

Interest expense, net of certain items (1)

382 386 (4) (1) %

Income tax expense 167 121 46 38 %

Depreciation and amortization 1,026 1,048 (22) (2) %

(Gains)/losses on asset sales and asset impairments, net (152) 269 (421) (157) %

(Gains)/losses on investments in unconsolidated entities, net (28) (346) 318 92 %

(Gains)/losses on asset sales, asset impairments and other, net

160 (152) 312 205 %

Gain on investments in unconsolidated entities, net

(15) (28) 13 46 %

Depreciation and amortization of unconsolidated entities (2)

84 87 (3) (3) %

Selected Items Impacting Comparability:

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Mark-to-market adjustment of Preferred Distribution Rate Reset Option embedded derivative (4)

(58) 189 (247) **

Foreign currency revaluation (5)

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$ 3,326 $ 3,167 $ 159 5 %

Interest expense, net of certain non-cash items (8)

Interest expense, net of certain non-cash and other items (9)

(365) (367) 2 1 %

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Implied DCF Excess (14)

$ 978 $ 1,012

** Indicates that variance as a percentage is not meaningful.

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(1) Represents “Interest expense, net” as reported on our Consolidated Statements of Operations, net of interest income associated with promissory notes by and among PAA and certain Plains entities.

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(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.

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The associated gains and losses are not integral to our results and were thus classified as a selected item impacting comparability.

(5) Other income/(expense), net on our Consolidated Statements of Operations, adjusted for selected items impacting comparability (“Adjusted other income/(expense), net”) is included in Adjusted EBITDA and excluded from Segment Adjusted EBITDA.

(6) “Other income/(expense), net” on our 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/(expense), 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.

(8) Excludes certain non-cash items impacting interest expense such as amortization of debt issuance costs and terminated interest rate swaps.

(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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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.

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”).

Our Chief Operating Decision Maker (“CODM”) (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Adjusted EBITDA, segment volumes and maintenance capital investment.

We define Segment Adjusted EBITDA as revenues and equity earnings in unconsolidated entities less (a) significant segment expenses including:

(i) purchases and related costs, (ii) field operating costs and (iii) segment general and administrative expenses, plus (b) our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities, further adjusted (c) 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 (d) to exclude the portion of all preceding items that is attributable to noncontrolling interests (“Segment amounts attributable to noncontrolling interests”).

See Note 19 to our Consolidated Financial Statements for a reconciliation of Segment Adjusted EBITDA to Net income attributable to PAA.

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In connection with our merchant activities, our Crude Oil and NGL segments may enter into intersegment transactions for the purchase or sale of products, along with services such as the transportation, terminalling or storage of products.

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Crude Oil Segment

Our Crude Oil segment operations generally consist of gathering and transporting crude oil using pipelines, 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 serve third parties and are also supported by our merchant activities.

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 subject to our risk management policies and may include the use of derivative instruments to manage exposure to commodity price risk and, at times, to provide upside opportunities.

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.

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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 prices, as well as grade and regional differentials and time spreads.

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.

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

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Purchases and related costs (2)

(45,033) (43,805) (1,228) (3) %

Field operating costs (2)

(1,440) (1,053) (387) (37) %

Segment general and administrative expenses (2) (3)

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452 369 83 22 %

Adjustments (3) :

Other segment items (4) :

Depreciation and amortization of unconsolidated entities

84 87 (3) (3) %

Derivative activities and inventory valuation adjustments 5 17 (12) **

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Deficiencies under minimum volume commitments, net

(31) 12 (43) **

Equity-indexed compensation expense

Foreign currency revaluation

(22) 19 (41) **

Line 901 incident

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6,731 6,356 375 6 %

Rocky Mountain (6)

474 372 102 27 %

1,729 1,732 (3) — %

Total crude oil pipeline tariff 8,934 8,460 474 6 %

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(1) Revenues and costs and expenses include intersegment amounts.

(2) Represents components of significant segment expenses.

(3) Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments.

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See Note 19 to our 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 year divided by the number of days in the year.

(5) 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 UJIs) for the year divided by the number of days in the year.

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.

Index to Financial Statements

(6) Includes volumes (attributable to our interest) from assets owned by unconsolidated entities.

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(7) Average monthly capacity in millions of barrels per day calculated as total volumes for the year divided by the number of months in the year.

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Segment Adjusted EBITDA

Crude Oil Segment Adjusted EBITDA increased for the year ended December 31, 2023 compared to the year ended December 31, 2022 primarily due to higher tariff volumes, tariff escalations and contributions from acquisitions.

These items were partially offset by fewer market-based opportunities for our merchant activities.

Crude Oil Segment Adjusted EBITDA increased for the year ended December 31, 2024 compared to the year ended December 31, 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 year ended December 31, 2024 compared to the year ended December 31, 2023.

Net Revenues and Equity Earnings.

Our results were favorably impacted by (i) higher volumes across our pipeline systems, primarily driven by increased production and new well connections, (ii) tariff escalations and (iii) contributions from acquisitions.

These benefits were partially offset by the impact of minimum volume commitment deficiency payments received in 2022.

Additionally, our results for the year ended December 31, 2023 reflect net fewer market-based opportunities compared to 2022 as the 2022 period includes the benefit of the sale of excess linefill and inventory in a higher crude oil price environment.

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, including increases in ownership of certain pipeline systems.

Additionally, our results for the year ended December 31, 2024 compared to 2023 reflect fewer crude oil market-based opportunities.

Field Operating Costs.

For the year ended December 31, 2023 compared to the year ended December 31, 2022, we had higher expenses associated with (i) utilities costs due to a combination of higher volumes and prices and an increase in the amount of drag reducing agents used, (ii) incremental consolidated operating costs in connection with acquisitions, (iii) employee-related costs primarily resulting from higher average headcount and salaries and (iv) 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).

The unfavorable variance for the year ended December 31, 2023 compared to 2022 was partially offset by a decrease in additional estimated costs recognized associated with the Line 901 incident (which impact field operating costs but are excluded from Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the table above).

For the year ended December 31, 2024 compared to the year ended December 31, 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 a component of “Other segment items” in the table above), (ii) an increase in estimated costs for long-term environmental remediation obligations, (iii) property taxes due to the impact of favorable adjustments in 2023 and (iv) incremental operating costs and employee-related costs associated with acquisitions, partially offset by (v) unrealized mark-to-market gains on power hedges (which impact our field operating costs but are excluded from Segment Adjusted EBITDA and thus are reflected as a component of “Other segment items” in the table above) and (vi) decreased costs resulting from lower third-party trucked volumes.

Maintenance Capital

Maintenance capital consists of 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.

The increase in maintenance capital spending for the year ended December 31, 2023 compared to the year ended December 31, 2022 was primarily due to ongoing facility maintenance investments, tractor trailer leases, integrity projects and tank maintenance.

The increase in maintenance capital spending for the year ended December 31, 2024 compared to the year ended December 31, 2023 was primarily due to (i) an increase in integrity management, maintenance and repairs and replacement projects and (ii) more trucking lease buyouts.

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) 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.

Our management of our commodity exposure is subject to our risk management policies and may include the use of derivative instruments to mitigate the risk of such exposure and, at times, to provide upside opportunities.

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

Index to Financial Statement s

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.

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 NGL received from a third-party straddle plant.

Index to Financial Statements

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.

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(83) (79) (4) (5) %

Adjustments (3) :

Other segment items (4) :

Derivative activities

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Long-term inventory costing adjustments

(10) 13 (23) **

Equity-indexed compensation expense

Foreign currency revaluation

(5) 5 (10) **

Segment Adjusted EBITDA

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Propane and butane sales

86 94 (8) (9) %

** Indicates that variance as a percentage is not meaningful.

(1) Revenues and costs and expenses include intersegment amounts.

(2) Represents components of significant segment expenses.

(3) Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments.

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See Note 19 to our 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 year divided by the number of days in the year.

(5) Average daily volumes are calculated as total volumes (attributable to our interest for assets owned through UJIs) for the year divided by the number of days in the year.

Segment Adjusted EBITDA

NGL Segment Adjusted EBITDA for the year ended December 31, 2023 was in line with results for the year ended December 31, 2022, primarily due to (i) favorable NGL basis differentials and (ii) additional market-based opportunities, largely offset by (iii) lower straddle production driven by turnarounds at a third-party facility, (iv) increased field operating costs and (v) the impact of the sale of our ownership interest in the Keyera Fort Saskatchewan facility in the first quarter of 2023.

NGL Segment Adjusted EBITDA for the year ended December 31, 2024 decreased compared to the year ended December 31, 2023, primarily due to the impact of lower realized frac spreads, partially offset by higher propane and butane sales volumes.

Index to Financial Statements

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

Index to Financial Statement s

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 increased for the year ended December 31, 2023 compared to the year ended December 31, 2022 primarily due to (i) favorable NGL basis differentials, (ii) additional market-based opportunities and (iii) higher processing revenues at our Empress straddle plants resulting from a commercial agreement executed in conjunction with the increase in our Empress ownership in the fourth quarter of 2022.

This was partially offset by (iv) lower straddle production driven by turnarounds at a third-party facility, (v) the impact of the sale of our ownership interest in the Keyera Fort Saskatchewan facility in the first quarter of 2023 and (vi) higher gains at certain of our NGL facilities in 2022.

Excluding such impacts, net revenues decreased for the year ended December 31, 2024 compared to the year ended December 31, 2023 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, (iv) tariff escalations and (v) market opportunities.

Field Operating Costs.

The increase in field operating costs for the year ended December 31, 2023 compared to the year ended December 31, 2022 was primarily due to (i) an increase 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) and (ii) increased utilities-related costs largely as a result of the increase in our Empress ownership in the fourth quarter of 2022 and higher prices.

The increase in utilities-related costs was largely offset by the benefit to net revenues from operating cost recoveries realized through commercial agreements.

The decrease in field operating costs for the year ended December 31, 2024 compared to the year ended December 31, 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 a component of “Other segment items” in the table above), partially offset by (iii) higher maintenance and repairs.

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 year ended December 31, 2023 compared to the year ended December 31, 2022 was primarily due a scheduled turnaround at our Empress facility during 2022, partially offset by an increase in routine integrity activities.

The decrease in maintenance capital spending for the year ended December 31, 2024 compared to the year ended December 31, 2023 was primarily due to timing of routine integrity activities.

Liquidity and Capital Resources

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(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 $17 million, respectively.

Index to Financial Statement s

(3) Excludes restricted cash of $1 million.

Index to Financial Statements

Usage of our credit facilities, which provide the financial backstop for our commercial paper program, is subject to ongoing compliance with covenants, as discussed further below.

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We have three primary credit arrangements, which we use to meet our short-term cash needs.

These include our $1.35 billion senior unsecured revolving credit facility maturing in 2028 (excluding a commitment of $64 million, which matures in 2027), $1.35 billion senior secured hedged inventory facility maturing in 2026 and $2.7 billion unsecured commercial paper program that is backstopped by our revolving credit facility and our hedged inventory facility.

These include our $1.35 billion senior unsecured revolving credit facility maturing in 2029 (excluding a commitment of $64 million, which matures in 2027), $1.35 billion senior secured hedged inventory facility maturing in 2027 (excluding a commitment of $64 million, which matures in 2026) and $2.7 billion unsecured commercial paper program that is backstopped by our revolving credit facility and our hedged inventory facility.

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.

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We were in compliance with the covenants contained in our credit agreements and indentures as of December 31, 2024.

Liquidity Measures

Management uses the non-GAAP financial 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.

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 related party notes and the net 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.

Index to Financial Statement s

Index to Financial Statements

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):

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Net cash used in investing activities (1)

(1,504) (702)

Cash contributions from noncontrolling interests 57 106

Cash distributions paid to noncontrolling interests (2)

Proceeds from the issuance of related party notes (1)

Adjusted Free Cash Flow

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Cash distributions (3)

(1,145) (989)

Adjusted Free Cash Flow after Distributions (4)

(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 16 to our 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

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Net cash provided by operating activities for the years ended December 31, 2024 and 2023 was approximately $2.5 billion and $2.7 billion, respectively, and primarily resulted from earnings from our operations.

Additionally, as discussed further below, changes during these periods in our inventory levels and associated margin balances required as part of our hedging activities impacted our cash flow from operating activities.

The 2023 period was impacted by net positive changes in working capital items, largely associated with (i) lower NGL inventory driven by both the impact of the price environment and NGL supply volumes during the year, including the impact of changes in margin balances required as part of our hedging activities, and (ii) timing of payments associated with the settlement of certain obligations.

Index to Financial Statement s

Index to Financial Statements

Investing Activities

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$ 930 $ 1,061

(1) Capital expenditures made to expand the existing operating and/or earnings capacity of our assets are classified as “Investment capital.” Capital expenditures for the replacement and/or refurbishment of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets are classified as “Maintenance capital.”

(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 $329 million and $242 million, respectively, for 2024, and approximately $310 million and $214 million, respectively, for 2023.

(4) Acquisition capital for 2024 primarily includes the acquisitions of additional ownership interests in equity method investees.

Acquisition capital for 2023 primarily includes the acquisition by the Permian JV of (i) the remaining 43% interest in OMOG JV Holdings LLC and (ii) gathering assets in the Southern and Northern Delaware Basins.

Acquisition capital for 2022 includes (i) an additional ownership interest in certain straddle plants included in our NGL segment, (ii) the purchase of an additional 5% interest in Cactus II and (iii) the remaining 50% interest in Advantage Pipeline Holdings LLC by the Permian JV.

See Note 7 to our Consolidated Financial Statements for additional information.

See Note 7 and Note 8 to our Consolidated Financial Statements for additional information.

Acquisition capital, net to our 65% interest in the Permian JV, was approximately $243 million and $281 million for 2024 and 2023, respectively.

In the first quarter of 2025, we completed two additional bolt-on acquisitions for $636 million (approximately $580 million net to our interest), which included (i) a Delaware Basin crude oil gathering business and (ii) an Eagle Ford Basin gathering system.

We used a portion of the net proceeds from our January 2025 senior notes offering to fund these acquisitions.

Investment Capital Projects

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Complementary Permian Basin Projects (1)

Permian Basin Takeaway Pipeline Projects (2)

Selected Facilities/Downstream Projects (2)

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(1) Includes projects associated with assets included in the Permian JV.

(2) Represents pipeline projects with takeaway capacity out of the Permian Basin, including investments for our proportionate share of the projects of Wink to Webster Pipeline and Cactus II Pipeline.

(2) Includes projects at our St.

James and Fort Saskatchewan terminals.

Index to Financial Statement s

Index to Financial Statements

Projected 2025 Capital Expenditures.

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We expect to fund our 2025 investment and maintenance capital expenditures primarily with retained cash flow.

Proceeds from the sale of assets have generally been used to fund our investment capital projects and reduce debt levels.

Proceeds from the sale of assets have historically generally been used to fund our investment capital projects and reduce debt levels.

The following table summarizes the proceeds received from divestitures during the last two years (in millions):

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(1) Represents proceeds, including working capital adjustments, net of transaction costs.

The proceeds from divestitures for the year ended December 31, 2023 are primarily from the sale of our 21% non-operated/undivided joint interest in the Keyera Fort Saskatchewan facility in February 2023.

The proceeds from divestitures for the year ended December 31, 2023 are primarily from the sale of our 21% non-operated/UJI in the Keyera Fort Saskatchewan facility in February 2023.

See Note 7 to our Consolidated Financial Statements for additional information.

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“Risk Factors—Risks Related to Our Business—Acquisitions and divestitures involve risks that may adversely affect our business.”

Related Party Promissory Notes

In July 2024, promissory notes with a face value of CAD$865 million (approximately $629 million) were issued by and among us and certain Plains entities.

The cash outflow associated with our investment in promissory notes issued by PAGP to us has an equal and offsetting cash inflow associated with proceeds from the issuance by our consolidated subsidiary of promissory notes to PAGP for the same face value amount, which is included as a component of financing activities.

In February 2025, additional promissory notes with a face value of CAD$473 million (approximately $330 million) were issued by and among us and certain Plains entities.

See Note 16 to our Consolidated Financial Statements for additional information about our related party promissory 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.

Index to Financial Statements

Borrowings and Repayments Under Credit Arrangements

During the year ended December 31, 2024, we had net repayments under our commercial paper program of $40 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 year related to funding needs for capital investments, inventory purchases, repayment of $750 million, 3.60% senior notes due November 2024, and other general partnership purposes.

During the year ended December 31, 2023, we had net borrowings under our commercial paper program of $433 million.

The net borrowings resulted primarily from borrowings during the year 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 year ended December 31, 2022.

Index to Financial Statement s

Issuances of Senior Notes.

We did not issue any senior unsecured notes during 2023.

During 2024, we issued senior unsecured notes as summarized in the table below (in millions):

Year Description Maturity Face Value Gross

2024 5.70% Senior Notes issued at 99.953% of face value September 2034 $ 650 $ 650 $ 643 (3)

(1) Face value of notes less the applicable premium or discount (before deducting for initial purchaser discounts, commissions and offering expenses).

(2) Face value of notes less the applicable premium or discount, initial purchaser discounts, commissions and offering expenses.

(3) We used the net proceeds from the offering, 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.

In January 2025, we also completed the offering of $1 billion, 5.95% senior notes due June 2035 at a public offering price of 99.761%.

Interest payments are due on June 15 and December 15 of each year, commencing on June 15, 2025.

We used the net proceeds from this offering of approximately $988 million, after deducting the underwriting discount and offering expenses, to (i) fund the acquisitions completed during the first quarter of 2025, (ii) fund the repurchase in January 2025 of 12.7 million Series A preferred units, including accrued and unpaid distributions and (iii) repay outstanding borrowings under our credit facilities and commercial paper program, and, pending such uses, for general partnership purposes.

See Note 7 and Note 11 to our Consolidated Financial Statements for additional information regarding our recently completed acquisitions and our Series A preferred units, respectively.

Repayments of Senior Notes.

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Year Description Repayment Date

2024 $750 million 3.60% Senior Notes due November 2024 November 2024 (1)

2023 $700 million 3.85% Senior Notes due October 2023 October 2023 (2)

2023 $400 million 2.85% Senior Notes due January 2023 January 2023 (2)

2022 $750 million 3.65% Senior Notes due June 2022 March 2022 (1)

(1) We repaid these senior notes with proceeds from our 5.70% senior notes issued in June 2024, cash on hand and borrowings under our commercial paper program.

(2) We repaid these senior notes with cash on hand and borrowings under our commercial paper program.

Index to Financial Statements

Registration Statements

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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 December 31, 2024.

We did not conduct any offerings under our Traditional Shelf during the year 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 offerings of $650 million, 5.70% senior notes in June 2024 and $1 billion, 5.95% senior notes in January 2025 were conducted under our WKSI Shelf.

Common Equity Repurchase Program

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Any common units or PAGP Class A shares that are repurchased will be canceled.

There were no repurchases under the Program during the year ended December 31, 2023.

We repurchased common units under the Program during the year ended December 31, 2022 for a total purchase price of $74 million, including commissions and fees.

There were no repurchases under the Program during the years ended December 31, 2024 and 2023.

The remaining available capacity under the Program as of December 31, 2024 was $198 million.

Preferred Unit Repurchase

On January 31, 2025, we repurchased 12.7 million units, or 18%, of our outstanding Series A preferred units at the issue price of $26.25 per unit for a purchase price of approximately $333 million, plus accrued and unpaid distributions through January 30, 2025 of approximately $10 million.

We used a portion of the net proceeds from our January 2025 senior notes offering to fund this repurchase.

See Note 11 to our Consolidated Financial Statements for more information regarding our Series A preferred units.

Distributions to Our Unitholders

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Holders of our Series A preferred units are entitled to receive quarterly distributions, subject to customary anti-dilution adjustments, of $0.615 per unit ($2.46 per unit annualized).

Index to Financial Statement s

Distributions to our Series B preferred unitholders.

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The total distribution of $267 million was paid to common unitholders of record as of January 31, 2025, with respect to the quarter ended December 31, 2024.

Index to Financial Statements

See Note 11 to our Consolidated Financial Statements for details of distributions paid during the three years ended December 31, 2024.

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See Note 11 to our Consolidated Financial Statements for details of distributions paid to noncontrolling interests during the three years ended December 31, 2024.

Related Party Promissory Notes

In July 2024, promissory notes with a face value of CAD$865 million (approximately $629 million) were issued by and among us and certain Plains entities.

The cash inflow associated with proceeds from the issuance by our consolidated subsidiary of promissory notes to PAGP has an equal and offsetting cash outflow associated with our investment in promissory notes issued by PAGP to us for the same face value amount, which is included as a component of investing activities.

In February 2025, additional promissory notes with a face value of CAD$473 million (approximately $330 million) were issued by and among us and certain Plains entities.

See Note 16 to our Consolidated Financial Statements for additional information about our related party promissory notes.

Contingencies

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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.

The following table includes our best estimate and the timing of these payments as of December 31, 2023 (in millions):

The following table includes our best estimate of the amount and timing of these payments as of December 31, 2024 (in millions):

2025 2026 2027 2028 2029 2030 and Thereafter Total

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Uncertainties involved in these estimates include levels of production at the wellhead, weather conditions, changes in market prices and other conditions beyond our control.

Index to Financial Statement s

Index to Financial Statements

Letters of Credit.

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Saddlehorn Pipeline Company, LLC Crude Oil Pipeline 40% $ 576 $ 18

White Cliffs Pipeline, LLC Crude Oil Pipeline 36% $ 377 $ 6

White Cliffs Pipeline, L.L.C.

Crude Oil Pipeline 36% $ 341 $ 1

Wink to Webster Pipeline LLC Crude Oil Pipeline 17% $ 2,288 $ 68

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For further information on all of our significant accounting policies, see Note 2 to our Consolidated Financial Statements.

Index to Financial Statement s

Index to Financial Statements

Fair Value of Assets and Liabilities Acquired and Identification of Associated Goodwill and Intangible Assets.

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See Note 7 to our Consolidated Financial Statements for discussion of the methods, assumptions and estimates used in the determination of the fair value of the assets and liabilities acquired and identification of associated intangible assets.

In October 2021, we and Oryx Midstream completed the formation of the Permian JV.

Fair Value of Derivatives.

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Quantitative and Qualitative Disclosures About Market Risk and Note 12 to our Consolidated Financial Statements for a discussion regarding our derivatives and risk management activities.

Index to Financial Statement s

Index to Financial Statements

Accruals and Contingent Liabilities.

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In addition, when we evaluate property and equipment and other long-lived assets for recoverability, it may also be necessary to review related depreciation estimates and methods.

Index to Financial Statement s

Index to Financial Statements

Investments in unconsolidated entities accounted for under the equity method of accounting are assessed for impairment when events or circumstances suggest that a decline in value may be other than temporary.

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In May 2015, we experienced a crude oil release from our Las Flores to Gaviota Pipeline (Line 901) in Santa Barbara County, California.

We have estimated that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $750 million, which includes actual and projected emergency response and clean-up costs, natural resource damage assessments, fines and penalties payable pursuant to the Consent Decree, certain third-party claims settlements, and estimated costs associated with our remaining Line 901 lawsuits and claims, as well as estimates for certain legal fees and statutory interest where applicable.

As of December 31, 2023, we have recognized a long-term receivable of approximately $225 million for the portion of the release costs that we believe is probable of recovery from insurance, net of deductibles and amounts already collected.

Insurers responsible for the majority of our remaining insurance coverage have formally communicated a denial of coverage.

We intend to vigorously pursue recovery from our insurers of all amounts for which we have claimed reimbursement.

We believe that our claim for reimbursement from our insurers is strong and that our ultimate recovery of such amounts is probable.

Various factors could impact the timing and amount of recovery of our insurance receivable, including future developments that adversely impact our assessment of the strength of our coverage claims, the outcome of any dispute resolution proceedings with respect to our coverage claims and the extent to which insurers may become insolvent in the future.

Without limiting our view that our claim for reimbursement is strong and that ultimate recovery is probable, we cannot provide complete assurance that actual receivable amounts will not vary significantly from our estimated amounts.

As of December 31, 2024, we have estimated 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 incurred, certain third-party claims settlements, and estimated costs associated with our remaining Line 901 lawsuits and claims, as well as estimates for certain legal fees and statutory interest where applicable.

We maintain insurance coverage, which is subject to certain exclusions and deductibles, in the event of such liabilities.

In November 2022, we submitted claims to several of our insurance carriers seeking reimbursement for a payment made in October of 2022 to settle a class action lawsuit stemming from the Line 901 incident.

As of December 31, 2023, we had recognized a receivable of approximately $225 million, of which we had classified $175 million as a short-term asset with the remaining $50 million recognized as a long-term asset.

As of December 31, 2023, we believed that our claim for reimbursement was probable of recovery despite the ongoing arbitration proceedings.

However, at that time we also noted that various factors could impact the timing and amount of recovery of our insurance receivable, including future developments that adversely impacted our assessment of the strength of our coverage claims, the outcome of any dispute resolution proceedings with respect to our coverage claims (including arbitration proceedings) and the extent to which insurers may become insolvent in the future.

Due to these factors, we noted that we could not provide complete assurance that actual receivable amounts recovered would not vary significantly from our estimated amounts.

Index to Financial Statements

A binding arbitration hearing with respect to our insurance claim against insurers representing $175 million of our total $225 million reimbursement claim concluded in early October 2024, and the arbitration panel’s final and binding decision was returned in January 2025.

The panel ruled that a substantial portion of our claims subject to the proceeding were not covered

under the applicable policy and therefore we were not entitled to reimbursement of our $175 million claim against the applicable insurers.

With respect to our remaining $50 million claim against different insurance carriers, we now regard collection of those claims as being less than “probable.” As a result, we wrote off the entire $225 million receivable in the fourth quarter of 2024 and will recognize any future collections as and if they are received.

See Note 18 to our Consolidated Financial Statements for further discussion regarding the Line 901 incident and our related insurance receivable.

Index to Financial Statement s

Recent Accounting Pronouncements

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis